ABSTRACT Snap Lay? is a method of laying rigid steel pipelines using mechanical connectors to join spoolpieces together. This paper outlines its applications including the laying of pipe from a barge or constructions vessel, laying from an drilling rig and laying pipe by snapping spools together on the seabed. Finally the paper will review the most recent installation of two kilometers of twenty four inch diameter pipe on the Harding field for BP. INTRODUCTION Snap Lay? is a pipelay system which can fundamentally changes the way in which oil field are developed because it offers new opportunities in the configuration and installation of pipelines. An alliance to promote Snap Lay? was formed by SubSea Offshore, Hunting Oilfield Services and Uglands Offshore which offers a complete installation capability SnapLay projects will normally be led by SubSea Offshore. The Merlin? Connector The heart of the Snap Lay?system is the Merlin? Connector. The connector has been in use for over twelve years primarily in conductor and casing applications but it was also used as the connection medium for the tendons for the Shell Auger and Mars TLP's in the Gulf of Mexico (Figure 1) the Merlin? is a box and pin type of connector with a series of parallel teeth on the outside of the pin and a corresponding set on the inside of the box (figure 2) (It should be noted that these are not threads and no rotation is required for make-up). Each component has a nib and recess which form the sealing elements. The connector is currently produced in sizes ranging from 16 to 48′ but larger and smaller diameters are possible. There are over two thousand Merlins?in use and there is an exhaustive history of testing to draw on (figure 3 shows a pipe test piece with an early Merlin type connector being tested and demonstrating that the connector is stronger than the pipe). Connector Operation The connectors are welded onto the pipe spools as shown in Figure 4. The method of make-up is shown in Figure 5. The pin is inserted into the box until the nibs on both components engage on the corresponding profiles prior to the entry into the sealing recess. The teeth are configured such that they will not engage until the final make up position a makeup clamp is fitted around the two connector components and a hydraulic injection line is installed. Hydraulic fluid is injected into the void bounded by the two nib/profile seals. The effect of this injection is to compress the pin and expand and with an axial force of up to 400 tons the two components are forced together until the nibs engage in the recess. The hydraulic pressure is then released and the teeth engage. This makeup sequence is fully reversible. Once made up clamp and hydraulic line are removed and plugs fitted. The connector offers four metal to metal seals between the bore of the pipe and the surrounding environment with each nib forming a metal to metal seal on its inner and outer faces.

ABSTRACT This paper briefly discusses Digital Terrain Modeling (DTM) techniques. Then, by presenting applications of DTM to Route Optimisation and Presweeping, it is suggested that over-engineering, normally introduced as safety factors to allow for limitations in the mapping of seabed topography, could be reduced with consequent savings In capital costs Similarly, it is shown that DTM-enhanced engineering techniques can be applied to trend monitoring of Pipeline Survey data, and that this approach can reduce rectification and its associated operating costs Indeed, if DTM-enhanced engineering IS applied through the life of a pipeline, this can have additional benefits at the end of life The paper closes with a discussion of future developments. INTRODUCTION All operators and offshore contractors are continually striving for two things reduction in costs, and improvement in safety In many ways it might appear that these two aims are mutually exclusive However, by applying DTM techniques to enhance subsea engineering, it is possible to reduce overall costs while maintaining and even improving the level of safety These aims are achieved through a better comprehension of the operating environment Unlike the civil engineer on land, the subsea engineer cannot step back and observe the lay of the land, or the details of the location of a subsea structure The range and field of view of a subsea video camera is very limited so that it is not possible to reference one feature to another, or to appreciate gradients of the sea floor. The real time output of echo sounders and sonars does not generally give an adequately comprehensive picture This is not a limitation if the seabed is flat but, in an area of rugged terrain, the subsea engineer must rely on visualization techniques The resulting unknowns have been compensated for by the application of safety margins or factors In this way safety has been maintained, but almost certainly at the expense of over engineering. However, this deficiency can be mitigated by the ability to visualise the subsea environment by graphical models The value of this approach depends upon two main criteria the quantity and quality of the input data, and the agility and speed with which these can be assembled into a usable graphical form, and then manipulated. The use of a Digital Terrain Model to visualize the seabed means that submarine pipelines can be designed much more accurately and subsequently monitored throughout then lives Indeed, it is possible to consider five stages In the life of a submarine pipeline design, installation, operating life, life extension, and abandonment This paper demonstrates how DTM techniques can be utilised to enhance engineering during all these stages DIGITAL TERRAIN MODELLING The Admiralty Chart can be seen as a form of seabed terrain model It shows depths and contours and the positions of seabed hazards It also presents information on the seabed material It IS actually quite limited, however, so far as seabed modeling IS concerned because, until very recently, depths were obtained from single readings taken at intervals along survey lines whose positional accuracy was limited

