bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of an Enhanced Lazy Wave Flexible Riser System in Extreme Shallow Water with an External Turret Moored FPSO
Authors: Hou Yucheng , Yuan Jiabei , Tan Zhimin , Witz Joel
Published: April 2019

This paper presents the design challenges encountered in a flexible riser application with an external turret moored FSO in a shallow water depth around 55m, and the solutions obtained for an improved lazy wave flexible riser system. Extensive dynamic analyses were performed with parametric variations and a model test was also carried out to validate the predicted dynamic responses.

The lazy wave flexible riser system is preferred for shallow water applications due to it being cost effective in terms of both fabrication and installation, and high reliability in operational performance. The system relies on the balance of the riser system weight and buoyancy applied, and it is required to accommodate large excursions and dynamic motions of the mono-hull vessel induced by the environmental loadings. The riser system weight varies due to pipe contents changes and heavy marine growth. When the water becomes shallower, the challenges escalate to maintain the riser system to remaining in suspension without clashing with the sea bed or vessel. An enhanced Lazy Wave Flexible Riser solution, a patented technology of BHGE, was adopted. In this technology, the ballast modules were used innovatively to maintain the configuration in suspension by automatically compensating the riser weight variation during entire service period.

The paper also summarizes preliminary benefits of the improved lazy wave flexible riser technology over the potential alternative technologies for such shallow water application, for example, the traditional S configuration and the latest middle-water-jacket configuration. Both alternatives involve significant high cost in fabrication and installation.
Optimization of Well Start-Up Using Integrated Well and Electrical Submersible Pump Modeling
Authors: Mukati Kapil , Wilson Oliver , Morales Milton , Arias Brian , Terry Clinton
Published: April 2019

An integrated multiphase flow well and electrical submersible pump model was used to optimize operating procedures for initial well clean-up and ramp up to production for a major deepwater production system before first oil. An integrated modeling approach was crucial to create and test start-up scenarios given uncertainty in the amount of completion fluid in tubing, uncertainty in density of near wellbore fluid and lack of prior experience in ESP operation.

The model was used to simulate numerous well start-up scenarios:Well BS&W rate profiles as a function of frac pack fluid recovery percentageWell unloading profiles as a function of injected base volumeNatural flowing well start-up profilesChemical injection volumes and associated surface injection pressuresPressure surging across the completion during ESP start-upsNumber of "A" annulus bleeds required during initial start-up

Accurately simulating such highly transient scenarios requires integrating multiphase flow phenomena in tubing to reservoir inflow and dynamic pump behavior. The integrated model proved to be very valuable in finalizing well start-up procedure with a high degree of confidence. This fully dynamic model can estimate phase, pressure, temperature and flow anywhere in the tubing including effect of well choke operations, pump pressure and temperature dynamics based on speed, effect of downhole conditions, and reservoir inflow. The transient behavior in tubing and annulus upon switching on or off ESP pump during well operation is also accurately represented.

In this paper, we will present how the integrated model was developed, how it was used to simulate various scenarios and how the results were used to create and validate well start-up procedure. The methodology presented here is applicable to any well using ESP artificial lift methods. This model is a very useful tool not only for engineering simulation, but for operator training and real-time surveillance as well.
A New All Electric Subsea Control System Development
Authors: Monteverde Carlo , Novello Marco , Kristiansen Karstein
Published: April 2019

Over the past few years a specific programme has focused on the development of subsea separators and a subsea water treatment and injection process composed of several modules and requiring a certain amount of new subsea technology (subsea barrier fluid-less water injection pumps, filters, special water analyzers, etc.). One of these technologies is the all-electric subsea control system.

The all-electric versus the electro-hydraulic solution was selected for its inherent capability to:enable long step-out distances;run logics such as sequences and fast closed control loops involving subsea proportional valves;handle high frequency of simultaneous valve actuations;implement safety functions, including SIL certified, when required.

Within the ongoing industrialization programme of the new technologies, a Joint Development Agreement has been put in place between two partners for the qualification of the open framework platform for the control of subsea processes.

The development is pursued according to the API 17N and DNV RP-A203 requirements.

The subsea control system is developed according to the approach to interface standardization, which is aimed at guaranteeing:–the interchangeability of modules coming from different vendors;–the reduction of physical interfaces;–the optimization of IMR intervention time.

The technology mainly consists of:a qualified basic component platform to be used for project-based assembly;a complete set of tools such as web-server, condition monitoring server, integrated software development environment, etc.;a standard and user-friendly approach for software application development, based on P&ID graphic, in order to facilitate the sharing of software information between contractor and clients;standard industrial communication protocols (no proprietary protocols) accessible to all users, which are designed for easy interfacing of the control system with third party equipment.

