Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5 – 8 October 2003. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Hard rock applications continue to pose serious challenges for PDC bits. Although improvements1,2,3 have been achieved in these environments, PDC bit performance is highly inconsistent and leaves much to be desired. Operational costs in such environments, due to reduced footage and/or low penetration rates (ROP), are enormously high. This paper will evaluate the challenges of hard rock drilling. It will discuss the effects formation hardness has on drilling efficiency, and the energy level requirements associated with the different rock failure mechanisms. The definition and relationships between WOB requirements, drilling efficiency, ROP, wear flat generation and on-bottom drilling time will also be discussed. An advanced cutting structure (ACS), which improves PDC bit effectiveness and consistency in hard rock drilling environments, will be presented. ACS improves drilling performance by re-defining and optimizing the relationships between ROP, durability and stabilization. It maximizes bit life, by slowing the PDC cutter deterioration process, without compromising ROP. This paper will describe ACS’s functionality, and show the positive effects it is having on operational costs. Laboratory and field data, supporting ACS’s effectiveness will also be presented. Background To improve PDC bit effectiveness in such hard rock environments, certain performance and/or behavioral relationships (PBR) must be understood and optimized. The conditions and levels of durability, required to enhance PDC bit longevity, must be defined. In addition, the appropriate operational medium needed to enhance drilling efficiency must be

established4,5,6. These conditions must be achieved, while maintaining efficient relationships between ROP, rate of wear flat generation and on-bottom drilling time. These characteristics will improve PDC bit performance in hard rock applications. To be durable and/or exhibit high ROP characteristics, PDC bits must be stable. This requirement, in ensuring effective use of available mechanical energy, also minimizes diamond table degradation through impact damage – spalling, chippage and delamination (Figure 1). The benefits of stabilization can be summarized as follows:

• Efficient energy use --- improves ROP • Reduced diamond degradation --- enhances durability

ACS achieves the performance and/or behavioral requirements listed in this section. Its effectiveness, in hard rock applications, is based on its unique ability to establish the appropriate energy efficiency and durability characteristics. Performance and Behavioral Relationships (PBR) Improving PDC bit performance, especially in hard formations, primarily requires the development of products and/or processes that will extend bit life. In addition, these products must be consistently effective in such applications. The poor performances of PDC bits in hard rock applications are due to the wrongful interpretation of the requirements needed to make these bits durable. As such, most of the solutions advocated have not had the desired effects. To address the hard rock applications problem, PDC bit durability7 - in terms of its definition, optimization and relationship to ROP - must be clearly understood. In addition, technologies and/or processes must be developed that drastically slow down the rate of PDC cutter deterioration. Solutions developed to address this requirement must not compromise ROP. Minimizing PDC Cutter Deterioration Accelerated PDC cutter deterioration, either through wear or impact damage, reduces durability and drilling efficiency. To improve PDC bit performance, especially in hard rock drilling environments, cutter deterioration must be drastically delayed.

SPE 84354

Advanced Cutting Structure Improves PDC Bit Performance in Hard Rock Drilling Environments Graham Mensa-Wilmot*, Smith Bits; Robert Soza and Kyle Hudson, Burlington Resources

*SPE Member

2 SPE 84354

New generation PDC cutters, having improved impact and abrasion resistance characteristics, have had positive effects on bit durability. These cutters have engineered substrate interfaces (Figure 2), specialized diamond and carbide materials and improved sintering processes. However, cutter improvements alone will not make PDC bits effective in hard rock environments. This is due to the types and complexities of the behavioral relationships that need to be analyzed and optimized:

1. WOB vs. ROP 2. ROP vs. cutter wear 3. Rate of cutter wear vs. time

WOB vs. ROP: When rock hardness, RPM and hydraulic influences are kept constant, the relationship between WOB and ROP defines a PDC bit’s mechanical efficiency. The ROP response of two 8-½” PDC bits (Figure 3), tested in the laboratory under similar test conditions (Table 1), is shown in (Figure 4). Bit X has 8 blades, 13mm cutters, 6 nozzles. Bit Y has 13 and 16mm cutters, six blades and six nozzles. The tests were designed to identify the different rock failure mechanisms associated with PDC bits. Bit X, at the start of its tests, exhibited a weak ROP response to increasing WOB. During this period, the stress generated by the bit was lower than that needed to shear the rock. WOB/Ab < σs --- (1)

