bluuebunny/crossref_metadata_2025 huggingface dataset:
Scrubber performance: Investigation of liquid holdup in mesh pad at ambient conditions with applications to high pressure separation.
Authors: Setekleiv Eddie , Svendsen Hallvard
Published: July 2010

The liquid holdup distribution and pressure drop of a wire mesh demister was investigated experimentally. The meshpad porosity was 98.06 vol % and the height 0.1m. It was tested at ambient conditions with air and water. The liquid holdup inside the mesh pad was measured at five locations with a gamma densitometer. The pressure drop and efficiency of the wire mesh demister were also determined. The results show variations in the axial holdup profile of the demister depending on gas velocity. The paper discusses relevant parameters for scrubber design, such as K-value and Stokes number, and their impact on separation properties of the demister. The droplet size distribution was also measured downstream of the mesh pad. Data for natural gas and the nitrogen/Exxsol systems at elevated pressures are compared and discussed in relation to the new findings.

Introduction

Wire mesh demisters, often called mesh pads, are used in many chemical engineering and oil production applications for removal of droplets, or as a droplet coalescer for downstream separation equipment. Gas flows containing small fractions of liquid and with droplet size distributions in the range 5-100 µm are considered appropriate for mesh pad operation. These are able to separate droplets down to 2 to 10 µm depending on the design of the demister. A wire-mesh can also be used as a coalescer or pre-conditioner for down-stream equipment. In this regime the mesh-pad may operate above the flooding point. The device is usually made of steel wires, but other materials may also be used such as polymers and other synthetic materials, as well as other types of metals. The wires are usually from 0.1 to 0.28 mm in diameter. The wire-mesh is placed in a support and placed inside an appropriate separation vessel, usually in vertical or horizontal position. An overview of mesh pad selection criteria is given by [1] and [11-12]. Investigations on mesh pad operation and criteria have been scarce in the public domain. Among the first investigations are found [10] and [18-19]. In recent years research in this field has received more attention, see [2-5], [6-8] and [13].

Increasing capacity of process plants or in gas/oil processing facilities may result in higher concentrations of droplets in gas streams and subsequently a more severe operational demand on the separation equipment. For downstream equipment such as compressors, having droplets in the gas stream, may result in poor performance and possible breakdown of the equipment. In other cases there is a desire to recover precious products suspended in the gas stream. Improving gas quality to meet specifications is another application. Mesh pads are ideal for removal of fine mists and sprays.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico: Thunder Horse Materials, Welding and Corrosion Challenges and Solutions
Authors: Burk James D. , Ribardo Charles L.
Published: July 2010

Materials selection, welding fabrication and corrosion management for the Thunder Horse Deepwater facilities required first-in-class and cutting edge technology solutions for the subsea equipment, flowlines and riser systems.. These solutions were developed through application and understanding of new and challenging technologies that demanded innovation and a broad and in-depth technological understanding of new solutions for successful delivery of first production in June of 2008. The technology challenges faced came from the high pressure, high temperature (HPHT) conditions found in the reservoir; 270°F, 12,300 psi, pH 4.5, 4.5 psi H2S, 6.0 psi CO2, 32,000 ft TVD, and deepwater depths of approximately 6,500 ft where the external temperature and pressure are 4°C and 2,950 psi.

Significant technology challenges were addressed and implemented in the Thunder Horse HPHT development to the industry were:Trees, manifolds and jumpers, not previously seen in subsea developments, with heavy-walled forgings and piping/fittings necessitated by strength, fracture toughness, welding and corrosion demandsFlowline and riser challenges including corrosion strategy, corrosion fatigue/sour service, thermal fatigue, and strength, toughness issues in thick-walled, microalloyed pipeline steels in sizes not produced previously with J-lay welding of sour service heavy-walled linesControls equipment materials requirements for miles of subsea umbilicals (15,000 psi)Drilling riser materials and fabrication technology for longer-term drilling operations from both drillship and the Thunder Horse production facility

Introduction

Staff with deep competencies across a broad spectrum of technical fields were required to be successful in material selection, steel processing in pipe mills and forgemaster shops, welding fabrication and pipelay installation, corrosion inhibition, erosion, corrosion resistant alloy stress corrosion cracking, cathodic protection, sour service issues, materials fracture, and fatigue coatings/non-metallic materials.

This paper is an overview of the Thunder Horse materials, welding and corrosion (MWC) issues, the approaches taken and the solutions developed to enable Thunder Horse, a world-class production facility, to be delivered and become the premier operating asset for BP and in the Gulf of Mexico. These learnings lead the way to future development of deepwater, high production HPHT fields, employing world-class materials, welding, and corrosion-applied technology solutions for safe and reliable operations.

