A pulled bit is the only direct evidence of what happened at the bottom of the hole. The IADC dull grade turns that evidence into eight short codes that the next engineer can read, sort and compare. This article grades the PDC bits of an 8½″ section in hard, abrasive sandstone cutter by cutter, works out what each run cost per metre, asks whether the worn bit came out at the right time, and shows how the dulls choose the bit for the next well.
What the IADC dull grade records
The IADC dull grading system describes a pulled bit in eight positions. The first four describe the cutting structure, the next two the bearings and the gauge, and the last two any other wear and why the bit came out. The same scheme covers roller-cone and fixed-cutter bits; only some of the codes change. Here is the grade of the worn PDC in this article, position by position:
| Position | What it records | Bit 2 |
|---|---|---|
| 1. Inner rows | Wear of the cutters in the inner two-thirds of the bit radius, 0 (none) to 8 (no cutting structure left) | 2 |
| 2. Outer rows | The same for the outer third | 4 |
| 3. Dull characteristic | The main kind of damage | BT, broken cutters |
| 4. Location | Where it is: cone, nose, taper, shoulder, gauge or all areas on a fixed-cutter bit | S, shoulder |
| 5. Bearings and seals | Roller-cone bearings; X for a fixed-cutter bit | X |
| 6. Gauge | I for in gauge, otherwise how far under gauge in sixteenths of an inch | 1/16 |
| 7. Other dull characteristic | A second kind of damage, or NO | WT, worn cutters |
| 8. Reason pulled | Why the run ended: TD, PR (penetration rate), FM (formation change), a tool failure and so on | PR |
So 2-4-BT-S-X-1/16-WT-PR reads: light wear in the middle of the bit, heavy wear on the outside, broken cutters on the shoulder, 1/16″ under gauge, worn cutters elsewhere, pulled because it had slowed down. Every position should be filled; a code with gaps cannot be sorted or compared.
Grading a PDC bit cutter by cutter
The two row numbers are averages, and an average is only as good as the cutters behind it. Eyeballing a bit and calling it a 2-4 hides how the wear is spread. The reliable way is to grade every cutter on a map: blades across, cutter positions from the centre to the gauge, each cutter 0 to 8 by how much of its diamond table is gone. A cutter worn halfway down is a 4; a cutter broken off at the substrate is an 8. The inner row is the mean of the cutters in the inner two-thirds of the radius, the outer row the mean of the rest, each rounded to a whole number.
The map gives more than the two numbers. Its shape says where the bit worked hardest. Cutters on the shoulder travel far on each revolution and remove the most rock, so in abrasive rock wear usually peaks there. Wear at the cone points to a centre problem such as coring or junk. Uneven wear from blade to blade suggests the bit ran off centre, as it does in whirl.
The example well
The example is the vertical gas well from the MSE article, set in conditions typical of the Cooper Basin, Australia. Its 8½″ section drilled soft Cretaceous to Triassic rock, then the Permian coal measures, whose silica-cemented sandstones are hard (CCS around 25 kpsi) and abrasive. Three PDC bits drilled the section. Two offset wells add three more runs through the same Permian rock, with two other designs.
| Run | Bit | Depth (m) | Metres, hours | ROP (m/h) | Dull grade |
|---|---|---|---|---|---|
| Bit 1 | PDC M223, 6 blades, 16 mm | 1,050–2,560 | 1,509.5 m, 54.3 h | 27.8 | 1-1-CT-S-X-I-NO-FM |
| Bit 2 | PDC M333, 7 blades, 13 mm | 2,560–2,985 | 425 m, 30.8 h | 13.8 | 2-4-BT-S-X-1/16-WT-PR |
| Bit 3 | PDC M333, 7 blades, 13 mm | 2,985–3,150 | 165 m, 10.5 h | 15.8 | 1-2-WT-S-X-I-NO-TD |
| Offset 1 | PDC M223, 6 blades, 16 mm | 2,540–2,712 | 172 m, 19.5 h | 8.8 | 3-6-LT-S-X-2/16-BT-PR |
| Offset 1 | PDC M333, 7 blades, 13 mm | 2,712–3,105 | 393 m, 29.0 h | 13.6 | 2-3-WT-S-X-I-CT-TD |
| Offset 2 | Impregnated diamond on a turbine | 2,575–3,120 | 545 m, 104 h | 5.2 | 1-1-WT-A-X-I-NO-TD |
Bit prices are US$28,000 for the six-blade PDC, US$34,000 for the seven-blade and US$62,000 for the impregnated bit, which leaves out the turbine's rental. The rig and spread cost US$48,000 a day, US$2,000 an hour. A round trip takes 3 hours of handling plus the depth out and back at 400 m/h. The metres and hours of this well's runs are the ones DrillIQ measured from the depth log, on bottom only.
