drilling bits

Drilling activity has increased in the last couple of years, with wells being drilled deeper and into harder and more-abrasive formations. These drilling environments present serious chal-lenges for drill bits in terms of rate of penetration (ROP) and bit durability. The high drilling-activity level and increased demand led to increased rig rates. To reduce drilling costs, drilling engineers have had to re-evaluate bottomhole-assembly

designs, drilling processes, drilling fluids, and applications.

Drill bits, although insignificant in terms of price, have huge effects on opera-tional costs. To improve drilling performance, considering the challenges, drill bits must drill faster and last longer. These targets are what drilling engineers have come to expect and what bit companies are delivering to the industry.

Several types of drill bits are available for different applications and drilling chal-lenges—polycrystalline-diamond-compact (PDC), impregnated, and roller-cone bits. To reduce drilling costs substantially in the current environment, technol-ogy development must expand and permeate into all the different bit types.

For PDC bits, new modeling tools and bit designs are being developed on a continuous basis. Bit-behavior analysis, especially the characterization of the different vibration modes, has become a standard in the bit-design process. New PDC cutters with very high abrasion-resistance properties continue to be developed. These cutters stay sharper for longer periods of time, thus improv-ing ROP and durability.

Substantial ROP and durability improvements are also being seen with impregnated bits. These improvements resulted from detailed evaluations that focused on the effects of drive tools (rotation speed and power regime), down-hole-pressure environment, and depth of cut on impregnated-bit development and performance.

For roller-cone bits, new technologies are improving seal reliability and cut-ting-structure durability. In addition, new developments in metal-seal-bearing technology have drastically increased the on-bottom drilling time of roller-cone bits, especially in directional wells.

Drill-bit companies have accepted the challenges, and they do not plan on slowing down.

Graham Mensa-Wilmot, SPE, is Vice President of Engineering and Research for Varel Intl. He has more than 20 years of experience in drilling research and technol-ogy development. Mensa-Wilmot serves on the SPE Drilling Technical Committee, SPE/IADC Drilling Conference Program Committee, the Technical Review Committee of SPE Drilling and Completions, and the JPT Editorial Committee. He earned an MS degree in drilling engineering from Romania’s U. of Petroleum and Gas.

OVERVIEW

BIT TECHNOLOGY

Bit Technologyadditional reading available at the SPE eLibrary: www.spe.org

SPE 102182 “Coupling of Downhole-Dynamics Recorder Enhances System-Matched Approach to Drill-Bit Design and Application With a Specific Rotary-Steerable System” by S. Barton, SPE, ReedHycalog, et al.

SPE 102134 “Vibration Analysis, Model Prediction, and Avoidance: A Case History” by G. Robello Samuel, Halliburton Drilling, Evaluation, and Digital Solutions, et al.

SPE 99193 “Real-Time Downhole Torsional Vibration Monitor for Improving Tool Performance and Bit Design” by D.C.-K. Chen, Halliburton Sperry Drilling Services, et al.

JPT

72 JPT • DECEMBER 2006

A new process for manufacturing poly-crystalline-diamond compact (PDC) cutters creates a wrapped thermo-stable region across the face and around the periphery of the PDC cutter. This differs significantly from existing first-generation thermostable product because the treated region has complex geometry in three dimen-sions. The full-length paper describes the new cutter geometry and shows how the thermostable region supports the cutter as it slowly wears.

IntroductionHistorically, there has been a trade-off between abrasion and impact resistance of PDC cutters. Typically, impact resis-tance was achievable by use of a larger diamond grain size but at the expense of abrasion resistance. The first attempts to extend the envelope of PDC-bit and -cutter performance occurred in the mid-1990s when multimodal polycrys-talline diamond was introduced. This used a mixture of grit sizes from 50 to 2 µm in diameter, allowing the smaller grits to fill the voids left between the larger particles, resulting in a much denser polycrystalline-diamond layer that improved abrasion resistance.

Additional improvement was achieved by use of nonplanar inter-faces. The move from planar to nonpla-nar interfaces was driven by a desire to reduce stresses at the interface between the polycrystalline diamond and its tungsten carbide substrate.

The introduction of the nonplanar interface combined with the multimod-al polycrystalline-diamond mix pro-vided significant improvement in both relative toughness and relative wear life over planar multimodal materials. The thicker diamond edge that resulted improved relative abrasion life.

