Drill bits are the core rock‑breaking tools in oilfield drilling operations, primarily used to fracture subsurface formations and shape the wellbore. Their performance directly determines drilling quality and penetration rate, while also significantly influencing overall drilling costs, making them indispensable key equipment in drilling engineering. Based on their structure, rock‑breaking mechanisms, and application scenarios, drill bits can be classified into several types, with commonly used varieties including drag bits, roller cone bits, diamond bits, and PDC bits. By function, they further subdivide into general‑purpose bits, core‑bitting bits, reaming bits, directional‑drilling bits, and other specialized‑application bits. This paper provides a detailed overview of the structure, operating principles, and usage guidelines for each major type of drill bit.

The scraper‑type drill bit was the earliest type of drill bit employed in rotary drilling. Since the advent of rotary drilling technology in the 19th century, it has been widely used and continues to be utilized in soft‑formation drilling operations at certain oilfields. This drill bit is well suited for drilling in soft and sticky‑soft formations, offering high mechanical penetration rates and substantial footage per bit. It also boasts key advantages such as a simple structure, ease of manufacture, and low cost, enabling oilfields to independently design, fabricate, and modify it according to their operational needs, thereby demonstrating exceptional practicality.

(1) Structural Composition
The scraper‑type drill bit features a simple, integrated structure, consisting of four main components: the bit body, scraper blades (cutting wings), a water‑diverting cap, and nozzles. The bit body is machined from medium‑carbon steel and serves as the structural backbone; its upper end is threaded for connection to the drill string, while its lower end is welded to secure the scraper blades and the water‑diverting cap. The scraper blades, also known as cutting wings, are the core working elements of the scraper‑type drill bit and directly participate in rock‑breaking operations. The water‑diverting cap, in conjunction with the nozzles, primarily functions to guide the drilling fluid, clean the bottomhole, and cool the drill bit.
(II) Operating Principle
The scraper‑type drill bit employs cutting and erosion as its primary rock‑breaking mechanism, and the rock‑breaking process exhibits distinct differences depending on the lithology of the formation.
In soft plastic formations, the rock‑breaking mechanism is analogous to that of a tool cutting soft metals. Under drilling pressure, the cutter wings penetrate the formation, while the torsional torque transmitted through the drill string induces continuous plastic flow of the rock ahead of the cutting edge. As a result, the formation at the bottom of the well is stripped away layer by layer, enabling rapid penetration.
In brittle formations, the rock-breaking process is divided into three cyclic stages:
1. Collision Phase: After the rock ahead of the cutter blade is fractured, torsional resistance decreases, allowing the blade to advance smoothly and directly impact the new rock in front.
2. Crushing and Minor Shearing Stage: Sustained torsional forces compress the rock at the front, causing it to undergo compressive fracturing and minor shear cracking.
3. Large-Shear Fracturing Stage: As the cutter blade continues to advance, the torsional force reaches the ultimate strength of the formation’s rock, causing the rock to undergo complete shear‑induced fracture along the shear plane, after which the torsional force drops sharply.
The three stages described above cycle repeatedly, constituting the complete operational process by which a scraper‑type drill bit breaks brittle and plastic rocks.
(3) Usage Guidelines
The scraper‑type drill bit is specifically designed for soft and sticky formations and must not be used in hard or abrasive formations. During operations, drilling pressure and rotational speed must be carefully controlled, with particular emphasis on preventing deviation, bit stalling, and cutter‑wing breakage.
Because this drill bit achieves high penetration rates and generates substantial cuttings in soft formations, operations require high‑displacement drilling fluid to thoroughly clean the bottomhole, promptly remove cuttings, and cool the bit, thereby preventing high‑temperature wear. Moreover, the outer edge of the cutting wings experiences high peripheral speeds and rapid wear; prolonged operation can cause them to erode into a conical shape, readily leading to borehole shrinkage and wellbore deviation. Throughout the entire operation, it is essential to closely monitor the bit’s condition and implement effective deviation control and wellbore stabilization measures.