To solve these challenges successfully and deliver the Thunder Horse HPHT deepwater demands, an integrated approach was taken using BP's technical staff working with materials suppliers for forgings, pipe fittings, equipment fabricators and installation contractors.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico" Paper Title - Thunder Horse and Atlantis Floating System and Riser Monitoring: Performance During Extreme Events
Authors: Cramond Neil , Petruska David Joseph , Geyer Jeff , Jesudasen Sandeep
Published: July 2010

Thunder Horse is the largest production semisubmersible in the Gulf of Mexico with a displacement of 130,000 mT, while Atlantis is also a large semisubmersible with an 88,600 mT displacement. Both platforms are equipped with instrumentation to measure metocean and platform/riser response. This paper presents measured metocean data with comparisons to hindcast predictions. The measured platform and riser responses are also compared to analysis results using the measured metocean conditions.

Both environmental and platform response (including mooring and riser systems) measurements have been recorded from the Thunder Horse PDQ and Atlantis PQ semisubmersibles. Several major hurricanes passed close to these two platforms since they were installed. This paper summarizes some of the key data measured in these extreme events. Data recording significant wave heights exceeding 40 ft and associated responses are included.

Thunder Horse was installed in 2005 and thus was exposed to Hurricanes Katrina and Gustav along with several other hurricanes that did not pass as close. Atlantis was installed in 2006 and experienced extreme conditions in Hurricane Ike. Thunder Horse saw hurricane wave heights and current speeds exceeding the original 100-year design conditions with wind speeds just below 100-year design values in Gustav. It also experienced a severe post-storm inertial current for several days following Gustav. Atlantis similarly saw over 100-year wave heights and just below 100-year winds during Ike. Even though the metocean conditions exceeded the design values, no major hull, mooring or riser damage resulted. Comparison of platform response to numerical analysis shows that generally the actual response is less than the original predictions.

It is not common to record real data in extreme storms. Valuable insight can be gained into the design assumptions and methodologies when comparing the actual response to design predictions. The results can determine how much conservatism is in the original design and can also have an impact on future FPS and riser designs. Such information can also be used to help assess the condition of the platform and post-storm inspection requirements.

Introduction

Both Thunder Horse and Atlantis experienced severe hurricanes in 2008. Hurricane Gustav passed 33 miles southwest of Thunder Horse and 79 miles northeast of Atlantis on August 31 - September 1, 2008. Hurricane Ike passed 66 miles southwest of Atlantis and 169 miles southwest from Thunder Horse on September 11 -12, 2008. The path of these two hurricanes relative to all seven of BP's floating production systems is illustrated in Figure 1. Due to the paths, Gustav was a more severe storm at Thunder Horse, while Ike was more severe at Atlantis.
SS: Thunder Horse and Atlantis Deepwater Frontier Developments in the Gulf of Mexico: Paper Title - Two Assets, Two Approaches to Tackling Subsalt Imaging - Thunder Horse and Atlantis
Authors: Howie John M. , Trout Matt
Published: July 2010

The BP-operated Thunder Horse and Atlantis developments are giants among the deepwater subsalt fields. It was recognized that effective development of these large fields would require a step-change improvement in the seismic imaging. Through close cooperation between asset and R&D teams, BP has pursued a two-pronged approach to deliver improved seismic imaging for these and other subsalt deepwater fields. New seismic acquisition and new processing techniques were needed to significantly improve the subsalt image. The methods of acquisition and processing applied to each field are very different and are dependent on field-specific issues that include: the timing and pace of development, existing seismic data, infrastructure, seafloor bathymetry, salt geometry, and reservoir configuration. Thunder Horse initiated an aggressive anisotropic reprocessing project incorporating three independent 3-D seismic surveys in a multi-azimuth processing sequence. Atlantis pursued a new 4-component ocean-bottom-node technology to provide uniform wide-azimuth acquisition, and then pioneered new receiver-centric processing to image the data. Both implementations yielded dramatic seismic image improvement while highlighting additional challenges.

Introduction

In the late 1990s a series of deepwater discoveries in the Gulf of Mexico opened up a new Miocene play where the fields were either partially or completely overlain by salt. The complexity of the salt provided major challenges to existing seismic methods to image the subsalt structures. It was quickly recognized that development drilling would be prohibitively expensive where the reservoir geometry and faulting could not be accurately defined. Atlantis (1998) and Thunder Horse (1999) were among the first of those giant discoveries to be developed (Figure 1). BP as the operator of both of these projects recognized the critical need for improved seismic data to ensure costeffective field development.

This paper outlines portions of the broad BP strategy to improve subsalt seismic to development quality imaging. BP has led the industry in efforts to provide improved illumination in complex salt environments using wide-azimuth acquisition and processing. New seismic processing capacity and techniques were required to fully exploit the wide-azimuth datasets.