Thermostable PDC CuttersCobalt normally is present in the cre-ation of polycrystalline diamond in the PDC press. It is introduced in the tung-sten carbide support, where it acts as a cement. At the elevated temperature and pressure where diamond-to-diamond bonding occurs, the cobalt migrates into the diamond grit and helps to cata-lyze the bonding process. It also forms a bond with the tungsten carbide sub-strate and ensures that the PDC is one integral component. However, cobalt significantly reduces the thermal stabil-ity of the PDC because it has a greater coefficient of thermal expansion than the surrounding diamond particles. Between 700 and 760°C, the cobalt expands and forces the diamond-to-diamond bonds apart. This results in the rapid breakdown of the compact. What appears to be abrasive wear when a dull PDC bit is analyzed often can be the result of the breakdown of the diamond-to-diamond bonds because of overheating. Therefore, it is important that the temperature of the PDC cutter is maintained below 700°C to avoid thermal breakdown. Unfortunately, the cutting-tip temperature often exceeds this critical limit.

Thermally stable product (TSP) dia-mond can be manufactured to overcome the temperature limitations of PDC. This can be made either by leaching synthetic diamond with acid to remove all of the cobalt or by adding silicon to form silicon carbide (by reaction with the diamond particles) to act as a

binder phase for the diamond in place of the cobalt. The removal of cobalt, or the low thermal-expansion coefficient of the silicon carbide, ensures that these TSP materials are thermally stable to temperatures higher than 1150°C. However, because of the lack of cobalt in the structure, these forms of TSP are not readily “wetted” by braze alloys and must be retained mechanically. In addi-tion, the removal of cobalt significantly weakens the mechanical structure, and the abrasion resistance of TSP is an order of magnitude less than that of PDC because its structure is designed to be more open to allow total leach-ing. The thickness necessary to provide structural strength precludes an effec-tive self-sharpening action.

It was the partial removal of cobalt, by partial and preferential leaching, that provided the long-awaited break-through. Taking a pressed PDC and leaching the cobalt to a predetermined depth created a completely new class of cutter—thermostable PDC cutters.

As the cutter wears, a lip is gen-erated from the preferential wear of nonleached, nonthermostable poly-crystalline diamond because of ther-mal breakdown at temperatures greater than 700°C. The relatively thin, leached layer at the front of the cutter does not

This article, written by Assistant Technology Editor Karen Bybee, con-tains highlights of paper SPE 102067, “Faster, Longer, and More-Reliable Bit Runs With New-Generation PDC Cutter,” by J. Clegg, SPE, ReedHycalog, pre-pared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Faster and Longer Bit Runs With New-Generation PDC Cutter

BIT TECHNOLOGY

Fig. 1—New-generation thermo-stable PDC cutter.

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

JPT • DECEMBER 2006 73


have the same temperature limitation and wears more slowly. This clearly demonstrates that cutting-tip tempera-tures do exceed 700°C.

When introduced commercially, these new cutters generated signifi-cant improvements in abrasive life as a result of thermal stability. Significant improvements in rate of penetration (ROP) also were achieved, partly by delaying the onset of wear and partly as a result of stress concentration in the rock resulting from the formation of the distinctive lip.

As well as improving performance in conventional PDC bit applications, this also allowed PDC bits to drill forma-tions that had been believed to require insert bits. As a result, in 2005, PDC-bit sales exceeded U.S. $1,000,000 and accounted for more than 50% of foot-age drilled for the first time.

New-Generation Thermostable GeometryWhere the existing thermostable designs had a 2D leached layer, the new-generation cutters extended it into 3D space. The leached layer across the face of the cutters was supplement-ed with a “ring” of leached material around their periphery (Fig. 1). This was expected to improve performance in three ways. First, the presence of additional thermostable material in the region of the cutting tip further delays the onset of wear compared with the first-generation thermostable cutters. This, in turn, delays both the devel-opment of wear flats and the point at which the tungsten carbide substrate begins to rub on the formation. Once the carbide begins to rub, heat dissipa-

tion from the cutting region is compro-mised and cutter wear is accelerated. Second, once the thermostable mate-rial eventually wears, a “dual-lip” cut-ting structure develops. This enhances ROP because both edges cut the rock. Third, a crescent-shaped lip is formed that supports and supplements the lip observed in first-generation thermo-stable cutters. This may make the over-all cutter tougher—through improved geometry—and, in particular, more resistant to reverse cutter motion and to axial impact loads.

