bluuebunny/crossref_metadata_2025_split huggingface dataset:
Heat Transfer and Well Bore Stability Analysis in Hydrate Bearing Zone in the East Sea, South Korea.
Authors: Khurshid Ilyas , Lee Kyung-jae , Bahk Jang-jun , Choe Jonggeun 
Published: July 2010

Abstract
For sustainable development and to feed the world's energy demand continuous supply of fuel resources is of utmost important. Wells drilled in deep waters and permafrost regions contain challenging gas hydrate bearing formations. The oil industry has made certain advancements by drilling and casing gas hydrates bearing formation safely. However, when a well gets deeper gas hydrates start dissociation behind the casing due to heat transfer from the heated mud.
The objective of this study is to analyze the heat transfer to these formations and drilling parameters effecting heat transfer. We developed a wellbore temperature simulator to model the temperature profile in deep formations and to determine the disturbance due to the circulation of the heated mud. We used the range of hydrate dissociation for the wellbore stability analysis to monitor the disturbance caused in gas hydrate bearing formations. The stability analysis shows that a well is in a great danger, if we are drilling deep formations through gas hydrates.
On the basis of wellbore stability analyses we suggest to insulate the outer surface of casing for controlling the heat transfer and dissociation of gas hydrates. The suggested approach is found to be very useful for decreasing heat transfer and consequently reducing gas hydrates dissociation and for stabilizing the well in deep water and permafrost regions.

Introduction
Gas hydrates are the solid crystalline compounds with a well-defined structure that consists of a cage network of water molecules with hydrocarbon mainly methane trapped inside these cages. These hydrates form at certain temperature and pressure conditions. The temperature for gas hydrate formation is above the freezing point of water. These naturally occurring gas hydrates can exist in deep water at relatively shallow depths, below the sea floor or at terrestrial locations within and beneath deep permafrost (Sloan, 1998). Major portion of gas hydrates occur in oceans due to the methanogenesis in sub-ocean sediments. The parameters which affect the formation of gas hydrates in the subsea sediments are temperature, pressure, organic content, water salinity, sediments characteristics and presence of geological features.
Worldwide increasing energy demand, raising energy prices and declining hydrocarbon reserves are increasing the exploitation of oil and gas. For this, a number of Exploration and Production companies are searching for hydrocarbons in terrestrial and harsh environments. These environments lie at low temperature and high pressure conditions which coexist in sediments, making gas and water to form a gas hydrate.
SS: LPG and LNG Offshore Operations: A Marine View on Offshore LNG
Authors: Dekker Johan , van Doorn Jos 
Published: July 2010

Introduction
For several decades LNG is shipped from production areas to the markets. While the loading and unloading of the LNG carriers (LNGCs) was traditionally done at terminals in harbours, we see now a trend to develop floating systems for the liquefaction or regasification of the gas. Both floating liquefaction units deployed for the exploitation of remote offshore gas fields (FLNG) and floating import terminals in the form of Floating Storage and Regasification Units (FSRU) connected via the local gas grids to houses and other users are on the drawing boards. As suitable cryogenic hoses are not yet available and LNGCs are not equipped for tandem offloading, the transfer LNG from FLNG to the LNGC or vice versa is done in a sideto- side mooring arrangement using conventional loading arms. The developer of the facility (further referred to as the owner) has in the operational phase not only the role as operator of the floating LNG plant; he is also harbour master of the LNG terminal. This paper discusses the advantages of considering these operational aspects in the early design stages of the project including the benefits of fast-time and real-time manoeuvring simulations.
For an onshore LNG terminal in a harbour, the operator of the LNG terminal and the harbour master representing the port authority have a different responsibility and relations with the captain of the LNGC and the pilot than in the offshore situation (Figure 1). The operator of the terminal has mainly an economic interest: he wants to ensure a maximum throughput at minimal costs under safe conditions. The harbour master specifies general regulations for port access including e.g. criteria for tug assistance to ensure the safety and availability of the port, while the captain of the LNGC is responsible for the safety of the vessel. The pilot assisting during port entry decides on the safety of the individual manoeuvre under the given conditions. Pilotage is sometimes part of the port authority, but is often also an independent organisation.
Parque das Conchas (BC-10) - Delivery of Deepwater Extended Reach Wells in a Low Fracture Gradient Setting
Authors: Bode Wouter , Hartmann Robin A. , Kenworthy Andrew Malcolm 
Published: July 2010

