bluuebunny/crossref_metadata_2025_split huggingface dataset:
Standardized Test Cell Design Using Qualified Analytical Computer Modeling of Unplanned High Pressure Releases
Authors: Mann Michael , Wieczorek Dave , Skeels Brian 
Published: May 2011

Abstract
The oil and gas industry is continually demanding products that operate at increasing pressures and temperatures; frequently completion equipment, including wellhead systems and valves now require up to 20,000 psi (138 MPa) working pressures and factory acceptance test pressures up to 30,000 psi (207 MPa). As operators assume projects in greater water depths, deeper wells and more extreme temperatures, some completion product extensions will eventually require extreme working pressures of up to 30,000 psi (207 MPa). Currently, water and gas mediums are typically utilized to perform factory acceptance pressure tests to verify product integrity. Consequently, as the industry migrates to higher pressure and temperature applications, oil and gas service equipment poses increasing potential risk to personnel in the event of an unplanned pressure release. Therefore, utilizing qualified standardized shielding can be a key method in mitigating personnel and environmental impacts. Historically conservative mathematical models have been constructed to understand the behavior of a high pressure release and the adequate shielding to contain it. This paper details the development of standardized enclosures or " test cells?? using advanced computer simulation software to model energy imparted from the flow characteristics of a gas blast, in addition to the energy from a projectile during the event of an unplanned pressure release. The resulting computer model simulation comprised of both Computational Fluid Dynamic (CFD) and mechanical Finite Element Analysis (FEA) simulations is then validated through testing of a pressure release up to 30,000 psi (207MPa). Once the computer model is validated, it can be utilized to determine minimum shielding requirements for varying high pressure testing applications.

Introduction
Pressure testing in the oil and gas services industry is often used to verify the product integrity. In addition to product design, an engineer must also design a test and corresponding equipment to ensure the safety of the personnel performing the respective scope of work. As the potential failure modes become increasingly catastrophic with higher pressures, the utilization of models that can accurately account for the cumulative impact of energy imparted from the combined effects of a projectile and corresponding gas blast is critical. This type of analysis is complex, as often times the behavior of an unplanned pressure release is impacted by many key variables:Initial distance from the shieldTest volume and fluid characteristicsTest pressureProjectile material and sizeProjectile interface characteristics with the test body
Test parameters and conditions vary considerably in the oil and gas service industry, and modeling each individual test case for shielding evaluation is not feasible. Therefore, defining standardized enclosures which can be utilized across the industry can be a streamlined approach for improving personnel safety in the field.
High Active, Dispersion Based Paraffin Inhibitors for Subsea Applications
Authors: Huijgen Martijn C. , Grondman Herman , Oschmann Hans-Joerg 
Published: May 2011

Abstract
Production of waxy crude oils can be challenging due to increased viscosity, restart issues and wax deposition. Due to a decrease in solubility of high molecular weight paraffins in waxy crude oils with decreasing temperature, paraffins precipitate and deposit on pipeline walls or form a 3-dimensional network in which liquid oil becomes trapped. Even for crude oils with low to moderate wax content, where viscosity and restart issues may not be a critical factor, deposition could be a huge problem when (subsea) flowlines are being affected and flow restricted.
Among other options available, chemical treatment with pour point depressants and / or paraffin inhibitors is used to impede wax related problems. Specific high molecular weight polymers, changing the wax crystallization process are commonly used as the active components in these pour point depressants and paraffin inhibitors. The products are formulated in solvents to allow for easy pumping and injection.
To achieve interaction with crystallizing paraffins, functional groups of the polymers are similar to wax and as such the polymers themselves are difficult to dissolve. Particularly for application in deepwater, subsea or cold climates, low active formulations are used which require high dose rates.
To overcome these typical problems, dispersion based products have been used for a number of years. High active dispersion base products have been successfully applied in land based operations as well as topsides offshore. New developments in formulating dispersion based PPDs and Paraffin Inhibitors has resulted in products suitable for subsea injection. One of these new environmentally friendly developments was proposed for inhibiting wax deposition in a subsea tieback in the Norwegian sector of the North Sea. Following lab evaluations that confirmed the performance of the product, the product has been successfully applied through a subsea injection line. This paper will discuss development, practical application and benefits of such products.
Nuclear Industry Concepts for Safety and Performance Management and Application to Offshore Operations
Authors: Nelson Bill 
Published: May 2011

Abstract
The commercial nuclear power industry has developed and applied improved methods for safety and performance management since the accident at Three Mile Island (TMI) in 1979. These include methods for risk management, identification and application of lessons learned, risk informed regulation, and safety culture improvement. Methods have also been developed to identify strategies and procedures to manage severe accidents - e.g. events outside the design basis that formed the envelope for the initial operating license. The combined implementation of all these technical, organizational, and regulatory changes has led to a significant industry-wide improvement in the performance of nuclear power plants in the US since TMI. This paper summarizes these developments in the nuclear industry, describes a recent application to risk informed safety culture assessment for a Canadian nuclear power station, and explores the potential to apply these methods for design, operation, and regulation of offshore facilities as part of the industry response to the Deepwater Horizon accident.

