bluuebunny/crossref_metadata_2025 huggingface dataset:
Operational Simulations of Safe LNG Offloading to Conventional LNG Carriers in Severe Open Sea Environments
Authors: Cahay M. , Paquet S. , Auburtin E. , Roberts B. A. , Olsen F. , Thorsen T. B. , Korneliussen P. B. , Voogt A.
Published: April 2016

Floating Liquefied Natural Gas (FLNG) units, which have been under development for decades, are now a reality with Technip delivering the first two major projects in open seas. Both these projects incorporate side-by-side offloading of LNG from the FLNG to the LNGC (LNG Carrier) using loading arm technology. This technology will not be applicable in severe environments. Several tandem LNG offloading systems are proposed by the industry providing greater separation distance between the vessels and higher environmental thresholds. The drawbacks with such systems are the use of a dedicated LNGC fleet with a specific bow loading system or the deployment of long-length floating LNG flexibles (~300 m) to the midship manifold of conventional LNGCs.

Recently, Technip has worked with HiLoad LNG to develop a smart LNG offloading system based on already proven and qualified technologies to be operated with conventional LNGCs (without modification). It allows a vessel separation greater than 100 m, high environmental conditions and a minimum length of LNG transfer lines. The system uses the HiLoad LNG DP (dynamically positioned) vessel for the position keeping of the LNGC parallel to the FLNG and Technip's cryogenic flexible pipes for the transfer of LNG and vapor. The system is suitable for either spread- or turret-moored FLNGs.

The full-mission bridge at MARIN's Nautical Centre in The Netherlands has been used to simulate normal and emergency operations of the Parallel Loading System by use of a DP System developed by Kongsberg Maritime for this application. Real-time navigation simulations have been conducted with contributions from LNGC and HiLoad captains who have field experience from earlier HiLoad operations in Brazil and the North Sea. These simulations were performed to assess the DP station keeping capabilities and the marine operational procedures under steady and dynamic/changing environmental conditions. Blackout scenarios have also been investigated as part of the simulation work.

The simulations have confirmed the ability of the HiLoad DP system to keep the LNGC inside a tight operating ‘green’ envelope during all investigated challenging metocean conditions and that the operation can be safely performed. The HiLoad LNG Parallel Loading System is a smart solution enabling a safe and robust LNG offloading method with use of conventional LNGCs.
Method for Field Monitoring Asphaltene Treatment Programs
Authors: Jennings David W. , Chao Kung-Po , Cable Robert , Oczkowski Wilson , Cote Dominic
Published: April 2016

In 2014 a new dead-crude oil asphaltene stability analysis method was introduced for evaluating asphaltene inhibitor performance (OTC25113). The method is named the Analytical Centrifuge Stability Analysis for Asphaltenes (ACSAA). It uses an analytical centrifuge in combination with a solvent destabilizing procedure tailored to push testing conditions closer to field conditions than previous dead-crude oil stability methods. It was also proposed to extend use of the method to field monitoring in 2014, but at that time, no applications had been trialed.

This paper presents results from the first field monitoring application implemented in a North America field with a CO2 - Water Alternating Gas (WAG) flood operation. The simple, rapid, high-throughput analysis capabilities of the method, coupled with precision to distinguish even small differences in asphaltene stability between samples, make the method well-suited for field monitoring. Examples are shown from more than a year of data, illustrating the method’s ability to detect changes in field treatment dosage rates and to compare treatment chemistries. Ongoing efforts to correlate the results to field expectations are also discussed.

Management of asphaltene deposition is a serious issue for the petroleum industry, so having additional means to improve treatment programs is highly valuable for operators. The introduction of this method for field monitoring now provides operators an additional tool for use in managing and optimizing asphaltene treatment programs.
Joining Forces to Unlock LNG Tandem Offloading Using 20? LNG Floating Hoses: An Example of Industrial Collaboration
Authors: Giacosa Alain , Mauries Benjamin , Lagarrigue Vincent
Published: April 2016

Moving LNG production to an offshore setting presents a demanding set of challenges. Along with the design and construction challenges of developing FLNG facilities, extra thought has been required regarding the transfer of the product; LNG transfer must now battle with the effects of winds, waves, and currents in open seas. In environments where conditions are much more demanding, conventional marine loading arms will not suffice as they could result in a shut-down of the liquefaction plant in bad weather conditions.

This paper outlines why tandem offloading solution that rely on the use of flexible hoses are a viable alternative for the industry - not only limiting downtime, but also improving safety. Hydrodynamics analyses have been performed to demonstrate that the performances of such an offloading system are in compliance with targeted environments and associated operating envelope. Key results of this study will be introduced here.

This paper will also discuss why – in the absence of mature solutions – different actors have been joining forces to develop and qualify an innovative LNG tandem offloading solution using floating hoses that fully satisfies the industry’s requirements. It will be shown how the joint industrial program has been benefiting from diverse inputs coming from an IOC, an EPC contractor, a hose manufacturer and a University laboratory specialized in flow assessment.

