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1) Steps to the Subsea Factory Abstract During the last 25 years Statoil, in cooperation with key vendors, have developed technical solutions for subsea field development resulting in more than 500 subsea wells. As part of the corporate Technology strategy Statoil has launched a technology plan for the Statoil Subsea Factory™ concept. The plan describes how to combine subsea production and processing technology elements together with key business prioritised elements such as long distance multiphase transport, floating production facilities and pipeline networks to enable costeffective field development. In addition, subsea production and processing can enable accelerated production and increased recovery in an energyefficient manner, and with low environmental footprint This paper provides an overview of the technologies enabling the Subsea Factory concept and the operating experience gained in assets having implemented subsea processing technologies. The paper describes the technology staircase starting with subsea boosting in the LuFeng field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot and the Tordis fields. The paper describes Tyrihans raw seawater injection and summarises the gas compression technology projects underway for the Gullfaks and Åsgard fields. The plan takes account of two specific valuecreation goals Statoil is targeting namely to realise subsea compression by 2015 and a complete subsea factory by 2020. Focus on establishing a Subsea Factory concept can be explained by the desire to improve the economic value of field developments. Utilizing a system approach from reservoir to export system, combine and reuse in new ways the subsea production and processing technologies already installed or being constructed in Statoil. The processing element will enable the fluids to be treated to a level where they can be safely transported in flowlines to a downstream host, whether onshore or offshore, fixed or floating. Future generations of subsea factory may include more sophisticated processing elements.
1) Steps to the Subsea Factory Abstract During the last 25 years Statoil, in cooperation with key vendors, have developed technical solutions for subsea field development resulting in more than 500 subsea wells As part of the corporate Technology strategy Statoil has launched a technology plan for the Statoil Subsea Factory™ concept The plan describes how to combine subsea production and processing technology elements together with key business prioritised elements such as long distance multiphase transport, floating production facilities and pipeline networks to enable costeffective field development In addition, subsea production and processing can enable accelerated production and increased recovery in an energy-efficient manner, and with low environmental footprint This paper provides an overview of the technologies enabling the Subsea Factory concept and the operating experience gained in assets having implemented subsea processing technologies The paper describes the technology staircase starting with subsea boosting in the LuFeng field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot and the Tordis fields The paper describes Tyrihans raw seawater injection and summarises the gas compression technology projects underway for the Gullfaks and Åsgard fields The plan takes account of two specific value-creation goals Statoil is targeting - namely to realise subsea compression by 2015 and a complete subsea factory by 2020 Focus on establishing a Subsea Factory concept can be explained by the desire to improve the economic value of field developments Utilizing a system approach from reservoir to export system, combine and reuse in new ways the subsea production and processing technologies already installed or being constructed in Statoil The processing element will enable the fluids to be treated to a level where they can be safely transported in flowlines to a downstream host, whether onshore or offshore, fixed or floating Future generations of subsea factory may include more sophisticated processing elements Statoil's vision is to develop and deploy all the necessary technology elements required for a "subsea factory??, i.e for the equivalent of a topsides processing facility to be operated on the seabed, enabling remote subsea to beach hydrocarbon transport solutions in any offshore location Statoil will be "Taking subsea longer, deeper and colder?? to accelerate and increase production?? by implementing the Statoil Subsea Factory™ The term "Older?? is also discussed in light of the potential to reuseexisting technology elements to increase recovery and maintain production at existing/brownfield facilities at the Norwegian Continental shelf 2) Subsea facilities Abstract This paper presents the system design and concept solutions selected for the Ormen Lange subsea facilities The field is located in a remote area off the coast of Norway and system availability has been a key driver in the subsea system selection and design This paper focuses on the following elements: Ormen Lange key technical challenges and concept development Subsea system architecture Design premises and essential functional requirements that have driven the subsea design Selected subsea system hardware solutions with emphasis on availability of the key functions Technology qualification programs that will be executed in order to provide confidence in the selected solutions 3) The future of electric controls: Trees and subsea processing Since 2008 the world’s first all electric production controls system is operating in the Dutch sector of the North Sea Valuable feedback is constantly being received and lessons learnt are being implemented for future generations of all electric technology A new generation has been developed for the operation of Subsea Production Systems, ie X-Mas Trees and Manifolds in particular But with Subsea Processing systems becoming more and more accepted by the industry, all electric technology could be a key enabler for further enhancement of Subsea Processing applications For instance with the subsea factory emerging on the horizon, a key requirement for complex systems is that control valves be operated in a continuous operation mode, either manually or in a closed loop (PID) For surface applications this generally poses no problem as various technical means are at the industry’s disposal ranging from pneumatic, hydraulic or electric actuation control For subsea this is different, with longer step-outs and deep water depths having a hydrostatic pressure constraint reaction times) These severe conditions require special equipment capable of handling the increased process control challenges Controlling valves faster becomes increasingly important, and in general demands electric control characteristics The majority of applications so far have used hydraulic actuators, although there are systems currently in build which will use electric actuation control This paper will focus on explaining electrical technology, its history, and identify its advantages especially when used for long offsets, zero discharge requirements and complicated process controls The paper will also provide a vision of the control technology for the future, drawing from proven Electro-Hydraulic and electric control systems of today and considering current technology developments 4) AKPO: The Subsea Production System Abstract It has been said "All deep water offshore projects are challenging?? Nowhere in the world projects have such high commercial pressures as those which take on the challenge of Deep Water Rarely if ever can it be said that any one field is a repeat of another Each therefore raises its own issues which each development must solve anew Some lessons are the same, and we forget them at our peril Some are new challenges, and we then call on our experience of the past to rise to meet them, and hence all our experience is necessary In the case of Akpo, many of the issues were totally new and we called on all of our experience of Deep Water fields in the Gulf of Mexico and West Africa The Akpo field in block OML 130, 200 km offshore Nigeria is in 1400 m water depth It is a gas/condensate field with high pressures and high temperatures One of the greatest challenges is to ensure that condensate and gas in multiphase flow reach the production facilities without being stopped by hydrates and wax and scale deposition The technical challenges alone are significant, but when set against the background of increasing oil prices and high commercial pressure on the suppliers from more than one operator and more than one field, the challenges take on a new dimension Added to that for Akpo were the issues of resources of personnel and manufacturing capacity in a very buoyant market as well as the new challenge of manufacturing in Nigeria This paper also addresses the challenges of the Subsea Production System of the AKPO development It shows how the conceptual design principles are encapsulated in the simple acronym - RAM and how these lead to some key issues The second most important issue facing all Subsea decisions is the fact that the cost of installation - whether by Drilling Rig or by Installation Vessel - FAR exceeds (in most cases) the cost of the equipment itself Added to that is the cost of the lost production This cost is effectively tripled if equipment has to be retrieved and then re-installed No Subsea Engineer ever wants to see their equipment return to the surface Nevertheless - things go wrong even on a single well - and in a system as large as Akpo, the opportunities for something to go wrong increase Such is the inevitable nature of large Systems The ability to recover and install was seen as vital Design for installation was a vital strategy in the design process This lead to design in order to minimize installation - and retrieval - costs 5) Subsea Processing Systems: Future Vision Abstract To surpass the main challenges established by deep water, high gas-oil flowratios, flow assurance and constant increases in produced water, Petrobras