Where Ab and σs represent the borehole area and shear strength of rock being drilled. As WOB was increased beyond 12klbs, bit X showed a much stronger ROP response. The stress generated by bit X now exceeded the value needed to shear the rock WOB/Ab ≥ σs --- (2) The conditions defining the scraping and shearing rock removal mechanisms are depicted by equations (1 and 2) respectively. Bit Y, on the other hand, had a much different behavior throughout its test protocol. It exhibited a stronger ROP response to increasing WOB, and was always in a shearing mode (equation 2). The consequences of the different failure mechanisms (equations 1 and 2), are more critical in hard rock drilling environments. Soft and/or medium hard formation drilling is usually governed by (equation 2) – shearing mode, even at low WOB values. For hard rock drilling, the specific failure regime is strongly dictated by bit type. For a given rock hardness, a drill bit is said to be mechanically efficient if it requires less WOB to exhibit a shearing rock removal process. This attribute results in the attainment of much higher ROPs. Although this property is critical for hard rock

drilling, it is not sufficient since several other characteristics must also be exhibited. PDC bits, to be effective in hard rock environments, must also delay deterioration of their cutters, either as a result of wear or impact damage. ROP vs. Cutter Wear: PDC cutter deterioration, defined in terms of cutter wear (deterioration as a function of impact damage will be discussed later), is strongly dependent on heat. The different rock failure mechanisms, scraping and shearing, identified in the previous section, generate different levels of heat in a cutter. Scraping, which is highly inefficient and associated with reduced ROP, elevates heat levels. On the other hand shearing, which is more efficient and associated with higher ROP, generates very low heat levels in a cutter. Although several other parameters and conditions contribute to ROP response, only WOB has an effect on the rock failure mechanism. In this regard depth-of-cut (DOC), a performance characteristic which depends solely on WOB, can be substituted for ROP. This enables isolation of WOB’s effect on the rock failure mechanism, heat generation, and cutter wear. At low DOC’s, signifying a scraping drilling mode, PDC cutters wear at an accelerated rate. From the above discussion, and relating to the previously discussed laboratory tests, it can be concluded that PDC cutter deterioration through wear is dependent on drilling efficiency (as previously defined) or DOC. Considering the nature of the ROP-WOB slopes, the corresponding failure mechanism as well as induced heat levels, wear flat generation will exhibit an inverse relationship with DOC (Figure 5). Bit X, if operated in a scraping mode (WOB < 12klbs), will generate accelerated wear flats. However bit Y, at the WOB conditions tested in the laboratory will always generate reduced wear flats due to its efficient shearing action. Beyond 12klbs, bit X will generate reduced wear flats, because it transitions into a shearing drilling action. The WOB threshold, needed by bit X to establish an efficient shearing mechanism, must be considered in BHA design. It must be stressed that the defined WOB threshold for bit X (12klbs) is not constant in all formations and/or applications. This value is a functional characteristic, which depends on rock hardness and/or PDC bit type. Different bits (X and Y), in the same formation, will have different WOB thresholds. Likewise, a specific bit will have dissimilar thresholds that will be defined by formation hardness. This discussion must not be underestimated, as it is critical to bit mechanical efficiency and hard rock drilling. The influence of heat on PDC cutter wear can further be analyzed in terms of friction and drilling-time. Different formations based on their mineralogical constitution, grain size distribution and angularity, exhibit varying degrees of abrasiveness. This trait directly influences the friction, and thus the heat, generated at the rock-cutter interface during the drilling process (Figure 6). In addition, drilling-time also influences the heat generated at the rock-cutter interface. For a given rock strength and drilling interval (footage), a long drilling-time is usually a result of reduced DOC or ROP.

SPE 84354 3

Dt = 1/ROP --- (3) or Dt = 1/DOC --- (4) Although, a low ROP does not necessarily indicate a scraping action, the associated increased drilling-time is detrimental to PDC cutter performance. At a defined temperature, time influences the heat build-up in a PDC cutter. The condition is harmful to bit performance, because it promotes PDC cutter degradation. Detrimental effects such as diamond table graphitization and oxidation, processes that are influenced by time and/or temperature, affect cutter performance. In addition, cobalt and diamond (materials present in the diamond table) have different thermal characteristics and experience rapid deteriorations with heat build up. PDC cutters will experience rapid wear, if the pair of “friction and drilling-time” points defining the drilling environment to which they are exposed, from a formation abrasiveness and/or hardness perspective, lie beyond the acceptable heat threshold (Figure 7). As an example, the locations of three different formations (A, B and C) having different “friction/drilling-time” coordinates is shown in (Figure 8). Formations A, B and C are classified as follows:

• Formation A --- Abrasive sandstone • Formation B --- Hard limestone • Formation C --- Medium hard limestone

Formation A’s location is due to its abrasiveness and ensuing friction capacity. Based on its hardness and associated low ROP, “drilling-time” is usually high for formation B. With regards to formation C, the abrasiveness (friction) and/or high “drilling-time” challenges are absent. PDC bits exposed to the friction and/or “drilling time” conditions or formations A or B will experience accelerated wear. Wear Rate vs. Time: Cutter wear reduces ROP, and has the ability to change a PDC bit’s shearing mechanism into an inefficient scraping action. WOB is usually increased to offset the ROP reduction seen at the on-set of wear. During this process, the cutter wear process grows at a non-linear rate (Figure 9). This situation establishes a condition that further causes WOB to be exponentially increased. In this regard, heat generation increases quickly, due to the rapid growths in wear flat and associated WOB requirements. In time, a self-sustaining cycle of “wear-increased WOB-increased wear” is created. Wear grows at a much faster rate (Figure 10), because “wear causes more rapid wear” This paper will show how ACS improves PDC bit efficiency, in hard formations, by addressing the challenges posed by the identified performance and behavioral relationships.

