ABSTRACT Multiplexed electrohydraulic (EH) control systems have been successfully deployed in significant numbers around the world since the 1980s. Supportability of this older standard of subsea equipment, however, has become increasingly problematic, especially where field life is now being projected well beyond the original design life of the installed system. Existing facilities are being used more and more for marginal field tiebacks and natural extensions to maximise the economic benefit of these facilities, which can only be realised in a number of cases by the introduction of modern control and instrumentation technology. By implementing effective technology insertion solutions, not only do operators gain a step reduction in supportability (obsolescence) risk, but they also gain the ability to apply current day techniques, sensors and support tools to improve efficiency and reliability and enhance oil recovery rates. This paper analyses the opportunities that can be exploited with the implementation of technology insertion and discusses some options available to operators. Each of these older fields has developed its own characteristics since its original deployment and thus will have a unique view forward for the rest of its life. Recognising this, the paper presents some examples of standard Brownfield options and packages that can be assembled into a complete solution for any mid-life update requirement. Finally, a recent contract, which typifies the successful embodiment of this approach, is discussed to demonstrate the improvements in operator value that can be realised. Drivers for Brownfield Upgrades Many of the older oil fields around the world based on multiplex EH control systems have been installed and functioning since the 1980s and 1990s. Early deployments of EH multiplex controls technology - BP's Magnus field and the Shell Underwater Manifold Centre (UMC) - both came on-stream in 1983. These early systems employ technology that was then in widespread use in high reliability/low volume industries (e.g. aerospace) and had a typical field life expectancy of 15–25 years. Now 2010 has arrived, the initial 15–25 years life has expired and the original "outside possibility" for the fields to be extended by many more years has become a reality in a significant number of cases. In a recent survey, GE Oil and Gas determined that of most of its older active fields (pre-2000), not one was due to be fully decommissioned prior to 2015 and most fields were predicting at least another 10–15 years of operation. Driving this life extension is the need to extract more oil from existing facilities due to the lack of major new fields in easy-to-access areas, and the time and cost of bringing on-line difficult fields in different areas of the world. Exploiting existing infrastructure and developing smaller pockets of proven reserves are making more economic sense in today's financial and political climate, especially with new technology that is now available. Typical subsea fields may have only recovered 35 percent of available hydrocarbons, compared to 55 percent for topsides and land-based facilities, so the opportunity to increase this rate by even a small amount

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. Introduction Increasingly complex machinery is being installed on the seafloor (Figure 1). Compared to production systems with their infrequently actuated valves, the large, high-powered, rotating machines currently being installed for applications such as subsea separation, gas compression and boost pumping require much more monitoring, maintenance and care. The oil and gas industry faces a significant challenge to ensure that this higher complexity equipment achieves the required operational efficiency and reliability. In a parallel trend, production operations are moving to very remote and challenging environments, such as the Arctic. Oil companies anticipate that conventional logistics, maintenance and intervention techniques in these regions will be very costly, driving operators to reduce costs and manage the risks inherent in bringing vessels, equipment and personnel into these regions. Control systems for offshore oil and gas production systems must accommodate the transition to increasingly complex equipment while simultaneously achieving high reliability. Other industries faced with similar increases in complexity and demand for very high reliability have evolved to manage the challenge. They have embedded significantly more sensing and actuation technology in controls for complex electromechanical systems. Advances in fabrication, functionality and scale of microelectronics have made this change possible. In addition, many system operation and maintenance functions are automated rather than manual. Information from operation and maintenance processes is also transported to decision-makers, independent of their location, who then send high-level commands and action plans back to the system being controlled.

ABSTRACT This paper describes the performance assessment programme initiated for the first operating DC all-electric control system. An overview of the applied method considering both model and data uncertainties is provided. In addition, the field experience gained within the successful installation, commissioning and operation of the system to date is discussed. While presently obtaining operational experience subsea, significant data assessment and processing capabilities of the first operating DC all-electric control system can be utilised. Key parameters of interest and their context are investigated in a thorough-detail, permanent monitoring of the condition of the system. By using this approach, expert confidence level increases as additional decision support is provided. The systematic condition evaluation is based on a continuous probabilistic investigation which complex physical phenomena tend to impose. Preventive planning of maintenance leading to long-term cost reduction is enabled. Introduction The central scope of an all-electric subsea control system consists of electric actuation allowing virtually zero response time, along with real-time reading and system feedback. The communication signal can be superimposed on the power transmission. On topside the DC electric system consist of a master control station (MCS) utilising standard human machine interface (HMI) software and two independently operating electrical power and communication units (EPCU). Each channel (A and B) serves two subsea modules which are remotely operated vehicle (ROV)/diver retrievable. Prior to access to an electric subsea control module (eSCM), the power regulation control module (PRCM) regulates power depending on actual demand and demodulates the incoming communication signal. The eSCM controls the subsea tree and manifold functions and also provides the interface for subsea instrumentation. More specifically, the PRCM converts and regulates the 3kV DC input from topside to 300V DC for each channel and ensures further transmission of the communication signal. The reduced voltage and independent communication signal are then transferred to the eSCM. The latter controls valve functions allowing the transmission of more than 250 different associated parameters, such as actuator parametric data, and communicates with surface control equipment. Sensor information is received and transmitted. A sketch of the system concept is shown in Figure 1. In order to minimise energy losses over long distances, DC, rather than AC, was chosen to transport electric power. This choice also allows for a reduced cable cross-sectional area in comparison with AC transmission. In comparison with the umbilical of a conventional electrohydraulic (EH) actuation system, the all-electric umbilical cross-sectional area is reduced as all hydraulic lines (LP/HP/return) are removed. An additional feature of a DC system is that seawater can be used as the electrical return path closing the electric circuit through the use of dedicated anodes and cathodes. The condition of the seawater return path is observed, and relevant data is transferred via the eSCM; however, this feature is not mandatory. The screens and shields of the umbilical itself can be used as a backup route, should the anodes or cathodes fail.

