This paper summarises the factors influencing the well design for a high pressure high temperature (HPHT) field development using a Not Normally Manned Installation (NNMI) in the UK sector of the Central North Sea (CNS). Introduction The Erskine gas condensate field is a 50% Texaco / 50% BP venture and will be the first HPHT field developed in the North Sea with first gas scheduled for 1997 (Fig. 1). The field development concept is to install a not normally manned installation (NNMI) with multiphase export of produced fluids to the Lomond platform from six platform wells. Drilling and completion operations will be carried out using a harsh environment jack-up rig in cantilever mode. Primary functional requirements for the wells include high reliability, high productivity and the ability to perform through tubing plug-backs. Reserves in the core area are found in three separate but generally overlying Jurassic sandstone producing horizons, the Kimeridge, Erskine, and Pentland sands. A multi-discipline project team consisting of reservoir, production, drilling and facilities engineers was set up to progress the development concept. Specific well design principles were adopted and an iterative approach was used to produce a robust and reliable drilling and completion design that is compatible with the overall development concept and provides reliability on a NNMI in HPHT service conditions. Jackup drilling will commence over the platform jacket which will be installed over an existing sub-sea appraisal well in the spring of 1996 (Fig. 2). Two wells will be predrilled through the jacket structure and suspended prior to the platform topsides deck being lifted into place in 1997. The appraisal well will be tied back and wells will then be completed ready for commercial gas export in late 1997. Further wells will then be drilled and completed as required. Platform Concept Outline By North Sea standards Erskine is a marginal field (335 MMSCF gas, 66.5 MMBBL oil). The resultant development has revolved around this in order to make development economic. The following lists the main features of the development.Simple NNMI 12 slot wellhead platform providing unprocessed multiphase fluids export to host platform with a projected field life of 15–20 years.Platform design and slot layout which enables access to all slots for cantilevered jack-up drilling in the 300 ft water depth. Well Design Considerations Primary considerations for the well design are:Reservoir fluids containing H2S and CO2. Reservoir pressure +/-14,000 psi, temperature 350 F, initial surface shut-in pressure 10,600 psi (Table 1).Design flow rates required from each well will be up to 60 mmscf/day of gas.The wells that are initially completed as Pentland sand producers will water out and require to be plugged back and recompleted as Erskine sand producers. Due to availability and cost of large jack-up rigs, this requires to be a rig-less operation. P. 103

Summary The purpose of this study was to identify the most effective methods to free stuck pipe and to quantify the success rates of these methods under various wellbore conditions on the basis of historical data. This information has been integrated into a decision-making flow chart based on risk economics to determine when to begin and terminate operations to free stuck pipe. Introduction The Offshore Producing Div. at Texaco U.S.A. has developed a standard operational procedure for handling stuck pipe. The procedure involves spotting a diesel-based pill (DBP) if the pipe cannot be worked or jarred free in the first few hours after sticking. If the DBP fails to free the pipe after about 24 hours, the pipe usually is backed off above the free point and we try to free the pipe with fishing jars. Until now, we made these decisions without supporting data to indicate whether the benefits of operations to free stuck pipe justified the cost. Although the costs of pipe-freeing procedures usually are small compared with sidetracking costs, they are significant. Attempts to free stuck pipe by spotting pills or jarring usually require several rig days and can cost hundreds of thousands of dollars. These operations should be implemented only if their potential benefits outweigh their costs. The primary objectives of this study were to quantify the probabilities of success for various methods of freeing stuck pipe and to formulate a generic stuck-pipe decision-making process based on risk economics. When fishing operations begin, a certain cost is associated with freeing the pipe successfully, and a higher cost is associated with an unsuccessful fishing attempt that leads to plugback and sidetrack. This situation (two possible outcomes with known costs and known probabilities) lends itself well to expected value analysis. In this study, the expected cost of attempts to free stuck pipe is called risked fishing cost (RFC).

