Exploratory drilling in the Faroe-Shetland Basin of the northeast Atlantic Ocean has been ongoing for several years. One of the greatest challenges of such drilling programs is cost-effectively drilling through the thick layers of Paleogene volcanic rock, which has thicknesses and depths that vary depending on the location of the regional tectonic geography. With the high expense inherent to remote offshore operations, total drilling costs will increase when expected penetration rates and interval lengths are limited due to drillbit inefficiency. An operator planned to drill a second well in the Brugdan prospect, which lies in License 006, Block 6104/21 off the Faroe Islands. The challenge of drilling through a hard, long section of basalt/volcanic sequence presented a great opportunity for investigating and implementing new drillbit materials and design changes to diamond-impregnated bits. A study for materials testing was focused on diamond grit/matrix combinations for wear, durability, and ROP on two representative basalt outcrop columns provided by the customer. The analysis of the physical characteristics of the rock provided an insight of the matrix and diamond combinations for blade material and grit hot-pressed inserts (GHIs) that would offer a reliable product to meet the challenge and drill the long section. Materials testing followed at the drillbit manufacturing facility to find the appropriate diamond-impregnated recipe. A competitive diamond-impregnated bit was developed for the 12¼-in section, resulting in an internal world record and an unprecedented drilling performance in the extremely hard and long volcanic sequence.

In The Netherlands the operator drilling in the Southern North Sea area had to drill through Germanic Trias super group sequences to the reservoir sections in Buntsandstein formations of lower Triassic series at a depth of about 9,800-ft TVD that are highly abrasive and hard sandstone formations. These formations are overlaid by middle and upper Triassic clay stones interbedded with hard dolomite stringers. The compressive strength of these formations ranges from 5,000–15,000 psi in the upper clay stones and from 15,000–30,000 psi in the Buntsandstein group. Drilling the build and turn wellbore profiles using a directional BHA with roller cone and/or PDC has been challenging. In offsets, these bit types produced slow ROP and short run lengths, requiring multiple bit trips to complete the hole section. In many cases, the bits were pulled in poor dull condition with severe cutting structure damage. In some cases, the operator was forced to use diamond-impregnated bits on turbine to TD the section. To drill the section in one run and at higher ROP, the provider recommended a new-style conical diamond element bit that uses multiple conical shaped diamond elements (CDEs) positioned from bit center to gauge. The CDE's conical shape penetrates high-compressive-strength rock with a concentrated point loading that fails formation with a plowing mechanism. Design engineers used a finite-element-analysis (FEA)-based modeling system to strategically place the CDEs based on specific drilling parameters and formation characteristics. Recent R&D tests confirm the hybrid PDC bit drills with 25% less torque compared with conventional PDC cutters, providing increased directional control and smoother toolface response. The result is higher build rates that achieve directional objectives in less time. The new 513 design also included a centrally located CDE to enhance bit stability and mitigate shock and vibration. The bit was run on an RSS BHA and drilled 1,279 ft of difficult claystone and anhydrite/dolomite with silt/sandstone stringers at an average ROP of 31.04 ft/hr, 200% faster compared to the closest offsets in the reservoir sand. The bit also set a new single-run footage benchmark for this section in Block P15. The RSS BHA efficiently delivered all directional wellbore requirements, building inclination from 26° to 39° with a DLS of 3.42°/100 ft and 6.09°/100 ft in Sidetrack 1. As a result, the operator saved one day of rig time and a bit trip for a total savings of approximately USD 635,000.

The purpose of the paper is to present how an integrated solution was designed to turn a challenging 6-in. section into a successful 6-in. production sidetrack in Norway. A threatening casing wear issue caused by the combination of slow progress and localized dogleg was addressed successfully with a complete redesign of the drilling system. A 6-in. pilot section suffered slow progress due to low rate of penetration and tool failures. Significant amount of metal swarf was recovered while drilling. A casing wear log quantified the wear in the 9 7/8-in. casing, and this led to questioning the feasibility of the planned 6-in. production sidetrack. Operator, rig contractor and integrated services provider worked together to find a solution. First, a detailed study of the wear was performed. A wear log was run, and the casing wear was quantified. Casing wear simulations were then calibrated based on wear logs and it appeared feasible to drill the 6-in. sidetrack if a minimum rate of penetration and a maximum number of revolutions were respected. Second, the drilling system was optimized to ensure faster progress. This was done thanks to the learnings from the pilot section. The mud system was changed, and a lower density was used to increase the rate of penetration. The drillbit was optimized based on the limited wear seen in the bits used in the pilot section. As it was more aggressive, the perceived risk of downhole tool failure was mitigated with the use of an anti-stall tool. Finally, to reduce the incremental wear from the sidetrack operation, casing protectors and lubricants were run. Also, the planned drillpipe was changed to a lighter drillpipe to reduce the sideforces. The new system resulted in a successful drilling and section TD was reached ahead of the estimated perfect time. With this paper we provide a detailed example of how a casing wear issue was addressed. The drivers we extract from this case are useful for the planning of future operations, especially in extended-reach wells.

Drilling a re-entry well is a routine operation on mature fields. Several techniques are generally used for re-entry operations including cement plug sidetrack and whipstock sidetrack (Hussain et al. 2016). Often the completion string is pulled prior to performing the sidetrack operation but when it is not, one calls this operation a Through Tubing Rotary Drilling (TTRD). Benefits of TTRD wells include lower cost to access small hydrocarbon reserves. Through-tubing wells are usually drilled with small hole sizes and in Norway such wells are generally drilled with 5 7/8-in. or 5 ¾-in. hole sizes. In this paper we present the case of a through-tubing well drilled with an uncommon 3 ¾-in. hole size. This paper will: Present the reason for planning such a sidetrack: drilling 3 ¾-in. hole is a rare operation on the Norwegian Continental Shelf (NCS)Describe the solution selected for the operation, including the directional plan, the whipstock setting operation and the 3 ¾-in. bottom hole assemblySummarize the risks and compensating measures associated with this solution, including the low buckling margins in this well planned at inclinations higher than 90°, the low tolerances on the downhole connections that could lead to a twist-off, the limited experience with the directional behaviour of such a slim bottom hole assembly, the bit design.Present the results of the successful operation: this rare 3 ¾-in. hole drilled on the Norwegian Continental Shelf was drilled successfully and below budget.Find the main drivers that will make this solution portable to other situations This case study demonstrates how detailed and thorough planning based on modelling led to the successful delivery of a rare well design at first attempt. It is an objective of this paper to share some key elements that will be useful for the planning of similar operations in other wells in the future.

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