bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing Red Zone Management and Operational Excellence in HWU Rig Operations Through Digitalization Using Real-Time CCTV Monitoring with Artificial Intelligence
Authors: Abdul Hamid A. , Ahmad T. , Majid Bin Allapitchai M. , Sellapan S. , Arumugam S. , Redzuan S. B. , Mohd Effendi S. , Abdul Razak M. 
Published: October 2023

Abstract
Real-time monitoring through CCTV is a crucial aspect of offshore operations in all types of rigs. While this system is widely utilized in conventional drilling rigs, it is not as commonly used in hydraulic workover unit (HWU) rig and this create a huge gap in Red Zone Management and Operation Excellence in term of efficiency. The primary purpose of this system is to enhance red zone management, increase operational efficiency, and allow for remote operation or supervision.
Recently, this system was implemented for workover operations in Malaysia that utilized an HWU rig. Six ATEX-rated cameras were installed in critical areas of the HWU rig and the accommodation work barge (AWB). ATEX rated are required to comply Zone 2 requirement. A detailed site survey and engineering were conducted to install these cameras, which had never been installed before on an HWU rig. The system is wired, requiring a long cable connection from the HWU rig on the platform to the AWB and supervisor office. Additionally, it is connected to the project team's mobile devices, allowing for real-time monitoring, and enabling the team to observe operations from onshore.
This system provides supervisors with improved supervision of offshore operations, equipment movement, and HSE supervision. Prior to its implementation, supervisors only had voice communication via walkie-talkie and no visual access to the operation from the supervisor's office. Furthermore, engineers in the office and service providers can observe the operation, especially during critical jobs. The system also aids in HSE case investigation by providing footage for the investigation team to review using its playback feature.
This pilot system closes a significant gap in the HWU rig, improving red zone management, increasing operational efficiency, and allowing for remote operation or supervision. This paper outlines the system's functionalities, installation and engineering procedures, detailed implementation, and the future scope of artificial intelligence in closing gaps in terms of HSE and operation.
Managing New Development Uncertainty with Scenarios and Multiscale Modelling: An Integrated Study of the Fogelberg Discovery
Authors: Mullins James R. , Mendez Maria , Bajan Luka , Rocher Dimitri , Spitzmüller Adam , Marsh Tom , Berntsen Bjørn A. 
Published: October 2023

Recent hydrocarbon developments are generally characterised by high complexity and uncertainty with lower margins for error in an unpredictable financial market. This is further compounded by new oil and gas discoveries being typically smaller today, than in the past; highlighting the need for robust and fit-for-purpose reservoir models that accurately capture key uncertainties to inform management decisions and to help avoid substantial financial losses.
To make an informed decision on either field development or relinquishment of the Fogelberg production license on the Norwegian Continental Shelf (NCS), an alternative full field reservoir model was commissioned by one of the License partners of a complex stacked tidal bar system in the Norwegian Sea. The model includes an accurate representation of the underlying heterogeneities observed in a drill stem test (DST) performed in 2018, incorporating the spatial evolution of the tidal bar system including the placement of low permeability inter-bars to stylolitisation at core-plug scale. Furthermore, the model is robust enough to permit future forecasting and well planning required to enable a management decision.
A scenario-based modelling approach (after Bentley and Smith, 2008) based on three discrete concepts was undertaken, accounting for uncertainty in the spatial geometry of the tidal bar complexes. This approach was combined with a hierarchical modelling strategy to honour the depositional concept model and to provide modelling flexibility. Sub-cell resolution heterogeneity in the form of stylolites that were prevalent in cored intervals were incorporated using a multi-scale approach in the form of a representative elementary volume (REV). A full uncertainty ensemble was generated for each of the three modelling scenarios.
The model produced a robust match to the bottom hole pressure (BHP) reported during the DST and was used to generate production potential and optimize lower completion strategy, including a side-by-side comparison of recovery of horizontal wells with fishbone stimulation, hydraulic fracturing stimulation and unstimulated slotted liner completions. Based on new static and dynamic understanding of the reservoir, the license will be re-applied for with a view to future development.
This paper highlights the importance of managing uncertainty through the use of scenarios, their flexibility with ensembles and the use of a multi-scale approach to accurately represent the respective lengths at which heterogeneities occur to build a better knowledge of the subsurface. The work undertaken for this petroleum system is both highly relevant and transferable for the future transition of safe and permanent storage of carbon, hydrogen and nuclear storage.
Application of 4D Geomechanical Modelling for Fault Critical Re-Active Stress Evaluation in CO2 Storage
Authors: He Xinxing , Zhou Wei , Tang Yongliang , Chen Dong , Huang Zhaotin , Xu Hanbing , Lian Liming , Cheng Ronghong , Chen Xiaobo , Fu Ying , Wu Yongping , Wu Mimi , Qiao Xia , Wang Yandong , Feng Guang , Xu Zhenzhen 
Published: October 2023

