Offshore wind is now a well-established technology in Europe with 12,631MW installed capacity from 3,589 grid connected wind turbines in 10 countries. The technology is now expanding in to new markets in North America and the Far East. This growth is being fuelled by the reducing cost of offshore wind generation with the first subsidy free projects now in development in Europe. In these markets offshore wind will be a lower cost and more environmentally friendly means of generating electricity than gas. This cost reduction has been driven by a number of factors but three important ones are discussed here together with a number of lessons learned from recent projects. The wind turbines are steadily getting bigger. Larger turbines mean that fewer need to be installed for a given project size. The average size of a grid connected turbine in 2016 was 4.8MW but the future subsidy free projects will require turbines closer to 15MW. This means larger foundations and heavier turbine components need to be installed. There is a significant degree of standardisation and repetition in the installation of offshore wind. High levels of repetition mean that a greater investment can be made on installation techniques, installation aids and procedures than would normally be seen on a one off project. This in turn places a higher demand on production and installation engineering than experienced on oil and gas projects. The cost of project finance has come down significantly. These projects are very large and most Utilities will no longer finance them off balance sheet. Therefore the bankability of projects is critical to the developer in reaching financial close. Based on recent successful project delivery there is a broad range of investors willing to provide finance. However, the financiers and their technical advisors set the risk levels, contracting strategy and very often the construction methodology. Trends in offshore wind projects and lessons learned from recent projects are discussed.

The journey towards the realization of the subsea factory is well on its way, promising the benefits of subsea processing and production. This "Grand Challenge" places extreme demands on the reliability, uptime and safety of the technology for distributing, delivery and control of the power system. ABB Oil & Gas is running a Joint Industry project together with Statoil, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion at greater distances, in deeper waters, and in harsher environments. The project started up in 2013 and is targeting a 3000-hour shallow-water system test in 2018, including the qualification of pressure tolerant medium voltage switchgear, medium voltage drives, as well as supporting controls and auxiliary supplies. The project budget is in excess of 100 MUSD, funded by ABB, Statoil, Total, Chevron as well as The Research Council of Norway. The target environment is water depths up to 3000 meters, transmission distances up to 600 km, and power levels up to 100 MW. The project follows the TRL development stages for technology qualification applied to components, sub-assemblies and equipment. This is a systematic approach ensuring that the technology will function reliably within specified limits, and it provides a common understanding and terminology of technology status and risk management. Qualification includes extensive testing of components subjected to test conditions derived from a common understanding of realistic component/equipment specific stresses throughout an agreed life-cycle mission profile, with particular emphasis on learning the behavior and limits of different designs. Comprehensive confirmation of the desired function as well as reliability testing is primarily conducted at the level of the component where a functional failure can be defined and accelerated conditions applied. Further, we perform sub-assembly testing mainly geared toward confirming the overall function, design margins, and the thermal and high-current performance. Formal qualification of key components and sub-assemblies is planned for 2017. Based on qualified components, final prototypes will be assembled in 2018 for a 3000 hour shallow-water endurance test and system demonstration. The project passed a decision gate milestone in April 2015, having verified technology concepts as well as TRL2 for key components. Prototypes under development include full-scale subsea drives and switchgear with supporting controls and LV auxiliaries and functional verifications in key ABB factories. During 2016 key prototype designs have been tested and functionally demonstrated over a limited operating range. This paper provides a summary of the current status of the project highlighting the most critical areas for success, such as designing for modularity and the demanding reliability and availability targets, and utilizing the best experts and experience across ABB as well as the participating oil companies.

