bluuebunny/crossref_metadata_2025 huggingface dataset:
Delivering Benefits: Approaches, Initiatives and Outcomes
Authors: Shrimpton Mark
Published: June 2014

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

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

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

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

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.
RADARSAT-2 Derived Sea Ice Information for Operations in the Arctic
Authors: Sharma Jayanti , Rabus Bernhard , Ma Andy , Nadeau Christian
Published: June 2014

Synthetic aperture radar (SAR) has been extensively used for the derivationof valuable information regarding sea ice properties and conditions. This workfocuses on the use of RADARSAT-2 ScanSAR Wide images (500×500 km swaths with50×50 meter pixels) to provide sea ice information for operations support inthe Arctic. Our developed processes generate several products that supportnavigation and operations in ice infested waters:Sea ice images, i.e.delineating and mapping sea ice relative to the open water,Seasonal trendcharts of sea ice over an area of interest and,Automated ice featuretracking and pressure zone mapping.

Using the RADARSAT-2 dual-polarization images and automated techniques, seaice maps are generated to identify regions of open water and of sea ice. Fromthe sea ice maps, total ice concentration is derived and combined withhistorical concentration maps. The output seasonal trend charts can be used toassist in monitoring Arctic sea ice extent and sea ice identification to aidwith navigational safety operations. Finally, we develop an automated icefeature tracking that can track moving ice and from which pressure and driftzones are identified. Future work will involve the development of theprediction of movement of ice floes and packs, using the ice feature trackingtechnique as the foundation.
Springs: Subsea Seawater Treatment - Case Study
Authors: Pedenaud Pierre , Hallot Raymond , Skivington Graeme , Riviere Luc Kristian , Anres Stephane Jean
Published: June 2014

New local subsea processing systems will need to be developed to allow remotely located satellite oil fields to be produced economically. One such system treats seawater for injection into the reservoir.

As reservoir waters often contain elevated concentrations of barium or calcium, treatment systems need membranes to remove any sulfates that may form in the seawater before it is injected into the reservoir, in order to avoid severe scaling.

SPRINGS (Subsea PRocess and INjection Gear for Seawater) is a collaboration project between Total, Saipem, Veolia Water and VWS Westgarth. It was initiated in 2007 and aims to provide robust solutions featuring the use of membranes for treating seawater on the sea bed in deepwater areas.

SPRINGS has now reached qualification stage and a first industrial application is planned for 2015.

This paper describes the SPRINGS development project, including an update on the latest progress to date. It presents a specific case study conducted in the Gulf of Guinea which illustrates the commercial and technological advantages, along with the limitations, of deploying this technology for future remote applications.

It compares the conventional field architecture utilized in conjunction with water injection from FPSO topsides with the architecture required for a SPRINGS solution on the ocean floor.

The information provided allows operators to consider an alternative development strategy for the application of membranes to water injection in remote satellite fields.

Introduction

The development of isolated subsea fields, far from existing production centres or from the shore, and sometimes in very harsh environments such as deep offshore, West of Shetlands or the Arctic seas, has led Total E&P to develop new building blocks of innovative subsea processing.

One block required for the development of subsea oilfields is the treatment of seawater for injection (sometimes going as far as desulfation, if the reservoir water contains significant levels of barium or calcium), to maintain pressure and optimize recovery of reserves.
Recommended Practice for Unbonded Flexible Pipe Employing Composite Armour Material
Authors: Yu Liang , Barbosa Neto Teofilo , Kalman Mark
Published: June 2014

This paper presents proposed requirements for qualifying composite reinforcement for the hoop and tensile reinforcement layers of unbonded flexible pipe, and progress towards meeting those requirements by one manufacturer.

Due to lighter weight and resistance to corrosion and fatigue, composite materials are being implemented for the hoop and tensile reinforcement in unbonded flexible pipe. By reducing the weight of the pipe up to 50% or more, riser system and installation top tensions are substantially reduced. The lower weight and tension reduces project CAPEX, installation cost and risk by enabling lighter weight capacity floating production systems and installation vessels.

Currently ISO 13628-2/API 17J Specification for Unbonded Flexible Pipe [1] does not apply to composite reinforcement, largely because of the limited operational experience with composite materials. Proposed requirements to be included in Annex H of API 17B Recommended Practice for Flexible Pipe [2] as guidelines for composite armour, are summarized in the paper. As operational experience is gained, it will be proposed to include these requirements and learnings in a future revision of ISO 13628-2/API 17J. The efforts of one manufacturer to develop and implement a design methodology and qualification program to meet the proposed requirements are presented.

