bluuebunny/crossref_metadata_2025 huggingface dataset:
Prediction of Wave Impact in Extreme Weather
Authors: Stansberg Carl Trygve , Baarholm Rolf , Berget Kjetil , Phadke Amal C.
Published: July 2010

There is a need for improved analysis and verification tools against wave impact, partly due to updated metocean criteria in various geographical areas, but also due to the complex nature of the problem. Model tests are usually recommended in the final design verification. In this paper, improved engineering methods and procedures in predicting wave impact loads on FPSO's and offshore platforms in severe weather are described. Applications include wave-in-deck on jacket platforms, wave amplification with wave impact on large-volume platforms, green water /bow flare slamming on FPSO, and impact on columns. The resulting theoretical procedures and tools are in particular intended for early stages in the design.

State-of-the-art knowledge is combined with systematic analyses of experimental data. New recommended tools and practical procedures for the fast, accurate and robust prediction of wave impact loads due to random waves are established and validated against model tests. Robust and practical methods are emphasized. Basic physical mechanisms and parameters critical to wave impact are pointed out. Experimental data includes existing data sets as well as new experiments. New engineering software tools are developed. Recommendations on model testing procedures are also given.

Introduction

Hydrodynamic impact loads resulting from random, extreme ocean waves are important factors in the design of ships and offshore structures. This includes extreme global loads such as ringing and whipping, global impact loads on fixed and floating platform type structures, and local impact loads due to green water, bow slamming and wave-in-deck impact forces. An example of the type of practical problems that may occur is the bow flare slamming event that was experienced on the Schiehallion FPSO North of Scotland /1/. The relevance of the wave impact problem is recently also increased due to new metocean criteria being established /2,3/. Because of the strongly nonlinear effects, and limited accuracy or robustness of available theoretical models for such applications, the loads are often estimated by use of model tests in offshore basins. Examples from experiments with structures in extreme waves are shown in Fig. 1.
Special Session : Advances in Flexible Riser Technology: Challenges of Flexible Riser Systems in Shallow Waters
Authors: Hanonge Didier , Luppi Ange
Published: July 2010

While much focus is given to the challenges of designing and manufacturing riser systems for extreme deep waters, the challenges are certainly not less when one tries to push the limit at the other end of the spectrum: in very shallow water. Due to their advantages FPSO's are being used in increasingly shallow waters (less than 50m water depth is current practice in Vietnam now days). This puts real challenges on the mooring and riser designers together with FPSO contractors and forces them to come up with novel configuration designs in particular when the very shallow water is combined with harsh environmental conditions and significant vessel motions. An active collaboration between the mooring and the riser designers is then of upmost importance, and requires validation of the concept at the earliest stage of the project: during FEED studies.

The main challenges reside in the need to accommodate the two extreme positions of the surface floater (Far/Ballasted and Near/loaded) which often result in contradicting requirements. Interference is also a main concern, be it with the hull of the FPSO, the seabed, the free water surface or other risers. Marine growth is also a critical issue as it impacts the riser configuration on the full length. To adequately address all those requirements, novel, generally complex, configurations are needed using combinations of clump weights, tethers, buoyancy elements and rigid or flexible structural members.

This paper will present and discuss the different issues faced when designing flexible riser systems in these very shallow waters and present a number of novel solutions to address those. It will also present some actual field experience on two very shallow water riser systems installed over the last two years and will explain how the designer reached the specific chosen solution.

Introduction

This paper will concentrate on challenges of flexible riser systems design (this is mainly focusing on unbonded flexible pipes but may be fully applied to umbilical) in very shallow waters, typically around 50m water depth.

Unbonded Flexible pipes are key elements for offshore oil & gas production, enabling connection of subsea wellhead to floating platforms in shallow to ultra deep water fields. Design of these risers is a complex and long iterative process; design criteria are well defined in relevant codes and standards (See Ref. [1], [2]).
Offshore Liquefaction of Natural Gas
Authors: Unum Arnfinn Ingar
Published: July 2010

BW Offshore (BWO) has operated 3 gas liquefaction FPSO's in the period 1983-2005, two units in Angola (same field) and one unit in Nigeria.

The units liquefy LPG and partly fractionize the components into a controlled single phase or mixture, and it normally involves pre-treatment in the form of separation, dehydration and dew point control.

Capacities vary between 5,000 bpd and 12,000 bpd of gas mixture.

The vessels used are converted gas carriers, where existing storage systems are utilized.

The vessel sizes are typically 35 meter wide and 220 - 230 meter long with cargo capacity approximately 70 - 75,000 cubic meters.

Usually, some of the boil off is used for fuel, while regasification units are used to keep cargo volumes cold and stable.