Laboratory TestsLaboratory tests were conducted to evaluate potential impact and wear resistance. Impact testing showed no significant difference in material prop-erties from the previous generation of thermostable cutters or from the multi-modal, nonplanar-interface cutters that preceded them.

One wear test required that the cut-ter be plunged into a premachined quartzite block and traversed across it as the block was rotated, to simulate the cutting action downhole in a full-scale drill bit. The onset of wear and thermally induced damage was acceler-ated because the cutter was run with no cutting fluid. The test terminated when the cutter burned out and a black line appeared on the rock, indicat-ing gross graphitization of the base polycrystalline-diamond material. The new-generation thermostable material showed a 75% improvement in wear resistance over existing thermostable cutters and an even more impressive 270% improvement over base material. All tests were conducted on chamfered

13-mm-diameter×13-mm-long PDC cutters. The results were consistent and repeatable and promised sufficiently dramatic improvement to move to con-trolled field tests.

Field TestsForty bits were built for controlled field testing. The tests were designed so that the only change was to the cut-ter type, so that any overall change in performance could be attributed to the new cutters. Second, the performance improvement observed would be with reference to the existing first-genera-tion thermostable cutters, which had already established significant perfor-mance improvements over premium-quality nonleached PDC cutters.

The field results with the new cut-ters showed very significant improve-ments in performance over the existing first-generation thermostable-cutter-equipped bits in hard, abrasive forma-tions. The best improvement in footage drilled in an individual case was 349%. In terms of ROP, the best individu-al improvement achieved was 144%. Mean improvements were 43% mean improvement in footage drilled and 26% mean improvement in ROP.

The improvement in footage drilled clearly results from the superior abrasion resistance of the cutters, as evidenced in laboratory testing. The improvement in mean ROP arises from delaying the onset of significant wear to the cutter and maintaining the cutter in a sharper, more-efficient form for a longer time.

Recent Field ResultsSince commercialization, many bits with the new-generation thermostable

Fig. 2—Dull 616 bit. Fig. 3—Scatter plot of ROP vs. footage drilled.


cutters have been run successfully. The full-length paper presents six case stud-ies to illustrate performance benefits.

Case 1. An 81/2-in.-diameter, 6-bladed, 16-mm-cutter (616) bit was run on a point-the-bit rotary-steerable system in the Cretaceous and Jurassic formations of the U.K. sector of the North Sea. Typically, drilling the section required two or three bits. This bit drilled it in a single run. ROP was limited by equivalent-circulating-density consid-erations, but the bit broke the field record for footage drilled. The field record of 1380 m had been set by the same bit design equipped with first-generation thermostable cutters. The second-generation bit drilled 2408 m, shattering the field record by 75%. The dull condition after this run was very good (Fig. 2).

Case 2. A 61/8-in.-diameter, 8-bladed, 13-mm-cutter (813) bit is regular-ly used to drill the very hard and abrasive Cotton Valley formations in Jackson Parish, Louisiana. This bit is equipped with a full-ring gauge design successfully used in the area with first-generation thermostable cutters. In this location, six bits of this design have been used with first-generation thermostable PDC cutters and nine bits with the new-generation thermo-stable PDC cutters. The bits have been run through similar formations, aver-age depth in for the two sets of runs differs by only 18 ft. Fig. 3 shows a scatter plot of ROP vs. footage drilled for the two sets of runs. On average, the new-generation thermostable-cut-ter-equipped bits have drilled with a 6% improvement in ROP and a 91% improvement in footage. Fig. 4 shows the bit. JPT

Fig. 4—Bit used in Case 2.

Resources


Drilling the hard and very abrasive Bunter formation in northwest Germany has been a challenge for 40 years. Low rates of penetration (ROPs) and high tool wear are common. The full-length paper details the analysis of histori-cal data and the combination of bits, motors, and other bottomhole-assem-bly (BHA) components to improve ROP. The combination of new impregnat-ed bits, new downhole motors, and improved hydraulics was the basis for the improvement.

IntroductionThe Bunter, a hard and very abrasive formation, typically at a depth of 8,000 to 12,500 ft, consists of layers of quartz-itic sandstone and silificated claystone with a compressive strength of 30 to 50 ksi. In the past, typical ROPs in 121/4-in. sections were 3 to 6 ft/hr. In the 1970s and 1980s, 15 to 20 insert bits were required to drill the section and reaming was necessary as a result of undergauge bits.

