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

A novel drill collar mounted pressure and temperature gauge tool has been used to measure and record temperatures and pressures near the bit while drilling the 8.1/2" hole section of a North Sea Central Graben HPHT well on the Erskine field in Block 23/26b of the UK sector. The tool was run on the first well in the development with the intention of improving drilling performance through a better understanding of downhole pressures in HPHT wells. The memory type pressure and temperature gauges were present during a series of experiments designed to test currently held theories and models of hydrostatic and hydraulic pressure changes in HPHT wells. The tool was also present when the 8.1/2" section was drilled and recorded temperatures and pressures during loss and gain flow incidents typical of HPHT hole sections in the Central North Sea. This paper presents data from the tool which show:–The effects of swab and surge pressures while drilling and tripping.–The effect of rotation on ECD.–The effect of wellbore temperature changes on measured bottom hole pressures.–The transmission of pressures in heavy oil based mud and the effects on leak off test accuracies.–Bottom hole pressures during stripping operations.–Bottom hole pressure variation during loss and gain events.–The need for downhole measurements to understand fully events that may be difficult to interpret from surface. These observations have resulted in operational procedures that have produced significant reductions in time and costs when drilling the HPHT section on subsequent wells. Introduction The Erskine field, situated in the North Sea Central Graben block 23/26b, is the UK North Sea's first HPHT development. Drilling of exploration and appraisal wells on Erskine has historically proven to be difficult with average kick frequencies of two per well, with at least one kick on every well. The reason for the demanding nature of the wells had previously been identified as the narrow window between pore- and fracture-pressure in the overpressured HPHT section. In this section the window between pore and fracture pressures narrows significantly and drilling becomes a fine balance between loss and gain - to and from "ballooning" shales in the formation. During the detailed planning of the Erskine drilling campaign it was decided to measure the effect of drilling variables (flowrate, pipe movement etc.) on downhole pressures and temperatures. These tests were intended to provide a better understanding of ECD's while drilling and a means of managing bottom hole pressure to reduce drilling problems in the critical section of this and subsequent wells. To this end a PWD (Pressure While Drilling) tool was installed in the drillstring while drilling out the intermediate casing shoe on the first Erskine HPHT development well. The well used for the tests was an 'S' shaped development well drilled form the heavy duty jack up rig Santa Fe Monitor. The directional profile and casings set at the time of the test are shown in Figures 1 and 2. The 10" intermediate casing had been set 60 ft into the Lower Cretaceous Unit, within the Erskine transition zone, at a depth of 15015 ft. The expected pore and fracture pressures are shown in Figure 3 and the expected pressure "window" for operations is presented in Figure 4. This representation was designed to help manage hydrostatic and hydraulic pressures while drilling. P. 169^