bluuebunny/crossref_metadata_2025 huggingface dataset:
SS Gas Hydrate: Prediction of Production Test Performances in Eastern Nankai Trough Methane Hydrate Reservoirs Using 3D Reservoir Model
Authors: Kurihara Masanori , Sato Akihiko , Ouchi Hisanao , Narita Hideo , Ebinuma Takao , Suzuki Kiyofumi , Masuda Yoshihiro , Saeki Tatsuo , Yamamoto Koji , Fujii Tetsuya
Published: July 2010

The Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) is planning to conduct production tests targeting methane hydrate (MH) reservoirs located in the Eastern Nankai Trough. Towards the successful implementation of the production tests, MH21 Research Consortium has been evaluating MH reservoirs located in the Eastern Nankai Trough from the viewpoints of geology, geophysics, petrophysics and reservoir/production engineering. Integrating the results of these studies, we have been attempting to construct 3D reservoir models, which have been used to predict the performances of production tests through numerical simulation. This paper presents how we constructed the 3D MH reservoir models integrating the results of the log interpretation and the 3D seismic data analyses. This paper also discusses how the heterogeneities of reservoirs with a different scale such as a fault, dip and change in permeability and a well location affect the test performances referring to the results of the numerical simulation.

Eastern Nankai Trough MH reservoirs are composed of alternating beds of sand layers and mud layers in turbidite sediments. First, the frames of the geological models for the vicinity of the candidate test wells including the faults were defined rigorously mainly reflecting the 3D seismic interpretation results. The insides of the frames were then divided into multiple grid layers replicating alternating sand and mud layers. The distribution of the properties of each grid layer such as lithology, porosity, permeability and MH saturation were estimated by geostatistical techniques using well log interpretation results as a hard data and seismic attributes (e.g., amplitude and acoustic velocity) as soft data. Finally, the geological models thus constructed were converted to the reservoir models by incorporating overburden and underburden layers and by specifying initial pressure and temperature.

Well production test performances were then predicted through numerical simulation assuming the application of the depressurization method. In addition to the base case run, case studies were conducted to examine the effects of reservoir heterogeneities and of well locations, which revealed that the large scale heterogeneities such as sealing capability and conductivity of faults and formation dip affected the short term production test performances rather than small scale heterogeneities like a small change in permeability. Furthermore, these studies showed the benefit of numerical simulation for the design of a field well test.
SS - Gas Hydrate: Microscale Modelling of Dissociation and Formation of Methane Hydrate in Sediment
Authors: Fukumoto Ayako , Sato Toru , Hirabayashi Shinichiro , Brumby Paul , Kiyono Fumio , Ebinuma Takao , Narita Hideo
Published: July 2010

Methane hydrate is a promising energy resource in the near future. One of the processes of its development in the sub-seabed sediments is depressurisation: pumping-up water through a well depressurises down to the extent lower than the equilibrium, and hydrate dissociates. However, hydrate dissociation is endothermic and temperature may become lower than the equilibrium point near a well and, hence, hydrate reforms. This may cause blockage of gas-water flow in the sediment. In this study, heat and mass transfer in water-gas-sand three-phases was analysed numerically by modelling them using a threedimensional lattice Boltzmann method. Sand grains were assumed to be spherical for simplicity and the dissolution of methane into water through the interface was also analysed. At the same time, volumetric rate of hydrate formation was obtained by comparing the model results with those of measurement.

Introduction

Methane hydrate is an ice-like crystal that consists of water as host cage and gas as guest molecules, and exists widely in the sub-seabed sediments and in the permafrost layer, which are under low temperature and high pressure. It is confirmed that methane hydrate contains methane more than that in the form of gas on the earth and has been paid attention as a new energy resource in recent years. To predict the technical and economical feasibilities of its production process, numerical simulations are necessary. One of the processes of its development in the sub-seabed sediments is depressurisation: pumping-up water through a well depressurises down to the extent lower than the equilibrium, and hydrate dissociates. However, hydrate dissociation is endothermic and temperature may become lower than the equilibrium point near a well and, hence, hydrate reforms. This may cause blockage of gas-water flow in the sediment. Therefore, formation of gas hydrate in the sediment should be understood and modelled numerically for the design of its production system. For modelling hydrate formation, its rate is particularly important.

