bluuebunny/crossref_metadata_2025 huggingface dataset:
Saving Time and Reducing Risk with Subsea Wellhead System Running and Test Tools
Authors: Williams Gregory D.
Published: April 2015

Reducing oil prices, wellhead system performance and regulatory testing requirements are driving the need for efficiencies in the installation, testing and support of well operations worldwide. Wellhead equipment manufacturers provide a critical role in maximizing these efficiencies by supplying installation and test tools with increased functionality, versatility, performance and reliability. Many operators provide minimum commercial bid specifications for subsea wellhead tools, but these may fall short of addressing the actual operating expense (OPEX) time savings certain tools provide. Likewise, in scenarios where operators are defining their wellhead system based upon these capital expense (CAPX) specifications, the realistic OPEX benefit of the tools provided by different suppliers may be overlooked. The goal of this paper is to expound upon the benefits and complexities of subsea wellhead tooling for the practical benefit of increased operational efficiency and reduced personnel risk exposure. Saving a trip may cover the cost of the subsea wellhead tool many times over.

In recent years subsea wellhead suppliers have focused on increasing bending capacity, increasing pressure ratings, casing carrying capacity, lockdown capacity and temperature ratings. At the same time considerable effort has been applied to reducing the number of trips into the well and accomplishing more activities with each trip. Saving just one trip into the well can save up to 24 hours of rig time thus saving USD 500,000 million of non-productive drilling cost. To achieve these trip savings, the running and testing tools will become more complex and therefore more costly. Additional purpose built tools may have to be added to the running and testing tool package to support the new trip saving equipment. At the same time operators and drilling contractors are demanding lower costs, more reliability, simple running procedures, fewer tools and less rig down time. This paper will strive to find the balance that meets the customer requirements and minimize the number of tools while saving as many trips into the well as possible. Tools with increased complexity will increase down time risk and cost but the reward in trip savings will make the risk manageable. Cost comparisons and trip comparisons between conventional and latest generation subsea wellhead systems will be presented.
FLNG: Applying Advanced Technology to Bring More Natural Gas to Market
Authors: Boekhorst Alexander , Steenson Bruce , van der Velde Harry
Published: April 2015

Shell is the world's largest international oil company by equity LNG production with ownership in many liquefaction projects currently in operation or under construction. Now floating liquefied natural gas (FLNG) is set to drive the next major shift for Shell and the LNG industry. FLNG technology allows for the production, liquefaction, storage and transfer of LNG at sea, as well as the ability to process and export liquefied petroleum gas (LPG) and condensate. This enables more gas fields to be developed which would otherwise be economically challenged and will bring more natural gas to market.

Shell's final investment decision (FID) for Prelude in May 2011 was the world's first FID for a FLNG project. Shell is the operator of Prelude FLNG in a joint venture with INPEX (17.5%), KOGAS (10%) and OPIC (5%). The facility is being built by a consortium of Technip and Samsung Heavy Industries (SHI), with the Geoje yard in South Korea being a key construction location.

The development of FLNG is complex. Shell has been working on FLNG technology since the mid 1990s drawing on more than five decades of expertise in LNG technology, LNG shipping and operating offshore facilities. Shell's approach to FLNG is to design for safe, high availability and reliabile production using proven technologies. The constraints of space and seaworthiness however, required the designers to assemble these technologies in novel configurations. Examples include the internal turret -suitable for tie-back of complex subsea systems and harsh meteocean conditions, a double wall substructure hosting the product storage tanks, processing equipment that has been modified to allow it to operate efficiently under marine conditions and specially designed cryogenic loading arms able to operate in a dynamic offshore environment.

The safety of the FLNG facility has been foremost during its design. The topsides layout has been developed using Quantative Risk Assessments and rigorous process safety standards. The layout also includes 20 meter safety gaps across the full width of the FLNG barge between the main processing modules with escape routes along both sides of the facility, as well as through the central alley.

Shell is applying standardisation as a philosophy for its FLNG design, so that developments can become faster and more cost effective. Based on this philosophy, we have also developed a FLNG solution designed for leaner gas fields that has many similarities when compared to the standard FLNG design. The so called ‘FLNG Lean' can be applied on fields with lower liquids yields and, by optimizing liquid handling and storage facilities, FLNG Lean is able to deliver higher LNG production capacities.
SpoolSep for Subsea Produced Water Separation - Experimental Results
Authors: Shaiek Sadia , Grandjean Laurent
Published: April 2015

Subsea Processing provides effective solutions to develop more and more challenging deepwater fields while maximizing oil recovery and optimizing the topsides.

By removing most of produced water at the seabed, a subsea liquid/liquid separation station allows to eliminate the need to transport high volumes of water from deepwater mature fields production and then to debottleneck existing topside facilities and to reduce the required water treatment surface equipment. Moreover, the low subsea separation pressure reducing the back pressure on the subsea wellhead allows for an increase in oil recovery, which is a key driver for such a system.

