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 Subsea control systems are becoming more complex. As they are moving into even deeper water, using more complex equipment and collecting more data, the demands on their performance are increasing. This has resulted in the need for faster data retrieval, more complex programmable processors, bigger power-hungry devices and continual technological progression. Thus whilst there is a desire in each project to keep innovation to a minimum and use only what is tried and tested, in reality the industry is seeing a steady product development and evolution. Nowhere is this more apparent than in the heart of the control system's subsea control module (SCM). It is no secret in industry that the SCM is one of the systems with the biggest reliability challenges. Chevron collects all the subsea reliability data in a database called Subsea Master. On reviewing the data of the SCM reliability statistics, not surprisingly, Chevron has found them to be one of its principal bad performers. Further analysis revealed that SCM reliability was not as high as desired or expected, and attempts to correlate against the various fields and environmental conditions revealed little. It appeared that there was no correlation between environmental factors and failure rate, or even the age of the systems and failure rate. However one thing clearly stood out, early life failure was a major problem. Background Chevron reviewed all of its conventional electrohydraulic (EH) systems with the SCM installed on or near the tree or manifold (see Figure 1). In most cases the control system is by a water based control fluid. An SCM typically controls the functions on a subsea tree or manifold and is designed to be installed and retrieved without disturbing the major pieces of hardware. Depending on water depth, this operation may be performed by a diver or a remotely operated vehicle (ROV). There are three main types of SCM currently in existence: all-hydraulic, which was historically used in the late 1970s and early 1980s; EH, which is the most common technique used since early 1980s; and all-electric, a primarily new technology that is likely to be the way in which controls will evolve. The SCM is the brain of subsea controls equipment. Made of computer-like electronics called the subsea electronics module (SEM), it normally receives power and communications through the subsea umbilical. The SEM, in turn, controls a hydraulic manifold system using a selection of solenoid driven control valves, which then directly drive the subsea hydraulic functions. Additionally, the SEM is connected to external sensor systems providing production condition information, and a selection of internal sensors condition monitors the overall system. The SCM's components and electrical connections are encased inside an oil-compensated outer housing that protects them from the elements. The hydraulic, electronic and electrical interfaces feed and distribute electrical and hydraulic power to the external sensors and valves that are usually installed into the SCM's base plate.

ABSTRACT At a time when there are major challenges facing the oil and gas industry, particularly with respect to the lead times on umbilicals, remote locations and increasing water depths, alternative thinking and approaches are playing an important role in finding solutions to these issues. To address this, this paper reviews the case for secure, high reliability acoustic signalling through water, with applicability to communication requirements for the subsea industry. Nautronix Acoustic Subsea Communication (NASCoM) NASCoM is the name given to the family of products discussed in this paper. Starting with Nautronix Acoustic Subsea Blow-Out Preventer (NASBOP) control system, this is a proven safety critical system that is currently used for subsea drilling operations by various operators worldwide. NASBOP is an eight-channel acoustic system that was developed in 2002 to meet Shell's requirements. Shell had recognised the benefits to its drilling operations - particularly development drilling - from the surface BOP drilling technique, but required a reliable acoustic control and monitoring system to make the concept a reality. This is because with a surface blow-out preventer (BOP) there is no control umbilical running to the seabed. Shell identified Nautronix' Acoustic Digital Spread Spectrum (ADS2) signalling as the most advanced and robust available in the market for this critical application. Subsequent to this, Nautronix worked closely with Shell and Cameron, the provider of the subsea isolation device, to develop NASBOP as the primary control and monitoring system and to provide an emergency disconnect capability. The system was first used in Brazil in 2926m of water. NASBOP provides a number of benefits to the customer. The most significant is that it is an enabling technology that allows the use of surface BOP operations with a subsea isolation device. NASBOP provides reliable control and monitoring of the subsea isolation device, as well as the capability to expand the depth rating on the majority of rigs through the use of surface BOP drilling. The use of a reliable acoustic control and monitoring system provides the possibility for reduced capex on umbilicals in other applications, and hence will reduce maintenance costs. The concept can also be expanded to full BOP control called Nautronix Acoustic Subsea Multiplex (NASMUX, discussed in Section 3). There were a number of design criteria which the NASBOP system was required to meet. Obviously, the reliability of the system and, in particular, the acoustic system was critically important to a successful outcome. As with all control systems, the probability of failure and demand had to be low and there had to be no possibility of an accidental triggering of the system. Due to the increasing issues of frequency management and conflicts in field developments, the system required to be immune to interference from other acoustic systems. Redundancy was always a key consideration in all aspects of the system, and good system operability was also a requirement. It is thought that the success of NASBOP has changed the perception of the drilling companies using this acoustic system

