bluuebunny/crossref_metadata_2025_split huggingface dataset:
NorMoor JIP, Mooring Design Code Calibration
Authors: Hørte Torfinn , Okkenhaug Siril , Paulshus Øivind 
Published: April 2017

DNV GL is currently running a Joint Industry Project, "NorMoor JIP," with participants from oil companies, engineering companies, rig-owners, manufacturers and marine authorities. It is a global study covering Northern Europe, Gulf of Mexico and Brazil waters. Our motivation for initiating a study on mooring line reliability was that all the global standards (API, ISO, DNV, others) are mostly based on work from late 1990s, when frequency domain analysis was prevalent. The reliability level implied by these regulations is not known, and we also see that the mooring standards are interpreted and applied differently.
Thus, there is a need for a mooring design code with a consistent analysis methodology and with safety factors for time domain analysis that are in line with this methodology and calibrated at an appropriate target reliability level. This is achieved through reliability-based calibration for a range of different units, mooring systems, water depths and geographical locations. The focus in the present paper is the calibration of safety factors and selection of target reliability level. The underlying structural reliability analysis results used for the calibration are reported in an accompanying paper at OTC 2017.
Structural reliability analysis has been applied to calculate the probability of mooring line failure for intact mooring systems (ULS) and damaged mooring systems where one line is removed (ALS). These results are used as input to the calibration process where the optimum safety factor is calculated as a function of target probability of failure. For ALS, empirical failure data are utilized to assess the probability that a line is missing.
Calibration for different design formats are carried out. The current format using a single safety factor is challenged with a format with two safety factors. The calibration is carried out to avoid significant under design and excessive over design.
The target reliability level is determined based on evaluations of the current mooring design practice. Final recommendations on safety factors and accompanying analysis methodology are presented. Due to the nature of the hurricanes, it is shown and discussed that a different design philosophy is needed for the Gulf of Mexico.
The present work provides a unique and comprehensive set of results, where advanced reliability methods are used to calibrate a mooring design code where the mooring line tensions are calculated in the time domain. The results provide a basis for regulators, such as ISO, to update their rules. ULS and ALS are covered here, and a potential phase 3 of the JIP will cover the fatigue limit state.
Stampede Multi-Purpose Dynamic Simulator
Authors: Puecher Leonardo , Clare Paul , Rastogi Ankur 
Published: April 2017

Abstract
The Stampede deepwater field is located in the Gulf of Mexico, Green Canyon block, and consists of approximately 3,500 ft of water. The Stampede project will include 10 in-service wells in a Miocene formation for a reservoir system at 28,000 – 31,000 ft. TVD. This unique reservoir has deep wells, a low gas-to-oil ratio, and a low bubble point, a combination that calls for an in-well gas lift injection design.
The Stampede project team identified dynamic simulation as a validation tool during the early design phase. High-fidelity fully compositional models were developed for Subsea to simulate heat-transfer effects in the well annulus to understand the interaction between production fluid and gas lift injection for various startup cases. After the simulation model was in place and in use, the project team identified the need to continue using the topsides and subsea integrated simulation models to validate additional phases in process design and engineering. We developed a multi-purpose dynamic simulator (MPDS) that proved to be a crucial tool for Standard Operating Procedures (SOPs) validation, Operations training and control system checkout.
The use of this integrated model provided tangible economic benefits because it led to better informed design decisions throughout the project lifecycle, minimizing workarounds. The challenges the project faced were solved by using the simulator, which connected all the systems together: the subsurface equipment and artificial lift method, the risers and production facilities, and the export pipelines pumps. Using the whole platform model, the project team was able to identify and solve potential issues before they became problems.
This paper shows how a simulator with dynamic full-facility components (subsurface, subsea, hull, and topsides) was used by the project team during each project phase (design, FEED, and construction) to benefit various disciplines (Reservoir and Flow Assurance Engineers, Operations, Automation, and Initial Startup teams). The paper refers to case studies and specific challenges faced by the project team to develop conclusions from the lessons learned and insights gained.
Testing of a Novel Autonomous ICD with Low-Viscosity Multiphase Fluids
Authors: Corona Georgina , Yin Weiqi , Fripp Michael , Coffin Maxime , Shahreyar Noman 
Published: April 2017