is developing, within PROCAP Technology Program - Future Vision, several projects in the subsea processing area, such as: Compact OilWater and Gas-Liquid Separation Systems, Multiphase Pump with High Differential Pressure and Gas Compression System The main applications of these projects are in fields with high fraction of gas and water, in fields/discoveries located far away from Production Units and to increase the reservoir recovery factor Furthermore, the application of these technologies may have great benefits, such as: production anticipation, reduction of process system footprint on the Production Unit, decrease in CAPEX/OPEX and especially an increase of the topside oil processing capacity This paper aims to present an overview of those technologies being developed in PROCAP - Future Vision Also, this article shows the main motivations of these developments, the main benefits of using each technology, the technological challenges and gaps, typical application scenarios and results of the evaluations performed so far Major petroleum companies are searching for new technical solutions that fulfill their needs of reducing both CAPEX and OPEX while increasing oil and gas production The development of new subsea processing technologies, as stated above, will enable, and in some cases reinforce, the use of these technologies for deepwater and/or subsea to shore scenarios 6) SS: Subsea Well Intervention: Development of a Deepwater Subsea Well Intervention Package Control System Abstract The paper describes the ongoing work, overall approach and process used to develop a deepwater subsea well intervention control system using structured risk and reliability principles and hardware based upon remotely operated vehicle (ROV) control technology It discusses the selection of IEC61508 and IEC61511 as the governing standards for development of the controls architecture and certification of this deepwater well control system It also presents the challenges that have to be addressed when using ROV hardware for well control and describes the methods implemented to overcome system deficiencies The methods used are currently being vigorously applied throughout the control system's development stage to insure the entire control system and not just its components, will be highly reliable, manufactured, tested and certified in accordance with the principles of IEC60508/61511 to a Safety Integrity Level of (SIL 2) 7) SS on Implications of Subsea Processing power Distribution - Subsea Power Systems - a Key Enabler for Subsea Processing Abstract The paper provides an overview of and operating experiences with the subsea power supply systems for the Statoil fields utilizing high voltage power; Lufeng (seabed booster pumps), Troll (oil/water separation, water re-injection) and Tordis (separation, boosting, water re-injection) The paper gives a status on performance of the power system for these projects, and an overview of the most important "lessons learned?? The Tyrihans pump power supply system, which represents the world's longest step-out with topside VSDs and highest subsea motor power, is also briefly presented Future fields utilizing subsea processing at deeper waters and with longer tie-backs will require further development of power system technology and Statoil is undertaking several qualification programs for such applications Status of Statoil's main ongoing qualification programs within HV power is given, including R&D and study activities The overview includes status on all main power supply components such as motors, connectors, VSD, switchgear, transformers and cables/umbilicals within these projects The information provided gives a good overview of "state of the art?? of subsea HV power systems and components within Statoil, and can be useful to both manufacturers and end users of subsea power components 8) SS IMPLICATIONS OF SUBSEA PROCESSING POWER DISTRIBUTION < SUBSEA SWITCHGEAR MODULE - A KEY ENABLING COMPONENT IN SUBSEA INSTALLATIONS> Abstract Subsea high and low voltage switchgear is a key enabling component for subsea process units Locating the switchgear module at the heart of the subsea load center avoids having to provide any top-side facilities, greatly reduces the operation expenditures and reduces the cost of the power lines The subsea environment has a very strong influence on the design, fabrication, assembly and testing of the module, both the enclosure itself and the switchgear equipment inside of the enclosure After the introduction and some general information regarding the subsea switchgear module, the feasibility study and various conceptual design calculations performed during the development of the switchgear portion will be described Since this is the first time that such a large electrical distribution system has been installed in a subsea environment, the main purpose of these studies was to ensure a very high availability of the switchgear to provide power to the process loads Reliability studies combined with mechanical and thermal analyses were performed to ensure correct installation and operation in a subsea environment at about 1000m below sea level Electromagnetic compatibility studies were also performed to avoid any nuisance operations of the switchgear and controlgear which could result in loss of production After the information about the switchgear portion, the design, fabrication and testing of the enclosure itself will be described There are two main criteria for the enclosure The first is the high pressure due to installation on the seabed The second is the requirement for the installation of the switchgear within the enclosure prior to its submersion, and also access to the switchgear during maintenance operations at the surface This criterion requires removable enclosure parts that must have adequate sealing to prevent any leakage when submerged Also very important are the constraints due to the handling of the complete module when installing it and also when it requires servicing Finally the integration of the switchgear portion within the enclosure will be described 9) Husky Liwan Deepwater Subsea Control System Abstract: The Liwan subsea control system located offshore China in deepwater of 1,500 meters is one of the most technologically advanced systems to be installed The control system for Liwan is of necessity large and complex and has incorporated many current industry innovations in control and communications across the system This paper will present a review of the control system and the key components provided for the deepwater Liwan field such as, • Subsea Control Modules (SCM) for Subsea Production Trees and Structures • Subsea Router Modules (SRM) for Manifold, Pipeline End Manifold (PLEM) and Umbilical Termination Units • Subsea Monitoring Module for Corrosion Monitoring System • Subsea Power and Communications Unit located on the Central Production Platform (CEP) • Chemical Injection Metering Valves for the methanol (MeOH), monoethylene glycol (MEG) and Corrosion Inhibitor (CI) distribution at the subsea structures • Umbilical Termination Units for Subsea Distribution • Umbilical Termination Heads for the Infield Umbilical Distribution • Fiber Optic Communications from Topside to the SRM's • High Voltage Direct Current (DC) system to all SRM's and SCM's located on all structures The development and engineering of the Liwan control system will be described within the paper from conceptual design, explaining the control system architecture due to the Liwan field layout complexity of area's Liwan 3-1 and Liuhua 34-2 and their distant geographical locations subsea This paper will also cover the subsea control system fabrication, integration testing and finally installation and commissioning offshore in China 10) Operation Of Subsea Electrical Power Systems Reliable, dependable and cost effective subsea electrical power supply systems have been one of the most important factors in the successful development of the subsea boosting and processing applications and technologies over the last 15 years This paper will provide an overview of how the system and component parameters and ratings have developed over this period In the early days of subsea, there was a lot of skepticism using high voltage equipment under water - today we see that when the design and qualification is done thoroughly, high availability is achieved on subsea electrical power systems Further, a focus on what have been the decisive factors for system design, correlation to the end-load and consequently component selection will be offered An overview of key component qualification methodologies and programs will be described, and finally an overview of operational experience of the existing subsea power systems will be given The end loads have increased in power rating from some hundred kilowatts to multi-megawatts This have obviously had a significant impact on the design and utilization of the power components, such as subsea wet mateable connectors, subsea transformers, variable speed drive units, electrical motors, etc In parallel to the increase in power rating, and consequently voltage and current, the water depths and environments for installation have changed in this time period and have led to increased requirements to pressure withstanding capabilities, cooling and physical robustness 11) Barracuda Subsea Helico-Axial Multiphase Pump Project Abstract PETROBRAS, other operators and suppliers have carried out many efforts to make available the subsea multiphase pump technologies Many of these pumps were installed and are now in operation, including helico-axial pumps However, until now, these pumping systems were limited to differential pressures lower than 45 bar, which is not attractive to PETROBRAS scenarios, since the gas-lift has similar performance Thus, PETROBRAS launched a program to qualify, through flow loop tests and field operation, a helico-axial multiphase pump to differential pressures up to 60 bar The Barracuda field was selected to host the prototype This paper describes the Barracuda helico-axial multiphase pump, including the design phase, qualification