The JDA activity has concluded the Q1 qualification tests of electronic components and Q2 tests of electronic assemblies, pursuant to API 17F, as well as all the other qualification activities (tests and analyses) relevant to the non-electronic components (e.g. 40kVA subsea electrical transformer), according to the relevant technology qualification plan. Additional software packages have also been developed and successfully tested using the Test Driven Development (TDD) method.

The qualification will be completed by Q1 2019 with integration tests of:–Topside Control System;–Subsea Power and Communication Distribution Manager;–Subsea Control Unit.

The integration tests will allow to reach TRL 4 of the above subsea equipment, in accordance with API 17N.
A 3D Digital Approach to Flow Assurance
Authors: Bouamra Reda , Petit Pierre , Smuk Stefan , Vielliard Christophe
Published: April 2019

The oil and gas industry has long perceived computational fluid dynamics (CFD) as a computationally expensive, high-end simulation method to analyzing extremely complex behavior. However, the recent increase in computational power and the democratization of CFD packages have enabled 3D modeling to become part of the regular in-house execution scope. This paper presents a range of flow assurance CFD applications and shows the impact of 3D workflows in the overall system design, the adoption of standard specifications, and fast-track project executions.

As oil and gas fluid journeys from the reservoir pore space to production facilities, it faces a wide range of complex flow assurance issues related to the nature of the live production fluids (compositional changes, viscosity, compressibility), the production system environment (high and low pressures) and its interaction with hardware (erosion, flow induced vibration, scaling). One-dimensional mechanistic models are used to solve these flow hindrance issues in wells and pipelines but provide limited results in the complex geometries of subsea and subsurface equipment.

In subsurface applications, a CFD workflow was used to tune near-wellbore reservoir properties based on advanced 1D and 3D thermal modeling of the completion interval. Accurate thermal modeling was then used to manage downhole flow assurance issues (e.g., asphaltenes and scale buildup). In subsea equipment, the methodology was used to fast-track project execution by using standardized equipment using project specific parameters at an early stage. CFD analyses were used to estimate the risk of erosion and flow-induced vibration in a subsea tree. The thermal aspect was not neglected because CFD conjugated heat transfer was used to detect cold spots and improve the thermal behavior of insulated equipment (trees, manifold) during normal production and shutdown. To avoid long and expensive material qualification campaigns, CFD was used to define the temperature gradient in trees and compare the design temperatures of materials against their calculated temperatures.

The ability to perform advanced CFD calculations has become a true enabler in the ability to adopt standardized equipment and supplier-led specifications on subsea field development applications, thus contributing to better capital efficiency and shorter time from discovery to production. Several concrete examples from wide-ranging subsea field development projects worldwide are presented to illustrate the added value of CFD in all stages of engineering, from concept definition to project execution.
Industrialisation of SPRINGS®, A Qualified Subsea Sea Water Desulfation Process
Authors: Giolo Riccardo , Berthelot Aurelie , Pedenaud Pierre , Skivington Graeme
Published: April 2019

SPRINGS® (Subsea PRocessing and INjection Gear for Seawater) is a qualified process for subsea water treatment and injection. It uses membrane technology for water desulfation upstream of water injection wells to prevent sulfate scaling on the production side (nearwell bore, well and production equipment). It moves the water treatment from topside to subsea locations close to the injection wells with only power and communication tie-backs to existing topside facilities. Qualification of the process was achieved through both onshore and offshore trials.

In advance of deploying the first industrial application, an industrialisation programme was undertaken in order to ensure that every component necessary for the subsea process implementation was available and had a sufficient technology readiness level to be safely installed and operated within the subsea plant.

The existing and available technologies were reviewed vis-À-vis the requirements arising from both the process and the business strategy. Several industrial partners were engaged to determine the elements of novelty that needed to be brought to each technology or component to satisfy such requirements.

The new technologies included:

Subsea barrier-fluidless pumps

Open framework all-electric control systems

High-cycling electric actuators and valves

Subsea water analyser

Subsea storage and injection units for chemicals

The design basis for the development of each technology, which in most cases included the realisation of a prototype and relevant qualification testing, was set up to consider a range of possible applications with differing environmental conditions, process data and/or IMR scenarios. The most challenging conditions were selected for each development to determine the relevant required performance.

Where available, specific standards, such as API 17F (ref. [8]) for subsea electronics, were followed to determine the qualification plans. In those cases where no dedicated specific standard was available, the evaluation of the proposed solution was performed in conjunction with the technology provider through the risk based approach stated in API 17N (ref. [9]) and DNV A203 (ref. [10]). Failure Modes, Effects and Criticality Analyses (FMECAs) as well as technology readiness assessments were performed in order to develop the technology qualification plans.