Most flexible pipe manufacturers are in various stages of developing and commercializing unbonded flexible pipe with composite armour. Yet, there has not been agreement in the flexible pipe community on product requirements. Without industry concurrence on requirements, manufacturers can expend significant funds developing and qualifying a design methodology which does not meet target requirements. This paper describes the first effort to obtain industry consensus on target requirements for unbonded flexible pipe with composite armour.
UOE Pipes for Ultradeepwater Application
Authors: Combaud F. Santos , Liessem Andreas , Schroeder Jens Santos , Fluess Peter , Reepmeyer Oskar , Maerten Bernadette , Buirette Christophe
Published: June 2014

Offshore oil & gas construction pipes for deep water are exposed to high collapse pressure, to high axial loads and partly to fatigue in the girth welds. Pipes suitable for this application are characterized by heavy wall thickness, higher strength material, by tighter tolerances and high fracture toughness properties. Looking into water depths of 10,000 ft (3,000 m) and above these properties are becoming increasingly more crucial.

Today the UOE pipe making process is best suited to produce longitudinal welded pipes of the same dimension in large amounts with short deliveries and low costs. Additionally to the UOE forming process generally the DSAW welding is applied in order to accommodate the high productivity requested to take full benefit from the high efficiency of the UOE process. Both fabrication methods have been limited to a wall thickness up to ca. 1.50?? (38.1 mm) wall thickness and the grade API 5 L X-70 to deliver the requested high fracture toughness and tight tolerances.

State of the art plate production, integrated R&D activities between plate supplier and pipe manufacturer create a position where the delivered pipes fulfil the extreme requirement for the ultra deep water business. Tendon pipes with 1.70?? (38.1 mm) wall thickness in X-75 were delivered with the fracture toughness requested, a wall thickness up to 2.0?? (50.8 mm) is possible and material grades higher than X-80 can reach into deeper water without changing the standard design for pipe based tools. This article takes reference to the above mentioned products and provides an outlook what will be available in the near future.

Introduction:

New larger offshore oil & gas fields justifying bigger scale investments and being able to serve larger markets are moving further out into the open sea. Most of the important oil & gas offshore areas are reaching water depths of 6,500 ft (2,000 m) and more. Areas like the Brazilian East Coast, the West Coast of Africa, the eastern part of the Mediterranean Sea, the Atlantic Margin and others are to be named. In these projects pipes are used not only for pipe lines in order to transport the fluids but also as structural components, partly in combination with the use as a liquid transportation tool. The challenges pipes have to withstand in this environment are becoming progressively more severe. Growing collapse pressures, high axial loads and increasingly fatigue loads are some of the most important challenges designers and pipe producers have to create solutions for. Over all beside the technical solution to be created the safe and long term operation is driving very much the economics for these projects which finally is the basis for a positive final investment decision.
Wet Gas Performance of a Low Energy Gamma Ray Multiphase Meter
Authors: Brister Casey Michael
Published: June 2014

There is a perception in the industry that the accuracy of low energy gamma ray multiphase meters suffers in wet gas or high GVF environments. This is generally attributed to the low density of the process flow having a much more reduced effect on the gamma ray beam and thus a reduced overall accuracy of measurement. These perceptions can have a dramatic impact on the cost of installations for monitoring Wet Gas flow where alternatives to multiphase meters can be tens of millions of dollars more expensive.

This paper describes a successful performance test of a 88mm (7?? ID) venturi, low energy gamma ray, multiphase meter at the CEESI wet gas facility in Colorado, USA on 31 October 2012. The test was performed at CEESI, an independent third party test facility which is well known in the industry for its high quality & accurate wet gas flow loop.