Offloading is by flexible hoses held by cranes.

The Angola operations are in relatively benign conditions with normal wind speeds of less than 20 knots, but local thunderstorms and wind gusts up to 75 knots can be experienced. Swell of 15 feet is normal.

The Nigeria operation was in the Niger Delta with benign conditions but significant currents from time to time.

During more than 20 years of operation, no problems of significance have been experienced, but precautions have been implemented for offloading by installing Azimuth thrusters and special procedures. Only one offloading has been missed due to environmental conditions.

Based on the LPG FPSO's operational experience, BWO has developed a more generic design through concept developments and studies. Two of these are described in more detail.

Basically, this design includes higher capacities (250 MMscfd of natural gas), more extensive pretreatment and a design to internationally recognized standards. Otherwise the operational mode and offloading is based on the principles from the operating units. DNV has approved the concept.

Furthermore, BWO has developed a liquefaction FPSO handling LNG. This unit handles between 250 and 300 MMscfd of gas and produces 1.7-2 Mtpa of LNG. Storage capacity of LNG is 180,000 cubic meters and there is room for another 100,000 cubic meter of storage for other hydrocarbons (condensate, potential LPG).

The vessel is 60 meters wide and 350-390 meter long depending on deck space and storage needs, with a Moss type LNG storage system.
Parque das Conchas (BC10): Subsurface Challenges in Developing a Deepwater Shallow Structurally Complex Field.
Authors: Stockwell Leon L. , vanKonijnenburg Jan-Henke , Stewart Greg , Holmes Gunnar , Zambrano Santiago
Published: July 2010

As part of the Parque das Conchas project, located in the BC-10 block offshore Brazil, the structurally complex Cretaceous moderately heavy oil " Ostra?? reservoir is developed in a deepwater, shallow overburden setting. Based on data from a vertical exploration and an appraisal well, the development plan called for completion of six producers with 600-1100m long horizontal sections. The integration of subsurface and drilling data and technology was critical in overcoming numerous challenges encountered during drilling.

Challenges encountered included:The shallow nature of the field (~900 mTVD below mudline) necessitated starting the build-up section near the mud line. Building the 16?? hole to 40º in 550 m TVD proved to be very challenging in the soft Pliocene and Miocene sediments using the original drilling assembly.The 12 1/4?? build-up section was drilled with synthetic-based mud (SBM). Build rates were problematic; Induced fracturing, opening of minimum-stress faults and the presence of high permeability sands resulted in substantial SBM losses.The high net-to-gross (NTG) reservoir model predicted from the vertical well control, and the need for gravel pack sand control, lead to a completion interval design with a straight line well path inclined near 88º for the 9.5?? reservoir section. This philosophy based on the appraisal and exploration data proved too simplistic and changes to the well trajectories were made to account for the formation encountered.

Many aspects of the drilling planning and while-drilling procedures were updated to improve performance and well placement. Mud weights were reduced, drilling fluids modified, and BHA configurations changed to meet the challenges faced while drilling the wells. The basic well design and drilling philosophy was updated to include geo-steering in the reservoir and additional pilot wells were drilled in the field. Advanced technology logging while drilling (LWD) tools (such as the Deep azimuthal resistivity, Imaging, and NMR) were incorporated to optimize the available data and to increase reservoir penetration. The correlation of 2D and 3D seismic data to steering ratios, build angles, rate of penetration, and weight on bit were novel approaches to improve wellpath planning and optimize geosteering. Collaboration of the subsurface and drilling teams lead to significantly improved drilling performance and well placement over the course of the 6 wells drilled to date.
SS: Mooring System Integrity: Phase 2 Mooring Integrity JIP - Summary of Findings
Authors: Brown Martin , Comley Andrew , Eriksen Morten , Williams Ian , Smedley Philip , Bhattacharjee Subir
Published: July 2010

Phase 1 of the Mooring Integrity JIP, as reported at OTC 2005 [2], highlighted a number of important mooring integrity challenges for the offshore industry. To address these challenges phase 2 was launched, which has attracted the support of 38 international participating organisations including Oil Companies, Operators, Design Contractors, Equipment Suppliers, Consultancies and Regulatory Authorities.

This paper presents a summary of some of the finding from the Phase 2 JIP, which has focused on testing, data gathering and improving design guidance. This paper covers the following areas:Formulation of a practical method to estimate wear/corrosion based on calibration with field measurementsFeedback on the break testing of worn mooring componentsThe influence of proof load on fatigue enduranceMaterial compatibility guidanceReview of the effects of Microbiologically Influenced Corrosion (MIC)Guidance on how to monitor station keeping performance and what to do with the data receivedSummary of mooring line failure detection optionsInspection guidance for ROV operators

Phase 2 has continued to bring to the fore the importance of mooring integrity which has led to improved offshore inspection and condition monitoring. This paper presents the steps which have been put in place to improve mooring durability both in terms of design and integrity management, based on the operational experience. This information is thus fed back to designers to improve future systems.

