bluuebunny/crossref_metadata_2025_split huggingface dataset:
Value Tracking Thru Digital Fields Countrywide Solution Big Data Analytics Project
Authors: Karim Anak , Abu Hassan Hairulirwan , M Izdihar Muslimin Sayyid , Fuenmayor Roberto , Kamarulzaman Ammar , Mokhlis Mohamad Mustaqim 
Published: August 2021

Abstract
The Digital Field initiative is transforming the daily operations on the oilfield and it is now part of PETRONAS corporate wide digital strategy.
This transformation is done by onboarding multiple disciplines such as subsurface team, facilities, and operations, HSSE and Business Planning and is designed to replicates the performance of an oilfield in the computer, combining business process management and technical workflows. Digital Field has enabled the customer to execute their work collaboratively, by providing decision support system (technical workflows and business process management tools) subsequently improving their process efficiencies and optimizing their production. It is believed that by conducting a systematic review of the improvement and tracking the values that has been achieved, it will help to promote and accelerate digital adoption faster.
The main objectives of the Automated Value Tracking are:
To promote opportunity generation through collaborative environment. To track stages of every opportunity of the following categories of Production Optimization, Unplanned Deferment and Process Cycle Efficiencies. To quantify values associated with opportunities generated from automated workflows and current business process. To promote ownership of the actions associated with the assigned opportunity and to help to quantify on individual level contribution to the corporate goal in terms of production volume and time savings. To measures optimized number of opportunities generated against production volume associated with Production Optimization activity according to Field category and Quality of Opportunity Generated from Optimization Advisor.
The process is summarized as follow:
Opportunity generation: Automated opportunity generation generated through current Production Optimization Advisory framework. Integration with existing Petronas business process tools i.e. Daily Operational Tracking System, Alpha projects, Opportunity Management system, etc. Manual opportunity generation. Opportunity evaluation and analysis: Provide quantitatively confidence level of production incremental volume from automated Optimization Advisory through machine learning. Establish relationship between numbers of opportunity completed and categories versus production volume gain. Opportunity tracking and approval: Tracking the opportunity generation according to the process level. Escalating Opportunity and value recognition through business process approval.
This workflow helps to improve to understand the current update of the different levels such as well, field, region and upstream with the help of integrating the value realization and allows "cards" to show information that can trigger opportunities to increase production, reduce time of decision and fast action.
Planning for Unknown in The New Age of Digital: A Paradigm for Offshore Oil and Gas Risk Assessment and Management
Authors: Hamedifar Hamed , Wilczynski Herve 
Published: August 2021

Abstract
Major Oil and Gas operators and service companies look to undertake large scale digital transformations aimed at producing integrated, connected, and intelligent enterprises. These transformations require accelerating the journey to the cloud to modernize the entire application portfolio. By transitioning to the cloud, firms enjoy improved data analytics which allow for evolution to next generation digital work environment. This shift, however, comes with workforce challenges. Employees in all categories and at most levels will require significant cross- and up-skilling to take full advantage of the digital transformation. As vendors, suppliers, service companies, and operators move products and equipment around an expanding ecosystem of assets, security threats are likely to increase due to further geopolitical instability. Data based decision making, which enables the optimization of assets and automation of operations to minimize workforce risk exposure must be implemented with consideration of enterprise risk reduction (across the asset and workforce operational risk life cycle).
As Oil and Gas operations become more geographically dispersed and diverse, they are exposed to new and evolving risk factors which can directly impact value. These risk factors make asset acquisition, development, management, and maintenance all more challenging. Analyses of risk in a digital foundation risk-based platform is most valuable at the earliest stages of asset development in determining whether to proceed with the planned development through to end-of-life decommissioning. Successful firms must create an end-to-end digital roadmap which delineates between technical and transactional activities and outlines effective stakeholder engagement at each project stage.
The fundamental thesis of this paper is that although risk can be mitigated and reduced through the introduction of digital tools into oil and gas operations, it can never be completely removed. Furthermore, while industry research on the impact of digitalization usually rely heavily on cost savings, optimization, and health, safety, and environment (HSE) related cases, they typically fail to consider the contribution of digitalization on risk assessment and management. This paper argues that we need to move away from the focus on cost savings, process optimization, and HSE metrics improvement metrics. This paper sets up a mechanism for developing risk-based strategies for implementation of digital solutions.
From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil
Authors: Santos Paulino Bruno , Junior Teixeira Gilberto , Nogueira Leonardo De Souza , João Vilain Leonardo , Torres Simas G Milton , Costa Leonardo De Menezes 
Published: August 2021