Finally, as an illustration of such a successful JIP, significant information will be given about pressure drop analysis within a flexible cryogenic hose based on advanced CFD models and small scale water/LNG flow tests.
Subsea ESP Skid Production System for Jubarte Field
Authors: Tarcha B. A. , Furtado R. Goes , Borges O. C. , Vergara L. , Watson A. I. , Harris G. T.
Published: April 2016

This paper provides a general overview of the subsea Electric Submersible Pump ESP skid boosting system, and describes the technologies introduced to make the ESP system more robust, the resources brought together to move the required assembly tasks to a controlled onshore facility, the equipment validation program, and the initial experiences in installation and operation of the system.

Production of the 17° API heavy oil from Jubarte requires some means of artificially lifting fluids to surface. The high installation and intervention costs associated to subsea ESPs has prompted an operator to search for alternate boosting systems. The mudline ESP skid provides a solution for more cost-effective boosting of fluids to surface in deepwater fields.

The experiences gathered and results obtained with the operation of MOBO (Modulo de Bombeio, which is Portuguese for pumping module) ESP systems in the Jubarte and Golfinho fields have encouraged the operator to develop new ways for producing oil from these offshore fields using techniques to reduce considerably the installation and workover time and cost. In this way, the development of Jubarte Phase III uses a different arrangement for the mudline ESP, with the equipment installed in a horizontal skid instead of a vertical module. The skid comprises two horizontal ESP systems connected hydraulically in series and powered electrically in parallel by a medium-voltage drive located in a floating production, storage, and offloading (FPSO) platform. This setup reduces the size of the subsea assembly and allows use of a vessel of opportunity for deployment instead of a rig.

The subsea ESP skid concept was developed and tested on two previous occasions: an extended well test in Espadarte offshore Brazil and a production module in the Cascade-Chinook development in the Gulf of Mexico. In this new project, the equipment has evolved in relation to the previous installations, with a new and larger ESP system, the inclusion of chemical injection, access to hot stab, and the added capability to install a flow homogenizer.

The skid system design aims at improving economics for production of heavy oil fields while also addressing ESP run life concerns in these low gas volume fraction and high boost pressure deepwater applications.
Compartments, Connectivity & Baffling Analyzed by the Extent of Equilibration of Asphaltene Gradients Using DFA
Authors: Dumont Hadrien , Mullins Oliver C. , Zuo Julian , Pomerantz Andrew E. , Forsythe Jerimiah , Mishra Vinay K. , Garcia German
Published: April 2016

This paper describes how the combination of Downhole Fluid Analysis (DFA) optical density for measuring asphaltene gradients combined with Flory-Huggins-Zuo (FHZ) EoS thermodynamic analysis is the method of choice to identify (in real time) three major field economical risks: compartments, connectivity and baffling. A deepwater field example from exploration/appraisal phase to development phase is reviewed. In this particular case, and for the first time within one field, DFA oil color measurements reveal initial or preserved charges, equilibrated charges and an intermediate state (monotonic gradient of asphaltenes but in disequilibrium). When part of the field is equilibrated and another part not equilibrated, the implication is that baffling impedes equilibration and production; both expectations are confirmed herein. Production data confirms that the region of the reservoir with equilibrated asphaltenes had much better production rates than the region with asphaltenes in disequilibrium. Moreover, the baffles are found to be associated with deformation banding seen in core and borehole image log. In addition, the improved understanding on controls over production rates helps to project wellbore results away from wellbore. The paper describes the detailed workflow using DFA asphaltene measurements and the FHZ EoS to successfully address many key reservoir properties at early and all stages of reservoir exploration and production.
Deepwater Hydrate Plug Remediation Using Gas Lift - A Unique Approach & Novel Application of Fundamental Physics
Authors: Boubenider Rafik , Rebello Armando , Alexander Lane , Spradling Russell
Published: April 2016

Hydrate formation is a known flow assurance risk in deepwater flowlines, and remediation via single-sided depressurization presents unique challenges to ensure the mechanical integrity of the subsea infrastructure. This paper describes the gas lift depressurization technique that was developed for hydrate remediation and the engineering study that was conducted to assess the risks.
Selection of Subsea High Boosting Multiphase Pumps for Incremental Oil Recovery of Aging Deep Offshore Fields
Authors: Fernandes Charles , Roux Christine
Published: April 2016

The Rosa oil field was discovered in 1998 and brought on stream in 2007 via 20 km subsea production flow lines routed to Girassol Floating Production, Storage and Offloading unit (FPSO) in block 17, Angola. The production of the field has been decreasing mostly due to subsea network pressure drop amid water-cut increase and limited gas compressor capacity.

