bluuebunny/crossref_metadata_2025_split huggingface dataset:
Revision of Sequences Boundaries and Maximum Flooding Surfaces: Jurassic to Recent
Authors: Wornardt Walter W. , Walter W. 
Published: June 2014

ABSTRACT
The key to recognizing the third and fourth order depositional sequences is the maximum flooding surface. An age designation of this surface is extremely important in seismic sequence stratigraphic analysis. Therefore, the purpose of this paper is to recognize and date the Cenozoic, Cretaceous and Jurassic maximum flooding surfaces in Ma and to assign a specific numerical age and letter designation to each of these maximum flooding surfaces from the Jurassic to Recent. These designations can be used as a standard of reference for the maximum flooding surfaces worldwide.

INTRODUCTION
Seismic sequence stratigraphy is the integration of high resolution biostratigraphy (including age datable bioevents, paleobathymetry and fossil diversity and abundance histograms), well-log signatures and seismic profiles. Each of these three components are interdependent and incomplete by themselves and, therefore, they must be analyzed and integrated with each other using an iterative process in order to obtain accurate, reliable and reproducible results. The introduction of high resolution biostratigraphy and paleobathymetry into seismic sequence stratigraphy in 1987 (Lamb, 1986) provided the key data set that permitted Sequence Stratigraphy and Seismic Sequence Stratigraphy to become a practical reality in exploration and development. It permitted the explorationist to age date the maximum flooding surface within each sequence and help divide a stratigraphic section in a well and on a seismic section into a series of third order depositional sequences and systems tracts in a reasonable amount of time with a high degree of confidence. Maximum flooding surfaces can be age dated in millions of years before present (Ma) because of their association with important chronostratigraphic species within the maximum flooding surface condensed section. These maximum flooding surfaces, within one third order depositional sequence can be correlated with the Global Cycle Chart of Hardenbol et al., 1998. The (MFS) maximum flooding surfaces within a third order depositional sequence permits the recognition of the lowstand systems tract below the transgressive systems tract and highstand systems tracts above the maximum flooding surface.
The maximum flooding surface is recognized by the bellshaped curve that is formed from the increase and decrease in fossil abundance in the maximum flooding surface condensed section, and the highest gamma and lowest resistivity peaks onthe well log.
The depth of these peaks, converted to seismic time correlates with the regionally continuous, high amplitude seismic reflectors on seismic reflection profiles. The sample by sample paleobathymetric interpretation (Lamb et al., 1986)from fossils permits the recognition of maximum flooding surfaces (Lamb et al., 1987, Wornardt et al., 1990 and Shaffer,1990) at an increase in water depth and the sequence boundary at the decrease in water depth.
The Tordis IOR Project
Authors: Gjerdseth Ann Christin , Faanes Audun , Ramberg Rune 
Published: June 2014

Abstract
The idea of separating oil from water on the sea floor has been an engineer's dream for years. Now, with the Tordis IOR (increased oil recovery) project in the North Sea, Statoil and FMC Technologies with partners1 are making this dream a reality.
The Tordis IOR project realises the first commercial full scale subsea separation installation in the world. Statoil expects to improve the Tordis field's recovery factor from 49 to 55 percent and to extract 35 million barrels of additional oil from the field.
The Tordis field is linked to a Gullfaks C platform via 11 km pipelines. Tordis is a mature field, which produces more and more water and less oil. There is not capacity on the platform to separate the vast amount of water needed to keep Tordis in production. Installation of a subsea separation, boosting and injection (SSBI) system removes the water subsea and enable lowering the well head pressure. This is the main driver for increased oil production even if the reservoir pressures start to drop. This allows Tordis IOR to remain operative an additional 15 -17 years.
Figure 1. Illustration of the subsea separation, boosting and injection (SSBI) station. Separator and desander vessels are illustrated in orange. The multiphase and water injection pumps and leakage detectors are shown in white. Note: Protection structure has been removed for better visibility. At distance the water injection well (upper left) and Pipeline inline manifold (right) can be seen.
The well stream is routed to the SSBI system, where water, sand and hydrocarbons are separated. Oil and gas are pumped through a 2,3 MW multiphase pump1 to the Gullfaks C platform.
The ability to handle sand is important in a mature field IOR project. The de-sanding process for Tordis is therefore designed to handle up to 500 kg sand per day. The separated sand is ejected into the water stream, downstream a 2,3 MW water injection pump1, and injected into the dump reservoir in the Utsira formation through a water injection subsea tree. Statoil has chosen a contract strategy where the SSBI technology development is handled as a normal delivery project, as opposed to a technology development project.

