Bit Trip: When to Pull the Bit and What the Round Trip Actually Costs
A bit trip (also called a round trip or simply a trip) is the complete operation of pulling the entire drill string from the wellbore to surface to inspect or replace the drill bit, then running the string back to bottom with the new or inspected bit — one of the most time-consuming and costly non-productive activities in any drilling program, because every stand of drill pipe (each stand typically 27-30 m of three connected joints) must be handled twice: once when pulling out of hole (POOH) as each stand is broken out, lifted by the traveling block, and racked in the derrick fingers, and once when running in hole (RIH) as the reverse process returns the string to bottom. Trip time scales almost linearly with well depth: a 3,000 m well with 27 m stands requires handling approximately 111 stands POOH and 111 stands RIH (222 stands total), with each stand requiring 2-4 minutes to handle on a modern WCSB top-drive rig — giving a total trip time of approximately 7-15 hours including the time to lay down the BHA and pick up the new bit sub and BHA components. At a WCSB rig day rate of CAD 25,000-40,000 per 24-hour day, a 10-hour bit trip costs CAD 10,400-16,700 in rig time alone, before the cost of the new bit (CAD 8,000-35,000 for a PDC bit depending on size and cutter grade). The critical economic decision in every WCSB drilling program is therefore the bit trip decision criterion: should the current bit run be extended (continuing to drill with the existing bit, accepting lower ROP from wear) or should a round trip be made now (incurring the trip cost to restore the higher ROP of a fresh bit)? The quantitative criterion is the cost-per-metre (C/m) calculation comparing the current bit's projected forward performance against the C/m of a new bit including the trip cost: C/m_continue = R times T_remaining / F_remaining; C/m_trip = (B_new + R times T_trip + R times T_new_run) / F_new_run. When C/m_continue exceeds C/m_trip, the optimum economic decision is to make the trip immediately; continuing to drill past this crossover point increases total well cost. This calculation is performed in real time on WCSB wells by the drilling engineer or company representative using MSE (mechanical specific energy) monitoring software and ROP trend data from the drilling data acquisition (DAQ) system, with the MSE trend providing an objective indicator of bit wear independent of the driller's experience-based assessment. In horizontal Montney and Duvernay wells where the lateral section can exceed 3,000 m, bit trip decisions are particularly consequential: a mid-lateral round trip adds 14-18 hours of trip time for a 3,500 m MD well (approximately CAD 14,500-30,000 in rig time), motivating the use of premium PDC bits capable of drilling the entire lateral without a trip — even at a bit cost premium of CAD 15,000-20,000 over a standard PDC bit — because the single-trip economics are favourable if the premium bit eliminates one round trip in a long lateral section. AER Directive 059 (well drilling and completion) does not specify bit trip procedures, but the well completion report submitted under Directive 079 must include a complete bit record documenting all bit trips with depth in, depth out, footage, hours, and dull grade, providing the AER with the complete drilling history of each well for subsurface data purposes.
Key Takeaways
- Cost-per-metre calculation for trip decision timing: The quantitative bit trip decision model compares the forward C/m of continuing with the worn bit versus the C/m of tripping and running a new bit. For a Montney horizontal well with worn PDC bit drilling at 8 m/hour (down from 20 m/hour when new), 800 m remaining to TD: C/m_continue = (CAD 28,000/day times 100 hours) / 800 m = CAD 145/m (assuming no further ROP decline). C/m_trip and re-drill = (CAD 30,000 new bit + CAD 28,000/day times 16 hours trip time + CAD 28,000/day times 40 hours re-drill at 20 m/hour) / 800 m = (30,000 + 18,667 + 46,667) / 800 = CAD 119/m. The trip is economically justified (CAD 119/m vs CAD 145/m) whenever the worn bit ROP is below approximately 55% of fresh bit ROP and more than 600 m of lateral remains. This calculation, run in real time using the current ROP trend and projected trip time, is the primary tool WCSB drilling engineers use to time mid-lateral bit trips optimally.