Abstract
Applying proven technology to control the production of water and gas has become necessary to extend the life of very light-oil reservoirs while optimizing economics. Traditional inflow control devices (ICDs) can help balance the flow of oil, but are not helpful once water and gas breakthrough occurs. Multiphase data and field-evaluation applications show that low-viscosity, fluidic-diode, autonomous ICDs (AICDs) support the production of very light oil while restricting gas and water.
Testing has proven that the low-viscosity, fluidic-diode AICD can differentiate oil from water and gas, even very light oils. Tool performance was characterized by measuring the pressure differential vs. the flow rate of diverse oil viscosities representing very light-oil formations in Canada, Russia, Malaysia, and Brazil. The AICD was flow tested with very light oils, water, and gas, as well as multiphase testing simulating mixtures of oil/water for different water cuts and oil/gas at diverse gas-volume fractions. The characterization of flow performance was embedded into sophisticated reservoir simulators for steady and transient evaluations.
The multiphase condition of the test fluids was achieved by increasing water cuts and gas-volume fractions. The flow performance tests indicated that the highly sensitive fluidic sensor of the low-viscosity AICD enhances the production of very light oil and restricts water and gas as the water cut and gas-volume fraction increase. The restriction process gradually increases as per the water and gas ratio in the mixture and is reversible if water and gas production recede. Comparisons of the low-viscosity, fluidic-diode AICD vs. a traditional ICD show approximately 25% less water production and 40% less gas production with the AICD. The ability of the low-viscosity AICD to produce very light oils while restricting the flow of gas and water extends the life of light-oil reservoirs by increasing the production of hydrocarbons while helping to lower costs.
For optimum reliability, this unique fluidic-sensor technology has no moving parts or control lines, but uses fluid dynamics to distinguish fluids. Multiphase-flow performance testing and field simulation of light-oil reservoirs indicate that the low-viscosity, fluidic-diode AICD favors the production of light oil (0.3 cP–1.5 cP) and restricts the flow of gas and/or water in a multiphase production-flow environment.
Reducing Subsea Technology Development Lead - Times –A Case Study
Authors: Albert J. , Bay L. , Portman L. 
Published: April 2017

Abstract
A new solution for subsea boosting, has been developed from concept to Technology Readiness Level 4 (TRL 4) in approximately two years. This is an accelerated timeframe for a multifaceted subsea technology, compared to other developments which historically have taken up to several years in the subsea space. Many factors contributed positively to the success of this development including: a methodical approach to product development with a system engineering perspective driven by early client engagement, re-use of field proven and standard components, and a large focus on modularization. Significant development work was required including prototype fabrication and verification testing. This paper chronicles the development of a seabed boosting system, from concept to commercialization, emphasizing the challenges involved with respect to technology development, customer acceptance and the team's experiences and lessons learned.
Qualitative Fault Tree Analysis of Blowout Preventer Control System for Real Time Availability Monitoring
Authors: Mutlu Mete , Arnold Zev , Franchek Matthew A. , Meraz Jose 
Published: April 2017

Abstract
This paper deals with the dynamic availability of a subsea blowout preventer (BOP) with respect to regional and industrial requirements. The study aims to reduce the non-productive time on drilling rigs due to complex propagation of failures within the BOP and BOP control system. In this development, fault tree analysis updated with near real time failure database is implemented into operational decision-making process. First, the system is defined with specifications, boundaries and assumptions. Failure modes of each component are stated. The requirements on the BOP control system are determined with respect to API Standard 53. Fault trees are constructed to address each requirement, and cut sets are produced. For dynamic analysis, a database on BOP state and failure component is created using reports from drilling contractor and operator. Upon detection of a failure, the cut sets are updated. With this application, impact of newly discovered failure in combination with the existing set of failures over BOP availability and compliance is determined in a standardized manner allowing consistent and efficient judgment.
Downhole Real Time Wireless Telemetry System Applications in Deepwater Completions in the Gulf of Mexico
Authors: Aguilar Sergio , Hawthorn Andy 
Published: April 2017

