Presently, drilling riser joints are inspected every five years. This is usually accomplished by rotating 20% onshore every year to be dis-assembled and inspected. This requires extensive boat trips from a mobile operating drilling unit (MODU) to onshore and trucking of the riser to the inspection facility. Typically, 20 riser joints from each riser system are transported on a boat and one riser per truck to an inspection facility each year, making the logistics of performing a drilling inspection complex and costly. A laser-based measurement for inspection together with monitoring of riser systems has been implemented with a new standard process for collecting critical riser data that is ABS approved. The aim is to mitigate the costs and time associated with essential MODU drilling riser inspections, by empowering operators to reliably determine the condition of drilling riser joints, consistently predict when vital components will require service and accurately assess remaining component life. The approach utilizes a life cycle condition based monitoring, maintenance and inspection system that can be deployed on a MODU, enabling resources to be deployed only when necessary, instead of on a calendar interval. The solution consists of: Performing a baseline inspection on the riser joints to assess their present state, Collecting the environmental and operating data when the rig is on site drilling, Feeding the environmental and operating data into a digital twin. The tuned digital twin can be used to predict future damage. The approach removes uncertainties surrounding damage of riser joints and will allow the owner to determine whether riser should be redeployed or replaced. This is the only process that is ABS approved for condition based monitoring of drilling riser systems. The system is compatible with all present owners’ maintenance programs and ensures that maintenance requirements are supported with robust engineering.

In the current low oil price market, innovative low cost solutions are necessary for development of new fields and life extension of existing fields. For deep water applications, Steel Catenary Risers (SCRs) and Steel Lazy Wave Risers (SLWRs) provide low cost alternatives to flexible risers and offer flexibility during design and life extension for Floating Production Systems (FPS) in deepwater. The majority of deepwater fields in offshore West Africa and the North Sea have traditionally been developed using flexible risers. SLWRs, a variation of the steel catenary riser (SCR) with added buoyancy near the touchdown point at the seabed, have recently been deployed in the GoM and Brazil for deepwater applications. Due to simplicity of design, good track record and qualified suppliers, fabrication and installation methods for SCRs, SLWRs have become a logical extension of the SCR. Buoyancy installed on the SLWR helps reduce top tension and decouple vessel motions from the riser touchdown zone, which ensures that the required strength and fatigue performance can be achieved. SLWR and SCR configurations are developed for mild environment, deepwater applications representive of offshore West Africa and in severe environment moderate water depths, representive of the North Sea. Riser configurations, hang-off loads, strength and fatigue responses are compared for the configurations. The advantages and disadvantages of SCR and SLWRs are discussed and compared to other riser types. Costs for flexibles, SCR’s and SLWR’s are also compared.

Objective/Scope In Q4 2012, the 8” Teal dynamic riser required replacement. A project team was assembled to remove the existing riser and install a replacement. The riser was originally installed in the 1990's by divers based on the Anasuria Floating Production Storage Offloading (FPSO). The FPSO facilities that were used to provide diver access into the chain table area to secure the bend restrictor were no longer operational. Previous diver intervention at the chain table had experienced high levels of non-productive time, so a remote removal method to cut and lower the riser and bend restrictor to the seabed was pursued. Methods, Procedures, Process The project team initiated a concept study to set the challenge to release the riser from the FPSO remotely to a) reduce HSE risk; b) de-risk project by separating release campaign from recovery campaign and c) perform the work offshore using a very small team (FPSO bedding constraints was one of the reasons the team didn't use an air dive team to do it from the FPSO). The concept selected was largely based on a method used for removal of other similar risers in 1999 albeit that all that remained from that campaign was a PowerPoint presentation. The majority of engineering calculations and drawings could not be located. Results, Observations, Conclusions The tooling was designed, fabricated and tested in less than 6 months from award of contract to offshore operations. During the offshore campaign, various issues were encountered (e.g. incorrect ‘as built‘ documentation) but the remote removal campaign was a success with both the riser and its bend restrictor being removed from the FPSO without requiring any diver intervention, thus reducing the project costs and HSE exposure. Novel/Additive Information Lessons learned from the offshore campaign are being captured with the concept being further refined to allow the removal of the riser and bend restrictor without first having to cut and remove the topside riser end fitting. This should reduce the offshore operational time for any future riser removals and remove the risks associated with unknown internal condition of the riser.