process and operational experience so far, involving: installation, commissioning and operation The Barracuda multiphase pump is designed to operate at maximum differential pressure of 70 bar The other main flow characteristics are: liquid flow rates between 2000 and 3000 m3/day; GVF between 35 and 60%; and viscosity between 15 cP and 20 cP The pump is installed at a water depth of 1040 meters and distant 10,5 Km from the P-48 production platform The boosting system is composed by many components, including a flow base, control system, topside equipments, integrated umbilical and subsea motor-pump unit inside the pump module This boosting system was comissioned in July of 2012 and since then its operational performance has been evaluated A description of the main subsystems of the Barracuda Multiphase pump is presented, including their qualification process and FAT tests In order to evaluate the hydraulic performance of the motor-pump unit, a special flow loop test program was established The results of this qualification process and the operational experience indicated that this technology is adequate to be applied in other similar applications Boosting untreated oil is a field proven solution and is coming to the age Efforts to develop high differential pressures multiphase pumps will increase its operational envelop, that will enable its use in important scenarios, accelerating the number of applications and increasing the benefits of this important subsea boosting method The benefits to brown and green fields will be significant, mainly to Campos Basin scenarios 12) Albacora Subsea Raw Water Injection Systems This paper presents the Albacora field Subsea Raw Water Injection (SRWI) systems Application of SRWI involves some challenges, which demand a detailed and systematic analysis in order to evaluate the technical feasibility and establish the requirements to implement this solution This paper describes the evaluation process carried out and details the adopted solutions Furthermore, the system installation and operation are presented The Albacora field is a mature field located at Campos Basin in water depths between 250 and 1100 meters In order to increase the oil recovery, its reservoirs are requiring a significant amount of water injection, what was not considered in the initial phases of the Albacora field development project Technical and economical constraints not allow the use of conventional seawater injection plants, since current production units have no available area to implement a conventional water injection system The selected alternative to overcome these constraints was the SRWI technology, by which seawater is injected in the reservoir with a minimum treatment, using mainly pieces of equipment installed at seabed The feasibility analysis involved studies of the seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, etc The solution was specified based on these studies and included subsea pumps, back-flushing filters, well components and topside facilities In order to achieve required seawater flow rates, the adopted solution considered the use of three subsea injection systems, injecting around 16,500 m3/day in seven wells Waterflooding is still the most common method used worldwide for improving oil recovery The SRWI technology can be an important alternative to inject seawater where it is not possible to use conventional systems, mainly in mature fields The SRWI is expected to generate large economical and technical benefits to the Albacora project 13) Power Distribution for Arctic Subsea Tiebacks Abstract Subsea tiebacks are becomingincreasingly prevalent in oil and gas field developments As the accessibilityof the production from wellheads becomes more difficult, the need for subseacompression and pumping increases Compression and pumping require significantpower which can be distributed and controlled from a HVSS (High-Voltage SubseaSubstation) The viability of an Arctic field development will be determined bythe reliability of all elements in the tieback and in particular, thecentralized subsea power distribution system 14) Subsea Water Treatment and Injection for IOR and EOR The patented SWIT technology enables production and injection of clean sea water directly from the seabed, a flexible and cost effective solution The technology, proven and ready to use, enables a step change in reservoir and asset management, accelerating production and increasing recovery A new test proved that a combination of SWIT and membranes can produce low salinity and sulphate free water for a long time without any degradation in performance The SWIT technology offers a different approach to how reservoir and assets are managed and produced Cleaning the surrounding sea water at the seabed and feeding directly into subsea injection wells is a completely different concept than the traditional topside approach The benefits are significant from many aspects; reduced weight and area required topside; no long reach platform water injectors (WI) required; acceleration of production; increased recovery through flexible and phased deployment of the WI capacity required In 2009 - 2010, a 15 months full scale pilot test was carried out at the seabed in the Oslo fjord The SWIT cleaned water was pumped to shore to NIVA Marine Research Centre for monitoring and testing The results exceeded expectations and documented superior water quality for WI compared to traditional topside facilities The Joint Industry Project (JIP) companies verified the results and technology is ready to be used in field applications SWIT has been approved via technology qualification program with major oil companies The superior quality water from SWIT, including the ability to control the chlorine level very accurately, paves the way for producing low sulphate and low salinity water at seabed A second test proved that SWIT feeding membranes make membranes last very long without any degradation in performance or maintenance requirement SWIT combined with membranes therefore enables low sulphate and low salinity water injection from seabed Currently planning is ongoing to design and build a full integrated sulphate free and low salinity water facility at the seabed 15) Subsea Control And Automation: Evolving For the Future ABSTRACT Increasingly complex machinery is being installed on the seafloor for applications such as subsea separation, gas compression and boost pumping The oil and gas industry faces a significant challenge to ensure that this higher complexity equipment achieves the required operational efficiency and availability Control systems are a key element in addressing this challenge The next generation of control systems must provide superior availability, lower lifecycle costs and superior performance Other industries faced with similar increases in complexity and the demand for very high reliability have evolved solutions to manage the challenge Several evolutionary themes recur across these industries, and they include: Significantly more sensing and control technology embedded in these control systems Software enabling many operation and maintenance functions to be automated rather than manual Information from operation and maintenance processes being transported to decision-makers independent of their location Some solutions created in other industries to achieve these objectives can also be applied to the subsea environment; these solutions can be adopted rather than reinvented (Examples include smaller, lower cost electronics, networkbased architecture and configurable hardware.) Challenges unique to subsea control systems include packaging technologies and subsea connection techniques, and these elements require invention rather than adoption Successful designs will yield lightweight modules that are suitable for subsea exchange by remotely operated vehicles (ROVs) and autonomous underwater vehicles (AUVs) Such modules will be less expensive to manufacture than conventional subsea control components The combination of adopted and invented technologies will make the next generation of subsea control systems connected, configurable, modular and serviceable 16) API 17G Specification for Subsea Well Intervention Equipment This paper describes the long awaited third revision of API 17G as it migrates from a Recommended Practice to a design and equipment Specification The revision provides a systematic approach for the design and operation of through BOP/drilling riser and open water completion/workover riser systems, and also provides the "boilerplate" from which ancillary recommended practices for emerging well intervention equipment and methods can reference common and standard requirements The specification updates design guidelines addressing: safety analyses, intervention planning and identification and testing of well barriers, including performance requirements for specific hardware and provides updates to global and local stress analyses The author’s focus is to provide the reader with guidance to navigate the document The updated specification is intended to illustrate current technology and design practice along with structuring its format to accommodate future intervention technologies and hardware It is also intended to provide the necessary safety review and campaign planning tools being asked of the offshore community in the realm of well intervention and workovers, similar those now being incorporated into offshore floating drilling practices The paper overviews the new Specification assisting the reader in navigating the lengthy document The results of the paper will be a simplification of the Specification and an in-depth understanding of the safety philosophy and strategy which is the core upon which the analysis and material specifications are based, extending the systems capability to deeper depths and harsher operating conditions The document stops short of addressing HP until the task group has time to review and incorporate API 17TR8 Establishing this set of standards will be crucial for industry safety and meeting regulatory scrutiny 17) Emergency Supply of Subsea High Pressure Control