Most of the key equipment qualification plans will be completed by mid-2019, establishing an industrial platform for the deployment of the subsea water treatment and injection technology in a completely all-electric configuration, i.e. connected to the surface only through a communication and power cable. Such an industrial platform will also contain the building blocks for other subsea processes.

The presentation and paper will introduce the elements of technological novelty and will describe the process, the challenges and the results of the relevant qualifications.
New Concepts for a Normally Unattended Installation NUI – Design, Operation, Automation, and Digitalization
Authors: LaGrange Elgonda , Maisey Joel
Published: April 2019

This paper is based on an ongoing multi-participant study which focuses on the development of concepts for unmanned or "Normally Unattended Installations" (NUIs) that can be used for the economic recovery of stranded oil and gas reserves considered too small for traditional floating production storage and offloading (FPSO) vessels, and too far away from existing facilities for tie-backs.

The primary objective of the study is to apply existing technologies in novel ways and to utilize recent advances in digitalization to develop low manning concepts by facilitating remote control, remote monitoring, and reducing maintenance requirements. The study engaged key technology vendors and operators, who provided operational expertise and defined future operation philosophies. Concepts are being validated by classification societies, yards and installation contractors.

The specific NUI concept explored in this paper is an unmanned production buoy that proved to be technically and economically feasible for the recovery of small hydrocarbon pools in deeper water. The case study is a realistic approximation of a small deepwater offshore development in the North Sea, however, it is not based on any specific prospect. The case study Basis of Design (BoD) has been defined to cover a range of API gravities, ensuring that the resultant topsides design concept is robust and applicable to a range of real field developments in the future without significant re-configuration.

The study into the technical and economic feasibility of the unmanned production buoy considered alternatives for gas compression, treatment, separation; heating and cooling, power generation, automation systems, and digitalization. This paper presents the outcomes with respect to production buoy design, operating philosophy, automation and digitalization.
Standardization of Procurement Equipment Specifications: A Step Change in Facility Cost and Schedule Reduction
Authors: Postema Adri , Wish David
Published: April 2019

Over the past decade, projects across the oil and gas industry have been plagued by cost and schedule overruns, exacerbating underlying cost escalation. Rising project costs must be addressed to ensure long term viability of the future capital programs. Standardization is widely recognized as part of the solution, and individual companies have been progressing standardization of specifications within their own businesses. However, the standardization journey is only just beginning: the oil and gas industry still lags others such as the automotive and aviation, as individual companies each maintain their own amendments on otherwise established industry or international standards.

Joint Industry Program 33 (JIP33), now in its third phase, aims to unlock significant value and drive a permanent reduction in project costs through the development and use of industry-level, global technical specifications for procurement of bulk materials, packages, modules and potentially, even projects.
Intelligent Completion in Extended Well Test
Authors: Coccoli Flavio Costa , Cruz Luiz Carlos Milagre , Vasconcelos Thiago Henrique Galindo , Marti Rogério Pinto
Published: April 2019

This paper describes the wells completion design, operational performance and use of intelligent completion by Libra Consortium for EWT wells. Additionally, it will describe new technologies that will support the full field development.

The paper presents the de-risking plan EWT Program implementation to help full field development, which consists up to four ultra-deepwater mega projects. The EWT wells were assumed as keepers, thus designed as convertible, with metallurgy requirements for both oil production and Water Alternating Gas injection. The intelligent completion, with multi-position valves for each production zone, was selected to allow choking-back gas coning, early gas breakthrough or water production in one zone, while another remains opened. These valves were useful to determine vertical communication between different reservoir zones, making it possible to have buildup in one zone while producing another.

Four appraisal wells were completed, for the EWT program up to now, using a full-dual rig. Three of the completions were in sequence, providing a sound learning curve with a significant time reduction, and no installation problems. It was noticeable a correlation between improvement in operational efficiency and a decrease in HSE incidents. The use of intelligent completion made possible an efficient well stimulation, avoiding inter-zonal communication during the acid job. A production rate higher than 60 kboe/day was reached and 100 MM scf/day gas was re-injected. This injection rate implied risk of control lines fatigue due to induced vibration, therefore a Computational Fluid Dynamics (CFD) study was required to determine the maximum injection rate. The Operator implemented mitigation measures for intelligent completion valves actuation since some operational difficulties were observed during the EWT. These situations did not affect the EWT information acquisition plan, but represented significant operational experience for Mero Field future development projects, where multiplexed intelligent completions and open-hole intelligent completion are being also considered.

