Historically, drilling long horizontal wells in the Valhall field offshore Norway has been challenging. Due to high drag levels, the Chalk formation is best drilled with rotary steerable systems (RSS). However due to severe stick-slip vibrations, a high number of LWD and RSS failures have occurred. The necessity to "geosteer" in the reservoir has also contributed to tortuous well paths that have further increased drilling and liner-running difficulties. In order to achieve 2,000m long reservoir sections, BP used a multi-disciplined team to leverage improvements in both drilling and linerrunning performance. The initial focus was on reducing stick-slip vibration and frictional drag. Drill string, BHA and bit design, LWD and logging tools, well profile design and mud design were all considered in the analysis. Significant improvements in both drilling and liner-running performance have been achieved. Introduction The Valhall field is located in the North Sea approximately 290km offshore southern Norway in 69m of water. The known challenges of drilling the Valhall reservoir are:Difficulty building inclination in the soft to very soft chalk.Localised sub-seismic faulting.Higher pressured, unstable Lista shale above the reservoir. If entered, a sidetrack would be required.Higher pressured Hod formation below the reservoir. If entered the mud weight may need to be raised to keep the wellbore stable.Geo-steering through the variable thickness in the reservoir.Anti-collision issues.Depleted zones around older wells.Hole cleaning as the chalk tends to go into solution rather than remain as discrete cuttings.Torque and drag problems while drilling.Problems while running and setting the liner. Increasing difficulties encountered while drilling the overburden from a crestal location have resulted in the failure to set the 9–5/8-in. casing of several ERD well in the correct location. Failure to do so was countered by the implementation of new well design [Ref. 1]. A wellbore stability study concluded that, for the required ERD infill wells, there would be less risk if the wells were drilled at a lower angle from a flank location [Ref. 2]. To facilitate drilling at a lower angle, an unmanned wellhead platform was installed on the South Flank in 2002 and a similar wellhead platform installed on the North Flank in 2003. This approach, to a large extent, mitigated the risks involved with drilling through the overburden. However, drilling up dip towards the crest introduced several new challenges for the drilling of the Tor reservoir formation. Drilling First Well on the South Flank Before Halliburton Sperry Drilling Services was called for the job, the first well was drilled using a competitor's BHA's. A steerable motor assembly with a mill tooth bit was selected to drill out the casing shoe at 2861m and complete the build up. The motor assembly gave an average dogleg of 7.4°/30m; but the well path dipped below the base Tor, and 76m of Hod was drilled. The well was geo-steered as required to 3727m where it was necessary to circulate bottoms up to reduce the drag. From 3778m, it was not possible to set the toolface; and the run was ended.

Accurate measurement of the true vertical depth (TVD) and reduction in the error uncertainty of the TVD measurement has become an increasingly important element in field development and well placement. A field on the North West Shelf of Australia required precise positioning of the wellbore within the reservoir. The trajectory within the horizontal production section depended completely on accurate geometric measurements to achieve the goal of keeping the well within +/-1 m of the target TVD for the entire length of the horizontal section – typically 1600m to 2300m. With great attention to detail, this is possible; however, the uncertainties associated with determining the actual wellbore inclination would normally overwhelm the required accuracy. The main sources of error while drilling horizontally result from misalignment (SAG) of the bottomhole assembly (BHA) within the wellbore, sensor axial misalignment, and axial accelerometer bias. To combat these sources of error, a multiple sensor system was designed with improved accelerometer bias (attained by using extreme calibration techniques). Compounded software programs for advanced BHA analysis and multistation analysis of the survey data were used. The data from the primary sensor determined the directional parameters used while drilling. The second directional sensor was positioned in the BHA to confirm the accuracy of the SAG correction applied to the primary sensor and to confirm any bias. Proprietary software was used in real time and post-drilling to perform multistation analyses of the accelerometer and magnetometer data from both sensors. This paper describes the methods used to reduce the TVD uncertainty while drilling long horizontal sections. Improvements were made to standard Industry Steering Committee for Wellbore Surveying Accuracy (ISCWSA) MWD+SAG error model to simulate the increased level of accuracy generated as a result of the multiple sensor system. Using data from the two directional sensors and a continuous at-bit accelerometer assembly, the ellipse of uncertainty was estimated throughout the section and remained with a +/-1.5 m (1 sigma) limit. TVD uncertainty was set to zero at the gas/oil contact (GOC); it was not necessary to model the total error from surface.