Nuclear industry practices prior to Three Mile Island
From the beginnings of the commercial nuclear power industry in the United States in the 1960's the primary unifying concept for demonstrating safety was the Design Basis Accident (DBA). A design basis accident is a postulated event that the plant must withstand. The Safety Analysis Report (SAR) for each facility was required to demonstrate that the plant could withstand the occurrence of specific prescribed DBAs. Examples include loss of coolant accidents (LOCAs), reactivity accidents, steam generator tube ruptures, loss of offsite power, etc. In addition to forming the basis for demonstrating that the plant could be operated safely within a prescribed " safe operating envelope,?? DBAs also established (perhaps inadvertently) the basic paradigm for the development of emergency operating procedures. Similarly, the design of instrumentation was intended to provide information up to but not beyond the conditions expected during a Design Basis Accident. Hidden within the emergency procedures were the assumptions that plant operators would be able to accurately diagnose the event in progress, and their major role would be to monitor the performance of automatic systems and only intervene when automatic systems failed to actuate or to restore normal conditions once the automatic systems had carried out their assigned functions. Finally, there was likely an unconscious assumption that events more serious than the design basis accident would not (or perhaps could not) occur, and that if a plant could withstand the DBAs then safety was assured for other conceivable accident sequences. Unfortunately, as we shall see later, these numerous, often unspoken assumptions were fundamentally flawed.
Overview of the SAFEBUCK JIP
Authors: Bruton David A.S. , Carr Malcolm 
Published: May 2011

Abstract
This paper summarizes key areas of research and development undertaken by the SAFEBUCK Joint Industry Project (JIP), including the development of engineering models and the testing of pipe-soil interaction, fatigue and local buckling.
The SAFEBUCK Joint Industry Project set out to address one of the key design challenges for pipelines - buckling due to the compressive forces created by internal pressure and temperature - by supporting and guiding a design approach that deliberately encourages pipelines to buckle, but in a controlled way. By controlled initiation of lateral buckles at regular intervals, the loads are shared and reduced at each buckle site. Early application of this idea was hounded by problems due to a lack of know-how, which led to a number of failures, including three full-bore ruptures and one abandonment, mostly due to the issue not being addressed correctly in design. A related challenge addressed by the JIP, is pipeline walking, which has been observed on a number of pipelines, leading to one failure and a number subsea interventions to prevent future failure.
With the JIP now entering its third and final phase, the design guideline and research findings have been applied on a number of projects. This is therefore a good opportunity to present the SAFEBUCK design methodologies and research to a wider audience, and outline work underway now, in the final phase. A series of papers follow in the same session at OTC 2011, to provide more detail on the SAFEBUCK Design Guidance, research findings and the practical application of this technology to the lateral buckling and walking of pipelines.
How MPD with Advanced Flow Detection System was successfully applied on an eHPHT Well in the Norwegian North Sea
Authors: Naesheim Sigve Krohn , Lefdal Frode , Oftedal Tor Oyvind , Sveinall Henrik 
Published: May 2011

Abstract
This paper will describe an actual field example of how a Managed Pressure Drilling (MPD) system was successfully used onboard the Heavy Duty Jack Up (HDJU) " Rowan Gorilla VI?? to successfully drill the Mandarin East eHPHT exploration well on the Norwegian Continental Shelf. The well is the most extreme well with regards to temperature and pressure ever drilled in Norway. The primary premise for the use of MPD in this case was that the well was always to be in statically balanced/ over balanced condition.
The well was drilled to a TD of 5933m MD RKB in formation of Triassic age. The wells location was carefully selected to avoid seabed conditions with high risk of punch through for the legs of the jack up rig and also to avoid potential accumulations of shallow gas pockets in the area. Although there were some offset wells in the area, the " Mandarin East?? well was going deeper than any of the offsets and, hence, had to be treated as a rank wildcat with regards to both geology and pressure.
Pressure evaluation and kick detection was viewed as very critical to the well success as the estimated surface pressure was very close to 15,000 psi. The most important factor in the well design was to get the 9 7/8?? production casing shoe as close to the potential reservoir as possible to obtain a fracture gradient that allowed for drilling the 8 ½?? hole section to TD with very narrow margins between the pore pressure and the fracture pressure. As experienced on most conventional HPHT wells, also the " Mandarin East?? well was expected to face significant well bore breathing challenges.
The rig RGVI belonging to Rowan Drilling is a Super Gorilla design jack up rig and it is very well equipped with regards to suitability for HPHT drilling. Prior to spudding the " Mandarin East?? well, the RGVI had recently drilled two eHPHT/HPHT wells in UK and the crews were already familiar with standard HPHT procedures.
Based on the drive to enable drilling an 8 ½?? hole to TD to facilitate a DST test in a discovery case and to, potentially, save time and cost in handling kicks and well bore breathing issues, it was decided to utilise Managed Pressure Drilling (MPD) equipment that used a closed circulation system, a Coriolis flow meter and flow detection algorithms to provide an early kick detection system.
This paper highlights the rig preparations made to accommodate the use of MPD equipment and the importance of structured and organised management in the rigorous process of preparing " tailor made?? procedures and training/preparing the rig crews for operating outside the " normal?? HPHT procedures. Furthermore, the paper highlights the experiences and many lessons learned after successfully drilling the eHPHT well " Mandarin East?? to TD. It is estimated that the MPD system saved 10 days of rig time/ US $ 7.5 million in addition to the improved HSE aspects of using this system.
Advances and Impact of Software-Based Deepwater Blow Out Preventer Testing
Authors: Franklin C. Mark , Sargent Timothy L. , Brown Charles Ray , Owen Gary , Griffith Steve , Osmond Jeremy Warwick , Gronas Tore , Cully Richard 
Published: May 2011