Introduction

Phase 1 of the Noble Denton managed Mooring Integrity JIP highlighted the susceptibility of the moorings on even custom designed Floating Production Systems (FPS's) to a number of degradation mechanisms [1] and [2]. This led to the launching of our phase 2 JIP to try to tackle some of the most pressing issues. Phase 2 has been well received by the industry and the number of participating organisations has increased from 23 in phase 1 to 38 in phase 2.

During the course of the phase 2 JIP a number of high profile mooring failures have continued to take place, see for example [3] and [4]. These problems have illustrated the continuing difficulties of achieving mooring integrity while also, in certain cases, providing vital forensic evidence as to the possible cause of some of the failures. The main subjects that have been studied in phase 2 are outlined in the bullet points in the abstract. It is appreciated that these represent a fairly varied collection of topics, but this was judged to be necessary to tackle the key priority areas of mooring integrity as quickly as possible. It should be noted that at the time of writing the JIP programme is still underway, so this paper represents work in progress to date.
Experience to date and future opportunities for subsea processing in StatoilHydro
Authors: Davies Simon R.H. , Bakke William , Ramberg Rune Mode , Jensen Roger Oen
Published: July 2010

Subsea processing involves one or more combinations of fluid conditioning and pressure boosting of wellstream fluids and water at the seabed. The main benefits of applying subsea processing include increased hydrocarbon recovery and accelerated production, together with reduced CAPEX and OPEX, and HSE benefits.

This paper provides an overview of field operating experience for subsea boosting in the LuFeng field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot and the Tordis fields, including the Tordis restart plans. The paper also describes design and installation of the Tyrihans raw seawater injection and summarises the gas compression technology qualification activities underway for the Gullfaks 2030, Åsgard Minimum Flow and Ormen Lange Pilot projects.

An overview of Statoil's future subsea processing opportunities is then presented and discussed, including new opportunities being assessed at the Norne and Astero and fields.

All aspects of subsea processing are reviewed, including boosting, raw seawater injection, separation, sand handling and produced water reinjection, and subsea gas compression technology. The important role of large scale testing and technology qualification, and close collaboration with key technology suppliers is described, together with a step-wise approach to deploying increasingly complex subsea processing systems in ever more challenging environments. Step out distance, water depth and harshness of the local environment for new fields are all increasing and new, more cost-effective technologies will be need to profitably develop future fields.

It is concluded that subsea processing has already provided positive business upsides, despite certain technical challenges, and Statoil expects to continue a stepwise development and deployment of subsea processing technology in the near and longer term future.

Introduction

Subsea processing involves one or more combinations of fluid conditioning and pressure boosting of wellstream fluids and water (from a reservoir or from the water column) at the seabed. Conditioning can include water removal from hydrocarbons, separation of liquids from gas, separation of sand and other solids from fluids, fluid cooling (or heating) and chemical injection.

There are currently four main types of subsea processing application:Single and multiphase hydrocarbon boostingGas compressionSeparation systems (gas / liquid and liquid / liquid with produced water reinjection)Raw seawater injection
Fit-for-Service Assessment of Deepwater In-Service Low Toughness Mooring Shackles
Authors: Mcmaster Fraser J. , Abadin Jose , Waldhart Chris , Lee Yi-Der , Das Samrat , Greiner Bill
Published: July 2010

Due to a recent mooring shackle failure within the offshore industry, focus has been directed toward existing in-service facilities that have similar manufactured shackles installed in the mooring systems. An in-service deep water facility was identified as having similar mooring components by the same manufacturer that failed in-service. A subsequent assessment of the material properties was undertaken on readily available spare shackles that identified Charpy impact toughness values below the original material specification. Consequently, a fitness-for-service assessment was carried out that included the assessment of the shackle fracture toughness, a finite element analysis of the shackle and associated mooring components, and a deterministic analysis procedure that assessed the structural capacity of the shackle by considering the response of the shackle to the presence of a crack or flaw located at a shackle stress hot spot coupled with a significant return period event. Finally, full-scale structural testing of spare shackles was performed to enable verification of actual shackle load capacity with a flaw located at the shackle stress hot spot.