2015 represents an important milestone for Statoil as both the Gullfaks and Åsgard subsea compression projects achieved production start-up. The Gullfaks subsea wet gas compression system is projected to increase recovery from the Gullfaks South Brent reservoir by 22 million barrels of oil equivalent. The solution involves two 5 megawatt wet gas compressors that handle a production rate of 10 million standard cubic metres of gas per day. The compressor system is connected to existing subsea templates and piping 15 kilometres from Gullfaks C. The Åsgard subsea compression system is projected to provide 306 million barrels of oil equivalent in increased recovery from the Mikkel and Midgard fields. The solution involves two 11.5 megawatt centrifugal compressors that handle a production rate of 21 million standard cubic metres of gas per day. The compressor system is connected to existing subsea templates and piping 40 kilometres from Åsgard B. The difference in scale and boosting requirements helps to explain why two quite different technical solutions have been selected. This presentation will provide an overview of the two projects including: Why subsea compression The business cases and technology selection The technology assessment and qualification. The execution program for the projects including engineering, procurement, construction, testing and installation. Commissioning and start up Future subsea compression opportunities

The Åsgard Subsea Compression (ÅSC) project has since project sanction in 2011 engineered, constructed, installed and commissioned the world's first Subsea Compression Station (SCSt). The ÅSC SCSt includes two individual compressor trains, each containing an 11.5 MW centrifugal compressor module, condensate pump module, scrubber module and inlet- and discharge cooler modules. The compressor trains are installed at a water depth of 260 meters, in a shared subsea structure with a total weight of 5100 metric tons, a footprint of more than 3300 m2, and height of 17 meters above the seabed. The SCSt is connected to a subsea manifold station routing all flow from the wells via the compressor trains to the gas processing platform Åsgard B. The installation includes a comprehensive SURF scope with more than 60 km of new flow lines, 11 PLEMs and 50 tie-in points. The compressor station is powered from the Åsgard A FPSO where a separate high voltage power module weighing 850 metric tons has been installed. The subsea station is remotely operated from the Åsgard B platform. The subsea compression station is compressing the gas flow from the Midgard and Mikkel reservoirs, boosting the production and securing stable flow conditions in the subsea flow lines towards Åsgard B. The subsea commissioning has been carried out during summer, autumn and winter 2015/2016. It has involved control system commissioning, dynamic commissioning with N2 and MEG, before final commissioning with hydrocarbons. In order to secure efficient commissioning with involvement of a large number of vendors and support personnel, a remote operation room for the commissioning team was installed at Statoil's Stjørdal office outside Trondheim where the Åsgard Operations land organization is housed, thus avoiding constraints imposed by offshore training, helicopter travel and shortage of offshore cabins. This paper describes the subsea commissioning phase, including experiences and lessons learned. Challenges including cooperation between onshore room, offshore platform, and installation vessel, as well as performing commissioning on one train with the other in operation, are discussed. In addition, it gives an outline of the experiences gained during the start-up and initial operation phases.

The Gullfaks subsea compression project is a brownfield development which aims to extend the plateau production and increase total recovery from the Gullfaks Sat. Phase II (L and M templates) with multiphase compression technology from OneSubsea. This is the world's first subsea wet gas compressor project, and the compressors are installed at approximately 135 m water depth. The subsea compressors will boost the unprocessed gas well stream containing liquids to Gullfaks C from year 2015 to 2030. The compressor station will be located at the M and L templates and the tie-back distance to Gullfaks C is approximately 16 kilometer. The compressor station is equipped with 3 future hubs for tie-in of additional fields in the area, which enables flexibility to the system. The Gullfaks Compression System (GSC) main components consists of 2 multiphase compressors (WGC4000) with individual recirculation systems, 2 subsea process coolers, 1 flow mixer and 3 bypass headers. The flow mixer is located at the inlet of the station and the main purpose of this device is to dampen out liquid slugs and provide an equal homogenous split of multiphase flow to the two compressors when operating in parallel. The subsea cooler main purpose is to cool the well stream before compression in order to limit the compressor discharge temperature below the flow line design temperature in addition to increase compression efficiency. The wet gas compression technology is applicable for most gas fields which will have use for pressure support at one stage. The system is quite simple i.e. there is no need for conditioning of the well stream. The Gullfaks Subsea Compression station was started up October 7 th 2015. This paper will describe the subsea commissioning phase, including lessons learnt from the subsea commissioning phase. In addition this paper will give an outline of the experiences gained during start-up and operational phase. The wet gas compression technology could have an impact on brown field developments where topside weight capacity may be constrain. Such project could also have a positive impact wrt HSE as no tap in to existing topside process will be required. Last but not least, this is a cost efficient solution where the recoveries from the wells are improved in addition to accelerated production.

