bit whirling

Alliance Yields New Understanding of

Bit Wear - Drilling Performance Relationship

JOHN V. KENNER

Hughes Christensen Company Melbourne, Australia

ROBERT WAUGHMAN

Woodside Offshore Petroleum Perth, Australia

TOM WINDHAM

Chevron Nigeria

ABSTRACT

This paper explores the potential for reducing drilling cost by employing an improved understanding of the bit wear-performance relationship and thereby optimizing when to replace a worn bit. Recognizing when a bit is “dull” and hence past its true economic life is a difficult process. Proper identification of bit dull state depends on several geological, financial, and environmental factors. This study presents full scale rock bit laboratory wear-performance data for all major bit types. Differing bit types were studied in the lab in order to more fully define the effect of wear on performance. A case study employing and validating this methodology will be presented in a separate work.

The exact dulling characteristics of diamond and roller cone bits are not well understood. The mechanisms leading to bit wear have been previously discussed in the literature; e.g., gradual abrasive wear and erosion, chipping induced by impacts, thermal induced cracking, and catastrophic dynamic events resulting in immediate failure. Previous laboratory experiments on individual bit components have been utilized to reproduce dulling mechanisms in order to provide a measure of a bit’s resistance to a given dulling characteristic; e.g., abrasion test of metallic specimens. However, accurate prediction of bit life in a given application based on these measures remains difficult due to composite effects. Therefore drilling system optimization and bit design remain iterative procedures.

INTRODUCTION

Many performance models utilized today are based on a linear relationship between bit wear and bit life or ROP. For instance, a linear LIFE model equates a T4 bit, based on the 8 point IADC dull bit grading system,1 as having half its life remaining. The linear model shown in Fig. 1 represents the level of understanding often used in the field. However, field and laboratory testing have clearly demonstrated the effect of dulling to be much more severe.2,3 This should not be too surprising when compared to the poor cutting efficiency of a knife blade that loses its edge. Numerous authors have

Simple Wear Models

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 2 4 6 8 Dull Grade Relative Performance

Linear Inverse Exponential

100% is relative to a New (T0) Bit 1-(DG/8) (1-DG/8) (1+DG) e-DG Fig. 1

published approximate methods for modeling the effect of bit wear on ROP4,5 (Fig. 2). In the field, both new and dull bits drill soft sandstone efficiently. Good drilling performance in these soft sands obscures an accurate reading of bit dull state. Subsequently when the bit encounters a shale the amount of tooth and gauge wear present have a significant performance impact.6 Therefore wear models must be calibrated in shale which possesses the highest sensitivity to bit wear, cutting tool sharpness, cutting structure design, differential pressure, and hydraulics.7

Poor drilling efficiency is a self-reinforcing problem8 that

generates excess heat and mechanical loading thereby leading to more damage, hence poorer efficiency. When the drilling rate slows down during a bit run the driller compensates by adding weight to maintain the desired penetration rate. Cheatham and Loeb9 showed in laboratory test that field-worn PDC bits required three to eight times as much weight-on-bit and two to four times as much torque to achieve the same rate of penetration as a new bit. This additional weight increases thermal and mechanical loading, thus causing the accumulation of bit damage and wear to accelerate as the bit dulls. The realization that bit wear is an accelerated nonlinear function directly infers that the majority of a bit’s useful life is spent at a T2 dull condition or less (see figure 1 models). Cheatham’s and Fay’s individual works dovetail with what will be presented here and underscores why few applications can be economical when rerunning severely worn bits.

The collective effects of the fluid system, directional profile, BHA design, formation drillability, and operating parameters remain as major obstacles to the accurate prediction of bit ROP and life.10 Additional inhibitors to modeling arise from the difficulties in accurately predicting and preventing vibrational excitation and damage.11,12,13,14

Thus, this study focuses on isolating the effect of bit wear on drilling performance.

