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.

Summary 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 was vital to the successful and economical development of the field. Wellbore instability was a key concern after recent experiences while drilling similar formations in nearby fields. These events had resulted in significant nonproductive time and cost overruns. A geomechanical model was constructed from data acquired during the appraisal-drilling phase and was used to make stability predictions for the proposed horizontal production wells. Wellbore instability while drilling was prevented through the application of a real-time wellbore-stability management system that validated the stability predictions by monitoring surface and downhole drilling parameters, produced solids, fluids, and log data. By combining efficient teamwork and a variety of logging and drilling technologies, the complex reservoir was successfully developed, both in terms of cost savings during well construction and subsequent oil production that exceeded expectation. Introduction The Tullich oil field is situated in Block 9/23a (Fig. 1) and operated 100% by Kerr-McGee North Sea (U.K.) Ltd. 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 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 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 extensive development of the 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. An oil column extends 200 ft between a gas cap above and an aquifer below. 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 wellbore-stability hazards, and how that information was included in the successful drilling and completion of the horizontal development wells. Details of how drilling and well-placement difficulties in this structurally complex environment were overcome are presented in recent publications by Greiss et al. (2003) and McDonald and Tribe (2003).

The Cygnus gas field is being developed by ENGIE E&P UK Limited in the UK Southern North Sea and is one of the largest discoveries in the Southern North Sea in the last 30 years. The field has two gas bearing reservoirs in the Carboniferous Lower Ketch Member of the Ketch Formation and the Permian Lower Leman sandstone. The Lower Leman Sandstone is the main reservoir target for 7 of the 10 wells in the development. The Lower Leman Sandstone is highly layered comprising fluvial influenced playa shoreline facies. The better reservoir quality intervals are restricted to thinly bedded laterally extensive sand rich intervals related to drier climatic events. Through utilization of reservoir navigation LWD tools the production wells have preferentially targeted these better quality thin intervals in order to maximize well productivity. To geosteer in these sands provided several challenges such as uncertainty in dip and the presence of sub-seismic faults. Furthermore the reservoir shows only subtle variations in log response from Gamma Ray and resistivity tools. This made correlations with offset well data difficult. As a result, the integration of information from multiple LWD tools and types of analysis was required to delineate the geological structure and to identify the stratigraphic position of the trajectory in order to place the well in the target interval. The key data sources for the leman productions wells have been the correlation to offset data, real-time Density images and utilization of Deep Directional Azimuthal Resistivity's. The limit of the Deep Directional Resistivity tool was tested due to the very low resistivity contrast reservoir (commonly 1-2 Ohm.m) but the data has still been utilized during geosteering operations. The quality of the density image data has also allowed for a real-time True Stratigraphic Thickness (TST) calculation service to be provided where extra stratigraphic control was required. Five of the Leman production wells have been successfully drilled and completed with results that were at the high end of expectations. This will contribute to maximizing the productivity for the field. In this paper the case studies showcased will demonstrate the Geosteering methodology utilized in this complex reservoir. For ENGIE, these examples demonstrate the value of investing in technologies for acquiring multiple data sets for successfully Geosteering in challenging geological settings.