bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Evolution of DP Technical Support
Authors: Moen Lars Kristian 
Published: April 2015

Abstract
The first initiatives to maintain vessel position by means of electronic (not yet computerized) control of propulsion forces was in 1961. Through the Eureka and Cuss 1 projects in USA, innovative DP pioneers succeeded to perform automatic position and heading control of free-floating vessels. Station keeping uptime was approximately 25% and this was considered as significant improvement compared to known alternatives at the time. Since the early years of Dynamic Positioning, the total fleet of DP capable vessels has now grown to approximately 5000 vessels. In average, a new DP Control System is delivered every day and upgrades of systems with obsolete technology take place at increasing pace.
Development of DP related technology has enabled very advanced offshore operations under demanding environmental conditions. Computerized control systems have evolved and become more robust and with enhanced functionality. In parallel, we recognize new and innovative solutions within engine, power plant and propulsion systems. Instrumentation now includes a variety of position reference systems suitable for different operational conditions and applications. Improvements in vessel design and engineering has produced vessels that are better suited for their purpose. Traditional FMEA and simulator based test and verification of control systems have largely eliminated common mode failures. Traditional and simulator based operator and maintenance training and awareness has contributed to reduce human errors. Collaboration across the DP industry has resulted in significant improvement of overall regularity in DP operations.
The purpose of this paper is to offer insight in how support of DP Control System has changed since 1976 to meet continuously evolving needs. As the fleet of vessels has increased, support expectations have expanded in geography, operational awareness, several DP technology generations, communication technology and more. DP Support is required everywhere DP vessels operate. A long term trend is that the support gradually change from traditional on-call service and spare part logistics to operational support, system extensions related to new requirements and available technology as well as Service Lifecycle support to communicate and offer upgrades to products with limited or obsolete technology.
Batching Top Quartile Ultra Deepwater Wells
Authors: Jones Stephen , Klein Mark , Cook John , Angelidis Diogenes 
Published: April 2015

The Phase 3 wells of the BC10 Parque Das Conchas field were drilled and completed in the Campos basin offshore Brazil in water depths between 1600-1900m. The wells were delivered as part of a batch campaign, 4 months ahead of schedule and approximately 40% under budget.
The development campaign consisted of 7 horizontal wells (plus a side-tracked appraisal section).
This paper will describe some key replication considerations at a planning, operational and organisational level that enabled the delivery of performance that benchmarks in the P5 range of the industry in both schedule and cost.
Essential catalysts for this performance included the immediate, repeat use of the 6th generation DP drillship MODU from the earlier Phase 2 campaign, standardisation of the well design and procedures, operating in ¨total batch mode¨, continuity of staff over the entire 4 year campaign lifetime and targeted contract incentivisation.
With these components fixed, focus could be applied to both actively reducing Invisible Lost Time using Deliver the Limit methodologies, and NPT by way of rigorous and monitored QAQC and maintenance programs, leading to this high quality performance result.
The New Technology Enablers Developed and Deployed on a Live Project
Authors: Cruz Ivan , Claro Cláudia , Gouveia João , Lemos Luiz , Câmara Marcelo , Pereira Leandro , Mair John A. , de Paula Marcus Tadeu R. , Escudero Carlos C. 
Published: April 2015

Abstract
Petrobras and partners (BG E&P Brasil and Repsol Sinopec Brasil, in Sapinhoá field, BG E&P Brasil and Petrogral Brasil, in Lula Field) selected the ‘Buoy Supporting Risers’ system as the most effective solution for their Sapinhoá and Lula Northeast fields in 2140m depth Santos Basin, offshore Brazil. For designing the system to fit its performance requirements, various novel technologies, both in equipment and processes, were required to be developed. The purpose of this paper is to provide an understanding of these major enabling innovations and to describe their roles and complementary relationships within the ‘Buoy Supporting Risers’ (BSR) system.
Subsea Wellhead System Verification Analysis Methodology for HPHT Applications per API TR 1PER15K-1 and API 17TR8
Authors: Perales Stephen A. , Kaculi Jim T. 
Published: April 2015

