bluuebunny/crossref_metadata_2025_split huggingface dataset:
SS: High Pressure Gas Liquid Separation: Scrubber separation - Droplet Entrainment in High Pressure Gas Liquid Separation
Authors: Patruno Luciano Emanuel , Marchetti Jorge Mario , Dorao Carlos Alberto , Jakobsen Hugo Atle , Svendsen Hallvard , Tayebi Davoud 
Published: July 2010

Abstract
This work presents experimental results on droplet entrainment in two different geometries: a stratified liquid film, and a wire flooded by liquid. The experiments feature the system pressure ranging from 900 to 1600 kPa (130 to 220 psia) and surface tension of the system in the lower range of 24 mN/m.
The resulting droplet size distribution after a liquid entrainment event plays a major role in the modeling of the gas liquid scrubbers. When a mesh pad-based separator gets flooded, the high speed gas running throughout the mesh can reentrain the liquid and carry over liquid droplets into the dry gas processing facility.
Conventional correlations for liquid entrainment overestimate the resulting droplet size as they were derived from higher surface tension systems. In addition, a correlation for the entire droplet size distribution is presented.

Introduction

Liquid fragmentation
A description of the interaction between the phases in multiphase flow is of major interest for the oil and gas industry as the presence of droplets in the gas phase can cause erosion and breakdown of equipment. The use of conventional separators at high pressure may not be sufficient since very small droplets may be entrained from liquid films at the walls. The droplet size plays a major role in choosing which separation technology is to be used, as smaller droplets are more difficult to separate than bigger drops, given the smaller ones have low inertia and will follow the gas stream lines.
The droplet separation process normally takes place inside a gas scrubber or separator. In a conventional vertical gas scrubber/separator the gas/liquid mixture typically enters the separator sideways through the inlet vane, then flows upward through a mesh pad or vane pack and finally through the cyclone deck. A schematic drawing of the separator is shown in Fig. 1. A detail description and characterization of a scrubber can be found in Austrheim et al. (2006).
When the gas/liquid mixture enters the separator the major portion of its liquid is removed in the inlet vane. The inlet vane is intended to redistribute and redirect the flow before reaching the mesh pad. The mesh pad is an arrangement of knitted wires that can be placed on top of each other or rolled into a cylindrical structure. The mesh pad is based on separation by droplet impactation to the wires. At low pressures, a mesh pad can give a very high separation efficiency, but when operating at high pressures the efficiency drops. Under high pressure conditions the mesh pad is in practice used as a coalescer and operates at, or above, the flooding point. At the flooding point, the liquid load is higher than the liquid drainage capacity and the gas re-entrains the liquid surrounding the wires (Helsør & Svendsen 2007).
Appraisal And Development-Sanction Challenges For A Small, Stranded, Offshore Heavy-Oil Project In The North Sea
Authors: Coghlan Gerard Philip 
Published: July 2010

Abstract
The Central North Sea Pilot field lies in UK license block 21/27. In 1989 a discovery of heavy oil - by North Sea standards - was made in Eocene sands at a depth of 2700ft TVDSS. Three vertical appraisal wells determined relatively extensive, thin package of turbidite sands (ca.100ft) of limited relief (ca.150 ft). Early flow-testing was constrained by difficulties in sustaining flow because of separation and flaring problems due to low rates, water coning, also sand production. Sampling was problematic with oil properties ranging from 17-22 degAPI and 90-160 cP.
In 1998, a 'prover', horizontal well was completed with an ESP with the intent to prove up sustainable, commercial rates, however this was not achieved, because the oil samples pointed to an oil of much lower quality than expected, 13 degAPI and 1900 cP. Venture Production acquired the field in 2001 as part of a package of acquisitions.
Subsequently all historic data were reviewed and a major effort to move field development forward resulted in the identification of several innovative approaches, centred on a cylindrical hull FPSO to commercialise this geographically stranded (nearest infrastructure 25miles), technically and commercially challenging opportunity. A postulated, developable OIIP of 110 MMstb with a viscosity of ca.100 cP or less was to be targeted by horizontal, hydraulically pumped wells and a waterflood.
Key uncertainties were a) the oil quality distribution and b) the need to recover samples of sufficient volume to allow flow assurance issues (such as calcium napthenate and sodium soap) to be assessed. A further appraisal well was proposed to acquire the necessary, large-volume, representative samples on wireline. An innovative appraisal strategy utilising a geotechnical drillship with much-reduced drillex was planned but the program could not clear all necessary HSE hurdles - resulting in a delay of 1 year and a conventional drilling program (and costs). The appraisal well was drilled in 2007 and determined that oil quality was variable and unpredictable and the necessary minimum OIIP/ reserves for project sanction could not be assured. Follow-up studies resulted in a decision to relinquish the acreage after 20 years of work.