Fluid Six Shooter Abstract An overview of the design and functionality of the Oceaneering subseaaccumulator or Six Shooter is provided The Six Shooter was developed as asolution to the historical challenges of BOP emergency intervention ROVtooling for subsea Blowout Preventer (BOP) intervention has been limited tosmall hydraulic pumps which require substantial amounts of time to operate BOPrams With faster closing times recommended for emergency intervention,supplementary accumulated volume is required subsea The Six Shooter can belaunched from a support vessel, IMR vessel or Rig, eliminating the need forcostly Rig or BOP modifications The unit can be deployed onto a customdesigned mudmat or an existing structure When deployed, the Six Shooter would allow a ROV (Remotely Operated Vehicle) ofopportunity to function and provide high flow (100 gpm) and pressure (5000 psi)to the BOP via a flying lead At these flow rates, the industry standardspecifications of 45 second ram closures can be obtained Equipped with dual regulators, the output pressure of the Six Shooter can beselected with the turn of a ROV valve Depending on the number of BOP functionsthat need to be closed during an emergency situation, additional units can beeasily added with standard high flow flying leads to increase the usablevolume The subsea accumulators are constructed with materials that allowdependable and repeatable functioning over long exposures to a subseaenvironment 18) Development and Qualification of a High Differential Pressure Subsea Pump Abstract Growing global demand for hydrocarbons has forced key operators to expand field developments towards deeper waters and remoter areas with increasing step out distances At the same time, brownfields already in production are facing high water cut and low reservoir pressure; these scenarios have created a demand for more powerful subsea pump systems FMC Technologies and Sulzer Pumps have jointly collaborated to develop a new multiphase pump system This new solution is a helico-axial pump that is driven by an innovative 3.2 MW permanent magnet motor (PMM) This subsea pump is distinguished by its high power and efficiency, with a design optimized for the seabed environment PMM technology has been applied and proven for topside and onshore applications but now is also qualified for subsea use The key advantage of using PMM is the high power density, the ability to operate at higher speeds and improved efficiency in a more compact design compared to traditional induction motors, these key differentiators are of significant benefit to subsea processing production schemes The pump unit proven during the qualification program was designed for water depths of up to 2000 m [6562 ft], internal pressure rating of 345bar [5000 psi], and a design temperature of 80°C [176°F] and furnished with helico-axial multiphase hydraulics and a highly tolerant waterbased barrier fluid (coolant/lubricant/motor pressurization fluid) Radial hydraulics are also available, as well as a combination of helico-axial and radial (hybrid hydraulic) depending on gas volume fraction (GVF) A full size subsea pump system, complete with motor, pump cartridge, fluid conditioning system, process control and additional systems was engineered and constructed and installed at a purpose-built pump test facility able to simulate multiphase field operational conditions The initial qualification test program of the 3.2 MW, 5000 psi multiphase pump module is now complete and complementary system endurance testing is reaching conclusion This paper presents an overview of the key features of the pump and motor system, and the qualification program to which this boosting system was subjected The paper also will describe case studies and the pump selection criteria for these scenarios 19) Qualification, Verification and Validation of Novel Subsea Tooling Abstract This paper describes the design, development and testing of a set of diver operated subsea tooling used to resolve a unique issue that occurred during the construction of two subsea wells installed by Esso Australia in 95 metres of water, off the coast of south-eastern Australia By following a structured and rigorous process of qualification, verification and validation it was possible to successfully develop the required tooling on a fast track basis in order to meet the schedule constraints of the on-going diving support vessel campaign A Western Australia based company with design and manufacturing capability and demonstrating expertise in the development of comparable customised subsea equipment was selected to supply the required tooling A considerable number of technical solutions were evaluated during the concept development phase prior to selecting a single optimised concept and finalising the design of the tooling Comprehensive onshore testing of the tooling and involvement of the diving personnel were essential steps in maximising the probability that the offshore operations could be executed in a safe and efficient manner As a result of these efforts the tooling operated flawlessly in the field and a multi-million dollar re-drill campaign was avoided This paper focuses on the steps undertaken in each part of the qualification, verification and validation process, in order to use this work as an example of the activities that are typically involved in each of these steps, and thus provide a roadmap for the application of this process in other time critical, high consequence situations 20) A Classification Society´s Experience with Subsea Mining Abstract Growing interest in deep water minerals resources is providing opportunities for both the mining and oil industries Exploration and production of ocean minerals require synergies between different technologies In this context appropriate standards are needed to cover both new equipment and existing equipment that may be subject to changed service conditions This paper covers ABS’ experience with related equipment such as deep sea oil and gas, certification of equipment as per existing API requirements, manufacturer’s Specifications and Coastal Administration’s requirements 21) Application of a Grouted Sleeve to Remediate Damaged Subsea Pipeline Abstract This paper describes the method and equipment developed to allow ROVinstallation of a groutfilled reinforcement sleeve on a damaged 18" subsea gaspipeline at a water depth of 2,300 ft The Williams Canyon Chief pipeline wasdamaged by an anchor drag that pulled pipeline approximately 1,500 feet out ofits original right-of-way, bent the pipeline to an unknown radius, and left asignificant dent in the side of the pipe as well The damage did not result ina leak and the pipeline was allowed to continue to operate at not only areduced pressure, but also a minimum pressure, while repair plans weredeveloped Extensive research and testing determined that the pipeline could be returnedto normal operating pressure and ultimately maximum design pressure if the dentcould be restrained from flexing due to changes in pipeline pressure.Laboratory testing confirmed that cement grout inside a steel sleeve installedaround the dent would provide the necessary reinforcement A specially designed, ROV friendly repair sleeve was developed to match thepipeline curvature that was estimated by side scan sonar imaging andphotogrammetry The sleeve was fabricated as a straight cylinder but the endswere angled and positioned off-center to account for the pipeline curvature.The sleeve was split horizontally so that all clamping screws were vertical Anarticulated spreader bar, ROV operated pull-down winches, and a large syntacticbuoyancy module allowed the ROV to control the entire installation after theequipment spread was landed on the seafloor A project specific metrology tool that measured the curvature of the pipelineat 24 points was built and landed on the pipeline to confirm earlier calculatedestimations An ROV video record of the gauge readings was then used in theshop along with the metrology tool to fabricate a dimensionally correct mock-upof the pipeline This mock-up was then placed into the repair sleeve to confirmthat it would fit on the pipeline 22) Completion Design for Sandface Monitoring in Subsea Wells Summary The expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run The objective of a recent engineering development program was to create a new deployment system that addressed these constraints directly Instead of individual gauges on mandrels, digital sensors were miniaturized and distributed along a single spoolable bridle In addition, a novel inductive coupling mechanism was developed to pass power and data from the upper to the lower completion In a recent subsea deployment in southeast Asia, such a coupler was attached to the top of a sensor bridle and both were deployed as part of an openhole gravel-pack completion Standard packers and gravel-pack service tools were used The system became activated when a mating inductive coupler was landed as part of the upper completion Surface indication of landing was provided by incorporating mechanical feedback into the lower assembly With the coupler components in position, the tubing hanger was landed into the horizontal tree Upon activation of the electrical penetrator, high-resolution temperature data were then immediately available across the length of the sandface, which was an industry first for a subsea producing well No additional penetrations were required in the tree Development of this system required coordination from the operator because of the multiple vendors involved in the project They supervised multiple qualification and systemintegration tests performed over the 2-year development period to ensure ultimate success in the subsea deployment Field results showed that the mating inductive couplers provided high-efficiency of power transmission so that industry-standard power settings were sufficient to power a bridle with one sensor per joint of screen The sandface data were available onshore during the cleanup phase, allowing the operator to monitor the cleanup in real time Once the wells are brought on line, the