bluuebunny/crossref_metadata_2025_split huggingface dataset:
Damping Identification from Measurement of Axial Riser Response Data
Authors: McNeill Scot , Stahl Matt , Bhalla Kenneth 
Published: April 2018

The current water depth record for offshore drilling is approximately 11,000 feet, with several energy companies having leases in substantially deeper waters. For a typical drilling riser and BOP stack, the first axial resonant period is approximately one second for each 2000 feet of deployed length, thus five seconds for 10,000 feet, six seconds for 12,000 feet, etc. Therefore a resonant condition will occur with vessel heave response in very deep water. The weight of a long drilling riser and BOP stack, together with large predicted dynamic loads can lead to significant restrictions on riser running and retrieval. Under resonance, the response levels are influenced greatly by the damping levels, which are uncertain. Total predicted damping from previously quantified sources is less than 1% critical. This work demonstrates that significantly more damping exists.
In this work, the damping ratio is identified for the first axial riser mode using several sets of measured riser response data. Data sets were obtained from several drilling rigs during riser deployment or retrieval at sites in various water depths, using an assortment of transducers and data acquisition systems. Within each data set, the deployed riser length varies over time.
Measured riser response data sets from load cells and accelerometers, have been analyzed to determine the first axial riser natural frequency and associated damping ratio using robust identification methods. Damping ratio values are presented for each data set. This effort has found a fairly consistent level of damping across the range of water depths, vessels and drilling riser systems for which data is available. Importantly, the damping values are significantly higher compared to calculated values traditionally used in axial dynamic riser analysis. To illustrate the methodology and support the resulting damping ratios, time history and spectral plots of the measured data are also examined.
To the authors’ knowledge, this effort represents the first set of published results on axial riser mode damping from full-scale measured data available in the literature. The findings are significant because they reduce uncertainty in the level of dynamic hook load fluctuation to expect when deploying a riser and BOP stack to extreme water depths. Conservatism in engineering assessment can be reduced substantially. However, this work also shows that the level of damping is still small enough that axial dynamic response will be a significant consideration for large water depths.
Enhance Flow Assurance in Large Diameter Gas Flexible Pipes
Authors: Lefer Bruno , Phelut Renaud , Decuupere Matthieu , Legeay Sébastien 
Published: April 2018

Abstract
Large gas field developments are an important trend of the oil and gas industry and is likely to be reinforced in the next decades. For these developments, flexible pipes with larger Inner Diameter (ID) and high flow rates are more and more required. This paper presents solutions developed to improve flow assurance in gas flexible pipes by assessing and removing flow induced pulsations (FLIP) risk occurrence and optimizing the maximum allowable flow rate.
This trend leads the industry to have a kind interest in FLIP free flowlines and risers as well as in flexible pipes with improved flow rates capacities for equivalent diameters. Beginning of the 2000’s smooth bore gas export flexible riser was a pioneered FLIP free solution which is now a well-known, field proven and recognized technology. In addition, the market and industry trend have led to develop a full panel of solutions to answer new market requirements: FLIP and pressure losses methodologies, appropriate selection of conventional carcass and smooth bore flexible pipes (smooth carcass & plastic smooth bore).
This paper describes the different solutions to enhance the flow assurance of flexible pipes for gas applications (less pressure losses & FLIP proof) with different flexible pipes solutions. Then a focus is done on the development of a cost-effective solution applicable to all types of pipes: the smooth carcass. This new carcass is an incremental improvement of existing technology. The industrialization, prototype manufacturing, qualification program and technical performances obtained so far including FLIP aspect, pressure loss and global mechanical behavior are detailed. Results have demonstrated that the smooth carcass allows reducing the pressure losses compared to flexible pipe with standard carcasses and thus to optimize the fluids flow rates or to reduce the flexible pipe internal diameters. Complete API 17J qualification compliance is planned for end 2018 for both static and dynamic applications.
Specific dedicated competencies and technologies were developed to answer market requirements of the new gas field developments. Furthermore, the development of smooth carcass will tackle the singing phenomenon on gas flexible lines, and provide an optimized solution for flow assurance improvement to oil and gas operators.
Efficient Condensate Mercury Removal Offshore
Authors: Manelius Tom , Aguedach Imane 
Published: April 2018