Abstract
As the oil and gas industry moves into drilling and production operations in deeper waters and harsher environments, there is a great demand to develop the next generation of tools and technology to meet these challenges. Subsea wellhead systems form a critical part of the drilling and production equipment, and a proper understanding of their behavior under complex loading conditions is crucial as they provide a critical barrier between the wellbore fluid and the environment.
High-pressure, high-temperature (HPHT) applications can require the use of heavy wall components with significant structural discontinuities and complex geometric features. These conditions result in nonlinear stress gradients across the wall sections and degraded material properties caused by high temperatures. For these applications, API TR 1PER15K-1 [1] suggests the use of elastic-plastic finite element analysis (FEA) in place of the standard linear elastic methodology of stress categorization. An elastic-plastic analysis of a subsea wellhead system with a standard 36 in. ×22 in. ×10¾ in. casing program in accordance with ASME BPVC Section VIII Div. 3 has been performed [2].
Following the recommendation of API TR 1PER15K-1 with regards to system approach evaluation, the full wellhead system was included in the model. To accurately account for the complex interactions and load transfer between system components contributing to the overall structural response, the model used in this analysis included all major components of the system and was sequenced and preloaded in a method analogous to real-world field installation. System preload, global external loads, pressures, and casing loads were applied to the model. The model extended 200 ft below the mudline, a depth considered sufficient for the wellhead system to be free of any boundary effects. The 3D model included non-linear springs to simulate soil resistance. Cements were also included where appropriate.
The wellhead system was required to demonstrate sufficient resistance to failure due to global collapse, local plastic damage, and buckling. Analysis results for each failure mode and a comparison of rated loads using the standard linear elastic and elastic-plastic methodologies is presented. Using more advanced analysis techniques based on industry best available and safest technology, FEA results have allowed for more insightful validation testing, better-informed design decisions, and an improved understanding of system performance in extreme field environments.
Development of a Post-Installed Deepwater Monitoring System
Authors: Seaman C. , Brower D.V. , Tang H. , Le S. 
Published: April 2015

Abstract
A monitoring system that can be deployed on already existing deepwater risers and flowlines has been developed. This paper describes the design concepts and testing that was performed in developing the monitoring system. A major challenge of a post-installed instrumentation system is to ensure adequate coupling is achieved between the instruments and the riser or flowline. This work investigates the sensor coupling for pipelines that are suspended in both the water column (from topside platform to the seabed) and for those that are located directly on the seabed. These different environments necessitate two sensor attachment methods: (1) sensor clamp design with subsea adhesive and (2) sensor clamp design with friction surface coating. This paper addresses the adhesive attachment method. The monitoring elements consist of fiber optic sensors that are encased in a polyurethane clamp. With a subsea adhesive, the clamp can be installed by divers in shallow depths or by use of an ROV for deeper applications. The NASA Johnson Space Center was initially involved in the selection and testing of subsea adhesives. It was determined that up to 75 percent of the bonding strength could be achieved with the adhesive from optimal dry bonding versus bonding in submerged sea water environments. The next phase of the study involved the design, fabrication, and testing of several prototype clamps that incorporated the fiber optic sensors. Several molds were produced by NASA using 3-D printing that allowed the fabrication of subscale test articles that would accommodate 4-inch and 8-inch diameter pipes. The clamps were installed with adhesive in a "wet" environment on the pipe test articles and evaluated in the NASA Structures Test Laboratory. The tension/compression and bending tests showed that the prototype sensor clamps achieved good coupling, and could provide high quality strain measurement for active monitoring.
The Buoy Supporting Risers (BSR) System: Engineering a Solution for Ultra-Deep Water Subsea Developments in Harsh Environments
Authors: Cruz Ivan , Hepner Gustavo , Karunakaran Daniel , Claro Claudia , Nicoletti Frederico , Fontaine Emmanuel , Hesar Majid , de Paula Marcus Tadeu R. , Trovoado Leandro C. 
Published: April 2015