Dealing with the deepwater and high design pressures constraints, the SpoolSep, developed by Saipem for subsea gravity liquid-liquid separation, is made of several horizontal pipes working in parallel. The use of small and long diameter pipes for effective gravity separation of produced water combines robustness and efficiency. The pipes are designed as subsea spools which can be connected and disconnected individually for easy installation and maintenance.

A first test campaign was performed in 2013 on a purpose built multiphase flow loop operating with air, water, and model oils at ambient conditions using a transparent SpoolSep model made of four parallel Plexiglas pipes of 200mm ID and 18m length each. Different inlet conditions, such as flowrates, water cut, gas-volume factor, shear rate on water/oil mixtures, water residence time, and spool inclination, were tested to qualify the separator efficiency and operability, resulting in a whole flow visualisation inside the pipes.

Additional tests using several solid particle sizes were performed to qualify sand deposition and determine the limits of sand transport by fluid flowing inside a single spool.

The paper presents the main findings of the experimental tests that validated the multiphase flow distribution inside the spools, levels control and symmetry. Moreover, the validation of the SpoolSep design criteria regarding required separation performances is presented. Main observations and key findings on tests with sand are also described.

The presented work focused on the development and qualification of the fluid processing technology and does not make mention of any mechanical or structural design work.
Modeling and Simulation; Subsea Stepout and Tieback
Authors: Korn Milton , Mesineni Shilpa , Hu Weiguang
Published: April 2015

Recovery of subsea resources located at great distances from shore at great depth often envision some processing of the recovered product on the sea floor prior to transportation to a floating or onshore facility. Processing and transportation efforts require that energy be transported at the required rate and controlled to facilitate stable operation. In sea floor processing facilities, energy consumers can be expected to be deployed down hole at primary pumping/compression and booster pumping/compression stations on the sea floor as well as being located along the length of the tie-back (pipeline) to the onshore receiving facility.

Electrical supply is likely to consist of a subsea transmission line running (step-out) alongside the tie-back and being periodically tapped along the length as required to deliver power to booster pumping/compression stations. The length of the transmission line, various global loading scenarios, and varying loading at specific receiving points is a challenge for maintaining power quality and stability at each receiving point, where energy/power is drawn to supply loads.

ABS has built preliminary models of subsea pipeline tiebacks and electrical step outs. Engineers have performed simulations of energization of the step out, and have studied step-out electrical transients. Future work will focus on the study of steady state and slow dynamic pipeline flow, power system characteristics and the interaction between the hydraulic and electrical systems refining the models to include more of the hydraulic characteristics and electrical characteristics of the coupled systems to increase the fidelity of the simulation.
Bonga Northwest Subsurface Development – Planning, Execution and Uncertainty Management
Authors: Pokima Sophie , Afolabi Raphael , Fakunle Oludayo , Njoku Chukwueke , Okonkwo Paulinus
Published: April 2015

The Bonga North West (BNW) field is located in Shell operated Oil Mining Lease (OML) 118, a deepwater development in Nigeria. This paper presents the BNW subsurface development strategy and the associated uncertainty management both at planning (Field Development Plan -FDP) and execute phase.

The first development in the OML 118 acreage is the Bonga Main field which came on stream in November 2005 via a Floating, production, storage and offloading (FPSO) vessel. The development strategy of the block is to maximize value from the asset, ensuring that the hub is kept full by developing reservoirs in the nearby fields while optimizing production from the block. In pursuant of this strategy, detailed subsurface evaluations were carried out to estimate expected recovery of the nearby fields as potential tie-backs to the Bonga Main FPSO. The size of nearby discoveries and proximity to the FPSO were two key parameters used to develop the OML 118 development strategy.

BNW was discovered in 2003 following the detailed interpretation of 3D seismic acquired in 1995 on the acreage. Integrated evaluation across key disciplines established commercial viability of the project. This, coupled with a detailed geo-hazard study, formed the basis for the 2011 BNW FDP. The FDP proposed the field being developed with nine wells in two phases of drilling. The development phasing was driven by the requirement to manage the field uncertainties by gathering additional data. The first phase development involves six wells (four oil producers and two water injectors).

