Investigation of Effective Parameters in Rotary Drilling Bits Selection
Ahmad NateghPour*, Mojtaba Allahyari**, Ali San’ati*** *Junior Student of Petroleum Exploration Engineering, Islamic Azad University ** M.Sc. of Reservoir Engineering, Sharif University of Technology ***M.Sc. of Drilling Engineering, Petroleum University of Technology
Abstract Since the drilling bit represents the heart of drill string therefore bit selection has the most fundamental effect on rate of penetration (ROP) and consequently the drilling time. The oil industry scientists have done hundreds of researches on bit design and manufacture in order to reduce drilling costs. Three major bit types are being used in drilling operations in which each of them has different designs to drill different formations and in different conditions encountered during drilling operations. Drilling engineers can reach to an effective ROP by using the right type of bit by the knowledge of its specifications. Although understanding the different types of bit and their respective applications is a pre-requisite to bit selection since holemaking involves not only the right bit in the right application but also running it with the right operating parameters.
Keywords: Bit Selection, Teeth Shape, Nozzle, Journal Angle, Offset Angle, Bearing System, Gauge Protection
1. Introduction The most important factors which affect the drilling time in rotary drilling operations are: bit type, formation characterizations, drilling fluid properties, drilling conditions such as WOB and RPM, corrosion of bit teeth, and bit hydraulic pressure. In rotary drilling operations the most important equipment of BHA in which is used to cut and crush the rocks on the bottom of the hole is drilling bit. Scientists have been studying the variables effecting ROP by the time rotary drilling has started. An extremely large variety of drilling bits manufactured for different conditions encountered
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during rotary drilling operations. Therefore, the drilling engineers ought to have a wide knowledge on effective parameters that control the drilling time. Consequently, the cost of drilling per foot has a direct proportion with performance of various bits. Drilling engineers utilize various types of drilling bits for various formation characterizations to increase the ROP and efficiency of drilling bits. This process eventually led to optimization of drilling time and to reduce the costs of drilling operation. In rotary drilling bit selection process we can follow the below sequence:
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Assemble offset well data such as Bit records, Mud logs, and etc. where they are drilled in the same field and through the same target formation
drilling operations, and 4) four cone bit which is used for drilling large diameter.
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Characterize the proposed hole geometry such as hole size, Casing points, and etc.
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Review offset well bit runs
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Develop candidate bit programs
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Confirm consistency proposed BHAs
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Perform economic evaluation
These types of bits were the most common bits which were being used in drilling operations mostly in soft formations. Unlike rock bits that have dynamic parts which turn besides bit in this type of drilling bits blades are fixed and there isn’t any dynamic part. Foresaid drilling bits previously were being used to drill soft formations however today recent technology in manufacturing drilling bits and using more stable metallurgy has improved them to be more effective for different formations from soft to hard and abrasive formations. Recent years drag bits were developed into four categories each for a different condition. These are 1) PDC (Polycrystalline Diamond Compact), 2) Natural Diamond Bits, 3) TSP (Thermally Stable PDC Bits), and 4) Fishtail Bits.
with
Otherwise the selection of the best available bit for the job can be determined only by trial and error. This paper highlights the effective parameters in drilling bits selection in rotary drilling operations. A number of properties affect rolling cone bits and others have effects on drag bits performance. 1.1 Rolling Cutter Bits (Rock Bits) This type of drilling bits include dynamic parts in which when drill string turn the bit therewith the dynamic parts (cones) will turn likewise and that helps the act of cutting and crushing the rocks on the bottom of the hole. Howard Hughes for the first time in 1909 introduced this type of bits into petroleum industry. Those bits were two-cone bits without self-cleaning feature. Nowadays rolling cutter bits which are being used for making hole are mostly three-cone bits and are by far the most common bit type currently used in rotary drilling operations. There are three types of rolling cutter bits including: 1) two cone bit which is mostly used in directional drilling operations, 2) three cone in which is the most common bit in
1.2 Drag Bits
2. Factors Affecting Rotary Selection in Order of Importance
Bit
2.1 Bit Nozzles In recent years, a number of new nozzle designs have been proposed to the oil industry. These designs were developed to enhance turbulence, or reduce bottom hole pressure thereby improving the ROP of rolling cone and PDC bits. Typically, nozzle configurations are designed to promote one or all of four primary flow properties in the jet. These are 1) high velocity, 2) impingement pressure, 3) high turbulence levels and 4) high jet spread to influence a large area at impingement. Number and size of bit nozzles, nozzle alignment, and Nozzle geometry has a
considerable effect on the resulting jet. Therefore utilizing a proper nozzle would increase the bit performances. For roller cone bit applications, for instance, high bottom hole shear, impingement velocity, is advantageous to aid in bottom hole cleaning along with high jet spread to increase the area along the hole bottom directly influenced by the jet.