Cutting Structure Evolution Three different cutting structures, single set (SS), plural set (PS) and alternating cutter size (AS) layouts are shown in (Figures 11, 12 and 13). In the SS cutter layout (Figure 11), individual cutters are deployed at unique radial positions along a bit’s profile. For the PS cutting structure (Figure 12), groups of cutters occupy identical radial positions along a bit’s profile. With the AS cutter layout (Figure 13), two different sized cutters are deployed at different radial locations along a bit’s profile, each size establishing independent and complete bottom hole coverage. PS8,9 has shown to be more stable than SS, and in most cases faster and more durable as well. AS10,11 has also shown to be more stable, faster, and durable than PS. Although these improvements have been beneficial, PDC bits still lack performance consistency in hard rock environments. To address this issue ROP, durability and stability, characteristics needed to enhance PDC bit performance must be improved while optimizing the performance and behavioral relationships. ACS achieves these requirements, and successfully extends PDC bit performance into hard rock environments. Description of Advanced Cutting Structure (ACS) The ACS cutting structure uses three different sized PDC cutters (Figure 14) in a unique layout to improve bit performance. The different cutter sizes (Фb, Фm, and Фs) are deployed along a bit’s profile under the following geometric conditions:

• No two adjacent cutters on any individual blade are of the same size.

• Along each blade, each cutter size is flanked by the two other sizes.

• When all the cutters on an ACS bit are rotated onto a single radial plane, no two adjacent cutters are of the same size.

• Each cutter size will be surrounded by the two other sizes, when all the cutters on an ACS bit are rotated onto a single radial plane.

In addition, the three different sized cutting elements, having diameters (Фb, Фm and Фs), and deployed at unique radial positions (Rj+1, Rj+2 and Rj+3) have the following geometric relationships:

Фb > Фm > Фs --- (5)

Фs ⊄ Фb --- (6) Фs ⊄ Фm --- (7) Фm ⊄ Фb --- (8) Фb3j+1 ∩ Фb3j+4 > 0.0 --- (9) Фm3j+2 ∩ Фm3j+5 > 0.0 --- (10)

Фs3j+3 ∩ Фs3j+6 ≥ 0.0 --- (11) j = 0,1,2,3,…,k --- (12)

4 SPE 84354

Functionality of ACS ACS enhances PDC bit performance, especially in hard rock applications, by re-defining and optimizing the relationships between ROP, durability and stabilization. ACS delays accelerated PDC cutter wear, by optimizing the performance and behavioral relationships. In addition, ACS addresses the issue of PDC cutter deterioration resulting from impact damage. ROP: The large and medium cutter sizes (Фb and Фm) in ACS’s layout establish independent and complete bottom-hole coverage. This means that when all of the medium and small cutter sizes (Фm and Фs) are removed, the large cutter size (Фb) establishes complete bottom hole coverage. Likewise, when all of the large and small (Фb and Фs) cutter sizes are removed, the medium sized cutter (Фm) also establishes complete bottom coverage. ROP, as a performance qualifier increases with cutter size12 when all other design parameters (profile, blade count, back rake, side rake and nozzle count) are held constant. However, enhancing ROP through the cutter size effect sacrifices cutter count, radial diamond volume13 (Rv) and durability. Without compromising durability (to be discussed later), ACS’s unique cutting structure enhances ROP. By achieving full bottom hole coverage with its largest cutter size (Фb), ACS establishes an ROP behavior which is governed by this specific cutter size. The ROP responses for three 8-½” PDC bits (X, M and N), at identical laboratory test conditions and in the same formation, is shown in (Figure 15). The design characteristics of the three bits, specifically their cutting structure descriptions, are presented in (Table 2). The three bits are shown in (Figure 16). Bit X, designed with the PS cutting structure, had 8 blades, 6 nozzles and only 13mm cutters. Bit M had the AS cutting structure with 9 blades, 13 and 9mm cutters and 6 nozzles. Bit N had the ACS cutting structure, with 8 blades, 6 nozzles and 13, 11 and 9mm cutters. Due to their respective layouts, the 13mm cutter established full bottom-hole coverage for all the three bits. The tests were designed to investigate the mechanical efficiencies of the three different cutting structures, as well as their expected behavioral relationships.

• Bit X (PS) transitioned from scraping to shearing at approximately 12klbs.

