Summary. The flexible riser and mooring system (FRAMS) provides a technically straightforward, commercially attractive method of developing small on fields. A passively moored 60,000-deadweight-ton (60,000-DWT) tanker with deck-mounted equipment provides a swivelless well fluid and injection water path from and to the wellheads. The system can be disconnected rapidly in severe weather. Introduction In a typical FRAMS field development, a small North Sea oil field would be developed by a moored 60,000-DWT tanker restrained against environmental forces by a 5-in. diameter spiral-strand wire to an anchor base by means of a midwater buoy. Three 5-in. OD flexible pipes would be held off the wire with spiders: one that conveys well fluid, one that transports injection water, and one that is an electrohydraulic umbilical cable. The tanker would be free to rotate about the mooring, using the inherent flexibility of the lower riser hoses, up to a design limit of 300 deg. rotation. The mooring would act as an inverted pendulum being displaced when environmental forces cause the tanker to move or to weathervane. The mooring would provide a restoring force to the tanker. (See Fig.1 for an overview of the FRAMS concept.) Experience shows that a field suitable for development by FRAMS would be one in the central North Sea with an oil reservoir of 10 to 20 million bbl, recoverable over 5 years with up to five wells. The GOR should not exceed 500, and the water depth should be at least 260 ft. This paper outlines the sequence of activities through conceptual design, analytical work, model testing, and voyage simulation. This work supports the hypothesis that a buoy/tanker system can be engineered to provide an attractive method of developing small oil fields. provide an attractive method of developing small oil fields. Design Philosophy The overall design aim was to reduce capital and operating costs by simplifying the design requirements and using straightforward engineering. Consequently, fluid swivels and dynamic and active positioning are avoided. Because no provision is made for the ship to remain connected to the mooring in all weather, the need to size components for the most severe conditions is avoided. A 5-year-old tanker would be converted and equipped with above-deck, palletized units and would use its attendant anchor handler as an occasional tug. The tanker would return to port to discharge its cargo, providing opportunities for inspection and dry-docking if needed. Preliminary Design Preliminary Design Analytical work was carried out with the AQWA suite of programs to determine the sizes of the mooring components for a typical base-case field. A detailed diffraction wave-loading analysis was performed with a 60,000-DWT tanker hull for 4 wave directions and 10 wave periods. Loading coefficients for wind, current, yaw, and mooring drag were calculated. This analysis provided top- and bottom-line loadings. A personal computer model was set up to simulate a mooring system's restoring forces for different buoy displacements, bottom-and top-line lengths, and tanker offsets. As in almost all design work, a had to be reached to satisfy conflicting ideal values. The final configuration of a 200-tonne buoy and top- and bottom-and lengths of 490 and 330 ft, respectively, was selected. The choice of a relatively long top-line length is supported by North Sea experience on tanker off-take loading operations. The longer length reduces the possibility of snatch loads and increases the fatigue life of the mooring. possibility of snatch loads and increases the fatigue life of the mooring. The loadings in the mooring led to the use of a 5-in.-diameter spiral-strand wire rope, giving a safety factor of at least four for the bottom line and eight for the top line. The analysis confirmed that the tanker stayed mainly in a 90 quadrant. On the basis of the manufacturer's limit of 0.33/ft acceptable torsion, the mooring system was felt to be capable of operating with enough uptime for adequate production performance. Topsides Design The process and utility facilities installed on the FRAMS tanker were designed specifically for a typical central North Sea field. Table 1 gives the characteristics of this reservoir. The topsides equipment was selected and sized in accordance with conventional principles. For oil production, a single train of three-stage separation was specified and sized for a nominal production of 10,000 B/D of total fluids with provision for produced-water facilities. No test separator was provided, so well testing would be done by shutting in the other wells. The water-injection equipment was sized for 120 % of the specified rate to allow for downtime and an increase in the injection rate. Additional power generation would be installed to take advantage of produced-gas availability. Two dual-fuel (diesel/gas) engines were proposed; two gas turbines may be used as an alternative. The flare tower, proposed; two gas turbines may be used as an alternative. The flare tower, which is 80 ft in front of the facilities, is rated to bum all produced gas (3 MMscf/D). The skid-mounted process and utility facilities are located near midships on the tanker. Hazardous equipment is separated from nonhazardous equipment. A weatherproof, mechanically ventilated control cabin would house subsea controls; process controls; and fire, gas, and emergency shutdown systems. The cabin, located in a safe area, is staffed continuously. Subsea and Downhole The major subsea elements of the base development include two producer wells and one water-injection well in a tight cluster (around a manifold structure), two parallel flowlines about 0.5 mile to the mooring base, a valve control system, and chemical-injection equipment fed by the umbilical line from the FRAMS tanker. Standard wellheads are used for both production and injection wells. production and injection wells. Well stream from the production wells is combined into a single flowline. Because the operating procedure calls for produced oil to be flushed from the flowline and header while the tanker is off-station, crossover pipework is provided in the manifold. A multiplexed electrohydraulic control system was selected for FRAMS. In normal operation, the system is largely conventional. While the tanker is off-station, the hydraulic pressure is locked in and electric power maintained by rechargeable subsea batteries on the manifold. Use of an acoustic control system was considered. This system offers the advantage of maintaining full control and status monitoring of the subsea equipment while the tanker is disconnected-for example, during a mooting unwind operation. It also offers improved operational life of the downhole safety valves. Downhole equipment was designed on the basis of a recent BP Exploration subsea field development tied back to a nearby host platform. Trees can be changed without heavy workover. For cost purposes, 13 % chrome production tubing has been allowed for because one of the candidate fields may require this. Copyright 1991 Society of Petroleum Engineers P. 465

