bluuebunny/crossref_metadata_2025 huggingface dataset:
SS: Subsea Well Intervention: Experiences From Operating New Generation Riserlesss Light Well Intervention Units in the North Sea: Challenges and Future Opportunities
Authors: Friedberg Robert , Joessang Siri , Gramstad Bernt , Dalane Snorre
Published: July 2010

Island Offshore has since 2005 been operating riserless well intervention units in the North Sea. The first unit has successfully performed more than 50 well interventions since start April 2005. Another two units have been put into operation in 2009. Both are purpose built based on experiences gathered from the first unit.

The paper will discuss the operating experiences from the first years and how these experiences have influenced two second generation well intervention units..

Further, the presentation will also discuss challenges for this type of service as well as future opportunities

Introduction

Currently there are more than 5000 subsea wells world wide and the number is growing, particular in areas like West Africa and Brazil. In the North Sea there are approx. 1300 subsea wells of which about 500 are located on the Norwegian Continental shelf (NCS). The intervention frequency on subsea completed wells should in theory not deviate substantially from platform wells. Platform wells on average experience an intervention every 4th year, while subsea wells more rarely are being maintained.

There is a significant discrepancy between UOR (ultimate oil recovery) for platform wells vs. subsea completed wells; as from subsea wells UOR < 35%, platforms wells experience >50% UOR (some fields > than 70%, North Sea - Statfjord).

On the Norwegian sector of the North Sea, Statoil during 2009 did totally 25 well interventions utilizing two specialized units for RLWI. The cost benefit by these operations, according to the operator, did result in a net profit of approx. $ 2,5 billion.

During 2010, approx. 40 well interventions are scheduled utilizing the same units, while a third unit will be operating on the UKCS, West of Shetlands, (WoS) extending the operation to even harsher environment.

The Units

During 2009, two of the units, (Island Frontier and Island Wellserver), have been operating on the NCS, while the third unit Island Constructor, has been operating mainly on the UKCS, WoS.
SS: High Pressure Gas Liquid Separation: Scrubber separation - Droplet Entrainment in High Pressure Gas Liquid Separation
Authors: Patruno Luciano Emanuel , Marchetti Jorge Mario , Dorao Carlos Alberto , Jakobsen Hugo Atle , Svendsen Hallvard , Tayebi Davoud
Published: July 2010

This work presents experimental results on droplet entrainment in two different geometries: a stratified liquid film, and a wire flooded by liquid. The experiments feature the system pressure ranging from 900 to 1600 kPa (130 to 220 psia) and surface tension of the system in the lower range of 24 mN/m.

The resulting droplet size distribution after a liquid entrainment event plays a major role in the modeling of the gas liquid scrubbers. When a mesh pad-based separator gets flooded, the high speed gas running throughout the mesh can reentrain the liquid and carry over liquid droplets into the dry gas processing facility.

Conventional correlations for liquid entrainment overestimate the resulting droplet size as they were derived from higher surface tension systems. In addition, a correlation for the entire droplet size distribution is presented.

Introduction

Liquid fragmentation

A description of the interaction between the phases in multiphase flow is of major interest for the oil and gas industry as the presence of droplets in the gas phase can cause erosion and breakdown of equipment. The use of conventional separators at high pressure may not be sufficient since very small droplets may be entrained from liquid films at the walls. The droplet size plays a major role in choosing which separation technology is to be used, as smaller droplets are more difficult to separate than bigger drops, given the smaller ones have low inertia and will follow the gas stream lines.

The droplet separation process normally takes place inside a gas scrubber or separator. In a conventional vertical gas scrubber/separator the gas/liquid mixture typically enters the separator sideways through the inlet vane, then flows upward through a mesh pad or vane pack and finally through the cyclone deck. A schematic drawing of the separator is shown in Fig. 1. A detail description and characterization of a scrubber can be found in Austrheim et al. (2006).