AbstractIn order to provide effective guidance for optimizing and adjusting the maximum operation pressure and dynamic monitoring well pattern of underground gas storages and ensure the operation safety of gas storages. With the continuous enhancement demand for resources is also growing. At the same time, with the rapid development of industry, the industrial waste gas led by CO2 has also caused great harm to the environment. Therefore, to solve the above two problems, it is crucial to accelerate the construction of underground gas storage, safe and efficient extraction of oil and gas reservoirs, and geological storage of CO2. As a critical technology for the construction of underground gas storage, oil and gas field exploitation, and geological storage of CO2, many scholars have carried out research on fault stability in terms of complex stratigraphic stress environment, lithologic contrasts on both sides of the fault, mudstone smear content, fracture mechanics and so on, and have made many vital understandings and progresses. However, with the development of oil and gas fields and geological sequestration of CO2, the problem of fault destabilization caused by fluid injection, leading to fault activation and, thus, oil and gas leakage, has become increasingly prominent. Fault destabilization activation will not only form a possible path for oil and gas leakage and cause fault seal failure but also may cause a series of safety problems. There have been many major oil and gas leaks caused by fault slipping at home and abroad, resulting in many casualties and property damage. Therefore, studying the fault activation and seal failure caused by fluid injection is urgent.
Minimizing Geological Core Destructive Analysis Using Machine Learning
Authors: Mezghani M. , Tao L. 
Published: October 2023

Abstract
The core analysis program we developed is based on artificial intelligence (AI) and aims to complement conventional core analysis methods for the measurement of rock properties. This program offers several advantages over traditional destructive analyses.
Firstly, the program allows for non-destructive analysis of rock samples. This means that the rock samples are not completely destroyed during the analysis process, allowing for their potential use in further studies or for future reference.
Secondly, the AI-based program is capable of conducting a large number of analyses, overcoming the restriction on the number of measurements that can be conducted using conventional core analysis. This enables a more comprehensive understanding of the rock properties, improves the accuracy of the results, and therefore reduces the subsurface modeling uncertainties.
Uncertainty and Sensitivity of Permeability Models
Authors: Farmer Russell 
Published: October 2023

Abstract
Quantifying and managing uncertainty leads to improved project and business performance, robust decision making, increased chance of success, fewer surprises and optimised reservoir characterisation outcomes. Informed decisions will be robust to risk and increase the likelihood of an outcome that delivers promised production from a well or development.
Petrophysicists have a crucial role in delivering an appropriate product for estimating productivity and its' uncertainty can have a significant impact on exploration, appraisal, and development project economics. This is particularly the case when estimating permeability and permeability thickness (kh) which are fundamental to predict robust productivity rates for wells.
When using core to build log-based permeability models, many issues need to be addressed, some of which may be significant. This paper supports an assessment of other factors that may contribute to variability between core, model estimates and well performance, but is primarily focused on a rapid screening of irreducible uncertainty and sensitivity as opposed to rebuilding a new model.
Quantifying the sensitivity and uncertainty of model estimates of permeability provides a framework to optimise reservoir management challenges and a workflow to screen for differences that contribute to sensitivity and ranges of permeability in individual cored wells and as a predictor in uncored wells.
for setting expectations (irreducible uncertainty), estimating ranges for undrilled reservoir and infill targets identifying other factors that may be significant in well and reservoir performance supporting optimised reservoir management indicating the potential benefits and value of additional data acquisition.
Transforming Decision Making in Carbonate Matrix Acidization Domain
Authors: Chandola Gaurav , Panga Mohan K. R. , Ugursal Assiya , Kumar Amit , Garima Garima , Chen Yang 
Published: October 2023

Abstract
Acid stimulation treatments are typically designed using a combination of experience, available field/lab testing data and a stimulation design software that ties it all together. The final design, given the large degrees of uncertainty, requires multiple iterations to arrive at the (near) optimum stimulation design. To account for the large number of variables and their uncertainty, a framework and associated tools have been developed for automating and optimizing the design process that allow to significantly reduce the optimization time. The adopted approach leverages modern web applications for overcoming the limitations associated with the legacy stimulation design tools. Python Dash is used for creating an interactive web application, allowing users to load a file containing all necessary inputs for the calculation and specify the ranges for different design parameters. The web app then generates a parameter space and spawns multiple parallel runs of the calculation engine. An optimization module utilizing existing python optimization libraries is developed within the web app framework, which guides the selection of the next sample point in the parameter space after each iteration until the optimum point is reached. After implementing this framework across multiple workflows, considerable improvements have been realized with time savings ranging from hours to days. A detailed case study is presented to demonstrate the application of the framework for designing a Limited Entry Liner (LELs) completion, where the nozzle distribution in different reservoir sections (compartments) is varied to achieve a desired acid placement into the formation and improve stimulation efficiency.
New Technologies and Practices to Enable Remote Operations, Increasing Complex Long Multilateral Horizontal Wells and Enriching Project Sustainability and Efficiency: A Real Case from Northern Europe
Authors: Dixit A. , Bang M. , Gonzalez R. , Inge Andresen O. , Stangeland T. 
Published: October 2023