In the 1990s, a research project was initiated and funded by the German drilling industry to improve ROP in ultrahard and abrasive formations. In the past, the Bunter was characterized by the lowest ROP, shortest bit life, and highest cost per foot. Increasing the depth of cut (DOC) of impregnated bits in the Middle and Lower Bunter was identified as having potential for improvement. DOC means the length that is drilled with one revolution of the bit. An increase in DOC can be

achieved by a decrease in overbalance or an increase in the amount of power available for drilling the rock. To ana-lyze the key parameters, drilloff tests or drilling tests at fixed drilling param-eters were conducted and plotted into Bingham diagrams.

Within the German drilling industry, two approaches to increase ROP have been chosen—use of downhole tur-bines and use of high-speed downhole motors in combination with improved hydraulics made possible by larger-inside-diameter drillpipe.

The full-length paper details results from downhole-motor runs with impregnated bits. All results are from 121/4-in. bits because this is the most common bit size used in Germany for the Bunter formation.

Rotary Speed. Until 1997, the standard for high-speed downhole motors was 400 rev/min at 790 gal/min (360 hp). In 1997, a 91/2-in. downhole motor was tested in Germany at 780 rev/min at 849 gal/min (515 hp). In 2004, a new 91/2-in. downhole motor was developed that delivers 975 rev/min at 1,055 gal/min (1,025 hp).

Weight on Bit (WOB). In 2004, the maximum WOB for high-speed downhole motors was approximate-ly 48,100 lbm. With the 975-rev/min

downhole motor, maximum WOB increased to 60,700 lbm because of improvements in bearings.

Flow Rate. In northwest Germany, salt sections occur at relatively deep depths above the Bunter. The mud weight required to drill the salt varies from 13.3 to 15 lbm/gal. With 5-in. drillpipe, flow rates with this mud weight are limited to 600 to 660 gal/min. Because of this high mud weight and low flow rates, turbines could not be used effec-tively because of the high differential working pressure. Downhole motors were preferred.

Today, use of 6-in. drillpipe allows operation of the 975-rev/min down-hole motor up to the operational lim-its of these motors. Even at 13.3- to 15-lbm/gal mud weights, the 5,000-psi rig pumping-pressure limit is sufficient.

DOC. Impregnated-bit DOC depends on rotary speed, WOB, and flow rate. Flow rate has a direct influence on bot-tomhole cleaning, which affects ROP. The influence and relationship of these parameters must be derived from actual drilling data and drilloff tests.

Data at different bit rotary speeds were collected for 400-, 780-, and 975-rev/min-motor applications. Plot-ting these data at a constant WOB shows DOC decreasing with increasing

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 99045, “ROP Enhancement in Ultrahard Rock,” by M. Roehrlich and K.-U. Belohlavek, ExxonMobil Development Co., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.

Improved ROP in Ultrahard Rock

BIT TECHNOLOGY

Fig. 1—Impregnated bit with continuous (left) and interrupted (right) cut-ting structure.



rotary speed. DOC is directly related to WOB and increases with increasing WOB. The DOC for a given WOB is greater at higher flow rates.

Overbalance The effect of overbalance on drilling is well known in the drilling industry. Drilloff-test data show that the influence of flow rate is larger in very-high-over-balance situations. Wells that did not achieve noticeable DOC at flow rates less than 660 gal/min had high differen-tial pressures at bottom. This leads to the conclusion that a bottomhole bit-balling effect occurs at high overbalance. A bed of fine cuttings and mud components hinders the diamond/formation contact at insufficient flow rates. An increase in flow rate leads to cleaning of this debris, resulting in a greater DOC.

New Downhole MotorDrilloff-test results show an almost linear relationship between DOC and flow rate. A new downhole motor was developed and built in 2004 to increase DOC by increasing flow rates. This new downhole motor uses a new stator tech-nology. Instead of a conventional stator, the stator is precontoured in the steel of the stator pipe and covered by a thin layer of polymer. Because of improved bearings, higher WOB can be used and motor durability is improved.

Bits and StabilizersNew materials and manufacturing processes made it possible to build third-generation impregnated bits. A typical impregnated bit used to drill the Bunter formation in the late 1990s had a continuous cutting structure (Fig. 1). Typically, these bits were worn down after less than 500 ft in the Bunter. The diamond quantity was increased to make the bits more durable. A third-generation 121/4-in. impregnated bit has almost four times the diamond quantity of a first-generation impregnated bit. Improved cooling of the impregnated-bit segments in the new-generation bit was accomplished by an interrupted cutting structure and optimized fluid courses (Fig. 1). Bits with a long gauge now are used with high-speed motors to prevent a spiral hole and to replace the near-bit stabilizer that wore down very quickly at high rotary speeds, espe-cially in deviated holes.