Abstract
There are Oil & Gas installations struggling with Mercury contaminated oil and gas streams. Mercury contaminants are not only toxic if exposed to staff, but it can also cause equipment damages and operational hazards. It is most often seen as an issue in the natural gas, especially in liquefaction operations, but there is an increasing interest and need to handle contaminated condensate streams, as well as glycol streams (MEG). The Mercury content in Oil & Gas streams vary significantly over the globe, even between specific fields. The Asia pacific region is generally known to be the most exposed, with Mercury levels often up to 100 times greater as an average, than in e.g. US or Canada
Mercury rich wet gas wells will also have Mercury contaminated condensate, with Mercury present in different states and often adsorbed to other suspended particles. Up to now filtration processes for Mercury removal in condensate streams has primarily been used, however the presence of very fine particles, and Mercury levels in average several times above the target level, made filtration a troublesome offshore operation. In pursuit of better technologies, an improved solution has been found in disc stack centrifuge technology. The suitability has been assessed by using a fast and well-developed assessment process including laboratory tests and field pilot tests followed by full scale centrifuge installations.
Particle sizes can be measured as a part of site testing. Mercury contaminants are typically small, often Hg resides in a relatively narrow particle size range, between 1–10 m micron, which explains why sufficient removal at process scale a can be achieved by filtration, but also why operation may be a challenging task with frequent filter blockages. A centrifuge processing system represent a separator option readily removing the Mercusry particle size range, including submicron particles, and can be made fully continuous, sealed and sized to handle required condensate flow processing. In average the stream leaving the centrifuge is found to be well below the acceptance level, moretowards concentrations typical for dissolved rather than particulate mercury level.
Qualify, Verify and Demonstrate Robust Synthetic Mooring Lines to Reduce Costs
Authors: Hansen A. B. , Ekrem S. , Larsen K. , Gabrielsen Ø. 
Published: April 2018

Abstract
Use of synthetic fiber ropes for mooring system components has many advantages. Reduced floater offset and simpler riser solutions, increased floater payload due to low weight and improved HSE performance due to easier handling and installation all lead to reduced cost for field development projects. All these aspects are important for deep water fields, to enable anchoring of MODUs adjacent to existing facilities or to reduce cost of floating wind turbines.
In addition, use of synthetic ropes may reduce life cycle cost as durability is increased and degradation mechanisms like corrosion and wear are reduced compared to steel components. However, one remaining technical challenge of synthetic mooring lines is to increase their resistance and robustness against external damage and abrasion. Functional requirements like pre-laying on the seabed and resistance against fish trawl impacts are being specified in several applications. This paper summarises the executed development and qualification work to increase robustness of synthetic fiber ropes against external impacts.
Case History: A New Approach to Section Milling: Leaving the Swarf Behind!
Authors: Nelson Jonathan F. , Jørpeland Jon-Tore , Schwartze Corinna 
Published: April 2018

Abstract
Section milling is a method used in plug and abandonment operations to remove casing over a specified interval, enabling a barrier to be placed for complete isolation across the wellbore. This method is preferred and often required when an annulus behind a casing string is not properly isolated and cannot be appropriately remediated by conventional methods such as cutting and pulling the casing, or squeezing cement through perforations.
Section milling and placement of a rock-to-rock cement barrier is a highly effective method for achieving proper wellbore isolation for plug and abandonment. However, this method poses unique challenges that can result in lengthy, complex operations and high costs to operators. A key challenge faced when removing high volumes of casing (up to and exceeding 50 meters (165 ft.) per interval), is circulating the generated steel cuttings (swarf) out of the well, and safely capturing and disposing of them. Much of the time spent on section milling operations is dedicated to mitigating the health, safety, operational, and equipment risks associated with the removal and handling of swarf in the well and on surface. These challenges inspired a joint operator/ service company project to develop a method of section milling that would deposit swarf into the wellbore, creating a unique, and in-situ approach to debris management that reduces risk and costs to the operator.
The prototype section milling system was extensively tested, with final, full-scale tests performed in a drilled and cased hole from a fully functioning land rig. Conclusions from the final test well operations yielded favorable results, resulting in a final system design that was qualified for field use. Currently, the system is in final preparations for its first field deployment, with candidate wells identified and equipment ready for use. First planned operations are scheduled for a platform well on the Norwegian continental shelf.
This paper will detail the final testing phases, field trial preparations, and candidate well selection leading up to the first field deployment of a first ever ‘swarfless’ section milling system.
Leveraging Field Intelligence Through Operational Certainty: How Automated Operating Practices Deliver Industry Leading Results
Authors: Jimenez Jose A. , Zornio Peter 
Published: April 2018