sandface data will further enhance the interpretation of flow allocation and reservoir drainage 23) Subsea Processing: A Holistic Approach to Marginal Field Developments Abstract Description The application of Full Subsea Processing (FSP) to develop remotely locatedmarginal fields in Offshore West Africa is an attractive option for breakingthe techno-economic barriers which have long hindered the development of thesefields Some of the fields have remained marginal and unproduced over theyears, arguably, due to incorrect estimates in recoveries and economicsoccasioned by erroneous estimates in basic input parameters Therefore, theright method of application for developing marginal fields must be sought toensure that both National and International Operating Companies partake in thedevelopment of these fields The present paper explores the use of full subsea processing technology todevelop marginal fields economically 24) Subsea Processing and Boosting in Brazil: Status and Future Vision Abstract Subsea processing and boosting can be key enablers or optimization alternatives for challenging field developments and their benefits increase with water depth, flowrates and stepout Petrobras has invested a lot on the development of such technologies, supported, among other pillars, on an aggressive R&D policy through its technological programs like PROCAP, and several subsea processing and boosting systems have successfully operated in Petrobras fields Considering that, these technologies are being considered for application in potential Petrobras' scenarios including mature and green fields This paper aims to give an overview of the systems developed and applied in Petrobras prospects during the last twenty years, such as the Vertical Annular Separation and Pumping System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water Separation (SSAO) It also reports the new R&D initiatives related to subsea processing and boosting that are being developed within PROCAP - Future Vision technology program, showing the main motivations of these developments, the main benefits of using each technology, the technological challenges and typical application scenarios Also, this paper illustrates the analysis and evaluations performed so far, for all of the new developments presented 25) Improvements to Deepwater Subsea Measurements RPSEA Program: ROVAssisted Measurement Abstract This report documents a project to improve subsea flow measurements to allowthe flow rates of individual wells to be known more accurately, thus reducingrisk to both producers and the US government while also improving reservoirrecovery In this project, a non-invasive metering approach was adopted using aclamp-on meter that may be conveyed to the sea floor using a ROV The goal ofthis project was to develop and prove methods for conveying a clamp-on meter tothe sea floor by ROV, and document the results as a draft standard for thefuture Meters/sensors were marinized for prototype demonstration in surfacemultiphase flow loops and in underwater test tanks 26) Experience to date and future opportunities for subsea processing in StatoilHydro Abstract 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 27) Development of a High-Boost, High-Power, Ultradeep Subsea Twin Screw Multiphase Pump System Abstract Between 2005 and 2010 Shell has been working with Flowserve and other specialty contractors to develop a next generation pumping system requiring a complete review and redesign of all major components The work has been performed at multiple locations in Europe and the Americas by an integrated team It has now reached the level of maturity that it can be shared within the industry In 2004, Shell performed a comprehensive assessment of industry capability for subsea pumping This study concluded that boost pressures available at the time were insufficient to meet future project needs, particularly for ultra-deep, heavy oil applications with large gas volumes As a result the high boost, high power, ultra-deep twin screw multiphase pump development was initiated The development included building and testing the subsea twin screw pump, a submersible motor, subsea electrical high power connectors, a pressure compensation system and high bandwidth fiber optic health monitoring system in addition to a purpose-built high capacity test loop The project is now reaching its conclusion with integration of the core components due to take place by the end of 2010 Individual components such as the pump have already been tested up to MW shaft power, 2400 psi differential pressure, flow rates up to 90,000 barrels per day, with viscosities ranging from - 2,000 centipoise, an order of magnitude greater than any similar existing machine This paper describes the work performed, the major challenges addressed and the methodology used to overcome them One particular challenge was the implementation of rigorous HSE requirements for such high energy, heavy equipment 28) The Development of an Instrument Measuring Pressure behind the Casing in Subsea Production or Injection Wells Abstract This paper presents the results from a long term development project to produce an instrument that measures pressure behind the casing in subsea production wells: online and in real-time Such an instrument will be an important application in protecting well integrity, where effective cement seals behind the wellbore casing provide a barrier against the high pressures encountered deeper in the well Poor or deteriorating cement sealing and/or loss of casing integrity can allow oil or gas to migrate vertically towards the surface along the outside of the casing which can lead to a number of unwanted and potentially hazardous conditions To this end, an instrument that detects any variations in pressure behind the casing will provide early warning of these conditions and allow intervention or other remedial actions to be planned and implemented in a timely manner The instrument also has a health & safety application in verifying the integrity of the B annulus Two challenges to be overcome were the need to avoid any penetrations in the casing string, thus maintaining its full pressure integrity, and the requirement to provide power to instrumentation behind this casing without using batteries The paper will describe the development process, technology choices and laboratory testing of the instrument It will also describe the applications and limitations of the new system, which has been developed as part of a joint industry project with Statoil (who co-author the paper) in competition with other instrument vendors The paper will be highly significant for oil and gas operators planning subsea production or injection wells and for government regulating agencies in i) improving well integrity; ii) meeting safety and environmental protection; and iii) in the development of a new technology instrument not previously available on the market 29) SS: Marlim Phase Subsea Separation System: Controls Design Incorporating Dynamic Simulation Work Abstract This paper describes the control system design for the Marlim three phasesubsea separation system (SSAO) and how the standard subsea control system hasbeen adapted for the new requirements for automated control This is the mostadvanced subsea process system to date with several "first ever" applicationsof separation equipment subsea: harp, pipeseparator, desanders andhydrocyclones The SSAO has a total of control loops and a number of complexautomatic sequences Further, the paper addresses how dynamic simulation analysis has been used tovalidate the process control strategy and improve the operational proceduresdesigned during the basic engineering phase Control and operation of the SSAO has proved to be very challenging for severalreasons: • There are strong interactions between different process components • The system dynamics are stiff due to small liquid hold-ups and low GOR in thesystem • The pressure drops of inline cyclonic equipment need to be balanced to ensureoptimal performance • Constraints in valve opening/closing speed and the importance of limiting thenumber of valve movements put restrictions on controller performance • Instrumentation is limited compared to topside facilities The content described above contain several new aspects compared to atraditional subsea control system and this paper will describe systemconsiderations with regards to implemented process control and also theimportance of using dynamic simulations as a design tool 30) Challenge and Solution of PanYu35-2 Subsea Manifold Design Fabrication and Testing Abstract As one of the main equipments of South China Sea Deep Water Gas Development project, PanYu35-2(PY35-2) subsea manifold provides a support for the connection of 6” and 10” pipeline in the pipeline route, and also provides a support for the field pigging and pressure test The manifold is connected with two production wells, and considering the commercial benefit of client, one spare hub and four spare valves are provided in the manifold system for the future wells During the design fabrication and testing, there are lots of challenges In the paper the design fabrication and testing of PY35-2 subsea manifold were presented, and the challenge and solution during the manifold development were presented as well These can provide a good reference to the subsequent project in South China Sea 31) Use of a Parallel System For Improving Subsea Intelligent Well Control, Monitoring And Reliability ABSTRACT The issue of improving monitoring and control of subsea completions while maintaining high reliability is critical due to accessibility and intervention costs Hydraulic control of the downhole choke valves in multiple zones can be complex, and the situation is further complicated by the fact that traditionally different companies supply the downhole completion equipment and the tree control system at the wellhead This can lead to less production data being available, reduced control functionality and valve control logic issues Additional interfacing requirements also lead to an increase in costs for a project This paper