bluuebunny/crossref_metadata_2025 huggingface dataset:
Techniques for the assessment of pipe-soil interaction forces for future deepwater developments
Authors: Bruton David A.S. , White David , Langford Thomas , Hill Andrew John
Published: July 2009

A large subsea development will comprise a floating production system connected to subsea wells by a large network of infield flowlines. These flowlines are all susceptible to lateral buckling and pipe-walking under operating conditions, with the challenge of meeting design limits states associated with local buckling, fracture and low-frequency fatigue damage during the operational cycles. The pipe-soil interaction response is the largest uncertainty in the design of such systems, and has a significant influence on the pipe response and structural limit states.

The Project therefore commissioned a series of project-specific test programmes, at large-scale and small-scale, to improve understanding of axial and lateral pipe-soil interaction under monotonic and cyclic loading. The project has also carried out novel in-situ pipe-soil interaction tests in the field. The test programme was focused on relatively heavy pipe behaviour associated with pipe-in-pipe systems in very soft deepwater clay. The findings from these tests have led to a radical reappraisal of the interaction mechanisms and provided much greater confidence in optimised design solutions for the project. The test methods are described and the results and interpretation are summarised. These illustrate the significant advance in geotechnical knowledge and understanding achieved during this project, which is expected to benefit many future projects.

Background

Field Description

This typical deepwater subsea development will comprise a floating production system connected to subsea wells by a large network of infield flowline systems, including:Production flowlines with high performance pipe-in-pipe insulation, and uninsulated service flowlines;Water injection networks comprising plastic-lined rigid steel pipe;Gas injection flowlines comprising uninsulated pipe for a future gas export system.

Susceptibility and Control

Any pipeline which is subjected to above ambient temperatures and pressures has a tendency to relieve the resulting high axial stress in the pipe wall by expanding longitudinally. This expansion is resisted by the axial soil resistance between the pipe and the seabed. This restraint causes an axial compressive force to develop in the pipeline, which can cause buckling. Because these pipelines are laid in deep water there is no requirement for pipeline trenching and therefore no lateral or uplift restraint acting on the pipeline to prevent buckling, apart from the lateral resistance between the pipe and the soil.

A key challenge for this subsea flowline design is the control of lateral buckling, pipe walking, or route curve instability of the flowlines between the riser base and the drill centres. Conceptual engineering and FEED (front end engineering design) confirmed that all flowlines are susceptible to lateral buckling and several are susceptible to pipe-walking. If left uncontrolled, this behaviour can have serious consequences for the integrity of a pipeline.
Flexible Flowline Thermal Exchange Coefficient Test Performed at High External Pressures
Authors: Pires Fabio , Clevelario Judimar Assis , Falcao Gelson , Souza Italo , Sheldrake Terry H.
Published: July 2009

It is known that the thermal exchange coefficient (TEC) of an insulated flexible pipe may be affected by both external pressure due to the operating water depth and by the annulus condition. International standards state that flexible pipe systems shall be designed considering the effects of these two environmental conditions. If not considered during the flexible pipe design phase, these factors may have an important impact in the production system by reducing the temperature and allowing hydrate and paraffin formation in the pipe bore.

As part of Wellstream's research and qualification programme, a TEC test was performed to assess and quantify the effects of external pressure and the annulus condition during the flexible pipe system operation. The test was carried out using a 3m long sample taken from a 6 inch internal diameter production flowline designed to 1500m water depth and a maximum fluid temperature of 60°C with 276 bar internal pressure. Special end fittings were designed to reduce the pipe axial heat loss during the test.

The tested pipe was designed in accordance with Wellstream methodology and design tools to provide a pipe structure with a TEC lower than a predicted value, even when subjected to external pressure due to the operating water depth, or in an annulus flooding event.

The test was conducted in two different phases to separately evaluate the external pressure and annulus condition. The first phase of the test was conducted sequentially at four different levels of external pressure, these being 1, 50, 100 and 150 bar on a dry pipe annulus.

The second phase of the test was carried out after flooding the annulus with water under an external pressure of 165 bar for 72 hours to soak the insulation tapes, which are responsible for the greatest part of the thermal exchange characteristics. After this period, the pipe TEC was measured sequentially at four different levels of external pressure.

By the end of the test it was possible to determine thermal exchange characteristics when the pipe was subjected to environmental conditions representative of actual applications. The relationship between the external pressure and the TEC variation could also be assessed and furthermore, it was possible to evaluate the behaviour of the flexible pipe thermal properties after an annulus flooding event. The test also demonstrated that Wellstream's design methodology properly accounts for the effects that both the external pressure, due to the operating water depth, and the annulus condition has on the pipe's TEC.
SS - Leveraging Technology And Best Practices To Develop The Giant Khurais Field
Authors: Al-Mulhim Waleed Abdulla , Al-Ajmi Fahad Abdullah , Al-Shehab Mahdi Abdulla , Pham Tony Reuben
Published: July 2009

The paper discusses the upstream development of Khurais field, referred to here interchangeably as Khurais Oil Complex, consisting of several fields and reservoirs to a capacity of 1.2 MMBPD of Arabian Light crude. It describes the planning, execution and leveraging of technologies coupled with best industry practices to deliver the target rate while reducing the unit development cost, increasing the well productivities and expanding the reserves base.