ABSTRACT FMC has developed and operated riserless light well intervention (RLWI) equipment in the North Sea since 2003. The development work started in 1999 and has resulted in a separate operating unit within FMC, FMC Production Systems FPS, that now operates RLWI systems onboard three vessels from the 2009 season. Long-term contracts are established with both StatoilHydro and BP, and additional work has been carried out in the spot market both on Norwegian and UK sector of the North Sea. The RLWI systems make it possible to perform wireline well interventions from mono-hull vessels, instead of using riser based systems that need to be operated from drilling rigs. The overall cost of the operations can therefore be reduced, and as a result, more subsea completed wells are intervened, and production rates and ultimate recovery can be improved. From the recent past, a gap(12–14 percent) in recovery from the fixed platforms relative to the subsea fields has emerged, even though the properties of the reservoirs are basically the same. To a large extent this gap is related to the high cost in subsea operations in general and well operations in particular. Experience, however, shows that efficient (i.e. low cost) well intervention solutions are of the utmost importance for increased field recovery as well. RLWI is one tool helping to close the recovery gap. RLWIs are steadily gaining industry acceptance since their introduction in 2003. This activity has significantly increased since 2005 in the North Sea, requiring at least two concurrent vessels for planned operations in 2010. RLWI operations are now common in shallow water up to 600m (2000ft), and a few operations in the Gulf of Mexico have been performed down to 900m. For open-hole logging, a demonstration down to 3000m has been performed with a similar solution. However, the current concept is not the ultimate technical solution worldwide, just the first step. Considerable efforts have to be made to improve the concept with respect to efficiency, weather sensitivity and - last but not least - deep-water compatibility. It is envisaged 3000m (10,000ft) water depth is well within reach. North Sea Experience All traditional wireline tasks are performed from these vessels. There has been a gradual development into more complex downhole tasks as experience has been gained. From a humble start with mainly simple mechanical tasks, the operations suite today consists of the following: Data gathering (production logging tool, or PLT) Perforating/re-perforation Zone isolation (plug/straddle) Inspection/repair/installation of insert downhole safety valve (DHSV) Milling of short-scale bridges Camera runs: visual or X-ray Well killing operation Pumping operations/scale treatments Selective tracer injection or sampling Change-out of gas lift valves Sleeve operations - downhole instrumentation and control systems (DIACS) valves Change-out of subsea trees Plugging and abandoning (P&A) operations of subsea wells. As a typical example of the results obtained from these operations, the following summary of a scale milling job is illustrative: Scale milling on WL tractor (breakthrough for advanced RLWI operations)

ABSTRACT Subsea high integrity pressure protection system (HIPPS) technology was initial developed some 15 years ago, although today relatively few projects have a subsea track record sufficient to achieve a technical readiness level 7 (TRL 7) designation. Standards defining the rules for instrumented safety systems (International Electrotechnical Commission, 2000, 2003) are well rehearsed, although the standard for subsea, in API 17O (American Petroleum Institute, 2009), has been slow to emerge. This paper discusses to what extent the API standard has settled the debate for subsea and in which other areas, if any, is there an ongoing tension between principle and practical application. What Function Does HIPPS Perform? Fundamentally, the function of the HIPPS is to protect downstream equipment from over-pressure by continuously monitoring line pressure and automatically closing an isolation valve(s) if the pressure rises above a preset level. Why Use HIPPS? Traditionally subsea pipelines/flowlines are rated to the full shut-in pressure of the reservoir, which can represent a very significant proportion of the field development cost, especially where long offsets are involved in combination with high pressures. The cost of the pipeline can be lowered by reducing its pressure rating; a thinner pipe wall results in less weight, which equates to lower capital cost and lower installation cost. Further, the subsea HIPPS also allows for a reduced rating of the downstream equipment (risers, separators, process plant, etc) and can make high pressure field developments commercially viable by allowing them to tie into existing lower pressure rated infrastructure. In an extreme case and particularly in deep water, it may not even be possible to develop the field without using subsea HIPPS because the pipeline would be too heavy to install using current installation techniques. Interestingly, at least one major oil company will only consider using HIPPS where there is technically no other choice, preferring not to use it as a cost-saving alternative where it is possible to install a pipeline rated to the shut-in pressure. The pipeline wall thickness can be reduced through three distinct criticality levels: no damage, no burst and burst critical. "No damage" is where the pipeline yield and burst pressure both exceed the shut-in pressure. "No burst" is where the yield pressure is lower than the shut-in pressure, but the burst pressure still exceeds the shut-in pressure. "Burst critical" is where the pipeline yield and burst pressure are both lower than the shut-in pressure. The choice of criticality level must be made cognisant of the fact that increased cost savings will result in increased risk, as illustrated in Figure 1. Operation of a Generic HIPPS Figure 2 illustrates a generic HIPPS arrangement comprising two barrier valves, known as the final element, plus three dual pressure sensors and the so-called logic solver. This decision-making logic solver device is most elegantly installed inside the subsea electronics module (SEM) contained within the subsea control module (SCM). The logic solver compares output from each pressure sensor against a preset trip threshold.