The paper reviews the way leading up to the Subsea Factory Compressor Stations with focus on important technology step-stones and breakthroughs. A dedicated and long term focus on technology development through R&D has been carried out within a series of disciplines supporting the subsea production application. The development has been along two important axis; multiphase flow and subsea systems. A comprehensive R&D effort was initiated in the beginning of the eighties resulting in a highly successful and profitable development and implementation on the Norwegian continental shelf, namely the subsea industry. Through a series of successful tie-backs and long distance multiphase flow lines, the ultimate concept was achieved for gas-condensate systems represented by the unprocessed transportation of well stream directly to shore. The first multiphase pumps were installed in the late -90 and in 2000 the first subsea separation station was started up. Today subsea boosting and separation is proven technology. In 2011, building the first subsea gas compression station was initiated, taken the last step to a full subsea factory installation. To realise subsea compression, the main components have been subject to a systematic technology qualification process. The paper describes how Statoil's large scale laboratory facilities has been mandatory for full scale qualification testing as well as focus on quality to achieve the necessary level of confidence. The Subsea Compression projects solely, have carried out nearly 60 qualification activities, further detailed in the paper. The paper also looks forward and point out that the subsea processing solutions that have been qualified and implemented can be utilized to achieve cost efficient solutions with low environmental footprint.

As part of the corporate technology strategy Statoil has launched a technology plan for the Subsea Factory concept. The plan describes how to combine subsea production and processing technology elements with key business cases and define enabling and cost-efficient field development concepts. With the advent of moving processing facilities from topside to subsea, Statoil has made major technological advances in placing conventional processing equipment on the seabed. As of today, Statoil has successfully deployed subsea pumps and subsea separators (Troll Pilot and Tordis). Statoil is also in the process of deploying the world's first subsea compressors in 2015 (at both the Åsgard- and Gullfaks field). While there has been a gradual increase in the complexity of the subsea processing systems we have also advanced our analytical and modelling approach to subsea processing concept evaluation and selection. In our recent concept evaluation we have used an integrated modelling approach, in which subsea processing options are directly linked to reservoir models, flow lines and surface facilities. This enables us to see value added in terms of increased reservoir productivity, but also overview of entire system behavior from reservoir to the topside, throughout the expected field life. The cost level within subsea has increased by a factor 2.5 over the last 10-12 years. Statoil aims at establishing a Business Agreed Standardization on subsea processing interfaces and modules. This standardization strategy will allow suppliers to compete within modules/technology elements, but standardize on module size and open interfaces to achieve plug-and-play functionality The goal is to reduce costs and improve competitiveness of subsea solutions: More profitable subsea developments Increased subsea processing volume Statoil believes that alignment with the other operators is vital to succeed in establishing a global, open standard. Standardization enabling cost reduction through simplification More profitable subsea developments Increased subsea processing volume (? win-win-solution for the O&G industry) The paper describes the ongoing work to achieve standardization of the Brownfield Subsea Factory with focus on near infrastructure solutions of existing fields. Subsea boosting and compression are important technologies enabling extended lifetime and increased recovery of mature subsea fields. In the paper several business cases will be described.

Offshore oil and gas pipelines are important assets for maintaining stable energy supply as well as being critical for maintaining cash flow to the owners and shippers. Emergency repair response time is in focus by all major pipeline operators, and the need for remote repair technology has been addressed since the mid 1990s. Statoil have, on behalf of the Pipeline Repair and Subsea Intervention (PRSI) Pool in Norway, developed new technology allowing remote controlled repair by hyperbaric welding of large diameter subsea pipelines in water depths down to 1300 meters. The new Remote Welding System consist of three main modules; a habitat providing a dry gas filled work location at the tie-in location, a power and control unit launched separately providing all essential services needed for the job and the remote welding tool performing the welding operation itself. The system is built and qualified for pipelines from 30" to 42" diameter, but may be expanded to smaller diameters and deeper waters.