Abstract
In the last three years, COMPANY has started the production of eight Surface Production Systems (Floating, Production, Storage and Offloading Units) in the Búzios and Lula fields of the Brazilian pre-salt that have generated technical knowledge, organizational learning and many opportunities to explore in upcoming projects. The lessons learned as well as the organizational knowledge acquired in this period, resulted in a new approach for the commissioning process to apply in COMPANY's coming FPSO projects.
During this period, COMPANY identified improvement opportunities and stablished structuring programs focused on adding value to these new assets. The main opportunity identified was to reduce the period required for ramping-up the oil production, considering aggressive target dates for start-up, with high up time on the gas compression systems with minimum flaring.
In this manuscript, will be described some of the important actions and changes made in commissioning process that allowed COMPANY to achieve better efficiency and safety in ramp up of new FPSOs in Brazilian pre salt fields.
Seismic Attributes and Acoustic Inversion for Shallow Marine Slope Stratigraphy Analysis
Authors: Son Jungrak , Boon Rebecca , Kuhn de Chizelle Julien 
Published: August 2021

AbstractGeophysical seismic surveys have been used in marine site characterization for subsea engineering and the design of offshore structures. Signal processing plays a key role in obtaining seismic attributes from observed seismic data to identify subsurface geological features within complex shallow sediments. Instantaneous amplitude, phase, and frequency are the most widely used seismic attributes to indicate geological features, but those time-domain data are too limited to define an accurate subsurface model in depth. Therefore, seismic inversion is also required to generate additional geospatial subsurface model information to aid in shallow stratigraphy interpretation. In this paper, we applied both geophysical signal processing and stochastic seismic inversion to a high-resolution multichannel seismic dataset from the Eastern North American Margin (ENAM). Seismic attributes from the Hilbert transform and inversion modeling results (acoustic impedance and modeling uncertainty) were integrated to define better geological horizons and discontinuities. The results show the integrated geophysical subsurface models can support seismic interpretation and improve shallow marine site characterization.
Unlocking Potential Thru Sand Management Insights in Digital Fields
Authors: Mohd Shabarudin Shazana Ezza , Salleh Mohamad Salhizan , Abu Bakar Hizamal Afdzal , Jamaluddin Nasri Muhamad , Vo Tri Nghia , Hermann Roland , Fuenmayor Roberto , Mokhlis Mustaqim Mohamad 
Published: August 2021