details the design approach, application and advantages of a dedicated intelligent well completion (IWC) control system for subsea fields It also reviews the methodology and issues related to the integration of the control system within an existing field development in the North Sea The proposed system has an electrohydraulic control module, provided by Schlumberger, mounted on a subsea production tree, which provides complete control and monitoring of the intelligent well independent from the tree control system This approach allows the intelligent well subsea control system to be tailored specifically for the completion equipment and well type It also provides additional protection to the tree control system from control line thermal expansion and the potential of leaks The subsea solution selected by the client aims to reduce the loading and project-specific customisation of the production critical tree control system This will allow it to be standardised while still providing maximum performance and flexibility for monitoring and control of the well This approach permits a single supplier, in this case Schlumberger, to manufacture and test the complete intelligent well control and surveillance system from surface to the subsea well prior to delivery and the site integration test (SIT) This reduces the overall project risk and avoids interface issues being detected late in the project phase 32) Integrated Control System & Human Machine Interface - Challenges for Uninterrupted Onshore & Subsea Operations Abstract The health and effectiveness of any Integrated Control System depends on many factors Among these factors is the proper design, selection of Control System, seamless integration, System Architecture, System Configuration, System Integration Testing, Control System Installation, Commissioning, Site Acceptance Test, Preventive Maintenance, Predictive Maintenance, Functional Testing etc The integrated solution for the Onshore, Offshore & Subsea Control System includes a dedicated Subsea Control System, DCS System, ESD System, Process Simulator System, F& G System, Large Screen Abnormal Situation Management Video Wall, Measurement Systems etc The power to the Offshore and communication to Offshore & Subsea is through Umbilical's The backup communication from Onshore to Offshore is through dedicated Microwave Network The communication from Onshore Terminal (OT) Control Room to Subsea wells is about 50 Km to 60 Km The remote Subsea wells are Controlled and can be Shut down from OT The best-in-class technologies in Control & Safety was effectively implemented by deploying various protocols like Foundation Fieldbus, HART, Control Net, OPC, MODBUS TCP I/P, Serial Interface etc The digital Control System reliably monitors and controls the over 1, 10,000 tags All the DCS hardware is integrated with the non DCS hardware while having a common control system information The System has the facility to provide information across the organization giving the best possible foundation for collaboration between people, processes and systems In such a large network of integration of technologies & integrated operations of Subsea & Onshore, identifying and minimizing control system errors are a big challenge It is a big challenge to ensure continued operations of these facilities without any Trips This article focuses on Control & Instrumentation Systems contributing factors for uninterrupted Operations of Onshore/Offshore/Subsea facilities during the first 1033 days of operations & the challenges to ensure continued operations without any facility Trips 33) Controls Reliability And Early Life of Field Failure of Subsea Control Modules Abstract Subsea control systems are becoming more complex As they are moving into even deeper water, using more complex equipment and collecting more data, the demands on their performance are increasing This has resulted in the need for faster data retrieval, more complex programmable processors, bigger power-hungry devices and continual technological progression Thus whilst there is a desire in each project to keep innovation to a minimum and use only what is tried and tested, in reality the industry is seeing a steady product development and evolution Nowhere is this more apparent than in the heart of the control system''s subsea control module (SCM) It is no secret in industry that the SCM is one of the systems with the biggest reliability challenges Chevron collects all the subsea reliability data in a database called Subsea Master On reviewing the data of the SCM reliability statistics, not surprisingly, Chevron has found them to be one of its principal bad performers Further analysis revealed that SCM reliability was not as high as desired or expected, and attempts to correlate against the various fields and environmental conditions revealed little It appeared that there was no correlation between environmental factors and failure rate, or even the age of the systems and failure rate However one thing clearly stood out, early life failure was a major problem 34) ESP Technology Maturation: Subsea Boosting System With High GOR and Viscous Fluid Abstract This paper provides insight into the Caisson ESP Technology Maturation for subsea boosting systems with high GOR and viscous fluids It will focus on the developmental research on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes The Electrical Submersible Pump (ESP) system is an important artificial lift method commonly used for subsea boosting systems Multiphase flow and viscous fluids cause problems in pump applications Free gas inside an ESP causes many operational problems such as loss of pump performance or gas lock conditions (Barrios 2010 [6]) The objective of this study is to predict the operational conditions that cause degradation and gas lock This paper provides a summary on the Technology maturation for a high scale ESP Multi-Vane Pump (MVP) for high GOR fields to in support of Shell's BC-10 developments These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment This paper will describe the capability and effects of viscosity and two phase (liquid & gas) fluids using a MVP 875 series G470 as a charged pump in a standard ESP system 1025 series tandem WJE 1000 mixedtype pump Extensive testing and qualification of the subsea boosting system was undertaken prior to field considerations Testing was conducted at the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for Shell's deepwater assets This paper describes the subsea boosting system maturity process, and reports the effects of viscosity and two phase liquid - gas fluids on ESPs The test facility work was performed using pumps with ten or more stages moving fluids with viscosity from to 400 cP at various speed, intake pressure, and gas void fractions (GVF, aka gas volume fractions) The testing at Shell's Gasmer facility revealed that the MVP-ESP system is robust and performance tracked theoretical predictions over a wide range of two-phase flow rates and light-viscosity oils 35) API 17TR12 - Consideration of External Pressure in the Design of Deepwater Subsea Equipment This paper will present an overview of the issues which must be addressed by designers of subsea equipment for deep water applications It will describe API guidelines which are being proposed to establish “Depth Adjusted Working Pressure” ratings for equipment, indexed to the water depth where the equipment will be installed A new recommended practice will be presented providing guidelines for how such equipment design should be conducted; using triaxial VME FEA methods, applying applicable load cases, and additional design verifications for protection against other identified failure modes The equipment is to be qualified using testing methods which simulate the effects of external ambient seawater pressure at depth The new “Depth Adjusted Working Pressure” (DAWP) ratings will have a significant beneficial effect, specifically on HPHT projects, where the external ambient seawater pressure at water depth can be used to improve or enhance the equipment maximum allowable internal pressure, allowing the equipment’s DAWP rating to be considerably higher than the traditional API “Rated Working Pressure” (RWP) The authors will propose recommended practices for how to equipment may (and should be) designed and qualified to take into account the effects of external ambient seawater pressure Using the proposed design, analysis and testing methods will result in an optimized equipment design which is lighter, less expensive, and more efficient equipment for high pressure projects in deep water applications Using the recommended methods for including external pressure in the design of deepwater subsea equipment can result in significant wall thickness optimization for pressure-containing components and connectors Maintaining an optimized wall thickness will result in valuable savings in size and weight, improves the reliability of heat treating and welding operations, and reduces the suspended weight for equipment installation operations (which can be a significant issue for projects in deep water) In many cases, by using the new Depth Adjusted Working Pressure ratings, one can avoid the need to jump to the next higher API RWP category for deepwater HPHT projects where internal pressures may only be moderately above the current API RWP category 36) Integrated Operations and Integrity Management: Subsea System Vendors as Value Added Providers Abstract The recent resurgence of interest in Integrated Operations (IO) and Integrity Management (IM) for the oil and gas industry has triggered necessary discussions of why revisiting these ideas and initiatives is important to the future of the industry By implementing IO and IM programs and initiatives, operators gain an advantage in achieving increased recovery, reduction of operating expenses (OPEX), efficiency in execution, and optimization of asset availability More than ever, the operator is held accountable by company stakeholders to determine rationalization when implementing any new program This paper is to provide supportive rationale that the operator