Performance Step Change in Kuwait: Drilling Deep-Directional 16inch Hole Build Section Saves Operator 13 Days Rig Time

Al-Saeedi, Mohammed Jasem; Mehesh, VS; Al-Enezi, Dakhil; Moore, Ross A.; Sharma, Maneesh; Eckstrom, Darren

doi:10.2118/102307-ms

IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition 2006

DOI: 10.2118/102307-ms

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Performance Step Change in Kuwait: Drilling Deep-Directional 16inch Hole Build Section Saves Operator 13 Days Rig Time

Mohammed Jasem Al-Saeedi

VS Mehesh

Dakhil Al-Enezi

et al.

Abstract: fax 01-972-952-9435. AbstractIn 2005, Kuwait Oil Company Exploration Group (KOC) began drilling KM-05, a deep directional exploration well in their West Kra Al maru (KM) field. The well was projected to TD at 16,285 feet MD. In order to intersect the reservoir fractures at the appropriate angle to enhance production potential, the well profile required drilling a 16" directional hole section. The operator considered this a significant challenge to complete the build section with a 16" PDC as it had never been … Show more

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Cited by 3 publications

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Solving Deep, Hard/Abrasive 16" Application Challenges with New PDC Technology Saves Operator 13 Days Rig Time, Kuwait

et al. 2011

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Drilling the deep vertical 16" hole (starting at 9,300ft) in northern Kuwait is challenging due to the complex stratigraphic section that contains abrasive Zubair sand (with pyrite), reactive Ratawi shale, hard Ratawi, Minagish, Makhul limestones and Hith anhydrite (UCS 10-30kpsi). Completing the 16" section typically requires around 45 days of rig-time and four polycrystalline diamond compact (PDC) bits on a positive displace motor (PDM) driven bottom hole assembly (BHA). However, inconsistent PDC bit performance/durability and lack of downhole stability was causing premature bit/motor failure. The operator required new PDC technology that could efficiently drill the abrasive, Zubair and continue as far as possible into the Ratawi without premature cutter failure at acceptable rates of penetration (ROP). The PDC bit would also need to possess improved stability characteristics to reduce PDM failures/trip hours.An engineering team was assembled to analyze the latest drilling/PDC technologies, optimize BHA design, and determine the best practices to enable reaching section TD with two PDC bits/runs. A finite element analysis (FEA) based engineering system was utilized to predict the dynamic behavior of each BHA component. The resulting information led to greater bit stability when drilling in lithologies comparable to the specific field application. The development of a new abrasion resistant cutter was considered important to improving durability and maintaining cutting efficiency.The in-depth study and PDC design changes/advanced cutter technology produced a new nine-bladed PDC bit. The new bit was run on a performance motor in Raudhatain field and set new PDC footage and ROP records for drilling through Zubair (1,200ft) in northern Kuwait (Figure 1). Historically, the Zubair alone required three/four TCIs or two/three PDCs to complete the formation interval. Next an eight-bladed PDC, fitted with the new cutter technology, drilled 2,508ft from Ratawi to section TD for the first time in Kuwait. The improved performance reduced rig hours by an average of 13 days for a total savings of approximately $390,000USD compared to the closest two PDC offset runs. SPE 139873Conclusions KOC's Deep Drilling Team 1, working in conjunction with the service provider, set a new performance benchmark drilling the deep 16" vertical hole section utilizing teamwork and new PDC bit/cutter technology. The new HPHT PDC cutters have reduced accelerated cutter wear and diamond table loss enhancing penetration rates and bit durability. Using the advanced dynamic FEA engineering software systems helped prevent BHA and formation induced vibrations, associated failures and trips by providing dynamically stable BHA and PDC bit combinations. The application specific bit design was tested and certified according to the operator's requirements through the use of dynamic simulations and rock laboratory tests. The result saved the operator rig time and reduced drilling costs by eliminating the traditional trial and error improvement/optimization...

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Solving Deep, Hard/Abrasive 16" Application Challenges with New PDC Technology Saves Operator 13 Days Rig Time, Kuwait

et al. 2011

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Innovative Drilling Technology Reduced Drilling Time in Deep Drilling Jurassic 16in Hole Section-Case Study

et al. 2013

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Directionally drilling of 16-in hole section in a deep gas field had been always a challenging task to the Operator. This is mainly due to the lithology, consisting of very hard limestone with thin bed of shale where the kickoff would generally start around 11,200 ft. The operator attempted to kick off the 16-in hole using both roller cone TCI bit and PDC bit technology and utilizing a mud motor as the drive mechanism. This method provided an unacceptable low rate of penetration. In addition, there were difficulties in achieving the directional control, and multiple bit trips were required to finish the required directional work. The operator determined that a new bottomhole assembly (BHA) would be needed to efficiently drill this section to the desired inclination and azimuth in one run, while meeting the performance requirement. Multi-function teams were organized to aggressively look for new BHA configuration that could consistently drill this interval in one run with a good rate of penetration. Historically the sliding ROP in the curve section consumes the maximum time (as low as 2-3 ft/hr) with PDC bits and Motor Kick off due to tool face control. To mitigate this, Motorized Rotary Steerable System was selected for this section. The section was kicked off very successfully achieving the required build rates with double the ROP compared to previous wells. The team collaborated to custom design a new bit and BHA with new drive system that would achieve the operator's objectives. The collaborative effort resulted in achieving new records in drilling, with the fastest ROP, 50 - 100% higher than previous attempts on the fastest offset wells ever drilled in a 16-in hole and precisely drilling to the planned trajectory. The application of this new technology proved to customer that what was not previously possible could be done now more efficiently and cost effectively.

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Performance Step Change: Optimized PDC Design for Directional Drilling Application Increases ROP by 39% Drilling Difficult Hard/Interbedded Formations in Northern Kuwait

Al-Khaldy

Failakawi

Al-Mulaifi

et al. 2015

Day 1 Mon, September 14, 2015

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Constructing the 12¼" 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 between 9-12 kpsi 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 12¼" 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 12¼" 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.

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Performance Step Change in Kuwait: Drilling Deep-Directional 16inch Hole Build Section Saves Operator 13 Days Rig Time

Cited by 3 publications

References 12 publications

Solving Deep, Hard/Abrasive 16" Application Challenges with New PDC Technology Saves Operator 13 Days Rig Time, Kuwait

Solving Deep, Hard/Abrasive 16" Application Challenges with New PDC Technology Saves Operator 13 Days Rig Time, Kuwait

Innovative Drilling Technology Reduced Drilling Time in Deep Drilling Jurassic 16in Hole Section-Case Study

Performance Step Change: Optimized PDC Design for Directional Drilling Application Increases ROP by 39% Drilling Difficult Hard/Interbedded Formations in Northern Kuwait

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