Abstract
Sand production is creating sand erosion and deposition issues at multiples levels such as tubing, choke and pipeline, therefore causing multiples undesirable events such as unplanned production deferment, integrity and sand handling capacity issues in each field.
Traditionally, each field has common practices to address sand issues. However, this creates non-standard procedures and prevents sharing best practices around all the assets. Managing sand production and related risks are keys where a multi-disciplined team (from subsurface to the surface) is required to ensure safe operations in more than 45 offshore fields.
To efficiently manage such a challenge at scale, there was a need to develop a single common digital platform for all. The digital platform provides unified user experience and proactive actionable insights to all assets with characteristics such as;
Scalable to all fields Solution architecture to allow fast implementation Same company-wide user interface/user experience platform
To achieve this ambition, it was necessary to move away from traditional waterfall project development to agile approach, automating ingestion of data from multiple sources, integrating the in-house development tool as engine based on equations develop specifically for Malaysia fields.
The solution was deployed to all fields during 2019. This had created additional benefits such as
Transparency on the data: Anyone can access to any field Visible Metrics: All fields sharing the same metrics, also improving and developing adjustments according to each situation Regulatory Compliance: Helping to keep up to date with sand sampling
There are already fields reporting examples of value realization in the form of Cost Avoidance and/or reduction in unplanned deferment due to improved Sand Management handling from the solution. It is expected that the value realization will increase by taking actions of protecting the field of any Loss of Primary Containment (LOPC), saving time of deciding as Process Cycle Efficiency (PCE). The solution can potentially be utilized for annual field forecasting for work program and budget cycle.
Design Perspectives for Selection of Subsea Gas Lift Technology for Deep Water Fields
Authors: Tornisiello Ligia , Taxy Stephane , Curto Rick 
Published: August 2021

Abstract
Riser base gas lift is conventionally used in deep water fields to minimize backpressure on wells, smooth start-up transients, and mitigate slugging in the flowline-riser system which can cause disruption in the topside facilities. The effectiveness of riser base gas lift depends on several factors, such as the reservoir performance, the fluid properties, the field architecture, and the topography. There are several technical solutions available to deliver the lift gas to the riser base. Such technical solutions differ in terms of lift-gas supply method (distributed vs point-to-point), riser specifications, and overall system complexity. The selection of technical solution has the potential for minimizing infrastructure. Available solutions include bundled risers and concentric riser configurations that allow gas lift functions to be integrated with the main production conduit. The evaluation of riser base gas lift effectiveness and the selection of the most appropriate technical solution is typically performed early in the field development cycle. This paper presents a review of the available subsea gas lift technical solutions and discusses an evaluation process, including criteria for the selection of the most appropriate solution. The presented case study assumes a deep water Gulf of Mexico field, in which the main subsea system consists of two wet insulated piggable flowline loops. Key decision drivers were flow assurance requirements, complexity, operability, impact on field layout, interfaces, installation, and schedule are discussed. This holistic approach aids the selection of the most appropriate riser base gas lift system in the early field development cycle.
An AI-Based Detection System for Mooring Line Failure
Authors: Sidarta Djoni Eka , Tcherniguin Nicolas , Bouchard Philippe , Lim Ho-Joon , Kang Mengchen , Leridon Aurelien 
Published: August 2021

Abstract
Safe and productive offshore operations are of utmost importance, with monitoring the integrity of mooring lines on floating offshore platforms being one of the key factors. The conventional method uses sensors installed on mooring components, which may fail over time and can be costly to replace. Alternative methods using dry and non-intrusive monitoring systems offer a lot of potentials to the industry.
An alternative method that uses only Differential Global Positioning System (DGPS) data has been proposed by Sidarta et al. (2018, 2019), and it does not require any information on environmental conditions. This alternative method is based on monitoring shifts in the low-frequency periods and mean yaw angles as a function of vessel positions, mass and added mass. The method utilizes Artificial Intelligence, specifically Artificial Neural Network (ANN), for the detection of mooring line failure, which is a pattern recognition and classification problem. The ANN model learns to recognize and classify patterns of intact mooring lines and those of a broken line. One of the proposed models is a group identification model, in which the model identifies the mooring group that has a broken line.
This paper shows that an ANN model can be quite robust and tolerant in dealing with conditions that are somewhat different from its training. As an example, an ANN model for detecting mooring line failure on a spread moored FPSO has been trained using MLTSIM hydrodynamic simulations with quasi static model of the mooring lines and risers to significantly reduce the computational time to generate the ANN training data. The trained ANN model can properly function when tested using fully coupled OrcaFlex hydrodynamic simulations with environmental conditions that are not included in the training. Moreover, although the ANN model has been trained using simulations with a completely removed line, the trained model can still function for a line broken at the bottom.
This ANN model is an ANN-based status detection model, which is one of the key components in the ALANN (Anchor Lines monitoring using Artificial Neural Networks) System. The system also composes of an ANN-based system evaluation model, an algorithm-based status detection program and an event detection program. A series of fully coupled dynamic simulations have been used to test the ALANN System. Most of the simulations have a single mooring line failure that occurs randomly during simulation, and the failed line varies for different simulations. Each simulation lasts for six hours. The ALANN System uses a two-hour time window at a time and moves every 20 minutes. The tests demonstrate how each component of the ALANN System contributes to and improves the robustness of the overall solution.
Assessment of Internal Tubular Coating Using Flow Loop
Authors: Zakaria Muzdalifah , M Sauri Shalabi A. 
Published: August 2021