As result of conceptual studies and Research and Development (R&D) efforts, the installation of high boosting subsea Multi-Phase Pumps (MPP) and related subsea and topside integration modules was retained as the best economical and technical solution to increase production and maximize reserves recovery of Rosa field.

This paper describes the development process leading to the selection of the high boosting MPP concept and how the development of a new technology is managed by TOTAL in parallel to the development studies.
Adapting Tension Leg Technology to Provide an Economical Solution for Floating Wind Power
Authors: Melis C. , Bauduin C. , Wattez A. , Newport A. , Poirette Y. , Perdrizet T. , Averbuch D. C
Published: April 2016

The development of floating offshore wind farms requires the parallel development of suitable floaters to support the wind turbines. These floaters must be economic and must also exhibit good motion characteristics to limit the accelerations and inclinations imposed on the turbines during operation. This paper reviews the required characteristics of these floaters, addressing the requirements of fabrication, turbine integration, tow to site, and offshore installation, as well as the required behavior of the floater once installed. The benefits of an integrated design approach considering all of the above is demonstrated, and consideration is given to the industrialization of the production process for large numbers of floaters for full-scale wind farms.

Based upon this review of requirements, an innovative light weight structural solution incorporating tensioned mooring legs has been developed as an economic solution for the floater. The modularity of the design facilitates construction, and offshore installation can be accomplished using standard anchor handling vessel (AHV) means. The floater design exhibits low turbine inclinations and low accelerations due to a combination of its mooring arrangement and its high degree of transparency to waves, which reduces fatigue loads and maintenance issues on the turbine.

The floater behavior during towing to site and in the installed condition is described, and key performance characteristics are reported based on analytical simulations and model tests results conducted at 1:40 scale.

The paper seeks to clarify the key factors to be considered in developing a floater to support a wind turbine, and to propose a solution that achieves good motion characteristics whilst satisfying the economic constraints of wind farm development.
CompactSep™ - Compact Subsea Gas-Liquid Separator for High-Pressure Wellstream Boosting
Authors: Kristiansen O. , Sørensen Ø. , Nilssen O. R.
Published: April 2016

Subsea separation has successfully been implemented on the Troll and Tordis fields operated by Statoil, Pazflor (Total), Marlim (Petrobras), and Perdido and Parque das Conchas/BC-10 (Shell). One objective of subsea separation is to separate gas and liquid to optimize working conditions for subsea pumps enabling high recovery factors. The objective of this work was to qualify a two-stage, compact, inline gas-liquid separation system with full turndown and slug handling capabilities, consisting of already proven components: one Gas-Liquid Cylindrical Cyclone (GLCC) and one InLine DeLiquidiser.

CompactSep and its separator components and control system were qualified through a comprehensive, large-scale, real fluid and high pressure test programme at K-lab, a Statoil large scale test facility in Norway. This was done in a Joint Industry Project with Statoil as operator and Chevron, Petrobras, Total, and FMC Technologies as participants. The tests were performed with realistic fluids – 59° API condensate and 25° API crude, recombined with natural gas – and at realistic pressure conditions, from 25 to 90 bar, with and without inlet slug flow. The separation requirements for the CompactSep system were a liquid output with gas volume fraction GVF < 0.1 and gas output with gas volume fraction GVF > 0.995 downstream the separator system. The pressure drop limits were 2 bar (soft target) and 5 bar (hard limit). Separate and stricter requirements were set for the system’s individual separator components.

The main results were: a wide operating range where the performance requirements were fulfilled, 99% to 99.9% separation efficiency, gas qualities (GVF) between 0.995 and 0.999, and liquid qualities (GVF) between 0.02 and 0.1. The operational boundaries were challenged to determine the onset of liquid carry over and gas carry under. The actual operating range exceeded the design and performance predictions. The system handled slugging and start-up scenarios. The control system stabilized the process with relatively slow control valves.

The work developed and qualified an inline separator system with full turndown and slug handling capability. Qualification was performed at a wide range of realistic conditions and with high quality reference and performance measurements. Comparison of CompactSep and conventional subsea separation stations shows significant cost and weight reductions for the compact solution. What can be done subsea can be done topside. The CompactSep separator is a viable alternative to conventional vessels for topside applications where size and weight must be limited.
A Sub-Scale Experimental Test Method to Investigate the Failure of Variable Ram Blowout Prevention Valves
Authors: Jayanath Shiyan , Huang Ming Yu , Mashue Aaron , Achuthan Ajit
Published: April 2016

