Bit Record: IADC Dull Grading, Offset Well Analysis, and WCSB Drilling Optimization
A bit record (also called a bit log or bit run summary) is a chronological drilling document maintained throughout a well's drilling phase that captures, for every drill bit used in the well, the complete set of technical and operational parameters governing that bit's performance: bit identification (manufacturer, type, size, serial number, IADC code), run timing (depth in, depth out, total footage drilled, rotating hours), operating parameters (average and range of weight-on-bit in kN, rotary speed in RPM, surface flow rate in L/s, standpipe pressure in MPa, mud weight in sg, nozzle sizes), reason the bit was pulled out of hole (POOH) before or at planned depth, and the IADC dull grade that characterizes the physical condition of the bit's cutting structure and bearing system at the end of the run. The IADC dull grading system, published in the IADC Drilling Manual and based on the 8-element code standardized in 1987 with revisions through 2015, provides a universal language for describing bit wear that allows engineers from different companies and countries to compare bit performance from offset wells without ambiguity. The eight elements of the IADC dull grade are: (1) Inner cutting structure wear (0-8, where 0 is new and 8 is no cutting structure remaining); (2) Outer cutting structure wear (0-8); (3) Dull characteristics (B = broken, C = cracked, CC = chipped cutters, CT = cutter loss, ER = erosion, FC = flat cutters, HC = heat checking, JD = junk damage, LN = lost nozzle, PB = pinched bit, PN = plugged nozzle, RG = gauge ring, RO = rough outer surface, SD = shirttail damage, TR = tracking, WO = washed out); (4) Location of dull characteristic (N = nose, A = all, C = cone, G = gauge, M = middle, S = shirttail, T = taper); (5) Bearing condition (sealed bearings: E = seals effective, F = failed, N/A for PDC bits; open bearings: 0-8 scale); (6) Gauge condition (I = in gauge, O = out of gauge with loss in 16ths of an inch); (7) Other characteristics (same code list as element 3); (8) Reason pulled (BHA = bottom-hole assembly change, CP = core point, DMF = downhole motor failure, DP = drill pipe, HR = hours on bit, PP = pump pressure, PR = penetration rate, RIG = rig repair, TD = total depth, TQ = torque, TW = twist-off, WC = weather conditions). A complete bit record for a WCSB Montney horizontal well with 6 bit runs might fill a single landscape-oriented A4 page in the daily drilling report (DDR) and occupies a few kilobytes in the operator's drilling database. Its value, however, far exceeds its physical size: the bit record from one well becomes the primary source of formation-specific bit performance data for selecting bits on all future wells within the same geological block. In the WCSB, AER Directive 079 (subsurface data requirements) requires operators to submit bit records for all wells spudded in Alberta, with data loaded into the AER ST50 database that is accessible to all licensed operators for offset well planning. BCOGC (BC Oil and Gas Commission, now part of the BC Energy Regulator) maintains equivalent well record databases for BC Montney wells. Together, these public databases contain hundreds of thousands of individual bit run records spanning decades of WCSB drilling, forming the empirical foundation on which every WCSB drilling engineer designs the bit program for a new well — selecting the IADC codes and operating parameters that achieved the lowest cost per metre in the specific formation interval and geological area targeted by the new well.
Key Takeaways
- IADC dull grade interpretation for PDC bits in WCSB formations: For a PDC bit pulled from a Montney lateral, the most critical IADC dull grade elements are Inner and Outer cutting structure wear (elements 1 and 2) and the dull characteristic code (element 3). A grade of 3-5/CT/S indicates inner wear of 3/8 (moderate), outer wear of 5/8 (significant), Cutter Loss on the Shoulder area — a pattern consistent with hard abrasive stringer contact (Montney dolomite carbonate layers within the siltstone sequence) that shattered individual PDC cutters rather than causing uniform wear. A grade of 2-3/FC/A indicates minor wear with Flat Cutters across All areas, consistent with thermal wear from inadequate bottom-hole cleaning that overheated the PDC cutter tables beyond the 750°C diamond graphitization threshold. Both dull characteristics indicate different remediation: the CT/S pattern calls for a higher-impact-resistance cutter grade on the next run; the FC/A pattern calls for increased nozzle flow area or higher flow rate to improve cooling. The dull grade directly drives the next bit specification recommendation in the end-of-well well completion report.