A hand check of bit 2's rows
Bit 2 has 7 blades with 10 cutter positions each; positions 1 to 6 sit in the inner two-thirds of the radius.
- Inner rows. The 42 inner cutters' grades add up to 69. 69 / 42 = 1.64, which rounds to 2.
- Outer rows. The 28 outer cutters add up to 125. 125 / 28 = 4.46, which rounds to 4.
- The shoulder. Position 8 on the seven blades graded 6, 7, 6, 8, 5, 6 and 6: a mean of 6.3, with one cutter gone completely.
- Outcome. An outer row of 3 to 5, broken cutters or a gauge 1/16″ to 3/16″ under each make a bit worn, needing repair before it runs again. Bit 2 has all three.
DrillIQ's grading engine gives the same rows from the same map, 1.64 and 4.46, and reads the outcome as worn for the same three reasons.
Reading the dull of bit 2
- Bit 2, 2-4-BT-S-X-1/16-WT-PR
- Bit 3, 1-2-WT-S-X-I-NO-TD
- Zone average (IADC inner and outer rows, rounded half up)
Each cutter graded 0–8 on the example's cutter maps (7 blades × 10 positions, inner rows = positions 1–6). Rows from DrillIQ's Bit Performance & Grading engine (cutter_map.rows).
Show the data
| Position | Bit 2, pulled for ROP | Bit 3, pulled at TD |
|---|---|---|
| 1.0 | 0.57 | 0.00 |
| 2.0 | 1.00 | 0.43 |
| 3.0 | 1.29 | 1.00 |
| 4.0 | 2.00 | 1.00 |
| 5.0 | 2.14 | 1.00 |
| 6.0 | 2.86 | 1.00 |
| 7.0 | 4.43 | 2.00 |
| 8.0 | 6.29 | 2.57 |
| 9.0 | 4.71 | 2.00 |
| 10.0 | 2.43 | 1.14 |
Both seven-blade bits have the same shape: little wear at the centre, a peak at position 8 on the shoulder, less at the gauge. That is the shape abrasion gives a PDC in uniform hard rock, and on bit 3 it stays mild because bit 3 stopped at TD after a third of the work. Measured as WOB times revolutions, bit 3 did 2.27 million klbf·rev against bit 2's 6.88 million, 33 %.
Bit 2's shoulder is worse than wear alone explains. Broken cutters (BT) are impact damage: a cutter that is hammered rather than dragged across the rock. The MSE article shows where that came from. Bit 2 started its run at 28 klbf and 110 rpm, above its founder point, and spent its first 82 m in stick-slip, where the bit stalls and then whips forward. The step tests at 2,642 m fixed the parameters, but the shoulder had already been damaged, and damaged cutters wear faster. The rise in MSE over the last 130 m was that shoulder wearing out: at the same weight and speed, the engine reads MSE 29.5 % higher in the last third of the run than in the first.
The gauge matters for the next bit. A bit 1/16″ under gauge leaves the bottom of the hole slightly undersize, so the next bit should ream the last stand to bottom rather than be run straight onto it. The offset's six-blade M223 shows where this goes if nobody stops: an outer row of 6, lost cutters on the shoulder and 2/16″ under gauge after only 172 m. Six blades with larger cutters put fewer cutters on the shoulder to share the load, and in this rock each one failed in turn.
Cost per metre
A dull grade says what state the bit is in; cost per metre says whether the run paid. The standard form charges the bit, the rig time on bottom and the trip to the metres drilled:
CPM = [ B + Cr (t + T) ] / F
T = Th + 2 D / vtrip
- B
- bit cost, US$
- Cr
- rig and spread rate, US$/h
- t, T
- hours on bottom, and round-trip hours
- F
- metres drilled
- Th, D, vtrip
- handling hours per trip, depth out (m) and tripping speed (m/h)
For bit 2: T = 3 + 2 × 2,985 / 400 = 17.93 h. The rig cost is 2,000 × (30.82 + 17.93) = US$97,500, plus the US$34,000 bit, over 425 m: US$309 per metre. The engine gives US$309.41.