BNW leveraged on its close proximity to the existing Bonga Main infrastructure and was approved as a subsea tie back development to existing Bonga Main FPSO. The FDP enabled a robust management of challenges such as shallow gas occurrence, structural/depth uncertainty, stratigraphic/reservoir development, reservoir connectivity, fluid prediction in the shallow horizons, bore hole stability and overburden shale issues encountered in the execution phase. Also a new technology that targeted managing of impairments in water injection wells experienced in the operation of Bonga Main field was also successfully deployed in the BNW field development. All Phase 1 development wells have been successfully drilled and several learnings from this project have been documented and will be used on projects going forward.
While History may not Repeat Itself, It Often Rhymes: Evolution of Offshore Technical Process Safety
Authors: Herbert I , Peterson E , Sanderson D
Published: April 2015

The 6th July 1988 explosion and fires on the Piper Alpha platform in the North Sea initiated a review and fundamental change to the offshore safety culture in the UK. A large part of this culture change was related to the use and application of risk assessments in the management of offshore major accident hazards. The 2010 Deepwater Horizon event can be seen as a repeat of a major accident event triggering a major review and update to safety culture, this time to US OSC operations. The European operations have adopted and developed risk-based performance requirements, thought of as ‘goal set’, compared to the focus on use of industry standards and compliance in the US OCS (Outer Continental Shelf) operations, thought of as ‘prescriptive’. This perception is not strictly correct but does indicate the emphasis that the two areas operate under. This paper shows how UK Offshore risk assessments still have to show use of good practice, but depending on the nature of the specific installation there is the flexibility to identify, assess and specify required measures that may be deemed beyond good practice. This has developed into a range of technical risk assessments that model in more detail, when required, the extent, severity and consequences of offshore hazards and the required performance of measures to prevent, detect, control, mitigate and allow successful escape from these hazards.
Safety Case in GoM: Method and Benefits for Old and New Facilities
Authors: Carval Julia , Das Bibek
Published: April 2015

The purpose of Bureau of Safety and Environmental Enforcement (BSEE)'s Safety and Environmental Management Systems (SEMS) is to enhance safety of operations in the Gulf of Mexico (GoM) region. One of the four principal SEMS objectives is to encourage the use of performance-based operating practices. However, the current U.S. Regulatory framework for offshore operations in GoM does not provide the adequate tools to focus on the specific risks associated with a facility. The adoption of a Safety Case regime would steer the operations in the GoM towards this goal. Operators could take over the Safety Case as a significant input for the development of their Risk Management and Asset Integrity Management (AIM) programs for existing operating facilities as well as new facilities being planned.

The paper discusses the application of a Safety Case and how the Operator can demonstrate that the major safety and environmental hazards have been identified, the associated risks are estimated and how these risks are managed by achieving a target level of safety. Throughout the Safety Case road map, the identification of the Safety Critical Elements (SCEs) and the associated Performance Standards represents one of the corner stone of the AIM Strategy. Introduction of the Safety Case would not imply a complete overhaul of the current Regulation, but would lead to a continuous and adequate enhancement of the Regulatory requirements towards a performance-based approach. It would include a prescriptive-based policy, combined with a performance/goal-oriented process, considering the specific risks inherent to the installations and the demonstration of how these risks are managed.

With help of an example the paper discusses how application of Safety Case for existing facilities would highlight particular risks that may have been misjudged, taking into account the current state of its installations and the actual operational procedures in place. Further, this paper shows how existing Risk Management and AIM systems could be revised based on identification of SCEs and definition of the associated Performance Standards. This would also give the Regulator a quantified picture of current operations in the GoM and assist in re-defining the distribution of its resources and efforts in order to have an efficient review and verification impact.

For the new facilities, the introduction of the Safety Case at the early stages of design would ease the integration of the overall risk management plan at each level of organization. The Regulator would have the ability to cross-analyze the risk results arising from the Formal Safety Assessment studies with the risk management plan drafted by the Operator. This paper investigates the possible integration of a performance/goal-oriented regime into existing Risk Management and AIM systems.
Integration and Flawless Start-Up of Different Systems in Bonga North West Project
Authors: Ilesanmi Olaniyi , Katimi Theo Ekiyor , Erhabor Kingsley , Ikhenebome Thomas , Kanu Chika , Mbonu Obinna , Mehta Tejus , Ofoni Sylvester
Published: April 2015

The Bonga North West Project (BNW) is the first subsea extension to the existing Bonga Main subsea facility, as well as the first major subsea tie-back to be executed in the Nigerian sector of the Gulf of Guinea deepwater. This paper provides a detailed discussion of the process of integrating the new systems comprising subsea producers, injectors and all the ancillary facilities, to an existing, but different, Original Equipment Manufacturer (OEM) system. It will also give a detailed explanation of the intermediate systems engineered to achieve this integration, and the process used for successful integration of the two different systems. The planning and deployment of a new Completions Management System for the commissioning of the new facilities, and the strategy adopted to achieve a flawless start up will also be presented in this paper.

To ensure a flawless start-up, Shell Project standards were employed. A Simultaneous Operation (SIMOPS) emergency shutdown was carried out to check the integration of the new subsea infrastructure as part of final checks performed prior to start up.