At the beginning of the project, a high resolution 3D seismic program was successfully performed to characterize the reservoir structure and geological features. Coupled with vertical-horizontal delineation wells, additional reserves were delineated and added to the development. To reduce the unit development cost, the paper shows that the project utilizes a complex well architecture with combination of maximum reservoir contact (MRC), multi-lateral, and horizontal wells as well as Smart completion, Smart ESP, and passive inflow control device to achieve and sustain the target rates. The development also sets the stage for technology leveraging in the future by drilling wells with large wellbores, allowing flexibility for the next generation complex well architecture while pursuing fit-for-purpose technologies through joint ventures and Saudi Aramco Advance Research Center.

The paper illustrates that the Khurais development is unique not only in terms of its size but also in terms of special technology applications and its complexity with respect to development of multiple fields and reservoirs with proper utilization of many complementing technologies. Through Saudi Aramco best practices, all of these are part of the development plan which utilizes applications of Advanced Mathematical Models in the form of Multi-Objective Function and probabilistic modeling techniques such as Experimental Design and Monte Carlo simulations. The development plan mitigates the development risk and optimizes oil off-take from different reservoirs and areas with respect to well placement, ESP design, depletion rates, injection production ratio, number of injectors and producers, pressure support, sweep efficiency, flood front conformance and oil recovery. The best practices also include real-time geosteering to ensure the horizontal laterals are directed through the best pay possible.

The efforts have paid off as field tests of the producers, at the time the paper was written, show three to five times productivity improvement compared to existing vertical wells in the fields. The development also goes beyond the initial stage of the production as Khurais is the company flagship for I-field technologies in real-time data gathering, transmission and operation remote controlling to enable continuous monitoring and optimization of the field development and reservoir performance.
SS: Arctic: Application of the Newly Adopted IACS Polar Class Rules to Offshore Support Vessels of Small Tonnage
Authors: Springer John A. , Caughlan Sean A.M. , Kristensen Dirk H. , Cronin Daniel D. , Menon Balji C.
Published: July 2009

The Glosten Associates, along with their regulatory partner, the American Bureau of Shipping (ABS), recently completed the design of the 242-foot, ice-strengthened Alaska Region Research Vessel (ARRV) for the University of Alaska Fairbanks (UAF) and the National Science Foundation (NSF). The vessel design is the first reviewed by ABS that meets the structural and mechanical requirements of the new Polar Class Rules developed by the International Association of Classification Societies (IACS). The application of these rules to vessels of smaller tonnage, such as offshore supply vessels (OSVs), maintenance vessels, anchor handling tugs, etc., is of particular interest to designers of vessels that will operate in the newly developing Arctic offshore areas.

The Polar Class Rules represent a major step forward in harmonized, ice-capable, structural design. However, some areas of the rules require further development and cautioned use, particularly for vessels with displacements below 5,000 metric tons1. It is recommended that simultaneous application of the General Ice Class Rules be utilized to identify major areas of impact.

Design consequences resulting from the application of the new IACS Polar Class rules include vessel weight and cost and changes to arrangements, machinery, and operations. These impacts are of great interest to designers and operators of Arctic vessels. This paper summarizes important design guidance for ice-capable offshore vessels and provides guidance on collaborative efforts with ABS, particularly for application to small-tonnage vessels.
OTEC Commercialization Challenges
Authors: Cooper Dennis , Meyer Laurie , Varley Robert
Published: July 2009

An industry and university team is developing ocean thermal energy power plant designs to provide baseload, renewable electricity to commercial power grids and to Department of Defense base grids. This paper provides some general thoughts on OTEC commercialization challenges. A brief description of OTEC and a view of the market are provided. Based on two years of design efforts and market assessments, challenges in technology, economics, and risk are discussed. No technology barriers are evident at this time. OTEC can be affordable though much work remains to be done. Because OTEC has not been commercialized nor has been demonstrated by anything approaching megawatt scales, a megawatt scale pilot plant is necessary to validate performance and cost for subsequent availability of financing for commercial applications.
Intelligent Well Completions in Agbami: A Review of the Value Added and Execution Performance
Authors: Adeyemo Kunle Mojeed , Aigbe Chris , Chukwumaeze Ikenna Chibuzo , Meinert David , Shyrock Steve
Published: July 2009

Application of Intelligent Well Completion (IWC) technology has continued to grow within the industry even in the face of perceived risks associated with installation and longevity of the system. In Agbami, where 80% of the development wells are planned with IWC installations, understanding these risks played a key role in justifying intelligent completions. This paper will present the methodology used to quantify the realizable value from zonal control and data acquisition, and review the execution performance for the initial IWC wells.