Abstract
The oil and gas industry loses approximately $300 billion profit annually to poor operating performance. Outdated technologies and work practices are largely to blame because they lack the predictive capabilities of modern automation. When oil and gas producers adopt modern technologies and adjust work processes, they can recover a significant portion of these losses and realize top quartile performance in production, reliability, and safety. Examples illustrate this.
In response to low commodity prices, the oil and gas industry has rationalized operations and procedures over the last few years. However, estimates are that the industry still loses hundreds of billions of dollars annually to poor operating performance. Much of that can be recovered by emulating the practices of the industry's best performers. The top quartile of oil and gas producers deploys technology, processes and people in a purposeful orchestration to boost production, cut costs and improve safety. They define a strategy, analyze inefficiencies, prioritize opportunities, and then select technologies that can scale and leverage existing investments. Doing this substantially boosts the bottom line.
Project R.E.A.D.S. RFID-Enabled Aerial Detection System: Providing Realtime Safety Information During Offshore Emergencies
Authors: Taylor Starr LaTasha , Bharadwaj Bommireddipalli Shashank , Ram Devaraj Pranesh 
Published: April 2018

According to the Bureau of Safety and Environment Enforcement (BSEE), injuries, fires and explosions on the outer continental shelf (OCS)[1] are the majority of incident types reported for fiscal year 2016. Although the number of incidents/spills have reduced over a span of 7 years (2009-2016) there is still a need to reduce casualties to human life and property that occur because of inadequate response techniques.
Offshore Oil and Gas drilling operations involve numerous occupational hazards and activities that could possibly harm or potentially lead to the death of personnel onboard during an off-shore emergency [1]. One such tragic event is Gulf of Mexico case study, where emergency responders were unable to track and rescue 11 workers involved.
The main objective of the project is to equip emergency responders and safety officers with appropriate tools needed to track crew members and launch a targeted evacuation rescue effort when an accident occurs in an offshore oil rig. The drone’s advantage of proximity as well as maneuverability enables detection of Radio Frequency Identification (RFID) tags, providing real-time location. The tags will also provide health status information of onboard personnel from a safe distance and assist with providing responders with the decision-making tools necessary for proper prioritization of response efforts.
Other safety information such as live visual feed and temperature profiles through thermal imaging will also be available to the emergency responders. This will assist responders in their effort to assess the severity and criticality of the situation and develop a rescue strategy. With the assistance of Project R.E.A.D.S. (RFID-Enabled Aerial Detection System), the rescue efforts would be more efficient and effective in saving lives because of the drone’s ability to accurately detect personnel via a system of readers attached to drones and tags strategically located on crew member clothing.
Enabling Longer and Cheaper Subsea Tie-Backs Utilizing Local Subsea Chemical Storage and Injection
Authors: Schroeder Art J. , Chitwood James E. , Gay Tom A. , Bahr Jeffrey , Brennan Kevin , York Matt 
Published: April 2018

Abstract
Strong economic drivers coupled with proper technical qualification of new equipment/methodologies are compulsory for industry adoption, especially with deepwater systems. This paper presents compelling economic findings from case study analysis that local, subsea chemical storage and injection can deliver significant savings compared to host platform storage and tube-based umbilical delivery. It then outlines a systematic approach developed for system qualification. Successful deployment of this new technology will greatly facilitate development of hundreds of smaller deepwater resources and billions of barrels (bbl) of oil equivalent (BOE) by enabling safe, cost-effective long distance tie-backs to existing infrastructure out of traditional reach of tube-based umbilicals.
Deposition and Shear Stress Initial Investigations for Hydrate Blockage
Authors: Aman Zachary M. , Qin Hao , Pickarts Marshall , Lorenzo Mauricio Di , May Eric F. , Koh Carolyn A. , Zerpa Luis E. 
Published: April 2018

Abstract
Over the past decade, the paradigm of gas hydrate research has transitioned from avoidance via thermodynamic inhibition toward management, where a limited amount of hydrate may be allowed to form in the flowline. This new paradigm enables new field development concepts, including longer-distance subsea tie-backs and limited chemical inhibition. This presentation reviews research datasets from flowloops on hydrate deposition phenomena and includes an initial analysis on the impact of shear stresses on hydrate deposits.
This study integrates experimental data from unique high-pressure laboratory flowloops, including single-pass, gas-dominant and recirculating, liquid-phase flowloops. The flowloops have visual observation ports that allow video imaging to be performed throughout the high pressure tests. These apparatuses together are estimated to provide coverage over 1-200 Pa of flowing shear stress at the wall, over a range of total liquid inventories and water holdup.
For this work, conceptual diagrams of deposition in oil, water, and gas-dominant systems are presented. Film growth rates are derived at the Colorado School of Mines (CSM) from visual observation in a deposition loop. Hydrate particle deposition rates are determined from a gas-dominant flowloop in Western Australia by fitting experimental data obtained from gas-dominant systems. The results demonstrate that the absolute shear stress required to prevent hydrate particles from depositing at the wall, or to remove/slough deposited hydrate from the wall, can vary with the primary fluid phase. Initial shear stress calculations from a specific test estimate that less than 5 Pa can be required to remove/slough hydrates from the wall in the aqueous phase, while more than 100 Pa may be required in a gas-continuous pipeline. This review suggests that deposition and flowing shear stress may be critical considerations in the design and operation of hydrocarbon systems, to help prevent hydrate blockage in industrial operations.
Concepts and Strategies for Developing Bankable Floating Production Solutions for Gulf of Mexico
Authors: Adil Adam 
Published: April 2018