To enable seamless integration between the two different subsea systems, staged system integration and verification tests were planned and executed to ensure that each component performs as per intended design. A series of assurance activities were carried out to demonstrate alignment between design intent and healthy operations of the new subsea system, for the following:

Correlation of field data with design analysis for both the existing and new systems

Benchmarking the performance of the new integrated system against the old system

Topside and Subsea controls integration between two distinct systems

Environmental barrier and isolation assurance

The success of this endeavor is evidenced on a Flawless Start-Up and operation of the new system as an integral part of the nine-year onstream Bonga Main system. Disruption to production and impact to the existing asset were successfully minimized.

Significant insights and learning were gained in the areas of subsea communication and control interfaces, defining multiple interfaces, integrated system testing, flawless startup and sharing of information across multiple vendors.
Enhancing Air Gap Design and Assessment in Deepwater Floating System Performance
Authors: Wu Wan , Zeng Jack
Published: April 2015

This paper discusses how to enhance air gap design and assessment for the deepwater floating systems. The authors first establish an analytical method to predict air gap considering global upwelling due to wave diffraction, as well as random wave effects. Then the authors apply the analytical method to simulate the air gap of typical deepwater floating systems through uncoupled analysis combining frequency domain and time domain global motion analysis. For comparison, a coupled analysis with hull structure, mooring and riser system is also carried out. The authors then look into model test verification and correlation analysis of air gap prediction, especially how to deal with random motion effects on deriving the extreme values of air gap. Furthermore, the authors illustrate how to improve deepwater floating system performance and cost-effectiveness by utilizing a practical and reliable air gap design approach.

The air gap simulation results derived from the proposed analytical procedure correlate well with the wave basin model test results. This analytical procedure has also been applied to deepwater floating system design for field development projects, which can be considered as a practical and reliable air gap design solution for optimizing global configuration to improve deepwater floating system performance and cost effectiveness.

Key words: Air Gap; Floating Structure; Model Test Correlation; Random Motion
Thermal Failures in Batteries Used in Subsea Power Applications
Authors: Marr K. C. , Somandepalli V.
Published: April 2015

Battery packs and modules have been used extensively in industries such as consumer products, transportation and grid energy storage. Recently, interest in using large battery packs in the oil and gas industry has significantly increased. In particular, there has been an interest in developing subsea power systems, using, rechargeable batteries, for autonomous underwater vehicles (AUVs) and measurement while drilling (MWD) applications. Operating a battery with high energy density in a subsea application has several challenges–one of which is how to safely manage potential thermal failures in a harsh high pressure, high temperature environment. In this work, we outline a testing methodology for quantifying thermal hazards and overpressures associated with battery thermal failures. This work provides a framework for analyzing and quantifying thermal failure hazards for battery packs and modules that may be used in subsea power applications. Detailed characterization of the thermal failure and quantifying metrics such as maximum overpressure, rate of pressure rise, and amount of gas generated are necessary to design and implement safety features in subsea power systems to operate these batteries safely and efficiently. Properly addressing these hazards can help reduce the loss of productivity of subsea machinery and instruments, and prevent the development of life threatening conditions when large batteries are used.
Investigation and Optimization of the Effects of Geologic Parameters on the Performance of Gravity-Stable Surfactant Floods
Authors: Tavassoli Shayan , Pope Gary A. , Sepehrnoori Kamy
Published: April 2015

A systematic simulation study of gravity-stable surfactant floods has been done to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes have been introduced to minimize the effects of geologic parameters and improve the performance and the economics of surfactant floods. The simulations were carried out using horizontal wells in heterogeneous reservoirs. The results show that gravity-stable surfactant floods can be done at a reasonable velocity and with very high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out using a three-dimensional fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed using realistic surfactant properties based on laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion viscosity and it turns out there is an optimum value that can be used to significantly increase the velocity and still be stable. The salinity gradient can be optimized to gradually change the microemulsion viscosity. Another alternative is to inject a low concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated and strategies were developed for minimizing its effect on the process.
Effect of Hold Up on the Hydrate Stability Zone
Authors: Chalkidis Anastasios , Tohidi Bahman
Published: April 2015

Currently, reservoir fluid compositions (based on PVT reports) are used in predicting the hydrate stability zone. However, in multiphase flow there are variations in the local composition that may affect the hydrate stability zone. The main objective of this work was to investigate the effect of hold-up and the resulting variation in the local composition on the hydrate stability zone of various hydrocarbon systems.

A thermodynamic software was used to predict the composition of various phases at different locations along a pipeline. A range of liquid hold-ups were assumed and the local composition was recalculated. The hydrate option of the software was used to predict the hydrate stability zone of the resulting local fluid composition. The calculations were repeated for a number of fluid systems and the results are presented in this work.