Abstract
To advance the technology of BOP leak detection through a software development initiative, operators, service provides, and drilling contractors established an industry consortium in early 2009. The initial development focused on the testing of BOPs in deepwater. Upon completion of the pilot program on five deepwater rigs, the results exceeded original expectations. The test results proved the software was effective, efficient, and rig friendly. Once a test plan was constructed, with the click of the " Start?? button, the software was completely automated, up to the time of printing the report.
Through an iterative and collaborative process, a unique solution for the Low Pressure (LP) and High Pressure (HP) BOP testing has been developed. For example, due to the constraints and subjective nature of the current Circular Chart Recorder (CCR) methodology for validating a test, a small leak may not be identified for up to 30 minutes into the HP test. With this new methodology, objective identification of a slow leak typically occurs during the LP portion of the test in less than three minutes; and a good test (no leak) typically validates in the regulatory agency's minimum holding time requirements. Additionally, the software provides greater assurances, transparency, and reliability as compared to the CCR. The antiquated CCR is easily manipulated in multiple ways, which is eliminated with this solution.
This software provides the industry with a tool for objective, efficient test validation. The software generates simple, clear, concise reports and contains more information as compared to what is currently available. It archives tests in a secure format, and the software allows the users to retrieve and review the tests for any required scrutiny. It also prints the reports to a secured PDF format and archives them.
This paper discusses the current state of the development along with the associated benefits. A vision of the application development pipeline for further pressure analysis opportunities is also introduced.

Introduction
The oil and gas industry has advanced very little with respect to pressure testing critical equipment on drilling rigs. As the industry moves into operating in deeper water and uses non-water-based fluids, the challenges associated with obtaining effective pressure tests continue to grow.
Historically, digital pressure measurement solutions had not been considered due to its accuracy. Prevailing interpretations of regulatory requirements to " hold pressure?? were to demonstrate a flat-line on a pressure chart for a specified period of time. With the relatively low resolution of a CCR device, a flat-line was essentially produced when the resolution of the device was exceeded (typically 4-6 PSI). Analog chart recorders had the additional " benefit?? of allowing excessive damping and manipulation without recording such settings or actions.
Maximize Offshore Reservoirs Productivity with the Latest Design Techniques and Advanced Centrifugal Compression Technologies
Authors: Costantini Stefano , Grifoni Luciano , Rubino Dante Tommaso , Corneloup Christophe , Baldini Bernardo 
Published: May 2011

ABSTRACT
Compressors installed in plants worldwide can be modified to meet new operating conditions and other specific customer needs. This basic concept is even more relevant in offshore application. Timely upgrading of the centrifugal compressors to suit the late life requirements of the reservoir means, in fact, increasing hydrocarbon recovery versus reservoir depletion.
GE Oil & Gas has accumulated extensive experience in upgrading Centrifugal Compressors. Customers can benefit from implementing GE Oil & Gas new technologies and modeling methods that allow the extension of the operational envelope of the compressors beyond that previously possible in a predictable manner.
This paper shows the solution adopted by applying GE Oil & Gas design, testing and offshore installation methodologies in the context of brown field constraints to extend gas field production achieving up to 5 additional years through a new re-bundle inside existing casing, obtaining +50% extra polytrophic head versus existing machine and with a new, tailor made, centrifugal compressor, same footprint, obtaining +130% polytrophic head versus original one.