The performance test was witnessed by participants from:Exxon Mobil BP Chevron MaerskTullow Oil WoodsideLetton-Hall Group CEESI Test FacilityFramo Engineering Schlumberger

The test envelope for the flow test was in the wet gas region with Gas Volume Fractions (GVF) range from around 97 % to over 99.5 % and a wide range of Water Liquid Ratios (WLR). The number of flow periods in the test matrix was limited due to the requirement to complete the flow test in a single day. Participants were also given the opportunity to propose flow rates for the flow periods run during the day of testing.
New Deep Water Frontiers in the South Atlantic Equatorial Margins
Authors: Mello Marcio Rocha , Takaki Tikae , Fontes Carlos Alberto , Mohriak Webster , Barbanti Silvana Maria , Azambuja Filho Nilo Chagas , Bender Andre A
Published: June 2014

Petroleum exploration along the West African and South American Equatorial Margin has led to important oil discoveries along both margins. Similar geochemical characteristics of these finds suggest analogous petroleum systems with enormous potential in the conjugate margin sedimentary basins. The Jubilee giant oil discovery offshore Ghana has an estimated recoverable reserve of about 600 million barrels. In the area that was once connected to the equatorial West African margin, but is now separated by the Atlantic Ocean, two discoveries have recently been announced. Tullow Oil announced the Zaedyus discovery offshore French Guinea, with 72m net oil pay in turbidite sandstones. Petrobras and BP announced the Pecem discovery in the northern Brazilian margin, with 140m of net pay in 2,129m water depth in the Ceará Basin. These discoveries appear to have a very similar geologic evolution, source rock facies, and oil types suggesting similar petroleum systems. Additionally, the integration of high resolution geochemical data from oils recovered from boreholes offshore the other basins along the South Atlantic Equatorial Margin has revealed four separate source rock systems: 1- an Aptian/Barremian calcareous black shale associated with a lacustrine brackish to saline anoxic environment; 2- a Late Aptian calcareous shale deposited in transitional environments, as indicated by oils found in the Ceará and Potiguar basins; 3- an Albian/Cenomanian/Turonian marine shale corresponding to an anoxic event widespread in the West African salt basins, particularly in the deep water settings of the Ghana and Angola continental margins. Similar oils have also been registered in the Foz do Amazonas Pará-Maranhão basins and in five ultra-deep water accumulations discovered recently (2011–2012) in the Sergipe Basin; 4- Paleocene-Eocene shales deposited in deltaic environments in the Niger Delta, the Amazon Cone, and Pará-Maranhão Basin. This work aims to restore these basins to their previous pre-breakup locations and to support new exploration efforts. Despite similarities shown above, simply matching discoveries in the conjugate margin basins, for example the Tano Basin offshore Ghana, with the Ceará Basin in northern Brazil, does not necessarily yield the entire story that may lead to a successful end. There is a great deal of contrasting sedimentary and structural development peculiarities from basin to basin and margin to margin. The application of a high-resolution petroleum system approach can lead to better exploration models for these basins and provide clues on the best strategy for drilling the new prospects that have been identified in the ultradeepwater regions of the South Atlantic Equatorial Margin.
Understanding the Full Extent of the R&D Capability Within Brazilian Universities
Authors: Dudgeon Christopher , Vahora Shahnawaz , Atie Helene
Published: June 2014

E&P companies in Brazil are required to invest in R&D projects with Brazilian universities as part of the special participation fee. Industry wide, this levy is expected to be cumulatively worth USD 10 Billion by the year 2022 and therefore the need exists for E&P companies to maximise value obtained through these R&D investments by understanding the full extent of the R&D capability within Brazil. A comprehensive and independent analysis of the E&P research capabilities of leading Brazilian R&D institutions has been carried out. The resulting R&D Landscape Map can now help the decision making process by identifying and selecting R&D institutions with the capability and resource capacity to deliver world-class results. Three E&P companies have recently collaborated with a firm of consultants to develop this R&D Landscape Map, a unique undertaking which has never been completed to this level of detail. This paper highlights some of the key results and conclusions from this multi-operator project, which comprised three phases of work. These phases included the development of an international university benchmarking diagnostic, primary research amongst Brazilian universities, and subsequent analysis and benchmarking. In the first phase, seven ‘world-class’ oil and gas research universities were visited in the USA and Europe. The objective of these visits was to create a calibrated diagnostic for assessing world-class excellence for conducting research across three dimensions - quality of working together, quality of resources, and track record. In the second phase, detailed visits were made to 48 shortlisted E&P research departments in Brazil, in order to carry out an independent and comprehensive assessment of their R&D resources, including staff and facilities. Finally, an assessment was made of how well the Brazilian research groups compare to their US/ European counterparts using key performance indicators. Recommendations were made as to how value may be maximised from this huge investment in R&D, for the benefit of all stakeholders including the government, E&P companies, universities and research organisations, and the Brazilian people.