needs in choosing the subsea system provider as the best equipped to develop the intelligence engine driving its IO and IM programs The key to a successful IO and IM program design and implementation lies in the provider's proven history of experience and competence in the areas of well completion, production flow management, power distribution (hydraulic and electrical), controls (subsea and topside), installation, intervention, and life of field services and support On both the technical and logistical sides of IO, expertise in these areas lends to the provider a better comprehension and applicable tools essential to the successful and effective implementation of a real-time diagnostics system and the associated support services program, including: 37) Merging ASME and API Design Methods for Subsea Equipment Up To 25,000 PSI Working Pressure Abstract A current challenge in the oil industry is the design of subsea equipment forpressures more than 15000 psi Current standard, American Petroleum Institute,Specification, 17D (API 17D) for designing subsea equipment is limited to 15000psi working pressure One of the key recommendations of API TR PER15K (draft)is the utilization of the American Society of Mechanical Engineers (ASME)Boiler and Pressure Vessel Codes (BPVC) for designing pressure vessels forpressures above 15000 psi This paper proposes a design methodology combiningthe relevant API and ASME design codes for the design of subsea equipment forpressures more than 15000 psi Specific guidance is provided in this paper to safely utilize the ASME designmethods with API materials These approaches allow for the increase of ASMEdesign test pressures to match API while satisfying ASME and API designallowable limits Methods and guidance are provided for the use of stressclassification, stress linearization, protection against general plasticcollapse, local collapse, buckling and cyclic loading Recommendations are madefor Load Resistance Design Factors to accommodate the difference in hydrostatictest pressure between ASME and API Additionally, approaches using bothtraditional stress-based fatigue analyses methods and fracture mechanics theoryare compared The design of closure bolting conforming to API requirements isintegrated with the ASME methods, along with the recommendation ofnondestructive examination (NDE) requirements to align with the recommendedstress and fatigue design factors An example design evaluation of a pressure containing API 6A, in 20 ksi type6BX flange is presented for a design pressure of 20000 psi with bolt preload asrecommended in API 17D The results show the existing API methods are adequateup to 25000 psi and the design verification methods meet the recommendations ofAPI TR PER15K 38) Transforming Raw Subsea Sensor Data for Advanced Dynamic Positioning and Autonomous Functions in Real-Time for Asset Management and Remotely Operated Vehicle Operations Oil and gas exploration is moving towards deeper waters, challenging geographical areas and dynamic working environments This paper outlines the technology developments in an advanced control system embedding intelligent algorithms with sensor data in a closed loop, to perform various IRM tasks autonomously on a workclass remotely operated vehicle (WROV) Original analysis and field trial results are presented The data from the navigation sensors can be used to position and geo-reference the payload data, however, survey has relied upon expert piloting skills to maintain the WROV on a set course at a predetermined speed, heading and height from the seabed In response to emergency situations, the equipment is hard to mobilise and the investment can be compromised if the WROV cannot be made to steer the course This paper presents novel work in developing an autonomous control function suite integrated on a WROV to maintain a pre-laid course and offer a stable platform to gather data, and perform a task Combined navigation functionality fuses data from GPS string, imaging sonars and a state-of-the-art phased array Doppler Velocity Log (DVL) with a Dynamic Positioning computer Operators are equipped with the tools to survey and inspect their environment in a compact, easily deployable form factor This development highlights vehicle and umbilical positioning, movement logging, advanced vehicle controls (sophisticated cruise, mission planning and object/target recognition modules) and increased reliability The Dynamic Positioning computer translates high-level mission requirements from a surveyor into automatic thruster commands providing automatic inspection and survey Results from a selection of trials conducted with a major subsea operator using the system will be shown The results demonstrate improvements in WROV control during transit, station keeping and conducting simulated riser inspection - via easy-to-use human-machine interface The advance controls offer significant reduction in time and costs, and increased reliability, compared to pilots performing operations manually The technical industrial contributions of this technology are reduced training costs, mitigating lump sum risks by saving time in construction support operations, maintaining the quality and reliability of drill support operations, improving the quality of data for survey and IRM activities and providing better umbilical management 39) Successful Placement of an Advancing Sand and Fines Control Chemical as a Remedial Sand Control, using Subsea Flow Lines from an FPSO The ENI Nigerian subsidiary operates a subsea field located in the north western sector of the Nigerian offshore deep-water, is an oil and gas producing field The production is from subsea wells which are directed to a Floating Production, Storage and Offloading vessel (FPSO) All the wells in this field require sand control measures in the reservoir section from the onset to prevent sand production Sand control in the field is challenging and various methods (gravel pack, frac pack and expandable sand screens) have been used Conventional sand control integrity has failed in one of the wells, compromising production rate and exposing subsea asset to risks related to sand production Compared to heavy workover required for primary sand control application, an advancing chemical treatment bullheaded through the subsea flowline and the production tubing provided a unique, highly economical, and effective solution to this challenging problem The product effect creates an ionic attraction between the sand grains and fines, using non-damaging water-based fluid The chemistry mitigates sand production, reduces or stops fines migration and increases the Maximum Sand Free Rate (MSFR) After pumping chemical treatment through a 4.2 km flow line in the failed frac packed completion, well returned to production with minimal sand presence, less than 24 hours NPT and eliminating the need for re-completion This was the first time the chemical had been pumped from an FPSO and through subsea flow line This paper discusses the planning, execution, post job analysis and lessons learned 40) Control System Upgrades for Tordis and Vigdis Field - A Project Case Study of Revitalising Brownfield Developments with Next Generation Subsea Controls Abstract Since the 1980s, multiplexed electro-hydraulic control systems have been successfully employed in subsea oil and gas production With field lives extending, and the original equipment becoming more difficult to maintain, particularly because of electronic component obsolescence, it is possible by applying new generations of control system equipment to bring enhanced controls capabilities into brownfield developments From the inception of the Tordis/Vigdis Controls upgrade & Modification programme (TVCM), it was seen that a number of the design limitations of the legacy system could be overcome when upgrading to a modern and flexible communications system with standard comms interfaces There were some specific limitations of the installed system, and in addition, for the legacy system, electronic component obsolescence was becoming an increasing burden in support of continuing production Following the completion of the upgrade under the TVCM programme, the new system will deliver significant step-changes in the performance envelope of the overall Control and Instrumentation System, including improved reliability, a new configuration employing ‘Open' communications protocols between topsides and subsea with the communications bandwidth available to the Tordis producer wells upgraded to 1Mbit/s A novel feature, and a key success factor for the project, is the use of Subsea Control Module interface adapters 41) A Innovative Liquid Detection Sensors for Wet Gas Subsea Business to Improve GasCondensate Flow Rate Measurement and Flow Assurance Issue In subsea business, the use of wetgas flowmeter is becoming a standard for deep and ultradeep field development The business growth is outstanding over the last few years and it is expected to continue at the same path Furthermore, the tieback of these fields to hosting platform or onshore facility has increased drastically The critical measurement is not only on high accuracy flow rates but also on water detection with 99.x% of the production being gas The liquid is initially predominantly condensate phase continuous before becoming more watery with the well ageing Water is the main concern either in presence of H2S or because hydrate could be formed and will plug the production line To counterbalance these catastrophic scenarii the chemical use is necessary, but the cost leads to loss of benefit, therefore an optimization is necessary The need for a reliable water detection became a compulsory practice with constraint to be working initially in oil and water continuous phase The innovative solution describes in this paper look at how an accurate measurement could be offered at any GVF and WLR based on the use of two different types of measurement having a different response to the water-hydrocarbon contrast and water conductivity sensitivity.This approach led to a development of an innovative add-on on the wet gas meter which provides