Stabilizer wear also is an issue for wellbore and well-path quality. Some of

the conventional stabilizers protected by tungsten carbide showed total wear after a 140-hour run in the Bunter for-mation. A new stabilizer design with diamond protection was tested in four runs in three Bunter sections for a total length of 2,960 ft and 240 hours. The new stabilizer design shows a signifi-cant reduction in wear and contributes to a better-quality wellbore.

Field DataDuring the last 3 years, data from six wells drilled through the Bunter section with 780- and 975-rev/min downhole motors and impregnated bits were col-lected and analyzed.

Well A. In 2003, a combination of new-design 121/4-in. bit, 91/2-in. 780-rev/min motor, and 65/8-in. drill-pipe was run for the first time. Total footage drilled was 2,507 ft and the inclination was increased from 36 to 48°. At the first roundtrip after drill-ing 1,093 ft of the Middle Bunter, the remaining cutting structure height of the original 1.0 in. was 0.4 in. The remaining 1,414 ft of the section was drilled with a new bit. When pulled out of the hole, the second bit had a remain-ing cutting-structure height of 0.7 in. Overbalance in this well was 1,650 psi.

Well B. Well B, drilled in 2004, was the fifth well in a field. The same type of BHA was used as in Well A, including the impregnated bit from the second bit run of Well A. The mud weight was nearly at balance with the pore pressure in the Bunter. For the first time in this field, the 1,920 ft Bunter section was drilled in one run with a 121/4-in. BHA. Average ROP was 14.7 ft/hr, which is twice the speed attained in the preced-ing wells in this field.

This bit drilled a total of 3,333 ft in two runs and set a world record for 121/4-in. impregnated bits. After approximately 15 million revolutions at more than 750 rev/min in deviated wells, the bit was still in gauge.

Well C. In Well C, drilled in 2004, two different high-speed downhole motors were used. Mud weight was nearly at balance with the pore pressure in the Bunter. ROP in previous wells in this field in the 1990s was approximately 3 ft/hr in 81/2-in. holes and less in 121/4-in. holes. Average ROP in this well was 8.8 ft/hr, and maximum ROP

was nearly 10 ft/hr. The main differ-ences between the motors were trans-mission and limitations in flow rate.

Data from drilloff tests of both motors at different flow rates were plotted. The curves indicate potential for DOC improvement at lower rotary speeds and at significantly lower flow rates. However, a minimum flow rate for sufficient bit cooling and hole cleaning must be guaranteed.

Well D. In 2004, a prototype of the 975-rev/min downhole motor was used for the first time in Well D. At a 1,055-gal/min maximum flow rate and 60- to 100-rev/min string rotary speed, the bit was rotating at more than 1,000 rev/min. A 19-ft/hr maximum ROP was achieved at maximum flow rate and a WOB that was limited operational-ly to 50% of nominal. This ROP is a 20% increase from Well A at the same WOB and a lower flow rate of 845 gal/min. Average ROP was 12.9 ft/hr.

Well E. In 2005, Well E was drilled in close proximity to the field of Well C. Average ROP on this well was 10.1 ft/hr. In this well, the new diamond-pro-tected stabilizer was run for the first time, and it was the second application of the 975-rev/min motor. At a high WOB, the bit wear in the upper part of the Middle Bunter formation was much higher than expected. It was found that, in these extremely hard and abrasive formations, high temperatures were generated at the bit and even 1,000-gal/min flow rates were not suffi-cient for bit cooling. The diamond-pro-tected stabilizer was still in good shape and was run in Well F after finishing the Bunter section on this well.

Well F. Well F was drilled in 2005 in the same region as Well D. The average ROP on this well was 13.1 ft/hr. The BHA in this well was similar to the one used in Well E, with the 975-rev/min motor and the diamond-protected sta-bilizer. The impregnated bit on this well was from a different manufacturer but had a similar quantity of diamonds. Bit specifications and bit-wear experiences in Well E were reasons for initial WOB limitations. The entire 1,517-ft section was drilled with one bit that showed 50% wear and was still in gauge when pulled out of the hole. The diamond-protected stabilizer was good for anoth-er run in the next Bunter section. JPT


Operators in the Gulf of Mexico (GOM) are constantly looking for ways to reduce the costs of drilling develop-ment wells. A new steel-tooth (ST) roller-cone bit with an advanced metal-seal bearing has achieved this goal and is having a significant effect on drilling economics. Improvements in bearing life, seal reliability, and cutting-struc-ture durability have resulted in more time on bottom, giving the operator the confidence to use the new roller-cone bits in long directional hole sections.