Introduction
The Pilot oilfield is located on the UKCS in the Central North Sea in license block 21/27, ca.100 miles east of Aberdeen in a water depth of ca.265 ft. The reservoir is located in Middle Eocene age, deep water sands which were deposited as turbidite flows from a shelf immediately to the west of the accumulation. The reservoir interval was deposited by turbidity currents that ranged from high density to dilute low density.
SS - Implications of Subsea Processing Power distribution on Field architecture : Electrical transmission and distribution architectures for subsea processing systems
Authors: Thibaut Edouard , Meyer Eric , Rambaldi Eric 
Published: July 2010

Abstract
Work is currently ongoing in the offshore oil & gas industry to develop subsea processing systems supplying multiple electrical consumers, over long step-outs and in deep waters.
To meet the technical challenges of these developments, new subsea electrical power transmission and distribution architectures have to be developed.
This paper gives an overview of possible electrical power transmission and distribution architectures. It addresses the main technical challenges and present limitations, describes the system approach and gives an operator's viewpoint as to the way forward.

Introduction
With today's fields fast becoming depleted and discoveries of easy-to-produce offshore oil & gas resources ever fewer, subsea processing equipment is the focus of an extensive development drive. The results are especially attractive for remote fields, deep waters and tough topside environments such as arctic locations.
As subsea equipment evolves to become increasingly sophisticated and power-intensive (pumps, compressors, processing, and flow assurance systems), there is a growing need for ultra-reliable electrical transmission and distribution systems to power the equipment over long step-outs.
Like subsea applications, electrical architectures are site-dependent and a suitable electrical transmission and distribution architecture has to be defined based on the electrical power needed, the water depth and the tie-back length for each specific oil and gas field development. This paper examines the ins and outs of using AC and DC transmission for subsea applications, overviews the options of electrical power transmission architectures open to the operator depending on the type of oil and gas field to be developed, and addresses the main technical challenges and present limitations. It focuses exclusively on power-intensive subsea applications, and the challenges of transferring large quantities of electrical power (&gt; 1MW) over long distances.
Gas Hydrate System of Shenhu Area, Northern South China Sea:Wire-line Logging, Geochemical Results and Preliminary Resources Estimates
Authors: Wu Nengyou , Yang Shengxiong , Zhang Haiqi , Liang Jinqiang , Wang Hongbin , Lu Jing'an 
Published: July 2010

Abstract
Shenhu Area, one of the most favorable locations for gas hydrates in the north slope of South China Sea, is located in the Pearl River Mouth Basin. The geological setting, temperature and pressure conditions are favorable for the formation of gas hydrate. Analysis of the geochemistry of sediments from large piston cores showed that the sulfate-methane interface (SMI) is from 10 to 27 mbsf in the research area. Methane was the dominant hydrocarbon gas in all gas analyses. The d13CCH4 values of headspace gases from the gravity piston core sediments ranged from -74.3‰ to -46.2‰, with the majority being less than -55‰. It is likely that the methane of gas hydrate originated from in-situ microbial activity.
The drilling recovered high concentrations of hydrate (maximum 26-48%, with the gas composition of &gt;99% CH4) in a disseminated form in foram-rich clay sediments. The wire-line log showed a very distinctive positive anomaly in resistivity and sonic velocity in the interval of the hydrate layer. It was also interesting that the caliper log was smoother through this interval and the density log also showed a small decrease. From the combined well-log and geochemical data, the hydrate-bearing sediments were determined to range from 10 meters to 25 meters in thickness, and to concentrate just above the base of the gas hydrate stability zone (BGHSZ).
The estimate of the total amount of methane trapped in the drilling-confirmed 15 km2 extent of the Shenhu hydrate deposit is about 160×108m3 at a 50% probability. Given the size of this accumulation, the Chinese government and industry have a keen interest in the commercial development potential of the resource.