Figure 1. Two types of rolling cone bit nozzles
Milled tooth bits are mostly designed for top-hole drilling and relatively soft and sticky formations. The milled tooth bits designed for soft formations usually are hard faced with tungsten carbide on one side of the tooth. Those that are designed to drill harder formations are usually case hardened by special processing and heat treating the cutter during manufacturing. The tooth height and the spaces between teeth also affect the bit performances as bits with higher teeth and more spaces between teeth have better performance in softer formations and those with lower teeth and smaller spaces between them are mostly utilized in proportionally harder formations. In bits designed for harder formations since teeth are lower with smaller spaces between them then number of teeth is comparatively larger. These do not rely on tooth penetration so the teeth are shorter than those used in softer formations. The teeth must be strong enough to withstand the crushing/chipping action and sufficient numbers of teeth should be used to reduce the unit load.
Nozzles intended for use in PDC bit applications are typically designed to generate wide, high velocity jets to help push cuttings through the junk slots and cool the cutters. In PDC applications, turbulence is secondary in importance to velocity. 2.2 Teeth Shape In rolling cutter bits the teeth shapes have a fundamental role in drilling bit performance during drilling operations. There are two primary types of rolling cutter bits which are being manufactured by companies to be used in different situations during drilling operations. The two primary types used are (1) milled tooth cutters, and (2) tungsten carbide insert cutters.
Figure 2.Hard faced teeth on a Milled tooth drilling bit
TCI (Tungsten Carbide Inserts) rolling cone bits are designed for harder formations which have chert and quartz layers. The tungsten carbide teeth designed for drilling soft formations are long and have a chisel-shaped end. The inserts used in bits for relatively hard
formations are short and have a hemispherical end. There is little change in the cutting structure of an insert bit due to wear. This allows an insert bit to be used over a wider range of formation types than is usually impossible for a milled tooth bit.
Figure 3. Different teeth shapes used in TCI Bits
Figure 4. Different teeth arrangement for different conditions
The PDC bit has cutters made from manmade diamond crystals that are bonded to a cemented tungsten carbide substrate in a high pressure/high temperature process. The tungsten carbide backing gives the compact high impact strength; it also reinforces the wear resistance properties of the cutters. As the bit rotates over the rock, the compact shears it.
Figure 5. PDC compact schematic In diamond bits natural diamonds are imbedded in a matrix and destroying actions of the drilling bit is by abrasion
process. Also the size and spacing of diamonds on a bit determine its use in which widely spaced diamonds are used for drilling soft formations and closely spaced diamonds are used in hard and abrasive formations. 2.3 Bearing Systems The first type of bearing system used with roller cone bits was a non-sealed, rollerball-friction bearing arrangement, utilizing rollers on the heel of the journal. The primary load, or stress was exerted on these rollers, and drilling fluid was used to lubricate the bearings. Bearing size was maximized, since room for a seal was not required. The bearing surfaces were machined and ground to very close tolerances to ensure dependable service. The next generation of bearing systems was a sealed roller bearing system, having a sealed grease reservoir to lubricate the bearings. There is, however, one serious drawback to the roller-ball-roller bearing system. The primary cause of roller bearing failure is journal spalling, which causes destruction of the rollers and the locking of the cone. To remedy this, instead of the standard roller bearing assembly, the “journal bearing” system utilizes solid metal bushings for direct cone to journal contact. This offers a distinct mechanical advantage over roller arrangements in that it presents a larger contact area at the load bearing point. This distribution of the load eliminated the chief cause of roller bearing assembly failure-spalling in the load portion of the bearing face. Journal bearing systems in the tungsten carbide insert bits features a metal bearing surface combined with a hard-faced journal and a lubricant. Specialized seals and reliable pressure equalization systems keeps the drilling fluid and formation contaminants out of bearings, and positively seals the graphitebased lubricant inside the bearing. Precision fit of the journal and cone distributes contact loading evenly throughout a near perfect arc. Bearing surfaces are finished to a carefully controlled surface texture to ensure optimum lubrication.
from about 4° for bits used in soft formations to zero for bits used in extremely hard formations.
