fax 01-972-952-9435. AbstractMaersk Oil and Gas AS are typically drilling the carbonate reservoirs in the Danish Sector of the North Sea in 8½" horizontal hole sections, with section lengths regularly over 15,000 ft. The two lithological components of the formation show a large variation in geo-mechanical properties: a soft, plastic chalk matrix and large, hard, brittle, chert nodules. Impact loading on cutting structures and penetration difficulties in the hard, microcrystalline chert are generally the limiting factors on bit longevity and performance. These long horizontal sections highlighted the opportunity for optimising the durability of single bit runs. In June 2001 Maersk Oil implemented a bit development priority that was to produce significant, beneficial results.

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.

In the Dutch sector of the North Sea the Ommelanden Chalk formation commonly contains large amounts of chert, a very hard nodular rock. High friction exacerbates the harsh drilling conditions leading to mechanical dysfunction of the drilling process: severe downhole shocks, large torsional vibrations, bit and bottom hole assembly (BHA) wear and loss of directional steerability. Acceptance of these drilling conditions have long prevented drilling teams in the Netherlands to make significant drilling performance improvements. This case study shows a step-by-step optimization approach, where we evaluated various drilling systems and their interdependence at each step. Separately optimizing the individual drilling sub-systems: bit, BHA, fluids and the rig led to little overall improvements. The initial focus was on the bit and drive system, but their successful utilization was limited by the harsh drilling environment. Close examination and various attempts proved that a combination of non-aqueous based mud (NABM), lubricant and a rotary drive control system could deliver a stable drilling environment. This allowed us to select different bits and drive systems. After multiple attempts with new technology PDC bits we proved drilling the entire chalk interval in one run was possible. In addition, rotary steerable systems (RSS) enabled directional steering in any part of the 12 ¼-in section. The improvements led to fewer bit runs. The average progress rate through this section has been increased from 100 m/day to 300 m/day, with estimated savings of 10 to 15 rig days per well. In addition, the downside risk of equipment damage, inability to maintain trajectory control and related cost has been reduced significantly. Pursuing drilling optimization can take considerable time and effort. It is often not a single-step process, but requires a multidisciplinary approach. This case study demonstrates important process improvements and technology applications, which reduced operating risk and cost.