Typical workover operations involve the switching of subsea well barriers from permanent equipment to temporarily installed barrier systems. During workover activities additional operational hazards are introduced such as drive/drift off and compensator lockup which can have severe consequences including injury to personnel. To account for these operational hazards a workover system will have additional barriers. These barriers consist of instrumented and non-instrumented protective layers. The instrumented protective layers consist of safety instrumented systems (SIS). The safety instrumented systems fitted to a workover system can vary. Most workover systems consist of three common safety instrumented functions (SIF); Process Shutdown (PSD), Emergency Shutdown (ESD) and Emergency Quick Disconnect (EQD). The non-instrumented protective layers are made up from mechanical barrier elements for example the weak links. DNV GL on behalf of Statoil performed an analysis to better understand workover hazards and the barriers required to mitigate these. The aim of the work was to assess the effectiveness and suitability of the current safety barriers and to identify what additional functional requirements might be needed. This paper details the results of that work. A generic workover system formed the basis for the study. Hazards were defined through a hazard identification (HAZID) workshop and the effectiveness of the measures was evaluated through a Level of Protection Analysis (LOPA). This paper documents the results of a study to establish whether the current barriers used during workover operations adequately mitigate the risks. Despite having dissimilar operational modes, it is often expected that the workover system barriers shall be suitable for all operational modes. The results of this study show that some of the barriers in workover operations are not as efficient as perceived, in particular the riser weak link designs and manually initiated EQD functions.

The paper addresses the use of steel chains in a lazy wave configured flexible riser system to provide an alternative flexible riser configuration for use in challenging environments including large vessel offsets and motions, and large ranges of riser internal fluid properties. While the compliant nature of flexible pipe provides excellent fatigue and strength resistance, flexible risers typically experience larger deflections when compared with rigid risers, which results in greater challenges managing interference issues with adjacent structures. Different lengths and variable masses of chain are installed at locations along the hog bend of the flexible riser configuration. The arrangement of the chain masses, length and positioning along the line are developed to primarily prevent contact with the seabed and the hull of the FPSO when a range of heavy and light internal fluids are considered. A number of weighted steel chain configurations are evaluated and presented through an analytical case study in order to demonstrate the benefits of this approach for a typical generic shallow water application FPSO system. Installation and hardware design aspects are additional requirements that may need to be addressed in further assessments. Through the in-place case study, comparisons are made between the performance of the flexible riser system with and without the weighted steel chains. Global finite element models are developed to simulate the performance of the different flexible riser configurations when subject to a range of loading scenarios covering large FPSO offsets, harsh environmental conditions and a range of riser internal fluid densities. Performance criteria of the flexible riser such as tensile loading, curvature and motion envelopes are presented to show the improvements derived though optimisation of the chains. It is also demonstrated that the chain section that extends along the seabed helps to reduce the transverse displacement and “lateral walking” thus reducing the risk of clashing with adjacent structures and changes in line lay azimuth under strong transverse current loading. The cost effectiveness of the chain weighted flexible is also compared to other solutions considering new and retro-fit applications. This work demonstrates that an improved and cost effective solution is developed to provide an acceptable flexible riser dynamic response for the range of operational fluid densities that may be experienced in its operational lifetime.

Use of full bore high pressure (HP) risers in ever more challenging locations and conditions has increased requirements to collect in-situ response data to confirm that the riser design is acceptable and confirm integrity. Due to the challenging combination of the 91m water depth and harsh environment at Huntington field in the North Sea, considerable analytical work was required to design and configure the proposed 24inch diameter HP drilling riser and well conductor system to allow successful and safe all year operations from the jackup rig. As well as careful strength and fatigue design of the upper and lower most HP riser joints, this potentially required modifications to the rig’s CTU deck to support the high loads expected. Typical conservatisms in analysis methodologies also needed to be removed to allow for a viable theoretical design. In-field measurements were therefore proposed to allow for verification and calibration of the analysis used as a basis for the design decisions and to ensure that the integrity of the riser was maintained during the 12 months of drilling and completion operations. The monitoring system developed to address this, the first type of its kind to be installed on a jackup rig, incorporated a range of accelerometer and strain sensors to record motion, load and fatigue responses of the riser and jackup system in real-time. This paper describes the background to the monitoring system design, the components that make up the monitoring system and presents the comparisons between the collected data and analytical predictions that allowed the objectives of verifying the analysis and confirming integrity of the riser to be achieved. Recommendations are also given as to how the monitoring system can be improved for future use in similar applications.