Abstract
Assessment of coating performance under flowing condition by using a proprietary flow loop system has been established. The 2 3/8" flow loop was designed to maintain a flow rate of 0.03-0.04 m3/sec, pressure of 3300kPa and temperature of 150°C to simulate actual field condition. Test section consisting of two 35" straight tubes with 45° elbow was internally coated and connected to the flow loop which was run continuously for 14 days with deionized water under the specified test condition. Upon completion, visual inspection, EIS and linear abrasion test were done on the test section to evaluate the coating integrity post exposure. Small blisters were noted at the elbow section potentially due to the improper surface preparation and/or higher fluid velocity at the bend section. Impedance value of 107 Ω/cm2 is a magnitude higher than the acceptance limit of 106 Ω/cm2 while abrasion resistance was found less than the set limit of &lt;100mg/1000 cycles. The flow loop test has been shown to be a reliable tool to evaluate the effect of wall shear stress and fluid erosion on internal tubular coating.
Sensor Ball: Autonomous, Intelligent Logging Platform
Authors: Buzi Erjola , Seren Huseyin Rahmi , Deffenbaugh Max , Bukhamseen Ahmed , Zeghlache Mohamed Larbi 
Published: August 2021

Abstract
Recent developments in automation and electronics have enabled modernization and miniaturization of oilfield instruments. One product of these trends is our autonomous logging platform called "Sensor Ball". The Sensor Ball is a handheld, untethered logging tool that one person can deploy and recover from a pressurized well with no special equipment and crews (Deffenbaugh, 2016). The only tool needed is a wrench to open the cap of the wellhead. The operator puts the sensor ball in through the cap, then sequentially opens and closes the crown and master valves. This process takes only a few minutes. Once clear of the well head, the Sensor Ball falls down the well, logging data as it travels downhole. During this time, all the wellhead valves are closed and there is no need for the field crew to stay at the well site. We present data from recent Sensor Ball deployments to log pressure and temperature profiles and bottom-hole pressures. Depth information is provided by a novel onboard sensor that detects the connections between casing or tubing joints like a casing collar locator. A small dissolvable metal weight is magnetically attached to the housing and is sized to make the Sensor Ball descend at about 1 foot per second. At the desired depth, Sensor Ball drops the weight to become buoyant in the wellbore fluids and return to the surface. As it returns, it repeats the logging measurements, storing temperature and pressure data in its internal memory. After a typical four-to-eight hour mission, the operator returns to the well, opens and closes the well head valves in reverse order, removes the cap and takes out the Sensor Ball. The logged data are downloaded wirelessly to a laptop or cell phone. A lightweight, syntactic foam housing provides buoyancy and protects the electronics from the well fluids. The small thermal mass of the housing minimizes the temperature distortion in the downhole environment. This miniaturized technology simplified logging to a one-person job and shortened the time at the well from multiple hours to a few minutes.
This work describes a novel method of retrieving downhole data, which is a practical and inexpensive alternative to wireline or slickline logging and permanently-installed sensors (Deffenbaugh, 2017). In this paper we present the system design and our recent field results from vertical and deviated wells. We also describe a new application of the Sensor Ball where we perform extended bottom-hole pressure measurements in addition to logging temperature and pressure along the wellbore.
Guyana: Liza Phase 1 Rapid Development in a Deepwater Frontier
Authors: Styslinger Amy , Yost David , Dickerson Gina , Minois Antoine , Wiwel Renee 
Published: August 2021