The calculated hydrate stability zones for various hold-ups were compared with that of original reservoir fluid. The results show that hold-up plays an important role on the hydrate stability zone. High gas hold-up shifts the hydrate stability zone to the right. However, as high gas hold-ups occurs at high point and away from aqueous phase, in case of changes in the system conditions the amount of hydrates are limited to the amount of water available.

This paper demonstrates that the hydrate stability zone of a multiphase fluid in a pipeline is a function of hold-up and the resulting changes in the local composition. This could have important consequences on the hydrate prevention strategies.
Seismic Processing Workflow with an Integrated Model Building Toolkit Significantly Improves Imaging in Shallow Water, Complex Salt Province
Authors: Zhu G. , Smith D.
Published: April 2015

We present a seismic processing workflow that significantly improves subsurface images of hydrocarbon targets in shallow water. Our workflow is dependent on an integrated velocity model building toolkit, which works well for salt geometry and sediment velocity model building. The workflow addresses the challenges associated with complex salt structures and produces an improved subsurface seismic image in the complex salt province. A real case is presented here to demonstrate the workflow.
Lucius Project: Export Oil and Gas Pipeline Development and Execution
Authors: Schronk L. , Biggerstaff G. , Langmaid P. , Aalders A. , Stark M.
Published: April 2015

This paper provides an overview of the unique challenges faced by the oil and gas export pipelines during the development and execution phases of the Lucius project. The oil pipeline will focus on the repurposing of 47 miles of the Phoenix gas pipeline for oil service which reduces infrastructure and environmental footprint in the Gulf of Mexico. The gas pipeline will focus on the re-engineering of the pipeline end terminations (PLETs) and installation procedures after the engineering and fabrication phases of the project were complete due to a change in installation vessel so that Lucius first production was not impeded.

The oil export pipeline, with a nominal capacity of 115 KBPD, is an 18-inch, 147 mile pipeline consisting of 3 segments: (1) 74 miles of 18-inch new build pipeline from the Lucius spar to the existing Phoenix pipeline, (2) test and re-use of an existing 47 mile section of Phoenix gas pipeline converted to oil service, and (3) 26 miles of 18-inch new build pipeline to the existing platform South Marsh Island 205 (SMI-205). First oil was delivered in 1Q2015.

The gas export pipeline, with a max capacity of 400+ MMCFD, is a new build 20-inch, 209 mile pipeline anchored by the Lucius and Hadrian South developments. The pipeline starts in Keathley Canyon 831 and terminates into a new build transportation platform located in South Timbalier 283 (ST-283). First gas was delivered in 1Q2015.
Top of Line Corrosion: An Evaluation of Critical Parameters that Drive Mitigation Methods and System Design in Deepwater Gas Systems
Authors: Osorio N. F. , Bukkaraju S. , Garduño J. L. , Jordan L. C.
Published: April 2015

Top of Line Corrosion (TOLC) occurs in deepwater wet gas systems when water vapor condenses on the upper internal walls of the flowline due to the heat exchange occurring between the hot fluid and the colder environment. The condensed liquid becomes enriched by the corrosive species naturally present in the gas stream and assumes a low pH because it does not contain any buffering species such as bicarbonate or iron. The predominant concern is carbon dioxide (CO2), which reacts with water to form carbonic acid (H2CO3), although hydrogen sulfide (H2S) and organic acids can also present significant challenges and drive the corrosion process.

Multiple factors influence the TOLC process. These include fluid characteristics and composition, flow regimes, pH, flowline material properties, fluid and ambient temperatures, protective and insulation layers properties, bathymetry and burial depth. These factors among others drive the heat transfer and consequentially impact the water condensation and the resulting TOLC rates. Adequate evaluation of the independent factors driving the TOLC risk is necessary in order to obtain an accurate assessment and mitigation option selection.

This paper aims to categorize and evaluate the impact of every key factor influencing TOLC risk and describes two methodologies available for TOLC assessment; Heuristic method, based on indirect determination of the TOLC rates, and the holistic method based on a system wide risk assessment, implemented through a System Component Analysis (SCA) approach supported by proven dynamic thermal-hydraulic and corrosion models and coupled with field experience. In addition, this paper presents the procedure to undertake effectively the TOLC risk assessment and mitigation option selection strategy based on the SCA methodology.
Numerical Simulation of Wave Loading on FPSO in Various Wave Conditions
Authors: Lubeena R , Gupta Vinay Kumar , Srinivasan Vedanth , Mohan L Srinivasa
Published: April 2015

In the design of Floating Production Storage and Offloading facilities (FPSO), it is important to predict the seakeeping parameters like FPSO motions. This paper focusses on the prediction of FPSO motions and wave impact loads in various irregular sea waves and proposes a Computational Fluid Dynamics (CFD) model. Accurate prediction of FPSO motions and wave impact loads requires the accurate prediction of wave kinematics. Waves generated by winds blowing over the water surface in real oceans are short-crested, so the dynamic responses of the moving structure will be very different in long crested and short-crested waves. In this paper, we have verified the pure propagation of oblique short-crested random waves in numerical wave tank with the analytical results, which serves as the basis of more complex analysis including ship hull interaction with waves.