Following the introduction of the first roller-cone drill bit in 1909, its broad compatibility with various formations and consistent rock‑breaking efficiency quickly established it as the dominant drill bit in global drilling operations. Among these, tricone bits are currently the most widely used type in rotary drilling; by adjusting the tooth geometry and bearing configuration to suit formations of differing hardness, proper selection can effectively optimize penetration rate and single‑bit footage, delivering outstanding overall operational performance.

(1) Basic Structure
The tricone drill bit features a mature design, with its core components comprising four major modules: the bit body, the cutters, the bearings and oil‑storage sealing assembly, and the nozzles.
1. Drill bit body: Composed of three cutting blades welded together, with a standard connection thread at the top for coupling with the drill string and transmitting drilling pressure and torque.
2. Roller Cone: A conical metal structure composed of a cone body and teeth, with teeth available in two types—milled teeth and insert‑type teeth—to suit different formation conditions.
3. Bearings and Oil-Sealing Assembly: Provides support for the rotary trunnion while lubricating the bearings via a sealed oil-storage system, thereby reducing wear and extending service life.
4. Nozzle: Controls the flow rate and direction of drilling fluid, ensuring cuttings removal at the bottomhole and cooling of the drill bit.
(II) Operating Principle
During operation, the roller cone drill bit exhibits a dual‑motion mode of revolution and rotation: the bit as a whole rotates around the central axis along with the drill string (revolution), while the three roller cones roll on the wellbore bottom along their own axes via bearings (rotation), thereby breaking rock through the combined actions of impact crushing and shear‑scraping.
1. Impact‑crushing action (core rock‑breaking mechanism): The drilling weight is transmitted through the roller cone teeth to the formation at the bottom of the well, achieving static crushing. Simultaneously, as the roller cone rolls, single‑tooth and double‑tooth contacts alternate with the wellbore bottom, while the cone’s center oscillates vertically, inducing longitudinal vibrations in the drill string. These vibrations convert elastic deformation energy into high‑frequency impact forces, repeatedly impacting and fracturing hard rock.
2. Shear‑scrape action: Due to the structural design of the roller cone—featuring an over‑top, a re‑tapered profile, and an offset axis—the cutting teeth generate both tangential and axial sliding as the cone rolls, producing a shear‑scrape effect on the rock at the bottom of the well. This mechanism is analogous to the cutting‑and‑breaking action of a scraper‑type drill bit, helping to clean the wellbore and enhance drilling efficiency.
Drill‑bit structures vary to suit different formations: for soft to medium‑hard formations, bits incorporate over‑top, multi‑cone, and offset‑axis designs; for medium‑hard to hard formations, they employ an over‑top plus multi‑cone configuration; and for extremely hard, highly abrasive formations, single‑cone bits are typically used, lacking over‑top or offset‑axis features to enhance wear and impact resistance.
(3) Classification and Selection (IADC Standards)
To standardize industry selection criteria, the International Association of Drilling Contractors (IADC) has established a three-digit coding system for roller cone bits. This system precisely defines bit type, compatible formations, and structural characteristics, serving as the core reference for on-site drilling‑bit selection.
1. First digit: Tooth type and compatible formation hardness
1=Mill‑tooth, soft formations; 2=Mill‑tooth, medium to medium‑hard formations; 3=Mill‑tooth, hard and abrasive formations; 4=Standby; 5=Insert‑tooth, soft to medium formations; 6=Insert‑tooth, medium‑hard formations; 7=Insert‑tooth, hard and abrasive formations; 8=Insert‑tooth, extremely hard and highly abrasive formations.
2. Second digit: Fine-grained hardness grade of the stratum
The corresponding major stratigraphic units are further subdivided into four hardness grades—1, 2, 3, and 4—to achieve precise adaptation.
3. Third digit: Drill bit structural characteristics
1 = Non-sealed rolling bearing; 2 = T‑type external‑drain tooth gauge; 3 = Gauge‑ring insert tooth gauge; 4 = Sealed rolling bearing; 5 = Sealed rolling bearing + gauge‑ring insert tooth gauge; 6 = Sealed sliding bearing; 7 = Sealed sliding bearing + gauge‑ring insert tooth gauge; 8 = Specialized drill bit for directional wellbore build‑up; 9 = Other special structures.