The Schiehallion Floating Production Storage and Offloading (FPSO) is moored by a Turret Mooring System (TMS) located in 400m water depth in the Atlantic Frontier and submitted to very challenging environmental conditions. The Schiehallion FPSO went on stream in 1998. As part of the planned field development the QUAD 204 FPSO currently under construction will replace the producing unit in 2015. In both cases, SBM Offshore (SBMO) is the supplier of the Turret Mooring System. This paper compares the main features of Schiehallion and QUAD 204 TMS: mooring lines, connectors, weathervaning system, manifold and swivel stack arrangement. The performance of the key components over 15 years of operation is reported. The changes brought to the original design are highlighted and discussed.

The design and operation of an FPSO in remote locations requires detailed information on the structural response of the vessel within the local environment offshore. Monitoring of critical components including the risers, hull and mooring lines simultaneously with the local environmental forcing of waves, wind and currents at the site location, provides a valuable insight into the performance and possible extension of the integrity life of the asset. Verification of the riser and vessel design is often theoretical and actual measured observation of the response of the critical components of an FPSO in the field is less frequent. As new technology is introduced, riser design becomes more sophisticated and extension of design life is required, it becomes increasingly important to monitor an assets performance. In hostile or remote locations where information on the environmental forcing is less known, monitoring becomes critical to assist with operational decisions, forensic investigation and the evaluation of design codes. This paper will provide a technical overview of an FPSO integrated marine monitoring system located in a hostile environment, typical of West of Shetland. The focus of this paper will be on the marine monitoring system; however an overview of the monitoring of subsea risers and moorings will be included for completeness. A discussion on the importance of monitoring the environment and the structural behaviour on a common time base for integrity management and forensic investigation of marine incidents will be presented.

For new build FPSOs or to safely extend the life of ageing assets, operators require technologies that enable them to safely monitor the subsea infrastructure in real-time, to identify problems before they occur. Annual inspections by Remotely Operated Vehicle (ROV), although useful to provide close up inspection, do not provide real-time information in the event of a mooring line failure or problem with the risers. Through the application of multibeam sonar technology, operators can now have real-time 24/7 information on the presence and position of mooring chains, risers and umbilicals. Unlike other acoustic techniques, multibeam sonar does not require additional sensors mounted to each mooring chain or riser, therefore removing the need for regular maintenance, servicing and power source replacement by ROVs. The multibeam sonar system provides autonomous alarms in the event of mooring line or bend stiffener failure and the accurate sonar data can be used for further fatigue analysis, assisting in the planned maintenance schedule. This unique technology was developed for BP and has been successfully deployed on an FPSO in the North Sea, where it has provided round-the-clock integrity monitoring capability. This technology was selected in 2013 for permanent deployment on a new build FPSO entering service in the North Sea with production planned for 2015.

Abstract PAZFLOR is TOTAL's ongoing largest oil development, and was launched in December 2007. After the success of Girassol, Dalia and Rosa, PAZFLOR represents a major new step in the development of Block 17, offshore Angola as it will raise the installed production capacity of the Block to over 700,000 barrels per day. PAZFLOR main technical challenge consists in producing two very different types of oils from four reservoirs, on a single FPSO. The heavy and viscous oil from the three Miocene reservoirs with low energy potential will be produced using the innovative technology of gas/liquid subsea separation. The three subsea gas/liquid separation and pumping units on the sea bed will constitute a World Technology First for a development of this scale. After separation, the liquids will be pumped to the surface using hybrid pumps, specially designed and qualified for PAZFLOR. Such development scheme also allows a different strategy with respect to hydrates preservation based on depressurisation rather than live oil replacement. The selection of a subsea gas/liquid separation concept raised new challenges, due to the relatively poor quality of the oil: the efficiency of the gas/liquid separation with viscous fluids, and the design of the subsea pumps which must be gas tolerant. Dedicated test programs were conducted in cooperation with oil industry partners and concluded in the qualification of a full scale hybrid pump as well as on separator internals.