The paper then reviews how the imaging efforts were implemented in the two fields- Thunder Horse and Atlantis. Although the same strategy was applied, the methods were quite different, as each field was under different timing and development constraints.
SS: Subsea Well Intervention: Subsea Intervention: The Balance of Effectiveness, Risk and Cosst
Authors: Hurzeler Kurt Lee
Published: July 2010

The balance of effectiveness, risk and cost is common to every offshore project. This is especially true of subsea well intervention where success may include a broader spectrum of outcomes and risks may be more difficult to quantify. Intervention planning may require a progression of assumptions and contingency planning for each variable. The variables may range from technical capabilities of the equipment to completion and production problems. Production problems are not always easily diagnosed. If a problem is identified, several solutions may be on offer. Solutions may range from simple through-tubing operations to total recompletion or even sidetrack. Misinterpretations and misapplications may do more damage than the original problem and as a result the cost of failure can be very high. In an environment of multiple high impact risks, the cost of mitigating all or most of the risk of failure can also be prohibitive. Balancing the potential benefit of the project, the various commercial and technical risks, and the cost of mitigating the most onerous of those risks is the job of the project team. With the emphasis on intervention equipment and deployment, this paper will summarize the broad scope of options, the associated risks, and some guidelines to control the cost of projects and mitigate the cost of failure.
Special Session: LNG & LPG Operations Offshore
Authors: Mclean David
Published: July 2010

In the mid 1990s our client realized that their recent offshore find would yield a viable Liquefied Petroleum Gas content. With the proposed field located over 20 Nautical Miles offshore from an underdeveloped area, the option of exploitation on site was identified. Oil Floating Storage/Offloading units, usually adaptations of existing oil tankers, were at that time already an established alternative to piping product ashore. Therefore tenders were invited for the provision of an LPG Floating Storage/Offloading unit. Any party tendering for this task would be covering new ground as this installation would be among the first of its kind. In particular, the physical properties of LPG demand different handling systems and techniques when compared to oil.

In tendering we drew from the diverse marine enterprises within our group. We also engaged a partner specialized in offshore solutions. We had access to existing LPG tonnage of suitable capacity and our own yard for conversion work. We also had a competent technical support structure and potential within our personnel base for operational requirements. As with any new project, once tender requirements were met and accepted, evolution occurred. This evolution is of course not limited to the period leading up to commissioning but has continued through to the present.

In the course of describing the project the following prominent items will be covered:Performance specifications and environmental factors.Conversion, installation and commissioning process.Upgrades and maintenance challenges.Specialized aspects of mooring and cargo handling systems.Classification and personnel.Cargo export and operational record.Management of safety.

It is often the case that delivery of a specialized service holds a narrow spectrum of interest. However it is our hope that this project, although relatively specialized, may also have value for any concern engaged in offshore storage and offloading. By this time we have operated the unit for 13 years and can share some valuable experience.

Introduction

The field's position in the tropical portion of the West African Continental shelf promised a favorable climate. The main environmental concern during cargo transfer to export vessels was therefore exposure to open ocean swell conditions. The common export method for oil FSO installations at exposed locations is by tandem transfer. In this familiar arrangement the export vessel attaches astern of the FSO and picks up a floating hose to connect to her cargo manifold. This avoids any contact damage between the FSO and export vessel, which individually ride to the prevailing environmental conditions.
Fiber-Optic Distributed Vibration Sensing Provides Technique for Detecting Sand Production
Authors: Mullens Stephen , Lees Gareth , Duvivier Giles
Published: July 2010

Throughout the past decade, fiber-optic technology has gained acceptance as a viable solution for continuous monitoring of distributed temperature profiles in a variety of downhole applications (Karaman 1996; Carnahan 1999). In wells completed with fiber-optic control lines, distributed temperature logs can be produced without well intervention. This paper reports a recent development of a surface instrument capable of measuring distributed vibration profiles on optical fiber. This technology has enabled an operator to identify downhole vibration events related to sand production.

Applications for distributed downhole vibration sensing are extensive; the technology can be used to monitor and understand almost any process that generates a vibration signature. The frequency range of the fiber-optic sensor allows different sources of vibration to be discriminated. Therefore, the difference between the sound generated by multiphase flow noise and increased sand production is distinguishable with regard to frequency content.

To assess the prototype system, several candidate wells with sand production issues were selected from the Deepwater Gunashli (DWG) field in Azerbaijan. These wells had been completed with openhole gravel packs and a fiber-optic sensing system installed outside the sand screens along the entire reservoir interval. On one of the wells, interpretation of the acquired distributed vibration data revealed the location at which the formation sand was penetrating the sand screens and migrating into the wellbore. Analysis of the distributed temperature data indicated that the location of the vibration spike signature corresponded to a high-producing interval.