- Cost per metre as the primary bit performance metric: The universal bit performance metric in WCSB drilling economics is cost per metre (C/m), calculated as: C/m = (B + R times T) / F, where B is bit cost (CAD), R is the rig rate (CAD/hour), T is the total time for the bit run including trip time (hours), and F is total footage drilled (m). For a Montney lateral run: bit cost CAD 30,000, rig rate CAD 750/hour, total time including trip in and out 60 hours, footage 2,350 m: C/m = (30,000 + 750 times 60) / 2,350 = (30,000 + 45,000) / 2,350 = CAD 31.9/m. Comparing this against an offset well with a cheaper bit (CAD 15,000) that required a mid-lateral round trip (trip time 12 hours) and drilled only 1,200 m before pullout: C/m = (15,000 + 750 times 72) / 1,200 = (15,000 + 54,000) / 1,200 = CAD 57.5/m. The premium bit is 44% cheaper per metre despite being twice the bit cost, because it eliminates the mid-lateral trip. This C/m calculation, extracted from the bit record, is the quantitative argument for premium bit specifications in WCSB horizontal well programs.
- AER Directive 079 bit record submission requirements: AER Directive 079 (Subsurface Data Filing and Submission Requirements) requires operators to submit bit records for all wells spudded in Alberta as part of the post-well data package, typically within 30 days of rig release. The required data fields for each bit run in the AER submission are: bit number, bit size, bit type (PDC, tri-cone), IADC code, manufacturer, serial number, depth in (m MD), depth out (m MD), footage drilled (m), rotating hours, nozzle sizes (in 32nds), average WOB (kN), average RPM, average flow rate (L/s), mud weight at TD (sg), reason pulled code, and all 8 IADC dull grade elements. This data is loaded into the AER's ST50 database and becomes publicly available to licensed well operators within 2-5 years of the well's license confidentiality expiry, contributing to the regional offset well database that all WCSB operators draw on for formation-specific bit selection. Non-compliance with Directive 079 submission timelines can result in AER warnings and ultimately license suspension under the Oil and Gas Conservation Act, making bit record documentation a regulatory as well as operational priority.
- Bit record analysis for formation-specific IADC code selection: Before designing the bit program for a new Montney horizontal well at Sunrise, BC, the drilling engineer queries the BCOGC (BC Energy Regulator) well data for all Montney horizontal wells within 15 km of the planned location, filters for intermediate and lateral bit runs in the Upper Montney siltstone target interval, and ranks the bit runs by cost per metre. The analysis might return 65 qualifying bit runs from 22 wells, identifying: (1) IADC code M433Y (matrix PDC, medium cutter, medium parabolic profile, extra-long gauge) achieves an average C/m of CAD 28-35/m in Upper Montney laterals; (2) code M532X (higher cutter density, longer gauge) achieves CAD 38-45/m; (3) roller cone TCI runs (IADC 5-1-7 in the harder Lower Montney carbonate stringers) achieve CAD 55-65/m. From this analysis, the engineer specifies M433Y as the lateral bit specification, confirming the cutter grade and profile against the top 10 performing runs in the database. This evidence-based bit selection process, grounded entirely in the bit record data from offset wells, is the standard WCSB practice that allows lateral bit runs to be optimized in advance rather than through trial and error on the well being drilled.
- Real-time bit performance monitoring during drilling: While the formal bit record is completed post-run, real-time bit performance monitoring during drilling uses the same parameters: ROP versus depth (detecting formation changes and bit wear), standpipe pressure trends (detecting nozzle erosion), torque-on-bit from surface measurement or downhole from MWD (detecting stick-slip and vibration), and WOB efficiency (detecting balling where WOB increases but ROP doesn't respond). The on-site drilling engineer or real-time operations centre (RTOC) in Calgary or Edmonton logs these parameters continuously and flags anomalies that indicate early bit wear. The MSE (mechanical specific energy) calculated in real time provides the comprehensive indicator: rising MSE at constant WOB and RPM indicates bit wear or vibration, triggering the bit run extension-or-pull decision. The real-time data logged during the run is archived and becomes the continuous record underlying the simplified bit run summary that appears in the formal bit record at the end of the run, providing the engineering team with full resolution drilling data for forensic analysis of bit performance issues.