IntroductionWith large regions of the GOM rapidly becoming mature provinces, operators are looking for ways to reduce the costs of drilling development wells. Most of the wells drilled are directional, and heavy water-based drilling fluids often are required in the intermediate hole sections. Relatively high bottomhole temperatures combine with high bot-tomhole pressures and balling shales to present a challenging drilling environ-ment. Operators strive to increase rate of penetration (ROP), maximize hours on bottom for each bit, reduce risk, and complete the section with fewer bits to reduce the number of trips.

Improved roller-cone bits with an innovative single-energizer metal-seal (SEMS) bearing were introduced in 1998 (Fig. 1). A step change in bit life was realized, yet it took a year or two

for operators in the GOM to gain suf-ficient confidence in the new ST bits to run them harder and leave them in the hole longer. By 2000, operators routinely were achieving runs as much as twice as long as was typical with the predecessor elastomer-sealed ST bits, particularly at higher rotary speeds (e.g., 175 to 275 rev/min). In 2000, enhanced ST cutting structures were introduced to complement the SEMS bearing (Fig. 2). The new ST cutting structure provided longer tooth life by improved tooth wear resistance and reduced tooth breakage.

GOM Drilling EnvironmentThe GOM drilling environment is one of the most diverse in the world. With exploration and development programs taking wells to ever greater depths, the demands placed on ST roller-cone bits and their sealed-bearing sys-tems become increasingly severe. The increased service life and reliability of rotary-steerable systems and top-of-the-line motor assemblies allow them to successfully drill long, complex well paths, which increases the directional challenges for roller-cone bits. Both

concentric and eccentric hole-opening technologies place unique loading con-ditions on roller-cone bits when they are used as pilot bits.

The drive toward improved drilling economics in the GOM demands that individual bits drill farther and faster than in previous years. Drilling these challenging hole sections with fewer bits per section is the ever-present goal. Sealed-bearing roller-cone bits cannot drill increasingly longer hole sections unless their demonstrated bearing life and reliability justify confidence on the part of the operator to leave the bit in the hole longer.

Many GOM well programs include 81/2-in. hole sections in the 12,000- to 18,000-ft measured-depth (MD) range, with mud weights (MWs) from 17 to 19 lbm/gal. Such high mud weights require high solids content in the mud. The combination of MD and high MW results in very high bottomhole pressures. The main chal-lenge from a bit perspective is being able to withstand these high pressures exerted on the bearing seals, as well as effectively resisting the deleterious effects of mud solids.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103074, “Step Change in Performance: Upgraded Bit Technology Significantly Improves Drilling Economics in GOM Motor Applications,” by B. Grimes, SPE, and B. Kirkpatrick, Hughes Christensen, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.

Step Change in Performance: Upgraded Bit Technology Improves Drilling Economics

BIT TECHNOLOGY

Fig. 1—SEMS bearing with enlarged view of seal package.



Wear AnalysisA research project was initiated in 2003 to improve the sealed-bearing life and reliability of 81/2-in. Intl. Assn. of Drilling Contractors (IADC) Code 117 ST SEMS bits. Ten 81/2-in. IADC Code 117 dull SEMS bits used in the GOM were examined. The follow-ing bearing-seal-related wear/failure modes were observed to be the prima-ry life-limiting factors in this drilling environment.

1. Worn metal-seal faces—the metal-seal system has a finite, relatively con-stant wear rate that typically provides longer service life than elastomer-sealed bearings. The position of the relatively narrow polished seal band can be measured accurately. The seal band starts out on the outside of the seal face and slowly wears across the seal face to the inside diameter, at which point the seal is totally con-sumed. The subject dulls experienced an average 65% metal-seal wear after 400,000-revolutions service.

2. Tribological examination of the narrow metal sealing band indicated that galling often occurs between the two mating stainless-steel seal faces. Galling is an adhesive wear mechanism associated with similar materials in slid-ing contact under pressure. Small wear particles are transferred back and forth between the wear surfaces, which can result in a roughened, smeared appear-ance. Galling can produce decreased sealing efficiency and advanced wear rates in metal-seal applications.