Background

In recent times, pre-salt exploration in Brazil has seen some of the largest and most exciting discoveries in the world. The total reserves discovered are estimated to be anywhere between 70 to 100 billion barrels of oil equivalent. The first oil produced from the pre-salt layer was extracted from the Jubarte field off the southern coast of the State of EspÍrito Santo in September 2008 and production from the pre-salt reserves has been increasing gradually. Currently Brazil is producing 100,000 barrels per day of oil from its deepwater pre-salt fields, but it is targeting a tenfold increase to 1 million barrels per day by 2017 (Beckman, 2011).
Assessment and Mitigation of Low-Toughness Forged Mooring Components for Floating Structures
Authors: Gallagher Dan , Ku Albert
Published: June 2014

The ability to maintain stationkeeping throughout severe environmental loading is critical to the safe operations of permanently moored floating facilities. Failures of forged mooring components have been observed on these facilities and noted by the issuance of multiple safety notices by United States regulatory bodies (U.S. Department of the Interior Safety Alerts No. 259 on 16 January 2008 and No. 296 on 12 May 2011). These alerts highlighted the need for Operators to remain vigilant in ensuring that the mooring components present are of sufficient quality and toughness to prevent the observed failures from occurring in the future. This paper describes a study which includes the following three main components:a survey of existing facilities to determine the extent of forged low-toughness mooring connectors in service,develop a high-level assessment procedure to assess such connectors, andidentify potential mitigation activities.

The main findings of this paper confirm the existence of low fracture toughness connections. Operators, manufacturers and the classification societies have actively pursued improved manufacturing and certification processes which significantly improve the toughness values, which will be demonstrated in this paper. Assessment and mitigation processes are also summarized in this paper which can be employed by operators to reduce the risk exposure from the low toughness mooring components.

1. Introduction

Several incidents involving failure of forged mooring line anchoring system connectors have been observed on permanently moored facilities. Post-failure analyses indicated that manufacturing processes were defective for each case, namely the heat treatment applied at the manufacturer resulted in the material being unable to meet specified Charpy impact energy. Failure to meet this specification indicates a lower material toughness that may adversely affect fitness-for-service. These events led the U.S. Department of the Interior Minerals Management Service Gulf of Mexico OCS Region (MMS) and the U.S. Coast Guard, 8th District (USCG) to issue Safety Alert No. 259 on 16 January, 2008. This alert identified several recommendations including:Operators review mooring component specifications to ensure manufacturing and testing activities provide a product that meets usage demandsOperator specifications will include sufficient Charpy testing to ensure adequate material toughness for componentsOperators review required destructive and non-destructive testing of critical mooring component elementsOperators will review equipment inspection and handling requirements to ensure no damage is induced during transportation or installation

While the safety alert does not impose explicit mitigation for existing mooring systems, it does indicate that a proper understanding of existing mooring system state should be developed and procedures in place to prevent below specification connectors from entering service in the future.
Accurate Measurements of Liquid Condensate Rate With Multiphase Metering Technology Improves Ecological Impact of Well Test in Deepwater Well Offshore Brazil
Authors: Maizeret Pierre David , Theuveny Bertrand C , Essenfeld David , Reid David
Published: June 2014

Separators have a proven track record and are widely used in well testing operations. However, their range of applications is relatively narrow and they can encounter limitations with fluids for which separation is an issue. For example, in wet gas wells, when the liquid volume is small compared to the gas, or the gas and liquid are foaming, it is difficult to separate properly the phases, especially at high flow rates where the retention time in the separator vessel may be too short. Inefficient separation results in wrong measurements, which can not only have significant consequences for the assessment of commerciality of a new field, but also have a negative environmental impact if the burning process is also adversely affected, resulting, for example, in production of black smoke or imperfect burning leading to hydrocarbon discharge in the environment.

This paper describes a well test in a deepwater well offshore Brazil. To be able to accommodate different production scenarios, two separators and a multiphase meter were used to measure the flow rates. During the test, the comparison of the flow rates from the multiphase flow meter and those reported by the separator made possible the identification of some carry-over in the separator at high choke setting. When the choke size was increased, the separator gas rate increased while the liquid rate dropped at the separator, resulting in a very low condensate to gas ratio (CGR). The multiphase meter on the other hand, reported a constant CGR. At the end of the test, the same choke setting was used for a short period of time to confirm the behavior. The same observations could be made on the rates and a small amount of liquid could be seen in the gas flare. The final proof came from the analysis of the downhole samples which confirmed the CGR measured with the multiphase meter.