Novel Power and Communications Solutions for Offshore Fields The oil and gas industry is continuously breaking barriers as new offshore fields are being developed in greater depths, further offshore and in extreme environments. Furthermore, the current high market demand requires quicker developments and enhanced reservoir recovery. Technology from the subsea communications sector is qualified and readily adapted to provide high-capacity, high-reliability communications to offshore surface and subsea structures. Additionally, the direct current (DC) power handling capability of the subsea cable may be exploited to efficiently deliver power for control and instrumentation systems. The architectures at stake can range between dry node(s) to dry node(s) and dry node(s) to wet node(s) architectures. A significant benefit of the dry-wet solution is the availability of DC power distribution to the wet nodes (circa 10 kW/node). When combined with all electric subsea systems, this offers the opportunity for cost-effective high-reliability control systems in any offshore area. This paper will introduce a number of dry-dry and dry-wet solutions. The key features will be described and their technological, developmental status and cost aspects will be discussed. INTRODUCTION The established subsea solutions for the international telecommunication systems that provide the worldwide web are characterised by: high-capacity (100s of GB/s) optical fibre transmission, DC power transmission (10s of kW) and high-quality, highly redundant configurations for fault-free subsea use over 25 years. These solutions actually affect three best-in-class features: reliability, undersea connectivity and ultra-large bandwidth.(Fig. 1, Fig. 2 and Fig. 3 are available in full paper) The Offshore Requirements The oil and gas industry seems poised to seize benefits of new technologies to enhance its business processes, knowing the oil demand is expected to grow from 80 millions barrel per day in 2005 to 130 millions barrel per day in 2020. As for the production from deep water, the production of both oil and gas is expected double from 2005 to 2010, the deepwater contribution shifting from 10 percent of the total production today to about 25 percent in 2015. Therefore deepwater expenditures match a substantial increase in activity. From a capital expense (CAPEX) standpoint, it is expected that deepwater spending will amount $20 billion per year in 2010, with an accumulated $94 billion in 2006–2010 (Robertson 2005; Hillegeist 2003). From a communication standpoint, the deepwater environment can be best characterized by extended reach, well over 100 km between any two points, sometimes in excess of 500 km away from shore. The environment may be severe, for example hurricanes like in the Gulf of Mexico or seasonal ice in the artic margin. Consequently, there is a trend to implement more and more subsea processing. Therefore, more and more control will be located subsea around the wellheads. For the offshore network interlinking strategically located hub platforms, the capacity requirement is over 2.5 GB/s of aggregated traffic per node.

ABSTRACT In the scope of the SEPCOMP (subsea oil separation with composite materials) project, the benefits of using composite materials in the design of a subsea oil/water separation module have been evaluated. These studies are mainly focused on four points: The hull of the horizontal gravity separator (30 m 3 ) made of a sandwich cylinder (skins, carbon filament winding; and core, foam) and two hemispheric end closures (RTM, carbon fibres) The composite pipes of the module The support frame of the module made of composite beams The protection cover of the installation made of sandwich plates Two different water depths are considered (1500 and 3000m). The expected benefits are: Lower costs of deployment mainly due to the reduction of the module weight Lower costs of maintenance mainly due to the reduction of corrosion problems New design possibilities in the envisaged water depths Standardisation of a number of structural parts On the other hand, the higher costs of manufacturing composite parts are considered to evaluate the economic gain of the composite design compared to a metallic design. INTRODUCTION The main concern of the SEPCOMP project is the exploitation of deep and ultra-deep offshore oil fields. In these cases, the dimensions of the production lines between the surface and the sea ground can be reduced by using a subsea oil/water separator. Consequently, the weight of the surface support is also reduced. The specifications of a subsea separator can lead to design a heavy unique module or several lighter ones. In each case, the setting up will be expensive. The object of the project is to evaluate the impact of using composite materials on the manufacturing, deployment and maintenance of a separation module settled in a large water depth. Potential materials for each part of the separator (structure, piping, separator, etc.) were identified and studied. The comparative study is based on the DIPSIS project (DORIS Engineering), whose design is mainly based on metallic materials. Due to the large water depths considered (1500 to 3000 m), the composite materials offer advantages?weight saving, absence of corrosion, fatigue strength?which make possible a global weight reduction and cost savings. Simplified Specification of the Separator Module Subset Definition All the technical studies are undertaken with the aim of replacing each metallic subset by one functionally equivalent that is made of composite materials. This approach does not lead to a high level of optimisation, but it was selected because it allows for: Organisation the technical studies by competence field Running of the prototype tests subset by subset Moreover, the gradual but soon introduction of these subsets in operational structures without modifying the global design

INTRODUCTION The Shtokman field development in the Barents Sea will be another milestone in the industry, with a challenging step-out distance and demanding environmental conditions. This paper will discuss the all-electric controls solution using the CameronDC system approach and its advantages over conventional systems. Some illustrations and conclusions are taken from technical evaluation studies recently conducted for several operators. Design Goals for CameronDC Controls System CameronDC technology is particularly applicable for long offset fields, though not specifically developed for those applications. The following principles were set early in the development process: Increased reliability: the removal of hydraulic components from the control system; a key factor in increased component reliability and system availability improvement. Elimination of control fluid: no hydraulic fluids to store, handle, transport, clean/flush, replenish or disposal resulting in cost savings and significant environmental benefits Enhanced functionality: improved equipment response times and system diagnostic capabilities A power transmission system designed to economically overcome distance limitations of current electro-hydraulic systems Challenges Requirements for extreme offset field developments such as Shtokman offer design challenges that have not been addressed previously. The subsea installation is up to 640 km away from the topside system. This distance provides a unique challenge for conventional electro-hydraulic systems, not only from operational and economical perspectives but also from a logistical perspective. The application of the all-electric CameronDC system completely eliminates the need for control hydraulics. This results in major advantages in production umbilical configurations as a much simpler and significantly less expensive power umbilical containing coaxial cables with fibre optic capability is used. The field lies in a region of permanent ice during certain times of the year, making it impossible to access for intervention activities. Significant improvements in system reliability and production availability over are required. Numerous studies demonstrate that all-electric CameronDC technology provides the necessary improvements that will reduce the need for intervention and the associated operational cost of the production system. Further advantages of all-electric controls and actuation involve addressing important issues in health, safety and environment (HSE). Total elimination of hydraulic fluid and the equipment necessary to store, pump, pressurise, filter and dispose of it is a significant benefit. Associated health and safety issues including contact with, or slipping on, spills on the deck due to handling and leaks are greatly reduced. Also, safety is improved by elimination of high-pressure accumulator bottles and pressurised hoses and lines. In addition, environmental problems are obvious when leaking and venting hydraulic fluid into the sea. These are alleviated with the use of all-electric controls technology. The Approach for Shtokman The system concept can be broken into several areas such as communication architecture, power system design and subsea control system design (see Figure 1). The subsea system configuration for Shtokman consists of three templates situated in distances of approximately 12 km. Each template provides the space for up to eight Xmas trees. A ?dual redundant? control system was selected due to the specified high production availability targets.