Abstract
Delivering wells capable of high rate and high ultimate recovery heavy oil is one of the key requirements for success of the Ultra-deepwater Parque das Conchas development in block BC-10, Campos Basin, Brazil.
This paper presents the Parque das Conchas well design to achieve these objectives while tackling key challenges such as shallow reservoir setting below mud line and low fracture gradient setting. It explains fabrication and final preparation efforts followed by a detailed description of execution efforts on the Transocean mobile drilling unit Arctic-1, including performance and learnings by well section.
The Parque das Conchas well design and execution efforts have resulted in several significant results to date:Two of the longest horizontal open hole wells successfully drilled and completed with a full-length alpha and alpha/beta wave gravel pack in Brazil at 1,115 and 1,160m.Top quartile drilling and completion times.Use of the Transocean Arctic-1 with a surface BOP (SBOP) system (Ref 1).Promising well performance from initial production.
For the drilling and completion of the Parque das Conchas wells a combination of existing and new technologies have been used. New technologies include the SBOP system, Spacer Spool, Collapsible 9-5/8" Casing Shoe Joint, 4-1/4" washpipe, tailpipe swell element and premium sand control screens with extensive mesh size QA/QC. Existing technologies are point the bit rotary steerable, Production Screen Tested (PST) drilling fluid, Alpha Wave Gravel Packing, Delayed Filtercake Breakdown system and Fluid Loss Valve (FLV) lower completion isolation.
Well construction results have been excellent to date with the wells delivered on time, within budget and with productivity indices exceeding expectations. Credit goes to a team of people working closely together across disciplines in wells, subsurface, subsea, production operations, HSE, logistics, finance and QA/QC departments, across a global team.

Introduction
The BC-10 block is located in the Campos Basin approximately 120 km southeast from the city of Vitoria off the coast of Brasil. Water depths in this ultra deepwater block range from 1,400 to 2,000 m. Shell is the operator with a 50% interest in a joint venture with Petrobras and ONGC with 35% and 15% interest, respectively. A total of 14 exploration and appraisal wells have been drilled to date, which discovered and appraised 5 oil accumulations in the BC-10 block. In June 2006 field development plans were submitted to the ANP for the development of the Ostra, Abalone and Argonauta-BW and Argonauta-ON fields. Phase 1 of the project comprises the development of the first three fields. Argonauta-ON is planned as part of Phase 2.
Given waterdepths, shallow below mudline hydraustatically pressurized reservoirs and oil properties a combination of long horizontal wells and artificial lift are required to deliver and maintain economic rates.
Ocean Thermal Energy Conversion: Strategies for system integration and implementation using commercially-available components and technology
Authors: Marti Jose A. , Plocek Thomas J. , Laboy M.A. , Ruiz Orlando E. 
Published: July 2010

Abstract
This paper summarizes work conducted in design and development of commercial and demonstration-scale Ocean Thermal Energy Conversion (OTEC) powerplants, and discusses conditions required for commercial implementation, expanding on the information provided by the same authors in the 2009 OTC conference. It documents that commercial OTEC plants for power and potable water generation, developed from commercially available equipment and techniques, are technically feasible today. If favorable financial and market conditions are present, such plants are also economically viable. Key factors for economic viability are long-term financing and stable and favorable interest rates, both of which in turn require a long term commitment for use of the power generated by the plant.

Introduction
Ocean thermal energy conversion (OTEC) is a renewable energy technology that is applicable to most parts of the world's deep oceans in tropical and sub-tropical areas, where the temperature difference between warm surface and the cold deep water is equal or greater than 20 °C (63 °F). In essence, the technology works by recovering the solar energy absorbed by the ocean. Since the temperature differential suffers very little fluctuation, OTEC is able to generate power on a continuous (baseload) basis, as opposed to some renewable technologies, such as solar and wind.
OTEC is most attractive for tropical locations where deep water is available at short distance from shore (less than 6 miles or 10 km), and the marine environment is sufficiently stable to allow operation. [1]. A feature that is particularly attractive is that, if desired, OTEC can be used to co-produce potable water through desalination, in addition to electric power. It is estimated that up to 2 million liters per day (0.5 million gallons per day) can be produced for each megawatt of electricity generated [2]
OTEC requires no fuel. Thus, cost of producing electricity and water is not susceptible to the volatility that affects other energy sources such as petroleum, coal and natural gas. Energy can be generated from purely local sources at a cost that is essentially fixed and predictable. Further, since no fuels or radioactive materials are used, environmental impacts (including greenhouse gas generation) are much less than those of conventional methods of power generation.

