Operator drilled section to TD and connected all targets despite extreme difficulties encountered in this complex wellbore
By Son Bui, Thang Long Joint Operating Company; Ngo Huu Hai, Petrovietnam Exploration Production Corp; Nam Nguyen, Geoff Blackwell and Jake Tretheway, National Oilwell Varco
Thang Long Joint Operating Company (TLJOC) was operating a well in the Cuu Long Basin offshore Southern Vietnam and needed to more effectively drill through a difficult section. Granitic basement drilling, where the formation is very hard (35 to 40 kpsi UCS), presented major challenges, as PDC cutters could not drill through the formation, very high levels of vibration were encountered, and rate of penetration (ROP) was limited.
Despite the inherent risk of drilling such a well, TLJOC planned an 8½-in., 3,217-m, 3D horizontal granite section with three distinct objectives: build inclination from 20° to 85.6° at a dogleg severity (DLS) of 3.65°/30 m, hold the lateral and turn from 62° to 14.3° azimuth. These targets had to be accomplished while drilling to total depth (TD) at 6,280-m measured depth (MD).
The traditional method of drilling the granite section in Vietnam is using a downhole bent motor, 8 ½-in. roller cone bit, and a reliable, simple MWD tool to take surveys and measure vibrations. Issues with using this bottomhole assembly (BHA) configuration include increases in torque and drag, poor toolface control and weight transfer to the bit, low ROP, premature bit failure, and risk of a lost cone incident. High vibration levels, however, typically result in high electronic tool failure rates, and total loss of circulation when drilling in the fractured reservoir limits the positive effect of mud lubricant on torque and drag.
To efficiently solve these problems, Agitator systems from National Oilwell Varco (NOV) can be placed in the BHA to reduce friction via axial oscillation. This article explores using a single Agitator system or dual Agitator systems in the BHA to reach planned TD and discusses how the BHAs were optimized for each bit run using lessons learned from earlier runs during the well.
Project Analysis, Planning
The two curves, including a 538-m build section and 466-m turn section, as well as the total length of the section, would make this the most challenging basement ever drilled in Vietnam. Weight on bit (WOB) had to be set at 40 to 45 klbf to efficiently drill the 8 ½-in. hole in granite. This relatively high WOB, combined with the complex well path, resulted in the neutral point being higher in the drill pipe, with all the BHA and some of the drill pipe in compression. Designing BHAs that were light enough to minimize torque and drag but stiff enough to minimize string buckling became the most challenging task as a result.
After researching the longest extended-reach drilling (ERD) basement well (Well 1) drilled in recent years, NOV and TLJOC determined that friction factors, torque and drag, and string buckling when drilling in the basement section were critical. Heavy string components, like heavy-weight drill pipe or drill collars, would not provide more WOB but rather increase the drag, which would cause more problems during drilling.
Despite knowing this, heavy-weight drill pipe had to be used somewhere in the string to minimize buckling. As it was the lightest BHA with the lowest drag, a BHA with 5½-in. drill pipe was used for analysis to identify buckling zones, help determine the severity of the subject well, and study how to optimize the BHAs to reach TD. After this, additional torque and drag modeling – with 5½-in. heavy-weight drill pipe in the BHA at areas of high buckling risk – was carried out, with and without the Agitator system, to verify if the section could feasibly be drilled while achieving the objectives.
The torque and drag model was built for Well 1 using actual drilling parameters, well trajectory and BHA configuration, which included one Agitator system. Analysis determined that Well 1 could be drilled with friction factors of 0.26 and 0.3 for the cased hole and open hole, respectively, and that the well could be directionally drilled to TD using one Agitator system in the BHA, the string in sinusoidal buckling during slide-drilling, and total accumulative slide-drilling drag up to 138 klbf at TD.
The subject well would be significantly more difficult than Well 1, as increases in slide-drilling drag and worse string buckling, particularly in two high-risk zones, were observed. These zones were immediately above the curve sections, with the first from 2,837- to 3,065-m MD and the second above the curve at 2,851-m MD. As the high-risk buckling zones did not move as the well was drilled deeper, the BHA was optimized by adding 200 m of heavy-weight drill pipe at the first high-risk zone and 350 m of extra pipe to ensure that the buckling risk zone was covered through the bit run.
Using the optimized BHA resulted in a large reduction in the buckling ratio, but the drag value remained high, especially when the buckling state was transitioning from sinusoidal to helical from 5,700-m MD to TD. Adding an Agitator system helped reduce drag and improved the string buckling state.
When slide-drilling reaches 60 to 70 klbf, it is difficult to control toolface when slide-drilling ahead. Based on this knowledge, the Agitator system would be beneficial around 3,600-m MD to help reduce drag and, importantly, maintain consistency in that drag value. The drag value would be easily offset by zeroing the WOB prior to tagging bottom for drilling ahead.
There were two high-drag zones, one from the bit to approximately 200 m above it, and one at the build section from 3,100- to 3,600-m MD. Although placing an Agitator system at the build section would have reduced the total drag value, it would not have reduced drag at the horizontal section to the bit. As such, the Agitator system should be placed closer to the bit to reduce drag in that zone, which would result in decreased compressive force and a smaller buckling ratio at the horizontal drill pipe section.