Figure 6. Sealed bearing
Figure 8. Offset angle effect
2.5 Bit Body Material In PDC bits the bit body material can be made of different metallurgy such as steel body which is less durable and less resistance to erosion or tungsten carbide matrix depending on drilling conditions and formation characterizations.
2.6 Journal Angle
Figure 7. Bearing types 2.4 Offset Angle The offset angle in rolling cutter bits controls the bit functioning and the rate of tooth wear in abrasive formations. In rolling cutter bits for softer formations more offset angle has a better efficiency yet the offset angle for bits designed for harder formations is more efficient when it tends to zero. Cone offset angle varies
Journal angle is an angle formed by a line perpendicular to the axis of the axis of the bit. This angle determines the diameter of the milled tooth cone in accordance with the diameter of the wellbore. If the journal angle is increased, the diameter of the cone should decrease and vice versa in order to avoid interference between cones. The advance of the roller tri-cone bit in the bottom of the wellbore is mostly regulated by the size and shape of the cones.
Figure 9. Journal angle
Figure10. Gauge protection
2.7 Gauge Protection
3. Conclusions
Bit diameter is an important parameter for drilling companies since the under gauge situation causes the low hole diameter from what they desired and they would have to do other operations to increase the hole diameter. In rolling cone bits the first teeth row and outer part of the bit body is called gauge surface. The outer portion of a drilling bit is the most vulnerable part of it because of its contact with the walls of the hole. In order to increase bit efficiency and prolongation its lifetime in hard and abrasive formations bit manufacturers reinforce bit gauge with hard and wear resistant material such as tungsten carbide.
1- Important factors affecting bit selection are bit nozzles, teeth shape, bearing system, offset angle, journal angle and gauge protection. 2- In soft and sticky formations such as unconsolidated sands and clays, and top-hole drilling: milled tooth bits are mostly used which are equipped with extended nozzles, large teeth with large space between them, and according to the above discussion maximum offset angle would result in best performance of the bit. 3- In medium formations which may include shale, gypsum, shaly lime, sand, and siltstone: rolling cone bits with relatively small teeth with small space between them and smaller offset angle would result in high efficiency of the bit.
4- In hard formations such as limestone, anhydrite, hard sandstone, and dolomite: rolling cone bits with small and round tungsten carbide inserts which are arranged with small spaces between them would result in best bit efficiency. Also when offset angle tends to zero. 5- According to what discussed above effective factors for selecting roller cone bits are nozzle size selection and teeth shape. Bearings efficiency and offset angle also play an important role. 6- PDC design influenced by eight factors: body materials, bit profile, gauge protection, cutter shape, number of cutters, cutter exposure, cutter orientation, and hydraulics. 7- PDC bits are used primarily in deep and/or expensive wells which can drill in either soft or medium to hard formations. 8- Natural diamond bits are used to drill hard and abrasive formations and when it is important to keep the bit and pipe and when long bit run is required.
4. References
1. Adam T. Bourgoyne Jr., Keith K. Millheim, Martin E. Chenevert, and F.S. Young Jr.: “Applied Drilling Engineering”, SPE Textbook series, Vol.2, 1991 2. Carlos Lopez Jimeno, Emilio Lopez Jimeno, Francisco Javier Ayala Carcedo: “Drilling and
Blasting of Rocks”, Taylor & Francis, 1997 3. Michael R. wells, Rolf C. Pessier: “The Effects of Bit Nozzle Geometry on the Performance of Drill Bits”, AADE-03-NTCE-51, 2003 4. Paolo Macini: “Drill Bits for Horizontal Wells”, The MiningGeological-Petroleum Engineering Bulletin, Vol.8, No.1, Dec. 1996 5. R. Feenstra, and Koninklijke: “Status of Polycrystalline Diamond Compact Bits”, part 1, Development Journal of Petroleum Technology, Vol. 40, No. 7, July 1988 6. Neal J. Adams: “Drilling Engineering”, PennWell Books, Tulsa, Oklahoma, 1985 7. Schlumberger Drilling Introduction Program Developed by Macromedia, Inc. 8. Tim Thomas: “IADC Codes”, Bit Brokers International, 2008 9. Total Professor Association: “Drilling Bits Planning Selection Course”, Held in PUT (Petroleum University of Technology) 10.Abdol Majid Heidari: “Drilling Bit Engineering”, Engineering Office, NISOC (National Iranian South Oil Company), 2006 11. Miscellaneous Documentation from websites: Schlumberger, Hydril, SPE, World Oil, and Baker Hughes 12. Miscellaneous Documentation from: “TOTAL Drilling Division”
and “Schlumberger Technology”
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