The objective of this paper is to report the development and validation of a simple sub-scale experimental test method [1] capable of simulating the extrusion and sealing type deformation of a typical variable ram BOP during its closing stage. Initially, an investigation into the failure of an elastomer at room temperature using a sub-scale experimental setup was performed. Failure under both static and cyclic loading was studied. Maximum nominal operating strain of an elastomer, estimated by performing a finite element simulation of a full-scale closing operation, was used as the reference for the sub-scale experiment. Under static loading there was no visible material failure, and the material behavior post-test remained unaffected. Cyclic loading caused significant variation in the material behavior of the elastomer as the test progressed, which was later recovered progressively with time after the cyclic test. The study was then extended to high temperature conditions; 72 °C, 120 °C and 170 °C. Both at 120 °C and 170 °C, noticeable elastomer degradation was observed. Residual strains remained permanent for specimens tested at 170 °C even after a few days. An increase in sealing pressure was observed as the number of loading and unloading cycles progressed. However, these changes in the material behavior due to temperature were relatively small for 72 °C. Overall, the observed failure in the sub-scale test agreed very well with that reported for variable ram BOP devices in the field. Results from the present validation study indicate that the proposed sub-scale test is a promising method to investigate elastomer failure in BOPs under realistic field conditions.
Subsea Sampling Performed in the Deepwater BC-10 Field Offshore Brazil
Authors: Håheim S. , Dutsch D. , Pires L. , Baima J. , Galgoul D. , Caldas L.
Published: April 2016

The BC-10 O-North field is developed using water injection for pressure support. For reservoir management it is of substantial value to know the source of water observed in each well. Due to comingled wells and long flow lines, individual well sampling topsides is very difficult and give undesirable production deferment. To enable well fluid sampling from each individual producer, a subsea sampling access has been installed in Xmas tree. ROV deployed subsea multiphase sampling tools (SuMS Tools) have been developed, and a first subsea sampling campaign has been executed, retrieving samples from two individual wells in the BC-10 O-North field. The paper discuss the motivation for the sampling program, describe the sampling system, including Xmas tree modifications, sampling tool development and qualification, and describe the offshore execution of the first sampling campaign, with operational experiences and lessons learned. In addition to the technical content, this paper will also discuss the organizational and HSSE aspects of the sampling system and sampling process.

The technology used consists of a SuMS panel installed on the subsea Xmas tree, which enable access to the production flow when connecting the ROV manipulated SuMS tool. The well is kept producing during the tool connection, sampling period and tool disconnection, enabling a sample to be taken with stable flow conditions. After retrieval to the intervention vessel, the ROV tool with the sample is transported to shore, where the sample bottle is disconnected, and brought to a laboratory. In the lab, the fluids are separated into gas oil and water before being shipped to the analyses laboratory in the US.

The first sampling campaign was successful. The operation was performed efficiently, without any environmental or production impact, or damage to subsea hardware.

The SuMS technology is innovative, and is a significant step forward in reservoir management of subsea wells in cases where individual well sampling at the topsides facility is not feasible or desirable. It is also presented as an alternative to the use of test separators for MPFM calibration, preventing production deferment.
Subsea Compression – Åsgard Subsea Commissioning, Start-Up and Operational Experiences
Authors: Time N. P. , Torpe H.
Published: April 2016

The Åsgard Subsea Compression (ÅSC) project has since project sanction in 2011 engineered, constructed, installed and commissioned the world's first Subsea Compression Station (SCSt).

The ÅSC SCSt includes two individual compressor trains, each containing an 11.5 MW centrifugal compressor module, condensate pump module, scrubber module and inlet- and discharge cooler modules. The compressor trains are installed at a water depth of 260 meters, in a shared subsea structure with a total weight of 5100 metric tons, a footprint of more than 3300 m2, and height of 17 meters above the seabed. The SCSt is connected to a subsea manifold station routing all flow from the wells via the compressor trains to the gas processing platform Åsgard B. The installation includes a comprehensive SURF scope with more than 60 km of new flow lines, 11 PLEMs and 50 tie-in points. The compressor station is powered from the Åsgard A FPSO where a separate high voltage power module weighing 850 metric tons has been installed. The subsea station is remotely operated from the Åsgard B platform.

The subsea compression station is compressing the gas flow from the Midgard and Mikkel reservoirs, boosting the production and securing stable flow conditions in the subsea flow lines towards Åsgard B.

The subsea commissioning has been carried out during summer, autumn and winter 2015/2016. It has involved control system commissioning, dynamic commissioning with N2 and MEG, before final commissioning with hydrocarbons. In order to secure efficient commissioning with involvement of a large number of vendors and support personnel, a remote operation room for the commissioning team was installed at Statoil's Stjørdal office outside Trondheim where the Åsgard Operations land organization is housed, thus avoiding constraints imposed by offshore training, helicopter travel and shortage of offshore cabins.