1. Introduction
Gas hydrate is an ice-like solid substance formed by the combination of low-molecular-weight gases such as methane, ethane, and carbon dioxide with water. Gas hydrate mainly occurs naturally in sediments beneath the permafrost and the sediments of the continental slope in water depths more than 300 m. The reason why marine gas hydrate systems are important to economic society and the environment is not only that gas hydrate in some places may be concentrated enough to be an economically viable fossil fuel resource, but also because gas hydrate can cause geo-hazards through large-scale slope destabilization (Maslin et al., 2004) and can release methane, a potential greenhouse gas, to impact the global climate (Dickens et al., 1995; Hesslebo et al., 2000; Maslin and Thomas, 2003; Kennett et al., 2003; Sowers, 2006; Bowen et al., 2006). Gas hydrate and its associated sediments have also become an important focus for biogeochemical study of the deep biosphere (Wellsbury et al., 2000).
SS: Ocean Mining: Deep Ocean Seafloor Mineral Extraction - Environmental and Social Considerations
Authors: Smith Samantha 
Published: July 2010

Abstract
Nautilus Minerals (Nautilus) is following the lead of the petroleum industry as it strives to tap vast offshore resources. Planning is well underway for the Solwara 1 Project in the Bismarck Sea, Papua New Guinea (PNG) to recover high grade seafloor massive sulphide deposits in 1600 m water depth. The deposit contains an average copper grade &gt;10 times higher than a typical land-based porphyry copper mine. The high grades combined with a relatively small amount of overburden ensure the Solwara 1 Project will have a significantly smaller physical footprint than its land-based counterparts. Offshore minerals production also has the advantage of minimal social disturbance.
Nautilus is dedicated to setting a high environmental and social responsibility standard. Nautilus recognises the importance of transparent and inclusive stakeholder engagement and has taken a proactive approach to involve as many stakeholders as possible. One of the first steps in the permitting process is the preparation of the Environmental Inception Report, which describes the project, its envisaged impacts and the proposed studies for the Environmental Impact Assessment (EIA). Local (PNG-based) and international environmental scientists, anthropologists, NGOs and other experts were involved in the definition of studies conducted for the Solwara 1 EIA and a team of world-leading experts was involved with carrying out the studies, culminating in the preparation of the Environmental Impact Statement (EIS). To ensure transparency, collaborating researchers are free to publish their findings. Following its submission, the EIS was made available for public review and public hearings were held at several locations. The EIS has also undergone a rigorous independent review by PNG government-engaged consultants. Outside the permitting process, Nautilus works alongside government officials to carry out ongoing community consultations. Information dissemination and feedback acquisition has also occurred through the Nautilus website and attendance at a number of international conferences, workshops, and meetings.
This paper will outline the leading edge approach Nautilus has taken in completing the environmental impact statement for the world's first deep seafloor copper-gold mine. In addition, this paper will review the permitting process and the government and stakeholder engagement undertaken as part of Nautilus' desire to " do it right?? in this exciting new industry.
Deepwater Pipeline Installation by Reel-lay Method
Authors: Smith Stuart N. , Clough Tony 
Published: July 2010

Abstract
The reel-lay method is generally the most effective way of installing infield subsea flowlines and risers particularly for sizes up to around 16 inch. This paper describes one of the most advanced reeled pipeline installation vessels in the world, the Seven Oceans, and the variety of pipelines and risers that she has installed including the welding and inspection of high fatigue life SCRs and sour-service flowlines.
The paper goes on to present various recent developments for reeled installation including HFI pipe, PE lined pipe, mechanically lined pipe, clad flowlines and SCRs, high strength pipe, hybrid risers and electrically heated-traced flowlines. These show the continuing attraction of reel-lay for ever more technically demanding work and that for options such as electrically heat-traced flowlines that reeling will be the main vessel based installation method.