This paper outlines the principles of distributed vibration technology and how—for the first time in the industry—this technology was successfully used with fiber-optic distributed temperature sensing for downhole monitoring. The combination of these two systems enabled the operator to identify the sand entry depth and the corresponding sand-producing interval, eliminating the need for further high risk interventions.
Un-planned Shut-in and Deepwater Gas Hydrate Prevention
Authors: Chen Shing-Ming
Published: July 2010

The main objectives of this paper are to (i) investigate key factors affecting gas hydrate formation and (ii) recommend methods for preventing gas hydrate in deepwater flowing and shut-in gas wells.

In this paper, key factors affecting gas hydrate formation in deepwater gas wells are discussed. Critical times when gas and water may contact each other at temperatures below the gas hydrate temperature inside the tubing during flow and shut-in periods are examined. For flowing wells, since gas hydrate formation can easily be detected by monitoring the gas rate, pressure and temperature at the wellhead, gas hydrate prevention can be planned and implemented properly if there is a need. For shut-in wells, since there is no real time data available to determine if gas hydrate formation is taking place, preparations for gas hydrate prevention should be made available at all times, especially for wells which may encounter unplanned shut-ins during the operations.

In order to assist in illustrating the need for gas hydrate prevention under different circumstances, examples using hypothetical data to represent different field or well cases are presented. Also included in this paper is an example which shows results from a gas hydrate study for a deepwater shadow gas well.

Introduction

Gas hydrate prevention is one of the big challenges[1-6] when developing a deepwater gas field or testing a deepwater gas well in a cold seabed environment. For a deepwater gas well, when gas flows at a high rate during normal operations, no gas hydrate will form because of the warm reservoir fluid flowing through the wellbore. However, during the well start-up, restart, shut-in, or when a well is flowing at low rate, gas hydrate may form due to the low wellbore temperature if both gas and water exist in the wellbore.

As the formation of gas hydrate depends on wellbore conditions and fluids inside the wellbore, it is important to understand the wellbore fluid behavior and heat transfer among fluids and all mediums inside and outside the wellbore such that the possibilities for gas hydrate formation can be predicted and its prevention can be planned.

Effect of Water on Gas Hydrate Formation

As gas hydrate is mainly caused by the existence of water inside the wellbore, prior to discussing the gas hydrate formation, possible water sources which may contribute to water production while producing a gas well should be identified:Water from water zone:When a gas well is being produced, water may come directly from the perforated zone that contains water or indirectly from the water zone through channeling behind casing due to poor cement bonding.Condensed water from natural gas:Unless the produced gas from the reservoir is completely dry, it is inevitable that some water vapor in the natural gas will condense out when the reservoir gas flows through tubing with temperatures that have declined from their initial values.
SS: Subsea Well Intervention: Development of a Deepwater Subsea Well Intervention Package Control System
Authors: Nellessen Peter
Published: July 2010

The paper describes the ongoing work, overall approach and process used to develop a deepwater subsea well intervention control system using structured risk and reliability principles and hardware based upon remotely operated vehicle (ROV) control technology. It discusses the selection of IEC61508 and IEC61511 as the governing standards for development of the controls architecture and certification of this deepwater well control system. It also presents the challenges that have to be addressed when using ROV hardware for well control and describes the methods implemented to overcome system deficiencies. The methods used are currently being vigorously applied throughout the control system's development stage to insure the entire control system and not just its components, will be highly reliable, manufactured, tested and certified in accordance with the principles of IEC60508/61511 to a Safety Integrity Level of 2 (SIL 2).

Introduction

ROV system elements include mechanical, electronic, electrical and hydraulic components. These components have continually matured and improved in operations over more than 30 years. Today ROVs perform subsea tasks which were previously completed by surface operations from a support vessel. ROVs have now been imbedded with, and integrated into, many subsea installations because they have shown to be valuable and reliable tools. However reliable we all may perceive ROVs to be, component and assembly reliability, based on operational use and factory testing, has largely not been fully demonstrated or documented. One reason for the lack of usable reliability data has been due to the ROV operators who generally have not provided the necessary information to the ROV industry. Even if data was available, many ROV components have evolved over the years so operational history is not long enough to predict component life for many components used in those systems.
Material Innovation for Ultra-Deepwater Performance of Long Term Mooring Cables.
Authors: Fletcher Sara Louise , Calverley Stephen , Cawthorne Stephen , Mohanraj Jagan , Verwaayen Johannes
Published: July 2010

Traditional materials abound in station keeping equipment and materials handling in the offshore oil & gas sector; High grade steels being widely utilised throughout all applications, including mooring systems; Synthetic fibres becoming more familiar for tethering and deployment applications. However, true innovation achieving technological step change is rare, driven by an awareness of inherent risk if there is movement away from traditional solutions.

