bluuebunny/crossref_metadata_2025_split huggingface dataset:
Realtime Lubricating Oil Analysis to Predict Equipment Failure
Authors: Alabi Oluwarotimi , Wilson Robert , Adegbotolu Urenna , Kudehinbu Surakat , Bowden Stephen 
Published: August 2019

Abstract
Oil condition monitoring for rotating and reciprocating equipment has typically been laboratory based. A technician or engineer collects a sample of lubricating oil and sends this to a laboratory for chemical analysis. After the laboratory has performed the analysis the results are sent to the engineer to make decisions on the health and/or condition of the machinery. This process can take up to 6 weeks, and consequently analysis may end up being performed only quarterly with little likelihood of critical failures being pre-empted. The slowness of oil condition monitoring analyses performed in laboratories has led engineers to substitute for real-time monitoring methods such as vibration analysis and thermography. Nevertheless, the chemical composition of the lubricating oil remains the gold standard for the diagnosis of machine health. The automation of methods for analysing the chemical composition of lubricating oil in real-time would provide engineers with data on the immediate condition of a particular piece of machinery, allowing the early diagnosis of incipient faults.
In this paper, we present a microfluidic technique that can perform real-time continuous monitoring of the chemical composition of lubricating fluid from rotating and reciprocating equipment. Results from this technique both in laboratory and field environments are comparable to conventional laboratory measurements. The microfluidic technique exploits the flow of fluids within micrometre-dimensioned channel, permitting liquid-liquid diffusive separation between otherwise miscible non-aqueous fluids. It can be shown that several fluids e.g. methanol, hexane etc. can selectively extract target components in lubricating oil. Following an extraction, these components can be quantified using a combination of optical techniques, e.g. UV/Vis, Infrared etc. This microfluidic technique has been demonstrated for a range of lubricating oils with several acid, alkaline detergent, asphaltene/insoluble content. This technology can potentially revolutionise the way oil analysis is carried out, automating and making the process rapid and in real-time.
In-Line Robot for Asset Pipeline Inspection
Authors: Carnie Greg , Prathuru Anil , Meng Xiangyin 
Published: August 2019

Abstract
An international Energy Company & independent engineering company have performed preliminary studies for an In-Line Robot (ILR) Project including: feasibility study, turbine design (with CFD calculations and flow assurance) and Energy Balance Assessments. This Robot will be a tetherless autonomous device capable of travelling with/against production flow to accomplish pigging and inspection missions inside pipelines with minimum production impacts. This is particularly adapted for single line long tie-backs, thanks to regenerative power management but the complexity of subsea architecture, flow conditions & fluids services raises some challenges.
The ILR development is programmed over five phases (Feasibility study, Preliminary Systems design & Energy Balance Assessment, Flow Loop Bench Testing, Prototype Testing and Commercialisation). Phase 2 utilised Computational Fluid Dynamics (CFD) simulation models to assess power extraction levels from production flow across various scenarios whilst minimising pressure drop.
The results obtained included the turbine CFD models that were coupled to power conversion and storage modules in order to ensure that system drive and power managementwere captured in a closed loop. An operational envelope was established considering the preliminary turbine design simulations as well as the associated energy balance.
This paper will present the results to date along with the key design features of the ILR and how the data will be used to verify the operational envelope during the next phase, Flow Loop Bench Testing which is due to start in late 2019. This will provide data to configure and predict operational envelopes of the robot for different flow patterns and fluid types.
Qualification Of A Novel Subsea Chemical Injection System
Authors: Leon Christopher , Silva Murilo , Strutt John 
Published: August 2019

Abstract
This paper describes a novel chemical injection system currently under development for long-term use in subsea oil and gas fields, and discusses the process being used to vet subsystems and components, and thereby increase the overall reliability of the system. Once proven and deployed, the system is expected to be a viable alternative to delivery of production fluids via umbilicals in deep water and with long step-outs from host production facilities.
For decades, deepwater engineers have discussed a future in which oil and gas production systems that are typically located on floating facilities, would be placed on the seabed. The resulting subsea factory would include pumping, fluid storage, separation, power management, connections and controls all operating in the marine environment. While these technologies have proven to be reliable in the topside environment, and some have been used for short-term intervention, to date only boosting and separation systems, subsystems and components have been qualified for long-term installation on the seafloor.
This paper details how the Technology Qualification Program, defined in the second edition of API RP 17Q, has been applied to qualify the novel subsea chemical injection system. The paper describes how the performance requirements were defined, together with their reliability implications, and provides examples of qualification activities.
Towards a Digital Twin Supporting Risk Based Decision Making for Offshore Installations
Authors: Murray Paul , Wattis Zoe , Bain Brian , Golowczynski Mike , Sadd Alf 
Published: August 2019

