Innovative geomechanical, drilling, logging and seismic techniques have been used to successfully develop a geologically complex discovery in the North Sea, Tullich field. With individual reservoir unit thicknesses below the limit of seismic resolution, and a restricted depth window for completion, optimal placement of horizontal production wells, without delays, was vital to the successful and economical development of the field. Wellbore instability was a key concern after recent drilling experience in nearby fields with similar formations. By combining efficient teamwork and the latest technologies, the complex reservoir was successfully developed, both in terms of cost savings while developing the field, and good oil production.
Introduction
Tullich oil field is situated in block 9/23a (Fig. 1) and operated 100% by Kerr-McGee North Sea (U.K.) Limited. It lies 5 km south of the Gryphon field and came on stream in August 2002 as a subsea tieback from a central manifold to the Gryphon "A" floating production, storage and offloading (FPSO) facility.
Hamilton Brothers originally discovered the field in 1991 by drilling wells 9/23a-27 and 9/23a-27Z, where thin oil- and gas-bearing sands were encountered within the Eocene Balder formation. The sidetrack well 9/23a-27Z was successfully drillstem-tested. However, development of the prospect was not considered commercially viable with the technology available at the time. Advances in seismic and drilling technologies led Kerr-McGee to reconsider the prospect and acquire the block in 1999. In 2001 they implemented an exploration and appraisal program by drilling two vertical wells (9/23a-29A and 9/23a-31) and six sidetracks (9/23a-29Z through 9/23a-29U).
Kerr-McGee recorded a 3D seismic survey in 1990, and in 1999 a 3D ocean-bottom cable (OBC) seismic survey was acquired over the Gryphon field and northern part of block 9/23a. Inversion of the shear data from the OBC survey indicated the potential for an extensive development of lower Eocene Balder sand, culminating in the exploration drilling program in 2001.
The reservoir is of excellent quality and is interpreted to be a complex of turbidite sands, which lie in the Balder B2 zone directly above the massive tuff (Balder B1 zone) shown in Fig. 2. While the individual sands are below seismic resolution, the package could be mapped on the new seismic.
The development program of four horizontal wells began in early 2002, with the drilling of well 9/23a-T2 and concluded in October the same year with the completion of well 9/23a-T3. The wells had horizontal sections between 3,852 and 5,606 ft.
This paper describes how the seismic, core, drilling, and logging data acquired during the appraisal phase were used to evaluate drilling hazards, and how that information was used in the successful drilling and completion of the horizontal development wells. Details of how well-placement difficulties in this structurally complex environment were overcome are in recent publications by Greiss et al.1 and McDonald and Tribe.2
Appraisal Drilling and the Geomechanical Model
Recent experience with severe wellbore instabilities encountered while drilling formations of similar age and complexity in nearby fields led the drilling team to develop a focused program of data acquisition during the appraisal phase. This program was used to assess the wellbore instability hazards that could be expected during the development phase. Full suites of formation evaluation logs, including DSI* Dipole Shear Sonic Imager in cross-dipole (anisotropy) mode, and UBI* Ultrasonic Borehole Imager, were acquired in the two vertical wells (9/23a-29A and 9/23a-31). Reduced logging programs were acquired on the six sidetracks (9/23a-29Z through 9/23a-29U). An MDT* Modular Formation Dynamics Tester was used to perform mini-fracture testing on well 9/23a-31. Conventional core was collected in the 9/23a-29U sidetrack.