The focus of this paper is on presenting an overview of the fit-for-service methodology and the results of the structural integrity assessment. While a full quantitative risk assessment of the effect of a low fracture toughness shackle in the mooring system would have been ideal, due to the level of data available and the timeframe required for a probabilistic assessment, it was deemed appropriate to undertake a deterministic assessment of the mooring shackles under realistic scenarios representative of service and severe loads that may accompany the service. The results of the deterministic assessment on an actual in-service deepwater floating facility will be presented. The fit-for-service methodology presented in this paper provides a robust method to assess in-service floating facilities that have been identified or suspected of having below-specification mooring components. It has successfully been applied to a number of Chevron in-service floating facilities in different geographical locations.

Introduction

Following the early failure of a mooring shackle on a new deepwater floating facility, attention has been directed to other new and existing assets that have similar manufactured mooring shackles installed in the mooring system. Additionally, the release of Safety Alert No. 256 from the U.S. Department of the Interior (Minerals Management Service), provided recommendations to operators to review their current specification and testing requirements for mooring systems to ensure that the mooring components are adequate for the proposed or current usage.
Smarter Pipe-Soil Interaction in FE Pipeline Analysis
Authors: Deis R. , De Brier C.
Published: July 2010

Due to unknowns in soil behaviour, a new deep water in-situ system has been designed to measure the interaction forces between the seabed and pipelines in the vertical, axial, and lateral directions. The system was used for the first time in deepwater in 2008. Several lessons were learnt during this deployment and significant modifications of the system were carried-out before mobilisation of the equipment on a second deepwater project in 2009. The paper summarizes the recent developments of the system and presents typical testing procedure and test results with an emphasis on how a better knowledge of the pipe-soil interaction can improve reliability of pipeline design.

Introduction

The understanding of pipe-soil interaction for High Pressure High Temperature (HPHT) pipelines installed in deepwater weak soils is of paramount importance for reliable pipeline design. Considerable advancements have been made recently in the study of pipe-soil interaction at low effective stresses. However, there are still some knowledge gaps and assumptions to be validated (Hill and Jacob, 2008) motivating the need for in-situ measurements. The FUGRO SMARTPIPE® was developed to fulfil this need. The in-situ soil-pipe interaction results allow to investigate the fundamental properties of the deepwater near surface soils such as consolidation rates or pore pressure response during pipe movement. With this knowledge, it is possible to test and calibrate theoretical and empirical models against real pipe behaviour and in-situ (undisturbed) soil conditions.

This paper presents recent developments of the SMARTPIPE® tool following lessons learnt from the first deepwater deployment in 2008. The paper focuses on the main operational and Data Acquisition (DAQ) issues encountered during field work operations and on how these issues where addressed in order to ensure reliable measurements. A description of the system is provided. Main findings following the first deep water deployment (offshore West Africa, 2008) are described including recent system developments. Typical results of the last site investigation (Offshore West Africa, 2009) are presented to illustrate the capabilities of the equipment. Interpretation of test results collected during this project will be presented in a follow-up paper.

System Description

This section provides a brief overview of the system. More detailed information on the system can be found in Jacob and Looijen (2008) and in Hill and Wintgens (2009).
Current Trends and Design Limitations of Subsea Control Hardware
Authors: Beedle Alan , stansfield John
Published: July 2010

The challenges associated with the deployment of subsea hardware used to interface between an umbilical system and subsea production system are greatly compounded when installed in deep and ultra deep water. The challenges are further amplified due to the current trend towards the incorporation of complex integrated foundation structures and the increased robustness of the hardware to account for installation and service loads. Two specific deep water projects are explored within this paper.

Introduction

Umbilicals

Subsea production continues to play an increasing role in the global offshore recovery of oil and gas as extraction moves towards ever deeper water depths and more remote geographical locations. Umbilical systems are critical links in subsea production systems and the impact on hydrocarbon recovery due to total or partial loss of functionality results in a significant loss of revenue for an operator.

An umbilical is a group of fluid conduits (thermoplastic hoses and/or metallic tubes), cables (electrical and fibre optic), power cores either on their own or with combinations of each other, cabled together for flexibility and over-sheathed with an extruded polymer or polypropylene rovings for identification and mechanical protection. Armouring layers can also be added for mechanical strength, impact protection or increased mass for seabed stability or dynamic performance.

Umbilicals can be employed in static or dynamic applications and they are typically used for the control of subsea wells, injection of chemicals, gas lift, data acquisition, telecommunications and electrical power for subsea pumping and separation. Some typical umbilical types are shown in Figure 1.