Background
A majority of Statoil's oil and gas production comes from subsea wells. Statoil has therefore been developing subsea processing equipment for more than 10 years, ranging from small, simple pumps to large compressors that are still under development.
The strategy has been to develop the technology incrementally and test it out thoroughly (topside) prior to installation. In this way, Statoil has gradually increased the power of electric motors, the step-out distance from topside facilities, water depths, and the complexity of processing systems. The Tordis field at the Norwegian Continental Shelf has been producing since 1994. It is a subsea development at 200m water depth with tie-in of the production to the Gullfaks C platform in the Tampen area.
LNG FPSO - Solving the supply shortfall
Authors: Iversen Ivin , Hellekleiv Vegard 
Published: June 2014

1. Market
Four years ago liquefaction capacity was considered to be the bottleneck in the LNG market. This unbalance in supply/demand of LNG led to huge investments in new liquefaction capacity and in 2009 and 2010 there is 45 and 30 mtpa respectively of new liquefaction capacity that is scheduled to come on stream. Roughly half of these volumes are not yet sold to a specific customer and HLNG expects that the new capacity, combined with the challenging economic environment, will lead to a slight change in the shortage of liquefaction capacity that we have seen these last years. For the liquefaction projects with planned start-up from 2011 and onwards HLNG expects that there will be severe delays because of the increasing construction costs we have seen the last years, the decrease in oil and gas price and difficulties to obtain financing.
Dynamic Medium Voltage Power Cables
Authors: Worrall P. , Hurtt J. 
Published: June 2014

Abstract
Designing dynamic subsea power cables for various renewable energy applications presents a range of challenges. The four most technologically demanding considerations are: maximum submersible depth, maximum cable capacity/voltage, maximum length before switching from AC to DC transmission and stress limits for dynamic cables.
This paper discusses the cable designs that exist for subsea power links and their benefits and limitations. Particular focus is placed on self-supporting cables, which tolerate gentle flexing through special flexible conductors and screening systems, and proven dielectric insulation systems. The latter enable subsea power cables to operate within water without rigid metallic barriers, such as lead, which would ultimately fail in such a dynamic environment.
To qualify this paper's findings, various data has been collected, cables developed and computer modeling completed in order to validate the conclusions.
There is a significant application under development, Ocean Thermal Energy Conversion (OTEC) plants, which will require dynamic submarine power cables.
It is widely accepted that OTEC is economically viable for plant sizes of more than 100 MWe-net power generation and a plant of this size will require offshore platforms located in water depths of at least 1000 m. At these water depths, a fixed position mooring is not possible so floating platforms and deepwater, dynamic subsea power cables are needed to supply OTEC-generated electricity from platform to shore.
A dynamic power cable of this size and at this water depth has not yet been developed but is required to enable OTEC to become economically viable. Electrical stress limits for dynamic cables will also be discussed, detailing several options, work in progress and their limitations. European wet systems (which are immersed in water), historical data, type tests and reliability type testing will be also referenced.
This paper will significantly advance research and development efforts in dynamic subsea power cable technology that will, in turn, help advance many offshore energy technologies.
Probabilistic System Approach for Risk Based Inspection of FPSO
Authors: Goyet Jean , Rouhan Antoine , Lharidon Emmanuel , Gomes Luiz Antonio Miranda 
Published: June 2014

Abstract
The paper presents a Probabilistic System Approach for Risk Based Inspection (RBI) of FPSOs. This approach is based on a hierarchical model of the hull and uses Bayesian Probabilistic Networks to propagate probabilities from component level to system level. The system approach makes risk analysis more tractable because consequence analysis, including evaluation of direct and indirect consequences of damages to the constituents of the system, may be developed in an exhaustive and systematic way. This approach is new as consequences of failure and damages are usually considered only in setting crudely acceptable failure probabilities at component level. A model example is given for illustration. The paper gives also some insights regarding the owner and class point of views in terms of RBI. This paper explained also how Risk Based Inspection may be developed within the Class regime.

Introduction
Floating Production, Storage and Offloading Units (FPSOs) are specific installations regarding their operating conditions and functions in comparison with classic ships. One of these specificities is the lack of opportunity to dry-dock. Operating FPSOs continuously whilst at the same time safely presents therefore a particular challenge which ultimately led to the development of new Inspection, Maintenance and Repair (IMR) procedures to be applied to FPSOs.
This has encouraged major companies and class societies to adopt Risk Based Inspection (RBI) as the most appropriate procedure for IMR planning of FPSOs. As a consequence, the challenge of both parties during the last decade was to develop and implement RBI methodologies which guarantee profitability and competitiveness of FPSOs while ensuring the required structural integrity level throughout the service life.
Bureau Veritas has developed, since the beginning of this period, RBI methodologies which have then been applied to a significant number of offshore units and can also be used within Class regime. Bureau Veritas thus acquired major knowledge and competency in the field of RBI. In parallel, many major' oil companies decided to implement risk based IMR plans to some of their FPSOs.
Advantages and benefits of RBI are first presented. It is shown how RBI may be a key issue to ensure the success of a Structural Integrity Management program for FPSOs. General principles of RBI are then reminded and a new RBI approach based on system considerations is presented: the approach uses a hierarchical representation of the hull and Bayesian Probabilistic Networks (BPNs) to compute at system level the risks associated to any inspection planning. A model example is given as illustration. The last part of the paper reverts on the challenge of the development of system approaches for RBI.
Stations and Terminals Modeling for Risk and Reliability Assessment
Authors: Gonzalez Jose L. Martinez , Betancourt Enrique Rodriguez , Taylor Irani Perez , Gomez Lorenzo Martinez , Garcia Augusto 
Published: June 2014