ABSTRACT Since the TROLL FIELD was declared commercial, many different development concepts have been considered based on a fully integrated offshore drilling, production and accommodation platform. Norske Shell has, as development operator and with Partners consent, decided to change this concept to include three main elements. The new concept consists of a less complex offshore platform, pipelines for transport of wet gas to shore, and an onshore processing and compression plant. In the processing plant the gas will first be treated and then compressed for export by pipeline to the European Continent. Land based processing was chosen to improve safety, increase the ability to meet a growing demand for TROLL gas and improve the economic potential of the project. Figure 1. INTRODUCTION A/S Norske Shell discovered hydrocarbons in Block 31/2 west of Beryen in 1979. Figure 2. In the early eighties several appraisal wells were drilled, indicating substantial volumes of gas with some underlying oil, particularly in the West. Neighbouring blocks were also explored and together blocks 31/2,/3,/5 and /6 became known as the Troll Field and was unitised in 1986 and is the largest offshore field in Europe. That same year Norske Shell was appointed Operator for Phase I gas development in Troll East gas province. Figure 3. The ‘troll’ is a creature which often appears in Norwegian folk-lore. The modern troll, however, is located on the Norwegian continental shelf in the North Sea. When gas begins to flow from the Troll field in 1996 it will provide for more than ten percent of Europe's total energy needs far into the 21st century. In fact Troll gas will be exported through several transport systems to a number of countries on the European Continent. The Troll field can be divided into three areas-Troll East gas, Troll West gas and Troll West oil. Oil and gas production from Troll has already started. In 1986 it was decided to export gas from Troll East to the Oseberg field from a subsea production module to enhance oil production from that field. The TOGI (Troll Oseberg Gas Injection) project came on stream in January 1991 and will deliver a total of 25 billion cubic metres of Troll gas for the next 10–12 years. Norsk Hydro is operator for TOGI. In 1989 the Troll Unit Partners decided to test oil production in Troll West. Two horizontal wells have been drilled - the first well was 500 metres and the second was 800 metres long. Both tests indicate that some of the large oil accumulations in the West can be exploited. The oil produced during these tests has generated income to the Partnership and partly covered the cost for testing. Norsk Hydro is also Operator for the oil test project TROLL UNIT PARTNERS The production license for block 31/2 was originally awarded to a group of companies comprising Statoil(SO%), Norske She11(35%), Norske Conoco(5%) and Mobil Exploration Norway(5%). The three adjacent blocks 31/3,/5 and /6 were awarded to Statoi1(85%), Norsk Hydro(9%) and Saga Petroleum(5%).

Introduction The main purpose of the presentation will be to illustrate by example how the effectiveness of the Pipeline Inspection exercise is influenced by the selection of the correct method and a clear understanding of the objectives of the inspection activity. The Operators' objective of satisfying the Inspection requirement as cost effectively as possible is very clear The presentation will not seek to explain methods in detail or to offer a critique of the different methods of pipeline inspection Background There are now over 4,000 km of subsea pipeline in the UK sector of the North Sea BP currently operates around 25% of the total length of subsea pipeline in this sector Many of these pipelines handle production from a number of Platforms (eg Forties MOL takes production from 11 different platforms) The consequence of £allure of these pipelines is potentially enormous in commercial terms, environmental terms and safety terms. We are now also approaching an era where some of the pipelines are approaching their design life The pipeline infrastructure is an enormous asset which needs to be preserved. Inspection Requirement Whatever inspection activities are to be undertaken whether onshore, offshore or subsea it is Important to retain a clear sight of the objectives and the mechanisms of failure which are being investigated. Most if not all inspection techniques have limitations of the technique which need to be understood Subsea inspection activities are no different from topsides inspection. In these respects The fundamental differences are in the relative costs of the activities and the difficulty/cost of a repeat inspection In the subsea activity The statutory inspection requirements for pipeline inspection are stated In SI1513. Different operators place different interpretations on how these requirements may be met by differing application of the available methods. This difference in application not only reflects the differing inspection requirements for each pipeline but the apparent subtle differences In inspection philosophy between the operators. It is arguable whether the satisfaction of these SI1513 requirements alone will guarantee the operator's primary objective of preservation of the integrity of his pipeline and the maintenance of production Inspection Methods The inspection methods available vary widely to the extent that they do not bear direct comparison They fall in to the two categories of techniques applied from the outside and techniques applied from the inside of the pipeline In general terms their effectiveness is limited to viewingthose mechanisms acting from the inside and outside respectively This last statement is contentious but certainly £allure mechanisms are more easily investigated from the side of the pipeline at which they act. Internal failure mechanisms The internal deterioration of pipelines is generally an age related phenomenon and the requirement to investigate internal corrosion is increasing with the age of pipelines and the producing fields Changes In produced fluids may Impact on pipeline internal corrosion rates