ABSTRACT Underwater acoustic technology has been revolutionised over the last few years by the introduction of complex signalling techniques into subsea acoustic control, monitoring and positioning systems. This technological innovation was made viable by the increasing availability of low power digital signal processing (DSP) devices resulting from the dynamic growth in the mobile telecommunications industry in recent years. Prior to this, such devices were too power hungry to be considered for use in commercial battery-powered equipment, such as subsea transponders, and through water data communication links. Consequently, acoustic system manufacturers were able to re-examine their approach to remote subsea control and monitoring as well as offshore positioning, resulting in a step change in the performance of these systems over recent years. Additionally, Sonardyne has recently launched its second generation wideband systems, which build on these advantages by providing a more flexible modulation scheme that can be configured for the optimum trade-off between data rate and robustness - for even the most challenging environmental conditions. This process has also seen the introduction of new terminology: digital acoustics, wideband, spread spectrum, DSP and others into the field of subsea acoustics. This paper is intended to provide guidance and clarification to existing and potential users, as well as those who specify these systems. It summarises the new technology, how it differs from conventional tone based acoustics and how it provides improved performance and cost-savings in existing subsea acoustic control, monitoring and positioning applications. Drawing upon Sonardyne's real-world experience, it provides examples of data from some recent offshore projects to illustrate the performance improvements achieved. It also identifies the opportunities presented by the new acoustic technology, for replacement of umbilical cables by high integrity acoustic links in certain applications, offering the potential for substantial savings in both capital and operating costs. Introduction Acoustic systems have been used for many years in the offshore industry for positioning and underwater navigation as well as certain control and monitoring applications, such as acoustic backup blow-out preventer (BOP) controllers. As operations have moved to ever deeper waters and field development times have decreased, the concentration of rigs using acoustic positioning systems within relatively small field development areas has increased. This has led to increasing overcrowding of the acoustic spectrum in busy areas, such as the Campos Basin, and the potential for the acoustic system on one rig to interfere with that of its near neighbours, with potentially serious consequences. With a very limited number of acoustic channels available, the management of channel allocation between neighbouring rigs has become increasingly difficult as the rig population have grown. This has placed increasing demands upon acoustic system suppliers to provide solutions that will enable many users to share the same acoustic spectrum without mutual interference. The solution to this problem lies in the adoption of digital wideband signalling techniques, which allows many more channels to be accommodated within the same acoustic spectrum than is possible using conventional tone based acoustic signals.

ABSTRACT Management of component obsolescence was seen as an important issue as early as the UMC development in the mid-1980s. Since then the approach of operators and suppliers alike has been generally limited to reactive component purchases. Some work on backwards compatibility for new systems has been seen in recent years, however, this is often limited by operator unwillingness to make firm future development commitments. This paper will look at how ongoing changes to the legislative and technical environment are affecting the obsolescence management processes within the subsea controls industry; specifically it will focus on the effects of the Restrictions on Hazardous Substances (RoHS) directive and die-shrink in the semiconductor industry. Having made the case for change, the paper will go on to present a model for proactive obsolescence management based around the concept of an obsolescence timeline approach tailored to the subsea controls industry. The paper will conclude with a case study, showing how this approach can be applied in practice. INTRODUCTION This paper builds on existing work in the area of obsolescence, including presentations made at the September 2005 Society for Underwater Technology (SUT) meeting (Cretenet, Roberson and Bruce) on obsolescence in Aberdeen. It starts by reviewing strategies used to date in the subsea controls industry, comparing them to a generic set of strategies taken from the military sector. This is important, as obsolescence management from the military supplier's perspective is well developed and there is much relevant work the oil industry can adopt. The main focus of this paper is on the electronic components, subsystems and products used in subsea controls. The issues raised and recommended approaches are, however, also relevant to obsolescence management across the oil and gas industry. Existing StrategiesM A list of strategies used to manage obsolescence in subsea controls equipment is shown below: Do nothing Push the problem down the supply chain Spare parts holdings Last-time buy Standardisation Emulation Redesign By far the most common approach has been ‘do nothing’ and, to be fair, to date it has proven to be workable strategy, but increasingly this is becoming a high-risk position for suppliers and operators alike. Depending where the company is in the supply chain ?pushing the problem down the supply chain? has its attractions, but in reality is no different (and potentially worse) than doing nothing unless the company actively manages and funds the process. The rest on the list, while less commonly applied, all have a role to play in obsolescence management but, taken individually, have their own problems. Strategies Common to the Military Obsolescence Management The list below is based on a presentation by BAE Systems for generic obsolescence strategies used in the military sector (Call 2005). The figures in parentheses provide an estimate of the average non-recurring engineering (NRE) cost associated with each solution on an individual part basis.