3. An elastomeric O-ring energizer is used to seal and anchor the metal seal ring to the head section. The energizer also urges the metal-seal ring against the polished end of the cone seal insert, which constitutes the second

metal-seal face. The head seal ring and energizer normally are station-ary on the head bearing, while the cone seal insert rotates with the cone so that all relative rotational sliding occurs between the two metal seal faces. Drilled fines, mud solids, and mud packing that make their way into the head seal ring and energizer cause the head seal and energizer to rotate on the head section. This is an undesirable condition because the O-ring energizer ceases to be a static seal and temporar-ily becomes a dynamic rotating seal. Energizer slippage quickly degrades the energizer to the point that seal failure occurs, even with remaining metal-seal-face life.

4. The specially shaped low-modu-lus backup ring (BUR) is positioned on the mud side of the O-ring ener-gizer. The BUR contributes to the total seal-face load and serves as an addi-tional anchor to keep the head seal ring and the energizer from rotating. It also occupies a volume that routinely filled up with mud and cuttings in the older dual metal-seal-face design. The BUR may become damaged from excessive mud packing in service; it also will wear very quickly if energizer slippage occurs.

Metal-seal-face wear and/or galling, energizer slippage, and damaged ener-gizers and BURs will all result in even-tual seal failure, whereby grease is lost from the sealed-bearing system and drilling mud and cuttings contaminate the bearing. Seal failure in service will result in accelerated bearing wear and cone drag, which produces cutting-structure wear and damage. Continued operation in a seal-failed condition will produce progressive wear of the head and cone bearing surfaces, eventually resulting in cone loss in the hole. Cone loss is extremely undesirable in the GOM because of the associated down-time and fishing services to retrieve the cone. A consistent, long-life bear-ing with a very low failure rate will allow an operator to drill wells much more cost-effectively, with a low risk of failure.

New Sealed-Bearing DesignThe new SEMS2 sealed-bearing pack-age was developed with specific fea-tures to address the wear/failure modes observed. The metal-seal cross-sec-tional width was increased approxi-mately 20%. Because metal-seal wear

is relatively linear, this results in a 20% increase in potential seal capacity.

A proprietary surface treatment was applied to the metal-seal face on the cone seal insert. The surface treatment produces an extremely hard, thin layer on the metal-seal face, which signifi-cantly decreases the seal wear rate and reduces the friction coefficient at the seal faces. Galling is essentially elimi-nated because the two seal faces are no longer identical materials. The surface treatment also allows high seal-face loads to be specified for high sealing efficiency, yet the high hardness and low friction result in a greatly reduced seal wear rate. The 10 SEMS dull bits from the GOM averaged 65% seal wear in 400,000 revolutions, while eight new SEMS2 bits averaged only 43% wear in 500,000 revolutions.

The new BUR was stress engineered by use of finite-element analysis to pro-vide a more robust shape with improved ability to keep out debris, and it is seated in an improved seal gland. Thus, the new BUR can protect the metal seals better from mud packing over an extended service life. Redesigned seal-energizer-seat geometry improves sealing efficiency, maintains constant face loads during axial cone movement, and provides increased seal-face loads to resist energizer slippage better and increase seal efficiency. An advanced pressure compensator and proprietary grease formulation combine to mini-mize torque, reduce heat, and increase bearing load capacity.

Case Study 1Case Study 1 called for drilling inter-bedded sand/shale sequences offshore Matagorda Island. The objective was to develop technology that would allow the operator to reduce drilling costs by eliminating the nonproductive time consumed tripping for new bits while increasing the amount of on-bottom time with each bit.

After an in-depth analysis of off-set information, the service company’s engineers selected an ST bit that would drill the 81/2-in. section efficiently. Key components included the premium SEMS2 metal-seal package for supe-rior bearing reliability and patented hardfacing technology to ensure cut-ting-structure integrity throughout the run. The newly designed 81/2-in. IADC Code 117 was run with exceptional results, drilling 2,820 ft of formation at

Fig. 2—New 81/2-in. IADC Code 117 ST bit.