In order to quantify the effects of bit wear, laboratory tests were conducted utilizing full scale rock bits drilling different formation samples.15 The high pressure drilling simulator, in its current configuration, can simulate bottomhole pressures (BHP) to 10,000 psi, weight-on-bit (WOB) to 100,000 lb., and rate-of-penetrations (ROP) to 100 ft/hr.

STEEL TOOTH BITS

Mouritz and Hutchings16 described and compared the wear rates and abrasive wear mechanisms of hard-faced steel teeth and cone steel. Material specimens were rubbed against both sandstone and limestone in order to measure relative abrasion resistance. Mass loss measurements of

(

)

a = exponent fit to observed field data K = constant set to fit field data

Bourgoyne and Young:

ROP K e-a *DG ; DG, a ,K same as above

1 1 1 ∝ + +    = ∝ 0 928 2 6 1 1 .

Fig. 2 _{Fig. 3: T3 Dull}

9-7/8" IADC Class 116 bits in Mancos Shale

MudWt 9.5 ppg, HSI 3.9 0 10 20 30 40 50 60 70 20 40 60 80 WOB (klbs)

Specific Energy (ksi)

New SE T1 SE T3 SE Balling 0 10 20 30 40 50 60 70 20 40 60 80 WOB (klbs) ROP (ft/hr) New ROP T1 ROP T3 ROP Balling

these materials were at least 140 times higher when abraded on sandstone than for limestone.

In this new study full scale laboratory test were conducted drilling Mancos Shale under 3000 psi bottomhole pressure. Steel tooth bits drilling shale were found to exhibit complex performance changes relative to the degree of bit wear and selected operating parameters (Fig. 3-4). In this particular case, the T1 bit performs moderately worse than the new bit as long as heavy balling is prevented. However, when the WOB is increased in an attempt to increase the penetration rate balling results and performance drops dramatically.

Figure 4 lab results reveal that the T1 dull bit required from 10% to 60% more specific energy (was less efficient) than the new bit and the T3 was much worse. The drilling specific energy is the amount of mechanical energy input into the drilling system in order to remove a unit volume of material, see Appendix A.17 Specific energy provides a measure of the apparent formation strength for the given operational conditions and when scaled against the formation’s Unconfined Compressive Strength18 (UCS) yields an effective estimate of the drilling efficiency, see Eq.(1).

E q . ( 1 )

E f f i c i e n c y U C S

S p e c i f i c E n e r g y =

Noting that the unconfined compressive strength of this Mancos sample was 10,000 psi, the efficiency of the new bit dropped from 33% to 17% while the dull bit drilled each set point at around 10% efficiency. The extra mechanical energy that is required by the drilling system represents additional work above the minimum required level. Portions of this extra energy are dissipated through vibration and heat leading to more bit damage.

The abrupt change in the performance of the T1 bit was triggered by approaching a WOB threshold, also commonly referred to as the bit floundering point. ROP is known to increase proportionally with incremental WOB up to some limit after which the laws of diminis hing returns take effect. Increasing the WOB beyond the floundering point19 will even decrease ROP. This example reveals that the bit dull state has a dramatic effect on the floundering point since the T1 bit initiated balling well before the new bit. In a controlled lab environment it is possible to operate just below the balling

threshold, but in a noisy field environment WOB excursions often occur and increase the likelihood of globally balling a dulled bit. Pessier7 et al noted that bit performance strongly depends on the type of shale encountered and bit hydraulics employed.

TUNGSTEN CARBIDE INSERT BITS

When Tungsten Carbide Insert (TCI) bits were introduced they were originally considered not to wear or plastically deform. Primary failure mechanisms were originally thought to be limited to microcracking and chippage. Drilling tool technology and metallurgical evolution have altered this view. Pessier et al found dramatic inefficiencies resulted due to gauge rounding and wear of TCI bits.6

Using the simulator, laboratory tests were also performed with two 12-1/4” IADC Class 417 bits at constant ROP, see Fig. 5. In this case the RPM was increased while setting the simulator at a fixed ROP (vertical feed rate) and the required WOB was monitored. The largest performance difference was observed at the lower RPM and heavier WOB. The