Umbilical Hardware

Typical items of subsea hardware include Umbilical Termination Assemblies (UTA), Subsea Distribution Units (SDU), Gravity Base Foundation Structures (mudmats), Tether Clamps, Weak Links, Repair Joints and Flying Leads. These hardware designs are typically performed in accordance with DNV Rules for Planning and Execution of Marine Operations(1).
Title Parque das Conchas (BC-10) Subsea Hardware and Artificial Lift Systems - Selection, Challenges and Lessons Learned
Authors: Olijnik Luiz Augusto , La Caze D.A.
Published: July 2010

The ultra-deepwater Parque das Conchas Project, located in the BC-10 block offshore Brazil includes the Ostra, Abalone and Argonauta-BW fields in separate clusters tied back to the FPSO Espirito Santo.

BC-10 is a two-phase project with initial production from Abalone, Ostra and Argonauta-BW. The first phase, now on-stream, includes nine production wells and one gas injection well at water depths around 2,000 meters.

The reservoir characteristics of the first phase of field development dictated the use of six boosting systems on the seabed, four in the Ostra and Abalone fields and two in the Argonauta / B-West field. Each boosting system requires an Electric Submersible Pump (ESP) of 1,500 horsepower providing subsea boosting of up to 2,300psi.

In these ultra-deepwater depths several significant challenges had to be overcome and significant new technology had to be developed to make Parque das Conchas a reality. These include, but are not limited to:The first ultra-deepwater completions deployed through a Surface BOP;A combination of MOBO systems in an artificial lift manifold;The world's deepest subsea MOBO's;First time use of a Heave Compensated Landing System (HCLS) in Brazil;A new world water depth record for subsea hammer operations.

This paper presents the challenges, design, installation and testing of the subsea hardware system, including some of the lessons learned which could benefit future projects in ultra-deep water.

Introduction

Parque das Conchas is located in the BC-10 block offshore Brasil in water depths around 2,000m. Shell Brasil E&P is the operator of the field with a 50% working interest in a joint venture with Petróleo Brasileiro S.A. (Petrobras) and ONGC Campos Ltda. (ONGC) with a 35% and 15% working interests, respectively.

Phase I of the project comprises the subsea development of 3 fields tied back to a centrally located FPSO. In Phase II a fourth field (Argonauta ON) is planned to be tied back (see figure 1).

The subsea hardware installation campaign commenced in Q3-2007 with the deployment of two artificial lift spacer templates and is ongoing at the time of the writing of this paper (Q4-2009).
Field Implementation Of A Real Time Drilling Problem Diagnostic System For Deepwater Exploratory Wells
Authors: Gandelman Roni Abensur , Waldmann Alex Tadeu Almeida , Martins Andre Leibsohn , Teixeira Gleber T. , Aragao Atila Fernando Lima , Rezende Mauricio , de Mari Alexandre
Published: July 2010

This article details the field implementation experience of an in house developed system for drilling problems detection and identification. Starting from real time drilling data (including MWD, PWD and mud logging sources), the system was designed to investigate reasons for deviations in important measured variables (such as downhole and pumping pressures, temperatures, torque and drag, etc.) during drilling operations. Based on a hybrid approach, including multi phase hydraulics and torque & drag modeling, case history matching and specialists knowledge, the system should identify undesirable events, such as influxes, poor solids transport, bit balling, bit wear, drillpipe washouts, hole instabilities among several others.

Field implementation issues includes offshore installations and remote operations from onshore decision support rooms, necessity of team working, requirements for conventional and MPD operations, software calibration and validation challenges and continuous knowledge updating. Examples highlight the benefits on investing in data interpretation and drilling automation technologies for deepwater exploratory scenarios.

Introduction

Deep and ultra deepwater exploratory drilling are very risky and costly operations, in which every effort to guarantee performance and operational safety is welcome. Low frac gradients, abnormal pressures, losses, unstable formations are among the topics which make well design complex and well construction a continuous challenge.

Several exploratory prospects currently ongoing in PETROBRAS faces very narrow or even zero operational windows and well construction will demand non conventional techniques such as MPD or UBD. Figures 1 and 2 show examples about narrow operational windows.
Applications of Multibeam Backscatter: Using Multibeam Echosounder Backscatter to Characterize and Map Seafloor Features in Shallow and Deep Water
Authors: Hewitt Antony T. , Salisbury Richard , Wilson Jerry
Published: July 2010

Recent developments in multibeam echosounder backscatter processing are now included in most commercially available processing software. These tools allow end users to produce properly corrected backscatter mosaics and add more robust qualitative and quantitative discrimination of seabed materials to their seafloor characterizations. This paper reviews backscatter processing and presents some examples that demonstrate the advantages of multibeam backscatter over conventional sidescan sonar. Fully corrected backscatter data increases confidence in interpretations of seabed features, and is an improved baseline data set for implementing automated mapping techniques, which can potentially produce more detailed maps in less time. The corrected backscatter is also more appropriate for integration with sediment samples and subsequent quantitative analysis used in seafloor classification systems. These mapping efforts are of benefit to engineering favorability assessments and other types of seafloor investigations.