43.4 ft/hr and completing the section in 65 hours. The new SEMS2 metal bearing performed exceptionally well, while the enhanced cutting structure transitioned efficiently between the sand/shale sequences without issues. Two offset wells required two and three SEMS bits to complete the same hole section; thus, the SEMS2 well realized cost savings of U.S. $59,000 and $156,000 to the same depth vs. the offset wells. An SEMS2 bit was run on another well and drilled 834 ft farther than the first SEMS2 run, for a total of 3,711 ft in 83 hours at 44.7 ft/hr and 946,000 revolutions. This demon-strates consistently good performance for the SEMS2 bits in this application.

Case Study 2Case Study 2 was in a very abra-sive sand/shale interval in Vermilion Parish, Louisiana. The challenge was to develop technology that would allow the operator to reduce drilling costs by reducing the number of bits required to complete the 81/2-in. hole section and decreasing occurrences of lost cones. The service company selected an ST bit that would drill the 81/2-in. section efficiently. Key compo-nents included the premium SEMS2 metal-seal package for superior bear-ing reliability and patented hardfacing technology to ensure cutting-struc-ture integrity throughout the run. The newly designed 81/2-in. IADC Code 117 was run in the well with excellent results, drilling 1,197 ft in 97 hours at 12.3 ft/hr for 1,048,000 revolutions. An offset well required two SEMS bits to drill the same section; these two bits averaged 370 ft in 34.3 hours at 10.8 ft/hr for 370,000 revolutions. The new SEMS2 ST bit realized a cost sav-ings of U.S. $36,000 to the same depth as the offset well, then drilled another 631 ft. As a result, the operator was able to drill the interval to an even greater depth with one less bit at 14%-higher ROP. Additional SEMS2 bits have been run in this field, continuing the performance improvements and cost savings over the SEMS bits. The SEMS2 bits have averaged 47% greater revolutions, with a seal effective ratio of 80% vs. 72% for the SEMS field aver-age, with a 65% greater average life to seal failure. This type of differentiable performance gains the trust of opera-tors and enables longer bit runs to be achieved with confidence. JPT

Rodney Eads, SPE, was named Executive Vice President and Chief Operating Officer for Pride Intl. Before this appointment, he was Senior Vice President–Worldwide Operations for Diamond Offshore Drilling. Eads earned a BS degree in chemical engi-neering from the West Virginia Inst. of Technology and an MBA degree from Rice U.

William Faubel, SPE, was appointed Vice President–Enterprise Marketing for Baker Hughes Oilfield Operations. Before this appointment, he served as President of Baker Atlas. Faubel earned a BS degree in mechanical engineering from Southern Methodist U.

Richard Fowler, SPE, was named Vice President and General Manager for Dominion E&P. He joined Consolidated Natural Gas Co. (CNG) in

1996; CNG merged with Dominion in 2000. Fowler earned a BS degree in mechanical engineering from Tulane U.

Joseph Franz Jr., SPE, was named President and Chief Executive Officer for Unbridled Energy Corp. Before this appointment, he worked for Schlumberger.

Judd Hansen, SPE, was appointed Senior Vice President–Shelf and Onshore for Mariner Energy. The company also announced the appoint-ment of Cory Loegering, SPE, as Senior Vice President–Deepwater and Richard Molohon, SPE, as Vice President–Reservoir Engineering.

Hossein Kazemi, SPE, was named Chesebro’ Distinguished Chair in Petroleum Engineering at Colorado School of Mines. He began teach-ing as an adjunct pro-

fessor in 1980 and has served as codi-rector of the school’s Marathon Center of Excellence in Reservoir Studies since 2003. Kazemi, an SPE Distinguished Member, is a member of the U.S. Natl. Academy of Engineering.

Gary Rich, SPE, was named President of Hughes Christensen. Before this appoint-ment, he served as Vice President–Mar-keting Drilling and

Evaluation. Rich earned a BS degree in accounting from Brigham Young U. and an MS degree in science and tech-nology commercialization from the U. of Texas at Austin.

Eve Sprunt, 2006 SPE President, has been named University Partnership and Re -cruitment Manager—Corporate HR, Re -gional Shared Services-

North America for Chevron Corp. She will coordinate development

and deployment of Chevron’s univer-sity recruiting efforts within the U.S. and with the newly created University Partnership Program. Sprunt will estab-lish strategic relationships in the areas of recruiting, research, and public affairs with the 16 global universities currently in the program.

Prior to the appointment, she was Senior Technical Adviser for Chevron Technology Ventures.

PEOPLE

Shofner Smith, Greenwood Village, ColoradoF.M. Stevenson, Greenwood Village, ColoradoGary Weimann, Calgary

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