The Agbami field is Chevron's first operated deepwater asset in offshore Nigeria. It is located 70 miles offshore of the Niger Delta in ~5000 feet of water. The subsurface is characterized by a double-plunging anticline structure with a thrust fault along the main axis and multiple flank normal faults dividing the three major reservoirs into five or six main producing areas. Each major reservoir is vertically subdivided into 3 or more sub-reservoirs. The field is being developed with 38 wells, consisting of 20 producers, 12 water injectors and 6 gas injectors spread over 3 development drilling stages. Pressure maintenance will be via peripheral Water Injection and produced Gas Re-injection.

The production facilities include full Subsea infrastructures (trees, manifolds & flowlines) producing to a Floating Production, Storage, and Offloading vessel (FPSO).

The Agbami wells are typically completed in multiple zones of the same reservoir. The completed zones are geologically in pressure equilibrium, but vertical and lateral/cross-fault connectivity under dynamic conditions is still very uncertain. Given this uncertainty, the water and gas flood-fronts are likely to advance at different rates through the reservoir. To optimize field performance and recovery, Intelligent Completions with downhole control valves are being installed in Agbami wells. The system will provide zonal information and control of production and injection into the completed sub-reservoir zones.
SS: Panel: Structuring Projects to Benefit Multiple Stakeholders - How IOCs, NOCs and service Companies Can Collaborate to Create Stakeholder Value and Promote Local Development
Authors: Ross Chris
Published: July 2009

Preface

This manuscript is intended to set the stage for a panel discussion, " Structuring Projects to Benefit Multiple Stakeholders—How IOCs, NOCs and Service Companies Can Collaborate to Create Stakeholder Value and Promote Local Development??, scheduled for Tuesday, May 5th, 2009. The panel participants include:Emmanuel Engelmann, Vice President of Technology, TotalWolfgang Puennel, Group Vice President, Global MarketingDean Slocum, President, Acorn International

And the moderator, who gratefully acknowledges the materials provided by the panelists and their predecessors Jean-Marie Guillermou of Total and Keith Morley of Weatherford in preparing this paper:Chris Ross, Vice President, CRA International

Theme

The large international oil companies (IOCs) are finding it difficult to gain access to resources under traditional terms. The citizens and national governments of several resource rich countries have become frustrated by their failure to translate oil revenues into lasting economic benefits for their nations. Increasingly, contracts awarding access to resources include provisions requiring a growing level of local content in capital and operating expenditures as well as programs to build local capabilities. Some awards go further and include an obligation to invest downstream of the resource development project. Some internationalizing national oil companies (INOCs) have been assisted by government to government agreements to invest in infrastructure development in the host country.

This panel will outline the expectations of government and society in resource rich countries, describe the issues as seen from the IOC perspective, explore the tension between global expertise and local content in the provision of products and services, and describe a model for building capacity in local suppliers.

Resource Rich Country Needs

The needs of resource rich countries vary widely according to their stage of development. Norway, for example, is fully developed and has successfully leveraged its resources into national economic development. According to Helge Lund, CEO of StatoilHydro: " I think most people regard the Norwegian model as maybe one of the most successful ways of organizing oil and gas activities to benefit not only the general public and government finances but also to build a strong oil and gas company and a strong service industry.?? Brazil voluntarily opened its upstream oil sector to attract competition, and privatized Petrobras, which has become a globally respected for its deep water competencies. Brazil also is developing a capable service sector. The needs of Brazil and Norway are to continue to attract competition with new ideas on resource discovery and development who will also be good citizens and customers for their service sectors.
SS - Sakhalin I: Managing a PSA Environment in Russia - A Success Story
Authors: Flood Jim , Harding Stephen J.
Published: July 2009

The Sakhalin-1 Project is a world-class development located in a remote, harsh environment off the east coast of Sakhalin Island, Russia. The first phase of the development was the Chayvo field, which has been successfully executed with full production achieved in late 2006. The Project presented multiple challenges, including the harsh sub-arctic climate, a remote location with minimal existing infrastructure, limited availability of skilled labor, and a complex and extensive regulatory regime. This paper provides an overview of the Project with an emphasis on the Phase-1 development of Chayvo field and describes the challenges, presents some of the key project management steps implemented to successfully address these challenges, and summarizes some of the benefits to Russia and the local community. This paper also serves as an introduction to the following Sakhalin-1 papers that address specific topics in greater detail.