Introduction

Both multibeam echosounders and sidescan sonars can be used to collected acoustic backscatter data. Backscatter data is obtained from the reflection of acoustic energy back toward the sonar, where its intensity can be measured. After various corrections are applied, backscatter intensity is essentially a function of the seafloor's physical properties, namely acoustic impedance, roughness (grain-size and small-scale topography), and volume inhomogeneity (variability in the thin layer of sediment penetrated by the acoustic signal). While backscatter from sidescan sonars, developed in the 1950's, has seen wide spread use across many disciplines, a broad base of users is increasingly utilizing the power of multibeam echosounder backscatter for their unique applications. For many years now, fisheries investigators have been utilizing multibeam echosounder backscatter for habitat mapping, and hydrographers have been using it for target detection in shallow water. However, it is only in recent years that it has come into common use in deep-water site investigations for oil field developments. This paper attempts to give a basic review of backscatter processing and presents some examples that demonstrate the advantages of multibeam echosounder backscatter over the more commonly used conventional sidescan sonar imagery.
Qualification of a Semi-Submersible Floating Foundation for Multi-Megawatt Wind Turbines
Authors: Cermelli Christian , Aubault Alexia , Roddier Dominique , McCoy Timothy
Published: July 2010

Recent trends in the wind industry point to the use of increasingly larger and more powerful machines with rated power ranging from 5 to 10MW exclusively designed for offshore use. Floating foundations offer greater flexibility in term of site selection for wind farms, and if properly designed, may result in comparable availability with equivalent offshore turbines on fixed foundations, while reducing the complexity and risks associated with offshore installation.

The WindFloat platform is a semi-submersible platform with three columns fitted with a large horizontal water-entrapment plate at the base. The wind turbine and tower are fitted on one of the columns. The platform is designed to support commercially available multi-megawatt wind turbines with no hardware modification to the turbine. The qualification process followed for the development of a 150MW wind farm offshore Portugal is discussed.

Because of economic constraints, optimization of the platform is essential to achieve project financial targets. A rational and comprehensive process was followed to optimize the system while maintaining the robustness required to survive in the offshore environment. The design process is based on a combination of advanced numerical analysis and scale model experimentation. Full-scale experimentation is ongoing.

Selected design codes and industry standards are applied. The return period of extreme events is adjusted based on experience acquired by the wind industry.

Because of the considerable aerodynamic loads generated by the wind turbine and their effects on platform motion, the ability to solve the combined aerodynamic and hydrodynamic problem is necessary. Additional factors, such as tower dynamics and turbine controls must also be taken into account. Development of a coupled hydro-servo-aero-elastic model constitutes a key element of the qualification process.

Rules for the design of Mobile Offshore Drilling Units are followed to verify platform stability in intact condition, and to ensure that compartmentation is sufficient to withstand damaged conditions with any compartment flooded.

Time-domain coupled analysis of the platform and its mooring system are performed. The hydrodynamic response is also validated with scale model tests.

A four-point mooring configuration is adopted. Reliability considerations are discussed to assess the level of redundancy required in the mooring system, in particular with regards to the one-line damaged condition.

The platform structural design is conducted using applicable offshore codes from several classification societies, as well as extensive finite-element analysis. Structural dynamics is critical to platform design due to the dynamic excitation of the tower and the corresponding loading of the substructure primary members.
API RP 2SIM: Recommended Practice for Structural Integrity Management of Fixed Offshore Platforms
Authors: Defranco Samuel , O'Connor Patrick , Puskar Frank , Bucknell Justin R. , Digre Kris A.
Published: July 2010

API Recommended Practices for the design and operation of GoM platforms have evolved in recent years due to the impact of large hurricanes in the Gulf of Mexico. This evolution of the API offshore practice is based primarily on work performed by the API HEAT Committee, interim API guidelines (e.g., API 2INT-EX), results from updated technology, and the ultimate harmonization of API RP 2A and ISO 19902. This paper summarizes the latest version of the proposed API RP 2SIM (Structural Integrity Management) and clarifies the intent and basis for the proposed revisions to previous draft versions of API RP 2SIM.

Background

API RP 2SIM (RP2SIM) has been the subject of recent papers that clearly explain its overall intent, philosophy, and link to international and existing API practices. In summary, SIM (Structural Integrity Management) is a rational framework for evaluating the integrity of a structure through its entire life cycle. SIM was first incorporated into international practice in the mid-1990s in Draft E of ISO 19902. ISO 19902 was officially published in 2007.

