The 6"hole section in Raageshwari Field NW India (onshore) is typically between 600-800m long and highly challenging in terms of formation strength and abrasiveness. Lithology in the upper part is composed of sandstone, claystone and weathered basalt with unconfined compressive strength (UCS) between 3-5kpsi. The lower section contains basalt, felsic and sub-felsic igneous formations with UCS range of 15-30kpsi. Historically, a two bit strategy was employed. First, a PDC bit on a positive displacement motor (PDM) bottom hole assembly was used to drill the soft 6" section until ROP dropped to an unacceptable level. The BHA was then pulled and followed by a diamond impregnated bit on a turbine BHA to drill the very hard volcanics. Typical average on-bottom ROP for the entire section was 4.5m/hr and took approximately 170 hours to reach total depth (TD). To reduce costs, new technology was proposed to improve bit durability in the hard/abrasive volcanics and drill the entire 6" section in one run at a higher ROP. Recent bit and drilling data from offset wells was analyzed to assist in developing a new, cost effective PDC design to replace the expensive diamond-impregnated bits and drill the 6" hole section in one run. The study resulted in a new six-bladed PDC bit with 13mm cutters that incorporates superior cutter technology to improve durability and resist physical and thermal degradation. The design includes a row of backup cutters in the shoulder area to increase radial diamond volume for maximum durability. The new PDC bits have been run on a motor and rotary steerable bottom hole assemblies and drilled the 6" section on three consecutive wells in Raageshwari field totaling 2328meters with an average ROP of 10.7m/hr. This represents approx. 47% decrease in drilling time compared to that previously achieved by Impreg/TCI bit runs. Typically, the new bits are pulled in re-runable condition. This improved performance has saved the operator approximately six-days of rig time and approximately USD 480,000/well.
Significant mud losses during drilling often compromises well integrity whenever sustainable annular pressure (SAP), is observed due to poor cement integrity around 9-5/8-in casing in wells requiring gas lift completion. Heavy Casing Design (HCD) is applied as a solution; whereby, two casing strings are used to isolate the aquifers and loss zones, thus ensuring improved cement integrity around the 9 5/8-in intermediate casing. Casing While Drilling (CWD) is a potential solution to mitigate mud losses and wellbore instability enabling an optimized alternative to HCD by ensuring well integrity is maintained while reducing well construction cost. This paper details the first 12 ¼-in × 9-5/8-in non-directional CWD trial accomplished in Abu Dhabi onshore The Non-Directional CWD Technology was tested in a vertical intermediate hole section of a modified heavy casing design (MHCD) aimed at reducing well construction cost over heavy casing design (HCD) as shown in the figure 1. A drillable alloy bit with an optimized polycrystalline diamond cutters (PDC) cutting structure was used to drill with casing through a multi-formation interval with varying hardness and mechanical properties. Drilling dynamics, hydraulics and casing centralization analysis were performed to evaluate the directional tendency of the drill string along with the optimum drilling parameters to address the losses scenario, hole cleaning, vibration, and maximum surface torque. The CWD operation was completed in a single run with zero quality, health, safety, and environment (HSE) events and minimum exposure of personal to manual handling of heavy tubulars. Exceptional cement bonding was observed around the 9 5/8 in casing indicative of good hole quality despite running a significant number of centralizers (with smaller diameter), compared with the conventional drilled wells (cement bond logging was done after the section). CWD implementation saved two days of rig operations time relative to the average of the offset wells with the same casing design. The rate of Penetration (ROP) was slightly lower than the conventional drilling ROP in this application. The cost savings are mainly attributed to the elimination of casing-running flat time and Non-Productive Time (NPT) associated with clearing tight spots, BHA pack-off, wiper trips. The application of CWD in the MHCD wells deliver an estimated saving of USD 0.8MM in well construction cost per well compared to the HCD well design. Additional performance optimization opportunities have been identified for implementation in future applications. The combination of the MHCD and CWD technology enhances cementing quality across heavy loss zones translating into improved well integrity. Implementing this technology on MHCD wells could potentially save up to USD 200MM (considering 250 wells drilled). This is the first application of the technology in Abu Dhabi and brings key learning for future enhancement of drilling efficiency. The CWD technology has potential to enhance the wellbore construction process, which are typically impacted by either circulation losses and wellbore instability issues or a combination of both, it can applied to most of the offshore and onshore fields in Abu Dhabi.