Abstract
This paper explores concepts and strategies around field development models as well as financing avenues that will structure the capital outlay in a manner that helps improve the economic viability of deep water projects. The long cycle time for development resulting from the exhaustive Front End Loading (FEL) efforts in the traditional development models tend to deteriorate the economic value of an average deep water development.
The main areas of focus will be:Field development and project delivery strategies that are aimed to deliverStructural changes that aid in sustainable cost reduction for developmentCycle time improvements balanced against project delivery certaintyNon-traditional project financing strategies and models that explore:Deferred CAPEX solutionsField equity solutions
Development of an API 17TR8 Compliant 18-3/4 Subsea Wellhead System rated to 20,000 psi and 350°F
Authors: Phillips Ryan , Tooley Keegan , Bingham Fred , Rodriguez F. Justin 
Published: April 2018

Abstract
As the industry progresses into deeper waters with reservoirs that require more complicated well designs, there is an increasing need for equipment that can withstand higher pressures, temperatures, casing loads, and structural and cyclic loads. A 20,000 psi 350°F rated 18-3/4″ wellhead system has been developed to meet those needs. The system was designed and qualified to API 17TR8 with the addition of rigorous internal design and testing requirements. The system design is based on the field-proven technology of a legacy 20,000 psi 350°F 18-3/4″ wellhead system (reference OTC paper 19694) which completed development in 2008, prior to the release of API 17TR8. This API 17TR8 compliant wellhead system can support a total of 4,400,000 lb of casing weight inside the high-pressure wellhead housing, including up to 2,400,000 lb of intermediate casing weight in the first position and up to 2,000,000 lb in the second position. The system is provided with annulus seal assemblies (ASA) designed and tested through an extensive qualification plan made up of industry required testing in addition to testing identified by a detailed Failure Modes, Effects, and Criticality Analysis (FMECA). Operators can install and test the first position and second position ASAs, up to 20,000 psi, in a single trip with the use of a specially designed single trip tool. A spring-loaded tool and wear bushing also allows the operators to test the blowout preventer (BOP) to 20,000 psi while isolating the ASAs. The design of each component involved detailed elastic-plastic finite element analysis (FEA) per ASME BPVC Sec. VIII, Div 3 and a rigorous qualification plan generated through the FMECA process. The goal of this paper is to provide an overview of the development (verification and validation) of the 20,000 psi 350°F wellhead system per API 17TR8 and the independent third party (I3P) review as required by BSEE for an HPHT wellhead system.
Building Cloud Services for Monitoring Offshore Equipment and Operators
Authors: Tang S. , Wang R. , Zhao X. , Nie X. 
Published: April 2018

Abstract

Objective/Scope
A cloud based platform is being built to create and maintain a machine's digital twin model, based on the as-built information and the operating data fed from the machine control system. By making the cloud based machine services available to most offshore operators, this platform has the potential to help monitor machine conditions and operator performance at a relatively low cost.

Method, Procedure, Process
Firstly, the cloud digital twin model serves as a vault to store the up-to-date machine data on the cloud for easy access by various parties from different locations. Secondly, when it is connected with a machine control system through a network gateway, operating data can be fed continuously to the cloud platform, enabling the cloud based analytics to digest and derive insights about the conditions of the machine, the performance and behaviors of operators, and the recommended maintenance schedule.
Equipment performance grade is used as indicator of equipment performance.

Results, Observations, Conclusions
Many modern machine controllers have built-in database capability and are connected into a network with an internet gateway. This makes them ideal for working with cloud services to improve on remote monitoring, trouble shooting and maintenance scheduling.
Two application examples, covering a typical drilling system and a crane, are presented. By publishing the up-to-date machine digital twin data on the cloud, which is to be consumed by any computer with internet connection, this platform could help operators streamline operation and maintenance activities, as well as reducing the costs due to the reduced number of site visits by technicians and the lowered expenses following a more optimized maintenance schedule.

Novel/Additive Information
The technologies for this platform are well developed with successful applications in many industries. This cloud platform was initially envisioned to be incorporated in our offshore drilling system and crane offerings to facilitate data sharing and trouble shooting of offshore equipment without sending technicians to site. The same cloud services can be used by operators with equipment from other vendors, with some adjustments on the network interfaces.