During extended reach drilling operations, stick-slip was identified within the operator’s Fast Drill Process™ workflow as the primary performance limiter in the 8-1/2-in. hole section. This dysfunction resulted in low penetration rates, frequent downhole tool failures, and bit damage. Subsequently, multiple bit runs were required to reach interval objectives. The redesign process identified two key solutions to mitigate stick-slip vibrations. First, the bit was redesigned to limit (or manage) the depth of cut to reduce the torque variations which can excite stick-slip. Second, the torsional stiffness of the drillstring was increased by changing from 5-1/2- to 5-7/8-in. drillpipe, which reduced the magnitude of the torsional oscillations. The systematic application of these design changes allowed higher weight on bit (WOB) to be applied without stick-slip dysfunction, resulting in significantly higher penetration rates. This paper presents the results of applying depth of cut control and drillstring design to eliminate stick-slip while drilling. Weight-on-bit, vibration, and penetration rate data will be presented over the course of eight wells. Results indicate the managed depth of cut and increased torsional stiffness provided significant reductions in vibrations leading to multiple field record rate of penetrations (ROPs), improved downhole tool life, and reduced bit damage.

In 2007, Hibernia Management and Development Company Ltd. (HMDC) began drilling operations on B-16 57 (OPA2). The plan involved drilling and completing an oil producer to 32,000-ft measured depth (MD) and to a total vertical depth (TVD) and horizontal departure that would put the well outside the worldwide ERD envelope. The well was temporarily plugged and abandoned at ~20,000 ft in the 12¼-in. hole section as a result of a combination of factors including complex geology and wellbore instability.The planning of the redrill began almost immediately and involved the collaborative efforts of the local drill team, the local geoscience team, industry experts from ExxonMobil, and the other HMDC co-venturers and service providers. The final trajectory was a result of HMDC co-venturer collaboration and balanced risk associated with encountering unstable zones and complex lithology. Successfully drilling this well would require an engineered approach to operations as well as incorporating an ultra thin fluid system in the 8½-in. hole section.The successful execution of the redrill was a result of enhanced cooperation between the operations, engineering, and geoscience teams. The application of proven HMDC and ExxonMobil practices for hole cleaning, rate of penetration (ROP) management, and wellbore stability were critical success factors. The increased focus on downhole mechanics and surface limitations through the ExxonMobil Fast Drill Process and the flat time reduction initiative allowed OPA2 to be completed successfully at a depth of 33,209-ft MD, further extending the worldwide ERD envelope. Application of the drill team's standard bit and bottomhole assembly (BHA) design allowed shock and vibration and mechanical specific energy (MSE) to be minimized, resulting in field record rates of penetration (ROPs). Most notably, the 8½-in. hole section was drilled in one shoe-to-shoe bit run in 5.7 days. The nearest offset, completed in 2003 in the same geologic fault block, required eight bit runs and 57.6 days from drill out to TD.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractTo qualify for use on a world record extended reach drilling (ERD) well, a trial well was selected to demonstrate the technical benefits of using a uniquely designed, low-rheology, synthetic-based drilling fluid. The 8½-in., production hole section was 1,755 ft (535 m) long and drilled to 20,472 ft (6,240 m) at an angle of 25°. Prior to drilling this section, a low-rheology drilling fluid was selected. Selection analysis was based on assessment of key drilling parameters as compared with wells drilled previously using a conventional API barite-weighted synthetic fluid. A unique characteristic of the low-rheology drilling fluid is its use of specially treated, micron-sized, barite-weight material (TMSB). It can be formulated with a much-reduced rheological profile without the risk of barite sag. This paper presents the background work performed leading up to the field trial. Field data is presented comparing the drilling performance and fluid characteristics between the low-rheology fluid and the previously used conventional API barite-weighted synthetic fluid system. Significant reductions in equivalent circulating density and standpipe pressures were accomplished, as well as torque reductions of up to 30%. Results demonstrated the low-rheology, synthetic-based drilling fluid's ability to reduce drilling risk. This paper reports the economic and technical benefits realized from using this fluid, including the first use of 400-mesh prototype shaker screens (API 200 mesh), the much reduced dilution factors, and cuttings re-injection volumes.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractTo qualify for use on a world record extended reach drilling (ERD) well, a trial well was selected to demonstrate the technical benefits of using a uniquely designed, low-rheology, synthetic-based drilling fluid. The 8½-in., production hole section was 1,755 ft (535 m) long and drilled to 20,472 ft (6,240 m) at an angle of 25°. Prior to drilling this section, a low-rheology drilling fluid was selected. Selection analysis was based on assessment of key drilling parameters as compared with wells drilled previously using a conventional API barite-weighted synthetic fluid. A unique characteristic of the low-rheology drilling fluid is its use of specially treated, micron-sized, barite-weight material (TMSB). It can be formulated with a much-reduced rheological profile without the risk of barite sag. This paper presents the background work performed leading up to the field trial. Field data is presented comparing the drilling performance and fluid characteristics between the low-rheology fluid and the previously used conventional API barite-weighted synthetic fluid system. Significant reductions in equivalent circulating density and standpipe pressures were accomplished, as well as torque reductions of up to 30%. Results demonstrated the low-rheology, synthetic-based drilling fluid's ability to reduce drilling risk. This paper reports the economic and technical benefits realized from using this fluid, including the first use of 400-mesh prototype shaker screens (API 200 mesh), the much reduced dilution factors, and cuttings re-injection volumes.

During extended reach drilling operations at the Hibernia Platform, operated by Hibernia Management and Development Company Ltd. utilizing ExxonMobil Canada Ltd. resources, bit gauge length and profile have been systematically varied to improve drilling performance while using a standard bottomhole assembly (BHA) and bit design. Prior to developing the standard BHA design and implementing a global performance management process, the ExxonMobil Fast Drill Process, multiple bit runs were required to drill a typical high angle, 10,000-ft interval of 12¼-in. hole. Tool failure and bit damage caused by vibration resulted in multiple bit runs. In order to reduce vibrations and improve drilling performance, bit gauge length has been systematically increased in 1-in. increments while utilizing a standard BHA. Partially tapered gauge was used in conjunction with the increased gauge length to allow directional control. This paper presents the results of progressing from a 4-in. non-tapered gauge bit to a 5-, 6-, and 7-in. partially tapered gauge bit from 2005 to 2009. Mechanical specific energy (MSE), vibration, rotary steerable wear, and directional response data is presented to show the impact of the incremental changes in gauge length over a group of seven wells. The tapered profile and increased gauge length provided comparable directional response with significantly improved drilling performance, resulting in multiple field record rates of penetration (ROPs) and bit run lengths.