• The transition for bits M (PS) and N (ACS) occurred at approximately 9klbs.

• Compared to bits M and N, bit X had lower ROPs. • Beyond 9klbs, bit N had higher ROPs when

compared to bit M. • Bit N, had the most efficient ROP response to WOB. • At comparable WOB, bit N will generate less heat

due to its superior mechanical efficiency. • Wear flat growth rate will be lowest for bit N • Below 12klbs, bit X will experience accelerated wear

• Beyond 12klbs, bit X will still wear faster when compared to bits M and N

Although bits M and N had multiple cutter sizes, their ROP response was not compromised. This performance qualifier (ROP), as discussed earlier, is governed by the largest cutter size that establishes complete and independent full bottom-hole coverage. For bits M and N, this happened to be the 13mm cutter size. From a mechanical perspective, the ACS cutting structure is clearly the most efficient. ACS will minimize heat generation and reduce the wear flat growth rate. This cutting structure effectively addresses the challenges posed by the first and second behavioral requirements. These advantages will improve performance and consistency of ACS, especially in hard rock drilling environments. Durability: As a pre-requisite to the establishment of durability13, the total diamond volume (Tv) of a PDC bit must be optimized. In addition, the axial (Av) and radial diamond (Rv) components must be maximized. This requirement has been impossible to achieve, especially for single cutter size bits (SS and PS), because Av and Rv (Figure 17) are inversely related

The Av of ACS bits is established by the largest cutter size, which provides complete bottom hole coverage (Фb). In comparison to other cutting structure bits, where Фb is the largest or single cutter size giving complete bottom hole coverage, ACS optimizes the Rv and Av relationship. This advantage is due to ACS’s three different cutter sizes. When profile, blade count and largest cutter size (Фb) are kept constant, ACS re-defines the relationship between Av and Rv, due to the presence of the other cutter sizes (Фm and Фs). Under the conditions described, the total cutter count deployed on a unit profile length is highest for ACS (Figure 18) when compared to other cutting structures (SS, PS and AS) with similar Av. This distinction maximizes the Rv of ACS bits, which when combined with their comparable Av characteristics, makes them more durable than the other cutting structures.

The three bits tested in the laboratory (X, M and N) had similar Av values. Although bit N had a medium parabolic profile, its total cutter count was comparable to that of bit X, which had a long parabolic profile. Bit M, which had a similar profile and back rake distribution as that of bit N, had the highest cutter count because of its higher blade count. From a diamond content perspective (Tv, Av and Rv), bit M will be the most durable. Although the diamond content requirement is necessary, it does NOT sufficiently establish durability since several other conditions have to be met. PDC bit durability must also have a functional definition. In addition to diamond content (Tv) being present in appropriate distributions (Av and Rv), the wear flat generation rate must also be controlled. ACS’s unique layout increases Rv, which permits use of lower blade counts, without compromising total cutter count. This characteristic promotes shearing, and establishes a second level of mechanical efficiency for ACS bits.

SPE 84354 5

Functionally, the improved efficiency gained without compromising diamond content minimizes heat generation and its detrimental effect on wear flat generation. This benefit reduces wear flat growth rate, and weakens its dependence on time. In this regard, ACS achieves the third behavioral requirement needed to extend PDC bits into hard rock drilling applications.

Stabilization: To improve bit life, PDC cutters must only deteriorate through wear. Vibrations change a bit’s operational medium from static to dynamic. Regardless of a cutter’s material characteristics and/or abrasion resistance, impact damage resulting from vibrations causes partial and/or total loss of a cutter’s diamond table. Since tungsten carbide has very low abrasion characteristics, wear flat initiation and growth accelerates at the loss of a cutter’s diamond table (Figure 19).

ACS’s unique cutting structure enhances stabilization. The curvature differences, between ACS’s three different cutter sizes, establish a highly uneven bottom-hole pattern with well defined scallops (Figure 20). During drilling and at the onset of off-center rotation, a condition that initiates bit vibrations, the cutters bite into the scallops. This action creates a restoration force, which acts to re-establish the bits true center rotation. The restoration force is situated in a plane perpendicular to the bit’s axis.

Stabilization improves durability, because it minimizes diamond table loss resulting from impact damage. By minimizing impact induced wear, and establishing effective and optimized behavioral relationships, ACS delays cutter deterioration. As a result, bit life is substantially improved. This advantage, which minimizes wear flat growth, further improves ACS’s mechanical efficiency in hard rock environments.

The vibration characteristics of two 8-1/2” PDC bits (K, C), tested in the laboratory in Carthage Limestone under identical test conditions, is shown in (Figure 21). Bit K, an SS bit, has 13mm cutters, 9 blades and 6 nozzles. Bit C has the AS cutting structure with 9 blades, 16 and 13mm cutters and 6 nozzles. Bit C proved to be much smoother than bit K, from a vibration standpoint. As such, bit K will be much more susceptible to cutter deterioration through impact damage. In addition, bit C had higher ROPs at comparable WOB values (Table 3). The two bits (K and C) are shown in (Figure 22).