Bit Record Analysis: Optimizing a Multi-Well Montney Pad Program
An operator drilling a 10-well Montney pad at Progress, Alberta pulls all bit records from the AER ST50 database for the formation interval 2,600-3,200 m MD (Upper and Middle Montney target) within a 10 km radius of the planned pad location, returning 78 qualifying bit runs from 24 offset wells. Statistical analysis of the 78 runs: mean cost per metre CAD 38.2, standard deviation CAD 12.5, 10th percentile C/m CAD 22.4, 90th percentile C/m CAD 55.8. Top 10 performing runs (all below CAD 25/m) share three characteristics: IADC code M433Y, flow rates above 30 L/s, and average WOB between 50-70 kN. Bottom 10 performing runs (above CAD 52/m) include 6 mid-lateral round trips (bits pulled short of planned TD due to gauge loss or excessive vibration), all associated with either IADC M532X (higher cutter density, more susceptible to cutter loss in harder Montney stringers encountered at this specific geographic location) or with WOB above 90 kN (inducing bit whirl in the harder intervals). Recommendation: specify M433Y at 50-70 kN WOB and 30-32 L/s as the standard for all 10 wells. Expected C/m improvement versus the 78-well average: approximately 35% (from CAD 38.2 to approximately CAD 25/m), corresponding to a total bit program cost saving of approximately CAD 180,000-220,000 across the 10-well pad relative to an average-performing bit specification.
Post-Mortem Bit Record Review: Devonian Exploration Well
After completing a 3,200 m Devonian carbonate exploration well near Bashaw, Alberta, the drilling team compiles the formal bit record and reviews performance against the prognosis. The bit record shows 6 bit runs totaling 3,200 m drilled in 18 rotating days. Bit 1 (surface, 444 mm PDC): 250 m, 18 hours, C/m CAD 18, IADC dull 1-2/WT/N, reason pulled TD section. Bits 2-3 (311 mm PDC, intermediate): 1,200 m combined, 42 hours, C/m CAD 32 average, both showing 3-4/CT/S dull grades from chert stringers at 900-1,100 m (requiring one unplanned round trip, costing 14 hours at CAD 28,000/day = CAD 16,300 of unbudgeted rig time). Bit 4 (222 mm PDC, production section upper): 850 m, 58 hours, C/m CAD 38, dull grade 4-5/ER/G from Cretaceous shale gas erosive mud contamination at 1,800-2,100 m. Bit 5 (222 mm TCI roller cone, Devonian carbonate): 480 m, 82 hours, C/m CAD 58, dull grade 5-6/WT/G from hard Devonian limestone. Bit 6 (222 mm PDC re-run, Leduc reef): 420 m, 36 hours, C/m CAD 28, dull grade 2-3/FC/A, good performance in the softer reef carbonate.
Post-mortem action items from the bit record review: (1) add one planned TCI roller cone run at the top of the chert stringer interval (1,000 m) on the next well, eliminating the unplanned round trip that cost CAD 16,300; (2) specify a harder cutter grade PDC for the Cretaceous section (Bits 2-3) to reduce the CT/S failure mode from chert contacts; (3) the TCI roller cone in the Devonian limestone section is confirmed as the correct selection but ROP of 5.9 m/hour is slow enough that the bit cost (CAD 14,000) versus equivalent bit run hours in PDC is marginal — test a grade 6-1 TCI versus the current 5-1 on the next well to assess ROP sensitivity to bearing and insert grade in the specific Devonian limestone hardness range at this location. These three action items, grounded entirely in the quantitative bit record data, form the drilling optimization inputs for the next exploration well AFE in the same geological block.