The Telemark Hub is being developed with a new design deep-draft floating production system [1]. This paper describes development of top-tensioned drilling risers and production risers with dry trees. The riser system includes standard riser joints, specialty joints and an innovative riser tensioning system. For the drilling and production phases, up to three risers may be used:a 21 in. low pressure (5,000 psi) riser,a 14 in. intermediate pressure (7,500 psi) riser, anda 10-3/4 in. high pressure (10,000 psi) riser. The single barrier drilling risers have a surface blow out preventer (BOP) and a subsea isolation device (SID) to provide emergency shut off in case of a breach or failure of the drilling riser. The SID consists of two 18-3/4?? blind/shear rams and is operated from the surface. The dual casing production risers have a 10-3/4 in. outer riser and a 7-5/8 in. inner riser. The ram style hydro-pneumatic riser tensioning system is designed for a nominal tension of 1,200 kips and a stroke of 26.5 ft. The tensioner module is supported by the hull rather than the deck. The same tensioner is used for all risers, with the nominal tension value adjusted to the design value for the particular riser. The system was designed for post-Katrina hurricane criteria, including robustness checks for the 1,000 year return period hurricane. Introduction The Telemark Hub is in Mississippi Canyon block 941 in approximately 4,000 ft water depth. Titan is moored with 12 taut polyester mooring lines as illustrated in Figure 1. A top-tensioned riser (TTR) support frame is located near the top of column. The riser tensioner module, illustrated in Figure 2, is supported by the TTR frame. The riser tensioning system supports the risers from a tensioner deck that is supported vertically on the four cylinder rods and is supported laterally by two guide posts. The risers extend through the TTR frame and are laterally supported near the keel by a guide tube. The bottom of the the riser is connected to an 18-3/4 in. wellhead profile with a hydraulically actuated connector. Titan has slots for six dry tree risers; three risers are planned for the initial development. Global performance of the system was analyzed using coupled analysis [2]. The hull, the mooring, and the risers were included in a single model. Results from the global model also served as a check of global motions and mooring analysis performed by others. The global model provides loading for detailed design of the riser and riser tensioning system components. Riser design requirements follow API RP 2RD [3]. System robustness was assessed for post-Katrina hurricane conditions including the 1,000 year return period hurricane [4, 5]. Site specific storm and current conditions were established for design. Environmental loading conditions for both strength and fatigue included storms, vortex induced vibrations (VIV) due to current acting on the risers, and vortex induced hull motions (VIM) due to current acting on the hull. Engineering criticality assessments (ECA) were performed to provide guidance for inspection during fabrication and to establish that the inspection interval exceeds the service life. The producing zones planned to be produced using the dry tree risers have a maximum shut in tubing pressure (SITP) of 8,000 psi. The BOP, tree and other equipment are rated for 10,000 psi service. Production risers were designed for a minimum service life of 20 years. Drilling risers were designed for a minimum service life of 5 years. The drilling risers will be pulled after the initial wells are drilled and sent in for inspection and storage until they are needed again.

This paper describes development planning for the Mirage & Telemark Fields located in 4000 -4500 ft WD in the Gulf of Mexico. These fields are relatively small, short lived oil fields with multiple pay zones. Factors driving development planning include: Lack of accessible nearby infrastructure Multiple pay horizons & short field life Limited availability of MODU's for pre-drilling Potential satellite tiebacks in the vicinity Parallel vs. sequential development of the nearby Telemark Field Functionality & Residual value in floating infrastructure These fields have 2 -4 pay zones in each well, so a dry tree concept was preferred. Because the floating platform design life is over 20 years vs. estimated field life of only 5 -7 years, the development facilities need to be designed for convenient relocation to other deepwater fields in order to maximize residual value.The MinDOC3 (Minimum Deepwater Operating Concept) hull was selected for field development because of flexibility, functionality and ability to fabricate in the US Gulf Coast. Hull construction required installation of the first graving dock for offshore construction in the US Gulf Coast.

The MinDoc3 platform, a dry tree capable, spread-moored deep draft floater featuring three columns braced together, was selected for Mirage field development because of flexibility, functionality and ability to fabricate in the US Gulf Coast. This paper presents the MinDOC's global performance and discusses impacts from hull form, mooring design and riser interaction and makes comparisons to previous design standards. The Mirage Field is located in Mississippi Canyon 941/942 in 4000 ft WD. The weather criteria includes the impact of hurricanes Katrina/Rita, and allows for maximum wave heights and robust mooring considerations. The MinDOC's global performance has been modeled experimentally and numerically with good correlation. VIM behavior was determined experimentally, and suppression is achieved by only straking the interior portion of the upper columns, which simplifies horizontal construction. The MinDOC was chosen for its payload, robustness and low motions. The mooring system is a relatively typical 3x4 semi-taught chain-polyester-chain system with a radius of approximately 6700 ft. The MinDOC hull form global motions are sufficiently low to permit the use of Top-Tensioned risers and Dry Trees. The low motions reduce riser stroke, which also reduced tensioner stiffness, and reduce the coupling impacts on the global motions. The low motions were achieved by a conscious effort to concurrently design the hull, risers, tensioners and mooring systems. Introduction MinDOC hull design was initiated in late 2006 with design and fabrication commencing nearly in parallel. The initial design site is for the Mirage field, located in Mississippi Canyon in Blocks 941/942. The location is near the edge of the shelf and the mooring system water depth varies from 3,822 ft in the north, to 4,288 ft in the south. The mooring pattern consists of 12 lines arranged in three bundles spaced 120° with each bundle having four lines grouped in two pairs. The platform bow orientation is 156 degrees. The leg numbering starts with the SE most line, counting clockwise around. Each mooring leg is chain-polyester-chain and consists of 5" R4 studless top chain, 9.75" Polyester and 5" R4 studless bottom chains. The nominal radius is approximately 6700 ft from the fairlead to the anchor chain touchdown. The total nominal length of each line is 7,500 ft. (Figure 1).