INTRODUCTION BP currently operates approximately 200 subsea wells worldwide Wells are located in many regions, and operate in diverse environments. Wells are located in water depths from 25 metres to below 1600 metres, and from warm-water locations such as Indonesia to cold-water environments, such as the North-Sea. Within these subsea systems, one of the most common failure modes noted is attributed to electrical Systems. The purpose of this paper is to describe some of the failures that BP has experienced with subsea electrical connection systems. The paper will concentrate on two distinctly different systems, namely BP Indonesia and West of Shetland Indonesia is an example of a geographically remote system where equipment operates in a shallow (diver depth) warm water environment, whilst West of Shetland is an example of a deepwater (Remote intervention) and hairshweather environment The paper aims to give an overview of the problems experienced, as well as an insight into some of the factors associated with managing failures in both of these environments and regions. It aims to show how common lessons can be learned from these two systems that may help to prevent these failures from occurring in future developments. It should be noted that the intent of is not to identify specific failures attributed to connector manufacturers designs, however it is aims to highlight critical elements and interfaces that may need specific focus and attention during the design and operation phases of a subsea system Both controls suppliers and connector manufacturer have been involved with the failures identified within this paper. Summary The failures observed in both subsea systems are not believed to be isolated events within the subsea industry, and both systems have noted common modes of failures These failures have resulted in High intervention costs and loss of production to carry out diagnostics and to complete remedial Work. The majority of failures experienced were believed to be extrinsic or failures that were outwith of the design intent of the electrical system. This identifies that designers, as well as controls and umbilical system supplier need to become more aware of the design and operational criteria of subsea electrical systems. It also highlight that the industry needs to ensure that connector manufacturers be more involved with both system design considerations and operational requirements. In return, connector manufacturers need to be pro-active with their failure diagnostics, and sympathetic with their understanding of the operational requirements General Conclusions As most of the failures were believed to be due to extrinsic mechanisms, this clearly highlights requirement for some form of best practice / common expectation guidelines to be written for electrical termination work. The electrical system is a crital of a subsea system, and therefore due consideration needs to be placed on the design, diagnostic and fault finding capability of the system architecture and design The environmental effects and location of the subsea system may also play a factor in the design of the system and the connector. These need to be carefully reviewed during the project phase, and needs to be considered by connector and controls/umbilical system suppliers. Transportation, storage and testing conditions prior to emersion also need careful consideration.

ABSTRACT Over the years, DNV has been engaged in a significant amount of failure investigations for the offshore industry and in particular the subsea industry. This paper will describe experience form the subsea control system failure investigation without going into the disclosing details of manufacturer. Through these practical examples it will further be described the principles of a new methodology developed for ‘Qualification for New Technology’ and the related benefits. The need for such a systematic approach has been recognised by the offshore industry, which has sponsored DNV during the preparation of a recommended practice for "Qualification of New Technology" /I/ INTRODUCTION DNV has been engaged in study, testing, verification and trouble shooting of subsea production systems and their control systems since they first were installed in the North Sea Malfunction of subsea systems may become extremely costly Therefore failure investigation are important both in conjunction with insurance and to avoid the occurrence of similar failures in the future. The experience DNV is gathering during failure investigation is used in cooperation with the industry for developing methods that reduces the probability for failure Examples form subsea control systems are explained in this paper. These illustrate how a failure analysis is typically conducted at a DNV laboratory, and how the likelihood of these failures occuring could have been reduced by following the principles outlined in the recently published DNV RP /1/ The examples quoted are all associated with subsea umbilicals cables and jumpers An umbilica1 is used in the control and monitor of subsea production units. These are multipurpose links between the topside and the subsea facilities of a large design variety. Typically, these consist of small bore pipes, electrical conduct and fibre optical conducts as illustrated in Figure 1 (please note that all figures are printed at the end of this paper) Therefore their design is complex and contains a large numbers of different materials with various properties. The failure cases described below are limited to an electrical failure and a control fluid tubing Failure. Such failures, if redundant systems are not installed may cause production loss with significant financial consequences not only through the loss of production but also in respect of a repair and perhaps replacement Electrical short circuit caused by salt water penetration and a consequent reduction the insulation resistance has been experience in many electro/hydraulic control systems used in the North Sea over the last two decades The causes of these failures appear to be different in each case, but always result from an underestimation of the difficulties of maintaining electrical insulation in submerged saltwater conditions Failure Analysis Control tube battle fracture During a marine operation a chain accidentally bit the #x0022;dynamic#x0022; part of the umbilical, i e the part extending from the surface to the sea bottom. This caused damage to the umbilical resulting in control fluid leakage. The umbilical was therefore retrieved and brought to the manufacturer for repair. The repair work was completed, and the umbilical was ready for final flushing before reinstallation During this flushing/cleaning operation a rather heavy leakage was observed in an original part of the umbilical at a location for from the original damage.