Abstract
A hydrocarbon logistics for transmission and distribution involves several facilities that are part of a complex process and associated functions for every single element. In comparison with pipelines, stations and terminals are generally confined to a specific site. Facilities modeling to assess risk and reliability are limited to what occurs within a fence. It is clear stations and terminals have not been subject to the same type of scrutiny as pipelines, however, this is changing and more engineering efforts are required.
Facilities components are covered in several engineering standards, where in many cases every element is considered individually without referring to every possible combination or arrangement – in other words, the user has to assemble a process from different sources. This paper provides a documented process to assemble this jigsaw in a simple way to convince operators and field engineers to use it as a supporting tool. These facilities may have one or more main parallel and support processes and a function, therefore defining a simple way for modeling becomes an important issue. It is important to bear in mind that stations and terminals may have one or more main processes, functions, auxiliary or support processes. Therefore it is important to make as simple as possible the connection between all components and a flow chart. This avoids assumptions by the analyst who has to model what it is actually seeing to obtain results that benefit its decisions.
Models to assess facilities must be based on a consistent hierarchy to establish boundaries between all possible layers in such a way that they can be evaluated independently to include their contribution in risk and reliability. This model is supported by ISO 14224 Petroleum, petrochemical and natural gas industries – Collection and Exchange of Reliability and Data maintenance for Equipment, which is devised for any user of a model's results: industry, business category, installation, unit, section, equipment, subunit and maintainable items.
Delivering Benefits: Approaches, Initiatives and Outcomes
Authors: Shrimpton Mark 
Published: June 2014

Abstract
Industrial benefits planning (IBP) can greatly assist oil companies inseeking to access or operate in frontier regions, including the Arctic. Anumber of ‘good practice’ approaches in the design and implementation ofsuccessful benefits plans have emerged. There is a general need for initiativesin such areas as supplier development, procurement/contracting, education, training and hiring. However, these initiatives, and an IBP program as a whole, will be most effective if the following approaches are adopted: cooperation, collaboration and education; building on existing strengths and capabilities;and seeking a diversified and more sustainable economy.
The Hebron Benefits Plan provides a recent and often innovative example ofpetroleum industry benefits planning. Of particular interest is the emphasis itplaces on: the role of contractors and suppliers, leaving a lasting legacy, andcooperation and collaboration with other stakeholders. In a further benefitsplanning innovation, ExxonMobil Canada Properties states that it will establishand maintain a ‘benefits culture,’ based on the well-established model ofsafety culture, within its organization and all Hebron contracting companies. The Plan presents policies, guidelines and procedures with respect to supplierdevelopment, contracting and procurement, employment and training, research anddevelopment (R&D), diversity, and monitoring and reporting.
Recent initiatives in Greenland illustrate the challenges faced inimplementing more limited benefits initiatives in an Arctic and near-Arcticenvironment. Cairn exploration programs have had Government of Greenlandmandated benefits plans and agreements that have delivered both employment andbusiness to Greenland residents and companies. They have also put in place newinfrastructure, for example related to weather forecasting and oil spillcontingency equipment. However, not all of the employment, business andinfrastructure initiatives have delivered the desired effects.
Newfoundland and Labrador, Canada, is an example of a jurisdiction where, facilitated by well-established IBP processes, the offshore petroleum industryhas delivered substantial and sustainable economic development. This is partlya result of the creation of a new offshore petroleum sector of the economy thatprovides employment and business and makes a major contribution to theProvince's GDP and tax base. Newfoundland and Labrador also now has anexpanding university sector, large numbers of university graduates, a small butthriving R&D community, an increasingly diverse and cosmopolitan urbanculture, and improved external transportation links, all of which can be atleast partly attributed to the oil industry.
Physical Testing Method to Study Ice Keel Strength Limits During a Gouging Process
Authors: Bruce Jim , Piercey Gerry , Macneill Andrew , Phillips Ryan , Derradji Ahmed 
Published: June 2014