Sakhalin-1 Background

The Sakhalin-1 Project is a world-class development opportunity, one of the largest single foreign direct investments in Russia, and an excellent example of how advanced technological solutions and front-end execution planning can be applied to meet the challenges of growing worldwide energy demands. The development consists of multiple offshore fields off the east coast of Sakhalin Island, Russia. Development of these fields is challenged by the presence of seasonal thick ice, gail-force winds, and the year-round potential for severe waves and seismic activity. The successful completion of the Project required the use of innovative technologies, disciplined management processes, and high levels of environmental and safety protection.
SS: Sakhalin-1: Project Execution Risks and Management
Authors: Roxburgh Sam , Kostiuk E.A.
Published: July 2009

Phase-1 of the Sakhalin-1 development serves as an example of how to successfully address the multiple challenges associated with working in a frontier environment with limited infrastructure. This paper highlights how the project managed the technical, execution and environmental challenges it faced as it developed the resources at Chayvo field.

A detailed front end execution planning effort identified execution risks and was used to develop plans to mitigate those risks. Major outcomes of this effort included an execution schedule that would allow use of the weather windows provided by the arctic region; winterization plans to continue construction progress during the winter months; the use of large modules built in a fabrication yard versus stick building on site and implementation of a " plug and play?? concept to maximize commissioning at the fabrication yard and minimize start-up in the field.

The project also managed the challenges associated with a complex regulatory regime, limited existing infrastructure, limited skilled labor and difficult logistics. All the challenges faced by the Sakhalin Phase-1development were successfully managed by the integrated project team. This fostered the development of execution strategies that lead to the ultimate success of the project. Lessons learned from this project can be applied at other projects in challenging frontier regions, particularly those in arctic environments with limited existing infrastructure.

Introduction

The Sakhalin-1 concession area, located along the east coast of Sakhalin Island, Russia, consists of the Chayvo, Odoptu and Arkutun Dagi fields with recoverable resources in excess of 2.3 billion barrels of oil and 17 trillion cubic feet of gas. The Sakhalin-1 Consortium consists of ExxonMobil affiliate Exxon Neftegas Limited (ENL) (30%, operator), SODECO (30%); ONGC Videsh Limited (20%); and two affiliates of the Russian national oil company, Rosneft (20%).1 The Consortium successfully completed the Phase-1 development of the Chayvo field with first production in late 2006, approximately 10 years after the signing of the Production Sharing Agreement.
SS: Canadian: Atlantic Development: The Sydney Basin of Eastern Canada An Overlooked Carboniferous Basin with Demonstrated Petroleum Potential Thoughts, Facts and Musings
Authors: MacDonald D. Jack
Published: July 2009

Introductory Comments

The Sydney Basin represents the most easterly extent of the upper Paleozoic fill of the much larger Maritimes Basin of Atlantic Canada (Figure 1). Thick sequences (12 km+) of mid-Devonian to Upper Carboniferous / Permian sediments include thick non-marine, multi-storied sandstones, extensive limestones and thick salt overlain by multistoried fluvial sands and coal measures. It is worth noting that a significant portion of Canada's light oil and gas output comes from Paleozoic reservoirs, and over 20% of world oil reserves originate in Paleozoic reservoirs. (Enachescu, M.E, 2006)

The Carboniferous sediments of the Maritimes Basin have been productive since the very early 1900's with both oil and gas being produced over an 80+ year period from the Early Carboniferous rocks in the neighbouring province of New Brunswick. Corridor Resources of Halifax has been producing natural gas from the McCully field in New Brunswick from these same sediments since 2003. That field is now connected to the Maritimes & Northeast Pipeline which provides some 400+ mmcf/d to markets locally and to the northeastern U.S. Corridor has also made a significant discovery of oil in sandstone lying beneath as well. Oil shales are found in New Brunswick, Nova Scotia and Newfoundland. Stealth Ventures Ltd. has committed to eastern Canada's first coalbed methane production agreement in the Cumberland Basin of western Nova Scotia. One nearshore well drilled just in the same rock units on the western side of Cape Breton Island, Nova Scotia yielded gas rates of 5.5MMcf/d. Shale gas has been evaluated in Nova Scotia with independent estimates suggesting that some 63 trillion cubic feet (in place) may exist in only one of several basins where the shales are known to occur. On June 24, 2008 Elmworth Energy Corporation submitted a development plan as part of their application in accordance with requirements for a shale gas production agreement. In each case sited, the mentioned resource has both its source and reservoir unit within the Carboniferous interval. Some fifteen companies are currently exploring for, or are developing, Carboniferous reservoirs in the Maritimes Basin of Atlantic Canada.
SS: Unlocking the Unconventional Oil and Gas Reservoirs: Utilization of Real Time Microseismic Monitoring and Hydraulic Fracture Diversion Technology in the Completion of Barnett Shale Horizontal Wells
Authors: Waters George A. , Ramakrishnan Harihan , Daniels John , Bentley Doug , Belhadi Jamel , Sparkman Deane
Published: July 2009

It is now well documented that hydraulically fractured horizontal wells are effective at stimulating shale reservoirs. Most commercial shale wells utilize cement or open hole packers to achieve some form of annular isolation. With annular isolation now commonly accepted, the general evolution of these completions has been to stimulate ever shorter sections of the lateral with multiple perforation clusters placed closely together. The objective being to create closely spaced fractures, thereby increasing the reservoir contact area that more effectively imposes a pressure drawdown within the ultra-low permeability reservoir, resulting in a higher recovery factor.