Abstract A new generation of lightweight, flexible, non-metallic, unbonded pipes has been developed for use in subsea and deepwater floating system applications. These pipes are the first of their kind offering large savings in weight and cost to operators. In addition, the elimination of metallic reinforcements removes the associated corrosion concerns in sea water and the U-value of the pipe is improved. The Flexible Fiber Reinforced Pipe (FFRP) is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. The unique design allows the construction of lightweight flexible pipes with attractive features such as capability for high internal and external pressures, in a wide range of sizes varying from 2 inch to 16 inch. It is intended to be used in deepwater. An overview of FFRP technology is presented in this paper. Typical designs of the pipe are described. A brief overview of qualification tests is provided along with a description of initial applications. This technology has the potential to be a 'game changer', enabling new, lower cost field development solutions in offshore areas around the world. Introduction Unbonded flexible pipe technology has enabled floating production systems of various types to produce oil and gas from offshore fields in shallow and deepwater. Flexible pipes are used as dynamic risers connecting seabed flowlines to floating production facilities, and as static sea bed flowlines where it is more cost effective to install than rigid steel pipe, or when it is desired to recover the flowline for reuse after a short field life. Flexible pipes are also used as static and dynamic jumpers at the sea floor, on a hybrid riser, or on the floating platform deck. Until now, flexible pipes have been available with helical metallic reinforcements made of steel. Use of reinforcement steel results in higher weight and several other disadvantages including corrosion, corrosion fatigue, and sensitivity to H2S and C02. In this paper, we present a new option for unbonded flexible pipes without the use of any metallic reinforcement. The Flexible Fiber Reinforced Pipe (FFRP) presented in this paper is constructed from extruded polymeric layers reinforced with unbonded laminated glass-fiber tape stacks. This new generation of lightwight, nonmetallic, unbonded flexible pipes have the potential to enable new field development scenarios in deep and ultra-deepwater fields around the world. Description of Pipe Structure FFRP is custom designed and built to meet project specific design requirements. There are two main types of patented pipe structures which are currently being offered for use in field development projects: 'Standard FFRP' and 'Freeventing FFRP'. Several variations and design options exist within each general type of pipe structure. We begin with a description of the first type.

Abstract The Foinaven field was the first deepwater development West of the Shetlands in the Atlantic Ocean. BP and its partners took a major financial and technical risk in developing the field but wanted to ensure that any environmental and safety concerns were fully addressed. The field has been on production since November 1997 and has produced over one third of the 250mmbbls reserves, achieving a production record of 130,000 bopd in August 2000. The operational track record to date has been world class and has been achieved through a combination of integrated field management and innovative problem solving. During 2001 and 2002 over 200 million will be invested in developing new reserves and work is in progress to mature additional projects. The emphasis of this paper will be on operational experience and lessons learnt and also to highlight future opportunities and the technologies needed to deliver them. Introduction The Atlantic Ocean West of the Shetland Islands has yielded a number of oil & gas discoveries since licences were first awarded in the area in 1970. However, meteorological conditions, deep water and strong currents coupled with the area's remoteness and lack of infrastructure, have been major factors in determining the commerciality of discoveries made to date. In BP, the West of Shetlands (WOS) business unit has been responsible for developing and operating the only two producing fields currently in the area, namely Schiehallion (plus Loyal) and Foinaven, with current production at over 220,000 bopd. Both these fields have completed their initial development phases and are looking at future infield and satellite tieback opportunities. In addition Clair is currently moving towards sanction in late 2001 and a gas pipeline taking Foinaven and Schiehallion gas for re-injection in Magnus has been approved with first gas planned for 1Q 2002. Foinaven Background The Foinaven field is located in two blocks, 204/19 and 204/24a, which are operated by BP with Marathon as co-venturer. These blocks are located some 190kms West of the Shetlands in water depths of 400–600m. Recoverable reserves from Phase 1 development of the field are 250mmbbls of oil. The development centres on subsea wells producing oil via a manifold, through rigid flowlines and then flexible risers into the Petrojarl Foinaven FPSO. Oil production started in November 1997, with two shuttle tankers taking the oil mainly to the Flotta terminal in Orkney, and at the end of 2000 over one third of the oil reserves had been produced. PGS Production operate the vessel and the tankers on behalf of BP based on a tariff arrangement. The Department of Energy has recently granted approval for additional infield drilling and the tie-back of East Foinaven. The East Foinaven satellite is located in blocks 204/24a and 204/25b, which is operated by BP with Marathon and Petrobras as co-venturers. First oil from Phase 2 of the Foinaven development will be in 2Q 2001 with an additional 87mmbbls of reserves and 233bcf of gas.