When the gas/liquid mixture enters the separator the major portion of its liquid is removed in the inlet vane. The inlet vane is intended to redistribute and redirect the flow before reaching the mesh pad. The mesh pad is an arrangement of knitted wires that can be placed on top of each other or rolled into a cylindrical structure. The mesh pad is based on separation by droplet impactation to the wires. At low pressures, a mesh pad can give a very high separation efficiency, but when operating at high pressures the efficiency drops. Under high pressure conditions the mesh pad is in practice used as a coalescer and operates at, or above, the flooding point. At the flooding point, the liquid load is higher than the liquid drainage capacity and the gas re-entrains the liquid surrounding the wires (Helsør & Svendsen 2007).
Appraisal And Development-Sanction Challenges For A Small, Stranded, Offshore Heavy-Oil Project In The North Sea
Authors: Coghlan Gerard Philip
Published: July 2010

The Central North Sea Pilot field lies in UK license block 21/27. In 1989 a discovery of heavy oil - by North Sea standards - was made in Eocene sands at a depth of 2700ft TVDSS. Three vertical appraisal wells determined relatively extensive, thin package of turbidite sands (ca.100ft) of limited relief (ca.150 ft). Early flow-testing was constrained by difficulties in sustaining flow because of separation and flaring problems due to low rates, water coning, also sand production. Sampling was problematic with oil properties ranging from 17-22 degAPI and 90-160 cP.

In 1998, a 'prover', horizontal well was completed with an ESP with the intent to prove up sustainable, commercial rates, however this was not achieved, because the oil samples pointed to an oil of much lower quality than expected, 13 degAPI and 1900 cP. Venture Production acquired the field in 2001 as part of a package of acquisitions.

Subsequently all historic data were reviewed and a major effort to move field development forward resulted in the identification of several innovative approaches, centred on a cylindrical hull FPSO to commercialise this geographically stranded (nearest infrastructure 25miles), technically and commercially challenging opportunity. A postulated, developable OIIP of 110 MMstb with a viscosity of ca.100 cP or less was to be targeted by horizontal, hydraulically pumped wells and a waterflood.

Key uncertainties were a) the oil quality distribution and b) the need to recover samples of sufficient volume to allow flow assurance issues (such as calcium napthenate and sodium soap) to be assessed. A further appraisal well was proposed to acquire the necessary, large-volume, representative samples on wireline. An innovative appraisal strategy utilising a geotechnical drillship with much-reduced drillex was planned but the program could not clear all necessary HSE hurdles - resulting in a delay of 1 year and a conventional drilling program (and costs). The appraisal well was drilled in 2007 and determined that oil quality was variable and unpredictable and the necessary minimum OIIP/ reserves for project sanction could not be assured. Follow-up studies resulted in a decision to relinquish the acreage after 20 years of work.

Introduction

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

Work is currently ongoing in the offshore oil & gas industry to develop subsea processing systems supplying multiple electrical consumers, over long step-outs and in deep waters.

To meet the technical challenges of these developments, new subsea electrical power transmission and distribution architectures have to be developed.

This paper gives an overview of possible electrical power transmission and distribution architectures. It addresses the main technical challenges and present limitations, describes the system approach and gives an operator's viewpoint as to the way forward.

Introduction

With today's fields fast becoming depleted and discoveries of easy-to-produce offshore oil & gas resources ever fewer, subsea processing equipment is the focus of an extensive development drive. The results are especially attractive for remote fields, deep waters and tough topside environments such as arctic locations.

As subsea equipment evolves to become increasingly sophisticated and power-intensive (pumps, compressors, processing, and flow assurance systems), there is a growing need for ultra-reliable electrical transmission and distribution systems to power the equipment over long step-outs.

Like subsea applications, electrical architectures are site-dependent and a suitable electrical transmission and distribution architecture has to be defined based on the electrical power needed, the water depth and the tie-back length for each specific oil and gas field development. This paper examines the ins and outs of using AC and DC transmission for subsea applications, overviews the options of electrical power transmission architectures open to the operator depending on the type of oil and gas field to be developed, and addresses the main technical challenges and present limitations. It focuses exclusively on power-intensive subsea applications, and the challenges of transferring large quantities of electrical power (> 1MW) over long distances.
Gas Hydrate System of Shenhu Area, Northern South China Sea:Wire-line Logging, Geochemical Results and Preliminary Resources Estimates
Authors: Wu Nengyou , Yang Shengxiong , Zhang Haiqi , Liang Jinqiang , Wang Hongbin , Lu Jing'an
Published: July 2010