Therefore, it is necessary to estimate the formation of hydrate and the consequent reduction of permeability accurately to predict the production rate of methane gas. In this study, a small high-pressure cell was filled with fine glass beads, methane gas, and small amount of water, and gas hydrate is formed in it by increasing pressure. The same was simulated by a numerical model. As a result, by comparing the both results, a hydrate formation rate was extracted.
Design Methods in ISO 13628-12 and Implications for Gulf of Mexico SCRs
Authors: Sharma Partha Pratim , Song Ruxin , O'Donnell Jeffrey , Mork Kim J. , Kavanagh William Kieran
Published: July 2010

A new riser code, ISO 13628-12 "Design of Dynamic Risers for Floating Production Installations" has recently been updated as part of an industry JIP and is scheduled for ISO ballot in 2010. Once approved, the new ISO 13628-12 will replace the current edition of API RP 2RD as the Code of Practice for the design of dynamic metallic risers for floating production installations. This paper summarizes the four design methods in draft ISO 13628-12 and investigates their implications on the design of future SCRs. The implication of the new riser design code is illustrated by an example of an SCR design in the Gulf of Mexico. Three of the four design methods allow for certain plastic utilization of the riser cross section, which requires additional considerations for design, analysis, material selection and fabrication. Combined loading code checks with the four different methods are performed and the results are compared. Additional material specific considerations including design stress-strain curve and fabrication requirements are also presented.

Introduction

The design methods in the updated draft ISO 13628-12 reflect an evolutionary progression from working stress design to limit state design. Limit state design ensures a consistent safety level, based on acceptable failure probabilities, with due considerations to the inherent uncertainty in the design loads and resistance to such loads. Typical limit states for deep water riser design application include:–Accidental limit state (ALS)–Ultimate limit state (ULS)–Serviceability limit State (SLS)–Fatigue limit state (FLS)

The ALS is associated with events with an annual probability of less than 10-2 and larger than 10-4, while the ULS corresponds to 100 year return period events or events with 10-2 annual probability. The SLS criteria define the loads during the normal operational conditions and normal temporary events. FLS is an ultimate limit state from accumulated excessive fatigue crack growth or damage under cyclic loading.

The performance criteria for the riser design depend on the specific limit state. For example ULS requires that the riser system must survive the design event with no damage, i.e. remain intact and avoid rupture, but not necessarily be able to operate. For ALS the riser system must survive, and may sustain some damage without any rupture i.e. no release of hydrocarbon is allowed. Typical load cases for strength design of SCR are presented in Table 1.

The paper presents a summary of the design equations to assess the capacity of the pipe. The performance of an 18 inch oil (X70 grade steel) export SCR suspended from a semi-submersible in 2000 m water in the Gulf of Mexico is assessed for ULS and the ALS conditions using combined loading equations for internal overpressure conditions. Potential for buckling due to compression in the touchdown zone (TDZ) is also investigated.
In-Service Mooring Inspection for Mobile Drilling Units
Authors: Hall Anthony David , Trower Alastair Michael
Published: July 2010

As with all ‘high consequence of failure’ systems, MODU mooring systems are subject to regulatory inspection regimes. This involves a combination of visual and mechanical measurement techniques that allow classification authorities to judge the onward suitability of individual mooring components.

Traditionally, MODUs have been required to dock or to tie up in-harbour in order to perform mooring inspection requirements. The resulting loss of day rate has rarely been highlighted as a concern, as downtime is often built in to long term contracts. As the drilling fleet ages, scheduled downtime is getting allocated to more significant hull and topsides issues.

The current economic outlook is driving the drilling industry to look at new ways to reduce bottom-line impact of day to day operations. In 2009, Welaptega Marine provided the ability for Pride International to fulfill compliance driven inspections at sea, during rig moves, whilst the MDU was still under contract.

This work has resulted in a new, beneficial approach to MODU operators worldwide. Compared to traditional inspection techniques this approach has been proven to achieve significant time and cost-savings.

Drilling companies are able to perform inspections that meet class and contractual requirements with minor disruption to drilling and rig move schedules.

This paper presents the following:Project background, industry drivers and technologies utilizedDetailed project report of an in-air mooring system inspection conducted in 2009Inspection Methodologies designed to fit-in with daily operations
Ormen Lange Hot Tap Operations - World Record in Hot Tapping
Authors: Apeland Kjell Edvard , Berge Jan Olav , Opheim Birgit S. , Armstrong Mike
Published: July 2010

Over the last 10 years Statoil has developed subsea remote hot tap technology. The first use of the remote hot tap technology was the Tampen Link hot tap in 2008. The hot tap operation itself was performed diverless; however, the preparatory works including hyperbaric welding of the hot tap tee was performed utilizing saturation divers. The world's deepest hot tap operations on a pressurized pipeline were performed on the Ormen Lange field in the Norwegian Sea in August 2009. Two hot taps were conducted in a water depth of 860 meters. These were carried out to tie-in a new seabed template in the southern part of the Ormen Lange field into existing pipeline infrastructure.