ABSTRACT Platelets ® are small mechanical objects which can be injected into pressurised fluid conduits to seal and locate leaks. Previous applications of the technology have been focused on large-scale pipelines, however, this paper will describe a novel application of Platelets ® to seal and locate leaks in small bore subsea umbilical lines. Leaks in these systems are particularly problematic because they are difficult to locate, and the eventual external egress of fluid may be some distance from the actual line failure due to the presence of additional outer sheath(s). The fundamental principle behind the technology is that the creation of a Platelet® seal, which is often effectively an instantaneous event, modifies the pressure and flow profiles in the line. From this initial insight several complementary approaches to leak location arise. The changes in flow and pressure may comprise both transient and steady state responses. It is therefore possible through remote pressure and flow monitoring to identify the instant of that change of state or, in some instances, the pressure transient. Additionally, through ?time of flight? measurements "again using remote monitoring" it is possible to locate the position of the seal and hence the leak to a high degree of accuracy. This paper will describe the theoretical background to these developments and go on to exhibit the outcomes from a series of tests on long umbilical lines. These tests include a successful ‘leak’ location on an 84-km-long umbilical, which had been achieved prior to its proposed subsea installation. In addition to the technology development itself the crucial issues of risk to infrastructure, hazard analysis and the establishment of the limits of the approach with regard to existing infrastructure and systems will each be considered. Background-Platelet Technology TM A Platelet TM is a discrete particle which is released into a pressurised pipe flow for the purpose of sealing a known or suspected leak. When a Platelet TM encounters the region of modified flow around a leak, fluid forces entrain it into the leak and hold it against the pipe wall; this facilitates sealing, and also marks the position of the leak for subsequent detection. Once entrained, a Platelet TM is held firmly in place by the pressure differential acting across it. Each Platelet TM that is released into the line has a certain probability of being entrained; statistical analysis carried out prior to deployment enables the optimum batch size to be selected to give the highest chance of a successful seal whilst keeping the volume of injected Platelets® to a minimum. Platelet Technology-takes a radically different approach to pipeline integrity in that it seals and then locates leaks in a single integrated process. Whereas conventional leak sealing techniques require direct access to the leak site, the elegance of Platelet Technology TM lies in its ability to be implemented remotely, mimicking the human body to work with the pressure in the line and seal from the inside. Crucially, Platelets® are best deployed when there is flow in the line; this means they can be introduced as part of a routine pipeline operation resulting in minimal disturbance to production.

ABSTRACT The Snøhvit project in the Barents Sea is a milestone in subsea oil and gas development, with a record-breaking offset and all subsea facilities tied back to shore. The key elements of technology required to implement such a new development with a subsea production controls system qualified to operate over a distance of 220 km are: Long-range communications with no repeaters Long-range supply of power at up to 3 kV High data rate requirements HV electrical and fibre-optic wet-mating connectors A cost-effective main umbilical Diverse back-up strategies This paper will focus on the technical achievements in executing this ultra-long offset subsea-to-beach project which is now nearing completion. The implementation of fibre-optic communications, subsea data routing, high voltage and power distribution technologies Back-up communications on power system (COPS) The back-up intervention control system (BUICS) designed for use in the event of main umbilical non-availability Snøhvit-Field and Project Background The Snøhvit project in the Barents Sea will be the first Norwegian and European production and export facility for liquefied natural gas (LNG). The field lies 140 km from the coast of northern Norway, and its production will be piped to a receiving and liquefaction plant on Melkøya Island outside Hammerfest. This field is the first development in the environmentally sensitive Barents Sea. It is located at 71 ° 30? north, within the Arctic Circle and 1,000 km north of the Norne field, currently the most northerly producing field offshore Norway. After processing and liquefaction, LNG will be shipped in special carriers to markets in Spain and the United States. Approximately 70 consignments are due to be exported annually over the field life of almost 30 years. Snøhvit is the first Norwegian offshore development with no surface-piercing installations on the field. The pipeline carrying production from the subsea installations to Melkøya is 145 km long?a world-record distance for piping an unprocessed well stream. The associated subsea control system that has now been installed is a world record for long-distance tie-back. In addition, the control system is designed to support the future Askeladd development where the total offset will be 178 km. All technology has been qualified to 220 km. It has taken time for the technology to be developed such that the field becomes feasible. The primary technology gaps that had to be closed were the long offset control and compact, efficient LNG plant, together with long offset multiphase flow. In combination these technologies allow subsea development without the need for a conventional surface structure. The first gas discovery was made in 1981, and the blocks containing the three discoveries were awarded in 1984 and 1985. A total of 16 exploration wells have been drilled in the area. In May 2002, Statoil obtained approval from the Norwegian government to develop the field. By the 12 June, construction work had started on Melkøya with first production scheduled for summer 2007.