The heterogeneous nature of unconventional shale reservoirs makes achieving a complex, closely spaced fracture network problematic. Frequently, geologic structure impacts the created fracture network to such a degree that fluid entry points into the reservoir are of secondary importance. Horizontal well evaluation can be utilized to optimize perforation placement and fracture staging for near-wellbore fracture geometry generation. This has proven to improve well performance. An additional productivity step can be achieved if the far field fracture geometry can be influenced by techniques other than perforation and fracture staging, especially if this technique can be applied in real time during the stimulation treatment.

One method that has been successful at altering the created hydraulic fracture geometry is real time microseismic fracture mapping coupled with fracture diversion packages incorporated into the fracturing treatment. Evaluating microseismic events in real time allows one to determine the need to change the fracture geometry being generated. The introduction of diversion packages to achieve this fracture geometry alteration can immediately be evaluated for effectiveness via the microseismic activity. This feedback allows the completions engineer to appropriately use these diversion packages so that effective stimulation along the whole lateral can be achieved.

Examples of the use of real time microseismic fracture mapping and fracture diversion packages are shown from the Ft. Worth Basin Barnett Shale formation. Both initial well completions and recompletions are shown. The importance of integrating well, geologic, log, and seismic information, is emphasized so that decisions can be made effectively in real time using the microseismic activity from the treatments. These examples demonstrate that hydraulic fracture geometries can be influenced by the introduction of these diversion packages. Resulting well productivity and fracture pressure responses validate the effectiveness of this real time diversion and evaluation process.
SS: Unlocking the Unconventional Oil and Gas Reservoirs: The Effect of Laminated Heterogeneity in Wellbore Stability and Completion of Tight Gas Shale Reservoirs
Authors: Suarez-Rivera Roberto , Deenadayalu Chaitanya , Yang Yi-Kun
Published: July 2009

Unconventional shale-gas reservoirs are complex systems with predominant layered heterogeneity. This results in high variability in material properties and in considerable contrast in mechanical and elastic properties along orientations parallel and perpendicular to bedding. Understanding the effect of this variability in strength and elastic properties with bed orientation, to hydraulic fracturing breakdown pressures, height containment, and long-term stability of wellbores and perforations, are of highest interest to unconventional, shale gas, reservoir applications. Successful hydraulic fracturing is fundamental for economic production from nano-darcy permeability gas shales. By incorporating anisotropic elastic deformation, to better represent the behavior of unconventional tight gas reservoirs, we facilitate the understanding of nearwellbore stress concentrations and their effect on fracture initiation. Results show that strong elastic anisotropy results in lower breakdown pressures and lower tortuosity at the wellbore face. As a consequence, selecting perforating intervals along sections with highest elastic anisotropy minimize fracture initiation problems, and results in lower treating pressures. In addition, elastic anisotropic behavior influences the magnitude of the minimum horizontal stress and the potential for fracture containment. Traditional isotropic-rock models do not capture this behavior. When applied in anisotropic formations these models misrepresent the potential of fracture containment. This leads to erroneous selections of perforation intervals (vertical completion) or landing depths of horizontal wellbores. A third consequence of strength and elastic anisotropy is the high risk of wellbore stability during drilling. In rocks with changing elastic moduli and strength with bed orientation, the highest risk of wellbore failure often occurs during building angle from the vertical to the horizontal directions. Along this path, there is a critical angle, defined by the strength anisotropy of the rock that will maximize the risk of failure. Minimizing this risk, e.g., by controlling the mud weight or well inclination, is of principal importance to the economic success of the play. In this paper we conduct numerical simulations on unconventional gas shales, exhibiting moderate to strong elastic and strength anisotropy, to evaluate the effect of their anisotropic behavior on well construction and completion. We also show that traditional isotropic models may lead to erroneous completion decisions, and underestimating the risk of wellbore failure. We conclude by suggesting that modeling and predicting near-wellbore effects of horizontal completions and wellbore stability in anisotropic shales is straightforward, provided that appropriate measurements of anisotropic strength and elastic properties are obtained on each of the various lithofacies present in the system.
SS: Offshore Floating LNG - LNG FPSO Development - bringing two industries together
Authors: Meek Harke Jan , Cariou Herve , Schier Marc
Published: July 2009

Floating liquefaction solutions are receiving growing interest lately as they are seen as potential enablers to un-lock and monetize offshore gas reserves that are currently considered stranded.