INTRODUCTION
Centrifugal compression facilities for Natural Gas Export and Enhanced Oil Recovery are affected by substantial changes in the operating conditions, which are the consequence of the reservoir depletion. Compression unit retrofit can be applied to offset those changes by increasing the compressor unit pressure ratio and/or flow rate.
At the end of the 90's GE Oil & Gas started to partner with End Users to retrofit the existing equipment by, mainly, changing centrifugal compressor internals, whose design was performed to center the machine envelope to the new operating conditions (as set by the analysis of the constrains, the goals and the thermodynamic performances of the available technology at that time).
A decade of experience accumulated in retrofit jobs in both offshore and onshore fields proved that cost effective projects are deliverable by lining up the machine internal stator and rotor components (re-bundle) to new operating conditions, this way avoiding off-design operation and allowing the retrofitted compressor to run outside its original envelope with increased operational efficiency.
In the early 2000 GE Oil & Gas started research activities, dedicated to retrofit applications, to develop the aerodynamic performances of the centrifugal compressor impeller stages to further enhance the existing assets value by combining the above approach (retrofit the machine to center it to new operating conditions) with the extra performances of advanced aerodynamic design developed to meet the constrains of brown field jobs.
Midstream & Subsea Pipeline Condition Monitoring
Authors: El Hares Layla , Strong Andrew Peter , Le Stanc Patrick 
Published: May 2011

Abstract
In this paper we present a fully integrated pipeline and flowline integrity monitoring system. The system uses optical-fiber distributed sensors to provide simultaneous distributed measurements of temperature, strain, and vibration for the detection, monitoring, and location of events includingthird-party interference (TPI), including multiple simultaneous disturbancesriser strain, pipeline buckling and upheaval, geohazards, landslides, and ice scoursVortex-induced Vibration (VIV)flow assurance and distributed temperature monitoring of heated pipelinesgas and oil leakspermafrost protection.
The technology also provides a unique means for tracking the progress of cleaning and instrumented pigs using existing optical telecoms and datacoms cables buried close to pipelines.
The solution provides a unique and proactive approach to pipeline integrity management. It performs analysis of a combination of measurements to provide the pipeline operator with an event-recognition and location capability, in effect providing a hazard warning system and offering the operator the potential to take early action to prevent loss.
Through the use of remote, optically powered amplification, an unprecedented range of 100 km is possible without the need for any electronics or therefore remote power in the field. A system can thus monitor 200 km of pipeline when configured to monitor 100 km upstream and downstream from a single location.
As well as detecting conditions and events leading to leaks, this fully integrated system provides a means of detecting and locating small leaks in gas pipelines below the threshold of present online leak-detection systems based on monitoring flow parameters. Other significant benefits includepotential reductions in the construction costs of new pipelinesenhancement of the operator's existing integrity management programPotential reductions in surveillance costs and HSE risks.
In addition to onshore pipeline systems, this combination of functionality and range is available for practicable monitoring in a wide range of other applications, such asthe monitoring of long subsea flowline for flow assurance, leak detection and movements such as ice scourflexible riser integrity monitoringstrain and shape monitoring of offshore riser and umbilical systemsFacilities perimeter security.
An important element of this system is a bespoke direct-bury optical sensor cable, designed to allow distributed strain measurement and hence enable monitoring of ground movement whilst withstanding the rigors of pipeline environment. The system can also be configured for detection of third-party interference and leaks with the majority of existing buried onshore cables.
Steel Tube Umbilical Design Life Verification by Full-Scale Fatigue Test
Authors: Brown Ewan 
Published: May 2011

Abstract
Steel Tube Umbilicals (STUs) are integral to many offshore production systems and must be designed to endure demanding fatigue environments over the course of their service life. It is therefore fundamental that the design methods employed to calculate the fatigue life of STUs are suitably validated against real test data.
This paper compares the predicted STU fatigue life derived using UFLEX2D analysis with that observed by flex cycling a manufactured sample to failure. Characteristics such as tube helical geometry, internal pressure, tension, bending, and friction stick-slip behaviour are considered. Calculated strains are presented alongside strain gauge measurements taken from the sample, and fatigue lives derived using DNV-RP-C203 are compared against the actual numbers of cycles for tube through wall-thickness cracks to develop.

INTRODUCTION
Oceaneering Umbilical Solutions (OUS) continues to invest in improving engineering technology and has key focus on developing accurate analysis techniques for designing reliability into its STU products. The past 2 years have seen a number of new initiatives including participation in the Umbilical Phase II JIP with Marintek to support development of the non-linear FE analysis code UFLEX2D and providing sample umbilicals to the project for test and validation work.
More recently work has been carried using UFLEX2D to compare the theoretically predicted fatigue life of an STU against a full-scale flexure test to failure. This paper provides a description of the analysis approach and results of the test.