Abstract
The Sapinhoá and Lula North-East fields were developed through pilot systems composed of satellite wells connected to spread moored FPSOs. Each of these developments needed to connect up to 45 lines coming from the wells to a single balcony at FPSO portside, not including gas export riser and its ESDV umbilical. It was expected variable levels of CO2 and H2S, posing the challenge to find a suitable solution that endure the 27 years life of the fields in 2140m water depth in the harsher Santos Basin. To cope with these challenges, Petrobras and partners (BG E&P Brazil and Repsol Sinopec Brazil, in Sapinhoá field, BG E&P Brazil and Petrogral Brazil, in Lula Field) decided to pursue a decoupled risers' system solution and launch a "design competition process" which ended up selecting the Buoy Supporting Risers (BSR) concept solution developed by Subsea 7. This paper describes the BSR System and the needed careful physical and numerical modelling and massive analysis of a largely complex new system, backed up by prototype tank testing, all of them tackled to capture the in-place behaviour to generate the design input envelopes for all system components.
Application of the Shear Band Propagation Method to Slope Stability Analysis of a Palaeo-Landslide in the Caspian Sea
Authors: Gray Thomas , Puzrin Alexander , Hill Andy 
Published: April 2015

Abstract
Geophysical observations of palaeolandslides in offshore settings include long and relatively thin failures that occur on very mild slopes. Back analysis of such failures using the limiting equilibrium approach and measured geotechnical soil properties is typically used to inform the likely causes of past failures. An assessment can then be made of the present day significance of causal factors (e.g. the presence of excess pore water pressure), with the limiting equilibrium approach used to assess factors of safety for present-day slopes and predict the potential size of any future failures. However, for long, thin slides, use of the limiting equilibrium approach can lead to the conclusion that either a significantly large seismic trigger or other, abnormal geological condition was required to initiate failure. A result has been the focusing of academic research into other failure causes and conditioning factors. Further, the stability of the present day seabed for offshore developments can be overestimated, given the rarity of large seismic events in many areas and geotechnical measurements that not always show abnormal soil conditions.
The shear band propagation approach offers an alternative view, where an initial small failure can grow into a larger failure at the point of initiation. A result is that an explanation of the conditions leading to failure can be attributed to many submarine landslides. Further, accounting for the potential propagation of a shear band in the future prediction of submarine landslides can result in greater predicted failure sizes and lower factors of safety than using limiting equilibrium only. The application of the shear band propagation approach to back analyse a palaeolandslide in the ACG Field, Caspian Sea, is used to demonstrate the methodology and compare with results using the limiting equilibrium approach. Results show that the shear band propagation approach successfully predicts observed failure geometries and suggests triggering conditions from a lower magnitude seismic event compared to that predicted using limiting equilibrium. The future application of shear band propagation theory to submarine landslide analysis is also discussed.
Implementing a CSEM Survey Around Existing Infrastructure - The Perdido Installation, Gulf of Mexico
Authors: Hite Damian A. , Hiner Mike , Solevåg Lars P. 
Published: April 2015

Abstract
It's been over a decade since the first CSEM acquisitions were done along 2D lines in relatively open water. Today's CSEM acquisitions cover hundreds of square kilometers in true 3D fashion using receivers and towing systems purpose-designed for ease of handling, accuracy of deployment and efficiency in towing. Making use of these advancements, EMGS has been able to acquire data closer than ever before to existing infrastructure in a safe and reliable manner.
This paper covers the acquisition of a portion of the multi-client survey Daybreak Phase III around the Perdido installation over the Great White field in the Alaminos Canyon protraction area of the U.S. Gulf of Mexico. The survey covers approximately 46 OCS Blocks in water depths from 1700-3000m. The survey was acquired by the vessel EM Leader during the month of June, 2014 and consisted of 130 receiver drops and 702 tow kms.
In order to acquire the survey, EMGS contacted Shell, the operator of Perdido, and requested permission to conduct operations around the facility. Shell agreed and provided the following stipulations which were to be complied with at all times: When the planned tow line crosses a pipeline location, the CSEM source must be raised from its nominal towing depth of 30m to 100m at a point 250m away from the pipelineNo gear or the survey vessel could come within 1.5 NM of the facility The survey area bathymetry and infrastructure are showin in .
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

Abstract
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.