The approach taken by Libra Consortium helps to gain early experience about well design for carbonate reservoirs and intelligent completion behavior, with high CO2 and GOR, where gas re-injection is a necessity and the use of intelligent completion is a mandatory strategy. The performance of the completion design fitted the field evaluation purpose and the wells will be successfully used as keepers.
Metocean Decision Making Lessons-Learned during an Oil & Gas Construction Project Conducted in a Harsh Coastal Environment
Authors: Bullock Terry William , Beale Steven Thomas , McCarthy Ron , Kelly Hugh Anthony
Published: April 2019

The Hebron Platform was constructed from 2012 to 2017 in the harsh environment of coastal Newfoundland and Labrador. The construction site experienced winds and seas that approached expected values for a 100-year return period event, unusual non-tidal water levels during topsides / GBS mating, and historically extreme sea ice conditions that delayed tow-to-field operations. Topsides marine operations required data collection and forecasting system enhancements more than 2 years in advance due to the sensitivity of the operations, and the complex topography and climate of the site. Installation offshore was limited by winds, seas and long period swells that could reach the site from remote areas of the Atlantic. A summary of metocean support for the Hebron Platform is presented with lessons learned and comparisons made with the Hibernia Construction Project executed 20 years earlier in the same location.

Several technologies were applied to the Hebron Project that were not available during the Hibernia Project. Emerging technologies combined with in-situ measurements of atmospheric and oceanic conditions were used to provide operational metocean support for the Hebron Project. Examples of effective processes are described that could apply to similar harsh environments, complex terrains or northern coastal construction projects. There were also technologies attempted which were deemed unfeasible. Complex metocean decision making for an environmentally sensitive oil and gas construction project is described within a quantitative risk assessment framework.

Embedded experienced metocean personnel used advanced information behind the scenes to improve forecast accuracy and to provide guidance on the timing and likelihood of threshold-exceedance events. It was demonstrated that an effective metocean decision making process was highly dependent on forecast magnitude and timing accuracy at various forecast horizons. It was found that specific operational parameters and governing, operational weather windows for the Hebron Project were achieved with minimal waiting on weather due to a ‘go/no-go’ decision making process which was based on confidence in the forecast accuracy, and a risk assessment system that embedded metocean specialists with the relevant event-likelihood information. Operational delays due to unreliable forecasting would have led to significant delays, personnel and equipment downtime, and cost over-runs for the Hebron Project.

Weather forecasting in support of the Hebron Project demonstrated that metocean analytic and predictive science has improved sufficiently over the past 20 years to effectively support oil and gas exploration and development operations that have moved into harsher environments.
Next-Generation Hybrid Drill Bit Produces Exceptional Drilling Dynamics and Time-Saving Improvements
Authors: Bone Kim , Bradley Ben , Kale Ibrahim
Published: April 2019

An offshore field has presented a challenging intermediate drilling application. The 2200-m section was drilled in a 17.5-in. hole to 3700-m true vertical depth. The lithogy of the section is variable, beginning with a soft claystone, followed by several sandstone formations, an 1100-m interbedded sandstone and claystone interval, a 125-m hard carbonate, and 50m of softer claystone before the casing point. The challenges presented in recent offset wells included high stick/slip, high levels of drill bit cutting structure wear and drill bit body erosion. Polycrystalline diamond compact (PDC) bit designs utilized in recent offsets varied from six to nine blades, with the interval requiring two or three bits to complete the interval.

Based on results from other challenging offshore applications, including improved durability and drilling dynamics, the next-generation PDC and roller-cone hybrid drill bit (hybrid) with improved design features was selected for the application. Improved design features included a new increased blade count concept, combined with a sharp and dense roller-cone cutting structure.

The application of the next-generation hybrid drill bit design delivered a reduction in drilling time and an improvement to drilling dynamics compared to offset wells drilled with conventional technology. Compared to the best offset well drilled in 17.5-in. hole a reduction in total drilling time of 59.4hrs (31%) was achieved. The reduction in drilling time resulted from both an increase in on bottom ROP of 32% and the removal a bit trip (19 hours) due to the interval being drilled in one run for the first time. Associated with the reduced drilling time, improvements in drilling dynamics were observed with stick/slip reduced by 73%.