- IADC dull grade criteria for planned bit trips: Beyond the economic model, planned bit trips are triggered by specific IADC dull grade criteria established in the well's bit program before drilling begins. Common pull criteria in WCSB Montney horizontal programs include: inner row wear (IADC element 1) above 5/8 (indicating more than 62.5% of inner cutter height lost, signaling the bit can no longer drill effectively in the siltstone); gauge loss above 3/16 inch (indicating undersized hole that may prevent casing from reaching TD); and specific dull characteristics such as LN (lost nozzle, indicating a nozzle has been ejected from the bit body, reducing hydraulics to approximately 67% of design and causing poor bottom-hole cleaning). The IADC dull grade at pullout is assessed by the bit company representative and the company drilling supervisor on the rig floor immediately after the bit arrives at surface, before the bit box is closed, and the grade is recorded in the real-time well reporting system that feeds the AER Directive 079 post-well submission.
- Managed pressure drilling to reduce trip frequency: Managed pressure drilling (MPD), used in WCSB wells with narrow pressure windows (typical Montney margin 0.10-0.20 sg between pore pressure gradient and fracture gradient), reduces bit trip frequency by maintaining precise ECD control that prevents unplanned trips caused by lost circulation events or kicks. In a conventional drilling scenario where a kick or mud loss at the toe of a Montney lateral forces an unplanned trip to POOH with the drill string and re-evaluate the wellbore before continuing, the unplanned trip costs CAD 14,000-22,000 in rig time and potentially requires barite addition and mud density adjustment before re-entry. MPD systems (rotating control devices, automated choke manifolds) that hold backpressure on the annulus during connections eliminate the ECD swing that causes unplanned fluid events, reducing unplanned trips to near zero in successful MPD applications at the cost of approximately CAD 2,500-4,500 per day in MPD service charges — a favorable exchange when unplanned trip frequency without MPD exceeds one per well program.
- Trip time measurement and rig benchmarking: Trip time is a key rig efficiency metric tracked in the WCSB drilling industry through standardized time classification systems (most commonly the IADC Well Classification System or company-specific drilling performance reporting). Trip speed is expressed as metres per hour (m/hour) for POOH and RIH, with best-practice benchmarks for a top-drive rig on a WCSB Montney horizontal well of approximately 550-700 m/hour POOH (in the lateral section) and 450-600 m/hour RIH. Below-benchmark trip times indicate rig efficiency issues: slow pipe handling, high friction in the horizontal lateral section requiring pipe rotation during tripping (reducing trip speed from 600 to 300-400 m/hour), or excess rig crew size causing confusion in stand handling. A rig operating at 300 m/hour trip speed versus 600 m/hour benchmark adds approximately 5 additional hours per round trip at 3,000 m well depth, costing CAD 5,800-8,750 in extra rig time per trip — a systematic inefficiency that accumulates to CAD 50,000-100,000 of excess cost across a 10-well pad program if the root cause (friction, crew coordination, equipment limitation) is not identified and corrected.
- Dry trip versus wet trip: well control implications: A dry trip pulls the drill string from a wellbore that has been filled with heavy mud (mud weight sufficient to overbalance the formation pore pressure without any annular circulation), while a wet trip pulls through a wellbore where the string displacement causes the mud level to drop unless additional mud is pumped in to fill the hole. All WCSB wells with overbalanced mud programs use wet trip procedures: as each stand is lifted out of hole, the derrick man signals the mud engineer to pump the exact displacement volume of mud (pipe displacement volume per stand) to maintain the full mud column in the annulus. AER Directive 083 (well control) requires that all wells be tripped in a controlled manner with the wellbore maintained full of mud at all times during POOH operations, with a trip monitoring log (record of mud volume added to the hole versus theoretical pipe displacement) completed and signed by the company representative and driller for every bit trip. Failure to maintain the mud column during a trip is the most common cause of formation influx events (kicks) that can lead to well control incidents in WCSB drilling operations.