- Worn
- Re-runnable
- Damaged
Cost per metre = (bit + rig rate × (hours on bottom + trip)) ÷ metres, every run on this well's basis: US$2,000/h, trip 3 h + 2 × depth out ÷ 400 m/h. Outcome from each dull grade. DrillIQ's cost and outcome engines.
Show the data
| Worn | Re-runnable | Damaged | |
|---|---|---|---|
| Bit 2, PDC M333, 425 m | 309 | ||
| Bit 3, PDC M333, 165 m to TD | 560 | ||
| Offset 1, PDC M333, 393 m | 328 | ||
| Offset 1, PDC M223, 172 m | 582 | ||
| Offset 2, impregnated, 545 m | 564 |
Costed on one basis, the seven-blade M333 is the clear choice for this rock. Its two full runs cost US$309 and US$328 per metre. The impregnated bit lasted longest and came out re-runnable, but at 5.2 m/h its 104 hours on bottom cost more than the bit itself, and it lands at US$564. The six-blade M223 was both slow and destroyed: US$582.
Bit 3 shows the trap in the formula. At US$560 it looks as poor as the failures, yet it drilled faster than bit 2 and came out nearly new. It drilled only the last 165 m to TD and still carries a full round trip and a full bit price. Compare runs of similar length, or treat the run to TD separately, before reading anything into its cost.
When to pull: the running cost per metre
The classic pull rule watches two numbers as the run goes on: the cost per metre to date, with a trip from the current depth, and the cost of the next metre, which is the rig rate divided by the ROP. While the next metre is cheaper than the average so far, each metre drilled lowers the average and the bit should stay in.
- Cost per metre to date (bit, rig time, trip from that depth)
- Cost of the next metre: rig rate × hours per metre, 5 m steps
Metres and hours at each depth from ROP Optimisation's duty measurement on the example's depth log; cost from Bit Performance & Grading's cost engine on the basis above.
Show the data
| Depth | Cost per metre to date | Cost of the next metre (rig rate ÷ ROP) |
|---|---|---|
| 2,660 | 846 | |
| 2,665 | 812 | 128 |
| 2,670 | 781 | 124 |
| 2,675 | 753 | 116 |
| 2,680 | 727 | 120 |
| 2,685 | 703 | 116 |
| 2,690 | 681 | 132 |
| 2,695 | 661 | 120 |
| 2,700 | 642 | 128 |
| 2,705 | 623 | 84 |
| 2,715 | 601 | 93 |
| 2,720 | 575 | 120 |
| 2,725 | 562 | 116 |
| 2,730 | 549 | 116 |
| 2,735 | 537 | 124 |
| 2,740 | 526 | 120 |
| 2,745 | 516 | 136 |
| 2,750 | 506 | 128 |
| 2,755 | 496 | 128 |
| 2,760 | 487 | 136 |
| 2,770 | 469 | 80 |
| 2,775 | 461 | 84 |
| 2,780 | 452 | 113 |
| 2,785 | 445 | 124 |
| 2,790 | 438 | 124 |
| 2,795 | 432 | 128 |
| 2,800 | 426 | 120 |
| 2,805 | 420 | 132 |
| 2,810 | 414 | 128 |
| 2,815 | 409 | 128 |
| 2,825 | 399 | 132 |
| 2,830 | 394 | 112 |
| 2,835 | 388 | 84 |
| 2,840 | 383 | 88 |
| 2,845 | 378 | 88 |
| 2,850 | 374 | 140 |
| 2,855 | 370 | 132 |
| 2,860 | 367 | 136 |
| 2,865 | 363 | 140 |
| 2,870 | 360 | 148 |
| 2,880 | 353 | 144 |
| 2,885 | 350 | 144 |
| 2,890 | 347 | 136 |
| 2,895 | 344 | 140 |
| 2,900 | 341 | 136 |
| 2,905 | 339 | 148 |
| 2,910 | 336 | 160 |
| 2,915 | 334 | 164 |
| 2,920 | 332 | 148 |
| 2,925 | 329 | 156 |
| 2,935 | 325 | 176 |
| 2,940 | 323 | 156 |
| 2,945 | 321 | 148 |
| 2,950 | 319 | 172 |
| 2,955 | 317 | 172 |
| 2,960 | 316 | 188 |
| 2,965 | 314 | 172 |
| 2,970 | 313 | 200 |
| 2,975 | 312 | 204 |
| 2,980 | 310 | 196 |
| 2,985 | 309 | 212 |
On bit 2 the average fell all the way to the pull: US$309 per metre at 2,985 m, with the next metre costing US$212 at 9.4 m/h. By the rule alone the bit should have stayed in the hole until its ROP fell to about 6.5 m/h, where the two lines meet. The crew pulled it early, on the MSE trend and the slowing ROP.