Due to the developmental freedom available to PS, AS and ACS bits, generalizations should never be made about their performance characteristics. If correctly implemented, based on specific applications requirements, these cutting structures show improved stabilization, ROP and durability characteristic when compared to SS bits.

Stabilization, when achieved without ROP compromise (PS, AS and ACS), improves energy efficiency. Such bits are able to establish shearing, as their failure mechanism, at lower WOB levels.

Performance Efficiency To be consistently effective in hard rock applications, the following characteristics must be exhibited by PDC bits. Shearing must be exhibited at reduced WOB. Performance and/or behavioral challenges (relationships between WOB, ROP, drilling-time and wear rate) must be optimized. Diamond content (Tv) must be optimized and its distribution (Av and Rv) optimized. ROP must be effectively optimized without compromising durability. PDC cutter deterioration, either through wear or impact damage must be delayed. Stabilization must be enhanced to improve energy efficiency and extend bit life. These characteristics, all of which are critical and must be achieved without compromise, will improve PDC bit performance efficiency, especially in hard rock environments. ACS achieves these requirements and, improves PDC bit performance in hard rock drilling environments. ACS Performance – Field Tests Different sizes of ACS bits, having different cutter size combinations, are being used widely in various hard and challenging applications. Although many runs have been recorded, three runs which show ACS’s efficiency at improving PDC bit performance in hard/harsh drilling environments will be discussed. Run #1 --- North Kuwait A 16” hard rock and challenging application, due to the hole size effect, was identified in Northern Kuwait as a project for ACS. The application consisted of sandstone, siltstone and limestone. Unconfined compressive strengths averaged 24kpsi, and peaked beyond 30kpsi. In addition to the hardness issues, the section is highly heterogeneous and presented several challenges for drill bits – very slow and extremely short runs. PDC bits had previously been tried and deemed ineffective, in this application. An average of 6 roller cone (RC) bits, averaging 4ft/hr was used for this section on offset wells. A lithological description of the interval is shown in (Figure 23). After elaborate formation drillability analysis, and several consultations with the operator, a proven PDC bit was identified for the application. The intent with this exercise was to establish a benchmark which could later be built on, due to the previous poor PDC bit performances. The selected bit, shown in (Figure 24), had the AS cutting structure, with 12 blades, 16 and 13mm cutters and 8 nozzles. The test was a huge success, as two of the AS bits achieved a 100% ROP improvement over the RC bits used on the offset well, resulting in significant operational savings. After analyzing the AS runs from a stability, ROP and durability perspective, a new PDC bit was developed with the ACS cutting structure. This bit (ACS1) had 8 blades, 10 nozzles with 19, 16 and 13mm cutters (Figure 25). ACS1 further improved ROP (250% over the RC bits), with no loss in stabilization characteristics and durability for this specific application when compared to the AS bits. The dull pictures of ACS1, after a run in this challenging application are shown in (Figure 26). Performance comparison for the RC bits, AS and ACS1 are presented in (Table 4).

6 SPE 84354

Run # 2--- Angola, West Africa An 8-1/2” bit (ACS2) was developed for a hard, abrasive and highly heterogeneous application on the west coast of Africa in Angola. The section consisted of mudstone, sandstone, limestone and dolomite. Average unconfined compressive strengths ranged from 6 kpsi to 20kps throughout the interval and sometimes peaked at 40kpsi. Three bits (two PDC and one RC) had been used to drill this application, in a similar hole size on an offset well. A single ACS2 drilled the required section, and was pulled in an excellent condition, when compared to the offset runs (Figure 27). Performance comparisons are shown in (Table 5). The ROP of ACS2 was similar to the average achieved by the three bits on the offset well. Run # 3 --- Fremont County, Wyoming A 17-1/2” bit (ACS3) was developed for a challenging application in Wyoming. The formations, with average unconfined compressive strengths in the 6 to 9kpsi range, were not as hard as the ones previously described (runs 1 and 2). However, this application presented a different kind of challenge. The Shotgun formation, situated in the middle of the section at approximately 3100ft, is highly abrasive. Due to the low compressive strengths, lighter set bits (19mm cutters with reduced blade counts) are run to the top of the shotgun formation. These bits are then pulled for either a RC or heavier set PDC bit. Such a drilling program always compromised ROP on exiting the Shotgun, because of the low compressive strengths of the underlying formations. After various trials with different types of PDC bits, a project was initiated to improve performance in this application. The objective was to develop a PDC bit that could drill the top formations, the abrasive Shotgun formation, and a considerable amount of the lower section in a single run. An 8 bladed ACS3, with 22, 19 and 16mm cutters was developed for the application. With the 22mm cutters establishing full bottom hole coverage, this bit achieve ROPs comparable to that of the lighter set 19mm cutter bits. ACS3 achieved all the project objectives, and was pulled for PDM failure in a very good condition (Figure 28). The performance comparison of ACS3, to that of the offset bit runs is shown in (Table 6). The offset bits were usually pulled in a rung-out condition (Figure 29). Conclusions

• PDC bits have lacked performance consistency in hard rock drilling environments

• New Generation PDC cutters continue to improve PDC bit performance.