ABSTRACT With a significant increase in the role of subsea production systems the need for reliable subsea control equipment has never been greater. This need is emphasized by the inclusion of advanced modules within the subsea controls package to manage the performance of new mission critical process elements (such as subsea processing packages and compression systems) designed to boost yield and reduce OPEX. Additionally, safety critical components such as pipeline protection systems may significantly reduce CAPEX by de-rating infrastructure pressure containment levels and allowing the tie back of new well sets into aged assets. Central to all such application is the knowledge that the control system itself is of high availability and reliability. In this paper, the acquisition and use of field and accelerated-lifecycle test data is illustrated and a case is built up for the ultimate reliability figures for the subsea control module The development of a HIPPS (High Integrity Pipeline Protection System) is used to exemplify the reliability arguments required to justify the use of a subsea control system in this particular safety critical application. Consideration is given to the mechanical components and failure modes associated with process fluid contamination. Finally the cost benefit argument is demonstrated based on ready deployed equipment Why Subsea HIPPS? Historically it has been the case that subsea flowlines and infrastructure have had to be rated such that they are capable of containing the fill shut-in pressure of the wells to which they are connected This is to cater for the eventuality at more produced fluid are admitted to the line than are being removed from it Examples of events that could lead to such as situation are Failure of a choke at the wellhead causing a sudden rise in production rates Hydrate blockage within the flowline Unexpected or sudden closure of a valve within the pipeline or downstream infrastructure Inadequate production control operations and procedures The occurrence of these events cannot be ruled out with any degree of certainty and the expected frequency is such that, In order to provide a safe system, a high flowline and infrastructure rating has previously been required The use of HIPPS allows pipeline and associated downstream components to be rated for a lower pressure than the well shut-in pressure Safety Instrumented Systems (SIS) such as HWPS are not new and have been used frequently in topside application to protect a relatively low-pressure system from a high-pressure source. These are already well established for topside applications as a means of safely de-rating pressure systems. This technology has now been developed by KOP to extend to subsea production systems, and in particular to High Pr essure/High Temperature (HPMT) hydrocarbon developments, which are now being actively pursued in many Central North Sea areas These prospects tend not to be large reserves aid often have Closed In Tubing Head Pressures (CITHP) in the region of 10,000 psi This leads to marginal economics of such fields, when the costs of higher specification pipelines are taken into account

Remember That Great Idea You Had Last Winter for the Subsea Sensor? That idea, could be patentable and/or may be copyrightable, could be entitled to trademark protection, and possibly even entitled to trade secret protection in the United States But what do you have to do to get this protection? This paper will Review a unique seven (7) step process for filing for patents which is faster and different than conventional filling techniques and includes Step 1- Write down a description of the idea Step 2- Decide on the strategy for patent filing Step 3- File the description of the idea at least as a provision patent application Step 4- Use Secrecy Agreements or ‘Non-Disclosure Ageements’ Step 5- Work with the lawyer and finish in four (4) weeks Step 6- Review all patent claim types while drafting Step 7- Use the free United States Patent Office Website or the European Patent Office Website to view similar technology to your inventions The current statutory criteria under 35 U S C section 102 for inventions Post Filing Events - After the patent application is on file with the governmental agency Post Issuance Events - After the patent Issues as a monopoly Consider copyrighting the drawings after filing the patent Consider trademarking the invention Consider increasing the trade secret protection for the invention I. A Unique Seven (7) Step ProcessM Step 1: Describe the Idea Describe the idea of the sensor and all is parts and how it works, consider using an invention disclosure form to make the process easier Invention Disclosure Form To help track new ideas, please provide the following information, attacking additional sheets as Needed Enter the title of your invention Describe your invention Attach more thorough documentation, such as source code, research reports, engineering drawings, sketches, flow charts, or the patent being improved upon (if available) Provide history of the development on separate sheets and attach Please list all end-uses of the invention Enter the following information for each invention (The Table is available in full paper) Please provide a flow diagram of your process 0i a sketch of your device or formula, or a diagram providing the steps of your software invention on a separate sheet Please list each part or step For processes, please provide at least 3–6 sentences describing each step For components that are commercially available, please list the supplier, part number and address of supplier. It is very important to describe how you believe the invention is different from what was being done before. Please provide a brief description of how the invention differs from known technology. List any publication or patent you know of that you believe disclose technology closely related to your invention, Attach copies of each item if available.

INTRODUCTION ‘Intelligent’ (or ‘smart’) well technology has developed such that they it is increasingly being considered for new oil and gas field developments. These wells can be especially attractive for subsea developments, where the cost of well intervention is very high. In these cases, the subsea production control system is required to host the 'third party intelligent well control equipment. The equipment for such wells places more demands on power, communication and physical space on sub-sea systems which have already been developed to optimise both space and power requirements. Within many smart well and sub-sea system suppliers the market, it was recognized that efforts to standardise interfaces would be required to avoid costly custom designs and so deliver equipment at an acceptable cost and delivery time. Early projects indeed experienced such problems IWIS is a joint oil and gas industry standardisation initiative, formed to improve the interfaces between intelligent wells, sub-sea systems and surface systems The IWIS ‘Industry Panel’ (Joint Industry Working Group) A group of representatives from three distinct communities oil and gas field operators sub-sea control system suppliers and Intelligent well equipment suppliers who wish to improve and develop the way intelligent well equipment interfaces to the supporting sub-sea process control system The group is managed by an and independent consultant The Operators BP, ChevronTexaco, ENI-Agip, Norsk Hydro, Petrobras, Shell, Statoil, TotalFinaElf The Subsea equipment suppliers ABB Offshore Systems, Cameron Controls, FMC Kongsberg Subsea, Kvaerner Oilfield Products The lntelligent Well/Downhole equipment suppliers Baker Oil Tools. Expro Group, Roxar Production Management, Schlumberger, Triangle Engineering, Weatherford Completion Systems, WellDynamics, Wood Group Production Technology. The Management Consultant Offshore Technology Management Ltd The Aim of IWIS The aim is to agree standard requirements for interfacing and integration of such systems, to avoid costly, custom made interfaces. This will be achieved by agreeing standard requirements for- physical integration of intelligent well equipment into sub-sea control systems Intelligent well power & communication with the sub-sea control systems testing the equipment This will allow intelligent wells to be more cost effectively, quickly and reliably integrated into both sub-sea and surface production systems. The Operator's Vision Operators will monitor data from an integrated production system, from down-hole sensors and control devices,(the intelligent well), the sub-sea production control system as well as surface facilities. The integrated system can be then be analysed and adjusted to optimize overall reservoir, well and facility performance, ideally without well or sub-sea intervention The Supplier's Vision Suppliers will offer a standard intelligent well / sub-sea system interface, greatly reducing the variety of types of interface they have to develop and support. This will lead to lower costs and shorter delivery times, making project proposals more attractive, leading to more projects The standard interface can be refined to improve performance and/or reliability. Suppliers will be able to contribute to improving life-cycle benefits of the well and sub-sea equipment, for ex ample providing monitoring diagnostic and support services post-cominissioning IWIS Group Activities