Mooring cables solutions have gradually evolved over the last 30 years, optimising performance characteristics such as weight, strength, elasticity, fatigue performance, to suit the demands of floating production facilities which are being utilised in ever deeper locations & more extreme environments. The conventional materials of steel wire ropes and synthetic fibre have been developed within their property range to match the current requirements but limitations are being reached:Strength to weight ratio of steel moorings is becoming prohibitive in ultra deep locations;Elongation of polyester tethers becomes excessive in ultra deep locations;Creep in HMPE tethers can be an issue in long life systems;High load cases require large diameter products which create complex and high risk installation requirements;Synthetic fibres are sensitive to mechanical damage.

This paper outlines the developments in mooring cable technology since its inception and reviews two key development programmes:

The first is development methodology of a new metallurgical chemistry that achieves the highest strength to weight ratio steel mooring cables. This collaborative project between Corus and Bridon resulted in an UHCSi-Cr grade final hot dip galvanised wire utilized in a spiral strand with 25% weight saving over historical performance.

The second being the step change innovation in materials and material processing developed by Bridon that introduces a synthetic wire product which can be directly substituted into a wire rope construction. This offers a solution for reliable, predictable deepwater permanent moorings with the light weight and elasticity of synthetic fibre tethers, but of robust constructional characteristics and reliable mechanical terminations of traditional steel wire rope solutions. The research, development and test programme will be presented with relevant performance properties for a mooring solution.
Failure Mechanisms of 8630M/625 Subsea Dissimilar Joints and Testing to Assess Performance
Authors: Bahrami Amir , Gittos Mike , Pisarski Henryk , Woollin Paul
Published: July 2010

1. Abstract

Fusion welded buttered connections are an integral part of subsea oil and gas production systems and typically comprise a nickel alloy buttering weld deposit on an alloy steel forged hub, tee or elbow, which is postweld heat treated, and a nickel alloy closure weld, which is between the buttering and a pipeline steel (hence the term ‘dissimilar joint’). In service, piping systems are protected by cathodic protection (CP). The CP provides a potential source of hydrogen which can be absorbed by the steel and, in the presence of sufficient amount of stress, can result in failure at the interface between the buttering deposit and the forging. In order to avoid future failures, it is important that the fracture mechanisms are understood and that there is a means of establishing fitness-for-service. The present paper describes the zones sensitive to hydrogen embrittlement (HE) in the buttering layer's partially mixed zone (PMZ) and summarises results of fracture mechanics tests carried out to assess HE of these interfaces, in seawater under seabed conditions. The paper further highlights the remaining issues that need to be addressed to ensure safe operation of these components.

2. Introduction

Subsea buttered connections are subject to CP, primarily using sacrificial aluminium anodes, which give an applied potential of approximately -1100mVSCE., which may result in HE, if the necessary conditions are met. The HE resistance of subsea buttered interfaces depends on three primary factors: material combination, buttering welding procedure and postweld heat treatment (PWHT) [1]. Each of these influences the microstructure and chemistry across the interface and unless specifically selected for resistance to HE, the joint is susceptible to failure. Whilst the vast majority of subsea joints have given successful service, a small number has failed. These failures have mainly involved installed components which have not been in service[2].
FDPSOs: The New Reality, and a Game-Changing Approach to Field Development and Early Production Systems
Authors: Harris W.D. , Howard Harry J. , Hampshire Kenneth Christopher , Moore Jeffrey Allen , Bayne Kenneth J. , Pepin-LeHalleur Jean
Published: July 2010

The Azurite field development, installed in the Republic of Congo in 2009, employed the industry's first Floating, Drilling, Production, Storage and Offloading (FDPSO) vessel to develop the field. While the FDPSO concept has been a subject of interest within the industry for some time, the Azurite project team took the FDPSO from concept to reality.

The concept has tremendous potential as a " game changer?? for field developments, whether it is employed to unlock the value of marginal fields in deepwater - even in a low oil price environment - or as an early production system. Because the concept employs a drilling rig onboard the vessel, traditional challenges regarding deepwater drilling rig day rates and availability are eliminated.

This paper summarizes development of the Azurite field as a way of providing context for evolution of the FDPSO concept. This paper also highlights other application for FDPSOs, and discusses some of the key variables that determine the suitability of the FDPSO concept for use in field developments.

Introduction

History was made in August 2009 when the Azurite field began producing offshore Republic of Congo [1]. Azurite employed the industry's first Floating, Drilling, Production, Storage and Offloading (FDPSO) vessel to develop the field. While the FDPSO concept has been a subject of interest within the industry for some time, The Azurite team made the FDPSO concept a reality. It is a robust concept that has potential for much broader application, as the number of large discoveries in deepwater shrink and the industry seeks new ways to monetize stranded pockets of oil and gas.

This paper will reflect on the project technical and economic drivers that led the Azurite project team to select the FDPSO concept. This paper will also discuss other applications for the FDPSO, and identify key variables that determine suitability of the FDPSO concept for use in field developments.