This paper illustrates the study of the application, applied learnings from new technology developments in hybrid technology evolution, and the subsequent improvements in drilling dynamics that resulted in improved penetration rates and cost savings in this challenging application.
Correlation Analysis of LiDAR, Wave Radar and Current Observations in the Gulf of Mexico
Authors: Mendelsohn Daniel L , Zarate Luz , Kurrus Keith , Leung Pak , Ruth Perry , Cristina Zwissler
Published: April 2019

Shell Exploration & Production Co. has recently expanded their Metocean observation capacity on several oil and gas platforms in the Gulf of Mexico, to include both LiDAR wind profilers and microwave wave radars, in addition to existing ocean current profilers. To date more than a year's worth of data has been collected with the combined system, observing a wide range of meteorological and oceanographic conditions, representative of the region, including the passage of Hurricanes Harvey and Nate. LiDAR wind measurement system and the wave radar system technologies are relatively new to operational use, and continued verification of their robustness and accuracy is necessary. LiDAR wind speed and direction observations were correlated with microwave radar wave and current observations, and those in turn compared to the observations from a subsurface mounted acoustic wave and current system. The LiDAR, microwave radar, and acoustic system are located on three different tension leg platforms with a few kilometers of each other. The data correlated well, captured the extreme conditions experienced during the period analyzed, and it was found that the acoustic system was likely influenced by the TLP superstructure against which it was mounted.
Creative Solution to Re-Establish Control of a Subsea Field with Failed Umbilical
Authors: Mao Jiayou
Published: April 2019

LH4-1 oil field is a subsea tie-back which was developed by CNOOC in 2012. After a short period of production, the subsea control umbilical started with low Insulation Resistance (IR) of its electric control quads. Extensive trouble shooting work immediately started. The trouble was identified to be on the main umbilical. The subsea electric control was swapped to the spare quad. After about a year, the spare quad also had zero IR. In order to resume the subsea control, feasibility of using the spare Medium Voltage (MV) power cable triads as control channel was studied immediately. The idea of using three core triad to establish dual communication channels with two frequency bands was thoroughly studied and it was found theoretically feasible. Originally the communication was one loop controls 4 wells, now with the new arrangement one loop controls 8 wells, 3-core with one as common return makes two loops. So the new MV cable communication configuration can still achieve subsea control with 100% redundancy. Subsea special bridge flyleads were designed and manufactured to convert the 70mm2 3-core MV flylead to 10mm2 4-core communication flylead. Offshore intervention work was done in 2014. After installation, subsea communication to all 8 wells was re-established as expected. The signal qualitywas much better that the original umbilical possibility due to the large MV copper cores.
AI-Driven Well Timelines for Well Optimization
Authors: Dalgliesh Jeff , Jones Allen , Palanisamy Arulmozhi , Schmauser Justin
Published: April 2019

Artificial intelligence and machine learning algorithms provide energy companies with the possibility to digitally re-construct well histories, using both public and company specific historical well data.

In this paper we discuss how oil and gas companies are creating a digital knowledge layer for oil and gas wells that provide a timeline of significant well events. Examples of key timeline events include, when drilling problems such as kicks happened, when blowout preventers were tested, when bottom hole pressures were taken, and when well interventions were done.

This new generation of AI-driven applications are powered by a combination of a computational knowledge graphs and AI algorithms. These AI algorithms encode the expertise of subject-matter experts such as Petro-technical engineers and combine their experience with decades of historical well-events data extracted from databases, documents, and sensors to automatically create well event timelines. This technology enriches and combines companies’ internal siloed well data with public well data to create an integrated digital knowledge layer for wells. Engineers can optimize the life cycle of the wells by visually exploring this interactive timeline to understand and make decisions about the well.

Petro-technical engineers have easy access to knowledge related to people, equipment, vendors, wells and more, so they can make better, more informed decisions faster. We show how we train the application's machine learning algorithms to read hundreds of thousands of historical reports to harvest knowledge about the well and store the extracted knowledge in an enterprise digital knowledge layer. By using the knowledge harvested and captured by this AI-driven application, experienced engineers can make better decisions that optimize the operations of their upstream assets.
From Prospect to Life of Field Service – The Role and Impact of Well Installation/ Intervention from a Subsea EPC Contractor's Point of View
Authors: Bay Lars Skoe
Published: April 2019

Being a global Subsea and Topside EPC contractor is often synonym with having an extensive portfolio of subsea production system solutions, sometimes including installation and well intervention systems such as landing string systems, riser based intervention systems and riser less intervention systems. However, unlike companies who focus specifically on subsea well intervention, and typically targets life of field opportunities, these EPC contractors might have this technology is in-house which enables cross discipline discussions already during concept studies and Front End Engineering Design studies (FEEDs). This enables contractor and client to select suitable technology not only based on equipment functionality and hardware cost, but highlights the operational impact such selections have both regarding installation of the equipment, and well intervention service throughout the lifetime of the field.