AbstractThe Liza Phase 1 development project, offshore Guyana, is an unique example of what the offshore oil and gas industry is capable of when working together to deliver a common objective. ExxonMobil and the Stabroek Block co-venturers, Hess Guyana Exploration Limited and CNOOC Petroleum Guyana Limited, commenced oil production from the Liza Destiny floating production, storage, and offloading (FPSO) vessel in December of 2019, less than 5 years from the initial discovery of hydrocarbons in the Staebroek block. With the production and export of its first barrels of oil, the project completed the establishment of a nascent oil and gas industry in Guyana that is poised for tremendous growth in the coming years.The Liza Phase 1 development consists of a 120 kbd conversion FPSO (The Liza Destiny) and a network of subsea infrastructure to produce from and inject in two drill centers. It is expected to develop a resource of about 450 MBO gross estimated ultimate recovery. The water depth ranges from 1,690–1,860 m throughout the development which is located approximately 200 km offshore Guyana.This paper highlights the scope and pace of the project and discusses three specific challenges overcome: the uncertainty of the metocean conditions, extending the application of the selected riser technology, and executing in a challenging and frontier offshore location. A key to the success of the project was the unified approach between stakeholders and the commitment to act as One Team.The Liza Phase 1 project rapidly developed a newly discovered deep water resource in a frontier location while overcoming numerous challenges. By delivering Guyana's first ever oil production among industry leading cycle times, the Liza Phase 1 project has set the foundation for the future of deep water developments in Guyana.
Daisy Chain and Manifold-Based Subsea Architectures for Brazilian Pre-Salt
Authors: Oazen Eduardo Valente , Macauley Lionel Nelson , Sertã Otávio Borges , Siu Christopher Tsi Fen 
Published: August 2021

Abstract
Brazilian Pre-salts fields lie in approximately 2200 m w.d. in a challenging environment and are often characterized by highly corrosive produced fluids that pushed to the extreme the application of the most advanced material technology and engineering. Nevertheless, Lula, Sapinhoá, Mero and Búzios are definitively world-class prospects with production rates that may exceed 30.000 barrels per day per well.
The development scheme of the Pre-salt fields followed the experience and the track record of the large number of deepwater fields that were previously developed in Brazil, in the post-salt regions, and is based on satellite wells tied to the floating production platform by means of dedicated production and service risers (i.e. each well has dedicated production and service lines). This satellite configuration offers the advantage to be simple, straightforward and resilient to field layout changes even during the project execution phase.
However, the continuous pressure to which the Oil & Gas industry is exposed in order to increase profitability, reduce cost and, more recently, green house gas emission is encouraging Operators to evaluate different field architectures that are more traditionally implemented in other deepwater provinces outside Brazil and that the recent technology and construction asset developments made suitable also for a potential application in the Pre-salt fields. Moreover, those field architectures that are normally based on commingling of wells production are also prone to provide a faster production ramp-up and a reduced time to break even.
This paper presents a description of possible Daisy Chain and Manifold-Based subsea architectures that are suitable to be applied to Brazilian pre-salt fields. The pros and cons of these alternative subsea layouts are explored. Additionally, cost and schedule analyses are presented to show the benefits of such architecture regarding CAPEX and ramp-up compared to satellite architecture, considering the "Brazilian pre-salt" scenario. Finally, a generic proposal for subsea architecture is presented for pre-salt developments jointly with practical solutions for typical operation demands related to flow assurance issues like, for instance, wax and hydrate management.