a high accurate local water fraction measurement that can be comparing with a global measurement This paper is focusing on the explanation of this innovative analysis after 10 years of work in this direction, and the value brought to oil/gas operator in detection of water and then optimizes the use of expensive chemical It is also possible to identify clearly, if the water is coming from the formation or not in any WLR mix It addresses also the use of MPFM beyond the classical metering flow rate performance and focus on the benefits of brought for a subsea flow assurance and reservoir management 42) The Ormen Lange Langeled Development Abstract This paper provides a summary of the challenges of executing the Ormen Lange Langeled Project Hydro is the operator responsible for the planning and development phase After Ormen Lange comes on stream in October 2007, Shell will take over the operatorship and be responsible for the operational phase This paper introduces three main features of the execution phase of the project: The Ormen Lange offshore development, the Ormen Lange onshore development and the Langeled gas export system including gas receiving facility in the UK This paper also addresses managerial perspectives concerning HSE, quality and risk management, and procurement management 43) Ormen Lange Pipelines - Geotechnical Challenges ABSTRACT The selected development scenario for the Ormen Lange gas field is a subsea tie-back to an onshore terminal located at Nyhamna in Mid-Norway There are large variations in soil conditions along the 120 km long pipeline routes from shore to the template area In narrow valleys in the near shore area one of the main challenges was to find enough space for installing all pipelines within the same corridor The severe seabed requires rock supports for free span mitigation of the gas pipelines both near shore and in the deep water area For the service lines, protection against trawling and dropped objects was required along the entire length and this turned out to be particularly challenging at the steep Storegga slide slope and in the rough terrain at the deep water area with soil shear strength of kPa The quasistatic stability of rock supports higher than 0.5 m was not satisfactory for the 10-2 earth quake load event due to the soft soil conditions A deformation criterion was therefore applied both for the 10-2 and 10-4 earth quake load events 44) Ormen Lange - Flow assurance challenges Abstract Ormen Lange is a gas field located 100 km off the Norwegian coast in water depths varying between 850 and 1,100 meters The selected development scenario for Ormen Lange is a subsea tie-back to an onshore processing facility at Nyhamna The field is located in a prehistoric slide area with varying water depths, from 250 to 1,100 meters The result of this subsea slide is an extremely uneven sea bottom with local summits 60 to 80 m high The back wall of the slide is steep, up to 26 degrees Environmental conditions are also challenging This paper describes the flow assurance challenges and technical solutions selected due to the harsh environmental conditions specific to the Ormen Lange development, including: Rough seabed combined with long tie-back distance Sub-zero temperatures (-1° C) All together, this makes the Ormen Lange project one of the most challenging field developments worldwide with respect to flow assurance 45) Slope Stability At Ormen Lange Abstract The Ormen Lange gas field is located in about 900 to 1100 m water depth in the slide scar of the enormous Storegga Slide that occurred about 8000 years ago The slide left steep and high headwalls above and below the planned field development area Today's stability of the headwalls is a major concern for the field development work The area under consideration is large and has been mapped extensively with 2D and 3D seismic profiling The number of geotechnical borings is limited and integration of geological, geophysical and geotechnical information was required to develop a geotechnical model of the area Stability analyses have been carried out for critical sections of the headwalls These involved long-term drained analyses under gravity loading and undrained analyses considering the effects of earthquake-loading and possible Influence from field installations like rockfill supports for pipelines and anchors Focus has been set on explanation of slide mechanisms involved in the Storegga slide and comparison of the stress-strain-strength conditions in the headwall at the tune of the slide and today Work is still ongoing and under review and the conclusions presented here are thus to be considered as preliminary 46) Ormen Lange Subsea Compression Pilot Abstract Ormen Lange is a long tieback gas field developed with gas processing facilities onshore 120 km from the production wells The development strategy is to deplete the reservoir In order to maintain the production plateau for as long as possible and recover the anticipated gas and condensate resources, offshore compression is required at a later stage This paper describes subsea compression as a cost effective alternative to the platform compression solution and the strategy for qualifying subsea compression system at the time of offshore compression concept selection This paper further describes the subsea compression technical solution 47) Ormen Lange Subsea Production System Abstract This paper presents the concept and the technical solutions developed and applied to the Ormen Lange subsea production system First, the key technical challenges related to the subsea system are presented Thereafter the paper describes the extensive design, fabrication and testing processes undertaken in order to verify correct functionality and gain confidence in the applied solutions Finally the paper summarizes achievements and key success factors for the project 48) Ormen Lange Onshore Processing Plant Abstract The Ormen Lange Plant at Nyhamna consists of well stream processing, gas export compression and condensate offloading to tankers The gas from the field is conditioned to dew point and heating value according to European specifications, then routed into the export pipeline to Easington, UK, via the leipner field Condensate recovered from the well stream is stabilized and stored in a custom-built rock cavern before being shipped from the terminal Gas and liquid products are metered to fiscal standards before being exported The process facilities at Nyhamna consist of two gas conditioning and dehydration trains, three export compressor trains and one condensate stabilization train The plant processing capacity is 70 million standard cubic metres per day (MSm 3/d) of sales gas at an initial arrival pressure of 90 bar Maximum condensate production is estimated to be 7000 Sm 3/d Before construction could start, a massive civil works task was performed, blasting more than million m3 of rock in order to prepare the plant site and build storage caverns The construction and installation of steel structures, buildings, pipes, cables and equipment continued throughout 2006, while in 2007 the main task will be to test out the plant before starting production 49) Ormen Lange Subsea Production System Abstract To ensure adequate safety of marine structures in extreme weather, it is conceivable that standards are needed that account for the characteristics of ultimate limit seastates based on wave conditions with a return period higher than 100 years Such standards must include an analysis of the reserve strength available when a marine structure is subject to an extreme event of a freak wave For the generation of freak waves traditional potential flow methods are not well suited to accurately predict wave loads, because phenomena such as wave run-up on the structure's legs and impact-related loads on the hull are not accounted for Therefore, wave effects were predicted with advanced computational fluid dynamics techniques The purpose here was to determine the safety level under freak wave conditions We selected a typical mobile selfelevating drilling unit stationed the North Sea and investigated its structural response under survival conditions and, in addition, under two extreme wave conditions representing freak waves Based on a comparison of the resulting stresses with the structure's rule based design capability, we assessed the reserve strength capacity still available under freak wave 50) Ormen Lange-Challenges in Offshore Project Execution Abstract Ormen Lange is the second-largest Norwegian gas field and was discovered by Hydro in 1997 The Ormen Lange field comprises an offshore subsea solution approximately 125 km off the west coast of Norway, an onshore gas processing and export facility at Nyhamna, a gas export transportation system between Norway and the UK, and the Easington gas reception terminal in the UK The Ormen Lange development is divided into three main sub-projects: Onshore, Offshore, and Langeled This paper gives a summary of the Ormen Lange Offshore development, including descriptions of project execution and contract strategy, and how Hydro's competence and systematic work processes have been utilized in order to secure efficient progress The Offshore project will be further described - including the technical challenges of the project -in three OTC 2007 papers: OTC 18965 Ormen Lange subsea production system OTC 18967 Ormen Lange pipelines installation and seabed preparation OTC 18969 Ormen Lange subsea compression pilot as a supplement to the summary provided here ... described There are two main criteria for the enclosure The first is the high pressure due to installation on the seabed The second is the requirement for the installation of the switchgear within the. .. protocols between topsides and subsea with the communications bandwidth available to the Tordis producer wells upgraded to 1Mbit/s A novel feature, and a key success factor for the project, is the. .. screen The sandface data were available onshore during the cleanup phase, allowing the operator to monitor the cleanup in real time Once the wells are brought on line, the sandface data will further