The development of the Pipeline Repair System remote hot tap equipment is a result of targeted R&D effort and extensive qualification work over several years. The hot tap technology enables cost-effective modifications to existing pipeline networks without interfering with the ongoing production. The technology is currently qualified to 1000 meter water depth and enables use of any pre-installed hot tap tees. Further development of the hot tap technology, involving development and construction of a retrofit Tee, is ongoing. This will make remote installation and welding of a Tee onto an unprepared deep water pipeline possible.

This paper will describe experience from the development and testing of the Remote Hot Tap system and give an overview of the offshore operations leading to the completion of the world's deepest hot tap operation.

Introduction

What is a ‘hot tap’?

A ‘Hot Tap’ is the process of breaking into a live pipeline (one in which the product is flowing) without interrupting the production to provide a pipeline branch for possible diversion of the flow in either direction. This is normally done by installing ‘tees’ either during the pipe laying process (pre-installed tees, see figure 1) or by retrofitting branch structures after the pipe is laid (retrofit tees). The process involves cutting the membrane of the ‘mother’ pipe through a valve placed on the branch of the tee, extracting the membrane and cutter and then closing the valve until an external connection is made to facilitate the diversion. Figure 2 shows a typical completed hot tap structure showing the ball valve connected to the branch and the spool off the top of the valve connecting to the appended pipeline.

The potential for this technology is the ability to make cost effective modifications to existing pipeline networks without interfering with the original production.
SS: GIS Applications in Marine Geohazards special session: Developing A GIS Data Model For Seabed Site Surveys
Authors: Turner Gareth , Bell Tom
Published: July 2010

Data acquired from site surveys provide an essential resource to various exploration and production activities, such as field development planning, well positioning, and subsea equipment positioning. For many years, site survey data has been delivered as a Computer-aided Design (CAD) product. As operators move into a Geographic Information Systems (GIS) environment, shortfalls from CAD-based workflows have become obvious. This paper presents a method of managing site survey data based on geo-information management principles and practices. The methodology presented in this paper defines a GIS data model for seabed survey data interpretation that satisfies GIS query, presentation, and data exchange purposes. This paper also defines a standard for GIS seabed survey data deliverables from contractors to operators, including methods and processes to move the model to/from CAD-based applications. The implementation of the data model has proven to be a relative success and allows for a better integration of subsurface applications internally. The results have helped define an efficient contractor-operator data exchange process by eliminating data ambiguity and enabling seamless GIS data transfer.

Results have also produced a more intelligent seabed survey GIS dataset with rules and behaviors capability offered by an ArcGIS Geodatabase embedded into the data model. Use of a standard GIS data model and a standard list of GIS data deliverables required from contractors to operators will allow project teams to fully embrace the power of GIS data integration and allow nearly seamless and lossless movement of CAD/GIS representations of the model.

Introduction

In order to reach maximum potential benefit of data provided from seabed site surveys throughout the E & P lifecylcle (Figure 1), there is a need to ensure that data delivered from survey contractors to operators is done so in a structured, efficient, and consistent manner.
SS: New API Codes: Updates, New Suite of Standards: API RP 2A-WSD, the 23rd Edition
Authors: Zwerneman Farrel , Digre K.A.
Published: July 2010

This paper summarizes the updating of API RP 2A Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms - Working Stress Design - API RP 2A-WSD 21st Edition with Supplements 1, 2, and 3, to a 22nd Edition. That 22nd Edition is planned to be the last edition of API RP 2A-WSD.

API RP 2A was due for a revision. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A complete and thorough review of the document was long overdue. The 21st edition was issued in December 2000, Supplement 1 in December 2002, Supplement 2 in September 2005, and Supplement 3 in October 2007. In addition, API desired to incorporate the content from API Bulletins 2INT-MET, 2INT-DG, and 2INT-EX plus accommodate development and alignment of API Recommended Practices 2SIM, 2MET, 2EQ, and 2GEO with ISO. In the process of making editorial revisions, it became obvious that some technical revisions were also needed.

Background

The design process has matured since platforms were first installed in the late 1940's. Figure 1 shows the evolution of offshore platform design in the Gulf of Mexico that has been based upon a combination of events such as hurricanes, development of standards such as API, and advances in industry practices. The first edition of API RP 2A used for designing fixed offshore platforms was published in 1969. Platforms built prior to this were designed to a wide variety of criteria and fabrication techniques. During the 1970's better application of design practices ensured higher engineering standards, until the first modern platforms began to be installed in the late 1970's using a consistent design recipe then available in RP 2A. Platforms installed since the early 1980's provide a more robust design and incorporate many of the lessons learned during the design, installation and operation of earlier platforms.