This paper was prepared for presentation at the 1999 Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

Abstract A downhole Splitter wellhead system was successfully introduced and field tested offshore in the Valhall Field, an upper Cretaceous chalk oil reservoir in the south end of the Norwegian sector of the North Sea (Figure 1) operated by Amoco Norway Oil Company on behalf of Amerada Hess Norge A/S, Elf Petroleum Norge A/S, and Enterprise Oil Norge Ltd. This is the first Splitter well in the North Sea area, and 3rd in the world. Extensive pre-planning and equipment function testing has been performed to meet the challenges posed by the application of this technology. The Splitter system is used in an innovative approach to drill, case and complete two independent wells in one wellhead housing. Each well can be operated, serviced and worked over as a complete separate unit. The 3 objectives with this project were: Test of new technology for possible better use of slots in a slot restrained environment. Explore near Valhall exploration area (Mjød Field) Provide a long term waste disposal solution for Valhall Due to hole stability problems, the second objective was canceled during the operation. Instead, a preplanned fallback production location on the Valhall field was drilled. Objectives 1 and 3 were successfully completed July 1997. One well is a 4700 m MD horizontal producer (850 m horizontal section) to the North of the Valhall Field. The second well is a high angle (68 deg) well with a long section of slim hole drilling prior to completion of a dedicated waste injection well, capable of taking roughly 4 MM bbls of waste at approximately 2200 m TVD in the overburden at the Valhall Field. Figure 2 shows a map of planned vs actual well locations. Introduction In January 1993 the Norwegian State Pollution Control Agency (SFT) reduced the allowable oil content on cuttings disposed to sea from 6% to 1%, a limit not achievable at the Valhall field with current technology, where there in addition to drilling waste also is generated large volumes of production waste (oily chalk and water). With cooperation from SFT, Amoco Norway and Amoco Production Research developed a unique through-tubing cuttings injection method in a dedicated injection well, capable of handling very large volumes of waste. This solution was successfully implemented at Valhall in January 1991. However, in the slot restrained environment at the Valhall platform, with a low-permeability reservoir, the cost for a non producing slot is high, and the Downhole Splitter wellhead system was identified as a potential way of optimizing slot use. The old waste injection well would be plugged and abandoned, the slot would be reclaimed, and a splitted slot installed. Another argument for implementing a new waste injection solution was the fact that the existing waste injection leg had several deformations in the wellbore above the reservoir, and there was some uncertainty with respect to future lifetime for this well. Mjød, an identified exploration opportunity some 4 kilometers south-east of the Valhall platform (Figure 2), had already been discarded due to too high dry hole cost. However, if the Splitter concept was used, a potential dry hole could be utilized for waste injection purposes. So although drilling the exploration well from an offset platform increased the drilling difficulties somewhat, it reduced the potential dry hole cost by as much as 90%.