• Several cutting structures (SS, PS, AS) have had different effects on drilling efficiency.

• To be effective in such hard rock applications, PDC bits must be mechanically efficient

• In addition, relationships between WOB, ROP, wear flat generation and time must be re-defined.

• To enhance durability, diamond content (Tv) must be optimized.

• To enhance durability, diamond distribution (Av and Tv) must be maximized without compromising ROP.

• To extend bit life in hard rock environments, PDC cutters must only fail through wear.

• PDC cutter deterioration through wear is dependent on heat, and influenced by friction and drilling- time.

• Stabilization must be enhanced to minimize PDC cutter failure through impact damage

• Relationships between ROP, stability and durability must be optimized.

• To improve drilling efficiency, PDC cutter deterioration rate must be minimized.

• Performance Efficiency must be established, in order to extend PDC bits into hard rock applications

• New cutting structure (ACS) achieves the requirements needed to make PDC bits effective in hard rock drilling environments.

Nomenclature ROP - Rate of penetration (ft/hr) PDC - Polycrystalline diamond compact WOB - Weight on Bit (klbs) DOC - depth-of-cut (in/rev) ACS - Advanced cutting structure RPM - Revolutions per minute (revs/min) Ab - Borehole area (in2) σs - Shear strength of rock (psi) Ф - Diameter of PDC cutters (mm) b,m,s - Subscripts for big, medium and small cutter sizes Dt - On-bottom drilling time (hrs) Tv - Total diamond volume (in3) Av - Axial diamond volume (in3) Rv - Radial diamond volume (in3) SS - Single set cutting structure PS - Plural set cutting structure AS - Alternating cutter size cutting structure 1,2,3 - Subscripts used for different ACS bits Acknowledgement The authors will like to thank Peter Chan and Daniel “Brad” Stasney of GeoDiamond for their invaluable contributions in the development of the concepts described in this paper. Special mention also goes to Steve Ernst, Charles Douglas, Boktor Mikhail, Ian O’leary, Bruce Maddox and Robin Larder, all of Smith Bits for their analysis of the field data. To Christy Carl, also of Smith Bits, we say thank you very much for making it all possible. References 1. Glowka, D. A.: “The Use of Single Cutter Data in the

Analysis of PDC Bit Designs” SPE 15610, October 1986. 2. Cooley, C. H., Pastusek, P. F., Sinor, L. A.: “The Design

and Testing of Anti-Whirl Bits” SPE 24586, October 1992.

SPE 84354 7

3. Sinor, L. A., Warren, T. M.: “Application of Whirl Resistant Bits Gains Momentum” SPE 25644, April 1993.

4. Henneuse, H.: “Surface Detection of Vibrations and Drilling Optimization: Field Experience” SPE/IADC 23888, February 1992.

5. Nicholson, J.W.: “An Integrated Approach to Drilling Dynamics Planning, Identification and Control” SPE/IADC 27537, February 1994.

6. Fear, M. J., Abbassian, F., Parfitt, S. H. L., McClean, A.: “The Destruction of PDC Bits by Severe Slip-Stick Vibration” SPE/IADC 37639, March 1997.

7. Mensa-Wilmot, G., Calhoun, B.: “PDC Bit Durability – Defining the Requirements, Vibration Effects, Optimization Medium, Drilling Efficiencies and Influences of Formation Drillability” SPE 63249, October 2000.

8. Mensa-Wilmot, G., Alexander, W. L., “New PDC Bit Design Reduces Vibrational Problems” Oil and Gas Journal, May 1995.

9. Weaver, G. E., Clayton, R. I.: “A New PDC Cutting Structure Improves Stabilization and Extends Application into Harder Rock Types” SPE/IADC 25734, February 1994.

10. Mensa-Wilmot, G., Krepp, T.: “Innovative Cutting Structure Improves Stability and Penetration Rate of PDC Bits Without Compromising Durability” SPE/IADC 39310, March 1998.

11. Mensa-Wilmot, G., Booth, M., Mottram, A.: “New PDC Bit Technology and Improved Operational Practices Saves $1M in Central North Sea Drilling Program” SPE/IADC 59108, February 2000.

12. Sinor, L. A., Powers, J. R., Warren, T. M.: “The Effect of PDC Cutter Density, Back Rake, Size and Speed on Performance” SPE/IADC 39306, March 1998.