Abstract A three-dimensional finite element analysis (FEA) modelling technique for multi-axis stress and strain analysis of metallic tube umbilicals has been developed utilising Abaqus FEA software. The FEA model has been compared against full-scale test data derived from bending and tensile tests and is shown to be precise in its comparable response to strain and load. The modelling technique can be used to produce virtual prototypes that can then be used to analyse stress concentration zones, which might not be detected using a standard mathematical approach to umbilical analysis. Introduction Umbilicals for subsea static and dynamic operation, such as in Figure 1, are being pro-posed for increasingly arduous service, such as is prevalent in the deep waters off the West Coast of Africa and new developments within the Gulf of Mexico ( www.offshoretechnology.com 2006). The most common method adopted to assess the suitability of umbilicals for such service has been to employ models of the umbilical structure (when available) using empirical and mathematical techniques based upon historical data and which are validated through expensive full-scale testing. Due to the diversity of design of umbilical structures, it is necessary to employ a high degree of conservatism in the design analysis to ensure sufficient confidence in the analysis outcome. As water depths of subsea oil fields increase and umbilical designs become more complex, the applicability of empirical and mathematical models will increasingly come into question. It may not be possible to design the umbilical structure to withstand installation, or the service or fatigue stresses due to the high level of conservatism inherent in the conventional analysis techniques and thus more advanced analysis techniques are required. Conventional two-dimensional FEA techniques are commonly used within the subsea industry and provide an accurate snapshot of the planar response of the umbilical to mechanical and thermal stresses and strains. However, a high degree of interpretation needs to be employed when projecting the two-dimensional response of the structure into three-dimensions, which can lead to inaccuracies and errors due to the helical lay of the umbilical components. This is especially true when examining radial compression"typically assessed during umbilical installation analysis"and stresses due to bending and tension typically assessed during dynamic service and handling analysis. Three-dimensional FEA improves the accuracy of the umbilical model; the helical response of the components within the umbilical structure as they interact in all three planes can be predicted. When accurate material models are employed, the umbilical stresses and strains can be predicted with a high degree of accuracy and, as the FEA model is umbilical design specific, the requirement for conservatism to be employed in the analysis is removed. The three-dimensional FEA modelling technique, once validated through full-scale product testing, can be employed to assess any umbilical design which, in addition to stress and strain analysis, provides a number of additional analysis possibilities:

INTRODUCTION Tordis Background The field was discovered in 1987 and developed by former Saga Petroleum and started production in 1994. Statoil took over the role as operator 1 January 2003. The Tordis oil field is located in the Tampen area in the North Sea; and the water depth is roughly 200 m. The field was developed as single subsea satellites, tied back to Gullfaks C platform via a central subsea manifold. Technology Assessment and Qualification Programme A comprehensive technology assessment has been performed. Key technical elements were classified and given criticality rating. To ensure robustness of critical components and close the remaining technical gaps, an extensive technology qualification programme (TQP) has been performed.(Fig. 1 is available in full paper) Project Summary The project is the world's first commercial application of subsea separation (full scale) in combination with water re-injection and multiphase boosting. Subsea process facilities are designed to handle high sand production and contribute to reach 55 percent recovery from a subsea oil field. Injection of produced water will reduce water discharge to sea. A comprehensive technology qualification programme has been performed. Low pressure production is scheduled to start in October 2006, and the subsea processing facility is scheduled to start in October 2007. (Fig. 2 is available in full paper) Field Layout The Tordis Subsea Separation, Boosting and Injection (SSBI) station field development will consist of three main structures: Pipeline inline module (PLIM) SSBI station Satellite Xmas tree (water injection) The purpose of the Tordis SSBI is to separate water and hydrocarbons from the existing Tordis production fluid and to boost production to Gullfaks C by subsea multiphase pumping. The separated water will be injected into a nearby disposal well that is assisted by a dedicated subsea water injection pump, which also will be located at the SSBI. The two existing flexible production flowlines from the Tordis central manifold (TCM) to Gullfaks C will be disconnected from the TCM and moved and connected to a new PLIM. Flexible production jumpers will be installed between the TCM and the PLIM. Flexible jumpers will also be installed between the PLIM and the SSBI, and between the SSBI and the Xmas tree. The production from the existing Tordis field will be routed to the SSBI for separation and injection of the bulk water. The resulting production is routed back to Gullfaks C. The subsea control system will include a dedicated SCM at the SSBI. New control umbilical and HV power umbilical (for the pumps) will be installed from Gullfaks C and terminated on the SSBI. In addition the new control system will boost the existing system. SSBI Station Process Layout The production from the existing TCM will be routed to the PLIM and further onto the SSBI and from the SSBI to the receiving facility Gullfaks C. The PLIM also gives a possibility for bypassing of the SSBI.