1. Introduction

1.1 Vessels
The reeled pipelay concept has been in use since the Pipelines Under the Ocean (PLUTO) project across the English Channel (Purvis, 1946). The reel ship Apache (Anon, 1979) is a notable name in the development of the technology and was first operated in 1979. Other reel lay vessels followed including the Skandi Navica (Clarkson, 2006) now named as Seven Navica. Another notable vessel was the Deep Blue (De Soras & Cruickshank, 2000) and more recently the Seven Oceans. Other reeled vessels also exist but the characteristics of these main ones are given in Table 1.
SS: Implications of subsea Processing Power Distribution: Optimized Oil Field Architecture for Electrical Boosting in Deepwater
Authors: Easton Steven 
Published: July 2010

Abstract
Currently the field architecture for most deepwater developments has been dictated by flow assurance constraints due to a reliance on conventional dual flowline loops with riser base gas lifting. Subsea boosting and separation technology will help expand these traditional boundaries and hence facilitate the operation of longer, deeper pipelines transporting fluids with lower temperatures and pressures.
Providing power to remote subsea equipment, which consume power measured in mega watts, will result in power distribution becoming a new driver for field architecture. High voltages will not necessarily be compatible with current power and control technology.
Contractors will therefore have to engineer and deploy large subsea units and integrated power and control umbilicals to match the new field architecture. The reliability of the power distribution system takes on a greater importance. Simply put, loss of electrical power will equal loss of production. How contractors adapt and qualify new technology during the design and installation phases of a project will be a key to its success.
A case study will be presented for boosting a remote deepwater oil field comparing the flowline and umbilical sizes and power requirements for different field layout options. The paper will highlight the implications that the power distribution systems have on the optimization of the field architecture.

Introduction
The start of the twenty first century saw the emergence of a number of large deepwater fields in West Africa, the Gulf of Mexico and South America. The technical risks associated with these developments were numerous but ultimately not insurmountable with flow assurance emerging as one of the main drivers for selection of the field architecture.
Flow assurance is a relatively new engineering discipline to the oil and gas industry, encompassing a broad range of engineering and scientific disciplines. Flow assurance gained particular importance for deepwater fields due the increased energy losses occurring in the riser. Deepwater reservoirs can be characterized with relatively low reservoir pressures and temperatures with viscous fluids with high wax appearance temperatures. The static head losses over 1000 to 2000 m are high and represent a high percentage of the total hydraulic losses and there is an accompanying temperature reduction due to the Joule-Thomson and loss of potential energy effects.
Special Session: Advances In Flexible Riser Technology: Flexible Pipe Design For A High Temperature / Highly Insulated Production Flowline For The North Amethyst Project In The North Atlantic
Authors: Mandeville R.J.R. , Turpin Louie , Searle Shawn , Phillips Gordon 
Published: July 2010