Azurite: Inspiration for the Concept

Discovery and Appraisal

The Azurite Marine Field lies within the Mer Profonde Sud (MPS) block offshore Republic of Congo, just north across the border from Cabinda Block 14. Water depths across MPS range from 1100 - 2000 meters.

Azurite field was discovered in January 2005 with the Azurite Marine-1 (AZRM-1) well. The field was subsequently appraised in late 2005 and early 2006 with the drilling of AZRM-2 and AZRM-3 wells. Each of the latter two wells was sidetracked (ST). AZRM-2ST was also cored and tested. Aquifer support was found to be essentially non-existent along the producing trend, necessitating the requirement for water injection to support reservoir pressure.

Field Size Description

The AZRM-2 and AZRM-3 wells were ST to appraise the four fault blocks of the field as shown in Figure 1 below.
Subsea Hardware Installation from a FDPSO
Authors: Stensgaard Thomas , White Charles , Schiffer Kevin
Published: July 2010

Subsea installation campaigns in support of deepwater field developments are expensive and require specialized vessels to carry-out the work scope. The traditional method entails deploying a costly subsea construction vessel, complete with remote operated vehicle (ROV) capabilities, survey and heave-compensating cranes. However, with a Floating, Drilling, Production, Storage and Offloading (FDPSO) postioned directly over the drill center, a new alternative to the traditional subsea installation campaign came into view. This paper presents the unique challenges related to subsea hardware installation from an FDPSO, and the methods developed to overcome those challenges.

Introduction

The Floating, Drilling, Production, Storage and Offloading (FDPSO) concept requires that it is located over the wells for direct access, and so the ability to perform subsea construction and intervention activities directly from the host becomes a real possibility. The FDPSO provides a large stable platform from which these activities can be accomplished, but it has limited access and maneuverability, and so these challenges must be addressed.

These challenges were met and overcome in the pioneering Azurite field development in Mer Profonde Sud (MPS) block offshore Republic of Congo. The FDPSO was fitted with a working class remote operated vehicle (ROV) spread, along with a 100 tonne heave-compensating crane mounted to the deck. The 100 tonne crane was sized to install hardware as heavy as subsea trees.

Some of the equipment deployed from the Azurite FDPSO included: subsea trees, flexible well jumpers, steel tube flying leads and electrical flying leads.
OTEC Power Efficiency Challenges
Authors: Hurtt James , Pellen Alain , Nagurny Nicholas John
Published: July 2010

The maximum possible Carnot thermal efficiency of an Ocean Thermal Energy Conversion (OTEC) power system is about 7% as it exploits the water temperature gradient between the surface and the deep ocean, which is only slightly over 20 degree C in tropical waters. The overall efficiency of a multi-megawatt-sized OTEC electrical power plant, all inclusive from seawater to net electric power, is typically around 2%. Only about half of the water temperature gradient can be directly harnessed across the power cycle, as the rest is needed for heat transfer and mass flow to maintain economical heat exchanger and seawater pump sizing. About a third of the gross power generated is consumed pumping seawater, powering auxiliary systems, and in power transmission losses. This paper reviews efficiency as it relates to the OTEC power cycle. OTEC has enormous potential as a source of clean, renewable, and base-load electricity for many nations, territories and states near tropical waters. As OTEC technology matures, large floating OTEC plants are expected to produce energy carriers or synthetic fuels that can be shipped to energy consumers. This paper will provide a current review of the various components used by one OTEC power cycle, their respective efficiencies and their contribution to the overall OTEC power plant economics. A thorough understanding of the efficiency losses, power burden, and potential areas for optimization is critical for OTEC to become an economically viable resource. This paper provides recommendations for the design of the OTEC plant main components and gives guidelines to optimize efficiency such that high quality power can be sold to the utility at competitive rates. Finally, the results of a parametric study of OTEC size in terms of Megawatts produced shows the efficiency gains that can be achieved with large scale OTEC power generation plants.

I. Introduction

Global energy demand is increasing rapidly. Growing populations and higher standards of living worldwide are pushing the limits of existing energy resources. At the same time hydrocarbon reserves are becoming harder to find. There is growing global concern for energy security and environmental sustainability. Global development and commercialization of renewable technologies is required before existing resources become scarce. For instance: wind energy has been used through the centuries but was surpassed during the Industrial Revolution by coal and oil. However, over the past decade, wind power has seen exponential growth as an energy resource (2009 US DOE). Solar and wind energy have the economic advantage of free " fuel?? but come with the intermittent and variable nature of that " fuel?? source. Ocean thermal energy enjoys the benefit of the large thermal storage of ocean waters and can therefore provide a base-load source of electricity to coastal areas in tropical waters and energy carriers to energy consumers.

