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It is usual for initial development wells on marginal fields to follow a conservative drilling programme using conventional technology with known drilling performance. In the case of the Janice Field situated in block 30/17a of the UK North Sea it became apparent, following field appraisal, that to effectively exploit the reservoir it was necessary to drill complex 3D well trajectories. Such wells would require significant directional work with large associated costs. Specific challenges included high torque and drag profiles, slow rates of penetration, limitations of conventional directional drilling techniques, tight target tolerances and the requirement for effective reservoir navigation. After careful consideration, the operator, Kerr-McGee North Sea U.K. Limited determined that the application of Rotary Closed Loop Steerable (RCLS) technology was part of the appropriate technical and economic solution for the drilling of these wells. This paper describes how the combination of RCLS and conventional drilling technology was used to achieve the field development objectives. This provided a unique opportunity to make a direct comparison between RCLS and conventional steerable technology on similar 3D complex well trajectories. Specifically, key performance factors were measured enabling quantitative and qualitative statements to be made of drilling performance with the two technologies. The experience gained provides an insight to where it is appropriate to use this new technology and demonstrates the applications for which this technology can provide significant technical and economic advantages. Introduction The Janice Field was originally discovered in 1990 and appraised by three nominally vertical wells in 1995/96 (Figure 1). The field is currently being produced by subsea wells coupled with a floating processing facility. This paper focuses on the planning and execution of the first three horizontal wells drilled in the period 1998/99. The initial field development plan featured drilling slant wells from a central wellhead cluster. However, analysis of the appraisal wells showed the existence of three sand layers with some degree of vertical permeability separation. This suggested that it would be better to pursue a horizontal well development. The revised plan required the drilling of four horizontal producers and four horizontal injectors. Two of the appraisal wells were to be incorporated as producers. This not only placed limitations on the surface location, but necessitated the planning of more complex 3-dimensional well trajectories. Conventional Versus Rotary Steerable? Early in the well planning process, it was apparent that the horizontal well trajectories would be challenging for conventional directional drilling technology. This was substantiated by an analysis of drilling operations in an adjacent block1 in which the operator had found directional drilling in the Upper Cretaceous Chalk to be "troublesome and time consuming" in 12¼" hole size. A study into the value and availability of Rotary Steerable drilling technology was initiated for the project. The study suggested that the market at that time (1997) could not deliver a reliable Rotary Steerable system. Further, the systems readily available were limited to drilling hole sizes in the range 8 ½" - 9 7/8". Final selection of a Rotary Closed Loop Steerable System2,3,4,5,6,7 (RCLS), shown in Figure 2, was based on meeting the key performance criteria, namely system operation up to a temperature of 150°C and dogleg capability in the range 0 - 5 °/100ft.

Continuous composite coiled tubing with embedded electric conductors can provide uninterrupted flow of data from downhole tools. This capability makes monitoring borehole stability throughout the entire drilling process possible, even when conventional mud-pulse telemetry tools are not operating and cannot provide information in real-time. An operator faces many borehole stability problems: stuck pipe, pack-off events, lost circulation, kicks, leak-off tests, and formation integrity tests, all of which can result in periods of non-circulation. However, an operator no longer has to rely solely on surface gauges to provide downhole information to deal with these problems because downhole readings are now available. The benefits of downhole pressure and tension data throughout these problematic and routine activities provide valuable information on events during the most critical operating procedures. Consequently, corrective actions can be taken to prevent or cure borehole stability problems almost as soon as they develop. In addition, downhole data can help reduce drilling time. The borehole is under constant scrutiny. Drilling, tripping, non-circulating, and circulating operations can be optimized while avoiding other potential problems. For example:Swab and surge pressures can be monitored constantly while tripping without circulating;Ledges and tight spots can be identified before they cause severe damage;Time for leak-off tests (LOT) and formation integrity tests (FIT) can be minimized;Early indications of borehole ballooning can be identified before ballooning becomes a major borehole stability issue; and,Hole cleaning intervals can be optimized, reducing drilling time. This paper covers a series of examples where continuous, uninterrupted data transmission was used to anticipate and prevent borehole stability problems and optimize the drilling procedure. Introduction The embedding of copper electrical conductors in Advanced Composite Coil Tubing (ACCT) allows a stream of high speed, high density data to be transmitted in real-time between the downhole components and the surface system. This uninterrupted communication enables the operator to receive all of the data, all of the time, regardless of the operating activities underway. In pipe-conveyed drilling, the real-time application of the "pressure while drilling" (PWD) data has been well documented. It is a very useful tool when used in conjunction with all the other drilling parameters to measure and anticipate drilling problems(1- 3). However, the extent to which mud-pulse telemetry data can be used during all operating activities is limited. The real-time application of PWD data has been hindered because of the constraints placed on the amount of data that can be pulsed to the surface. Ironically, one of the times when PWD data is most useful occurs when it cannot be pulsed up. This could be due to low flow rates or the pumps having to be switched off to avoid damaging the borehole or getting stuck. Surface gauges then have to be relied upon for downhole measurements. With the ability to have "real-time data all the time," pump-off data that could not be seen until the end of the run can now be seen immediately.

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