Shenhu Area, one of the most favorable locations for gas hydrates in the north slope of South China Sea, is located in the Pearl River Mouth Basin. The geological setting, temperature and pressure conditions are favorable for the formation of gas hydrate. Analysis of the geochemistry of sediments from large piston cores showed that the sulfate-methane interface (SMI) is from 10 to 27 mbsf in the research area. Methane was the dominant hydrocarbon gas in all gas analyses. The d13CCH4 values of headspace gases from the gravity piston core sediments ranged from -74.3‰ to -46.2‰, with the majority being less than -55‰. It is likely that the methane of gas hydrate originated from in-situ microbial activity.

The drilling recovered high concentrations of hydrate (maximum 26-48%, with the gas composition of >99% CH4) in a disseminated form in foram-rich clay sediments. The wire-line log showed a very distinctive positive anomaly in resistivity and sonic velocity in the interval of the hydrate layer. It was also interesting that the caliper log was smoother through this interval and the density log also showed a small decrease. From the combined well-log and geochemical data, the hydrate-bearing sediments were determined to range from 10 meters to 25 meters in thickness, and to concentrate just above the base of the gas hydrate stability zone (BGHSZ).

The estimate of the total amount of methane trapped in the drilling-confirmed 15 km2 extent of the Shenhu hydrate deposit is about 160×108m3 at a 50% probability. Given the size of this accumulation, the Chinese government and industry have a keen interest in the commercial development potential of the resource.

1. Introduction

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

Nautilus Minerals (Nautilus) is following the lead of the petroleum industry as it strives to tap vast offshore resources. Planning is well underway for the Solwara 1 Project in the Bismarck Sea, Papua New Guinea (PNG) to recover high grade seafloor massive sulphide deposits in 1600 m water depth. The deposit contains an average copper grade >10 times higher than a typical land-based porphyry copper mine. The high grades combined with a relatively small amount of overburden ensure the Solwara 1 Project will have a significantly smaller physical footprint than its land-based counterparts. Offshore minerals production also has the advantage of minimal social disturbance.

Nautilus is dedicated to setting a high environmental and social responsibility standard. Nautilus recognises the importance of transparent and inclusive stakeholder engagement and has taken a proactive approach to involve as many stakeholders as possible. One of the first steps in the permitting process is the preparation of the Environmental Inception Report, which describes the project, its envisaged impacts and the proposed studies for the Environmental Impact Assessment (EIA). Local (PNG-based) and international environmental scientists, anthropologists, NGOs and other experts were involved in the definition of studies conducted for the Solwara 1 EIA and a team of world-leading experts was involved with carrying out the studies, culminating in the preparation of the Environmental Impact Statement (EIS). To ensure transparency, collaborating researchers are free to publish their findings. Following its submission, the EIS was made available for public review and public hearings were held at several locations. The EIS has also undergone a rigorous independent review by PNG government-engaged consultants. Outside the permitting process, Nautilus works alongside government officials to carry out ongoing community consultations. Information dissemination and feedback acquisition has also occurred through the Nautilus website and attendance at a number of international conferences, workshops, and meetings.

This paper will outline the leading edge approach Nautilus has taken in completing the environmental impact statement for the world's first deep seafloor copper-gold mine. In addition, this paper will review the permitting process and the government and stakeholder engagement undertaken as part of Nautilus' desire to " do it right?? in this exciting new industry.
Deepwater Pipeline Installation by Reel-lay Method
Authors: Smith Stuart N. , Clough Tony
Published: July 2010

The reel-lay method is generally the most effective way of installing infield subsea flowlines and risers particularly for sizes up to around 16 inch. This paper describes one of the most advanced reeled pipeline installation vessels in the world, the Seven Oceans, and the variety of pipelines and risers that she has installed including the welding and inspection of high fatigue life SCRs and sour-service flowlines.