The dull says they were right to. The cost formula assumes a bit that slows down gracefully. A shoulder with six of seven cutters at grade 6 or worse, one gone, and broken cutters among them does not slow down gracefully: it is one or two cutters away from a cascade, where each failure overloads the next, and a ring-out can leave junk in the hole and cost the next bit too. That risk is not in the formula. The practical answer is to agree pull criteria before the run, from the running cost per metre, the MSE ratio and the torque, and then use each dull grade to check whether the criteria were right.
What the dulls tell the next run
DrillIQ's bit selection compares only runs of the same size that drilled the target formations, all costed on the new well's basis. For the next well's 8½″ Permian section it left bit 1 out, because bit 1 drilled none of the Permian, and ranked the three designs that did:
- PDC M333: three runs, mean US$399 per metre (bit 3's short run pulls the mean up), 14.4 m/h, none damaged, expected life 26.7 hours on bottom. First.
- Impregnated: one run, US$564, none damaged, 130 hours of life, 5.2 m/h. Second.
- PDC M223: one run, US$582, damaged. Last.
The engine rates its own confidence low: three runs are a start, not a record. The design scorecard, which groups by design across every formation, shows why the formation filter matters: there the M223's median is US$347 per metre, because one of its two runs is bit 1's 1,509 m of soft rock.
For the next well the dulls give four actions. Run the seven-blade M333 through the Permian. Start each bit with a drill-off test and keep the first metres below the founder, because bit 2's broken shoulder began in its first 82 m. Agree pull criteria before the run. Ream to bottom after any bit that came out under gauge.
A checklist for the rig team
- Grade every bit, all eight positions, before it leaves the rig floor.
- Grade a PDC cutter by cutter on a map and let the averages give the rows.
- Photograph the face, profile and gauge of every bit next to its grade.
- Record the location and the second characteristic; they carry the cause.
- Ring-gauge every bit, and ream the last stand after an under-gauge bit.
- Cost every run on one basis and compare runs of similar length in the same rock.
- Set pull criteria before the run: running cost per metre, MSE ratio, torque.
- Link each dull to the drilling parameters of its run before choosing the next bit.
How DrillIQ handles it
In DrillIQ, Bit Performance & Grading keeps each run's IADC grade with a cutter-by-cutter map that sets the inner and outer rows, the maker's grade beside the operator's, the witness and the photos, and reads each pulled bit's outcome from its grade. It takes each run's metres, hours, revolutions, work and energy from ROP Optimisation's measurement of the depth log, costs every run, this well's and the offsets', on one basis with the trip from depth, and draws the running cost per metre. For a bit in the hole it compares the work done so far with what comparable bits were pulled at, and for the next well it ranks designs by size and formation with the evidence behind each. Every number above came from those engines.
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References
- International Association of Drilling Contractors. IADC Drilling Manual, 12th ed. IADC, Houston, 2015.
- Bourgoyne, A.T., Millheim, K.K., Chenevert, M.E. and Young, F.S. Applied Drilling Engineering. SPE Textbook Series Vol. 2, 1986.
- Mitchell, R.F. and Miska, S.Z. (eds). Fundamentals of Drilling Engineering. SPE Textbook Series Vol. 12, 2011.
- Dupriest, F.E. and Koederitz, W.L. Maximizing Drill Rates with Real-Time Surveillance of Mechanical Specific Energy. SPE/IADC 92194, 2005.
About this example. The well in this article is a representative scenario set in typical Cooper Basin, Australia conditions and worked through with DrillIQ's engines. It is not a client's well, and its figures are not field results.