Abstract
The scope of the paper is to introduce the application of a new wireless downhole real time telemetry tool and its applications in three different deepwater completions operations. The main method to explain the technology application is through three case histories. In two of these case histories, the availability of downhole real time data led to actions on the surface that ensure the positive outcome of the operation. In the third one, the continuous monitoring of well conditions increase the safety and efficiency aspect of the operation. Another approach used in the paper to validate the technology is the comparison of the field real time data with the expected behavior predicted by the modeling done before the operation.
In the fracpack case, pipe contraction due to cooling led to the application of unexpected additional weight on surface. The quantification of different contraction ratios versus temperature drop can help understand the relative movement during operations of downhole tools. In the second case, in the multi-zone single trip system (MZST), the downhole weight transmission monitoring was able to quantify weight transmission at different times of the operation, as expected when the inner string of the tool was inside the outer and permanent string of the system, according to the tubing movement analysis buckling was minimum.
In the fluid loss control case, fluid level drop in real time, allowed the determination of fluid loss rate in-situ and secure the well control aspect of the operation immediately after perforating gun (TCP) firing and after an acid frac job. The control of the losses by an optimum overbalance, minimize fluid control losses and reservoir damage. The case histories will show the direct benefits of the technology in well control and productivity, in the completions operations like TCP, fracpack and MZST.
Pipeline Span Assessment Lessons Learned from Numerical Simulations
Authors: Huang Shawn , Sun Jason , Abdalla Basel 
Published: April 2017

Abstract
Offshore pipeline on-bottom roughness analysis is generally performed to understand pipe stress and areas of free spanning. In this paper, the predicted pipeline profiles, by finite element analysis (FEA) modeling, are compared with survey data. Several case studies are presented and parametric effects are assessed.
The FEA modeling procedures are presented in this paper along with several project experiences. The pipeline on-bottom roughness analysis is conducted to determine the pipe stress and the associated fatigue damage due to internal pressure and temperature fluctuation and vortex-induced vibration (VIV) of free span sections due to seabed unevenness. The analysis presented in this paper can aid the design of pipeline free spans and mitigation, if required. The parametric effects of higher and lower bound soil stiffness, friction resistance, pipeline bottom tension, external / internal pressure, and content density are considered.
The predicted pipeline profiles by FEA modeling are compared with surveyed profiles under several loading conditions. A strong correlation between survey data and finite element analysis (FEA) is achieved. This paper shows that the FEA stress prediction is adequate, and the FEA modeling is suitable as an advanced design tool for pipeline on-bottom roughness assessment and free span behavior analysis.
A commonly used mitigation method for VIV fatigue is to install VIV suppression strakes. For overstresses due to pipeline bending effect, the common mitigation methods are to install mechanical supports, use heavy wall pipe and correct the seabed unevenness among others. It is important to reliably predict the pipeline profiles in order to precisely assess the pipeline free span response and to provide guidance to determine a proper free span mitigation strategy. The FEA method can be utilized to realistically simulate the pipeline on-bottom roughness behavior affected by the pipe properties, pipe-soil interaction including penetration and soil friction resistance, the internal and external pressure, product content, temperature profile, and the bottom tension from pipe-lay. An accurately built FEA model can provide a reliable prediction for the pipeline profile, free spanning length and gap under all conditions, which are crucial for the stress and fatigue assessment as well as for the design of free span mitigation.
Topsides Engineering by Modular Simulation Models
Authors: Felorzabihi Neda , Feng Jeffrey , Shariat Hoss , Wilson Michael 
Published: April 2017

Abstract
In recent years as the offshore industry strives for alternate ways to lower price and increase project efficiency, topsides are often designed and built based on modular design due to the compact process layout, lack of personnel accessibility for site fabrication and also similarity in design of process units involved in most of offshore projects. The modularization process requires a robust simulation model that can quickly perform screening exercises at early stages of the project and be able to validate the detail design from module sub-contractors as the project progresses. This article presents the application and benefits of a modularized, off-the-shelf dynamic simulation tool to support the modular design of an offshore platform during the whole lifecycle of the project, from conceptual design (Pre-FEED), to Front End Engineering (FEED), to EPC, to commissioning and start-up and to post-start-up (normal operation).
Modular-off-the-shelf dynamic simulation tools will support the modular design of the offshore project by modeling each individual modular section of the plant using standard off-the-shelf template models that have been built to meet project requirements. The off-the-shelf models can also be replaced with customized models according to modular design of the plant and based on the data available at each phase of the project.
The dynamic simulation tool has supported various projects for life cycle analysis, for verification of design, testing and verification of control strategy, for operation support during start-up, and troubleshooting and debottlenecking of operation of the plant with proven cost savings. This methodology was originally developed for installations in the United States and later was adopted for the design and engineering in other part of the world. In this article, case studies will be presented as well as the benefit achieved in the application of the modular simulation tools for topsides engineering.
Based on the project scope, the modular simulation domain may vary from a single compression module to an entire topside facility for any floater with modular design such as an FPSO, semi or FLNG, associated wells and flowlines as well as linkage to third party software.
Neptune Spar Life Extension Assessments
Authors: Hua David , Paradkar Mayuresh , Garcia Sharon , Young Sam , Hogelin Pat , Webb Tyler , Farmakakis Kim 
Published: April 2017