The significant events occurring in 2004 and 2005 (Hurricanes Ivan, Katrina, and Rita destroying over 120 platforms and damaging an equal number with most of these platforms being fixed based structures installed prior to 1980) led to the issuing of API Bulletins 2INT-MET, 2INT-DG and 2INT-EX in May 2007 in order to respond quickly to industry's needs. These interim documents, the work in progress on RP 2SIM, the planned alignment of API Recommended Practices with ISO and the fact a new edition to API RP2A had not been issued since December 2000 led to the formation of API Task Group 13, responsible for updating RP 2A, with their first meeting held on 25 October 2007. The TG met seven times between October 2007 and December 2009 with some delay caused by the aftermath of hurricane Ike in 2008. The TG submitted final sections of their draft to API on 8th December 2009. Note, the API RP 2A 22nd edition has not been balloted at the time of this paper's submission.
SS: Fiber Moorings, Recent Experiences and Research: Impact of Splinters on Polyester Rope Strength
Authors: Shu Hongbo , Ridge Isabel Mary Louise
Published: July 2010

Foreign objects such as splinters from broken steel wires or wood decks have been found embedded in polyester mooring ropes during handling. Shell initiated an investigation on the impact of such foreign objects on polyester ropes' strength. The laboratory test program was developed with input from the US regulatory authority, MMS. The results of this investigation indicated that the damage mechanism of such foreign objects in fiber ropes is different from what had been covered by the existing industry guidance on damaged fiber rope assessment. This paper presents the outcomes and insights from this investigation to help improve offshore handling of polyester ropes and to provide guidance on how to mitigate the risk if a foreign object is found in a fiber rope.

Introduction

Prior to regulatory approval for operators to use polyester ropes in US Gulf of Mexico mooring applications, a key concern was the polyester rope's resilience to possible handling damage. To address the concern, Shell led a JIP in 1999-2000 to develop a handling procedure and to demonstrate the viability of implementing the procedure on existing anchor handling vessels (Ref. 1). Since 2000, Shell has used polyester rope based moorings in most deep water and ultra-deep water mobile mooring applications (Ref. 2), as well as in permanent moorings such as the Perdido production platform mooring system.

To reduce the mooring installation time window, in 2006 Shell started to explore the possibility of prelaying polyester mooring lines on the sea floor similar to what they did in Nakika field development with steel mooring lines in 2002. In early 2007, a few polyester inserts with regular 20 µm sand barrier were deployed to the sea floor at a Shell prospect in water depth about 7000ft. One insert was connected into a MODU mooring line. Two inserts were recovered a couple of months later, and tested as part of a program to evaluate the impact of sea floor contact on the rope's integrity and strength. A surprise finding was that a few metal ‘splinters’ had penetrated the braided jacket and lodged into one of the ropes (Figure 1).
Technical Challenges and Success for Deepwater Riser Wet Parking, Recovery and Transfer Installation In Frade Field
Authors: Wang Jun , Radan Ecaterina , Hagen Rune Krister , Bullock Jackson D.
Published: July 2010

As a contingency plan to decouple the Polar Queen installation from the Frade FPSO installation, 18 flexible pipe risers and 4 umbilical risers needed to be wet parked with tight field architecture, high and unpredictable bottom currents at Frade development field in Brazil. After turret FPSO was in place, all of the risers and umbilicals were recovered from 1065 m water depth and transferred to Frade FPSO. The FPSO turret slot arrangement makes the riser pull-in operation very challenging due to the nearby slot separation angle of only 3 degrees. However the entire recovery, transfer and pull-in operation was a success, finishing in 9 days (3 days ahead of schedule) without a single safety incident, or damage to equipment.

This paper will present the highlights of the technical challenges for riser wet park, recovery, transfer and pull-in installation operation from analytical and operational aspects, and how the main challenges (such as wet park curve, anchor clamp chain installation, riser recovery route, transfer depth, and interference risk assessment) were overcame. Heave velocity methodology was introduced in this project and became a key to success in application for the entire operation. Conclusion, recommendations and lessons learned will be made.

Introduction

Frade BV developed the Frade field located in the northern Campos Basin, 122 km offshore in water depth ranging from 1000m to 1,350 m with irregular sea-bottom. This included around an FPSO the installation of 36 flowlines, 18 flexible risers and 17 umbilicals.

Subsea installation activities began in June, 2008, and 36 flowlines had been successfully installed by December 2008. To decouple the FPSO installation from the Polar Queen installation, Chevron decided to wet park all 18 flexible pipe risers and 4 umbilical risers in the Frade Field, and to later recover and transfer to the Frade FPSO when it was in-place.
SS: Multibeam Backscatter - Insights into Marine Geological Processes and Hydrocarbon Seepage
Authors: Orange Daniel L. , Teas Philip A. , Decker John
Published: July 2010

By combining multibeam bathymetry and backscatter with accurately placed piston cores, and integrating these data with 2D multi-channel seismic and high-resolution sub-bottom profiling, we can gain a better understanding of the processes active in a marine basin. In addition on mass transport complexes, basin floor fans, slumps, and faults, we can identify and sample potential hydrocarbon seeps that provide direct samples of a petroleum system. This paper will examine features imaged during a large (400,000 sq. km.) survey carried out in Indonesia in 2006-2008.