Abstract The Norwegian Continental Shelf (NCS) is being revitalized, with new discoveries and production replacement. The NCS rig market is characterised by an ageing rig fleet, where 2/3 of mobile offshore drilling units (MODUs) are 25 years or older. Additionally there are perceived high entry barriers, high cost levels, constrained rig capacities and a lack of fit for purpose rigs for mid-water production drilling and completion as the market is dominated by deep-water rigs optimised for exploration drilling. An aggressive drainage philosophy from a high number of wells is required for a sustainable production profile on the NCS. Thus, a new rig category strategy has been developed to ensure fit for purpose rigs to achieve higher operation efficiency. Additionally a new procurement model has been a key to achieve industry collaboration in the rig design process. With 40 years experience on the NCS we are confident of what tools we need. The main goal is to implement the category strategy to secure fit for purpose tools for our operations. We have among others had a good start with the mid-water Cat D semi-submersible rig, and a shallow-water Cat J jack-up rig for efficient year around drilling, completion and heavy intervention operations. Ambition for these " workhorse rigs" is 20% more cost efficient production drilling activities on the existing mature fields compared with present rig fleet. Early involvement and collaboration with the industry has been key to unlocking experiences from different drilling contractors and yards. Key success factors have been to facilitate experience gained from the previous 6th generation MODU new builds into the new safe and cost efficient production drilling concepts. The Cat J units are currently in a tender process, while the first four Cat D units are under construction in Korea. One key take away so far is that competition in all levels of the product is a more important cost driver than the requirements, specifications and equipment.

Abstract CO2 injection implies displacement of water, and thus aquifer pressure build-up or displacement of water to other rocks. Both may be problematic. Pressure build-up may result in seal failure and / or restrict injection rates, whereas displacement of brine to other rocks may have undesired effects on the environment, such as contamination of potable drinking water. CO2 storage capacity also depends on pressure management, especially in closed systems where displaced water cannot be adequately displaced in the subsurface or vented to the surface. Fluid pressure management at individual storage sites will be planned based on theoretical considerations as well as practical experience. The theoretical work includes analyses of widely different subjects such as stress tensor analyses, fracture propagation dynamics, reservoir connectivity and 3D permeability distributions. Practical experience will come from a growing number of injection sites, of which the experiences from the ongoing Snøhvit CO2 injection project are currently the most important. Statoil has injected CO2 at Snøhvit since 2008. Injection took place in the Tubåen formation which underlies the Stø Formation natural gas reservoir. Fracturing of the caprock from the CO2 injection could thus result in CO2 leakage to the overlying producing reservoir. The CO2 injection resulted in an initial well pressure increase, probably caused by precipitation of salt in the near wellbore area. This challenge was resolved by injection of methylethylenglycol (MEG). Continuous downhole pressure measurements nevertheless documented a continuous pressure increase, albeit at a lower rate. This pressure increase was interpreted as evidence of insufficient far-field permeability to displace formation water laterally rather than of storage space shortage.

1 Introduction: Oil production from the Norwegian Continental Shelf is declining, and it is the production of gas that keeps the number of oil equivalents up. To make the reduction in production curve as low as possible in the years ahead, it is essential to drain the existing fields in an optimal and cost-effective manner. New discoveries will also have to be exploited faster than before - at a lower cost. The cost of drilling offshore wells on the Norwegian continental shelf has increased far more than the general price inflation in mainland Norway. New wells and field developments may not be economically attractive due to the accelerated costs and increased competition for capital in the market. The golden age of the giant fields offshore Norway is most likely history, and the remaining known reserves and discoveries are less accessible and of less volume. This fact makes it even more important to be as cost effective as possible in recovering these resources in a commercially interesting manner. Cost-, and drilling efficiency are key issues to make the depletion curves as gradual as possible in the next few decades on the Norwegian continental shelf. Production drilling efficiency with focus on Completion and well interventions are essential factors in keeping the recovery rate from existing fields as high as possible, and must have high focus in the industry in the years to come. There is a shortage of mature Drilling and Completion rig design Concepts tailor-made for mid water (100-500m) for operation on the NCS, hence Statoil has decided to develop a new Mobile Offshore Drilling Unit (MODU) concept, " CAT D??, which we believe will be a " Workhorse rig??, tailor-made for Production Drilling in cold climatic-, mid water conditions on marginal- and existing mature fields on the NCS. The future on the Norwegian continental shelf (NCS) will consist of mature- and marginal fields where the hydrocarbons are found in smaller structures. This will require lower development costs by changing from customization to standardization of MODU concepts.