Although Onshore LNG liquefaction facilities and Offshore Oil&Gas FPSOs are each successfully proven in operation, combining the two technologies into a LNG FPSO poses new technical, organizational, execution and economical challenges to the industry that have to be properly addressed to be able to successfully implement a first of a kind concept.

Having to integrate two distinctly different industries during design, execution and operation, and the LNG FPSO concept not being operational to date yet, being technically quite complex and capital intensive, it is essential to have a well-balanced, reputable, strong and experienced team to develop and execute such a project. It is hence critical that organisations involved in the execution concentrate their efforts and leverage complementary skills, capabilities and track records to make the LNG FPSO project a success.

Important aspects of a LNG FPSO are the space constraints and the location of operation. Contrary to an onshore LNG plant, space is very limited on the LNG FPSO and utmost care and creativity is required to arrive at a safe, constructible, operable and maintainable topside configuration. Any LNG FPSO concept shall find a good balance between efficiency and simplicity to safeguard the reliability of the facility.

SBM and Linde have approached the development challenge by operating as one fully integrated team during the complete project development, which allows us to manage critical interfaces and leverage each other's complementary expertise in the best possible way. The so-called Generic LNG FPSO design uses only proven components and can handle a wide range of gas compositions. The flexibility of the concept is achieved by designing the layout and weight requirements for the most conservative scenario in the design envelope. The generic design can subsequently quickly be tailored for a specific field application.

Having finalized the FEED phase of the generic LNG FPSO concept and the associated detailed CAPEX estimate by the end of September 2008, SBM/Linde believe that a mid-scale LNG FPSO is a technically and economically feasible concept that can unlock value of gas reserves that are currently considered stranded.
Special Session, AGBAMI Field Development - AGBAMI Offloading System - Worldwide design and fabrication challenges
Authors: Maretti Serge , Hoekstra Sjoerd , Mitwally Hisham
Published: July 2009

The Agbami field is located 110 km offshore Nigeria in 1,400 m of water and is operated by STAR Deepwater Petroleum Limited on behalf of the concessionaires Nigerian National Petroleum Corporation, Famfa Oil Limited and the other funding participants: Statoil Nigeria Limited, Petroleo Brasileiro Nigeria Limited, Star Deepwater Petroleum Limited (an affiliate of Chevron Corporation) and Texaco Nigeria Outer Shelf Inc. (an affiliate of Chevron Corporation).

The Agbami Offloading System consists of a surface buoy connected to the FPSO via two U shaped steel offloading lines. Design and fabrication of the Agbami Offloading System was carried out by a consortium of two companies and the engineering, fabrication and installation planning was carried out by the consortium offices and their subcontractors in several locations worldwide.

This paper will provide an overview of the major safety, design and fabrication challenges encountered during the engineering, fabrication and installation of the Agbami offloading system throughout the various phases of the project, from contract award to commissioning and first offload. The paper will also present some of the lessons learned that were gathered throughout project execution.

Establishing a strong QA/QC system, acceptance criteria and a close working relationship with suppliers proved to be essential in securing the needed quality of the fabricated critical components. Robust interface management system and timely resolution of interfaces was also critical to ensure completion of engineering and delivery of interface components on time.

Agbami Project

Agbami field is a full subsea development consisting of an FPSO (Floating Production Storage and Offloading) connected to subsea wells via flexible risers and static and dynamic umbilicals with crestal gas injection and peripheral water injection.

The subsea production system consists of 20 wells centered around 6 drilling center manifolds and tied back to the FPSO by dual flexible risers and flow lines, allowing round trip pigging from the FPSO. Flexible jumpers connect each tree within a drill center to the production manifold. The subsea water injection system consists of 12 injection wells tied back to 4 water injection manifolds via flow lines and jumpers and the manifolds are connected to the FPSO via single flexible risers. The subsea gas injection system consists of 6 gas injection wells tied back to two gas injection manifolds via flow lines and jumpers and the manifolds are connected to the FPSO via dual flexible risers to allow round trip pigging. The FPSO is capable of producing 250,000 barrels and has a storage capacity of 2.15 million barrels of oil.
SS: Agbami Field Development : Agbami Nigerian Content Execution: Successes, Challenges, and Lessons Learned
Authors: Ehondor Henry Ukpomwan
Published: July 2009

Star Deep Water Petroleum Limited, an affiliate of Chevron Corporation, is the operator of the Agbami Unit. The concessionaires are Famfa Oil Limited and the Nigerian National Petroleum Corporation. Other partners are; Texaco Nigeria Outer Shelf Inc. (a Chevron affiliate), Petroleo Brasileiro Nigeria Limited and Statoil Nigeria Limited.