Using hull-mounted systems, an average 1000 sq. km. of high resolution (25m bathymetric bin, 5m backscatter pixel) data were acquired per day in water depths from 100 to 3500m. Piston cores accurately placed on seafloor targets using USBL navigation were described visually on the coring vessel, sub-sampled for geochemical analyses, with the remainder of the core preserved for later analysis. Approximately 35% of the cores have been CT scanned, highlighting density differences related to seepage (such as authigenic carbonate and shell fragments), or related to sedimentological features (where higher density sand grains can be distinguished from lower density mud).

The cores, and the targets they analyzed, provide a catalog of anomalous backscatter features that have been ground-truthed to constrain the processes that created the features. Features such as basin floor fans, overbank deposits, upslope climbing mud-rich mega-dunes, sand-rich channel axes, drowned carbonate reefs, mud volcanoes, and chemosynthetic seeps have been sampled throughout the program. This catalog demonstrates that backscatter can be calibrated by cores to specific processes, and thus that multibeam backscatter is a robust tool for constraining geologic processes active in a basin including present-day sediment distribution on the seafloor. Piston cores accurately placed on zones of potential hydrocarbon seepage interpreted based on multibeam backscatter can significantly impact exploration. Specifically, the presence of oil and gas in a basin, and the composition of the hydrocarbons, can dramatically reduce the exploration risk by providing information on source, migration, and maturity.

Introduction

Human beings have been gathering information about the seafloor since they first took to boats. Until the development of acoustic techniques, soundings were taken by lowering a weight to the seafloor (lead line), and marking the length. Acoustic techniques involving a " ping?? of energy sent out, and then received, by a transducer, only became commonplace after World War II (for an excellent discussion on the evolution of seafloor mapping, see Mayer, 2006). The next big leap in seafloor mapping capabilities came in the 1960s.
Seafloor Acoustic Backscatter Measurements With Multibeam Echosounders
Authors: De Moustier Christian
Published: July 2010

This paper is a tutorial on the fundamentals of seafloor acoustic backscatter measurements made with multibeam echosounders. Such measurements are used to infer seafloor geoacoustic properties, including: acoustic impedance contrast at the water/sediment interface, mean sediment grain size, spectral characteristics of the roughness of the water/sediment interface, contributions from subbottom layers or inhomogeneities in the sediment volume.

Introduction

From the 1960s to the mid-1990s, acoustic backscatter imaging of the seafloor was primarily done with towed sidescan sonar systems (e.g. Belderson et al., 1972; Mazel, 1985; Fish and Carr, 1990 & 2001), some of which had bathymetric capabilities (e.g. Blondel and Murton, 1997). Meanwhile, the hull-mounted multibeam echosounder technology has gradually improved since the early 1970s from a purely swath bathymetric survey function to include backscatter imagery (de Moustier, 1988; Lurton, 2002).

Today, most modern swath mapping sonar systems used in seafloor surveying collect swath bathymetry and concurrent seafloor acoustic backscatter data. When processed together, these data can be used for remote sensing of seafloor characteristics, with applications in geotechnical surveys (e.g. offshore drilling and mining, dredging and disposal, subsea cable and pipeline routes), in resource management (e.g. fisheries habitat assessment, coastal zone monitoring), in navigation and homeland security surveys (e.g. harbor entrances, waterways, Q routes), and in basic and applied research (e.g. sonar modeling, seafloor acoustic processes, mine warfare).

In this paper we shall focus on the particular application of multibeam swath mapping sonars to remote sensing of seafloor geoacoustic properties. The development is tutorial in nature and we begin with a short review of the relevant seafloor acoustic backscatter processes. Then, we consider how acoustic backscatter is measured with a multibeam echosounder, and what processing steps are required before inferences may be made about the underlying geoacoustic parameters. Finally, we review various inference and interpretation methods and conclude with cautionary notes on comparison of results from different sonar systems.