The proposed CFD model uses Multiphase Volume of Fluid Model (VOF) along with Six Degrees of Freedom Model (6DOF) to predict the hydrodynamic forces and the ship responses. Long crested and short-crested random waves are simulated in a numerical wave tank, where boundary conditions for free surface profiles and velocities are imposed at the velocity inlet boundary using Jonswap frequency spectrum and cosine-2s directional spreading function.

Wave slamming loads and the structural responses depend on many factors, like sea state, FPSO speed, draft, wave heading angle, local structure etc. In this paper, we have analyzed the wave slamming on a moving FPSO for different sea states (unidirectional, multi directional with 45 deg and 90deg angular spread) and studied the resulting hydrodynamic forces and related structural interactions. Ship motions (heave, pitch and roll), vertical accelerations, pitch velocities, roll velocities and the wave impact pressures are compared among different sea states.
Process Support and Marine Systems in the Hull - Innovation Meets Regulation
Authors: Kitchen Peter
Published: April 2015

Historically, the marine systems on a Spar (ballasting, de-watering, ventilation, access, etc.) are relatively simple. However, attracted to the operational value of having large volumes of storage, particularly for flow assurance of the subsea wells and flowlines during shut-down conditions, the Gulfstar hull design criteria included the capabilities to store, inside the hull, 10,000 bbl of dead oil, 1,000 bbl each of diesel and methanol, all in integral carbon steel tanks, plus 2,400 bbl of subsea chemical in 18 individual stainless steel, vertical pressure vessels in both 100 and 200 bbl sizes. This took the Spar hull from being a relatively ‘unsophisticated’ hull to something much more complex.

The paper traces all the key process support and marine systems from their humble beginnings to their final form with all the Regulatory inputs and requirements which, in hindsight, turned out to be almost ‘a bridge too far.’ After a short description of the systems with unique features and the regulations and design challenges behind them, the paper focuses on recommended changes for future projects, in addition to the obvious idea of radically simplifying those systems.

As marine systems get more complex and projects try to introduce lower weight/lower cost/safer solutions ideas to optimize them, the existing Rules and Regulations can impede attempts to innovate in this area. As part of the lessons learned discussion, the paper speaks to the efficacy of risk-based design as compared to the traditional proscriptive/rules-based design approach as a way to accelerate innovation without compromising safety and operability.

The information and results presented in this paper are applicable to engineers, class societies and regulators when trying to introduce more efficient process support and marine systems.
An integrated Power Solution for Enabling Large-Scale Subsea Processing
Authors: Rasch Bjørn
Published: April 2015

There is a growing demand within the oil and gas industry for an integrated subsea power system in order to achieve the highest availability of power supply and power distribution subsea. For that reason, since 2010, a subsea power grid system is being developed by Siemens. The purpose of this system is to power subsea consumers like pumps and compressors in deep and ultra-deep waters and for long step-outs.

The subsea power supply and distribution system, including all its components, is designed and qualified to work at a water depth of 3000 meters, and up to more than 200 kilometers step-out distance. It will offer an integrated, reliable and cost-efficient subsea power solution for multiple consumers on the seabed.

The development and qualification program is currently in its last stages. Testing of the individual components (subsea transformer, switchgear, variable-speed drive and communication/control system) will be followed by a complete system test. Overall, the development and qualification program is expected to be completed in 2016, at which time the system will be ready for a full-scale subsea pilot project.

The power system must have standardized, flexible and configurable interfaces to have an optimal fit with the processing system. The integrity of the power system is governed by a dedicated power control and monitoring system which enables transparent and standardized communication with all the power modules. The Subsea Power Grid solution offers an infrastructure with standardized interfaces both on the topside / onshore power generation and to the subsea consumers – both for the power line and for the power control and communication line. This ensures flexible arrangements with the subsea field's overall processing system without challenging the integrity of the power distribution.

The paper focuses on how a subsea power distribution system can be integrated in any subsea pumping or compression systems without sacrificing the integrity of modules in the subsea power grid solution.
Gulfstar - VIM and Mooring Chain Fatigue
Authors: Park Young-Chan (Y.C.) , Antony Arun , Moideen Hisham , Jamnongpipatkul Arada
Published: April 2015

Spars have been scrutinized for years for their response to large current velocities in the form of the so-called, "Vortex Induced Motions." While some field data on such motions have been collected, the availability of this data is limited, so inquiries and computations about this phenomenon are largely based on the results of tow tank-based model testing.