In a reference project a global EPC company is the main contractor for the engineering, procurement, construction and installation of the Subsea Production System (SPS) equipment in projects related to two large field developments West of Africa for a major operator. A total of 92 vertical subsea x-mas trees (VXTs) was awarded between 2013-2014 designed to be installed in depths down to approximately 2000m. In this case it was decided to install the tubing hangers using simplified landing string technology, while a riser based light intervention system was selected to provide flexible options for VXT installation, well clean-up/ flow back and life of field well intervention. A cross-vendor workover control system was selected to be used in both installation and intervention modes, allowing the operator to perform well interventions on existing subsea infrastructure in the region with 3rd party XT vendors, in addition to the planned field developments.

This paper will discuss how an EPC contractor can exploit the benefits of being both a subsea EPC contractor and an installation and well intervention service provider. The referenced project will be used as a case study, starting with the early phase studies, to show how decisions related to installation and intervention systems can greatly impact the XT selection and life of field strategy, and hence the configuration of the overall SPS and corresponding tooling. The philosophies around rig related services such as this connects the operator spend on SPS, SURF and drilling scope, and can greatly impact the overall project economics due to synergies across the distinct areas of investment. Furthermore, the paper discusses the importance of having a holistic approach when considering an intervention system for late life management, why it is beneficial to discuss such strategies at an early stage, and the benefits this brings to the end client over time.
Mooring Line Failure Detection Using Machine Learning
Authors: Jaiswal Vivek , Ruskin Alex
Published: April 2019

Offshore floating vessel mooring failure and subsequent loss of station can have catastrophic consequences for the vessel and the associated subsea infrastructure. Therefore, integrity management and timely detection of mooring failure is critical. Traditional methods of failure detection rely on line tension measurements and watch circle approaches. Both these approaches have limitations and are not reliable. Alternate methods of detecting line failure are therefore required.

This paper discusses a novel approach of using measured vessel positions and 6-degrees-of-freedom accelerations along with a deep machine learning algorithm to detect mooring line failure in near real time. Results from a numerical case study for a turret moored FPSO with over 4000 test cases demonstrate that this approach can accurately identify failed mooring line cases over 99% of the time.
Correlation of Finite Element Analysis FEA Predicted Residual Strength of Degraded Offshore Mooring Chains with Test Data
Authors: Farrow Gary H. , Potts Andrew E. , Dimopoulos Simon , Kilner Andrew A.
Published: April 2019

The first phase of the Chain FEARS (Finite Element Analysis of Residual Strength) Joint Industry Project (JIP) aimed to develop guidance for the determination of a rational discard criteria for mooring chains subject to severe pitting corrosion which, based on current code requirements, would otherwise require immediate removal and replacement.

Critical to the ability to establish rational discard criteria, is the ability to accurately predict the residual strength of degraded chain, and to have as a benchmark for loss in strength, an accurate estimate of the chain in its as-new condition. With a correlated FEA method for residual strength prediction and a benchmark for as-new condition capacity, it would then be possible to establish a theoretical relationship between different types of degradation and mooring chain capacity loss, from which rational discard criteria would be derived.

To this end the Chain FEARS JIP first developed a Finite Element Analyses (FEA) residual capacity assessment method to accurately predict the residual strength of degraded chains. A number of assessments were carried out to establish the sensitivity of the Predicted Break Load (PBL) to both engineering parameters such as friction coefficient, and numerical modelling techniques. The developed method was validated by the correlation of the PBL against a number of physical break tests.

This paper presents a review of the break strength test data of pitting corrosion degraded chain links. The FEA modelling methodology based Predicted Break Load (PBL) are compared with the test data Actual Break Load (ABL) along with the sensitivity of engineering parameters and numerical model modelling techniques on predictions. The developed FEA method accurately predicts the location of the ‘failure’ within the chain string and the ductile necking failure mode, determined to be the prevalent mode of failure for the chain links samples considered in this study. The degree of correlation between PBL and ABL confirms that accurate prediction of the effects of corrosion degradation consequent on uniform and large pitting corrosion can be accurately predicted by use of the Finite Element Method.

The developed FEA method was also employed to establish a benchmark for the strength capacity of as-new condition links as presented in [1], the basis for assessing the relationship between corrosion degradation and residual chain link capacity [2] and a basis for a multi-axial fatigue assessment method to establish the fatigue capacity of as-new and degraded chain links [3,4,5].
Developing Probabilistic Risk Assessment, PRA, for a BOP System Reliability
Authors: Holmes John Steven , Shah Viral
Published: April 2019

Recent regulatory changes have moved in the direction of more oversight and more prescriptive solutions. One of the areas that can help operators and drillers alike deal with the new regulations is improved risk analysis. This paper addresses a methodology for Probabilistic Risk Analysis (PRA) modeling of blowout preventer (BOP) systems. The PRA utilizes a combination of event trees and fault trees to determine the probability of a hazard under a given set of conditions. The fault trees are populated with reliability data from the best available sources.