Abstract This paper describes the two phase development of the Hudson field and the production performance in Phase I that was used to modify the development plan. The paper follows field development into the first months of Phase II and covers plans for future reservoir management. Like many current and future Northern North Sea developments, the Hudson field is relatively small and within reach of existing infrastructure (figure 1). Limited appraisal data and the desire to limit up front capital expenditure (CAPEX) led to an innovative phased development concept with early cash flow from leased production facilities funding the later full field exploitation. Reservoir data gathered in Phase I would be used to optimise the Phase II expansion. The highly successful Phase I development was from 2 wells producing to the Petrojarl I floating production storage and offlake vessel. There was no water injection. Results yielded information about aquifer connectivity, geological layering and well deliverability that have influenced several aspects of the development plan in addition to producing 17.5 mmstb of oil to fund the remainder of the project. Field Description The Hudson field, situated at the western edge of the East Shetland Basin, is an easterly dipping, tilted half graben bounded to the West by a major normal fault which dips West (figure 2). It was discovered in 1987 and operatorship passed to Amerada Hess Limited (AHL) in 1989. A Field Development Plan (Annex B) was submitted in October 1992 and approved in December 1992. The reservoir sandstones in the Hudson field are assigned to the Brent Group which comprises five formations, Tarbert and Ness which form the Upper Brent Unit, and the Etive, Rannoch and Broom which form the Lower Brent Unit. As with many Brent sandstone oilfields, significant heterogeneities are present within the formations. In addition, variation in sand quality at the layer boundaries may effect vertical transmissibility. At the time of the Field Development Plan, oil water contacts (different for Upper and Lower Brent) were inferred from RFT pressure measurements and were therefore not certain as pressures in the field were disturbed by other field developments in the basin. This coupled with ranges and uncertainties assigned to seismic depth conversion, oil saturation, net to gross ratio and possible erosion led to a range of Stock Tank Oil In Place (STOIP) of between 109 and 341 mmbbls. The most likely estimate was 209 mmbbls. Development Decision Although it was believed that satisfactory recovery could be achieved from the Lower Brent, the uncertainty about the extent of aquifer support and the effect of layering made optimising the development plan very difficult. In addition, much oil was mapped in the Upper Brent 'Shore Face Sandstone' but with only 15–25 ft of net pay, recovery factors were uncertain. Initial scoping studies focused on three options. Conversion of an existing semi to a floating production vessel, upgrading an existing monohull floating production, storage and offloading vessel (FPSO) and a subsea tieback. Conversion of a semi would be costly and time consuming. In addition, the lack of storage would be a disadvantage. Northern North Sea tanker loading operations would be frequently disrupted by weather. Use of the Petrojarl I monohull FPSO for full field development was investigated. However, significant upgrading would be required, not least in the turret area where up to 8 wells would have to be accommodated. A subsea tieback to the Tern platform (6 miles) was found to be feasible but limited capacity and long lead time (2 – 3 years) for major upgrade work prompted Amerada Hess Limited to look for an alternative solution. With the wide range of reserves and the uncertainties about vertical sweep and aquifer support, a phased development was favoured to gain reservoir information to allow optimising of the full field development plan. P. 669

Abstract Subsea wireline well intervention has been performed from the Multi functional Support Vessel (MSV) Seawell since I 988. In a joint Coflexip Stena Offshore (CSO) and Camco venture, an impressive track record in wireline work and abandonment has been created. Despite this, there is a growing need for developing the range of services to provide deep water well intervention and coiled tubing activities. This paper presents Coflexip Stena Offshore's current capability and experience and future strategy. This includes extending the range of the existing system for operations in water depths down to 3,300 ft (1,000 m) and modifying it to allow for riser and coiled tubing compatibility. The CSO Seawell is certified as an offshore installation capable of handling hydrocarbons at surface. Utilising a derrick structure, situated above a dedicated 22ft (7m) × 16 ft (5m) moonpool, well re-entry, wireline, pumping and abandonment tasks can be performed. Such tasks include gas lift, logging, perforating, cementing and setting plugs. Observation Remote Operated Vehicles (ROV) are an integral part of every well servicing operation, and the vessel can be equipped with a work-class Multi Role Vehicle (MRV). The first stage of developing Coflexip Stena Offshore's integrated subsea well intervention services is to extend the range of the existing system from 600 ft through to 3,300 ft. Modifications required include a new umbilical, incorporating an MRV operated panel on the lubricator and upgrading the lubricator winch wire and the four guide wires. The existing MRV unit has been successfully utilised in deep water diverless pipelay operations and can be fully equipped for well servicing operations. Following the above modifications a coiled tubing and tie-back riser system will be developed. This new system will allow for a smooth subsea changeover from normal wireline to tie-back riser activities by incorporating a high angle connector on the lubricator, compatible with the tie-back riser and the lubricator stuffing box. Coiled tubing equipment will be efficiently located on the vessel by modifying the existing equipment and vessel handling systems. This will include a purpose built injector head lifting frame to allow the injector assembly to be racked back into the derrick when not in use. A hydraulic control system will be required to power the coiled tubing equipment and will be a permanent feature on the vessel. Thus only an injector head and tubing reel would have to be mobilised for standard coiled tubing jobs, reducing time for overall mobilisation. The development of this integrated service from a dynamically positioned monohull will place Coflexip Stena Offshore in a unique position to take up the challenges of deep water West of Shetland and world wide. Introduction In Oil and Gas it has long been realised that cost savings and improved efficiencies in work methods are essential for the development of the industry, this is especially true in the North Sea in order to keep available investment from moving to other areas. One of the ways improvement can be made is for the North Sea industry to increase the efficiency with which assets are used. This is being done by looking for innovation in operations that will allow two or more tasks to be done simultaneously from the one offshore spread. This concept of simultaneous operations can involve the combination of any number of activities such as drilling, workover logging, pipelay, diving and general construction. This paper will focus on the simultaneous operation of diving services along with subsea well abandonment / servicing.