ABSTRACT This paper will document a mapping process undertaken to quantify data sources within BP's subsea assets during 2005. An important additional goal of this paper is to provide feedback to the many instrument and subsea control system vendors who provided valuable input to the work. The initial need for a subsea data-mapping exercise was identified following a similar exercise covering BP's topside data sources for the field of the future TM program. The aim has been to quantify current subsea data types together with likely trends, to inform both field of the future TM activities and future BP subsea control architecture use. The paper concludes that a) the umbilical still presents a major restriction to improvements in data flow within subsea control systems; and b) looking at how current developments in subsea communications technology may be focused to meet BP's future goals. INTRODUCTION In early subsea developments telemetry data was limited to basic analogue transducers each with its dedicated connection to the surface. With the advent of multiplex control systems that needed to meet the growing complexity and step-out distances, a potential for far greater levels of telemetry became practical. The effective data rates of early systems were typically 1200 b/s. This compared well to dial-up modem speeds used for computer access at that time, which were often no quicker than 300 b/s. However, with the limited range of connected instruments field update times were more than adequate for effective production monitoring. Moving quickly forwards to the present day, the fastest communication speed for a control system installed last year?by BP for the Gulf of Mexico FMC Thunder House and Nakika projects-was only 2400 b/s. While there are faster copper and fibre based systems in the market place, these have their own drawbacks, for instance in terms cost, or implementation difficulties with longer step-outs. The initial need for a subsea data-mapping exercise grew out of a concern that potentially useful data was being delayed or left subsea because of the limited data bandwidths available. This followed a similar exercise covering topside data sources for the field of the future TM program. The field of the future TM project was intended to define and develop methods of utilising advanced technologies and processes, while accelerating ?better decisions faster? around production, expense and investments. The stated aims of the data mapping activity were therefore: To quantify current subsea data types together with likely trends To inform BP's ongoing field of the future TM program on the potential problems associated with trying to exploit subsea data fully To improve BP's future use of subsea controls technology Process Figure 1 shows the basic processes followed for the subsea mapping. To make the results more relevant Rhum, Schiehallion and Greater Plutonio were chosen as ‘real’ data sources for the work. Data from these was combined with a selection of other instrument and controls suppliers to build up a complete picture of the subsea data environment. Information was collected through directed interviews and questionnaires with follow-up telephone conversations where needed.