The Gulfstar FPS, with its relatively small Classic Spar hull (85 ft diameter, 524 ft draft) is no exception to VIM. In fact, its "Classic" (full cylinder) hull is more affected in this regard than either the Truss Spar hull form or the multi-column floaters, Semis and TLPs.

This paper describes the Gulfstar hull's journey through tow tank testing, flume tank testing and computational fluid dynamics (CFD) computations. This journey uncovered concerns about the fatigue life of the chain. Several design changes were implemented during the design phase to mitigate the fatigue concerns. These concerns, mitigation strategies, differences in the testing programs and CFD results plus notable lessons learned are described and commented upon in this paper.

The paper concludes with analysis results of the platform's responses to loop current events in the second half of 2014 and how the actual motions compare with predicted motions.
Gulfstar - Naval Architecture From Design to Hull Installation
Authors: Antony Arun , Park Young-Chan(Y.C.) , Zou Jun , Jamnongpipatkul Arada
Published: April 2015

Williams Field Services (WFS) use of the classic Spar hull form for the deepwater field development projects is the first classic Spar hull since ExxonMobil installed the Diana/Hoover Spar in 2000. Since that time, 14 Truss Spars and one Cell Spar have been installed. Learnings from those Spars along with increases in the metocean condition since 2000, significant increases in topside payload during detailed design, support of the five initial SCRs on a porch at the keel plus the decision to fabricate the hull in a US graving dock provided new challenges for the Naval Architects from design through to hull installation.

The paper discusses the key drivers, constraints and criteria that had to be reconciled into a floating system with acceptable global motions, acceptable horizontal trim and robust characteristics for changes in topside payload and CGs. Examples of these sometimes conflicting design requirements include: the increased hull freeboard which was driven by the new metocean condition which then led to a higher topside VCG, a 30% increase in the topside's maximum operating payload between the end of FEED and midway into final design yet the depth and length of the graving dock dictated that these changes had to be accommodated without increasing either the diameter or draft of the hull. This paper presents the challenging results of the model tests and their impacts on the design of the mooring system as well as the very close tolerances in trim and stability for the tow out of the graving dock and then to site.
Guidance for Civil Engineers Working in Marine Renewable Energy Areas – Keynote Address
Authors: Stewart William P. , Hudon Thomas J.
Published: April 2015

This paper provides an overview of the evolution of a guide document for civil engineers produced by the American Society of Civil Engineers (ASCE) Coasts, Oceans, Ports, and Rivers Institute (COPRI) Marine Renewable Energy (MRE) Committee over the last five years. The document will provide guidance to MRE designers and analysts, providing confidence as to reliability and insurability. All papers in the MRE session address specific civil engineering aspects of MRE projects. The papers cover multiple engineering disciplines required for relatively new MRE technologies that are arriving into the well-established and documented ocean environment. Some papers naturally touch on the electrical and mechanical issues involved with specific MRE device technology. The guide document that has evolved includes chapters developed by experienced engineers, generally working in sub-committees, including sections addressing: Environmental Loads,Geotechnics,Government Issues,Moorings,In-Stream Hydrokinetics (ocean, riverine, and tidal currents)Ocean Thermal Energy Conversion,Risk and Reliability,Submarine Cables, andWave Energy Converters.

In most areas the guide points towards existing well-established codes including API, ISO and Classification Societies, as well as newer evolving international codes such as those being developed by the International Electrotechnical Commission (IEC). Several MRE committee members also sit on the IEC Technical Committee (TC) 114 US Technical Advisory Group (TAG) and improve liaison between IEC and ASCE COPRI. In some areas, particularly geotechnics, the guide provides information not found in existing codes. Engineers who read the guide will gain a basic knowledge of a wide range of MRE devices, as well as an understanding of how to deal with the civil engineering aspects of their design and analysis. This information is difficult to find in a technical and comprehensive form elsewhere. This paper presents an insight as to what will be in the ASCE COPRI MRE guide.
Fabrication and Installation of the Williams Gulfstar 1 FPS (GS1) Classic Spar Hull
Authors: Cizek Mark , Godfrey Dan , Wright Larry
Published: April 2015

The majority of Spar hulls have been fabricated overseas on skid ways and transported stateside for quayside offloading using submersible Heavy Lift Vessels. For the Williams Gulfstar 1 FPS (GS1) Floating Production System (FPS) we elected to construct the hull in a graving dock and tow it directly to the installation site. This paper will describe the unique fabrication and installation techniques that were used to build a classic Spar hull within a graving dock, rather than using the traditional skid way and overseas-transport approach. It will also describe the GS1 hull installation campaign including tow to site, upending, and hull and mooring installation.