Traditional BOP risk analysis was done on a deterministic approach. The probabilistic approach will allow a logical method to assess top level hazards resulting from specific component failures. This approach has been used in other industries such as nuclear power and space exploration. A method of combining testing intervals with PRA results to determine the probability of failure on demand is also included.
ABB Subsea Power JIP – Going the Distance
Authors: Ingebrigtsen Stian , Vatland Svein , Pretlove John , Nesheim Henning
Published: April 2019

ABB is running a joint project with Equinor, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion. The output will form a critical part of future advanced subsea field developments. Started in 2013, the project reached a major milestone in late 2017 when the first full-scale prototype of the variable speed drive (VSD) passed a shallow water test. Final preparations are now underway for a 3000-hour test of the complete subsea power system with two VSDs in a parallel configuration combined with subsea switchgear and controls.

The new solution will ultimately mean operators can free up topside space, or use no topside installation whatsoever, yielding significant cost and safety benefits. It is an extremely challenging endeavour, not only due to the harsh conditions to which the equipment will be subjected, but also because of the considerable reliability required. The equipment, the medium voltage (MV) switchgear, control and low voltage (LV) distribution equipment and the VSDs, must be able to run without intervention for many years.

The VSD's successful shallow-water test is the subject of a separate OTC paper; here, we present the highlights in the context of the wider project and particularly the steps taken to build confidence along the way that the proposed solution will be fit for purpose when fully launched. Readers will gain insights into the key steps of this cutting-edge project. These include modifying prototypes of the equipment based on rounds of simulations, laboratory assessments (eg accelerated aging, vibration and shock testing) and water testing.

As such an undertaking has never been achieved before, it is a journey with considerable learnings to be shared not only upon completion but also en-route. As we approach the goal which is anticipated by the end of 2019, it is appropriate to begin to share what we have learnt as we have been going the distance.
uROV – The Next Generation IMR Platform Utilizing Supervised Autonomy
Authors: Vincent Jack Heath , Sevinc Nazli Deniz , Herbst Neil Andrew
Published: April 2019

Autonomous Underwater Vehicles (AUVs) have shown promise to disrupt Inspection, Maintenance, and Repair (IMR) activities typically performed by Remotely Operated Vehicles (ROVs) tethered to large, expensive vessels on the surface. There are many concepts and projects within oil and gas that are focused in utilizing the efficiencies of these AUVs in novel deployment framework.

A novel autonomous vehicle platform in this domain is being developed called uROV (untethered ROV). The uROV vision has three main elements to bring to the IMR market. The first is to develop efficient deployment solutions such that IMR vessel expenditure is reduced or removed. The second is to bring next generation sensing technology to the market and integrate into the uROV platform. This is aimed at collecting better and more insightful data to use for integrity evaluation. The third main element is to bring digital enablement to the market through connectivity, data process automation, and visualization.
Application of Coupled Simulation Optimization Methodology to Study Dual Nitrogen Expander Liquefaction Response to Feed Gas Variations from an Optimized Design
Authors: Tierling Shane , Attaway Doug
Published: April 2019

Interest in dual nitrogen expander liquefaction technology for floating liquefied natural gas (FLNG) applications is driven by the following factors: inflammable refrigerantsimplicitylow weightno refrigerant sloshing or maldistribution due to motionquick start-upeasy adjustment for changing feed conditions

The downside is that dual nitrogen expander technology offers significantly lower liquefaction efficiency than competing FLNG technologies. The proper selection and sizing of the upstream gas treating and liquefaction system is critical during Front End Engineering Design (FEED) to ensure that the system footprint, weight and center-of-gravity is appropriately estimated as this effects the sizing, design and performance of the floating hull.

This paper will demonstrate how the process design can be optimized over a range of feed compositions or conditions if some flexibility is built into the liquefaction heat exchange during design. This preserves flexibility as a key advantage of the technology. The intent is to reduce process inefficiencies and promote competitiveness with other technologies. Note that there are many different nitrogen expander technology configurations available in the market. The configuration used here is generic and used to demonstrate the optimization concept.

With 10 independent variables and coupling between the variables, this optimization is difficult to perform using simple manual methods. Therefore we will employ a coupled simulation-optimization method.

This paper also provides insight to the application of coupled simulation-optimization to problems, as illustrated by the specific application to a dual titrogen expander technology. Although this method is applicable to the initial design of liquefaction processes, the focus here is on off-design optimization of the facility later in the design cycle and in operation.

