bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Combination Corrosion-Scale Inhibitor for the Subsea Separation and Boosting Systems of the Parque das Conchas Project in Brazil
Authors: Silvestri Maximilian A. , Emmons Daniel Hugh , Linares-samaniego Sandra , Gingrich Randy 
Published: July 2010

Abstract
The deepwater, low pressure reservoirs, developed as part of the Parque das Conchas project, located in block BC- 10 offshore Brazil, require artificial lift for most of their field lives to enable flow. The complexity of the artificial lift system presents a host of challenges in terms of flow assurance and asset integrity. This paper presents our laboratory efforts in developing and qualifying a novel combination corrosion-scale inhibitor (CI/SI) that is effective under these challenging conditions. This represents the first time a combination product has been developed in the oil and gas industry for a deepwater artificial lift system.
Subsea boosting and separation are integral parts of the successful development and production of oil and gas from this deepwater project. The Parque das Conchas project employs subsea separators and electric submersible pumps contained within subsurface caissons. Electric submersible pumps are particularly sensitive to corrosion and scale formation due to extreme skin temperatures that can develop and often require continuous chemical injection to control these problems.
The application of these chemical solutions occurs via subsea umbilicals. However, limitations in the availability of umbilical lines require the use of combination chemical solutions that effectively and simultaneously control corrosion and scale problems.
High temperature rotating cage autoclave experiments as well as scale inhibitor bottle tests and dynamic tube block tests were utilized to qualify this custom combination corrosion-scale inhibitor. Conditions for both corrosion and scale testing were based on the caisson and flowline environments. The laboratory results suggest that the combination product is effective at mitigating corrosion and scale deposition under these simulated conditions. The product also displays broad chemical compatibility with produced fluids and other production chemicals. The combination corrosion-scale inhibitor also displays enhanced thermal stability, unique to this subsea application.
This chemistry is the first qualified combination product for mitigation of corrosion and scale for a deepwater development requiring both subsea boosting and separation.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Special Session: LNG & LPG Operations Offshore
Authors: Mclean David 
Published: July 2010

Abstract
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

Abstract
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

Abstract
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.