Abstract
While many global energy transitions have happened throughout history, today we need to satisfy the world's growing demand for energy while contributing to deliver energy in a cleaner, safer and continuously more efficient way. This paper looks into how the latest multilateral wells delivered, achieved the well targets by choosing optimized solutions to deliver on efficiency and accuracy from planning to execution. Using the latest digitalization and automation technology, along with recent developments on advanced rotary steerable systems (RSS), low friction water-based mud and extended life drill bits, has played a major role in relocating most of the service company personnel from rig site to remote operations centers. Relocating personnel has reduced exposure at rigsite and thereby reduced health, safety and environment risks and carbon footprint, while continuously improving operational performance. This is achieved through close collaboration between different subject matter experts in the same geographical location, enabling collaboration during follow up of multiple operations and improving the overall project executionWe will detail how successfully drilled 6624m horizontally in one run within the well target in the reservoir and without any HS&E incident. The services were run from a remote operations center with minimum personnel at the rig site. The rotations per minute (RPM) were optimized to reduce high frequency torsional oscillation (HFTO) vibration. No severe whirl was observed which is common in long tangent sections. The run ended in the top 5 fastest average ROP for the field and achieved the longest bit run in the same field. Moreover, due to running the operation remotely, it saved in transport to and from rig site, enabling an estimated of 697,261kg in savings of equivalent CO2.
This outstanding result was achieved by incorporating technology across multiple product lines, enhancing performance, reducing cost and risk associated with several bit-runs and improving effective wellbore placement. The aim of this paper is to present how new ways of working to manage projects by continuous improvement in technology, automation, digitalization enables energy deliveries in a safer, more efficient and sustainable way.
Diagnosis of GOR Evolution in Carbonate Reservoir, Offshore Abu Dhabi, Undergoing a Major Miscible Gas Injection Operation
Authors: Khan M. N. , Mogensen K. , Sainz A. 
Published: October 2023

Abstract
One of the largest miscible gas injection operations worldwide is currently being conducted in an offshore carbonate field located in Abu Dhabi, which has a near-critical fluid system. Throughout the production process, there is an observed gradual increase in the gas-oil ratio (GOR) in ‘Reservoir A’. The evolution of the gas-oil ratio (GOR) may be attributed to various physical mechanisms, including production below the bubble point, gas coning, or the breakthrough of miscible gas. In the latter scenario, there exists ambiguity regarding the extent to which reservoir dispersion has caused the diffusion of the miscible displacement front, potentially leading to a loss of miscibility. The primary aim of this study was to assess the GOR response through the utilization of numerical simulation and other analytical techniques.
A producer-injector pair was utilized in a numerical simulation to investigate various scenarios, including: (1) production below the bubble point; (2) gas coning originating from the gas cap; (3) a perfect miscible displacement; (4) a perfect immiscible displacement; (5) a miscible displacement that transitions to immiscible due to dispersion; (6) a combination of the aforementioned scenarios. The primary output parameters monitored encompassed the gas-oil ratio (GOR) and the flowing bottom pressure at the producer. Subsequently, various runs were compared to each other and in relation to the observed gas-oil ratio (GOR) response.
A surveillance strategy that was suitable for the intended purpose was implemented in order to evaluate the efficacy of the overall development strategy. The results of recent production logging tool (PLT) tests conducted at different choke sizes revealed no evidences of free gas production downhole. The utilization of inline multiphase flowmeters has been deemed essential in capturing the evolutionary trends of gas-oil ratio (GOR). The primary factor contributing to the evolution of gas-oil ratio (GOR) was determined to be the oil swelling resulting from miscibility, as observed through the comparison of simulation-based type curves with the GOR trend.
In addition, it has been suggested that regular monitoring of compositional ratios (C1/C2+C3) should be conducted alongside the ongoing inter-well tracer campaign. This will provide an enhanced ability to anticipate and track the movement of the gas front within the reservoir. Optimizing the gas injection pattern and oil production offtake is crucial in order to enhance sweep efficiency.
Re-Skilling Young Sarawak's Talents into Oil and Gas Workforce, A Noble Social Engagement to the Community
Authors: Banda M. E. Yanez , Johan Z. J. , Dubois A. , Abang D. H. , Musa N. 
Published: October 2023