Abstract Well abandonment is now becoming an important consideration for many operators, particularly in expensive offshore locations. The traditional methods are very expensive to apply, and it is important to remember have a negative economic impact, other than good housekeeping. An innovative technique has been developed to enable all the well casing annuli to be permanently sealed in a single operation. A simulated well abandonment using this technique is planned for the summer of 1995 and the results will be presented together with time analysis and cost estimates. Introduction When production from a well drops below an economic level, the well may be stimulated, worked over or be subject to secondary and/or tertiary recovery techniques. However, the well will eventually require abandoning when it is no longer economic. Operators traditionally accrue for this eventual abandonment. However the costs of abandonment have soared due to inflation, and the higher costs of meeting ever stricter environmental requirements. Current techniques involve plugging each of the casings in a large number of sequential steps, then removing the casing. It requires the mobilisation of a rig and associated equipment to remove the casing from the well. A large cement plug is then placed to finally seal the well. The cost of the currently employed techniques are prohibitively high with operators often budgeting in excess of 650,0002 for abandonment costs. These high costs has forced operators to look at more cost effective methods1. However until now no cost effective method has been developed which could guarantee the long term integrity of the abandoned well. The technique proposed in this project will improve the quality and long term integrity of casing annul sealing at greatly reduced cost. The greatest assistance to oil companies can be given in the case of offshore where logistics and the environmental issues are more expensive to address. The techniques developed can be equally applied to land operations. Regulatory Requirements For platform structures - all well equipment and platform hardware has to be removed up to a minimum of 55m below sea level. For sub sea wells - the sea-bed must be cleared to 10 ft below mudline of all well equipment. For wellbores - all producing zones must be effectively isolated from each other. all producing zones must be effectively isolated from the sea-bed. all other potential producing zones that are either over pressured or hydrocarbon bearing must be effectively isolated from the sea bed. "effective isolation" is normally achieved with two verified cement barriers. Project Philosophy To significantly reduce the cost of well abandonment while matching current and potential future regulatory requirements, which will almost certainly involve post abandonment sampling of the seabed within an ever growing radius. By removing no casing or tubing from the wellbore avoids the use of a rig and the disposal of these used tubulars which potentially could have radioactive scale deposits. P. 53