The paper goes on to present various recent developments for reeled installation including HFI pipe, PE lined pipe, mechanically lined pipe, clad flowlines and SCRs, high strength pipe, hybrid risers and electrically heated-traced flowlines. These show the continuing attraction of reel-lay for ever more technically demanding work and that for options such as electrically heat-traced flowlines that reeling will be the main vessel based installation method.

1. Introduction

1.1 Vessels

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

Currently the field architecture for most deepwater developments has been dictated by flow assurance constraints due to a reliance on conventional dual flowline loops with riser base gas lifting. Subsea boosting and separation technology will help expand these traditional boundaries and hence facilitate the operation of longer, deeper pipelines transporting fluids with lower temperatures and pressures.

Providing power to remote subsea equipment, which consume power measured in mega watts, will result in power distribution becoming a new driver for field architecture. High voltages will not necessarily be compatible with current power and control technology.

Contractors will therefore have to engineer and deploy large subsea units and integrated power and control umbilicals to match the new field architecture. The reliability of the power distribution system takes on a greater importance. Simply put, loss of electrical power will equal loss of production. How contractors adapt and qualify new technology during the design and installation phases of a project will be a key to its success.

A case study will be presented for boosting a remote deepwater oil field comparing the flowline and umbilical sizes and power requirements for different field layout options. The paper will highlight the implications that the power distribution systems have on the optimization of the field architecture.

Introduction

The start of the twenty first century saw the emergence of a number of large deepwater fields in West Africa, the Gulf of Mexico and South America. The technical risks associated with these developments were numerous but ultimately not insurmountable with flow assurance emerging as one of the main drivers for selection of the field architecture.

Flow assurance is a relatively new engineering discipline to the oil and gas industry, encompassing a broad range of engineering and scientific disciplines. Flow assurance gained particular importance for deepwater fields due the increased energy losses occurring in the riser. Deepwater reservoirs can be characterized with relatively low reservoir pressures and temperatures with viscous fluids with high wax appearance temperatures. The static head losses over 1000 to 2000 m are high and represent a high percentage of the total hydraulic losses and there is an accompanying temperature reduction due to the Joule-Thomson and loss of potential energy effects.
Special Session: Advances In Flexible Riser Technology: Flexible Pipe Design For A High Temperature / Highly Insulated Production Flowline For The North Amethyst Project In The North Atlantic
Authors: Mandeville R.J.R. , Turpin Louie , Searle Shawn , Phillips Gordon
Published: July 2010

The North Amethyst Field is the first of a series of offshore tie-back satellites to the Sea Rose FPSO, located in the greater White Rose Area, approximately 350 km off the east coast of Newfoundland, Canada. Water depths in the field range from 120m to 125m. The North Amethyst Field is operated by Husky Energy Ltd. on behalf of its partners Suncor Ltd. and Nalcor Energy.

The North Amethyst expansion consists of the North Amethyst Drill Centre (NADC), through which the field is developed by a combination of production & water injection wells. The subsea equipment is located in excavated ‘glory holes’, placing the top of the subsea equipment 2-3 m below the surrounding seabed level to protect against iceberg scour. The subsea facilities are tied back to the pre-existing Southern Drill Centre (SDC) in the South Avalon Pool via flexible flowlines.

This paper will provide an overview of the major design and fabrication issues encountered during the engineering, fabrication and installation of the 10?? North Amethyst production flowline.

The challenges associated with designing a high temperature flowline requiring a low thermal conductivity included onbottom stability, material temperature limits, and the design impacts on ancillary equipment (bend restrictors, dropped object protection).

Flowline systems designed for use offshore Newfoundland require a " weak-link?? at the subsea equipment connection to prevent damage to subsea assets and environmental impact due to loss of containment. The " weak-link?? presented a number of design, manufacturing and installation challenges.

The flowline design implications on the installation campaign and schedule is also discussed and the measures taken to mitigate the issues.

Introduction

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

Production operations at the Parque das Conchas (BC-10) development rely on multiple subsea pumps that are powered from the host FPSO. As such, the design and installation of a robust subsea power distribution methodology was an enabling requirement. The limited number of I tubes in the FPSO turret, coupled with a desire to simplify and optimize the subsea layout, provided incentive for the development of a multi-circuit power transmission and distribution system that could be combined with traditional electro-hydraulic control and chemical delivery umbilicals.