Abstract As Statoil and other companies find and develop oil and gas reserves in more remote, deep and harsh locations, in some cases with more challenging reservoirs and fluid properties, the technological challenges, qualification requirements and technical risks of deploying subsea compression will all increase. However the business upsides of subsea compression will also increase and there will almost certainly be areas where subsea compression becomes an enabling technology, without which fields cannot be profitably developed. The challenge of increased recovery in development of fields in remote location, deep water and fields located in harsh environments, implies the need for a proactive technology strategy. It is part of Statoil's strategy to actively drive the development of subsea gas compression to a technical readiness level where subsea gas compression can enable subsea gas fields, both from a technical and commercial point of view. This paper summarises the results from rich gas subsea Technology Qualification Program (TQP) completed for Statoil's Gullfaks 2030 Subsea Compression project (GSC) in Norway applying Framo Engineering's WGC4000 compression technology. The paper will focus on the results and conclusions from the TQP that has been ongoing during the last two years. The Gullfaks 2030 Subsea Compression project business case and the subsea compression system design will also be presented. In May 2009 Statoil entered into a two year technology qualification contract with Framo Engineering AS for the engineering, manufacturing and testing of a full scale subsea gas compression system. This multiphase compressor has completed rigorous tests with hydrocarbons to prove that it meets the hydraulic capacity and is otherwise suited for Gullfaks' field design requirements. The system described in this paper is currently being matured in parallel with other subsea and topside compressor systems. The Gullfaks South Fields comprises several subsea satellite fields tied back to the Gullfaks A and C platforms. If a subsea compressor concept is selected, Statoil plans to install the subsea compression system close to two of the subsea production templates at the Gullfaks South field. This will boost the flow of gas towards Gullfaks C, and will both accelerate the total production, increase the total recovery rate and delay or eliminate the need for conventional low pressure production phase. The important role of full scale testing, Statoil's technology qualification program and close collaboration with key technology suppliers is further described. The Gullfaks field in general The Gullfaks Field (Figure 1) is located in 135-220 meter water in block 34/10 on the Norwegian continental shelf, 175 kilometers north-west of Bergen. It covers 51 square kilometers and is developed with three large concrete production platforms, Gullfaks A, B and C (GFA, GFB and GFC), and several subsea production system templates. Discovered in 1979, Gullfaks South contains oil, gas and condensate in two formations (Statfjord and Brent) Early production and first oil to the Gullfaks A platform came from subsea satellite wells and started December 22´th 1986. Later the field was developed further with mainly four slot subsea templates in three phases, Gullfaks Satellites Phase 1, Phase 2 and Skinfaks Rimfaks IOR. Phase 1 subsea production started October 10´th 1998 from a new generation of subsea production facilities. A complex reservoir structure, large volumes of associated gas and technical challenges such as high wax content in the oil have been among the most challenging factors.