13. Mensa-Wilmot, G, Truax, D.: “Twin Edge Cutter (TEC) – Enhancing PDC Bit Development and Performance” SPE/IADC 37637, March 1997.

Figure 1 – Spalled PDC diamond table.

Figure 2 – New PDC cutters with stress engineered tungsten carbide interfaces. Figure 3 – PDC bits X and Y.

Figure 4 – ROP response of bits X and Y, tested in the laboratory under identical conditions to identify the different PDC rock failure mechanisms - scraping and shearing.

Bit X Bit YBit X Bit Y

ROP versus WOB for Bits X and Y

0

10

20

30

40

50

60

70

0 2 4 6 8 10 12 14 16 18 20

WOB, klbs

RO

P, ft

/hr

Bit YBit X

Transition Weight

8 SPE 84354

Figure 5 – Relationship between wear flat size and WOB generated ROP or DOC Figure 6 - Relationship between formation abrasiveness and friction characteristics Figure 7 - Effects of friction and drilling-time on PDC cutter deterioration through wear. Beyond the heat threshold, PDC cutters experience accelerated wear.

Figure 8 – Friction/drilling-time coordinates of three formations with different abrasiveness and/or hardness characteristics Figure 9 - Wear flat growth rate vs. time based on WOB influence. Figure 10 - Diagram showing required ROP’s influence on the "wear - increased WOB-increased wear" cycle.

Wea

r Fla

t Siz

e

ROP (DOC)

Wea

r Fla

t Siz

e

ROP (DOC)

Fric

tion

Cha

ract

eris

tics

Abrasiveness

Fric

tion

Cha

ract

eris

tics

Abrasiveness

Fric

tion

Drilling-time

Heat thresholdFric

tion

Drilling-time

Heat threshold

Fric

tion

Drilling-time

A

BC

Fric

tion

Drilling-time

A

BC

Wea

r fla

t gro

wth

rate

Time

Wea

r fla

t gro

wth

rate

Time

RO

P

WOB

RO

P

WOB

SPE 84354 9

Figure 11 - Single set cutting structure (SS). Each cutter occupies a distinct radial position Figure 12 - Plural set cutting structure (PS). With this layout, multiple cutters have identical radial positions Figure 13 - Alternating cutter size cutting structure (AS). This layout has two different cutter sizes, with each size establishing complete and independent bottom hole coverage

Figure 14 - Advanced Cutting Structure (ACS), which uses three different cutter sizes. The largest and medium sized cutters establishing complete and independent bottom hole coverage. Figure 15 - ROP response of three 8-1/2" PDC bits (X, M and N) with different cutting structures (PS, AS and ACS), tested in the laboratory under identical conditions. Tests were aimed at establishing cutter size effect on ROP as well as quantification of mechanical efficiency. Figure 16 - 8-1/2" PDC bits (X, M and N) tested in the laboratory.

Bit X Bit M Bit NBit X Bit M Bit N

ROP versus WOB

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20

WOB, klbs

RO

P, ft

/hr

Bit N

Bit M

Bit X

10 SPE 84354

Figure 17 - Representation of Radial (Rv) and axial (Av) diamond volumes on a PDC bits. Av and Rv have an inverse relationship for single cutter size bits (SS and PS). Figure 18 - Profile segment of ACS cutting structure showing maximized radial diamond volume (Rv) due to presence of smallest cutter size Figure 19 - Accelerated PDC cutter wear, due to initial diamond table loss from impact damage, as a result of vibrations.

Figure 20 - Highly uneven bottom hole pattern of ACS cutting structure due to differences in curvature between the three different cutter sizes. Figure 21 - Vibration characteristics of bit K (single set) and bit C (Alternating cutter size) tested in the laboratory in the same rock type and under identical conditions. Figure 22 - Bit K (SS) and bit C (AS)

Bit CBit K Bit CBit K

Bit K Bit CBit K Bit C

SPE 84354 11

Figure 23 - Lithological description showing formation hardness and heterogeneity of Northern Kuwait 16" application. Figure 24 - Initial PDC bit with AS cutting structure, used to establish benchmark in 16" Northern Kuwait drilling program. Test program was successful as bit ended up replacing 6 roller cone bits at a much higher ROP.

Figure 25 - ACS cutting structure bit (ACS1) developed for 16" Kuwait application. Bit had 8 blades with 19, 16 and 13mm cutters. Bit and was 250% faster than the RC bits (6 in total) used on the offset well. Figure 26 - Dull picture of ACS1 used in 16" challenging North Kuwait application. Figure 27 - Dull condition of 8-1/2" ACS cutting structure bit (ACS2) used in hard formation Angolan application in West Africa.