Loss of circulation while drilling the surface holes has become the main challenge in the Abu Dhabi Onshore developed fields. Typical consequences of losses are blind drilling and high instability of the wellbore that eventually led to hole collapse, drill string pack-offs and other associated well-integrity risks. Expensive operations including implementing aerated drilling technique, high water consumption and logistical constraints lead to difficulties reaching planned depth and running casing with added complexities of well integrity due to poor cement quality and bonding in the required isolation zones. Casing while drilling (CWD) is becoming a powerful method in mitigating both lost circulation as well as wellbore stability issues. This paper details the first 13 3/8″ × 16″ successful non-directional CWD trial accomplished in Abu Dhabi and the various advantages of the process. The Non-Directional CWD technology is used to drill vertical or tangent profiles with no directional drilling or logging (formation evaluation) requirements. The casing string is run with drillable body polycrystalline diamond cutters (PDC) bit and solid body centralizers are installed into the casing to achieve the required stand-off for cementing purpose. Some of the best practices applied to conventional drilling operations are not valid for CWD. The paper presents the methodology followed by the drilling engineers during the planning and preparation phases and presents a detailed description of the execution at the rig and the results of the evaluation including time savings, cement quality, rate of penetration, bottomhole assembly (BHA) directional tendency and losses comparison among others.The implementation of CWD saved the operator five days. The bit selection and fit-for-purpose bit design were critical factors for the success of the application. The interval was drilled (as planned) in one run through interbedded formations with a competitive rate of penetration (ROP). In this trial the interval consisted of 2,470ft with an average on-bottom ROP of 63.7 ft/hr, zero quality, health, safety and environmental (QHSE) incidents with enhanced safety for the rig crew.The technology eliminated the non-productive time (NPT) associated with tight spots, BHA pack-off, vibrations or stalls which it is an indication of good hole cleaning and optimum drilling parameters.Medium losses (10-15 BBL/hr) were cured due to the plastering and wellbore strengthening effect of CWD allowing drilling to resume with full returns.Well Verticality maintained with 0.3 degrees Inclination at section final depth.The drillable CWD bit was drilled out with a standard 12.25-in PDC bit in 1 hour as per the plan.
Abu Dhabi National Oil Company (ADNOC) offshore and Schlumberger jointly initiated a project to drill the longest 12¼-in section ever drilled in United Arabs Emirates (UAE) as part of the integrated drilling service for an extended-reach project. The plan involved drilling 14,400 ft in an extended-reach drilling (ERD) well in the field. The objective was to reach section TD in one run, drilling from 5,194-ft MD and reaching TD at 19,494 ft MD. In the well in study, Well 29, the trajectory crossed different formations—including limestones, shales, and dolomites—and built inclination from 30° to 78° to achieve an optimal step-out for the following sections to reach the boundaries of the reservoir at 27,000 ft. Different formation challenges throughout the section required a step change in engineering to complete the objective successfully. ADNOC needed a robust steerable system selection with metal-to-metal sealing that would be exposed to severe downhole conditions, a new bit technology design, anti-collision analysis to help reduce additional gyroscopic operations, and optimized drilling parameters with an enhanced drillstring design. The section was planned to drill in 17.7 days. The total section was finished 10 days ahead of planned AFE, setting the record for the longest 12¼-in section ever drilled in ADNOC and UAE of 14,400 ft, which was 58% longer lateral than field average. Through increased cutting efficiency and superior impact resistance, the new bit design with ridged diamond elements drilled the fastest 12¼-in section on the field in 0.91 d/1,000 ft. Good hole conditions facilitated successfully running and cementing the longest 9⅝-in casing, meeting ADNOC well integrity barrier requirements. The 12¼-in section had the fastest IADC-recorded ROP in the field, with an on-bottom ROP of 105 ft/h, which was 110% faster than the field average. The Geomagnetic Reference Service correction was implemented for the first time and was allowed to drill in proximity with a high anti-collision risk well, eliminating a gyro trip in the middle of the run. Downhole drilling parameters analysis from the drilling mechanics module was crucial for understanding downhole energy transmission and implementation of efficient drilling strategy and reducing shocks and vibrations. The drillstring was redesigned, replacing the traditional 5-in × 5⅞-in drillpipe and enabling a stiffer BHA, which helped maximize the bit performance.
Drilling a 12¼-in hole section in the Agbami field offshore Nigeria presents a number of challenges.The section contains abrasive sandstone and shale that are interbedded with sandstone and siltstone, and all have unconfined compressive strengths (UCS) that vary across the field. The abrasive sandstone/shale section has UCS of 12,000 psi, and the interbedded sandstone/siltstone section has UCS of 15,000 psi or higher. The variation in lithology, formation strength, and abrasion/impact index make ensuring shoe to total depth (TD) runs with consistent ROP difficult because the conditions dull the polycrystalline diamond compact (PDC) bit's cutting structure, leading to a significant reduction in ROP before reaching section TD. An operator wanted to drill the 12¼-in section from shoe to TD in a single run with a 45% improvement in average ROP compared with the four-well offset median of 38.26 ft/h. To accomplish the objectives, the operator required a PDC bit with a differentiating drilling action designed to increase penetration rates and extend bit life in heterogeneous formations. A finite element analysis (FEA)-based modeling system was used to experiment with cutter types and their placement to improve drilling performance. Based on the modeling work, design engineers recommended a conical diamond element (CDE) with a thick synthetic diamond layer. The diamond layer on the CDE is approximately twice as thick as a conventional PDC cutter and exhibits 25% more wear resistance with almost double the impact strength. The element's unique geometry delivers high point loading for effective formation fracture. To fully exploit the CDE's advantages, the PDC bit body was redesigned by selectively abbreviating the blades at bit center and positioning a single CDE in the void space. The modeling system was also used to generate an operating parameter roadmap to maximize performance. The new 12¼-in central CDE bit drilled the 2,320-ft section from shoe to TD at 92.06 ft/h, a 102% increase in ROP compared with the best offset rate of 45.64 ft/h over a 2,419-ft interval. The performance improvement, which was achieved on the first deployment of the bit in this application, reduced drilling time by approximately 26 hours, saving the operator USD 1.2 million in offshore rig time. The bit design was deployed in another well where a comparatively heavier mud weight was used, but the run still recorded an outstanding increase in ROP over the best offset.
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