Deepwater Production Control Systems Production system success requires a high integrity control system, one which provides high availability through intelligent use of modularity, standardisation of component and sub systems, expandability and designed-in simplicity with the appropriate redundancy factors Schedule compression for fast-track developments provides an opportunity for systems with the above features Ceiba Development The Ceiba developments were challenging in that the reservoirs are located in deepwater offshore Equatorial Guinea with no real existing infrastructure. With Ceiba the customer had to consider the interfaces, economics and regulations inherent to every project. Because of the fast-track strategy every consideration was accelerated resulting in increased risk. Safety remained paramount throughout project execution. The project required dedicated resources from all participant companies, and the selected contractors followed the the client's strict ?code of cooperation? Each contractor understood the project goals aid was motivated to meet these fast-track goals, the approach required that all involved proceeded with the project even though final design criteria was in development and the overall work scope was not defined. Both the operator and all contractors proved up to the task Some companies want the latest technology, some seek project implementation expertise and some expect the lowest Capex possible. On Ceiba EPS project implementation (i e schedule) was the main driver. As long as the technology was reliable and qualified for the 20-year field life, then use of pre-designed equipment was acceptable The preferred solutions were off-the-shelf technology that required only slight modification where necessary This approach meant technical risks was decreased, which lead to increased availability for the deepwater development By implementing strategy of running parallel operations, requiring approval of subsequent project phases while earlier phases and operations were not yet concluded both first oil and future phase operations could be accomplished in much faster time frame than similar scope projects. Contracts were only signed with suppliers able to dedicate the correct and necessary resources to bung the project in on time, and without undue cost By issuing functional equipment specification and maintaining a simple and focused invitation to tender (ITT) process, contractor proposals were reviewed and initial awards made within weeks of releasing specifications. Contracts were initially agreed and then further negotiated during early project execution. The selected primary contractors (i e, Cooper Cameron, Bergesen Offshore, ABB Offshore Services, Oceaneering Multiflex, NKT Flexibles and Stolt Offshore) together with the client and its working interest partner Energy Africa enabled project success. The client understood that ‘Companies bringing the right fit of skills and experience to a partnership are the right ones for the job’ Contractors provided standard component systems that included flexibility for operations and expansion Equipment costs for the standard systems were reduced by approximately 20 % compared to a purpose-designed system The shortened review and award period enabled system start-up and first oil in less than fourteen months after discovery.

ABSTRACT An increasing number of wells are being completed subsea. Increasingly these developments are further away from existing infrastructure, in deeper water or exposed to hostile environments. All of these features mean that production must become increasingly reliable. In addition, in such a risk averse industry(especially when considering the challenges above), the rate of innovation (or speed to market) can be greatly hampered, regardless of potential economic benefit. This is mainly due to the current difficulty in demonstrating the reliability of new technologies (such as HIPPS, MFM s , Subsea pumping, Subsea Processing and so on) because of a lack of field experience. The Implication of slower innovation and less understanding of the risks may lead to a slower path to the improvement of both performance and reliability The achievement of reliability requires an understanding of what causes unreliability and how unreliability and its associated risks can be managed or prevented This paper will discuss current industry method of measuring, record and understanding the causes of unreliability with particular attention of using averaging statistics such as Mean Time Between Failures (MTBF). The paper will present methods available to increase the understanding of reliability, including understanding the causes and frequency of failure, through data acquired from filed experience and accelerated testing. The implications of these methods on the development of novel technologies of assured reliability will be explored. INTRODUCTION The North Sea saw the first the first subsea architecture development in the early to mid-sevents Notable success included, Ekosfisk, shell UMC(underwater Manifold Centre) and the Hamilton Argyll field. The shell UMC is still operating today, while the Argyll field is about to be re-opened and revised after being abandoned some tens years ago Subsea field development are becoming increasingly challenging. The challenges include deepwater, HPHT, aggressive environment and ?marginal? economics. It is increasingly important to get ‘get it right’. This means higher reliability and technology development. It is essential that we manage our future by managing the introduction of new technologies. Today#x0027;s global challenges tend to be focused on ultra deepwater developments (>1500m), but mature provinces also have an important part to play, both in terms of fossil fuel but also as a platform for renewable development. (The Figures is available in full paper) Deepwater developments are characterised by high infrastructure and intervention costs, which mean that high productivity levels need to be ensured to recover the exploitation costs. Mature provinces are characterised by marginal reserves where the development relies on minimum CAPEX through minimum infrastructure, and the profitability of the field can be extremely vulnerable to operating upsets and downtime. For technically demanding fields, such as HPHT, the development relies on potentially difficult trade-offs between CAPEX and operability, which can also mean the profitability of the field is vulnerable to operating upsets and downtime. The challenge then, is very clearly high reliability. There is a perception that reliability can be improved, this is discussed more in the following section. A number of high profile early life failures have adversely affected the perception of the subsea business.