Basic Principles
The basic principles of OTEC have been presented in multiple publications (such as [1], [2] and [3] among others). All OTEC plants are heat engines that convert heat into work through the energy gradient between a " source?? and a " sink.?? The basic principle is the same of a steam engine, although in the case of OTEC, the temperature gradient is much smaller. This makes OTEC plants much larger than steam plants of comparable generating capacities.
Perdido Deepwater Export Connection
Authors: Dupre Mike H. , Nelson Don 
Published: July 2010

Abstract
The Perdido Development project, in the Gulf of Mexico, has set several record firsts; including, in 4500 feet of water, the first diverless deep-water tie-in to an existing export line and the deepest tie-in to an in-service pipeline system. It is also the first to employ a unitized foundation and prefabricated jumper spool.
Identifying options for transmission of oil and gas production from the deepwater spar facility to shore required innovative thinking and input from many technical disciplines. The options were limited; Perdido is located in an area with little export infrastructure, and the route to shore covers some of the gulf's most challenging terrain. The closest shallow-water platform is over 140 miles from Perdido.
Analysis revealed that the lowest cost option with the most manageable risk was a tie-in to the existing HOOPS export pipeline, approximately 70 miles north of Perdido. However, connecting to an 18-inch, operating pipeline in deep water provided major engineering challenges.
The project required subsea installation of a piggable wye in the HOOPS pipeline to provide a connection point for Perdido. In a clear break with conventional tie-in projects, an innovative new methodology was developed that enabled the Perdido export connection system to be fabricated in its entirety onshore and reassembled on the pipeline using a reference system to ensure a perfect fit.
The objective was to reduce HOOPS shut-in time and return the pipeline to service as safely and efficiently as possible. However, the connection system also had to meet several other criteria: zero release of hydrocarbons and re-configurable, which would provide the flexibility to serve future connection needs.
Six months after the project's spar production platform was put into place, the Perdido subsea tie-in was installed on the seafloor. HOOPS production was interrupted for 17 days in March 2009 to accommodate the connection. Consistent with Shell's commitment to protecting people and the environment, the work was executed with no safety or environmental incidents.
The ability to connect subsea without a pre-existing connection point is an enabling technology available to the industry as it continues to move into ultra-deep water while executing projects far from existing production transportation infrastructure.

Introduction
The Perdido spar is the world's deepest direct vertical-access spar. Moored in a water depth of 7817 feet with flowlines extending to 9790 feet, it will act as a hub for and enable development of three fields: Great White, Tobago and Silvertip. The Perdido Development is a joint venture between Shell (operator), Chevron and BP. Located in Alaminos Canyon blocks 857, 859 and 815 in the western Gulf of Mexico, it supports subsea wells connected to the spar host facility by a system of flowlines and subsea structures.
Parque das Conchas (BC-10) FPSO Espirito Santo - An Ultra-Deepwater Heavy Oil Surface Host Facility
Authors: Howell Christopher T. , Andring Robert , Wibner Chris , Muirhead Tom , Felderhoff Jean Michel 
Published: July 2010

Abstract
The FPSO Espirito Santo represents an exciting advance in ultra deepwater technology for floating systems. The FPSO, which arrived in Brazil 25 months after project sanction, is moored and operating in 1780 meters of water offshore Brazil in the BC-10 block (Parque das Conchas field development). The FPSO Espirito Santo is owned and operated by a joint venture between SBM Offshore and MISC, and leased to the BC-10 Joint Venture, operated by Shell, with partners Petrobras Brasileiro S.A. (Petrobras) and ONGC Campos Ltda (ONGC).
The Parque das Conchas project presented many challenges to successful execution of the surface host facility. These challenges include the ability to receive, process and offload heavy crude ranging from 16-42 API grade and incorporation of unique design features into the hull to increase environmental protection and prolong the life of the 1975 converted VLCC hull. The water depth of 1780 meters and demands of the complex subsea infrastructure, which relies on continuous surface supplied power and circulated oil at critical stages, required careful consideration during execution. Finally, the selection of Steel Catenary Risers (SCRs) dictated a new design for the riser interface in the turret. The facility represents the first application of SCRs tied back to a turret moored FPSO.
This paper provides a summary of the FPSO Espirito Santo design, fabrication, transportation, installation and start-up. The unique design aspects and technical challenges faced during the project execution phase for FPSO delivery are outlined. Subjects discussed include: execution planning; process facilities; hull and marine work scope; mooring system; and riser/umbilical interfaces with the host.
The methodologies selected for overcoming the key technical challenges are presented. For processing produced oil covering a wide API grade range, including low API grade heavy oil, the use of multiple process trains with input heat is detailed. The hull systems include the use of cargo tank heating for offloading of heavy crude and utilize stabilized crude as ballast to prolong the hull service life. Dedicated hull tanks for subsea flow assurance fluids (methanol and light crude) also form part of the hull design, while sponsons have been incorporated during conversion of the single hull VLCC to provide double sided protection. The turret design required the application of novel concepts to accommodate the interface with SCRs and high voltage swivels to meet the subsea equipment power demands.
SS: Offshore Wind Energy Special Session: Inspection Guidance for Offshore Wind Turbine Facilities
Authors: Sheppard Robert Edward , Puskar Frank , Waldhart Chris 
Published: July 2010