Figure 1 is a map showing the vast worldwide OTEC resource.
SS: Metocean: Comprehensive Hindcast of Hurricane Ike (2008) in the Gulf of Mexico
Authors: Cardone Vincent J. , Cox Andrew T.
Published: July 2010

The immense impact of Hurricane Ike (2008) on Gulf of Mexico (GOM) offshore infrastructure and production is unexpected for a Saffir-Simpson Scale (SSS) Category 2 hurricane. This paper describes a comprehensive hindcast of the surface wind and sea state fields generated by Ike that shows that the extreme ocean response is mainly caused by a marked expansion of the wind circulation after the eye of the storm crossed the western tip of Cuba, leading to storm with a large radius of maximum wind speed and a shelf-like radial wind speed profile. The modeling of these attributes required the description of the radial pressure distribution in the boundary layer in terms of a double exponential analytical formulation. The fitting of that functional form utilized all conventional meteorological data, high-temporal density flight level measurements made by reconnaissance aircraft and remotely sensed satellite meteorological data within an analyst-assisted workstation that allows the fitting of either the classical single exponential form or, if appropriate, the more complex form. The surface wind field is specified by solutions of a newly recalibrated primitive equation mesoscale boundary layer model augmented by available kinematic analyses of the inner-core wind structure derived directly from measured wind data. The wave response is hindcast by a proven third generation (3-G) spectral wave model adapted to GOM at high resolution that includes shallow water effects and incorporates a saturation surface wind drag formulation consistent with recent hurricane inner core measurements of same. The hindcast and available measurements support that Ike generated peak significant wave heights of about 45 feet (~14 m) in the north central GOM. The hindcast is compared to public-domain wave measurements currently available and good skill is evident. In the near term these results aid post-mortem engineering studies conducted to ascertain causes and modes of failure of damaged platforms and other infrastructure and to assess the suitability of related designs. Of longer term significance, the hindcast methodology applied to Ike has been used to incorporate the impact of lower ranked SSS hurricanes and of all hurricanes that exhibit the non-classical radial pressure and wind structure on the specification of extreme metocean criteria derived either by the direct historical or deductive approaches.
Parque das Conchas (BC-10) - An Ultra-Deepwater Heavy Oil Development Offshore Brazil
Authors: Stingl Kent H. , Paardekam Albert H.M.
Published: July 2010

Parque das Conchas is an ultra-deepwater heavy oil development located in the northern Campos basin offshore Brazil. The project is a joint venture between Shell, Petrobras, and ONGC. The first phase of the project is the development of 3 independent subsea fields tied back to the centrally located turret moored floating, production, storage and offloading (FPSO) host facility entitled the FPSO Espirito Santo. The phase 1 Abalone, Ostra, and Argonauta B west fields are small to medium in size, with low-pressured reservoirs, and range in oil gravities from 17O to 42O API. A fourth 16O API gravity heavy oil field requiring water flood, Argonauta O north, will be tied back as part of phase 2 and is planned to be ready for production in 2013. The phase 1 subsea infrastructure consists of 10 producing wells and 1 gas injection well connected via 140 kilometers of pipelines and flowlines ranging in size from 6?? to 12??, 15 flowline sleds, 2 production manifolds, 2 artificial lift manifolds housing a total of 6 vertical subsea separation caissons with 1500 hp ESP's, 25 jumpers, all of which are serviced by 30 kilometers of high voltage multi-circuit electro/hydraulic umbilicals and 20 kilometers of static electro-hydraulic umbilicals. The FPSO Espirito Santo is a converted 1975 VLCC moored in 1,780 meters of water and equipped to process 100,000 bopd, 50 MMscfpd, with 1.4 million barrels of oil storage capacity. The Parque das Conchas development is the result of a 9-year effort to understand the complex geology, identify sufficient reserves to support a development, identify an economic development concept, and to design, mature and apply the significant new technologies required to safely execute the project during an extremely volatile market period. This paper provides an overview of the development and execution of the project, highlights new technologies that have been developed and implemented and introduces the key challenges, achievements, and learning's in various parts of the project and the tight integration between all disciplines required to successfully deliver the Parque das Conchas project. Additional details can be found in the dedicated support papers have been generated and listed in the Reference section of this paper.

History

The Parque das Conchas development grew out of a substantial exploration and appraisal program commencing in 2000 in which 13 wells were drilled and 6 discoveries were made. The Declaration of Commerciality was signed with the ANP (the Brazilian National Petroleum Agency) in December 2005 and the project was sanctioned in November 2006. The four main reservoirs; Ostra, Abalone, Argonauta B west, and Argonauta O north were named after aquatic shellfish indigenous to the area. Together they form " Parque das Conchas?? or " Shell Park?? in Portuguese. This is the first project taken by Shell from exploration discovery to production. First oil from Phase 1 was achieved on the 12th of July 2009, just 9 years after discovery.
Measurements of the Capillary Pressure-Saturation Relationship of Methane Hydrate Bearing Sediments
Authors: Ghezzehei Teamrat Afewerki , Kneafsey Timothy J.
Published: July 2010

Methane hydrate present in permafrost and sub oceanic sediments has been identified as a potentially large energy source. Producing natural gas from hydrate results in the hydrate dissociating into gas and water, which then become distributed in the pore space according to gravitational, viscous, and capillary forces.