ABSTRACT This paper discusses the utilisation of steel tubes in subsea control and injection umbilical. It examines what has happened in the past, where the industry is at the present time, and the future direction in respect of these product types. It also contrast differences in design requirements between thermoplastic hose and stell tube components. The contents of the paper are provided to assist the reader to appreciate and comprehend the difficulties encountered by the umbilical manufactures and operators in successfully utilising this product type within subsea hydrocarbon production systems. It is not the intention of this document to prejudice specific tube materials and/or the companies and processes associated in their manufacture Umbilicals form a critical link in a subsea production system and, despite the talk of umbilical-less control systems, it seems likely this vital linkage will be a part of the industry for the foreseeable future with both thermoplastic and steel tube components or combination thereof. It is in the industry's interests that whichever component type/combination is chosen, that the product is fully understood, properly designed and well manufactured to provide the Operators with a lasting, trouble free product Historical Subsea production systems have been utilised for almost 40 years and in that period of trine many hundreds of subsea wells have been installed worldwide. It is unusual, even now, with this large number of wells to find two systems which are alike The process of technical evolution, coupled with the design engineer s desire to continually innovate, has resulted in the constant redesign and customisation of subsea production systems. In the pioneering era of subsea production, wells were remotely controlled using umbilicals incorporating thermoplastic hoses bundled together and contained within an extruded thermoplastic sheath. Seabed stability and tensile strength was achieved by means of a wire rope tied to the umbilical during installation. Such products were prone to damage and the wire rope was replaced by the two layer wire armour concept which provides all-round mechanical protection to the internal functional components. During the mid 1980's, with relatively short tie-back distances, director piloted hydraulic control systems were a design consideration for subsea production systems. As a consequence some interest was shown in using steel tubes for control lines where response tune was considered to be an important was consideration. Some umbilical were supplied containing steel tubes, mainly for the Brazilian market. However such products had limited success due to the following factors The umbilical were supplied as a 'flatpack constriction? whereby the steel tubes are laid parallel to each other embedded in a thermoplastic polymer extrusion. Such a product with minimal functional component protection, present installation difficulties due to its uni-directional bending characteristic and, additionally effects with sea currents. Steel tubes were constructed in stainless Steel (grade 316 and were prone to corrosion. Outside of Brazil, steel tubes in umbilical service started in the early 1990's and in recent years have found increasing usage, with the trend to deepwater subsea production systems, higher operating pressures and the requirement to withstand very high seabed hydrostatic pressures.

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

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.

ABSTRACT A novel autonomous power and control system (APAC) is being developed by Total The system is designed to replace the control umbilical on subsea producing wells. The system comprises 2 thermo-electric generators (THEGS) which are housed m flowline spools, lead acid batteries, a closed loop electro-hydraulic control system and its associated electronics and 2 hydro-acoustic communications links. Prototypes of the main elements were built and tested independently to prove their feasibility Subsequently a full scale production system has been built and tested In the final development phase, the system will be installed on a subsea well m order to prove its long term performance and reliability. This paper looks briefly at the background to the development of autonomous control systems and to some of the design considerations The APAC development process, up to the completion of performance testing, is described. Finally, economic issues, comparing the cost of autonomous versus conventional systems, are addressed. INTRODUCTION APAC is a collaborative effort funded by Theme and FSH (Fonds de Soutien des Hydrocarbures) It represents an extension of an earlier research and development (R&D) project for Total's Hunter field (HAPAC) and incorporates technology developed within a separate project called SPARCS. HAPAC-Hunter Autonomous Power and Control System - funded by Total, Bertin, DCN Cherbourg and Sonardyne. It involves research into a gas driven turbo-generator, a thermo-electric generator and a long range hydro-acoustic communications link W A C was to be installed on Hunter, a single gas well m the southern sector of the North Sea Originally planned for 1994, the Hunter Project has yet to be sanctioned. SPARCS - Subsea Powered Autonomous Remote Control System - funded by Kvaerner FSSL, Enterprise Oil p 1 c and Elf Enterprise Caledonia Ltd, SPARCS has been developed over a number of years Conceptual design started m 1989 and offshore trials took place off Falmouth in early 1996 The SPARCS system comprises a turboelectric generator, a thermo-electric generator, sea water batteries, lead acid batteries, a closed loop hydraulic control system and a hydro-acoustic link. (The figure is available in full paper). APAC has completed successful integration and performance testing at DCN Cherbourg The next stage of the development includes a field trial on a producing well The main objectives of the field trial are to. prove the concept of autonomous well control prove the long term viability of an autonomous subsea control system verify the performance of thermo-electric generators verify the performance of long range acoustic links m all environmental conditions verify the performance of lead acid batteries verify the performance of a closed loop subsea hydraulic power unit (HPU) verify the performance of a buoy based radio and/or satellite communications link