Abstract At the end of 2009, Statoil commenced four mobile drilling units (MODU) for operation in the Gulf of Mexico (GOM) and on the Norwegian Continental Shelf (NCS). The MODUs were Aker Spitsbergen, Deepsea Atlantic, Maersk Developer and Discoverer Americas. They were in general (with the exception of Deepsea Atlantic) delivered according to contract, budgets and our internal delivery time predictions. Two more MODUs (COSLInnovator and COSLPromoter) are under construction in China. Statoil's established a project organization " MODU newbuilt group?? for following up all MODU newbuilt projects from contract award to commencement. The " MODU newbuilt group?? ambition was to carry out task responsibility for all MODU Newbuilt Projects across line organizational task responsibilities to ensure continuity and transfer of experience throughout the entire project period. The main goal for the MODU group was to deliver newbuilt drilling, completion and intervention units in compliance with established project goals, together with the steering committee and Asset manager group: Deliver new rig concept made for safe and efficient operations. In compliance with MODU's delivery prognosis In compliance with agreed cost budgets High focus on HSE during the construction period The goals were achieved and we believe that the MODU group's organization and the applied??hands on?? approach have proved to be a success. The experience is that the detailed follow-up in the yards with the interaction from the " support centre?? in Stavanger during the construction phase was extremely important in order to have full status control when managing the project. Introduction In 2006, Statoil, along with other operators, established a strategy for renewal of the Mobile Drilling Unit fleet on the Norwegian Continental Shelf. Prior to the merger of the two companies, Statoil and Hydro entered into several MODU newbuilt contracts, for MODUs to be used both in the Gulf of Mexico and on the Norwegian Continental Shelf (NCS). The construction of these units started after the merger, and at that time the responsibility for following up these units was assigned to Drilling Technology (DT), department for Drilling Facilities (DFA). In order to utilize potential synergy, all newbuilt projects were organized in one common project organisation within DFA called " MODU Projects??, securing cross project experience transfer and learning including optimum use of shared resources. MODU Project Organisation Model: Establishing a Common Project Management Administration system for: Cost management – Contract administration – Handling of non-conformities – Risk assessment method to identify and follow up the predicted delivery schedule. – Optimize the use of project personnel recourses. One project organisation with one site team for each MODU. Common administration with " on line?? commercial and technical support from project support centre collaboration room to the assembly site offices.

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. Background The Tordis and Vigdis oil fields lie in block 34/7 in the Tampen area of the Norwegian North Sea, and came on stream in 1994 and 1997 respectively, developed with subsea installations and operating in water depths from 200m to 280m. In addition to the main Tordis structure, the development embraces the Tordis East (1998), and Tordis South East (2001) fields.

Abstract Authority regulators as well as shareholders, the public and other stakeholders require owners and operators to demonstrate the safety performance of their processing facilities. A particular focus is put on safety barriers managing major accidents with the potential of causing severe fatalities and long-lasting damage to the environment. Statoil has implemented a structured approach for assessing the condition of the safety barriers on their processing facilities as a key measure to control and reduce major accident risk. Performance Standards (PS's) are defined for each barrier and each PS defines a set of Performance Requirements (PR's) to be met by that particular system with respect to system function, integrity, survivability and management respectively. The set of PR's incorporates regulatory and internal requirements based on best industry practice. A comprehensive assessment program, incorporating a detailed grading system, regularly reviews compliance with the PR's and assigns a common grading. The TTS process focuses on a systematic assessment of the actual technical integrity and condition of process safety barriers implemented in facilities in operation, as well as facilities under design and construction. TTS provides a powerful approach to: Measure and ensure safety performance Prioritize corrective actions and major accident hazard risk management improvement initiatives Build process safety awareness and competence Demonstrate regulatory compliance. Introduction and Background Managing major accident risks on complex hydrocarbon processing facilities is an ongoing challenge. The TTS process for structured evaluation of technical safety systems or barriers at operating facilities have been developed over a number of years. Initially, a process for systematic and structured evaluation of technical safety systems in operation was developed by Statoil in 2000. The process was named TTS - Teknisk Tilstand Sikkerhet (Norwegian for technical condition safety) and focused on a systematic assessment of the technical integrity and conditions of the existing process safety barriers. DNV was engaged to provide support in Statoil's roll-out and implementation of the TTS process. Following successful implementation at Statoil facilities, Norsk Hydro showed interest and implemented a similar approach at their facilities with Statoil's consent. The TST (Teknisk Sikkerhetstilstand) process was launched in Hydro in 2003. Following the merger between Statoil and Norsk Hydro Oil & Gas business, Statoil is still applying the process under the name TTS, which in fact combines the best practices of the former two companies.