Seafloor acoustic backscatter processes

Seafloor remote sensing with multibeam echosounders relies on the acoustic backscatter processes that take place at and below the seafloor. These processes depend on the type and distribution of sediments in the survey area and on the corresponding geoacoustic parameters. Among these parameters, we focus on the acoustic impedance contrast at the interface, the roughness of the seafloor relative to the acoustic wavelength, attenuation and scattering within the sediment volume, and the angular dependence of the bottom backscatter process.
Efficiency And Economy Of Automating Displacements For FPSO Pipe Stress Analysis
Authors: Robleto Robert , Williams Jim
Published: July 2010

Because Floating Production, Storage, and Offloading (FPSO) modules experience significant deflections from wave motion as well as hog/ sag, on board piping must be analyzed to assure that it is suitably designed for high cycle fatigue. This is done by keeping accumulated damage to a value less than 1.0 using the Palmgren-Miner rule. In order to simplify the acceptance criteria, a method must be developed to convert allowable accumulated damage into an allowable stress range that pipe stress engineers are accustomed to evaluating. This is done by combining methods from PD5500, DVN publications and the Fatigue Handbook: Offshore Steel Structures Probabilistic Fracture Mechanics; Tapir 1985.

To consider the effects of deck bending and module sway, displacements must be calculated from the naval architects hull data for every restraint in the pipe stress analysis model. Multiple loading cases require this process to be repeated for each loading case being considered.

Most engineering companies have developed a technique for automating the computation of module and/or deck displacements. These values once computed must be entered into the pipe stress analysis software. This task normally requires 8 to 24 hours per calculation depending on size and complexity of the piping system being analyzed. Since the data has been manually entered it must also be checked, which requires another 4 to 12 hours.

If a method can be found to calculate displacements and then automatically load them into the pipe stress analysis software, significant cost savings can be realized through reduced engineering work hours. On a project requiring 100 calculations, the potential savings using a reduction of 25 hours per calculation will be 2500 hours. This will result in a cost savings of $225,000 using $90/ hour as the cost basis. Savings could range as high as $700,000 on large FPSO's. By using the Caesar II neutral file writer to import/ export input data, it is possible to automate this process. An engineer, after entering the piping geometry into Caesar II and assigning restraints at the applicable nodes, can export a neutral file which can be read into displacement generating software (this is a company proprietary tool) where the displacements and rotations are applied to each restraint node. This enhanced neutral file can be re-imported into Caesar II ready for analysis complete with displacements and rotations. The most complex calculations can be processed in less than 30 minutes. By automating this process it may be possible to reduce FPSO pipe stress analysis time by as much as 40%.
Perdido Development: Subsea and Flowline Systems
Authors: Ju G.T. , Littell Howard Steven , Cook Terry B. , Dupre Mike H. , Clausing Katrina Montrose , Shumilak Edward E. , Schoppa Wade , Blizzard William Allen
Published: July 2010

Perdido is located in the Western Gulf of Mexico in 7,817 feet of water. It is being developed with cutting-edge subsea technologies to mitigate the project's key development challenges, which include extreme water depth, rugged seafloor terrain, low-pressure reservoirs, and aggressive hydrate formation tendency.

This paper provides an overview of the Perdido Development subsea and flowline system and its associated flow assurance strategy. This paper also includes reviews of the design, fabrication, and installation of key subsea equipment such as twophase separators, subsea trees, manifolds, top-tensioned production risers, umbilicals, and flowlines. In particular, the two enabling subsea technologies, subsea boosting system and surface Blow-Out Preventer (BOP) for drilling and completing of subsea wells, are discussed.

Unique features of the Perdido subsea system include:All wells are subsea (wet trees operated by umbilicals) and consist of 22 local Direct Vertical Access (DVA) wells and 12 offset wells.The subsea DVA wells are drilled, completed, and intervened through a single high-pressure drilling/completion riser and a surface BOP with the host rig.All production will flow from manifolds into five subsea boosting systems where gas will flow naturally to the topside facility, while liquids will be pumped using electrical submersible pumps (ESPs).

Introduction

The Perdido Development, jointly developed by Shell, BP, and CVX, includes the Great White, Silvertip, and Tobago fields and is located in the Perdido Basin and Foldbelt, in the Alaminos Canyon Protraction Area. This area is located in the western Gulf of Mexico, 200 miles south of Freeport, only eight miles north of the Mexico maritime border. All three fields are developed with subsea wells tied back to the host, which is a Spar with full offshore processing capabilities and pipelines for export.
SS: Imapct of subsea processing Power distribution: Powering New Frontier Ultra-Deepwater: R&D, Innovation or Evolution?
Authors: Noel Cornelia , Dee Ronald , Vicic John Charles
Published: July 2010

The subsea portion of the oil industry began as small power consumers connected to a bulk power system provider (a topsides host). The growing demand for oil and gas worldwide coupled with the depletion of existing fields is driving production towards deepwater assets further away from the shore or a host facility. Such fields require ultra-reliable bulk long-distance power that will push AC power transmission/distribution (T&D) to its technical limit. The technology challenges that the oil industry will face in realizing economic power supplies for ultra-deepwater require focus in a number of strategic areas. Reconciling these challenges with the continued growth in energy demand (the advent of the Subsea Processing era) highlights the need for a diverse, industrywide approach. For example, some estimates put the power need for subsea -pumping, -compression, - separation and -processing systems to as much as +30 MW (full field development).