This paper describes the subsea commissioning phase, including experiences and lessons learned. Challenges including cooperation between onshore room, offshore platform, and installation vessel, as well as performing commissioning on one train with the other in operation, are discussed. In addition, it gives an outline of the experiences gained during the start-up and initial operation phases.
Turning FPU's into Hubs: Opportunities and Constraints
Authors: Yoshioka R. , S Swerdon A. Salem. , Loper C. , Pritchett W.
Published: April 2016

Offshore project capital costs have increased by an astronomical 400% forcing IOC's, NOC's and independent players to re-evaluate the feasibility and the profitability of some major developments. A decade long boom is now confronting unpredicted reality, altering the offshore development landscape and resulting in fewer opportunities and major consolidations in owners and contractors. Some owners are now shifting focus to brownfield and marginal field tie-backs to eliminate costs and risks associated with new installations. This paper explores one of those opportunities, namely turning Floating Production Units (FPU's – Semi, TLP, SPAR) into hubs, where various field owner/operators share production through the same FPU. Typically, hub developments are contracted under Production Handling Agreements (PHA). The PHA provides for price tariffs on produced oil, water and gas and is collected as the field owner/operator produces. Tariffs are paid for actual production which reduces reservoir production risk for large capex investments. Hub developments offer the field owner/operator the following value: Lower developmental CAPEX investmentReduced operating costsAccelerated development scheduleRisks and liabilities for decommissioning and poor well performance are reduced or eliminated.

Aspects of selecting the appropriate FPU are considered while presenting the suitability and limitation of each type for appropriate production sharing models. The paper will present a recent case study for a Semi-submersible designed with reserve topside, hull and mooring system capacity to meet tie-back requirements. The Semi- submersible is located in the deepwater Gulf of Mexico, at 6060 feet water depth, and approximately 145 miles southeast of New Orleans. The Thunder Hawk Semi-sub came online in July 2009. The unit has maximum oil production of 60,000bopd, and gas processing of 70mmscfd. Oil and gas is exported from Thunder Hawk via Steel Catenary Risers (SCR's) that connect into the export system. The recent tie-back to Thunder Hawk consists of three (3) wet insulated 8? SCRs, 8,500 psi. Three new wells are tied to the facility with capacity to produce up to 20,000 bopd each. The paper will focus on the technical and commercial constraints and opportunities employed to implement the tie-back, namely: engineering design, regulatory requirements, and production sharing philosophy.
Integrated Field Study Involving Downhole Fluid Analyzer DFA for Reservoir Connectivity in Thin Complex Lithology Formation: Case Study from Oman
Authors: Razvi Maria , Al Hadhrami Abeer , Al Shaibani Mohammed , Azzazi Mohammed , Frese Daniela , Al Bahrani Mundhir , Mohtadi Ashkaan , Al Mandhari Alyaqdhan , Daungkaew Saifon , Al Ajmi Issa , Al-Yaarubi Azzan , Zuo Julian , Mullins Oliver C.
Published: April 2016

Early information about reservoir fluid complexity, dynamic behavior, and reservoir connectivity is crucial for development planning and production optimization of new plays. Such impact is manifested in three main areas: (1) reservoir presence and connectivity to understand the extent of the play (2) reservoir fluid variation to understand the charge history and devise production strategy (3) completion optimization in exploration wells to maximize early production.

Petroleum Development of Oman pursued an ambitious exploration campaign firstly consisting of 8 wells targeting a shallow, thin, complex lithology formation to better understand a new play, especially from reservoir extension and connectivity viewpoints. In addition to advanced formation evaluation logging consisting of elemental spectroscopy and nuclear magnetic resonance, an advanced Downhole Fluid Analyzer (DFA) was deployed with Wireline Formation Testers (FT) aimed to obtain formation pressure and fluid samples. The fluid scanning using in-situ fluid analysis was also performed to obtain reservoir fluid information in real time and at reservoir condition. In addition, Interval Pressure Transient Tests (IPTT) was conducted to evaluate permeability of each well.

This paper provides the workflow of using the DFA and laboratory data for full field development. This will include discussion of DFA data such as asphaltene, fluid composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help draw a full picture towards reservoir connectivity.

Having detailed fluid properties data available in real time allows to optimize the completion decisions (pump selection as one example) in order to maximize early production while allowing longer term reservoir management planning. This paper also discusses the use of in-situ fluid viscosity and pressure transient data to estimate zone permeability during the FT operation, which will later be compared to actual well test data. Results show a good comparison and provide comfort to use FT pressure transient data to evaluate zone permeability at early stage of the operation.

The DFA data from the first 4 wells suggested the presence of subtle but distinct fluid differences in terms of composition, oil color, and fluorescence yields. This DFA data was then supported by full PVT laboratory results. The differences in fluids will be examined in more details. This paper will present an effective workflow to integrate pressure, DFA, and PVT data to understand reservoir connectivity issue in this newly discovered formation. In addition, the DFA color gradient model was then used to help supporting other available information.
Using Electro Active Polymers to Transform Wave Energy Conversion
Authors: Wattez Ambroise , van Kessel Rick
Published: April 2016

The first generations of wave energy converters have had a number of forms, but all are essentially large steel structures concentrating the power take off onto small mechanical devices. A number of prototype devices have been installed offshore, but due to their high fabrication and installation costs, coupled with significant maintenance requirements, the production of electricity at an acceptable cost has remained elusive.