The challenges posed by this hybrid umbilical design, specifically the delivered power quality and manufacturability of the umbilicals, was addressed through the development of a cross section incorporating multiple trefoils for power transmission. To achieve the required umbilical lengths, a slim line electrical splice is a key component of the umbilical design program. These high voltage (HV) cables are designed to provide the power for the subsea pumping facilities, whilst not compromising the base functionality of the umbilicals.

In addition, to ensure the mechanical performance of the umbilical in a dynamic application, steel tubes serve a dual purpose as conduits for the hydraulic and chemical services for the subsea fields, as well as provide support for the HV electrical cables. This approach eliminated the need for supplemental strength members or armoring that would typically have been required for the dynamic application of large copper subsea power cables in ultra deep water.

This work resulted in an optimized umbilical and subsea distribution design incorporating both traditional electro hydraulic control elements and multiple HV transmission circuits that can be used as a model for similar subsea developments.

Introduction

The Parque das Conchas (BC-10) development is located in deepwater offshore the Brazilian state of Espirito Santo. The asset is a partnership between Shell Brasil (operator, 50% working interest), Petrobras (35%) and ONGC (35%).

A combination of low reservoir pressures, medium to high viscosity crude, and the ultra deep-water depth at the development site requires the use of subsea boosting to enable production. A key component to enable the boosting system is a high voltage, three phase AC transmission system. While host-to-subsea power transmission is not new technology, traditional options for transmission, such as individual power cables for each motor, or a dedicated power umbilical, could not be applied. This was due to limitations in the number of I-tubes in the turret, and the extreme water depth. These and other design requirements/challenges were accommodated through the inclusion of HV power transmission elements into traditional electro-hydraulic control umbilicals.
Field-Wide Interference Test For Understanding The Hydraulic Communication Between Two Stacked Reservoirs
Authors: Al-quaimi Bandar Ibrahim , Ansah Joseph , Al-Shehab Mahdi Abdulla , Al-Ajmi Fahad Abdullah
Published: July 2010

A field-wide interference test was recently conducted to delineate the hydraulic communication between two large carbonate reservoirs separated by a thick non-reservoir formation. The reservoirs were newly developed with peripheral water injection for pressure support. This initial development stage provided an opportunity to take advantage of the undisturbed state of the two reservoirs during field commissioning to conduct this interference test prior to production. The injection start-up was, therefore, designed to inject into one reservoir while monitoring pressures at various parts of the other reservoir. Several observation wells across the field were designated to record the pressure changes during the initial water injection stage to provide the field coverage. The injection rates were also closely monitored and modified throughout the test period to record the rate of pressure change in the observation wells.

The field was developed with the state-of-the-art permanent downhole monitoring systems (PDHMS) which provided the means for comprehensive monitoring of this field-wide interference test. The test showed some interesting findings within the reservoirs themselves, areas of communication were indentified and the extent of the lateral connectivity was observed. Additionally, the dynamic data acquired during this interference test will complement the static data for building improved geological and engineering models.

This paper describes the test design, implementation and presents the results and findings. The test was concluded but monitoring is continuing utilizing the intelligent field (I-field) infrastructure and the results will, in future, be incorporated into reservoir simulation models for production/injection strategy optimization and accurate field performance forecasting.

Introduction

The field consists of two large carbonate reservoirs, referred to in this paper as Reservoir A and Reservoir B, stacked one on top of the other and separated by a thick non-reservoir formation. The field was produced in the past. Pressure data that were collected from both reservoirs during these past periods were analyzed and showed pressure match between the offset wells in the two reservoirs. The only fact known at that time was that the reservoirs are in hydraulic communication, but the media of the communication and the areas where they communicate were not well identified. The two reservoirs were developed recently using peripheral water injection to support oil and gas production from both reservoirs. The primary concern of the development was that some injected water might migrate from one reservoir into the other and negatively impact the productivity of the producing wells. The key was to understand the communication mechanisms, delineate the areas of communication dynamically, and set the proper plan, to minimize any adverse effects of inter-reservoir communication, to maximize hydrocarbon recovery.1
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

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

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

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

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

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.