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Ibrahim H.,Smith Bits | Gidh Y.,Smith Bits | Purwanto A.,Smith Bits | Visinescu V.,Schlumberger
Society of Petroleum Engineers - Canadian Unconventional Resources Conference 2011, CURC 2011 | Year: 2011

The Bakken Shale is one of the largest, unconventional crude oil plays in the United States covering as much as 25,000 sq miles in the Williston Basin. The formation underlies portions North Dakota and Montana and is found at depths ranging from 9000ft to 10,500ft. Reserve estimates vary but the United States Geological Survey (USGS) has calculated risked undiscovered resources of up to 4.3 billion barrels of recoverable oil and bbl/cu ft equivalent using current technology. At this time the field is being developed with single, dual and triple-leg horizontal wells with laterals extending 4500ft to 9500ft into the formation. However, drilling activity in the area has fluctuated as a result of changing oil prices. Accordingly, reducing overall operation costs is essential to the economic feasibility of each drilling project. Because of the significant impact on drilling costs, the correct selection and utilization of drilling equipment including bits, drilling fluids, hydraulics and downhole tools is paramount. To optimize operations, a holistic approach was adopted to create a drilling "road map" utilizing several application software systems. These software tools enable engineers to envision the specific drilling environment and tool/BHA interaction before the bit goes in the hole. A recent Bakken project included expert drill bit selection, rock mechanics analysis, shock studies, drilling fluids and hydraulics optimization. The directional well plan was optimized with wellbore simulation software. In order to circumvent deficient options prior to and during actual drilling operations, multiple scenarios are simulated using a collection of detailed geological and offset drilling information. These results were studied, analyzed and assessed as the optimum drilling solution prior to submitting them to the operator. Finally, the service provider monitored and implemented the recommended engineered solutions. The initial results were encouraging: Drilling days on Well 1 were reduced by 30% which represents a cost savings of $572,000USD while achieving the drilling target and delivering a high-quality wellbore. Building on this initial success, second and third wells confirmed the value of holistic optimization saving the operator 13 days ($676,000USD) and 16 days ($832,000USD) of rig time respectively. Copyright 2011, Society of Petroleum Engineers.

Varela R.,Schlumberger | Guzman F.,Neyrfor | Cruz D.,Smith Bits | Atencio N.,Schlumberger | And 4 more authors.
SPE/IADC Drilling Conference, Proceedings | Year: 2014

This paper highlights the design, execution, and evaluation of the first application of turbodrill and hybrid bit to drill cretaceous formations with up to 40% chert content in Mexico South region. The complex cretaceous formations in the Terra field presents many drilling challenges: mud losses, gas influxes, hard [Unconfined Compressive Strength (UCS) 15-30 ksi] and abrasive formations, difficulty building inclination, low rate of penetration (ROP) requiring many runs of 8-1/2″ tungsten carbide insert (TCI) bits. The goal of a new drilling system application was to reduce trips for TCI bit changes due to drilling hours limitations, optimize flat times, reduce rotary steerable system (RSS) failures, deliver a wellbore with minimal tortuosity to enhance wellbore evaluation and running liner operations, and eliminate the risk of fishing for lost cones. To meet these objectives the use of turbodrilling and hybrid bit technologies was evaluated. Hydraulic simulations were run to determine if the mud pumps could deliver the required hydraulic power to the turbine, a drill string design was performed to avoid fatigue failures and increase on-bottom rotating hours in a high temperature environment, directional requirements were analyzed to estimate the dogleg severity (DLS) in carbonates with chert nodules to be able to reach the proposed well objective. The turbodrill and hybrid bit application drilled 1240 ft, which is the longest run in the field eliminating two trips when compared with TCI bit runs. The turbodrill application successfully built inclination and turned the wellbore at the planned DLS. Additionally, increased service life of the managed pressure drilling (MPD) rotary head and top drive washpipe was observed. Casing wear was reduced due to the low drill string revolutions per minute (rpm) on surface which was corroborated with the low amount of steel recovered in the shale shakers magnets. Trips to surface were without drag and 7″ liner was run immediately after logging, eliminating a wiper trip. The Terra field has an aggressive development plan and lessons learned from this application will reduce drilling times and meet regional objectives to boost production from hard carbonates reservoirs. Horizontal wells are now being drilled, turbodrills and hybrid bits demonstrated to be viable solutions for this technical challenge in southern Mexico region. Copyright 2014, IADC/SPE Drilling Conference and Exhibition.

Bruton G.,Chesapeake Operating Inc. | Crockett R.,Novatek | Taylor M.,Novatek | DenBoer D.,Novatek | And 5 more authors.
Oilfield Review | Year: 2014

Polycrystalline diamond compact bits have led the way to greater drilling efficiencies in many recent plays. However, as operators push the limits of depth, temperature and distance in pursuit of new reserves, they also push the limits of drillbit life and efficiency. Recent advances in cutter technology are enhancing bit performance and durability across a wider range of lithologies than was previously possible. Copyright © 2014 Schlumberger.

Al-Khaldy M.D.,Kuwait Oil Company | Al Failakawi K.,Kuwait Oil Company | Al-Mulaifi M.,Kuwait Oil Company | Al Rashidi A.,Kuwait Oil Company | And 3 more authors.
Society of Petroleum Engineers - SPE North Africa Technical Conference and Exhibition 2015, NATC 2015 | Year: 2015

Constructing the 12 1/4″ direction hole section through approximately 3000ft of difficult interbedded lithologies (Mutriba-Lower Burgan) in northern Kuwait presents a number of distinct challenges. In the upper portion of the hole section, a PDC bit must penetrate medium to hard carbonate and shale formations with compressive strength ranging betwee kpsi 9-12 with peaks up to 30kpsi. Next, a challenging abrasive sand with compressive strength between 6-9kpsi requires an RSS/PDC assembly to reach TD. The operator experimented with several different bit designs attempting to efficiently achieve directional objectives and improve borehole quality with limited success. Issues with baseline designs included lack of cutting structure durability and low ROP. To accomplish the operator's objectives, the engineering team analyzed all relevant offset data and concluded an existing 12 1/4″ six-bladed bit with 16-mm cutters would serve as the starting point for an optimization effort. The bit's design data was fed into an FEA-based modeling system. Formation characterization software was then utilized to select the appropriate rock samples to simulate the field formations in the laboratory. Multiple simulations were run to determine the best combination of technologies to achieve the objectives. A new 12 1/4″ directional design (616-type) would include premium cutters that can withstand impact in the interbedded carbonate/shale section and remain sharp while drilling the lower sand formations to TD. The bit also features a torque limiting feature in the blade top and TSP inserts in gauge to ensure hole quality. Next, a series of simulations were preformed to observe how different RPM and WOB values would affect vibration and torque levels. The results were plotted to create a smooth drilling parameter window to maximize the new bit's ROP potential. The new bit design was run on RSS with PDM assist and set a new ROP record of 46 ft/hr, 39% faster than the best offset of 33 ft/hr and 68% higher than the five-well offset average (27.3 ft/hr). The bit met all directional objectives (5-6° DLS) and was pulled in excellent dull condition (0-1-WT). The authors will discuss the bit design and selection process in addition to the HTHP cutter technology which saved the operator 2.5 days of rig-time and associated costs. Copyright © 2015 Society of Petroleum Engineers.

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