The aim of this paper is to review systems that can supply power to the New Frontier Ultra-Deepwater. The focus will be on the identification and evaluation of optimal system(s) for the generation and delivery of electrical power. In tandem with this is a comparison of the three (3) competing power system architectures: local micro-grid power; long-distance AC T&D; long-distance DC T&D (emergent solution). In making this comparison, we considered the key performance indicators (KPIs): cost, efficiency, reliability, potential for ancillary services, and technology readiness level (TRL). The paper concludes with recommendations for future investigations.

Introduction

Subsea pumping and processing technology enables the industry to exploit additional deepwater and/or long offset reserves and accelerate production. The technology include: oil pressure boosting, gas compression, seawater injection, water separation/re-injection, amongst others. Deployment of these technologies depends on a reliable electric power system. The fundamental problem with the supply to, and demand for, electricity is its storage. Once generated, electricity must be delivered and consumed immediately owing to technical difficulties with, and the prohibitively high cost of, storage. In this regard, electricity is perhaps a unique commodity in that the rate of its production must balance the rate with which it is consumed at all times by the end-load.

The power system value chain elements are as follows (see Figure 1): power siting; energy sources; power generation; power transmission; power distribution; end load. Ancillary power system elements include data acquisition/control, energy storage, combined heat and power (CHP), amongst others.
Plate Tectonic Reconstruction of Nova Scotia
Authors: Luheshi Matt , Nunn Keith , Roberts David , Wilson Hamish
Published: July 2010

The Offshore Energy Technical Research (OETR) Association has initiated an industry standard Play Fairway Analysis (PFA) program. This program is intended to serve a pivotal role in stimulating industry interest in exploration of Nova Scotia's offshore petroleum resources by providing explorers with critical information about prospectivity and resource potential to aid in decision making.

The Play Fairway Program was initiated in May 2009 with a workshop including leading academic thinkers from Canada, Morocco and Europe. The workshop concluded that one of the important issues that needed to be addressed, as part of the overall Play Fairway Program, was plate tectonic reconstruction.

The purpose of the Plate Tectonic Reconstruction Project is to provide an integrated 3D model of the crustal structure and evolution of the Nova Scotia continental margin, in space and time, from rifting to spreading. This model will underpin an understanding of early rift and post-rift depositional environments and provide a predictive model for salt deposition and the distribution of Triassic and Early Jurassic source and reservoir rocks. The project includes a number of elements such as acquisition of new refraction data offshore Nova Scotia, reprocessing of refraction data offshore Morocco, reprocessing of long offset multi-channel seismic offshore Nova Scotia, merging and integrated reprocessing of potential fields data, and integrated interpretation of all these data. The integrated interpretation of these data will enable a revised plate reconstruction to be produced, together with a model for the along strike variation of rifting styles, for the Nova Scotia margin.

The tectonic analysis leads to an interpretation that allows for the possibility of an Early Jurassic source rock system offshore Nova Scotia and provides a model for the distribution of such a source rock system. This, in turn, greatly enhances the potential for hydrocarbon prospectivity.

This project is a key part of an extensive integrated PFA for offshore Nova Scotia.
SS FA- Deliquification of an Offshore Oil Well - An Innovative Approach to Overcome Paraffin Plugging
Authors: O'Brien Shawn Patrick , Kiihne Eric , Macias Jose M. , Vita Eric William , Gonzalez Joel A.
Published: July 2010

A deliquification technique has historically proven effective for land-based operations. The objective was to deliquify a deepwater dry-tree oil well with minimal impact to normal offshore operational objectives. The deployment of a production chemical to successfully deliquify the oil well involved the study of typical well deliquification techniques for land based operations which were modified to address deepwater, offshore operations regulatory requirements and system objectives. This application also involved flow restrictions due to paraffin depositions in the tubing.

Typical liquid unloading techniques require system analysis, fluid modeling, deployment planning, and implementation. These techniques were applied to the offshore environment with special attention to deployment and implementation phases due to fluid flow-rate limitations associated with offshore production equipment. Modeling tools were used to identify required velocities to successfully unload the liquid hold up and to better understand expected performance.

This paper will discuss the project planning and processes used to successfully deliquify a flow-restricted liquidloaded deepwater oil well. Modeling data, critical flow-rate limitations of the system, and deliquification process planning are included. Results of this application will be discussed in further detail to help understand requirements of offshore chemicals induced deliquification techniques and lessons learned.