To avoid the limitations of these devices, a second generation wave energy converter is being developed using electro active polymers (EAP), which are capable of generating electricity directly from wave action without the need for any mechanical power take off. The resulting system is flexible and possesses an infinite number of degrees of freedom, allowing wave energy to be captured more efficiently than with conventional devices. Deployed offshore, such a device would have no complex mechanical parts, would function silently, and would require minimal maintenance. The economics of such a system lead to predictions of a cost of electricity significantly below the levels of the first generation devices.

The paper explains the principals involved in using EAP for the generation of electricity, the application of EAP to wave energy conversion, and reports key results from the ongoing development program. The paper also describes the main features of the prototype wave energy converter system presently under development for deployment offshore.
Advantages of Applying a Multifaceted Approach to Asphaltene Inhibitor Selection
Authors: Bae Jaehoon , Fouchard David , Garner Susan , Macias Jose
Published: April 2016

The right Asphaltene Inhibitor (AI) selection is crucial for the control of asphaltene issues in oil production. Although many factors contribute for the asphaltene precipitation/deposition in the fields, the chemical selection process in the laboratory were often conducted only under ambient temperature and pressure. In this paper, we introduced a multifaceted approach for asphaltene inhibitor selection process to overcome the test condition discrepancy between laboratory and the fields. The importance of temperature on the performance of chemicals was evidenced by our high temperature optical scanning device results. The Coupon Deposition Test (CDT) clearly demonstrated the difference between deposition and precipitation behavior and the impact of the water phase on inhibitor performance. High pressure Asphaltene Rocking Cell (ARC) enabled to incorporate high pressure, high temperature and water conditions in the laboratory to show the difference of inhibitor performances. By incorporating field conditions such as temperature, brine composition and pressure into our tests, better recommendations can be achieved that would have not been possible with any optical, precipitation based technique. Furthermore, a suite of AI test methods which cover various field conditions brings a degree of refinement in product selection unmatched by any single method and allows for selection of the best asphaltene chemical program for a particular field through its life cycle.
Qualification of Composite Pipe
Authors: Wilkins Jonathan
Published: April 2016

Magma Global manufactures a thermoplastic composite pipe for use in high performance riser, jumper spool and intervention line applications. m-pipe® is a unique product manufactured from PEEK, carbon fibre and glass fibre materials using an automated laser-based welding process.

Managing the qualification of new technology is a significant challenge. Magma must demonstrate the reliability of m-pipe® to its customers, to third-party assessors, and to the regulators. Since thermoplastic composite pipe is a new area of technology, Magma has combined the guidance from a newly published DNV recommended practice [1] with a risk based approach to qualification management [2].

This paper gives a summary of the approach used by Magma to qualify m-pipe®. It describes the methods used to:

Identify and mitigate risks in the design and manufacturing processes.

Comply with relevant requirements from existing codes and standards that are applicable to the design and qualification processes.

Develop test procedures to evaluate both fundamental material behaviour and structural behaviour of the complete product.

Develop analysis models and design tools based on learnings from the testing.

Collaborate with suppliers, operators and other manufacturers to develop a new standard specifically related to m-pipe® type thermoplastic composite pipes.

 

It is hoped that these learnings will be useful to others in the wider oil and gas community who are working on the development of novel materials technology.
Development and Engineering of Offshore Mining Systems - State of the Art and Future Perspectives
Authors: Knodt Steffen , Kleinen Torsten , Dornieden Christian , Lorscheidt Jan , Bjørneklett Børge , Mitzlaff Alexander
Published: April 2016

This paper gives a brief overview on the major milestones of the deep sea mining projects in the 70's and 80's with focus on the OMI/OMCO-Consortia and the engineering milestones SEDCO 445, Hughes Glomar Explorer, Clementine II and PLA2 6000, the pilot mining tests of the AMR, the environmental study DISCOL and the joint efforts of Gemenod/Preussag. Among the most interesting and technologically challenging systems are those for deep sea mining of manganese nodules in water depths of 4,000 to 6,000 meters in the Mid-Pacific. Following the total integrated systems (TIS) approach, the technology transfer between ultra-deep water drilling and deep sea mining is outlined based on several subsystems and specified for the key components of the vertical transport system. As example for state of the art engineering and technologies recent developments of heavy-load active heave compensated drawworks, ultra-deep water riser systems, motion-compensated offshore mining drill pipes with air-lift slurry transport, remote subsea workclass-crawler ISUP and the Korean manganese nodules collector MineRo II are described. Based on the principles applied for development and engineering of systems for shallow water offshore mining and the experiences available from the pilot mining tests conducted in the past, a concept for an offshore mining system was developed by MHWirth in corporation with the German Federal Institute for Geosciences and Natural Resources (BGR). This concept will be outlined in the current paper together with the main results of an economic feasibility study. Furthermore, an overview on the current European deep sea mining research projects and a renewed German-French industrial cooperation is given. Synergies with the emerging private space industry are anticipated regarding systems engineering. Future perspectives for a new pilot mining test are discussed.
Performance Evaluation of Recently Developed Soil Models in Well Conductor Fatigue Analysis using Field Measurements
Authors: Kannala Jomon , Zakeri Arash , Long Ge Michael , Buba Kebadze Elizbar
Published: April 2016