ABSTRACT The use of optical fibre in the telecommunication industry has greatly improved communication quality capacity and reliability over the period since it was first introduced. In the offshore oil industry, the use of this technology is still at a comparatively early stage as the first commercial installation was in '97, but the advantages are rapidly becoming clearer as the number of installations increase. Optical fibre has many advantages over the conventional copper-based solutions, such as 1,000-fold increase in bandwidth and reduction in error rate and inherent electrical noise immunity, but it has also introduced a number of new challenges, which include cable construction termination, jointing, testing and handling The experience gamed from the use of electrical systems in the subsea environment was only of limited use here, and the potential supplier had to draw on some of the solutions developed by the telecommunication industry as a starting point in many cases. The use of fibre optics has introduced some novel problem into system and component design. This paper will outline the various areas where the use of optics has clear advantages, the details to be considered when using this technology and will also identify specific application which have proven to be landmarks in the development process The paper will also review some of the problems encountered and the solutions used to achieve a reliable and installable product. INTRODUCTION The acceptance of optical fibre connectors into th e Offshore Oil Industry has been an ongoing process within initial evaluation and experimentation beginning in mid 1990?s Prior to that, in the late 1980's, fibre cables had been used for topside-to-topside links between platforms The five years since the first commercial opatical fibre connector installation has seen the maturing of the technology and its gradual adoption as a technology that supports advances. In subsea architecture in the main, the problem for component supplier has been to provided devices which are as reliable as their electrical counterparts and which can be handled in the same way. As with the early days of electrical systems, there has been a step-wise development through qualification, lessons learned during first application and re-design and re-qualification. With more than 1400 multi-pin connectors delivered on 24+ projects, we are now approaching a tune where the connectors can be regarded as being a mature and field-proven technology. The good news from the reliability standpoint is that once installed, there has not been a single optical fibre failure. With this as an deal starting point, the paper will discuss how the use of optics can enhance both Performance and Reliability lay out the step taken to achieve the present state of the industry. Before that, it is relevant to contrast the development of fibre optic connectors with the advances made in the reliability of electrical connector systems. Electrical Connectors In the begining" the only available connectors were rubber-inolded types such as Envirocon, EO and Brantner, some not even wet-mateable.

ABSTRACT This paper is intended to address the subject of local electrical power generation for remote subsea production development. Allied to this the provision of the infrastructure required to provide basic utilities to the development, specifically controls, processing, pumping and injection. Currently, a remote development, (for the purposes, one which is in excess of 10 km from an existing facility) will require an umbilical for the transport of electrical power, data, hydraulic control fluid and chemicals for injection into the well and the export pipeline. Where water or gas re-injection is required, these will have to be piped to the piped to the development. The export pipelines will carry the primary well product, (oil, gas, condensate) plus quantities of water and solid by-products. These utilities can be provided on site by a surface facility, (platform, EPSO) or a combination of surface and subsea equipment. A remote, marginal development will present problems in terms of the cost of providing utilities, in relation to the value of produced fluids. A balance is sought between the cost of the surface, versus that of installed umbilicals and pipelines run from a distant, existing facility. By generating electrical power locally in sufficient quantities, and uitilising packaged, subsea processing and pumping equipment, it is proposed that greater profitability can be achieved from marginal developments. Summary It is feasible to power a remote subsea development, requiring separation and boosting of produced fluids, with a local power supply generated by a moored, wind turbine. Table 1(all tables, figures and calculations are printed at the end of this paper) indicates a possible economic breakpoint for capitol equipment cost, at an offset of 15 km distance. That is to say, the cost of providing a high voltage power line, a control umbilical and water injection line will exceed the cost of providing a wind turbine on a flotation structure, with linking catenary umbilical. Table 2 indicates likely power requirement for two production options, and the load shedding regime to enable continued production, at reduced levels of available power. Option 1 show a lower overall power requirement attributable to complete separation of produced liquid and gas, and could be supported by a 2 MW surface facility. Option 2 shows higher power requirement, commensurate with partial separation and multi-phase pupped export. This could be supported by a 5MW facility. In general the rated power the turbine will be achieved at a wind speed higher than the mean value found in the North Sea and North Atlantic (see Figure 1- European Wind Atlas) and the mean power output will be equivalent to the facility part load (1 MW for option 1, and 2 MW for option 2) The wind regime at deepwater ocean location is reasonably consistent, and the facility will at most times be operating between low and full load, with only short and occasional periods at standby load. Periods of calm are experienced most frequently during midsummer, when product demand is low, and when planned field shutdown for maintenance is usually carried out.

INTRODUCTION The Otter field, formely known as wendy is a small oil and gas accumulation discovered by Phillips Petroleum in 1977. In 1997 Fina appraised the reserves with a second exploration well and TotalFina proved the geological model in 2000 with a third exploration well. The Otter filed is located in 210/15a block in the Norther UK North Sea sector and he s2030 m below sea level in 185 m depth of water. Many development scenarios had been considered but the oil price, reserves in place and the low reservoir pressure requiring artificial lift to extract the crude initially proved a standalone development uneconomic However, spare processing capacities of neighbouring offshore facilities re-activeted interest in the development. In January 2001 Fina Exploration Ltd, a wholly owned subsidiary of the TotalFinaElf group, was commissioned on behalf of other block licencees (Agip, Exxon Mobil and shell) to operate the development. At the time of writing the sub sea facilities are in the process of being deployed and crude production is expected 3 rd quarter 2002. OTTER Field Development Description Figure 1 illustrates the general Otter Field architecture Figure 2 is a schematic illustrating the crude patgh through the downhole assembly, subsea facilities and the platform The Otter development will produce from three subsea production wells and will have reservoir pressure support via 2 subsea water injection wells. The filed will initially flow naturally for 6 months to 1 year, but thereafter production will require to be maintained by the use of down hole installed Electrical Submersible Pumps(ESPs) Reservoir product will flow through a 5–1/2 tubing string, Via the Xmas tree and subsea manifold. And finallythrough the sea line to Elder platform processing facilities. Elder is operated by shell and located 21 km South East of the Otter sub sea facilities. The reservoir effluent will initially be a mixture of oil and gas but increasing percentage of water will be produced being either pure formation and injected waters. The subsea facilities are based on an integrated template / manifold system incorporating 3 production and I water injection wells. The second injection well is a satellite lied back to the manifold and is some 25 m distant. Each well will have horizontal trees installed. For reservoir management purposes, the subsea manifold incorporates facilities for routing the production from individual well via a subsea multiphase meter mounted within the manifold piping. The manifold also incorporates facilities for round trip pigging.(The Figures is available in full paper) The subsea chemicals distribution provides the manifold, X/mas trees and the wellswith chemical injection, as appropriate, for hydrate mitigation, scale, corrosion, H2S and emulsion control The effluent will be evacuated via a 10 10″ insulated carbon steel sealine to the Eider platform Injection water will be provided by Eider platform via a 10″ non-insulated pipline.