ABSTRACT The growth in subsea completions at increasing step-out distances and the reduction or elimination of new build topside facilities has continued. When this trend is combined with improved reservoir management using intelligent sensors and the results of current development projects using downhole and seabed metering, separation and process equipment, the volume of control system and sensor data will have expanded beyond the capacity of conventional communication systems. Fibre optics technology offers the necessary long step-out, high speed, high bandwidth data transmission. An added bonus of the move to fibre optics is noise immunity, and consequent high data integrity needed for safe operation in the severe EMI environments created where high power motors and power cables are used subsea. This system uses telecommunications grade single mode optical fibre with laser generated optical pulses at 1550 nm as the information carrier. Multidrop communication at data rates of 2 0 Mbs −1 and with error rates as low as 1 10 9 h as been achieved. The modem supports unrepeated communication over distances in excess of 100 Km Modular systems installation is possible, using proven wet mate hybrid connectors Equipment and installation costs are comparable and in many cases significantly cheaper than for electrical communication, demonstrating that optical communication is a technically and commercially feasible and reliable alternative to existing electrical systems INTRODUCTION The high cost and hazardous nature of recovering hydrocarbons offshore, have led to the trend to reduce topsides facilities, and to the growth in subsea production control Subsea control capabilities have been considerably enhanced by the recent generation of microprocessor based systems. These advanced controls facilities, enable the provision of a subsea interface for advanced technology installations such as, artificial reservoir lift systems, multiphase flow measurement, down hole monitoring and intelligent sensors as well as the conventional tree control functions Also recent development projects to install seabed separators with direct water re-injection, and multiphase pumps have required development of the subsea control and monitoring systems. However these advanced technologies impose increased data processing and communication overheads. These additional communication requirements appear as closed loop motor control, local sensor support and data processing, multichannel communications, downloading of calibration software, intelligent diagnostics and provision of dedicated, uninterrupted communication channels. This expanded functionality has created a need for increased data transfer. In particular the controls umbilical must now provide a data highway capable of supporting communications between topsides control systems and a network of Subsea Control Modules (SCM) and then extended control functions Traditionally this has been implemented using a number of either dedicated shielded twisted pairs or coaxial conductors, or by utilising the power conductors for Combined Power and Signal (CPS) The available data transmission rates have been necessarily low, often of the order of a few hundred bits/sec, to reduce errors, maintain reliability, and provide an economical solution This transmission performance is no longer sufficient for the inevitable requirements of the offshore industry A high bandwidth communication link is now a critical enabling technology for the continued development of subsea control

ABSTRACT The Subsea Electrical Power Distribution System (SEPDIS) is a combination of a high voltage transmission system and an industrial power distribution system Naturally an electrical power distribution system of this type requires a given level of operational control and monitoring when used in a surface application Additional monitoring and control functions and novel design features will be required when the equipment is to be deployed subsea The SEPDIS control system must be designed to meet all the required electrical functions and be fully adapted to subsea use in terms of underwater performance, availability, reliability, installation, retrieval and maintenance requirements It should be remembered that any form of subsea intervention and maintenance will inevitably incur high costs and so the system must provide all the necessary control and monitoring functions to enable safe and reliable operation of SEPDIS in the intended manner 1.0 INTRODUCTION The oil and gas industry has, in recent years, focused more and more on marginal and complex fields These type of fields very often imply long offset distances and/or substantial water depth The challenge, both for the oil companies and the manufacturing and system supplier companies, is to develop technology facilitating economic attractiveness of these type of fields A large number of tools have been developed and offered to the market In this paper some of the tools requiring high energy supply for operation will be mentioned Subsea separation and injection systems, in ABB terminology called SUBSIS, is a very attractive concept improving the economics of marginal, complex and fields approaching the high water cut period The general idea is to separate out the water from the well-stream at the seabed, before it enters into the production pipeline The produced water is then re-injected into a disposal well or possibly back into the reservoir for pressure support Depending on the amounts of water produced from the separation process, one or more subsea water re-injection pumps are required The typical unit rating of these pumps is 0 8–2 0 MW Subsea multiphase booster pumps feature increased oil production by lowering the flowing wellhead pressure, compensating for increased well back-pressure caused by increasing water cut, overcoming function losses in flowlines (increased utilization of the flowlines), etc The typical unit rating of these pumps is 0 5–1 5 MW Several other subsea power consumers can be mentioned, such as subsea ESP's, booster pumps, water injection pumps, wet gas compressors, centrifugal process separators, heat tracing, etc All of the above tools are designed to enhance oil and gas production, still they themselves require energy to operate and this energy has to be controlled, very often by quite sophisbcated techniques Several investigations show that an electrical power supply system will be the most cost efficient solution for driving all the subsea processing pumps and other energy consuming systems at the seabed There are two possible man concepts, the first based on a topside electrical power distribution system, where each subsea consumer is fed by a separate power umbilical from the host facility, while the other concept has one supply cable and local subsea power distribution, in ABB terminology called SEPDIS (Subsea Electrical Power Distribution System).