Abstract
A test program, undertaken as part of a C-CORE led Joint Industry Program(JIP), was carried out to investigate the limiting strength and failuremechanisms of seabed gouging ice ridge keels. A test frame was designed, fabricated, commissioned and used in the test program. During tests, methodswere developed to build & test large size keel specimens, and surfaceprofile both keel and soil bed before and after test. Testing consisted ofloading the keel with a surcharge force and initiating a horizontal movement ofsoil bed until keel failure was observed. In total, nine keels weremanufactured and tested under a variety of initial confinement pressuresranging from 0 kPa to 75 kPa. Six tests were conducted with a gravel berm andsoil bed and three tests were conducted using a steel (rigid) berm face andgravel soil bed. A summary of the test results and key observations arepresented in this paper.
Oil Spill Detection and Mapping tool in Low Visibility and Arctic Ice Settings
Authors: Eriksen Peter Koldgaard 
Published: June 2014

Abstract
Modern active acoustic multibeam sonars have the last 1.5 years achieved amajor breakthrough in terms of performance, physical size, power consumption, uplink flexibility, processing and not least price. This now allows the tool tobe used in a much wider context during arctic subsea hydro carbonate (Oil/gas)detection, quantification and visualization. As the new generation sonar is soflexible it will easily integrate to any platform, AUV, ROV, Gliders, permanentinstallation, ship borne etc. The multibeam sonar will be capable of monitoringlarger areas and perform various tasks in an arctic oil explorationsetting.
Active acoustics can be used for various applications such as A) Reservoirfault monitoring, a good example of such an event was the Frade field spillNovember last year, under ice this would have been disastrous B) Natural seeps, this is instrumental to monitor during exploration but also during operation ofthe field C) Leakage detection on infra structure, naturally this is of greatconcern to have real time detection of leakages from critical infra structureD) Oil spill response, detection of hydro carbonate suspended in the watercolumn as well as under the ice, on seafloor E) Dispersant mixing efficiency, real time 3D monitoring of the mixing process during application of dispersantF) Major events such as the deep water horizon it is important to be able tomonitor hydro carbonate in the water column Results, Observations, andConclusions: Active acoustic test data will be shown, this will be a mix ofreal offshore data as well as laboratory based data sets. Examples of datarelevant to all the application areas described will be given Significance ofSubject Matter: Obviously those applications are highly relevant for the articexploration area.
River Overflood and Strudel Scour Potential - Smith Bay to Camden Bay, Alaskan Beaufort Sea
Authors: Hearon Greg , Dickins David 
Published: June 2014

Abstract
This paper characterizes the spatial and temporal variability of riveroverflooding on the sea ice and related pipeline and facility siting concernsfor the nearshore region of the Alaskan Beaufort Sea. This phenomenon occurseach spring during a brief period when river discharge precedes the break-up ofthe landfast sea ice. The river water flows on top of the grounded and floatingsea ice, and can spread several kilometers offshore and encompass vast areas. The overflood waters drain through holes and discontinuities in the ice, andcan create large scour depressions on the sea floor when the drainage rate ishigh. These so called " strudel scours" can constitute a significant designconsideration for subsea pipelines.
Airborne Observations of the Distribution, Thickness, and Drift of Different Sea Ice Types and Extreme Ice Features in the Canadian Beaufort Sea
Authors: Haas C. 
Published: June 2014

Abstract
Extensive airborne electromagnetic (EM) ice thickness surveys have beenperformed in April 2009, 2011, and 2012 over the Canadian Beaufort Sea with along-range airplane. These are contributing to the Beaufort RegionalEnvironmental Assessment (BREA) project which gathers ice information inpreparation of a regulatory framework for safe and environmental responsibleoil and gas production. Results show that the location of the multiyear iceedge can be very variable from year to year. Multiyear ice modal thicknessesranged between 3.0 and 3.7 m. The seasonal ice zone had very variable icethicknesses depending on the amount and age of ice formed in coastal polynyasand leads throughout the winter. However, we gathered enough data to show thatmodal first-year ice thicknesses of 2.0 to 2.2 m emerge if profiles are longenough, which can be considered the most representative first-year icethickness estimate in the Canadian Beaufort Sea in April. However, in theseasonal ice zone also regions with heavily deformed ice thicker than 10 m, andoccasional multiyear hummock fields of similar thicknesses occur. Resultssuggest that multiyear hummock fields may not comprise the thickest ice as theyare affected by melt during the summer. Two ice islands had thicknesses between20 and 30 m. Our results suggest a melt rate of ice islands of 10 m per year inthe Southern Beaufort Sea. Ice thickness surveys were complemented by theanalysis of satellite radar data and tracking of ice features by means of GPSbeacons. We demonstrate that all these activities combined comprise a powerfultool for a future Arctic sea ice environmental observatory.