Diamond drill bits are monolithic tools that achieve rock breaking by virtue of diamond grains embedded in the matrix. With its ultra‑high hardness and exceptional wear resistance, diamond is currently the best known material for rock‑breaking and abrasion resistance; accordingly, these bits are well suited for drilling through hard and highly abrasive formations, delivering high penetration rates and long service lives per bit. Although the raw material cost of diamond is relatively high, its outstanding overall performance makes it widely used in deep wells, ultra‑deep wells, turbine‑drilling operations, and core‑taking applications—particularly in the form of thermally stable polycrystalline diamond cutters ( TSP ) Drill bits are the most widely used and enjoy strong market competitiveness.

(1) Structural Features
Diamond drill bits feature an integral, non‑movable design that ensures overall robustness and stability. The core comprises five components: the bit body, the crown, the hydraulic structure, the gauge‑keeping structure, and the cutting edges.
1. Drill body: Made of steel, it features a threaded connection at the top for coupling with the drill string and an integral connection to the crown section at the bottom, serving to bear loads and transmit forces.
2. Crown: The core working section, with diamond cutting teeth inlaid on the surface and gauge‑maintaining teeth on the sides, responsible for rock fragmentation and wellbore diameter control.
3. Hydraulic structure: Includes the water eye, nozzle, water trough (flow channel), and cuttings discharge groove, which are used to guide drilling fluid, clean the well bottom, remove cuttings, and cool the drill bit.
4. Gauge‑maintaining structure: Inlaid gauge‑preserving diamond teeth to prevent wellbore diameter reduction and ensure wellbore roundness.
5. Cutting Edge: A fractured edge composed of diamond particles, serving as the direct rock‑breaking component.
(II) Operating Principle
The rock‑breaking mechanisms of diamond drill bits vary with formation lithology and are primarily categorized into three modes: plowing, crushing, and grinding.
1. Plastic Formation—Plow‑Cut Rock Breaking: Under drilling pressure, the diamond cutting edge penetrates the formation, and the drill bit’s torque induces plastic flow in the rock, operating on a principle similar to plowing. This process progressively removes rock layer by layer, resulting in continuous and stable rock breaking.
2. Brittle formations—crushing and fracturing of rock: The combined action of drilling pressure and torque induces shear stresses beneath the cutting edge, leading to crack formation. As the diamond bit advances, it tears the rock, resulting in volumetric fragmentation, which delivers high rock‑breaking efficiency and rapid penetration rates.
3. Hard, abrasive formations—grinding‑type rock breaking: Impregnated diamond bits are commonly used, with fine‑grained diamonds embedded within the matrix. The exposed sharp edges and corners fracture the rock through micro‑cutting, scratching, and grinding—principles similar to those of a grinding wheel. This represents a surface‑breaking mechanism, well suited to extremely hard formations, though its rock‑breaking efficiency is relatively low.
(3) Usage Guidelines
Diamond drill bits are suitable for medium‑hard to hard formations and highly abrasive formations, and are particularly well suited for deep wells, ultra‑deep wells, turbine drilling, and geological core‑sampling operations.
Prior to operations, the well bottom must be thoroughly cleared of debris to eliminate metal fragments and prevent impacts that could damage the diamond bits. Once the bit is lowered into the well, perform a break‑in run at low weight on bit, reduced rotational speed, and slow drilling rates to condition the wellbore. During normal drilling, employ operating parameters characterized by low weight on bit, high rotational speed, and high flow rate, balancing drilling rate with bit life.
During operations, avoid reaming whenever possible; if reaming is unavoidable, maintain low weight on bit and low rotary speed throughout the process, and execute the operation smoothly and uniformly to prevent diamond‑bit breakage or excessive wear in the gauge‑keeping zone.