The overall fabrication approach for the GS1 hull was a stateside program utilizing Gulf of Mexico fabricators. The fabrication portion of the paper will focus on the construction methodology for the hull, including the lessons learned incorporated into the design before the start of construction, as well as those realized during construction that were implemented at site to improve both cost and schedule. The major challenges addressed will include modular fabrication, dimensional control, and sequencing and lifting the modular blocks into the graving dock using one of the world’s largest onshore cranes.

The GS1 installation planning and execution experience will be described with focus on a record-breaking installation program with specific identification of the considerable benefits realized by using a temporary work deck for pull-in of all mooring lines and risers. This paper highlights lessons learned, both good and bad, through the unique fabrication and installation approaches used to safely fabricate and install GS1. These lessons learned are applicable to engineers and planners for the fabrication and installation of a Spar-based FPS.
Developments in Deepwater Installation Systems
Authors: McPherson Gregor
Published: April 2015

With more processing equipment and functions traditionally based topside being deployed subsea to deeper waters, so the industry is pushing the limits of installation engineering technologies. Lowering heavy subsea processing equipment to water depths in excess of 1,500m is challenging the industry to reassess long held assumptions on the performance of steel wire and synthetic fibre ropes, together with winch technologies.

In this paper, Caley Ocean Systems draws on its experience of both deepwater installation systems (high loads, waters depths up to 2,000m) and oceanographic winch systems (small loads, water depths in excess of 10,000m) to propose a holistic approach that considers the characteristics of the rope and winch as a whole rather than as separate elements.
Aligning Diverse Portfolio and Execution for Capital Efficiency
Authors: Martijn Dekker , Paul McNutt , Greg Roder , Stuart Wheaton , Sandeep Khurana
Published: April 2015

Today oil and gas companies are continuously facing choices encompassing a wide range of opportunities, from unconventional to ultra-deepwater, known basins with deeper and different plays to new frontiers and untested plays in the international arena. A quick look at the market underscores the diversity of deals across the conventional and unconventional sectors, across the globe and across public and private companies. Business is further complicated with large gas resources in areas with limited local gas markets and in frontier or remote locations.

Aligning a diverse portfolio with an organization's execution capabilities and capacity is an imperative to achieve capital efficiency and meet shareholder expectations. It stems from a challenge of constructing a portfolio that provides both cash flow and long term growth. There should also be a direct connection of the organization's strategy and its investment proposition; i.e. should companies mitigate risk by diversification across countries, or asset types, or play types, or alternatively, be a focused "pure-play" organization leaving the investment diversification to the investors themselves. Either way, it demands a versatile organization to create and maintain the value, and it requires innovative techniques to find a competitive edge.

This manuscript is intended to provide basic background and to set the stage for a panel discussion scheduled for 9.30am- Noon, Wednesday, May 6, 2015 at the conference. After identifying the main industry trends and discussing the basics of capital efficiency, the manuscript investigates key elements of a portfolio that enables the company's pursued strategies with the focus on exploration and development initiatives. Four (4) main plays, namely, deepwater and ultra-deepwater, unconventional, oil sands and gas (that includes liquefied natural gas, coal seam gas, etc.) plays are examined as a premise for the panel discussion area. The panel will discuss how companies are handling these challenges of diversity with financial and organizational strengths while carefully selecting technology to be competitive.
Genetics of Interstitial Lung Disease:Vol de Nuit(Night Flight)
Authors: Furukawa Hiroshi , Oka Shomi , Shimada Kota , Tsuchiya Naoyuki , Tohma Shigeto
Published: April 2015

Interstitial lung disease (ILD) is a chronic, progressive fibrotic lung disease with a dismal prognosis. ILD of unknown etiology is referred to as idiopathic interstitial pneumonia (IIP), which is sporadic in the majority of cases. ILD is frequently accompanied by rheumatoid arthritis (RA), systemic sclerosis (SSc), polymyositis/dermatomyositis (PM/DM), and other autoimmune diseases, and is referred to as collagen vascular disease-associated ILD (CVD-ILD). Susceptibility to ILD is influenced by genetic and environmental factors. Recent advances in radiographic imaging techniques such as high-resolution computed tomography (CT) scanning as well as high-throughput genomic analyses have provided insights into the genetics of ILD. These studies have repeatedly revealed an association between IIP (sporadic and familial) and a single nucleotide polymorphism (SNP) in the promoter region of the mucin 5B ( MUC5B). HLA-DRB1*11 alleles have been reported to correlate with ILD in European patients with SSc, whereas in Japanese patients with RA, the HLA-DR2 serological group was identified. The aim of this review is to describe the genetic background of sporadic IIP, CVD-ILD, drug-induced-ILD (DI-ILD), pneumoconiosis, and hypersensitivity pneumonitis. The genetics of ILD is still in progress. However, this information will enhance the understanding of the pathogenesis of ILD and aid the identification of novel therapeutic targets for personalized medicine in future.