Abstract
Sarawak, a state in Malaysia has long been the key contributor to probable and proven (2P) Petroleum reserves, in which the state bearing and account to 60.8% of total National reserves. Known for its untapped reserves and with sturdy relationship with partners and investors to spur growth to national economy for decades, now it just the right time for the State to focus on its social contribution to Sarawak's young talents in the energy industry.
CO2-e Emissions Factors for Well Completion Operations in Mature Oil Fields in Colombia
Authors: Sánchez Walter , Gomez Nelson , Hernandez Claudia , Hernandez Mario , Tibavizco Laura , Quintero Eloisa , Guarín Liliana , Martinez Santiago , Gomez Juan Jose , Rangel Diego 
Published: October 2023

Abstract
The methods available for calculating emissions in the industrial sector are limited to industry-average, supplier-specific, hybrid or spend-based emission factors (tCO2e per material purchased or tCO2e per dollar billed, respectively). This provides a high-level view of the total emissions and average CO2-e values ​​generated per drilled and completed well. However, these data are not sufficient when it is necessary to know the emissions from a specific activity such as the completion of a well, a well service, a drilling or workover rig consumption, or when it is desired to determine the reduction of emissions from the use of a technology in a specific activity.
This article will present a methodology to calculate the CO2-e emission factors during the completion of injection and producer wells in different fields in Colombia. Includes an analysis of the existing literature regarding emission factors for completion operations, the description of the main emission sources in completion operations and the procedure used to obtain the emission factors by type of well (tCO2e/completed well), by completion activity (tCO2e/activity) or by type of equipment (tCO2e/equipment).
The calculation methodology includes the procedure for data gathering and validation, database creation, specific CO2-e factors calculations as well as the premises considered. For the studied wells, the work identified the activities with the greatest impact on operations, the type of well with the highest emissions, and offers a comparison in terms of type of intervention equipment such as Workover Rig, drilling Rig or Coiled Tubing. Finally, a list of emission factors will be presented by type of well, by type of equipment and by specific activity.
CO2 Huff and Puff Injection Operation Overview in Jatibarang Field Lessons Learned from a Successful Case Study in Mature Oil Field
Authors: Halinda D. , Zariat A. Az , Muraza O. , Marteighianti M. , Setyawan W. , Haribowo A. , Rajab M. , Firmansyah M. , Hasan I. , Nurlia D. , Adham A. , Prabowo P. , Okabe H. , Mikami K. , Kento K. , Susanta P. , Palupi A. S. 
Published: October 2023

Abstract
The objective of this paper is to provide an overview of the CO2 Huff and Puff injection operation in the mature Jatibarang field, Indonesia, and share the lessons learned from a successful case study. The scope of this paper includes the project preparation, implementation, and troubleshooting. The aim is to provide insights into the key factors that contributed to the success of the project and to identify potential challenges and their solutions. The paper will present a comprehensive review of the CO2 Huff and Puff injection process, start from the design of the injection plan and the monitoring and evaluation of the injection process. The methods, procedures, and process used in the project will be discussed, including the selection of candidate wells, the injectivity test, the CO2 injection rate, and the well performance evaluation. The paper will also highlight the challenges faced during the implementation of the project and the solutions adopted.
The results of the CO2 Huff and Puff injection operation in the Jatibarang field are promising, with an oil production rate increase of up to 86% with minimum operational difficulties. The successful implementation of CO2 Huff and Puff injection operation in Jatibarang Field was mainly attributed to the good operation procedure that prioritized safety and efficiency. With careful planning and intensive discussion conducted to identify potential risks and minimize operational difficulties, the operation was able to run smoothly, with minimal issues and zero HSE incidents. One of the key challenges that CO2 injection operations usually face is the risk of pipe blockage due to CO2 freezing. Fortunately, no such incidents occurred during the operation. Continuous monitoring of the injection process and fluid properties managed to ensure that the CO2 remained in gas phase in surface and supercritical state in the bottom hole throughout the operation. In conclusion, the success of the CO2 Huff and Puff injection operation in Jatibarang Field was due to the careful preparation and execution of a well-designed operation procedure. The operation demonstrated that with the right approach, the potential risks and challenges associated with the project can be mitigated.
This paper will present novel information on the implementation of CO2 Huff and Puff injection in a mature oil field in Indonesia. The lessons learned and the best practices identified in this project can be of benefit to the petroleum industry, particularly for those dealing with mature oil fields. The paper will also provide insights into the design of the injection plan and the monitoring and evaluation of the injection process, which can be useful for future CO2 Huff and Puff injection projects.