The use of a Flow Improver to remediate liquid loading associated with depleting wells offers another solution to offshore facilities. The modeling and identification of wells near the liquid loaded critical rate can prevent well downtime associated with pressure buildup and coil tubing techniques typically applied. This approach can significantly reduce CAPEX costs associated with artificial lift techniques while maintaining offshore operational objectives in regards to pipeline oil quality and water discharge regulatory requirements.

Introduction

Deliquification Techniques

Deliquification techniques have historically proven effective for land-based operations. Many different techniques have been used in the past. The majority of these techniques involve increasing the gas velocity or lifting the water to reduce liquid loading. Some of the different techniques for reducing liquid loading can be found in Table 1.
The Effects of Large Scale Forgings and Heat Treatment on the Mechanical Performance of Mooring Connectors
Authors: Hughes Paul , Flores William
Published: July 2010

A shackle failure in the Far East in 2007, called into question the integrity of some processes used in the manufacture of longterm mooring systems. This paper reports the results, so far, from a joint First Subsea Ltd and University of Sheffield's Institute for Microstructural and Mechanical Process Engineering (IMMPETUS) research into larger scale metal forging processes and the resulting mechanical properties.

The objective of the Large Scale Forging research project is to more fully understand what happens during the forging process and, in so doing, better characterise the micro structure of forged metals, its relation to Charpy toughness values (CVN), fracture toughness values and the design and integrity of mooring connectors.

Large scale metal forging is a complex, and far less understood process, compared with many other metals treatment techniques. Mooring components need to exhibit high levels of strength and toughness, as well as outstanding fatigue behaviour over an extended period. While the latter relies heavily on established computer modelling techniques, the factors governing strength and toughness are less well understood. The paper reports on the different aspects of the forging process including: chemical composition of the steel material, heat treatment processes, quenching and cooling rates and test procedures. In particular it will focus on the role and importance of heat treatment, cooling rate and geometry of the material on the mechanical performance of the finished forged connector.

Forging trials have been extensively carried out, comparing parameters like soak and quench times as well as cooling rates and durations. The results of the forging trials, so far, has been a better understanding of the optimum conditions for metals forging with respect to chemical composition and the relevance of microstructure due to internal thermo-couples and thermal imaging cameras. In addition, improved testing methodologies have been reviewed together with the development of a heat transfer model used to predict toughness properties along the ingot.

Introduction

Forged metals are widely used for chains, shackles and other mooring line accessories in offshore mooring systems. The failure of a mooring shackle in 2007 called into question the integrity of some processes used in the manufacture of long-term mooring systems. Moreover it highlighted significant gaps in the knowledge of manufacturing large scale forged items and the influence on their mechanical properties.

First Subsea Ltd, The University of Sheffield and Somers Forge Ltd have undertaken a project to identify best practice for the specification and manufacture of large scale forging and heat treatment for its subsea mooring connectors. The project is also intended to have wider implications for other forged metal mooring components such as chains and shackles.
The International Marine Minerals Society
Authors: Verlaan P.
Published: July 2010

The Code for Environmental Management of Marine Mining (the Code) is necessary because there is little national regulation of marine mining, especially beyond the territorial sea, and other than the work by the International Sea Bed Authority in the Area, almost none in Areas Beyond National Jurisdiction (ABNJ).

The Code was adopted in 2001 by the International Marine Minerals Society (IMMS) following extensive and wide-ranging consultation. The Code provides a framework and benchmarks for development and implementation of an environmental program for a marine exploration or extraction site by marine mining companies, and for stakeholders in governments, nongovernmental organizations and communities in evaluating actual and proposed applications of environmental programs at marine mining sites. The Code also assists in meeting the marine mining industry's requirement for regulatory predictability and minimization of risk, including environmental regulations and risks, and in facilitating financial and operational planning.

The Code provides for its periodic review by IMMS with a focus on modifications based on experience with its implementation and in light of developments in the field of marine mining and associated environmental practices, in consultation with the marine mining industry and with other stakeholders in marine mining operations.

The first review of the Code is now in progress. It has been circulated widely with a request for comments in particular with regard to the focus set out above. It was also assessed in the context of other mining codes from e.g., the Minerals Council of Australia, the International Council on Mining and Metals, and the International Seabed Authority, and it was examined under the international law of the sea and international environmental law.

The proposed revised draft Code, reflecting the comments received and the analysis described above, is presented. Input is welcome until 31 May 2010. Its adoption is expected in October 2010. For the foreseeable future, the IMMS Code will be the only international instrument designed specifically to guide environmentally responsible deep sea mining. It is likely to serve as an example when legally binding legislation is eventually introduced.