Agbami project is recognized as a pacesetter in Nigeria in the successful execution of prescribed Nigerian content scope of work. Agbami Project achieved over 300,000 manhours of Nigerian content engineering and training, 4.2 million manhours of Nigerian content fabrication and over 10,000 tons of Nigerian content fabrication. The project faced several challenges during the execution of the Nigeria content scope and successfully completed the work on schedule without any lost time injury.

This paper will discuss the various successes, challenges and lessons learned during the design and construction of the Nigerian content scope of Agbami Project. Additional insights into specific issues that were addressed will be discussed.
SS: Jack-up Technology: Improved Guidelines for the Prediction of Geotechnical Performance of Spudcan Foundations During Installation and Removal of Jack-up Units
Authors: Osborne Julian , Houlsby G.T. , Teh K.L. , Leung C.F. , Bienen B. , Cassidy M.J. , Randolph M.F.
Published: July 2009

Incidents of unpredicted, and often adverse, jack-up foundation performance continue to occur regularly, while the safety records of other jack-up activities, such as towing, drilling, structural fatigue, collision, fire and blow-outs have improved significantly. Even with comprehensive site assessment procedures in place, and at a time when the jack-up industry is increasingly focused on the control of risks, foundation incidents continue to occur.

To address these issues a Joint Industry Funded Project (" InSafeJIP??) has been launched with the intention of developing a document titled " Improved Guidelines for the Prediction of Geotechnical Performance of Spudcan Foundations during Installation and Removal of Jack-up Units??.

This JIP is being supported by a wide range of organizations, with representation from:5 Drilling Contractors 5 Operators 4 Marine Warranty Surveyors1 Classification Authority 1 Legislative Authority 1 JU Designer and Builder2 Geotechnical SI Contractors / ConsultantsThe work is being undertaken by a Project Team drawn from the following Universities:National University of Singapore Oxford University The University of Western Australia

This fast track initiative is being project managed by RPS Energy with support from Keppel FELS, and the Guideline is scheduled for Industry release possibly as early as 2010.

Introduction

The overall safety of offshore operations continues to improve at an appreciable rate, but similar success is not being achieved on the predictability, and consequential safety, of jack-up rigs during installation and extraction operations. Unpredictable jack-up foundation performance during installation regularly leads to rig damage, lost production time and project delay with severe cost implications, and at worst can endanger personnel (Osborne et al., 2006).
Key Chayvo Drilling Results and Planning the Interfield Move of the World's Largest Land Rig on Sakhalin Island
Authors: Grini Morten , Kessler Vincent Kessler
Published: July 2009

The drilling program at the Chayvo field has concluded after five years of operations. This paper highlights the world-class extended reach drilling (ERD) and completion results achieved at Chayvo using Yastreb, the world's largest land rig. During this time, Yastreb drilled and completed 12 out of the 16 longest ERD wells worldwide to date. At the conclusion of the drilling program, Yastreb and its support infrastructure were moved from the Chayvo location to the new Sakhalin-1 Odoptu field. This paper also describes the significant planning and execution effort required to successfully accomplish the Yastreb rig move in a remote location like Sakhalin Island.

The scope of work to move Yastreb from Chayvo to Odoptu includes disassembling, moving, and rigging up and commissioning the rig and associated infrastructure in a harsh arctic environment with limited logistical support ~200 km away at its new location at Odoptu. Due to the additional requirements of the more challenging Odoptu wells, significant brownfield modifications were also needed, including a new higher torque top drive system and a larger drilling mast. A key focus area during the rig move was executing the scope of work safely with minimum impact to the environment.

The Yastreb rig move started in July 2008 and transportation of the rig and related material was completed in January 2009. Rig up and commissioning is ongoing. The rig is expected to be ready to drill its first well at Odoptu approximately seven months after starting the rig down operation at Chayvo. The application of Chayvo ERD learnings to the Odoptu well design will also be discussed.

Introduction

Sakhalin Island is located north of Japan off the east coast of Russia. The Chayvo and Odoptu fields are located near the northeast coast of the island approximately 10 km offshore (Fig. 1). The climate is sub-arctic with temperatures lower than freezing over half the year, and minimum temperatures below -40°C. Sakhalin Island is also at the northeastern edge of the Eurasian tectonic plate and is subject to significant tectonic stresses resulting in movements along nearby faults. An earthquake of 7.6 on the Richter scale was experienced in 1995. In addition to factoring in potential thermal and seismic effects on the rig and its equipment, both the Chayvo and Odoptu wellsites are on the beach, which contributes significantly to increased " wear and tear?? and creates additional transportation challenges.
RPSEA: Securing Energy for America
Authors: Ming Charles Michael
Published: July 2009

The Research Partnership to Secure Energy for America (RPSEA) doubled its membership in just two years as it combined a congressional mandate with a leveraged research, development, demonstration and commercialization process designed to bring United States consumers more domestic natural gas and oil at lower cost. Congress primed the effort when it passed the Energy Policy Act of 2005 (EPAct), delivering legislation for the Department of Energy for a program that would speed access to the nation's ultra-deepwater, unconventional and other petroleum resources with particular attention to passing production technology to small producers.