The consistent results from the multiphase meter make it ideal to validate the flow rate measurements from the reservoir and improve the burning efficiency reducing the HSE risks associated with well test operations.
Risk Assessment Methodology for Flow Assurance Challenges: The Sooner You Look at it, the Better
Authors: Gomez Susana , Pena Jose Luis Henrique , Duenas-Diez Marta Henrique , Merino-Garcia Daniel
Published: June 2014

It is a reality that oil and gas production is moving to areas where Flow Assurance (FA) risks take a prominent role in the success of operations: arctic, ultra-deepwater conditions imply that the pressure-temperature envelope during operation enlarges, leading to greater chances of solid formation; longer distances to processing facilities difficult remediation operations, in case a blockage occurs. More and more decisions, even in early stages of field life, depend on fluid quality and fluid behavior.

To tackle this issue, Repsol has developed a methodology to account for fluid composition and behavior that allows for an integrated view of Flow Assurance risks that is updated from Exploratory to Operation Phases, from high-uncertainty to low-uncertainty periods of field life.

The presentation will describe several field cases where the methodology is applied, to assure flow assurance constraints are considered in all Phases (Exploratory, Development and Operation); special stress is given to cases where alternatives from conventional tools are required to better represent reality, both in terms of solid formation management, and instabilities associated to multiphase flow.

The objective of this work is to highlight, by means of examples, how critical it is to have an integrated view of fluid properties from Exploratory to Operation Phases, and illustrate how it affects decision taking throughout the life of a field.

Introduction

Flow Assurance (FA), as a discipline in the Oil and Gas industry, refers to the analysis of the factors that may affect the flow of oil and gas from the reservoir to the facilities. Figure 1 shows the main challenges that are covered inside of Flow Assurance. FA topics can be divided into problems associated to Solid Formation and Fluid-Dynamics: the former deals with the reduction of productivity associated to the appearance of solids in the production lines, either originated in the hydrocarbon or in the water that is being co-produced; the latter, with the phenomena related to the presence of several continuous phases (hydrocarbon liquid, hydrocarbon vapor and liquid water) and how their interaction may modify the deliverability of a production network.

Being a quite broad discipline, FA comprises phenomena as different as solids plugging the face of the formation, the difficulties to re-start a pipeline after a long shut-down in cold temperatures or emulsion problems in a separator [1, 2]; it is acknowledged that other companies also include Material Integrity (Corrosion) and Sand Control inside Flow Assurance [3, 4], but these are treated in other areas of Production Engineering inside of our company.
A Critical Assessment of the Main Challenges Related to Feasibility Studies, Risk Analysis and Monitoring of Current Offshore Projects in Brazil
Authors: Freigedo Armando , Prates Antonio , Almeida Paulo Octavio
Published: June 2014

The remarkable heating of the Brazilian oil and gas market in recent years has led to a significant boost in the orders of offshore units (such as exploration and production platforms, drilling rigs and various types of support vessels) as well as in the construction of new shipyards or the expansion and modernization of existing ones.

In this context, entrepreneurs (operators, constructors, shipowners and shipyards) as well as governmental funding entities, financial agents and insurance companies, face new challenges, commensurate with the size and complexity of the involved projects, and their degree of innovation. In addition to the specific challenges of a more technical nature, special care should be given to those involving critical business decisions, such as the development and analysis of feasibility studies, validation of assumptions, risk analyses, insurance warranties, contract evaluation, claims and contractual amendments, construction follow-up, and physical and financial progress of projects in the marine and offshore markets.

This paper presents and discusses some important technical and economic aspects involved in these studies and typical difficulties found in projects of greater complexity, comparing and evaluating different approaches and mechanisms, and their suitability to the needs and resources of key stakeholders. The authors intend to contribute to the identification, discussion and dissemination of available best practices, comparing them with those applied in similar contexts, both in the domestic and international scenarios.

The paper also presents suggestions for the improvement and development of methodologies and tools, addressing issues of the content and format of reports and studies, as well as the support of information systems.
Submarine High Voltage Power Transmission: Challenges and Opportunities
Authors: Voight Richard William
Published: June 2014

Seabed equipment is at times deployed to do work on, or add energy to, produced fluids to improve or ensure sustained flow when natural reservoir pressure declines. This hardware includes subsea pumps and compressors. The power required to create a meaningful impact on production with these systems is generally substantial, i.e. several thousand horsepower or more. The power supplied to a fluid is hydraulic and is accommodated through application of rotating machinery (subsea pumps/compressors). This machinery converts electric power into rotational power through an electric motor, which then turns the shaft of the pump/compressor to do the work. Electric power to the subsea equipment from the source is generally transmitted via subsea power cables operating at 50/60 Hz. However, as distance and power levels become ever greater, stable AC power transmission becomes challenging due to excessive reactive power demand within the transmission cables.