Abstract
Risk Assessments are used to assess the impact of alternativedesigns, changes during operations, and compliance of offshore installations against tolerabilitycriteria. Typically, asset information is used to develop a mathematical model; this can beupdated to reflect changes during the facility's lifecycle. This paper examines how the use ofcloud-based technology to develop a Digital Twin improves efficiency. Allowing projectstakeholders full access to the QRA model also enables greater understanding of hazards.
Digital technology pervades all areas of business and societyand offers great advantages to safety engineering relative to traditional approaches. This paperdemonstrates how cloud basedtools canturn the traditional static QRA process into a living QRA which can be updated throughout aninstallation's lifecycle by creating a digital twin. This type of living QRA allows projectstakeholders to change key parameters and assess the effect of these changes on risk levels. Inaddition, the results can be interrogated down to fundamental levels using a Microsoft Power BIdashboard.
The output of QRAs are usually static reports providing anoverview of the detailed work undertaken and a high-level summary of the results which arecompared with tolerability criteria or to demonstrate ALARP. This paper demonstrates howcustomised internet browser tools utilising 2D and 3D graphics may be built on top of the QRA toextract more detail than previously possible and communicate risks in a flexible and interactiveway. It also shows how consistent data management can form a basis for innovating beyond thetraditional approach. This allows a wider range of stakeholders to determine risk drivers, isolatesingle accident scenarios and filter results to a greater depth than is possible through a paperreport and allow a greater understanding of their hazards.
Digitalisation is an increasingly ‘hot topic’ in the process industry. Making use of new technologies to provide greater insights can aid in better and more timelyhazard management whilst reducing costs to stakeholders. Examples of innovations which promote better assessment are provided.
AR and VR Applications Improve Engineering Collaboration, Personnel Optimization, and Equipment Accuracy for Separation Solutions
Authors: Clarke Stephen , Kapila Ketan , Stephen Mark 
Published: August 2019

Abstract
With the most recent industry downturn still fresh in many minds, the oil and gas E&P sector is approaching this recovery with a commitment to long-term cost discipline. As a result, augmented reality (AR) and virtual reality (VR) technologies are being adopted by operators and service companies alike as a means of cost savings while driving operational efficiency.
AR technologies employ enhanced visualization hardware, techniques, and methodologies to create new environments wherein digital and physical objects and their data coexist and interact with one another, enhancing the user experience of the real world (Kunkel and Soechti 2017). VR refers to the full immersion of the user intoand interaction with a completely digital environment. Together, these technologies form the core of immersive experience and a new paradigm in industrial interaction.
Until recently, these technologies were primarily applied as enhanced entertainment products, most notably within the gaming industry. However, during the past several years, and thanks to the introduction of hands-free, head-mounted display (HMD) technologies, such as Microsoft® HoloLens™ and now HoloLens 2, AR and VR are migrating into the enterprise sector.
While the oil field has not been as quick to integrate AR and VR as other sectors, such as medicine, defense, and aeronautics, operators and service providers alike have increased adoption overthe past 12 months. Motivated by a mandate to keep operating costs low and improve efficiencies in terms of field processes, operators have begun implementing AR/VR applications as collaborative problem-solving, planning, and design tools.
For example, some operators are initiating ARconcepts to promote internal use development and prototyping for both oilfield applications and remote refinery inspections. Additionally, service companies are embracing the use of smart glasses and wearable technologies to help improve remote work and collaboration to help increase in-field safety and reduce downtime.
As part of its strategy to help drive the oil and gas industry's digital transformation, one major service provider is developing AR/VR applications to create digital representations of physical oilfield assets on the Microsoft® HoloLens device. One area of focus is the planning, design, and deployment of solids control, fluid separation, and handling technologies for offshore drilling applications.
Removal of Magnetic Metallic Contamination – Improved Drilling Fluid Performance
Authors: Saasen Arild , Pallin Jan Egil , Ånesbug Geir Olav , Lindgren Alf Magne , Aaker Gudmund , Rødsjø Mads 
Published: August 2019

