The value of the mechanical specific energy (MSE) concept to analyze drilling efficiency and bit performance is well established. Recent operator-driven research has concentrated on predicting and maximizing rate of penetration (ROP). The specific energy ROP model has been successfully implemented in numerous high-cost/high-profile environments. To further advance the mechanical specific energy (MSE) concept, an engineering team is developing a methodology to optimize polycrystalline diamond compact (PDC) bit design for the entire hole section based on modeled MSE and unconfined compressive strength (UCS) values.Traditionally, PDC design engineers adjust cutter density/size, back rake, blade count and nozzle placement to optimize the bit for a specific application. The goal is to maximize ROP and total footage capabilities by minimizing damaging vibrations (axial, lateral, torsional) in a predetermined series of formations. Generally, the selected design has the least potential for vibration across all lithology types. PDC bits can generally drill a homogeneous formation without issues, but when transitioning zones or penetrating interbedded/unexpected formations vibrations can lead to performance degradation and cutter damage.The industry requires a method to unify bit efficiency throughout the entire section on a meter-by-meter basis. To calculate a bit efficiency factor (E m ), engineers are utilizing a sophisticated, integrated, dynamic engineering modeling system. They start with a meter-by-meter correlation between actual borehole lithology and a digitized rock library (UCS). MSE is then calculated using the modeled drilling parameters, torque, and ROP. The resulting two curves are then standardized by calculating the mean value of MSE/UCS fraction to derive a hard value bit efficiency factor. By overlapping the two curves, design and field engineers can identify lithologies that have the optimum correlation then compute the mean efficiency factor for the interval and use it as baseline for the entire hole section.In the test case study a 38m thick shale section offered the best match, yielding a median efficiency factor. Using the fixed median efficiency factor, engineers designed and optimized a PDC bit for the entire 16-in. hole section instead of each specific formation. The resulting ROP was significantly improved, as is documented in a case study that will be presented.

To develop gas/condensate reserves in Dorra field offshore Kuwait, the operator is setting a long string of large OD casing to facilitate short-radius horizontal drilling techniques in the 17-in hole section. The procedure has proved challenging for existing technologies and has led to the customization of tools for specific areas and in extreme cases on a well-by-well basis.To standardize operations, engineers studied offset data and conducted a lithology/formation analysis. The investigation indicated the lithology is PDC drillable from surface down to 1200ft and that reaching the Tayarat dolomite at 4000ft with acceptable ROP was possible with current PDC technology. However while drilling the first two wells, three different PDCs failed to achieve the target depth in-spite of steadily increasing blade count (6,7,8) and diamond volume in critical wear areas. The lack of durability resulted in one/two extra trips for a new PDC and/or rollercone to finish the hole section. The operator required a new approach to reduce CPF.A rock strength analysis was preformed to select the best TCI insert shape and gauge/heel configuration. An initial trial with a standard 17-in rollercone (GS18VEJ3) on rotary BHA proved successful. Although the new strategy required two bits to reach section TD, it reduced CPF by 10% compared to the best PDC/TCI performance. After analyzing dull bit condition and TCI cutting structure degradation, several additional challenges were identified as performance limiters.A new design was produced that included a precision sealed bearing system and new cutting structure geometry and insert shapes. The new design (MGS18VC) was run on a motor BHA in the next two wells with outstanding results increasing average footage and ROP by 24% and 8% respectively compared to average PDC/TCI drilled wells. The customized bit reduced CPF by an additional 8.5% for a total cost savings of $100,000USD/well.

While ERD multi-lateral wells in a large Middle East field are typically drilled in six to seven well bore sections, drilling the 8.5-in curve and the 6.125-in lateral sections represents more than 50 % of the total time spent drilling the well. Challenges while drilling the curve section with a motor include difficulty transferring weight to the bit while sliding and differential sticking in the highly poros zones of gas cap. The laterals, which can extend up to 12,500 ft of reservoir contact, are characterized by medium to hard compacted carbonate formations with high stick and slip tendency. This represents several challenges for drill-bit design engineers given that aggressive cutting structures are preferred to generate good rate of penetration even though this often leads to high bottom-hole assembly vibration. Trajectory control, hole cleaning and long circulating hours also represent significant challenges. This paper will present details of the engineering analysis performed to optimize both 8.5-in and 6.125-in wellbore sections. For the curve section, the first step was to change the drill string from 5 in to 4 in which considerably reduced the time taken to change the string prior to drilling the laterals. This change of drill string was accompanied by the use of a rotary steerable system and a PDC bit. This was a combination that had never been implemented since the field discovery in 1968. These changes resulted in performance improvements in excess of 50 %. For the laterals, the engineering analysis resulted in the need of a completely new bit design. The cutting structure was modified to provide a more aggressive bit to formation interaction, and the gauge contact with the formation was enhanced to maintain the bit and BHA stability. The resulting design broke the field rotary steerable ROP record by 28 %. The bit drilled the highest single run footage in the field (12,698 ft) at the highest ROP (96.93 ft/hr) with a rotary steerable system. This was further complemented by optimizing the drilling practices and well bore cleaning practices allowing the elimination of several conditioning trips within the long laterals which resulted in three days of savings in a three lateral well. The paper will conclude with a discussion regarding the reduced injury exposure that resulted from changing the drill string earlier within the well and a review of further improvement opportunities.