This optimization methodology is shown to provide benefits beyond the initial process design, extending into the operation of the facility. The methodology does not rely upon a specific tool set and there are non-academic tools that support this approach.
The Fusion Bonded Joint: A New Way of Joining HDPE Lined Pipes for Reeling and Fatigue Sensitive Applications
Authors: Lirola François
Published: April 2019

Corrosion protection is a key aspect of all subsea developments. Indeed the complexity of subsea pipe maintenance and repair makes it necessary to provide solutions suitable for the full life time of the field. Though sensitive applications such as production lines transporting corrosive compounds, CO2 and H2S for instance, immediately comes to mind when mentioning corrosion, other applications, though seemingly less demanding, also require to be properly addressed from a corrosion perspective. One of these applications is water injection lines.

Corrosion in these lines is usually tackled with using a wide range of approaches depending on operation philosophy: topside treatment, corrosion allowance, cladding or plastic liners. A balance usually has to be found between how extensively the injected water is processed topsides and what other corrosion mitigations methods are deployed. This assessment should be carefully conducted the selected approach will impact procurement and installation costs. For instance, increasing the pipe wall thickness to cope with corrosion would results in higher lay vessel installation capabilities as well as longer welding time while relying on clad pipes would negatively impact procurement costs and require more complex NDT methods to be implemented.

Plastic liners offer a relevant alternative though their implementation has to be carefully assessed so as to ensure it remains cost competitive. To that extent, the Fusion Bonded Joint has been developed and qualified. This system ensures the continuity of the plastic layer at carbon steel weld locations while limiting the offshore cycle time thus preserving lay rates of the installation vessel.

This paper includes an overview the technology itself as well as a summary of the extensive qualification campaign that has been carried out. A global overview of the testing campaign will be provided from the early stages of the development to the full scale testing of the technology in an environment representative of its actual operating conditions. Topics discussed will include: prototyping of the system and associated tools, qualification of the electro-fusion welding process as well as its control and qualification of the carbon steel welding process. The main challenges and outcomes of tests performed will be presented and discussed. A focus on the specificities of the fatigue testing campaign will be presented including fatigue string design as well as fatigue performance of plastic electro-fusion weld. Eventually, the applicability of the FBJ to reeling will be discussed.
Drilling Permit Application Hurdles for Gulf of Mexico Oil and Gas Exploration
Authors: Crouch Don , Hoefler John
Published: April 2019

The objective of this paper is to provide insight into a few of the dominant hurdles applicants experience when preparing information for review by the US Bureau of Safety and Environmental Enforcement (BSEE) when applying for a permit to drill. Numerous requirements for the Application for Permit to Drill (APD) exist that can present a complex task of aligning documentation and information across multiple process participants that are not always apparent at the outset. The included information will follow the general path that exists in BSEE APD development, including 30 CFR §250.410, which defines some of those numerous requirements.

The paper will include BSEE requirements in 30 CFR §250.410-16, -18 "How do I obtain approval to drill a well?" the BSEE APD Development Phase Flow-chart, 30 CFR §250.731 "BOP Systems and … Components", §250.713 "if I plan to use a MODU", and additional required compliance statements, and explain how the sources of information can differ from project to project and within groupings of defined requirement sets (BSEE 2016).

The paper will also include a brief review of requirements set out by other parts of 30 CFR §250, not specifically delineated as part of the APD, but specifically required for execution.
Providing Well Containment Equipment for HPHT Service
Authors: Cowan Bill , Kaculi Jim , Frazer G. Ross
Published: April 2019

It is instructive to think about the current state of subsea well system design in its historical context. That is especially true if you look first at the earliest years, then at the years following the 1969 Santa Barbara blowout and spill, and then at the years following the Macondo blowout and spill. These last two periods illustrate both important similarities and important differences in equipment design, standardization, and regulation.

This paper examines the advances in design, standardization, and regulation of subsea well control and well containment equipment. This progress has continued the conservative, step-wise advances that have characterized the history of the subsea drilling and well control industry. This paper uses as an example the recent project developing a new 20,000 psi/350F capping stack.
Offshore LNG Mega-Module Solution
Authors: Dimbour Jean-Philippe , Ferron Loic , Luquiau Eric , Laflotte Benoit
Published: April 2019

Offshore floating LNG can offer an optimum CAPEX solution either for the development of large or stranded gas fields, including full processing functions, or as an enabler to oil production while monetizating associated gas.

The offshore LNG mega-module solution was developed to meet the challenge of producing competitive LNG offshore, leading to the next generation of floating LNG facilities.

This paper decribes the offshore LNG mega-module innovative solution of which the features are patent pending. The design features are highlighted, then the specifics of combining topsides with hull are presented, followed by the installation particulars. Finally, perspectives and savings in using this solution are presented.