Oil and natural gas producers continuously strive to control costs, and that goal becomes even more important when market conditions are challenging. To maximize the return on their capital investment and continue to extract reserves on legacy fields, many owners and operators are looking for ways to extend the service lives of aging assets.
The Neptune Spar was the first production spar platform in the world, when it was installed in 1996. Currently owned and operated by Noble Energy, the unit continues producing at Viosca Knoll 826 in the Gulf of Mexico. As the platform ages, there is an interest in extending its service life to allow continued operation in the field. As requested by Noble Energy, ABS Group initiated a life extension assessment project.
This paper describes the process of the Neptune Spar life extension assessments and challenges encountered during the process. One of the critical aspects of the life extension process is regulatory approval. Since the life extension for floating production platforms is a relatively new trend in the offshore industry, the regulatory compliance process is still under development, and this project is providing a significant contribution to the development of guidance and criteria.
The purpose of a life extension assessment is to understand the history of the facility and its current physical condition to determine its structural integrity and outline what is needed for the unit to be maintained for safe and responsible extended service. The life extension project began with a roadmap for life extension assessments that included conducting baseline inspections, reviewing historic inspection and repairs records, undergoing gap analyses that compared the spar's current condition with the original design premise and calculations, and performing additional engineering analyses.
As part of the regulatory approval process, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) and the U.S. Coast Guard (USCG) require that a Certified Verification Agent (CVA) verify the entire process of life extension and submit reports that document findings and recommendations. ABS served as the CVA. During the life extension assessment process, ABS Group and Noble Energy consistently coordinated with ABS, BSEE and USCG.
Based on the life extension assessments, ABS has granted class certificate for the life extension of this platform. The process of the spar's life extension assessment provides industry with a better understanding of the technical requirements for life extension of other floating production assets, which will have a long-term impact on future asset integrity management for these types of facilities in deep water.
Mooring Integrity and Machine Learning
Authors: Prislin Igor , Maroju Soma 
Published: April 2017

Abstract
Maintaining the expected position is critical to the overall safe operation of a floating oil platform. Mooring systems are critical to the integrity of the platform. Relying on instrumentation for monitoring the mooring line tensions represents multi-faceted challenges. Therefore, alternative methods have been introduced across the industry to reduce the costs and complexities of maintaining these systems.
The paper discusses implementation of the Position Response Learning System (PRLS), a novel concept for addressing the integrity of mooring systems. PRLS is based on emerging data technologies and particularly machine learning that bridges the gap between a variety of global position measurements of the oil-platform and the mooring integrity paradigm. Machine learning enables learning from large amount of data without explicit programming. The PRLS concept does not require expensive line-tension measurement systems, but rather the global motion systems enhanced with the metocean monitoring. The global motion systems that include DGPS and MRU are typically already installed on oil platforms. In addition to measured data, PRLS can utilize a plethora of other data sources, including numerical simulations, model test data, and most importantly, the real-time and archived field data other than the line tensions. When the data are coupled with machine learning methods, they provide reliable, robust, and cost-effective solutions to address the integrity of the mooring system in real time of the oil platform.
The article illustrates how the PRLS can identify a mooring line failure and even indicate which of the mooring line fails. Preliminary results based on the simulated data show that the accuracy of such predictions is better than 98%. The PRLS runs in the background independent of other integrity monitoring systems. It requires retraining periodically with new field data to improve the prediction robustness and accuracy. PRLS may be deployed on all types of floating platforms under a relatively moderate capital expense, and with very low operational costs when compared to high capital and operational expenses of a subsea mooring line monitoring system.