Introduction The Johnston Gas Field lies in blocks 43/26a and 43/27 of the UK sector of the Southern North Sea, 11 km to the Northeast of the Raven spurn North production platform (Figure 1). The water depth at this location is approximately 145 feet. The field was discovered in April 1990 by the 43/27-1 well and successfully appraised in July 1991, by the 43/26a-8 well. The field (Figure 2) is formed by a structural trap bounded to the Southwest by a NW-SE trending fault and by structural dip to the north and east. The reservoir itself comprises Permian Lower Leman sandstone exhibiting excellent porosity and permeability characteristics. Recoverable reserves are estimated to be in the range of 155 to 195 BCF. The gas sales contract requires a DCQ of 53 MMSCF/D for a six year plateau, with a peak rate of 90 MMSCF/D. Two wells located near the crest of the structure satisfy the production contract requirements, however a third well may be required in the third year of production. The overall field life is expected to be 13 years. This paper describes the selection, design and installation, in this field, of the first horizontal subsea trees to be installed from a jack-up. Development Plan Two primary development options were considered for developing the Johnston Field; a "not-normally manned" satellite platform or a subsea installation, both of which would be tied back to the Ravenspurn North processing facilities. Evaluation of both these options concluded that the subsea installation was preferred, due to shorter lead time for fabrication and lower initial capital expenditure. The Johnston subsea structure contains a three slot drilling template, a protection frame incorporating a spare fourth slot, production and methanol injection manifolds, and the subsea control equipment. The template and protection frame were designed to be installed either sequentially or in one piece, the choice of which was to be determined by delivery constraints. The Johnston field development was 'fast-track', first gas was produced ahead of schedule and under budget, some 14 months after project sanction. The procurement of the trees was also 'fast-track', the wellhead equipment was tendered, design finalised, manufactured, tested and installed within 12 months. Prior to placing the order for the trees, the operator in conjunction with the tree manufacturer, carried out a detailed technical review and HAZOP of the horizontal tree concept. Both parties were fully satisfied that the spooltree design was the preferred option for the Johnston development. These advantages of horizontal trees are discussed throughout this paper, however, the primary advantages were considered to be:–Reduced capital and installation costs–Reduced delivery times–Reduced size allowing easier handling Horizontal 'Spooltree' The Johnston mudline spooltree is shown in Figures 3 and 4. The 5000 psi spooltree comprises the main spool body with an integral hydraulic 5-1/8" production master valve (HMV), and an integral manual 2" annulus master valve (MAV). The 5-1/8" hydraulic production wing valve (PWV), the 2" hydraulic service wing valve (SWV), the 2" hydraulic annulus cross-over valve and the 2" hydraulic annulus drilling valve are in separate valve blocks bolted to the main spool body. The tubing hanger is landed within the spool body and is ported horizontally to allow flow into the production valves. The production master and the production wing valves provide the main well control barriers in the production flow path. The well barriers in the vertical bore are provided by two independent, positively sealing plugs. P. 11

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The Flexible Riser and Mooring System (FRAMS) provides a technically feasible and commercially attractive method of unlocking small U. K. North Sea oil fields. A moored 60,000 OWT oil tanker, fitted with deck mounted production equipment is restrained by a mid-water bu::>y, while the swivel-less riser bundle conveys well fluid from, and injection water to, the subsea wellheads. In severe weather, oil production is stopped, and the tanker disconnects from the mooring, re-connecting when weather allows.

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