Abstract
With the expected introduction of wind turbine facilities for the generation of electricity to the US Outer Continental Shelf (OCS) waters, there is a need to evaluate how the long term operations of these facilities can be ensured through Integrity Management (IM) activities, particularly inspections. There is a long operational history of IM in the Gulf of Mexico, offshore California and Alaska, and around the world for fixed and floating oil and gas platforms. Both prescriptive and Risk- Based Inspection (RBI) methodologies have been established and implemented. This experience provides a foundation for implementing similar integrity management programs for offshore wind turbine facilities. This paper describes a guidance document developed to assist operators and regulators in developing IM programs for offshore wind farms, the incorporation of existing guidance for subsea structures, above-water structures and access systems, along with guidance from subject matter experts regarding critical inspection areas, inspection techniques, and inspection intervals that are unique to wind turbine facilities. This work was funded by the US Department of the Interior, Minerals Management Service (MMS).

Development Approach
An integrity management program is designed to ensure the safe and efficient operations of a facility over its service life. It is comprised of three primary activities:Inspection activitiesContinuous monitoring activitiesEngineering evaluation and data management
This basic framework has been used extensively with offshore oil and gas platforms worldwide. Coupling this with inspection and monitoring practices unique to wind turbine facilities (both onshore and offshore) provides a basis for developing guidelines for an offshore wind turbine integrity management program.
These guidelines and the approach used in their development are documented in MMS TA&R Project 627, " Inspection Methodologies for Offshore Wind Turbine Facilities?? [1]. Information from regulatory standards, industry recommended practices, and subject matter experts was used to divide a typical offshore wind turbine facility into specific systems and structures with similar inspection scope, frequency and approach. The highlighted critical inspection locations were coupled with practical inspection realities (e.g., what can be accessed and how can areas be inspected) important to developing a successful integrity management program.
This paper provides an overview of the MMS TA&R Project 627 [1] including:Description of a typical offshore wind turbine facilityPotential failure modes and inspection techniquesRecommended integrity management guidelines
Structural Repair at a Production Platform by Means of a Composite Material Patch
Authors: De Marco Meniconi Luiz Claudio , Porciuncula Ivan Neves , McGeorge Dag , Pedersen Arve 
Published: July 2010

Abstract
This paper shows work performed through a Joint Industry Project (JIP), aimed to enable repairs made from composite materials to be applied to metallic structural components of offshore platforms in general and FPSOs in particular. The basic motivation was to provide a repair methodology that would cause a reduced impact to platform operations, particularly in classified areas. The focus on FPSOs derived from the fact that most of them are converted tankers, originally designed for overhauling in suitable docks from time to time. That is no longer possible once they are deployed as floating platforms, intended to stay in place for twenty years or more. An important prerequisite was that the repair procedure had necessarily to have the approval of the Classification Society of the platform. The project was conducted in three phases. The objective of the first phase was to develop a qualification procedure for the repair of relevant defects with adhesive patches and to demonstrate its feasibility with simple examples. Along phase two a Project Recommended Practice for Patch Repair was issued and more qualification tests were performed. Phase three consisted of a practical application of the Recommended Practice, accomplished within Petrobras by a repair at a ballast tank of the production semisubmersible platform P-20, in operation at Campos basin. The repair was accomplished by means of carbon fiber reinforcements within a vinylester matrix. This paper describes the P-20 repair case and the design of the bonded repair. A brief overview is presented of the installation of the repair, quality assurance issues and needs for future follow-up. The experimental and theoretical studies performed in support of the repair trial are briefly described. The successful repair trial demonstrates the utility of bonded repairs in managing the integrity of offshore steel structure assets.

Introduction
This paper shows the result of several years of research aimed to develop a cold repair technology for marine structures based on bonding of composite materials. The main objective was to minimize impact on the operational routine of a floating production platform, even if the repair takes place in a classified area. The work was done by means of a Joint Industrial Project (JIP) coordinated by Det Norske Veritas (DNV). The sponsors of the JIP were Petrobras, Petronas, Statoil, Norsk Hydro, Shell and ConocoPhillips. The role DNV plays on the usage of composite materials in offshore is well known, through the documentation it already produced on the subject. DNV is also the Classification Society of some production platforms in Brazil, making it easier to have the necesssary approval for a field trial of the technology.