Abstract
Different logging operations can suffer from presence of metallic particles in the drilling fluids. Directional drilling in Arctic areas can be a challenge because of magnetic contamination in the drilling fluid. This is a challenge especially when drilling east-west relative to the magnetic north direction. Magnetic and paramagnetic particles in the drilling fluid will shield the down hole compasses and introduce additional errors to the surveying than those normally included in the uncertainty ellipsoid. The objective of the project is to remove the magnetic particles being the largest contributor to this error.
On many offshore drilling rigs there is mounted ditch magnets to remove metallic swarf from the drilling fluid. These magnets will normally only remove the coarser swarf. In this project we use a combination of strong magnets and flow directors to significantly improve the performance of the ditch magnets. This combination, together with proper routines for cleaning the ditch magnets significantly helps cleaning the drilling fluid.
By the combined use of flow directors and ditch magnets it was possible to extract more than five times as much magnetic contamination from the drilling fluid. This is verified by comparing the ditch magnet efficiencies from two drilling rigs drilling ERD wells. The logging tool signal strengths of several down hole instruments were unusually good and insignificant down times were observed on the logging tools. The results are anticipated to have aided to the directional drilling performance.
Detailed information on how to clean the drilling fluid properly from magnetic contamination is presented. It is also shown that this cleaning is significantly better than conventional cleaning of magnetic debris from drilling fluids.
Kaombo Field Thermal Performance Test; A New Reference
Authors: Rolland Julien , Henneuse Xavier , Balagué Benoit , Jackson Mark 
Published: August 2019

Abstract
The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.
A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.
The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.
A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.
Surfactant Stimulation Results in Captain Field to Improve Polymer Injectivity for EOR
Authors: Jackson A. C. , Dean R. M. , Lyon J. , Dwarakanath V. , Alexis D. , Poulsen A. , Espinosa D. 
Published: August 2019

Abstract
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.
Enhancing Industry Subsea Well Intervention Response Capabilities
Authors: Munro Neil , Myers Andy , Lund Chris , Neate Roger 
Published: August 2019

Abstract
Nine years have passed since the Deepwater Horizon disaster and industry is in a considerably better position to respond to a loss of well control of that scale. With the delivery of the Offset Installation Equipment (OIE) in January 2018 the joint industry Subsea Well Response Project (SWRP) has drawn to a close. Despite this, equipment and services continue to be developed. This paper will communicate developments in subsea well response technologies and the latest guidance developed by industry.
This paper provides an overview of the International Oil and Gas Producers (IOGP) Report 594 - Source Control Emergency Response Planning Guide for Subsea Wells. What should a comprehensive subsea Source Control Emergency Response Plan (SCERP) consider? What resources including manpower, expertise and equipment would be required for a controlled response? In addition, it provides an overview of recent enhancements in subsea well response equipment. This includes; offset installation equipment (OIE) for shallow water scenarios where vertical access above a wellhead may not be possible and air-freight capping stack solutions to minimise incident country configuration and testing.
The findings from technical and logistical studies, whilst developing this technology, will be clearly communicated for industry consideration. This includes critical activities to be considered in developing response times models. This paper will demonstrate that capping equipment located in country does not necessarily improve the overall response time for a loss of well control event; an effectively planned response is more important than immediate hardware availability. The importance of mutual aid of personnel and equipment in a response will be key as not one company can provide all the solutions.
Although only required for remote or land locked basins, to further enhance industries capabilities, it has recently been demonstrated that existing ram based capping stacks can be transported by air, without disassembly, and thereby maintaining pressure boundaries. This allows for a more rapid air mobilisation to the incident location without the need for major re-assembly upon arrival.
Predictive Digital Twins for Structural Integrity Management and Asset Life Extension – JIP Concept and Results
Authors: Knezevic David , Fakas Emmanuel , Riber Hans Jorgen 
Published: August 2019

Abstract
This paper presents a Digital Twin concept aimed at assets in the oil & gas and wind industry, that provides an accurate estimate of the true fatigue life of these assets in order to unlock potential fatigue life and ultimately extend the life of assets. This concept is divided in four tiers that allow to unlock remaining fatigue life one after the other. The first tier consists of using a high-resolution finite element model of the asset, delivered by Akselos unique RB-FEA technology. The subsequent tiers consist in using data from a few strategically placed accelerometers, as well as wave radar recordings, in order to calibrate the model and estimate the real loading on the asset. This concept delivers a true digital twin of the asset and offers a compelling and cost-effective method for offshore assets that are facing life time extension beyond what current methodologies can provide. The concept is being implemented on one of Shell's platforms in the Southern North Sea.
A New Flow Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset
Authors: Hatscher Stephan , Ugueto Luis 
Published: August 2019

Abstract
The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows re-use of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.