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. Introduction Subsea processing involves one or more combinations of fluid conditioning and pressure boosting of wellstream fluids and water (from a reservoir or from the water column) at the seabed. Conditioning can include water removal from hydrocarbons, separation of liquids from gas, separation of sand and other solids from fluids, fluid cooling (or heating) and chemical injection. There are currently four main types of subsea processing application: Single and multiphase hydrocarbon boosting Gas compression Separation systems (gas / liquid and liquid / liquid with produced water reinjection) Raw seawater injection

Abstract Gas lift valves are an integral part of the tubing in gas lifted wells. Many operators use tubing with premium threads for these wells. Additional safety equipment, including the packer and the downhole safety valve, has been subjected to a program intended to prove its capabilities as a safety device. This is not the case with standard gas lift valves, developed and delivered according to the governing standard, ISO 17078-2. On the contrary, this standard states that the valves are only intended to be a flow check and not a pressure safety device. This paper discusses the development of a new validation standard, where the intention is to prove the equipment's safety capacity, as well as new equipment developed to meet these challenges. Introduction Most operating companies design their wells according to external or internal regulations with respect to safety equipment and safety levels. Each component needs to meet material standards and specific equipment standards. The standards will also describe production requirements as well as acceptance testing procedures for the equipment in question. New equipment typically has to be qualified to a certain validation procedure described in a standard issued by an external standards organization and often to additional internal company requirements. Barrier Philosophy The safety philosophy of preventing uncontrolled release of hydrocarbons is often referred to as barrier philosophy. The barrier philosophy for a given well typically depends on region, nationality and operating company. The Norsok D-10 is an example of a standard describing elements preventing hydrocarbon or pressure release to the atmosphere and it defines well barriers as; " Well barriers are envelopes of one or several dependent well barrier elements preventing fluids or gases from flowing unintentionally from the formation, into another formation or to surface. The well barrier(s) shall be defined prior to commencement of an activity or operation by description of the required well barrier elements to be in place and specific acceptance criteria.??

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. Introduction Since installation of the world's first subsea electrically driven seabed booster pumps on the Lufeng field in the South China Sea in 1997, the installed power used for subsea processing systems has increased substantially - and is expected to increase further in the years to come. Subsea processing systems include single and multiphase boosting, compression and separation, and power demand is far above what conventional subsea developments require. The majority of systems installed today are boosting applications and app. 35 machines have been installed on the seabed worldwide (not including spares/replacement motors). Accumulated installed shaft power since 1997 will pass 50 MW by 2010 and be close to 70 MW by 2011 (confirmed projects Jan 2010), ref figure 1. Although the activity has varied over the years, the trend towards increased subsea power consumption is very clear. Statoil has played a key role in this development and within 2010 more than 25 % of the installed subsea power and approximately 30 % of all motors will be on Statoil operated fields. Cost effective and reliable power supply systems is a key element in the success of subsea processing systems. While development and optimization of the processes and machines (multiphase pumps, compressors) has had attention from the industry for decades, real focus on development of subsea power supply systems has only been present for the last 5-10 years. This paper gives an overview of Statoil experiences with subsea power supply systems and also presents ongoing qualification activities within the area. Only experiences within subsea power for processing applications are included, experiences with control power, instrumentation, process etc. are not included. Statoil's experiences with subsea processing is described in another paper presented at OTC 2010; paper No 20619; Experience to date and future opportunities for subsea processing in Statoil.