American Petroleum Institute (API) [2] recommendations for modeling the lateral soil resistance-displacement (p-y) response were not developed for fatigue analysis of deepwater wells. The recently developed soil models [1] is aimed to fill this knowledge gap. Based on extensive physical testing in a geotechnical centrifuge and complementary numerical modelling, a more accurate approach was developed for soil modeling specific to well conductor fatigue analysis. The approach was presented at OTC2015 [1]. While the approach proposed in [1] performed very well in predicting the fatigue damage in the model tests, its performance is yet to be evaluated against actual field data obtained in the field. This paper evaluates the performance of the recently developed soil models in predicting field measurements and fatigue damage obtained from a monitored well in the Gulf of Mexico (GoM). Important considerations for modeling soil response (e.g., modeling of soil crust near mudline) are also discussed. The new approaches are applicable to fatigue analysis of conductors pertaining to subsea wells worldwide. The motion monitoring loggers collect acceleration and angular rate information at the point of installation. The objective was to investigate the fatigue performance of the wellhead and conductor system. Fatigue was estimated based on the motion data collected from the data loggers. The measured motions and fatigue damage obtained from the loggers were compared to those estimated from predictive methods using the proposed soil model. This paper demonstrates that the recently developed soil models perform satisfactorily in predicting the deformations (displacements and rotations) measured at the top of the lower marine riser package (LMRP); hence, providing a more accurate prediction of the system (LMRP, wellhead and casings) response and thereby, its fatigue damage.
Power Generation Interconnection Between 2 Existing Deep Offshore FPSO's a World First
Authors: Leforgeais Bruno , Bourgogne Olivier
Published: April 2016

This is the worldwide first-ever Power Interconnector between Deep Offshore FPSOs, i.e. over the two Girassol and Dalia FPSOs, including the integration of an Integrated Power Management System, together with Load Sharing and Load Shedding that has enable the implementation of subsea multiphase pumps to enhance oil recovery.

This paper presents the overcome of technical challenges the project team has met on very different aspects of the execution phase: innovative design such as Dynamic Section studies and thermal studies of Interconnecting Power Cable, Prevention of excessive voltage drop during the magnetization of the 33kV power interconnector, and testing & energizing strategy such as Management of dissimilar Power Generation, Short circuit level limitation.
Subsea Operational Technologies Development
Authors: Augustus Marcello , Roberto Ramos
Published: April 2016

The offshore oil and gas companies have been facing, mainly in the last five years, an increase in their operating costs (OPEX). The cost of subsea production system monitoring, inspection, intervention and maintenance is growing up very fast and, in most of the cases, is responsible for the high OPEX and low NPV (net present value of the project). In some cases, the use of subsea technologies focused on reduction OPEX and NPV maximization could be mandatory in order to keep the project attractiveness. These technologies have been used since the mid-1970s and are being developed through R&D companies or suppliers. Despite these initiatives, the companies have realized that there is a gap between the R&D efforts and the operational needs. The objective of this paper is present how Petrobras is dealing with this challenge and how the use of subsea technologies is supporting the OPEX reduction.
High Boost Multiphase Pumps: The Challenges of Flow Assurance and Operation
Authors: Le Rodallec Jean-Luc , Delourme Cecile
Published: April 2016

The implementation, after 8 years of production, of four High Boost MultiPhase Pumps (MPP) within an existing subsea installation not originally designed for, modifies deeply the flow assurance and the way of operating the Rosa fields and the Girassol FPSO, to which the production loops are tied-back.

Thanks to an extensive flow assurance program launched at the project kick-off, design optimizations were proposed, verified and tested through dedicated simulations during project studies and execution.

On top of the design, this paper shows how the results and conclusions of these studies were translated into operating procedures, training simulator and up to the maintenance program.
Effective and Innovative SIMOPS Management: A Key to Minimization of Production Shortfalls Associated to Deep Offshore Subsea and Drilling Brown Field Activities
Authors: Kiehl Vincent , Alexandre Celma , Ferreira Elgar , Dembele Marcel
Published: April 2016

By definition Brownfield projects are executed on facilities in production, with inherent risks and constraints. The Deep Offshore dimension increases the complexity of these activities with the construction and installation work carried out on live subsea networks and FPSO's. Very often with drilling rigs operating on the location and sometimes in parallel with maintenance and integrity works.