Background

The Department of Energy's (DOE) National Energy Technology Laboratory (NETL) competitively selected RPSEA in May 2006 and signed an oversight contract with RPSEA on January 4, 2007. RPSEA went to work with a budget of $37.5 million a year in directed spending for 10 years not subject to congressional appropriation, plus a core of 70 members and a plan to leverage its research money into the most effective research partnership ever assembled for the energy industry. Partnership and membership form the foundation of the RPSEA open innovation public/private partnership. Together, they build the research steps to maximize the value of domestic resources through more efficient and lower cost exploration, drilling and production techniques in three program components—Ultra-Deepwater (UDW), Unconventional Resources and Small Producer. NETL internally manages an additional $12.5 million research program that is complementary to and supportive of RPSEA for a combined annual program of $50 million. Also, NETL has oversight responsibility for RPSEA and the entire program.

RPSEA members come from every corner of the energy industry. Producers of all sizes identify real-world field challenges and drive RPSEA toward solutions that work in everyday operations. Service companies offer a long history of meeting those challenges with sophisticated research facilities geared to affordable solutions. Universities compile the latest techniques and technologies, add post-graduate innovation and pass that learning to others. Public and private organizations, including the national laboratories, lend a focused approach as they help transfer potential new technology to field applications. Together, they create a powerful partnership within the organization and the scope to bring additional resources to bear on specific industry needs.
Strategy for seismic depth processing in Deep Water, Subsalt environment
Authors: Brandsberg-Dahl Sverre , McClean Jim , Wijnen Peter
Published: July 2009

Reverse-time prestack depth migration (RTM) has over the last couple of decades been established as an accurate and robust depth-imaging tool. Continuous advances in CPU speed and computer technology are helping make RTM more cost efficient. Today, we see it being used as a standard tool in most seismic imaging projects in conjunction with other imaging tools such as one-way wavefield extrapolation migration and Kirchhoff migration. Reverse time migration uses the full two-way wave equation for the wavefield extrapolation steps; hence there is no intrinsic dip limitation with this approach. This allows the method to handle turning waves and multiply reflected prismatic waves.

All migration methods benefit from spatially well-sampled input data with a large acquisition aperture. The introduction of wide-azimuth towed streamer (WATS) surveys has helped improve both aspects by offering wide receiver spreads and dense sampling. This ensures a more complete initial boundary condition for wavefield migration schemes, which again leads to improved sub-surface images. Applying RTM to wide azimuth data is a proper match between a state-of-the-art imaging algorithm and state-of-the-art acquisition.

Here, we outline some of the challenges of implementing RTM so that it can be applied to explorationscale datasets and wide-azimuth data in particular. We illustrate the performance of the RTM algorithm through comparisons with Kirchhoff, one-way wavefield migration and beam migration on a wide azimuth field dataset from the Gulf of Mexico.
Síndrome das Pernas Inquietas
Authors: Prado Gilmar Fernandes do
Published: July 2009

A síndrome das pernas inquietas (SPI) é uma doença freqüente e muitas vezes debilitante, descrita há cerca de 330 anos. Thomas Willis, um dos mais famosos médicos da Londres do século XVII, deu detalhes do quadro clinico e foi o primeiro que se tem noticia a utilizar opioides para o tratamento dessa doença. Karl Axel Ekbom, após um longo período de dormência desse assunto na literatura médica, voltou a dar atenção à doença, tendo sido responsável pela sua descrição sob a moderna forma do pensar médico: a clínica. Ekbom trabalhou desde 1944 até o final de sua carreira fazendo observações sobre essa doença, tendo sido o responsável pelo alavancamento de pesquisas que hoje ocorrem envolvendo essa entidade. Apresentamos no corpo do artigo, os textos de Willis sobre a SPI, uma leitura não muito mas interessante, e também algumas palavras sobre a medicina pré-clinica.
Intervenções fisioterapêuticas para pacientes com fibromialgia
Authors: Vitorino Débora Fernandes de Melo , Prado Gilmar Fernandes do
Published: July 2009

A fibromialgia é uma síndrome dolorosa, de etiopatogenia ainda desconhecida. A terapêutica orientase fundamentalmente para o alívio dos sintomas. À medida que se amplia o conhecimento a respeito da fisiopatologia e dos mecanismos de controle da dor, novas propostas terapêuticas surgem. O objetivo deste estudo é fazer uma revisão dos diferentes métodos usados no tratamento desta síndrome já testados cientificamente.