CONCEPT The use of minimal intervention operations and keep it simple designs lead to successful distributed control systems on well buoy type applications To make minimal intervention successful a balance of the following characteristics must be used Extremely high availability Good reliability Minimum complexity and size High levels of remote live diagnostics drawings both of the control system and the production facilities High level of system integration and low system diversity Obviously the first three characteristics are a must on small remote installations, as equipment space is minimal and accessibility is not good Therefore high availability systems guarantee operability for extended periods At the simplest level it can be achieved by a minimum of components, but this is not often the case as most applications need to be designed so that they continue to function even when a fault occurs This generally leads to the use of some form of redundancy The fourth item is in the man an important characteristic As experience has shown us, remote diagnostics as a requirement by operations personnel, is essential to providing maximum production, with minimum support costs Using live diagnostic drawing it is possible to pinpoint faults, and ensure dispatch of the right person together with the right spares, keeping unnecessary visits and down time to a minimum. The last characteristic is where there is a need for simple design, and getting away from the box on top of a box syndrome, which is most evidently used in many system designs The concept of box on top of a box inherently makes the system very complicated As every box, or part of a system which interfaces to another third party type of box, is laden with complexity and bugs waiting to emerge Also the component count increases dramatically which in general proportionally impairs the overall reliability of the system To overcome these pitfalls the use of a simple single box which comprises all of the above criteria is needed. In doing so, it will remove the knit one purl one mess of interconnects between boxes keeping component count down and helping to keep reliability high and overall cost down. This type of design will also help operations personnel to understand the mass of real time information which is rapidly changing in then system By unification of different systems like ESD, F & G and Fiscal Metering under the same information technology umbrella, operations personnel can view their facilities through the same unambiguous window, from the production base right down to the field terminals(Diagram 1 and 2 are available in full paper) Diagram 2 shows a single box comprising all the integration to various Fieldbus technologies, with fully open system connectivity and the capability of bringing in conventional I/O wiring, simplifying systems design completely. On top of this add the ability to bring back to the operator a real time diagnostic drawing which shows all process changes as they happen, you have a unique and very powerful system. The units can also be networked together to form larger systems using standard LAN type technology like Ethernet and open system type TCP/I/P protocols The LAN acts as the flexible backbone for the system and it allows for straight forward expansion if the need arises.

ABSTRACT The need for more and more flexible subsea control systems led ECA to develop a new concept, called TOV, based on fully standard and very light modules linked to a trunkline network After a long term test carried out in Norway, the system has been chosen by Total Austral SA, Bridas Austral SA and Deminex SA to equip the first subsea field in Argentina, Argo Developed in two phases, Argo comprises two subsea wells and a subsea manifold, located 12 7 away from the existing Hidra platform. The TOV system is organized in a daisy chain and uses six modules per well and an additional eight for the manifold Benefiting from the main characteristics of the TOV, the complete system is simple, light, and reliable. On the first well, already installed, the previously sequential hydraulic system is easily replaced, using the same interfaces, by the TOV electrohydraulic control, where conventional pod would have needed an additional structure. Though first installed in the shallow waters of Argentina, the TOV system is optimally designed for deepwater fields, considering its light weight, small size ideally adapted to ROV intervention, and 2000 m depth rating FOREWORD The offshore production of oil and gas is moving very quickly in several directions Contractually speaking, large groups are preferred, financially, the budget is always lighter than the previous one, and technically, it is more and more difficult To deal with these trends, the master word is flexibility In the control system business, the electrohydraulic pod is, today, very well implemented and represents the basic offer for subsea systems. In order to improve the flexibility previously mentioned, ECA developed, a couple of years ago, a new concept called TOV which can be described as a mini-pod, or a one function pod. After a long term test in Norway, and thanks to the EEC funding within the THERMIE programme, this concept has been chosen by Total Austral SA, operating the Argo field in South Argentina, in partnership with Bridas Austral SAand Deminex SA. This paper describes the application of the new TOV concept to the Argo field 1. GENERAL PRESENTATION OF ARGO 1.1. Foreword The Argo field is developed as a satellite to the Hidra field in south Argentina The lines will be tied in to the Hidra centre platform Communication between Rio Cullen, onshore, and Hidra platform is ensured by a telemetry link Argo will include two subsea wells within a phased development The first phase consists in a single subsea well tied back to Hidra centre by use of an 8″ production line, a 4″ gas lift line and a control umbilical. In order to allow for a simple installation of the second phase, a production and a gas lift manifolds are installed within this phase. 1.2. General organization (figure 1) Figure 1 represents the organization of the complete field The first phase includes a 12 7 km production line (8″) a 12 7 km gas-lift line (4″) a control umbilical a subsea well ARGO I a production manifold a gas lift manifold