RP2SIM incorporates sections of ISO 19902, API RP 2A 21st Ed. (Section 14 and Section 17) and API 2INT-EX as a basis with a significant expansion in explanation and clarification. RP 2SIM has been organized around the framework of the overall SIM process consisting of Data, Evaluation, Strategy and Program. The main sections of the document are as follows:–Section 1: Introduction, Purpose and Scope–Section 2: Normative References–Section 3: Definitions and Acronyms–Section 4: Structural Integrity Management Process–Section 5: Surveys–Section 6: Damage Evaluation–Section 7: Structural Assessment Process–Section 8: Assessment Criteria and Loads - API 20th Edition and Earlier Platforms–Section 9: Assessment Criteria and Loads - API 21st Edition and Later Platforms–Section 10: Mitigation and/or Risk Reduction–Section 11: Decommissioning

The reader is referred to O'Connor et al. (2005) and Puskar et al. (2006) for further details on each of these sections. RP2SIM will replace the portion of API Bulletin 2INT-EX related to fixed platforms. The original intent of 2INT-EX was an " interim?? guidance document based upon results of the HEAT studies that indicated an assessment was recommended for fixed high consequence L-1 and A-1 structures and floating structures located in the Central Region of the GoM. The Central Region is the location of the largest increase in the estimated extreme hurricane conditions. The " interim?? notation for the EX Bulletin designates that it will be ultimately replaced by other API documents, in this case RP2SIM for fixed platforms. 2INT-EX will be fully replaced once the associated floating structure API documents have been updated to account for assessment, with this work currently underway within API.
SS Metocean / A Synthetic Model for Gulf of Mexico Hurricanes
Authors: Vickery Peter , Wadhera Dhiraj , Stear James
Published: July 2010

This paper describes the development of a synthetic model for Gulf of Mexico hurricanes, for use in establishing design criteria. The model has been derived using atmospheric and historical hurricane data from the 1940's to 2006, and eddy data for the period 1984 through 2006. The influence of sea surface temperature and mixed layer depth on storm intensity is accounted for explicitly. The model is validated by comparing the results of a 100,000-year simulation to historical storm data. Using 300,000 years of storms derived from the model, wind criteria across the Gulf has been estimated for return periods up to 10,000-year, and compared to results from the traditional approach of extrapolating from site-averaged historical data.

This effort represents a step-change in the way hurricane criteria has traditionally been developed by industry. The synthetic hurricane model can improve the stability of hurricane design criteria, and provide more insight to the types of storms which generate rare (1,000- to 10,000-year) site conditions. In addition to offering a more stable basis for hurricane design criteria, the synthetic model also offers the following advantages:Being able to assess the impacts of climate change scenarios such as increasing sea temperature and mixed layer depth, by changing environment parameters and re-generating storms for them.Allowing for a combined hurricane-loop/eddy database, with synthetic storms developed concurrent with synthetic eddies, so that joint hurricane-loop load cases may be better determined.

Introduction

Hurricane design criteria for offshore facilities has traditionally been developed from extrapolations of historical wind, wave and current site data, using a method such as track shifting or site averaging to account for having a limited database and future storm track variability (Toro, et al., 2004). However, industry has long recognized the limitations in the traditional approach in estimating extremes associated with very rare (10,000-year) return periods, and has explored other methods such as deductive modeling to develop improved estimates. Furthermore, the occurrence of very large, powerful storms near a site will affect extremes at the 100-year level calculated using the traditional approach significantly, even with the application of spatial averaging, as was experienced in some parts of the Gulf of Mexico following the addition of hurricanes Ivan, Katrina, Rita and Ike to the historical record. Estimating the potential for combined hurricane-Loop Current eddy (LCE) cases is also problematic, given the even smaller set of LCE data together with an already limited hurricane record. Finally, the traditional approach does not allow for an explicit relation of site extremes back to hurricane climate, making it difficult to project changes in extremes based on changes to the prevailing environment.
Dry versus Wet: An Evaluation of Subsea Tie-Backs and Surface Platform Development Strategies for Nova Scotia
Authors: Dunn Cameron , Rushton Phil
Published: July 2010

The Nova Scotian Offshore has many discovered fields with low quantities of recoverable resources. These marginal fields will need development plans which require lower capital costs than that of standard development. Other areas of the world have also faced similar issues regarding the economics of developing marginal fields. Some of these fields have become economically viable by reducing the cost of the offshore facility and production used to extract and distribute the gas or oil.

This paper presents the results of the evaluation of a case study of a marginal gas field in the Sable Island area of Nova Scotian Offshore. It provides a comparison of the technologies and strategies that would be used to develop the field for a low production rate, including a direct comparison of an exclusively subsea development with that of a minimal Dry Caisson platform development. The comparison includes costs as well as benefits and disadvantages of each development option.