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

Abstract This paper presents experience of subsea and marine systems gained from the first four years of production from the Ivanhoe/Rob Roy fields focusing particularly on those areas which are different from a fixed platform development. As an introduction the overall field layout is described and the success of the development is demonstrated by summarising availability of the facilities. The paper then describes the field development work since first oil, together with the inspection, repair and re-design work that have been necessary to ensure this success. The description includes work on all facilities on the sea bed, work on marine systems, and subsea well servicing. If thus includes the hull, stability and damage stability, bilge and ballast systems, subsea Christmas trees, moorings, flexible risers, flowlines and jumpers, valves, chokes, electro-hydraulic control system, umbilicals, downhole gauges, etc. The information can be used to lead towards more cost effective developments in the future. Introduction Ivanhoe/Rob Roy Fields The Ivanhoe/Rob Roy fields came on stream in July 1989 and have now been producing successfully for nearly four years. Typical production rates are in the region of 70,000 bpd. The fields are located in the UK sector Block 15/21a approximately 110 miles north east of Aberdeen in 140m of water. The layout of the field facilities is shown in Figure 1. From the centrally located Floating Production Facility, designated AH001, a flexible riser system (Fig. 2) connected to a Riser Base Manifold (RBM) conveys fluids up and down to the sea bed. From the RBM oil and gas export lines go to the Claymore and Tartan platforms respectively and infield flexible flowlines travel approximately 1.6 kms to the Ivanhoe and Rob Roy manifolds. There are a total of 16 subsea wells clustered around the manifold; Rob Roy manifold has 6 producers and 3 injectors (Fig. 3) and the Ivanhoe manifold has 4 producers and 3 injectors (Fig. 4). The electro-hydraulic control system consists of a dynamic umbilical at the aft end of the AH001, splitting three ways to distribution units and control modules on each manifold (Fig. 5). The control system also recovers data from a range of pressure and temperature gauges. The vessel is moored on station by a twelve point multi-component system (Fig 6), with the position being monitored by an acoustic system and also by reference to line lengths and tensions. The vessel draught, trim and stability are altered and maintained by a bilge and ballast system. P. 131^

Abstract Continued access to invert drilling fluids is a pre-requisite for efficient drilling operations across much of the North Sea. However, legislation now specifies that the oily cuttings, generated in the drilling process, have to be cleaned to a target level of 1% residual oil, on a weight by dry weight basis, prior to discharge overboard or they have to be disposed of other than to the seabed. A number of options for disposal are being developed (ref 1) but one that appears particularly attractive is the grinding and slurrying of oily cuttings. The resultant fluid is used to induce fractures in the sub- surface formation within which its permanent disposal is achieved. This process has been utilised successfully onshore in Alaska and from fixed platforms offshore in the Gulf of Mexico, the Norwegian North Sea and on the UKCS (ref. 2 and 3). In each case the wellheads have been easily accessible, providing simple access to the well or annulus for injection. For subsea wells drilled from a floating exploration drilling vessel, access to the annulus is much more complex, requiring modification to both the permanent guide base (PGB) and the subsea wellhead. This paper is a report of a successful field trial of one such subsea system where the permanent guide base (PGB) and subsea wellhead have been modified to allow access to an appropriate annulus for slurry injection. Introduction A Drilling Engineering Association (DEA) project was established in 1990 to investigate the feasibility of injecting a cuttings slurry into the annulus of a subsea well. This project was supported by 12 participating Operators (Agip, British Gas, British Petroleum, Conoco, Elf, Mobil, Norsk Hydro, Ranger Oil, Shell, Statoil, Texaco and Total) with Thule Rigtech as project managers. BP Exploration, at that time, held a patent for a design of a subsea cuttings injection wellhead (ref. 4), an adaptation of the Universal Subsea Wellhead which was detailed in SPE/IADC paper 18699 (ref 5). Dril- Quip were contracted by the project to develop and design a subsea wellhead system from the patent, with support from BP Exploration's Drilling Technology Division. The resultant design, manufacture and stack-up testing of the PGB/wellhead assembly will be presented in this paper, including the general safety design philosophy. The deployment of the system will be outlined and key elements of its operability will be detailed. The injection trial itself will then be presented, as it relates to the functionality of the PGB and wellhead assembly. Finally, the applicability of this approach to waste disposal will be discussed within the overall framework of continued invert emulsion drilling fluid use in the North Sea operating area. OVERVIEW OF THE CUTTINGS GRINDING AND SLURRY PROCESS Figure 1 presents a schematic of the slurrying process, depicting, in this case, annular injection. Oily cuttings, separated from the circulating fluid by the solids control equipment, pass to a grinding/mixing/dispersing process plant where the slurry of finely divided particles in water is generated. P. 99^