What follows is a discussion of the present and anticipated, future power demands associated with subsea pumping and compression systems and the technical issues associated with conventional long distance, high power AC transmission for these applications. Distribution system topology and technology limits will be discussed to address more complex subsea configurations. Furthermore, the focus of submarine cable applications will be limited to Subsea Tiebacks to streamline the subject matter and manage document length.

Finally, solutions (opportunities) are proposed to address the range of issues presented. Solutions include high voltage, low frequency power transmission and high voltage DC power transmission. Reference is also made to this year's Subsea Processing Poster, developed by INTECSEA and published by Offshore Magazine (March 2013). In particular, Graph 4 - Subsea Power Transmission is briefly described to reinforce the aforementioned subject matter and afford readers a fuller understanding of the range and depth of information embedded within the graphic.

Introduction: A Brief History of Submarine Cable Applications

Early Uses

Submarine power cables have been around for more than a century and their application has evolved over the years. Early in life, submarine power cables were used to supply isolated offshore facilities such as lighthouses, infirmary ships, etc. As submarine power cable technology evolved, cables were used to link shore-based power grids across bays, estuaries, rivers, straits [1].

Present Day Uses

Today, submarine cables are used in a variety of applications, including:Carrying power between countries or to remote locationsCarrying power and communications to offshore installations, e.g. oil/gas platforms and ocean science observatories;Transferring power from offshore renewable energy schemes to shore, e.g. wind, wave and tidal systems.

With growing reliance on offshore-based renewable energy schemes, many countries now class submarine power cables as critical infrastructure.
Risk Based in Inspection Applied to a Semi-Submersible Platform
Authors: Daniel Giovani , Silva Mariana , Junior Jorge Souza Pinheiro , Barros Mariana , Krzonkalla Viviane Coelho de Souza , Costa Viviane , dos Santos Luciano Barbosa , Portugal Leonardo Monteiro , Duarte Romulo Leonardo , Nunes J. Arroyo
Published: June 2014

This paper has the main purpose to describe the overview development of a Risk Based Inspection (RBI) methodology applicable to a semisubmersible production platform. Considering news and inventive methodologies for: inspection, acquisition and management of corrosion rates, critical points monitoring, crack propagation studies based on fracture mechanics, structural reliability and a structural database in order to facilitate the structural management in the asset. The data for this paper are based on inspection historical data and hydrodynamic and structural analysis software ABS OSAP System; see reference 8, to provide the structural results of buckling and fatigue analysis. RBI methodology can be applied to semisubmersible platforms in order to rationalize the structure integrity management, as well as optimize the class process maintenance.

The RBI methodology when compared with the traditional method has a lot of advantages as: focusing inspection during the unit life, lower accidents risk, resulting in the reduction of the maintenance cost. The main focus of RBI methodology for semi's concentrate in the reduction of underwater scope of inspection, while increase the importance of focusing critical areas based on the risk assessment and reliablility results.

The proposed paper has a significant contribution to the knowledge on reliability of semisubmersible, as well as the optimization and rationalization of integrity management.

Introduction

The pioneer development of RBI for FPSO has been done during the year of 2001. It has been a result of significant joined efforts from different companies and the first implemented RBI in the world. Since this time, the methodology has been improved and for different purposes ABS also establishes different levels for the methodology and respective requirements. Considering the needs to optimize the conventional survey inspection programs of a semi-submersible Platform, the RBI methodology has been considered a next step of new technology to be invstigated. In order to reach the objective some tasks have been carried out and will be described on this paper.
Dry Tree Semisubmersible Application With Low Heave Motion and VIM Response
Authors: Lambrakos Kostas , Kyoung Johyun , Kim Jangwhan , O'Sullivan James Francis
Published: June 2014

The oil and gas industry has made substantial efforts to find a semisubmersible design with low hull motion response suitable for a dry tree application in deep water. The top tensioned riser (TTR) makes possible both the drilling and completion of production wells, and the support of production risers for vertical access to the producing well over the life of the field, without need for dis-connecting due to environmental events. The application of TTRs requires a hull with both minimal heave response and lateral motion due to the limitation of tensioner stroke in extreme conditions. Conventional semisubmersible designs exhibit motion responses to extreme environmental design events for the central Gulf of Mexico that exceed current generation of riser tensioners stroke limits.