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

INTRODUCTION "If you can look into the seeds of time, and say which gram will grow and which will not" William Shakespeare, Macbeth In the engineer's mind, time is a straightforward linear process Short term means tomorrow, next month, or perhaps next year Long term tends to mean five or ten years from now The economist however is not burdened with this convention The difference between the economist's long term and short term is the number of factors which have changed. In the short term, one or two factors may change - in the long term, all factors change We, in the subsea control business, are generally short term thinkers in the economist's framework We concentrate on the next project, the new alliance, the prospect of all eclectic production controls, or whatever else looms on the horizon. The fact we work the next problem in line is natural and not inherently bad Nevertheless, it is important to realize that just because this problem is five years away does not make us long term thinkers if we adopt the economist's definition. ‘Short termism’ reeks of criticism and it is tempting to believe that the measure of our success is that of all the factors which limit subsea development, control and data acquisition rarely impedes progress This is historically untrue For many years the most serious opposition to subsea development was posed by reservoir engineers who believed that the inaccessibility of subsea wells, in terms of logging, posed an insurmountable obstacle to effective reservoir management This was a persuasive argument to management and, while arguably untrue, there is little doubt that the development of successful downhole pressure and temperature gauges has been of material benefit to the proponents of subsea developments. The importance of subsea control and data acquisition is not fully appreciated by some Too many people refer to the familiar pie chart of costs and note the relatively small segment allocated to subsea production equipment, the even smaller segment allocated to control and data acquisition, and dismiss development requirements in this area as far less important than cost reduction in drilling and pipelines This is short-sighted indeed since it is improved control which will facilitate advances in these higher cost areas The ‘smart’ well may be a daunting prospect The drilling and completion technology required may need refinement but the fundamental equipment is available In the absence of reliable recovery of additional downhole information, flowrates, fluid properties etc, the potential of this technology cannot be fully exploited The cost savings achievable by reducing the number of subsea wells are exciting but the demands placed on control and data acquisition providers is large Pipeline savings may be achieved through subsea processing and this requires additional instrumentation Pipeline costs can be reduced by developments such as HIPPS which in its ultimate form will require dynamic flow control which is beyond current experience

INTRODUCTION Kvaerner Oilfield Products' (KOP) experience in deepwater development is present in projects wherever the word "deep" is mentioned around the globe Some of these projects were the first of their kind and due to their nature had always required our design approach to be flexible, innovative and able to adapt to various subsea environmental conditions KOP deepwater systems typically consist of Xmas trees, manifolds and/or templates, control systems, umbilicals, intervention and be-in/connection systems This presentation aims to describe these products and systems delivered or currently under manufacture at KOP for use in deepwater developments, highlighting their technical solutions and concepts Deepwater intervention bands Firstly, it is important to establish an intervention terminology in relation to the development design water depths The proposed bands are subject to many variables, however, it serves as a preliminary guide to our approach to deepwater intervention At KOP, these are defined as follows(The Chart is available in full paper) Current and past experience KOP has designed a number of systems for deepwater Below is a bnef list of installed and current projects for reference(The Table is available in full paper) DEEPWATER PROJECTS LAMINARIA SUBSEA PRODUCTION SYSTEM The Laminaria and Corallina fields are located of the permit areas AC/P8 in Northern Territory waters in the Timor Sea, 550km WNW of Darwin. The fields will be developed using subsea completions and a monohull type Floating Production Storage and Offloading vessel (FPSO) permanently moored in approximately 385m of water and designed to remain on station without disconnection of its mooring for its 20 year life The field location and the proposed field layout and well locations are shown in the attached presentation overheads. The base case development for the Laminaria Field is for 6 subsea production wells with expansion up to fourteen wells in total The base case for Corallina, which lies approximately 9 km west of Laminaria, is for two subsea production wells, with provision for a total of four wells A single subsea gas injection well will be used for the disposal of excess gas and LPG, provisionally located approximately 6 5 km south-west of the FPSO System Overview The subsea system proposed for the Laminaria and Corallina fields is based upon the concept of convenhonal5 x 2 through bore Xmas Trees and cluster well manifolds Chokes and subsea control pods are to be housed in independent, diverless retrievable modules fitted in the manifolds, thus allowing the use of a simple tree design Each manifold choke and subsea control module will service two wells, minimising the size and weight of the manifold and facilitating installation by a range of vessels including DSV's Due to the modular nature of the manifold design, it can be readily configured for 2,4, 6, 8 or up to 10 well cluster developments Future wells and/or manifolds can be ‘daisy chained’ from an existing manifold as required, allowing the initial development to be readily expanded