12-1/4" IADC Class 417 bits in Mancos Shale

MudWt 9.6 ppg, HSI 1.8 0 10 20 30 40 50 60 70 80 50 150 250 RPM WOB (klbs) New WOB T3 WOB 0 10 20 30 40 50 60 70 80 90 100 50 150 250 RPM

Specific Energy (ksi)

New SE T3 SE

performance differential ranged from 50% to 200%. Note how the new bit’s drilling specific energy worsens as the rpm is increased and the dull “heavily balled” bit performs poorly for all parameters tested. The imposed depth-of-cut, the amount of bit balling, and tooth shape all affect this relationship. The average imposed depth-of-cut (DOC) is calculated in Equation 2.

Eq. 2: DOC=

(

)

(in feet or meter per revolution)

As the DOC decreases the macro-chipping and scraping of the cutting action is reduced and replaced by small mirco-cutting events. This micro-mirco-cutting action produces a fine powder that when drilling shale under pressure leads to bit balling.20 A dull bit’s increased sensitivity to bit balling is a primary limitation to its useful life.

FIXED CUTTER BITS

PDC bits in shale respond in a similar fashion to what we have discussed thus far, e.g., small wear changes result in dramatic performance

degradation in shale. An even more pronounced drop in performance occurs in formations such as marble, hard limestone, dolomite, and anhydrite. Carthage Marble is particularly difficult to drill under pressurized conditions with PDC bits, see Fig. 6-7. High WOB levels are required for a PDC to take a bite and then only micro-chips are produced. The increased WOB required to drill

these formations increases the weight per face-cutter and consequently the thermal loads.21 In another laboratory test, drilling shale with a new PDC bit required 250 lbs per face cutter while drilling marble required 800 lbs. Once the WOB is sufficient for the cutter to pierce the marble and begin shearing, the specific energy will decline with increasing WOB up to some efficiency limit. As expected, these test revealed that a new bit proves to drill dramatically better than a dull bit. A WOB of 18,000 lbs was found to yield 12 ft/hr for the dull bit and 35 ft/hr for the new bit.

BALLASET BITS

Laboratory test data for new and dull IADC Class M724 BallaSet bits are presented in Fig. 8-9. Constant RPM tests were performed and the

WOB required to achieve the set ROP was measured. Berea Sandstone was drilled with a higher bottom hole pressure of 6000 psi in order to model a tough interval. Once again the new bit performed dramatically better than

the slightly chipped T1 dull bit. The new bit also responded better to changes in operating parameters. At 20,000 lbs WOB the dull bit was found to drill at 6 ft/hr and the new bit at 42 ft/hr. BallaSet bits were previously considered to be more damage tolerant than other products, however, these test reveal them to also be highly susceptible to the detrimental effects of wear.

6-3/4" IADC Class M121 in Carthage Marble

MudWt 9.5 ppg, HSI 4.9 0 5 10 15 20 25 30 35 40 45 50 0 20 40 WOB (klbs) ROP (ft/hr) New ROP T1 ROP T8 -Theoretical Dulling 50 60 70 80 90 100 110 120 130 140 150 0 20 40 WOB (klbs)

Specific Energy (ksi)

New SE T1 SE

Fig. 6

Fig. 7: T1 Dull

Fig. 8: T1 Dull IADC Class M724 Bit

DISCUSSION OF RESULTS

Figure 10 presents a summary of the laboratory data versus sample wear models discussed herein. A number of useful observations can be gleaned from this data:

• PDC bits drilling hard formations stop drilling with even the slightest wear.

• Bits experiencing bit balling are better approximated by the accelerated models.

• Bits drilling weak formations and staying perfectly clean may approach the linear wear performance line.

• However, staying perfectly clean drilling shale with a water-based-mud (WBM) is difficult • Accelerated wear is known to occur in hard and/or

quartz bearing formations.

• Bit dull state is the mo st critical when entering a shale or very hard formation.