The key for safe and successful Brownfield activities, minimizing the production losses caused by required shut-downs, goes consequently through a specific management of these Simultaneous Operations (SIMOPS).

This paper presents the SIMOPS management principles implemented in TOTAL E&P Angola for Brownfield activities executed on FPSO's and their subsea network, along with different innovations recently introduced to further optimize the requirement for production shut down.
Subsea Compression - Designing and Building a Subsea Compressor Station
Authors: Storstenvik Anders
Published: April 2016

The Åsgard Subsea Compression is a high capacity system, designed for large flow rates and pressure ratios. The project has worked towards high ambitions of reliable, efficient and flexible operation. The Åsgard Subsea Compression is a platform: To a large degree, the subsea compressor station extends towards the capacity and flexibility of a conventional topside compressor platform. More importantly, it provides a technology and experience platform for both more advanced and broader applications, yet also simpler and leaner solutions.

This paper dives into the trial and tribulations from concept to detailed design, fabrication and testing. All were executed within the framework of one contract in an EPC execution framework. Examples will highlight critical activities, both anticipated challenges and issues not foreseen at the outset of the project.

Lack of flexibility in future modification is a general objection to the subsea factory. The Åsgard compressor station has a long operational life and the production profile varies significantly throughout the whole life cycle. The paper will discuss how future functionality can be included in initial design or, if best suited, provisioned for future stages.

Technology qualifications have been handled with the rigor and timing required in established industry practises. However, in an EPC execution framework, even smaller "first of" engineering or -designs will disturb the project's pace; eventually demanding "out of sequence work" to recover quality and progress. The paper presents some "first-of's" and discusses the dependency towards the EPC execution framework. This also includes external interfaces and main procurement activities.

The compressor station is inherently more multidiscipline than a conventional subsea delivery. One could say that it represents a "platform on the seabed" in terms of process functionality. Therefore engineering tools, methodology and expertise from topside projects has been utilised in the work. The experience harvested by use of integrated systems for schematics, 3D modelling and engineering registers will be summarized and concluded.

Finally, the organisation set-up and development for the various project phases will be discussed, in particular with respect to follow-up towards main procurement activities, fabrication, manufacturing, completion/testing and commissioning support.
An Analytical Approach to Predict the Fatigue Life of Flexible Pipes Inside End Fittings
Authors: Campello G. C. , de Sousa J. R. M. , Vardaro E.
Published: April 2016

The offshore operational experience has shown that the flexible pipe end fitting (EF) may be the weakest point in terms of fatigue resistance of the tensile armor layers. The findings observed in dissections from risers which were in operation or subjected to qualification tests reveal that there is a key point with respect to fatigue inside the end fittings. This point corresponds to the section in which the wires of the tensile armors are subjected to significant plastic strains caused by the end fitting assembly process. Thus, this study aims to propose an analytical approach to predict the fatigue resistance of flexible pipes focusing on their terminations.

A local analytical model is employed to predict the stresses induced in tensile armor of the pipe due to the end fitting assembly and also during operation. These stresses are used in conjunction with a previously detailed approach that is employed to compute the fatigue resistance of flexible pipes. The methodology is validated by comparing its results to several real scale prototype tests.

The results obtained during validation showed that the application of this methodology in calculating the fatigue life has low variability and therefore the failures observed in the qualification tests are well predicted. This methodology has been successfully used by Petrobras in flexible risers life extension.
Fatigue Assessment for Pressure Armor Layers Subjected to Cyclic Pipe Cross-Section Ovalization
Authors: Chen Y. G. , Liu J. , Zhu L. F. , Tan Z. M.
Published: April 2016

A flexible riser is typically protected from over-bending at the hang off region by a bending limiter, i.e. a bend stiffener or a bellmouth. The pipe will be forced into contact against the bending limiter at one side during bending. As a result, the side contact load may deflect the pipe cross-section and induce some additional stress on the pressure armor layer. Such additional stress is dynamic in nature and is anticipated to induce fatigue damage in combination with other dynamic stresses caused by tension variation and pressure for example.

This paper highlights the mechanism governing potential pipe cross-section ovalization, and subsequent stress alternating and fatigue damage of pressure armor under dynamic loadings. Also presented in this paper is a procedure and technique for capturing such induced pressure armor damage in the pipe design process. It is noted that the pressure armor typically consists of strips with a profiled cross-section wound almost circumferentially. A theoretical approach is presented to evaluate the pipe cross-section ovality by considering the resistance from governing strength components such as carcass and pressure armor, and to calculate such induced stress variation and subsequent fatigue. This theoretical approach taken has been validated by FEA models and calibrated against a number of full-scale dynamic tests with pipe samples ranging from 4.75 to 16-inch ID. The methodology was third party reviewed and approved and deployed for riser system design and analysis.