To satisfy the industry demand on the dry tree application, the Heave and VIM Suppressed (HVS) class semisubmersible has been adapted to provide a longer heave natural period while maintaining reduced heave motion and VIM (Vortex Induced Motion) response. The longer heave natural period of the hull accommodates the natural period reduction effect of TTRs. This new adaption of the HVS class of semisubmersible maintains the characteristic features of a column step and tall narrow pontoon. The column step breaks the coherence of vortex shedding along the length of columns. The design transfers the water plane area from the narrower pontoons to the larger diameter columns, which provides greater shallow draft stability for quayside integration of topsides and for ballasting down of the hull at site. The new adaptation increases the heave natural period by adding hydrodynamic mass (added mass) with the inclusion of upper and lower "paired" pontoon plates at the junction of the pontoons and column. These "corner" paired pontoon plates also increase the stiffness of the lower h ull. Model tests for the adapted HVS class of semisubmersible were performed to investigate the in-place hull motion for the Gulf of Mexico environmental conditions, and the measured data were correlated with the numerical tool MLTSIM, which is the in-house time-domain nonlinear 6-Degree of Freedom (DOF) motion analysis program. Also, extensive Computational Fluid Dynamic (CFD) work was done with Technip's proprietary Numerical Wave Basin (NWB) to optimize the design. With the addition of pontoon plates, the HVS class of semisubmersible hull can now be designed to serve either wet or dry tree completions by adjusting hull geometry parameters in order to achieve the desired heave natural period. Note also that the dry tree version of the HVS class of semisubmersible does not use keel joints on the risers making the hull layout and structure similar for wet and dry applications.
Lacustrine Carbonates - For the Purpose of Reservoir Characterization Are They Different?
Authors: Borghi Leonardo , Corbett Patrick W M
Published: June 2014

The reservoir characterisation of lacustrine carbonates is currently challenging, as historically they are not common as major carbonate reservoirs and therefore have been less studied in terms of reservoir characterization. The giant discoveries of the Pre-Salt of the South Atlantic Margin in Brazil have introduced lacustrine carbonates as a major target for exploration and development and are driving new research.

Lacustrine carbonates are formed in lakes which are particularly sensitive to salinity, pH, water level and sediment supply variations. This variability results in a wide range of primary fabric types and associated porosity types, likely formed by the interaction of microbial and chemical processes. Lacustrine grainstones can be formed from spherulites or coquinas and stromatolites and stromatolite bioherms can form cavities and laminated pore systems. Shrub morphologies are found that can form complex pore networks. These fabric types can be affected by a series of diagenetic processes that can both enhance and occlude porosity.

In this paper, we review how porosity in these systems may be characterised in thin sections and using micro-CT and how permeability and resistivity might be determined in the laboratory or by 3-D modelling. We also address how rock types may be determined by analysis of capillary pressure data, to determine relative permeabilities for different rock types. This paper addresses some classical reservoir characterisation issues that are likely to be important in these reservoirs. The approach considered here emphasises an integrated link between petrography, facies analysis (outcrop studies) and porosity description in a petrophysically-based rock typing framework appropriate for geomodelling, upscaling and calibration with dynamic data. This reservoir characterisation workflow methodology is applicable to all carbonates, however, it is recognized that lacustrine carbonates present some special challenges.

Introduction

Carbonate reservoirs are strongly controlled by the nature of the porosity distribution. To understand the main primary controls on porosity we need to go back to basics. There are four main constraints on primary porosity (Moore, 2011):Framework (created within and between the dominant depo-structural features such as stromatolites),Boring (created by various bio-erosional agents),Detrital (intergranular porosity between grainstones or interbedded clastics) andCement (early cements occurring during the earliest phases of diagenesis).

Secondary processes such as karstification (epi- or endokarst) can create new porosity largely through dissolution. Burial can result in the development of microporosity generally in the fine grained carbonate rocks and/or dolomitisation (either through reflux from marine water mixing) or hydrothermal activity often associated with faults and fractures. Lacustrine carbonates can also be associated with exotic clays and minerals through evaporitic influences.