PDC drill bits, short for polycrystalline diamond compact drill bits, are a new type of drill bit developed in 1973 based on cutting‑edge polycrystalline diamond compact technology. With their outstanding advantages—high penetration rates, long service life, high footage per well, and excellent stability—they quickly gained widespread adoption upon introduction, becoming one of the mainstream drill bits used in oilfield drilling. Major drill‑bit manufacturers have since established comprehensive product lines of PDC drill bits.

(1) Structural Features
PDC drill bits feature an integral, non‑movable‑part design and consist primarily of a bit body, PDC cutting teeth, and nozzles. Based on manufacturing processes and materials, they are classified into two major series: steel‑body and matrix‑body types.
1. Steel-body PDC drill bit: The body is machined from medium-carbon steel, and the PDC cutting teeth are press‑fitted into the bit crown using an interference fit. The crown undergoes surface hardening to enhance wear resistance. Advantages include a simple manufacturing process and low cost; disadvantages are poor erosion resistance of the bit body and insufficient stability of the cutting teeth, resulting in limited current applications.
2. PDC drill bit with a carbide matrix: The upper portion is a steel connecting body, while the lower portion features a wear‑resistant tungsten carbide matrix formed via powder metallurgy sintering, with PDC cutting inserts brazed in place using low‑temperature solder. The tungsten carbide matrix exhibits high hardness, excellent resistance to erosion and abrasion, significantly extending bit life and increasing penetration rate per bit, making it the most widely used type in field applications today.
(II) Operating Principle
PDC bits employ shear‑cutting rock‑breaking, with a key advantage being their strong self‑sharpening capability. During operation, the PDC cutting teeth readily engage the formation under bit weight and, driven by drill‑string torque, advance in a sliding motion, subjecting the downhole rock to intense shear‑induced fracturing. With multiple sets of cutting teeth working in concert, ample free surfaces are created at the bottom of the wellbore, facilitating easy fracture and spalling of the rock. This results in low rock‑breaking resistance, high efficiency, and a drilling rate that significantly outpaces conventional bits.
(3) Usage Guidelines
The optimal operating conditions for PDC drill bits are large sections of homogeneous soft to medium-hard formations; they are unsuitable for gravelly layers, alternating soft–hard formations, or fractured formations, where issues such as tooth chipping and excessive wear are likely to occur.
1. Operating parameters: Employing a “low drilling pressure, high rotational speed, and high flow rate” mode maximizes drilling efficiency and extends drill bit life.
2. Preliminary Preparations: Before entering the well, thoroughly clean the bottom of the well to ensure there are no metal debris or hard rock fragments, thereby preventing damage to the cutting teeth.
3. Initial Operations: After entering the well, begin with light weight on bit and low rotary speed for break-in; once the bottomhole is formed and operating conditions have stabilized, switch to normal drilling parameters.
4. Compatibility with Drilling Processes: Its monolithic design, devoid of moving parts, ensures excellent compatibility with high‑speed turbine drilling, delivering significant advantages in efficient deep‑well drilling.

1. Scraper‑type drill bit: Suitable for soft and sticky‑soft formations, with a simple structure and low cost, ideal for rapid shallow‑depth drilling.
2. Roller-cone drill bits: They exhibit the broadest formation compatibility, performing effectively in soft, medium-hard, and hard formations, and are highly versatile, making them the workhorse of conventional drilling.
3. Diamond drill bits: Specifically designed for medium-hard, hard, and highly abrasive formations; suitable for deep wells, ultra-deep wells, and core‑taking operations, with high penetration rates per pass.
4. PDC drill bits: Suitable for homogeneous soft to medium-hard formations, offering fast penetration rates, long service life, and optimal cost-effectiveness for efficient drilling.