Thus different performance envelopes exist for differing drilling conditions, formations, hydraulics, and tools selected (Fig. 11). These principles can now be applied to actual real-time monitoring in the field by measuring the mechanical

energy input at the drill rig floor, calculating the drilling specific energy, checking current formation type via downhole gamma ray reading, estimating the formation strength from offset electric log data (Spaar et al), equating the estimated formation strength to the minimum specific energy, and finally using these values to obtain the drilling efficiency. This mechanical model is proposed as a post well analysis tool to help determine when the bits should be

12-1/4" IADC Class M724 in Berea Sandstone

RPM 100

Flow 500 gpm, BHP 6 ksi, TFA .75, MudWt 9.5 ppg, HSI 4.5

0 5 10 15 20 25 30 35 40 45 10 15 20 25 30 WOB (klbs) ROP (ft/hr) New ROP T1 ROP 0 10 20 30 40 50 60 70 10 15 20 25 30 WOB (klbs)

Specific Energy (ksi)

New SE T1 SE

Fig. 9

Laboratory Test Results

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 2 4 6 8 Dull Grade (0-8) Relative Performance Linear (1-DG/8)/(1+DG) e-DG ST - Shale DIA - Marble BallaSet - Sandstone TCI - Shale Fig. 10

Different Performance Envelopes

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 0 2 4 6 8 Dull Grade (0-8) Relative Performance Moderate Balling Soft Sand

Heavy Balling or PDC in Hard Rock

pulled. The method’s foundation is based on the following principles:

1. No rock is 200,000 psi strong and, in fact, most rocks drilled in the oil field are under 35,000 psi with shales below 15,000 psi.

2. Specific energy levels in the field frequently exceed 1,000,000 psi.

3. Drilling efficiencies in the laboratory at atmospheric pressure have been observed to reach or slightly exceed 100%.13 This condition represents ideal efficiency with no balling, drill string drag, or other problems.

4. High pressure laboratory drilling tests in shale have revealed drilling efficiencies with balled bits as low as 1% and that improved efficiencies can approach 50%.

Ideally downhole data should be utilized to estimate real-time drilling efficiency. Peak efficiencies at the start of a run that are calculated with downhole data may approach laboratory efficiencies of 50%. Surface data is an acceptable alternative when downhole data is unavailable. Maximum calculated efficiencies in this case are limited due to string and BHA drag. Regardless of the data source, runs should be benchmarked in every shale/hard section and the trends closely watched for creeping or sudden inefficiency.

CONCLUSIONS

• Different bit wear - performance relationships exist for differing drilling conditions, formations, hydraulics, and tools selected.

• A dull bit’s increased sensitivity to bit balling is a primary limitation to its useful life.

• PDC bits exhibit a pronounced drop in performance drilling hard formations with even the smallest wear. • Future drill bit development must focus on keeping bits

sharp “like-new” longer and on building them with a higher damage tolerance so as not to diminish performance as dulling progresses.

In the absence of catastrophic failure events, if a drilling operator is regularly pulling bits graded T4-T8 he is likely adversely impacting his section drilling cost through poor ROP. An acceptable drilling practice is to finish a hard stringer before pulling out of the hole in order to start a new bit in a softer formation. However, to continue drilling with a bit as the ROP drops substantially will cost the operator accordingly and risk an undergauge hole, for example, as the

ROP falls from 60 to 3 means that if the first foot cost $200 then the last foot cost $4,000. Historically we have reduced section cost by eliminating bit runs. However, today with an improved understanding of the effects of incremental bit wear and realizing the high ROP potential of a new bit leads us to consider adding a bit back into the program in order to minimize cost.

ACKNOWLEDGMENTS

The authors wish to thank the management of Woodside, Chevron, and Hughes Christensen for permission to present this paper.

APPENDIX A

Energy Input Into System via Torsional and Axial Effort

WOB Torque Specific Energy (A.1)

E

WOB

A

NT

A

ROP

=

+

120

π

*

ε

ε

ff

E

E

E

UCS

ff

UCS

E

=

≈

=

*

*

100

100

DBIT = Bit Diameter

ABIT = Bit Cross Sectional Area N = Rotary Speed (rev/min)

UCS = Unconfined Compressive Strength (psi) ESmin = Minimum Specific Energy (psi)

REFERENCES

1 Brandon, B.D. et al, “First Revision to the IADC Fixed Cutter Dull Grading System”, SPE Paper No. 23939, presented at the SPE/IADC 1992 Drilling Conference in New Orleans, USA, 18-21 February, 1992.