Mid-Lateral Bit Trip Decision: Montney Horizontal Well Economics
A Montney horizontal well at Progress, Alberta is drilling in the lateral section at 3,180 m MD (780 m from the planned TD of 3,960 m). The 178 mm (7 inch) PDC bit entered the lateral at 2,200 m MD (980 m ago). Current ROP: 9 m/hour, down from 22 m/hour at lateral entry. MSE trend is rising, now 45% above the baseline MSE established in the first 200 m of the lateral — indicating significant bit wear. The drilling engineer runs the trip decision calculation: C/m_continue = (CAD 28,000/day / 24 hours) times (780 m / 9 m/hour) / 780 m = CAD 130/m. C/m_trip-and-redrill = (CAD 32,000 new premium bit + CAD 28,000/day times (16 hours trip time) + CAD 28,000/day times (35.5 hours to drill 780 m at 22 m/hour)) / 780 m = (32,000 + 18,667 + 41,333) / 780 = CAD 118/m. The trip is economically justified. Decision: POOH immediately. Total trip time actual: 14.5 hours (rig had some friction in the lateral section requiring rotation while tripping, reducing POOH speed to 270 m/hour versus 550 m/hour benchmark). New bit runs the final 780 m in 36.5 hours at an average 21.4 m/hour. Actual C/m for the trip decision: (32,000 + 28,000/24 times 51 hours) / 780 = (32,000 + 59,500) / 780 = CAD 117/m versus the pre-decision estimate of CAD 118/m — near-perfect pre-trip economic prediction.
Trip Efficiency Optimization on a WCSB Multi-Well Pad
A drilling contractor operating a 750-hp top-drive rig on a 6-well Montney pad at Sunrise, BC benchmarks trip speed performance across the 6 wells. Average POOH speed in the lateral section (2,200-4,200 m MD): 380 m/hour versus 550 m/hour design benchmark. Root cause analysis identifies two contributors: (1) high rotational drag in the lateral section requires pipe rotation at 10-15 RPM while pulling, reducing effective trip speed from 600 to 380 m/hour; (2) the rig's manual pipe-handling system requires a 45-second pause between each stand pickup versus the 25-second design cycle on the rig specification sheet. For a 4,200 m MD well with 27 m stands, the POOH time is: (4,200 / 27) times 45 seconds per stand = 155.6 stands times 45 seconds = 6,999 seconds = 116 minutes (just for stand breaks, excluding actual pipe lifting time) versus 155.6 times 25 seconds = 64.8 minutes. The 51-minute per-trip delay from the manual handling inefficiency costs approximately CAD 994 per trip (51 minutes at CAD 28,000/day). Across 6 wells with an average 2.5 trips per well = 15 trips total, the cost is approximately CAD 14,900 in excess rig time. Recommendation: upgrade the rig's pipe-handling arm to automated stand pickup (CAD 85,000 capital) would recover the investment within 6 pad programs (90 wells) at similar trip frequency — a maintenance item flagged for the next scheduled rig maintenance window between the current pad and the next pad program at an adjacent lease.
Fast Facts
The cost of round trips in deep wells was already recognized as a dominant drilling expense by the earliest systematic studies of well costs in the 1920s and 1930s, when cable tool and early rotary drilling rigs required 8-12 hours to trip a 1,500 m well with manila rope and mechanical drawworks. The introduction of the top-drive rig in the 1980s reduced average trip time for a 3,000 m well from approximately 24 hours (with a rotary swivel rig requiring a full crew making up and breaking out individual joints) to approximately 10-14 hours by allowing the driller to rotate the string continuously while tripping, eliminating differential sticking and reducing friction-related delays that were endemic to 1970s rotary rig practice. The further reduction in bit trip frequency from premium PDC bits capable of drilling 2,000-3,000 m without a bit change is estimated to have saved the WCSB drilling industry approximately CAD 400-600M cumulatively between 2010 and 2025 by eliminating mid-lateral round trips that were routine on the roller cone and early-generation PDC bits used before ultra-compact cutter technology became standard.