12 SPE 84354

Figure 28 - Dull condition of 17-1/2" ACS cutting structure (ACS3) used in challenging Fremont County, Wyoming application. This bit drilled the top formations at very high ROPs and all of the abrasive shotgun formation.

Figure 29 - Common dull characteristics of offset bits used in the abrasive shotgun formation.

Table 1 - Test conditions use in the laboratory to identify the scraping and shearing modes of 8-1/2" PDC bits X and Y.

Table 2 - Design attributes of 8-1/2" PDC bits X (Plural Set), M (Alternating Cutter Size) and N (Advanced Cutting Structure) Table 3 - ROP comparisons between 8-1/2" PDC bits K (Single Set) and C (Alternating Cutter Size) tested in the laboratory under identical conditions.

Rock Type Carthage LimestoneCompressive Strength 18 kpsi

Rotary Speed 120 rpmW OB Range 6 - 18 klbs

Flow Rate 350 gpmNozzles Sizes 4X11 and 2X10

Mud W eight 9.5 ppgBorehole Pressure 1100psi

Type Cutting Structure Blade Nozzle Bit Profile Back Rakes Cutter Sizes Cutter Counts Cutter Count Count Count Cone/Nose/Shoulder/Gage Face/Gage Total

Bit X Plural Set (PS) 8 6 Long Parabolic 5&10/15/20&25/30 13mm 48/12 60Bit M Alternating Cutter Sizes (AS) 9 6 Medium Parabolic 15/20/25/30 13 and 9mm 60/12 72Bit N Advanced Cutting Structure (ACS) 8 6 Medium Parabolic 15/20/25/30 13, 11 and 9mm 45/14 59

Bit K Bit CWOB @ 120 rpm ROP (ft/hr) ROP (ft/hr) ROP (% Change)

12 20.36 23.3 14.4

15 27.5 35.2 28

18 35.44 49 38.3

21 41.76 70 68

SPE 84354 13

���������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������

Well Name Hole Size Bit Type Out (ft) Footage Drilled ROP (ft/hr) Flow Rate (gpm0 MW (ppg) I O DC L G O RPRC1 10895 248 4.4 784 13.0RC2 11459 503 4.9 744 14.0 4 7 BT G IN HRRC3 11759 300 4.7 703 14.0 3 4 WT A IN NO HRRC4 12086 327 3.8 732 14.0 4 5 WT A IN PRRC5 12434 348 3.3 732 14.0RC6 12766 332 2.8 718 14.8 TDAS1 12472 1947 8.5 757 12.3 2 3 BT A IN WT BHAAS2 13075 603 10.6 732 13.3 0 1 NO A IN NO TD

Well C (offset 3) 16" ACS1 13180 2133 13.2 860 13.5 1 1 CT G IN WT TD

16" Section - Northern Kuwait

Well A (offset 1) 16"

Well B used 2 AS bits to drill 2550' at an overall ROP of 8.9 ft/hrWell C used 1 ACS 1 to drill 2133' at 13.5 ft/hr

Well A used 6 roller cone bits to drill 2058' at an overal ROP of 3.9 ft/hr

Well B (offset 2) 16"

Table 4 - Performance comparison between ACS1 and other bits used on offset wells in 16" hard formation application in Kuwait.

Table 5 - Performance comparison between ACS2 and other bits used in offset well in hard formation application in Angola

������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������

������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������Well Name Bit Types Depth Out (ft) Ftg. Drilled ROP (ft/hr) Flow Rate (GPM) MW (ppg) Dull Grade (Inner) Dull Grade (Outer) Reason Pulled

PDC1 3150 1680 57.9 1005 10.5 1 4 DMFWell A (Offset 1) PDC2 3524 374 24.9 1005 10.5 1 8 PR

PDC3 7126 3359 27 990 11.2 2 8 PRPDC4 4276 2683 35.3 1000 11.4 7 8 PRPDC5 6019 1743 39.2 980 11.6 1 8 PR

Well C ACS3 5836 4401 51.5 1005 11 1 2 DMF

Well A: 3 PDC bits drilled 5413 ft at 32 ft/hrWell B: 2 PDC bits drilled 4426 ft at 36.7 ft/hrWell C: 1 ACS3 bit drilled 4401 ft at 51.5 ft/hr

Well B (Offset 2)

17-1/2" Section - Fremont County, Wyoming

Table 6 - Performance comparison between ACS3 and other bits used on offset wells in challenging Wyoming application

������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������������

Well Type Out Footage Drilled ROP (ft/hr) Flow Rate (GPM) MW (ppg) Dull Grade (Inner) Dull Grade (Outer)

Well A ACS2 8640 5568 28.7 506 10.3 1 2PDC1 4391 1221 61.1 480 10.0 1 1RC1 6163 1772 35.1 460 10.1 2 3

PDC2 8624 2461 22.5 506 10.1 6 8Well B - Offset

8-1/2" Section - Cabinda, Angola