Placing the Agitator system closer to the bit would also provide extra axial force to the roller cone insert bit, improving the rock-failure mechanism by compression and thereby increasing ROP.
Based on TLJOC’s past work, the applied WOB should be increased to 50 klbf to maximize bit performance. Torque and drag modeling was done for this WOB value to see how it compared with the WOB of 35 klbf. Slide-drilling drag increased by 30 klbf, and string torque increased by 2,300 ft-lbf, with an acceptable buckling state, and modeling confirmed that drilling to TD was still achievable even at the increased WOB value.
Planning also anticipated that the real well’s drilled trajectory would encounter higher levels of tortuosity versus that seen in the software analysis because the well path correction would not be as smooth when directional drilling with a bent motor.
Additionally, much higher torque and drag could be encountered versus that of the model. A second Agitator system was prepared in case drilling conditions dictated that it would be required in the high-drag concentration zone. The prediction was that the BHAs with dual Agitator systems would be required from 5,400-m MD.
The strategy to optimize the BHAs was strictly followed in the field, and torque and drag analysis was conducted after each run. These results were used to help optimize performance on subsequent runs, informing TLJOC whether an Agitator system would be necessary. The first three BHAs were run without the Agitator system, and lubricant was added to the brine mud to help reduce friction.
The torque and drag model predicted that BHA four would encounter slide-drilling drag up to 67 klbf, and NOV recommended adding an Agitator system to prevent any issues. A single Agitator system was run as part of the next five runs, and TLJOC encountered no problems with slide-drilling during this time. Toolface control was excellent, and the friction factor was maintained between 0.1 and 0.2 in runs four, five and six.
Considering the compressive strength of the rock, the overall complexity of the well, and the downhole drilling conditions encountered from the first through the sixth run, it was important for TLJOC to understand quantifiable performance metrics of using the Agitator system. ROP when using the tool was 26.2% higher than without it, and 26.7% longer intervals were drilled when using the system.
Runs seven, eight and nine were problematic. In the seventh run, a total loss was encountered, with a concurrent increase in off-bottom torque of 90% and increase in slackoff drag of 160%. In addition, the friction factor increased to 0.3. According to the model, slide-drilling in these conditions would be extremely difficult, with drag predicted to increase up to 155 klbf, and the string would enter helical buckling in run eight, even with an Agitator system in the BHA. At approximately 4,950-m MD on the eighth run, poor sliding ROP had effectively stopped progress, and TLJOC decided to rotate drill until the end of bit life. This caused the well path angle to drop and turn to the left.
A motor BHA with a rotary steerable system (RSS) was used in the ninth run to see if the well path could be corrected, but the BHA continued to drop angle and turn to the left. In the 10th run, dual Agitator systems were used, with the main objective being to steer the well back to the planned target. Based on the model, the second Agitator system was placed at the horizontal turn section to reduce friction at that zone. As a result, the BHA was able to steer the well back to the target.
This run was the longest bit run in the basement section of the field, at 505 m. Torque spikes near the end of the run caused the bit to be pulled with three cones left in the hole, and post-run analysis revealed an excessively high WOB of 90 klbf, which was the suspected cause.
Through the 11th, 12th and 13th runs, dual Agitator systems were continuously used. Cones left in the hole were milled out, and the BHA continued to drill ahead while correcting the well path when required. There were no problems while slide-drilling. Motor RSS BHAs were used to drill to TD on the 14th and 15th runs, as there were no more bent motors available on the rig. As suspected after use of the earlier motor RSS BHA, in these runs the well path dropped angle and turned left.
TLJOC achieved all three objectives set at project initiation while drilling the longest and most directionally challenging basement section ever in Vietnam. The company drilled the section to TD and connected all the targets despite the extreme difficulty of drilling such a complex and challenging well due to the robust BHA optimization methodology and use of the Agitator systems for axial oscillation and friction reduction.
Drag was significantly reduced when the Agitator system was in the BHA through better toolface control. It was possible to drill a longer well, and the planned trajectory was more easily achieved. Further, having the Agitator system in the string improved drill bit performance, including increases in ROP and extended bit life on the longer interval.
With regards to project economics, the overall actual drilling operation time was 21% shorter (9.6 days saved) compared with the planned time, representing cost savings of 35.42% below AFE in offshore operation.
After researching the longest extended-reach drilling basement well drilled in recent years, NOV and TLJOC determined that friction factors, torque and drag, and string buckling when drilling in the basement section were critical.
Continuing to champion innovative and highly technical solutions will facilitate drilling of other such complex, long sections through challenging lithologies to connect multiple pay zones in the future. DC
This article is based on SPE 191872, “Axial Oscillation Tool Combined with Optimized Bent Motor BHAs Successfully Drills Record 3D Horizontal Granitic Basement Section in Vietnam,” presented at the SPE Asia Pacific Oil & Gas Conference and Exhibition, 23–25 October 2018, Brisbane, Australia.
Agitator is a trademark of National Oilwell Varco.