2 Fay, H., “Practical Evaluation of Rock-Bit Wear During Drilling”, SPE Paper No. 21930.

3 Mensa-Wilmot, G. and Alexander, W., ”New PDC Bit Design Reduces Vibrational Problems”, Oil & Gas J. May 22, 1995.

4 Galle, E.M. and Woods, H.B., “Best Constant Weight and Rotary Speed for Rotary Rock Bits”, API paper 801-39J, presented at Spring Meeting of the Production Division of the American Petroleum Institute, May 21-23, 1963. 5 Bourgoyne, A.T and Young, F.S. Jr., “A Multiple

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6 Pessier, R.C. et al., “Rolling Cone Bits with Novel Gauge Cutting Structure Drill Faster, More Efficiently”, IADC/SPE paper No. 30473, presented at the 1995 Drilling Conference in Dallas, USA, 22-25 October, 1995. 7 Pessier, R.C., Fear, M.J. and Wells, M.R., “Different

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8 Gleick, J., Chaos Making A New Science, Penguin Books, 1987.

9 Cheatham, C.A. and Loeb, D.A., “Effects of Field Wear on PDC Bit Performance”, SPE 13464, presented at the SPE/IADC 1985 Drilling Conference in New Orleans, USA, 6-8 March, 1985.

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11 Brett, J.F., “The Genesis of Torsional Drillstring Vibrations,” SPE Drilling Engineering, September 1992, pp. 168-174.

12 Cooley, C.H., Pastusek, P.E., and Sinor, L.A.; “The Design and Testing of Anti-Whirl Bits,” SPE Paper No. 24586, presented at 1992 SPE Technical Conference & Exhibition, Washington D.C., Oct. 4-7.

13 Kenner, J.V. and Isbell, M.R., "New Energy

Decomposition Study For Rolling Cone Rock Bits",

ASME Drilling Technology Transactions, PD-Vol. 65, pp.163-178.

14 MacPherson, J.D., Mason, J.S., and Kingman, J.E., “Surface Measurement and Analysis of Drillstring Vibrations While Drilling”, SPE Paper No. 25777, presented at 1993 SPE/IADC Conference in Amsterdam, Feb. 23-25.

15 Ledgerwood, L.W. and Kelly, J.L., “High Pressure Facility Re-Creates Downhole Conditions in Testing of Full Size Drill Bits”, ASME paper 91-PET-1, presented at Energy-Sources Technology Conference and Exhibition, New Orleans, January 20-24, 1991.

16 Mouritz, A.P. and Hutchings, I.M.,” The Abrasive Wear of Rock Drill Bit Materials”, SPE 24222, October 1991. 17 Pessier, R.C. and Fear, M.J., “Quantifying Common

Drilling Problems with Mechanical Specific Energy and a Bit-Specific Coefficient of Sliding Friction”, IADC/SPE paper No. 24584, presented at 67th Annual Conference and Exhibition, Washington, DC, 4-7 October, 1992. 18 Spaar, J.R., et al, “Formation Compressive Strength

Estimates for Predicting Drillability and PDC Bit Selection”, IADC/SPE paper No. 29397, presented at 1995 SPE/IADC Conference, February 28-March 2, 1995, Amsterdam.

19 Bourgoyne, A.T. et al., Applied Drilling Engineering, p 226, Society of Petroleum Engineers (1991).

20 Hughes Christensen Drilling Hydraulics Manual, 1996. 21 Glowka, D.A.: “Implications of Thermal Wear

Phenomena for PDC Bit Design and Operation”, SPE Paper No. 14222, presented at 1985 SPE Conference in Las Vegas, NV September 22-25, 1985.