Abstract Several fields on the Norwegian Continental Shelf are in the decline phase with an increasing production of water and gas, often in combination with reduction in production pressure. The available area and weight for installation of new equipment on the platforms is often limited, and it is important to minimize both the operational and capital costs. Compact, inline separation devices can be a key technology for mature fields, and also for subsea fields at large water depths where the weight is critical. The Statoil operated Gullfaks licence has identified compact separation as a key technology to increase the oil recovery. Due to low foot print and low operating cost the technology can aid prolonged production from the reservoir. The technology will also make it easier to use the existing infrastructure at Gullfaks for tie-in of new fields. A survey identified a need for both compact gas/liquid as well as compact oil/water separation. Statoil has chosen to test and develop relevant units in close co-operation with vendors of compact separation equipment. All the tested technologies are based on cyclonic separation devices with low or moderate pressure drops. Statoil is carrying out an extensive qualification program where selected compact solutions for several unit operations are developed and tested at real operating conditions. The tests have been done in high pressure laboratory flow loops as well as offshore at the Gullfaks field. The compact technology has been tested for a wide operational window, showing that efficient processing of well stream can be achieved using compact separation equipment. The results from this work leads to the conclusion that compact technology has a large potential both in replacing conventional gravity separators topside and for deep water subsea separation. Introduction Several oil fields world wide are in the decline phase with an increasing production of water and gas, often in combination with reduction in production pressure. Increasing water cut means that water occupies a large part of the separator volume, which otherwise could have been used for 3rd party processing or for low pressure production. Due to low weight, low foot print and use of piping code, compact separation units can provide new processing capacity at existing installations as well as debottlenecking of existing separation equipment. The Norwegian offshore field Gullfaks is one of the fields that have reached tail-end production. They started up in 1986 and with a peak production of 600.000 bpd oil in 1994. In 2008 the oil production was reduced to 92.000 bpd. The Gullfaks field consists of three concrete platforms, see illustration in Figure 1. The oil is stored in the concrete cells and loaded into shuttle tankers on the field, while associated gas is piped to the Kårstø gas treatment plant on the Norwegian west coast, and then further to continental Europe. Three satellite fields have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms. The recovery factor on Gullfaks is 59 per cent, however the aim is to increase it to 62 per cent.

Abstract The idea of separating oil from water on the sea floor has been an engineer's dream for years. Now, with the Tordis IOR (increased oil recovery) project in the North Sea, Statoil and FMC Technologies with partners1 are making this dream a reality. The Tordis IOR project realises the first commercial full scale subsea separation installation in the world. Statoil expects to improve the Tordis field's recovery factor from 49 to 55 percent and to extract 35 million barrels of additional oil from the field. The Tordis field is linked to a Gullfaks C platform via 11 km pipelines. Tordis is a mature field, which produces more and more water and less oil. There is not capacity on the platform to separate the vast amount of water needed to keep Tordis in production. Installation of a subsea separation, boosting and injection (SSBI) system removes the water subsea and enable lowering the well head pressure. This is the main driver for increased oil production even if the reservoir pressures start to drop. This allows Tordis IOR to remain operative an additional 15 -17 years. Figure 1. Illustration of the subsea separation, boosting and injection (SSBI) station. Separator and desander vessels are illustrated in orange. The multiphase and water injection pumps and leakage detectors are shown in white. Note: Protection structure has been removed for better visibility. At distance the water injection well (upper left) and Pipeline inline manifold (right) can be seen. The well stream is routed to the SSBI system, where water, sand and hydrocarbons are separated. Oil and gas are pumped through a 2,3 MW multiphase pump1 to the Gullfaks C platform. The ability to handle sand is important in a mature field IOR project. The de-sanding process for Tordis is therefore designed to handle up to 500 kg sand per day. The separated sand is ejected into the water stream, downstream a 2,3 MW water injection pump1, and injected into the dump reservoir in the Utsira formation through a water injection subsea tree. Statoil has chosen a contract strategy where the SSBI technology development is handled as a normal delivery project, as opposed to a technology development project. Background A majority of Statoil's oil and gas production comes from subsea wells. Statoil has therefore been developing subsea processing equipment for more than 10 years, ranging from small, simple pumps to large compressors that are still under development. The strategy has been to develop the technology incrementally and test it out thoroughly (topside) prior to installation. In this way, Statoil has gradually increased the power of electric motors, the step-out distance from topside facilities, water depths, and the complexity of processing systems. The Tordis field at the Norwegian Continental Shelf has been producing since 1994. It is a subsea development at 200m water depth with tie-in of the production to the Gullfaks C platform in the Tampen area.