The evaluation results show that for the case study water depth of 40m, the Dry Caisson platform is suitable for use and provides an option for development with a capital cost far lower than the comparable subsea option. Limitations of access, installation considerations and maintenance of both systems are also compared.

Introduction

Currently the Nova Scotian Offshore (NSO) region has many discoveries which could be defined as marginal fields, as shown in Figure 1. Historically, offshore field development for the NSO has used standard large scale and capital intensive infrastructure which would likely be uneconomical for these marginal fields. Minimal platforms and subsea development may provide more cost effective options for future developments.
CO2 injection and storage - qualification of well barriers and adjacent wells
Authors: Vignes Birgit , Enoksen Arne Mikal , Ovesen Monica
Published: July 2010

The Petroleum industry needs a common industry practice related to design of adjacent CO2 injection wells and plugging & abandonment of CO2 injection wells. Adjacent wells are defined in this paper as wells that can be exposed to the injected CO2. A CO2 injection reservoir may be penetrated by a number of adjacent wells that can be potential leakage sources. These wells can be abandoned-, production-, injection- and disposal wells. Adjacent wells can have well integrity issues that can lead to leakage of CO2 to the surroundings. The paper presents some of the potential reservoir- and wellbore- related leakage pathways.

Seismic surveys are performed to verify how the CO2 medium moves within the reservoir. There are identified challenges related to the verification methods of the structural integrity and how the CO2 medium is spread within the CO2 injected reservoir. This can have an impact with regards to the well integrity and degradation of the construction of the adjacent wells.

Carbon dioxide can occur in the liquid, solid or gas phase depending on temperature and pressure. When the pressure containment of a well is lost, the carbon dioxide can have phase changes which can lead to very low temperatures in the wellbore. This paper presents the challenges related to qualification and testing of well barrier elements related to low temperatures and the exposed medium.

The paper illustrates the industry need to further consentrate on well integrity related to CO2 injection wells as well as to the adjacent wells. The control of barrier status is a crucial HSE factor to avoid major incidents caused by i.e. unintentional leaks and well control situations. Knowledge of well integrity status at all times enables the companies to take the right actions in a proactive manner and thereby prevent incidents.
Tandem Transfer of LNG - Interface with the Operator
Authors: Cox Phillip John , Jeanneau Eric , Eidem Johan
Published: July 2010

Tandem transfer of crude oil and condensate in dynamic marine conditions has a long history with much accrued experience. Initial systems relied simply on a hawser connection, which was subsequently improved with the advent of Dynamic Positioning Systems.

The new requirement to transfer LNG in true dynamic conditions between two very large floating structures, whilst respecting the stringent rules governing the safety of such operations, has led to the design, testing and qualification of a new heavy duty transfer system, known as the Amplitude-LNG Loading System (ALLS).

The transfer of produced products, mainly LNG but also LPGs and condensate, has to proceed on a regular and repeatable basis, with 2 of the main criteria being:Continuous production and operation of the FLNG over a 20 to 30 year periodProject monetization linked to LNG-C rotations

To ensure that these criteria can live in harmony the LNG transfer system must ensure that the correct volumes of LNG can be safely and efficiently offloaded from the FLNG to the LNG-C whilst minimising the turn around time of the carrier.

The ALLS incorporates a custom built Constant Position Monitoring System (CPMS) which can ultimately be integrated into the DP system of the LNG-C and / or the FLNG, and may eventually lead to on-site operations without the need for a hawser link. However full analysis of the project specific conditions will be required prior to taking such an important step.

An offshore LNG project is a multi-billion dollar investment, from subsea drilling and development, through construction of the floating process & liquefaction plant (FSPO-FLNG) to operation of a fleet of LNG carriers, some of which may be dedicated on a project basis. As such the reliability and repeatability of the CPMS /

DP couple is a key element in the overall functioning of the offshore LNG transfer system, as any emergency shut down and prolonged interruption in fluid transfer can have significant consequences on the functioning of the FLNG and its capacity limits for storage.

This paper will investigate the history and evolution of tandem transfer in open sea conditions, elaborate on these issues from the points of view of the Client, the Operator and the transfer system supplier, and detail the importance of a fully integrated and modern LNG transfer system.

Introduction

When developing and proposing new methods and systems to the Oil and Gas Industry, especially when safety of personnel and equipment is paramount, co-operation between the main involved parties at an early stage gives a firm base from which to work. In marine environments involving the transfer of LNG and gas, a concerted approach between the end user, the equipment supplier and experienced marine operators will ensure that practical procedures will result whenever possible in similar methods, based on existing know-how.