Capillary pressure is a function of the medium (wettability, geometry) and the saturations of all phases (e.g. gas, hydrate, water) in the pore space. The presence of hydrate alters the geometry of the pore space, changing the capillary pressure-saturation relationship from the hydrate-free condition. Understanding the capillary pressure-saturation relationship of hydrate-bearing media is important for modeling the flow of gas and water through that medium, and predicting natural gas production from hydrate-bearing reservoirs. We have developed a method for measuring the capillary pressure-saturation relationship in methane hydrate-bearing sand, and our measurements and modeling aid in understanding the behavior of the gas and water in hydrate-bearing sediment. Our experiments involve hydrate formation in unsaturated sand, saturating the sample, followed by step-wise drainage from full water saturation to residual water saturation while measuring the pressure difference between the water and gas phases. During drainage, a number of intermediate static equilibrium conditions were established during which flow was discontinued. The static equilibrium observations provide water saturation vs. capillary pressure relations. For selected samples, drainage was followed by step-wise imbibition to full saturation.

Introduction

Natural gas hydrates are solid compounds in which a network of water molecules form clathrate structures around small gas molecules such as methane, ethane, and carbon dioxide. These compounds generally form and are stable at elevated pressures and low temperatures where water and the hydrate-forming compounds are available in sufficient quantities. Natural gas-hydrate-bearing deposits in sub oceanic sediments and permafrost regions are estimated to hold an enormous quantity of hydrocarbons, with the primary constituent being methane. Estimates of the volume of hydrocarbons contained in gas hydrates span a large range (from 1 to 5 × 1015 m3 (Milkov, 2004) to 1.2 × 1017 m3 at standard temperature and pressure (Klauda and Sandler, 2005)), and dozens of natural deposits have been encountered. It may be possible to develop some of these deposits to produce natural gas, providing a potential energy resource given that a sufficient amount of hydrate is present, permeability is adequate, the deposit is confined, and needed infrastructure is located nearby.
Consolidation Around Seabed Pipelines
Authors: Gourvenec Susan , White David
Published: July 2010

The build-up of pipe-soil resistance that can be mobilized on a seabed pipeline, particularly in the axial direction, is affected by consolidation of the seabed beneath the pipeline after it is laid. On fine-grained soils the consolidation period may extend well beyond the laying period, and involve a significant gain in pipe-soil resistance: a process analogous to the set-up of piles driven in clay. The available level of pipe-soil resistance affects many aspects of pipeline design, such as stability on route curves and down slopes, geohazard vulnerability, lateral buckling and axial walking behaviour. This paper considers consolidation around on-bottom pipelines through a numerical study, supported by field data. The soil is modeled as an elastic material with coupled Biot consolidation. Pipe embedments of up to 0.5 diameters have been considered and the effect of soil berms adjacent to the pipe, formed of the displaced soil, has been explored. The solutions and guidance provided in this paper allow pipeline designers to estimate the ‘set-up’ periods over which the effective stress at the pipe-soil interface will rise in the period after laying, indicating the build-up of available axial pipe-soil resistance. The results account for the enhancement of this resistance through a ‘wedging’ action. The dissipation process is retarded by a factor of up to 2 if the displaced soil forms a berm that is collapsed against the pipe wall. Similar solutions for the analogous situation of consolidation (‘set-up’) around driven piles have existed for many years. This paper provides the equivalent design tool for on-bottom pipelines.

Background

Subsea pipelines are commonly laid directly on the seabed. The axial resistance that can be mobilized between the pipe and the seabed is an important consideration for both the installation and the in-service behaviour. It is an input into the following design aspects, and others:Resistance during shore pulls and bottom-tow installation.Stability of route curves during laying.Stability on a sloping seabed.End expansions and buckle feed-in in response to internal temperature and pressure.Restraint to support the pipe adjacent to externally-loaded sections - such as when impacted by submarine slides.

When a pipe is laid on the seabed it penetrates into the surficial soils, which are typically very soft in deep water. In finegrained clayey soils the usual rate of laying is such that the embedment response is undrained. Excess pore pressure is generated in response to the imposed weight of the pipeline, and due to shearing of the soil. The effective stress in the soil remains low, as it was in situ, until drainage occurs. After full dissipation of the lay-induced pore pressure, the sum of the vertical effective stress around the pipe-soil contact equals the pipe weight.