Abstract
The North Amethyst Field is the first of a series of offshore tie-back satellites to the Sea Rose FPSO, located in the greater White Rose Area, approximately 350 km off the east coast of Newfoundland, Canada. Water depths in the field range from 120m to 125m. The North Amethyst Field is operated by Husky Energy Ltd. on behalf of its partners Suncor Ltd. and Nalcor Energy.
The North Amethyst expansion consists of the North Amethyst Drill Centre (NADC), through which the field is developed by a combination of production & water injection wells. The subsea equipment is located in excavated ‘glory holes’, placing the top of the subsea equipment 2-3 m below the surrounding seabed level to protect against iceberg scour. The subsea facilities are tied back to the pre-existing Southern Drill Centre (SDC) in the South Avalon Pool via flexible flowlines.
This paper will provide an overview of the major design and fabrication issues encountered during the engineering, fabrication and installation of the 10?? North Amethyst production flowline.
The challenges associated with designing a high temperature flowline requiring a low thermal conductivity included onbottom stability, material temperature limits, and the design impacts on ancillary equipment (bend restrictors, dropped object protection).
Flowline systems designed for use offshore Newfoundland require a " weak-link?? at the subsea equipment connection to prevent damage to subsea assets and environmental impact due to loss of containment. The " weak-link?? presented a number of design, manufacturing and installation challenges.
The flowline design implications on the installation campaign and schedule is also discussed and the measures taken to mitigate the issues.

Introduction
Unbonded flexible pipes are composite structures; composed of metallic layers for both axial and radial strength, thermoplastic layers for fluid retention, tapes for both ordering and containment off metallic wires, and various types of foam for thermal insulation. Though the low bending stiffness of flexible pipes is seen as most beneficial in riser systems which must be compliant with the motions of a floating production system, the use of flexible pipes as static flowlines yields significant advantages when compared with rigid steel pipe:Storage upon reels or carousels reduces the restrictions on the type of installation vessel requiredThe routing of the pipeline on the seabed is simplified as tighter bend radii and more extreme elevations changes can be accommodatedThe inherent lower thermal conductivity reduces the need for externally-applied insulation coatingsTransportation and logistics are easier when the installation location is removed from spool bases
Parque das Conchas (BC-10) High Voltage Power Umbilical Design and Installation
Authors: Eckerty Sean P. , von Tungeln Rob , Liney David J. 
Published: July 2010

Abstract
Production operations at the Parque das Conchas (BC-10) development rely on multiple subsea pumps that are powered from the host FPSO. As such, the design and installation of a robust subsea power distribution methodology was an enabling requirement. The limited number of I tubes in the FPSO turret, coupled with a desire to simplify and optimize the subsea layout, provided incentive for the development of a multi-circuit power transmission and distribution system that could be combined with traditional electro-hydraulic control and chemical delivery umbilicals.
The challenges posed by this hybrid umbilical design, specifically the delivered power quality and manufacturability of the umbilicals, was addressed through the development of a cross section incorporating multiple trefoils for power transmission. To achieve the required umbilical lengths, a slim line electrical splice is a key component of the umbilical design program. These high voltage (HV) cables are designed to provide the power for the subsea pumping facilities, whilst not compromising the base functionality of the umbilicals.
In addition, to ensure the mechanical performance of the umbilical in a dynamic application, steel tubes serve a dual purpose as conduits for the hydraulic and chemical services for the subsea fields, as well as provide support for the HV electrical cables. This approach eliminated the need for supplemental strength members or armoring that would typically have been required for the dynamic application of large copper subsea power cables in ultra deep water.
This work resulted in an optimized umbilical and subsea distribution design incorporating both traditional electro hydraulic control elements and multiple HV transmission circuits that can be used as a model for similar subsea developments.

Introduction
The Parque das Conchas (BC-10) development is located in deepwater offshore the Brazilian state of Espirito Santo. The asset is a partnership between Shell Brasil (operator, 50% working interest), Petrobras (35%) and ONGC (35%).
A combination of low reservoir pressures, medium to high viscosity crude, and the ultra deep-water depth at the development site requires the use of subsea boosting to enable production. A key component to enable the boosting system is a high voltage, three phase AC transmission system. While host-to-subsea power transmission is not new technology, traditional options for transmission, such as individual power cables for each motor, or a dedicated power umbilical, could not be applied. This was due to limitations in the number of I-tubes in the turret, and the extreme water depth. These and other design requirements/challenges were accommodated through the inclusion of HV power transmission elements into traditional electro-hydraulic control umbilicals.