PDC drill bits Physical features

Physical features

1. extreme hardness

2.higher compression strength

3. good self-sharpening     4. impact toughness is better than natural diamond, worse than cemened carbide. The polycrystalline layer is easy to fracture under the effectof impulsive load

5. sensitive to temperature. About 350℃, the wear rate accelerated significantly. about 700℃, strength failure

6. Journal sealed insert bit

7. The durability of premium tungsten carbide inserts is improved with new formulas and new techniques

8. The premium HNBR Oring, optimal seal compression and curved seal structure can enhance the seal performance

9. The pressure compensator system and advanced grease can greatly increas

Model	114,117,127,437,517,617,637,737,837etc
Type	Steel body PDC drill bits, tungsten carbide matrix PDC bit
Appliable	water well, oil field, construction, geothermal
Formation	sticky,soft,medium hard,hard formation
Bearing	rubber seal or metal seal
Packing	steel box,or as customer requirements
Payment Term	T/T,L/C
MOQ	1 Piece

Function &Advantage:

1. Suitable for soft to medium-hard formations

2. Operating in cutting principle, cutting rock in low energy consumption

3. PDC cutters have the characteristics of super hardness, wear resistance and self-sharpening 

4. PDC diamond bits

belongs to fixed tooth bit, hasn’t active components and work in high reliability

Cements

Cementing the casing serves several functions: segregating formations behind the pipe to confine production to a specific zone, providing support for the casing and helping to protect the pipe from corrosive formation fluids. As wells are drilled deeper, high pressures, high temperatures and corrosive fluids place demands on the performance of cements that are quite different from those encountered in conventional drilling.

For example, the cement slurry needs to have a low viscosity to enable it to be easily pumped to a greater depth. High pressures and temperatures can alter the setting behavior of the cement, so the slurry must be specially designed for predetermined downhole conditions. If the cement sets too quickly the well can be lost; too slowly can mean an expensive loss in drilling time and possible communication behind pipe due to fluid influx.

The long-term integrity of the cement under harsh pressure and temperature conditions is also important. Poor cement qualities over time can result in casing corrosion and collapse, fluid migration behind pipe, or loss of support and formation-to-pipe seal. Formation fluids high in carbon dioxide are particularly effective at causing cement to deteriorate; in some cases within five years.

Polycrystalline Diamond Compact bit

Polycrystalline Diamond Compact bit, known as PDC drill  bits, is made up of small cutting blocks which consist of polycrystalline diamond thin round sheet inserted onto the drill bit body. It is suitable for soft to medium-hard formations.

PDC bit is an integral drill which hasn’t activity components. The structure of PDC bit is very simple, it generally includes drill body, cutting teeth, nozzle and junk slot, etc.

Detailed description

PDC bit can be divided into two types: steel body and tungsten carbide matrix. The surface of steel body PDC bit is easily to be eroded. While tungsten carbide matrix PDC bit is difficult to eroded. 

Selfsharpening of PDC tooth is very good. Polycrystalline diamond grains shed in the process of cutting the rock and form new blade grain to update the selfsharpening. In addition, tungsten carbide substrate forming sharp cutting edge after wearing, exhibiting good antiimpact performance and providing flexibility for diamond.

Operating principle:

1. Crushing process of soft plastic formations:   

 Continuous cutting, similar to the process of machine tools cutting the metal.

2. Crushing process of hard brittle formations:

 Crash--- crushing and small shear---big shear

Size and formations:

Diameter(in)	Applicable formations
24	Dead-soft
19	soft
16	medium
13	Medium-hard
8	hard

Drilling and Completion Fluids

carrying cuttings out of the hole; cleaning, cooling and lubricating the diamond bits; giving buoyancy to the drill string; controlling formation fluid pressures; preventing formation damage; and providing borehole support and chemical stabilization. There are three types of drilling fluids: water-based, oil-based and synthetic-based. Technical requirements, cost, availability, and environmental concerns can all influence the selection of fluid type. However, as wells penetrate deeper formations, extreme conditions can result in failure of the drilling fluid to perform as needed.

For example, the role of the drilling fluid to act as a lubricant to reduce torque and drag on the drill pipe and bit becomes increasingly important in deep drilling. High temperatures encountered at greater depths can cause a direct change in the lubricating capacity of drilling muds. At the same time, the better lubricating qualities of oil-based and synthetic-based drilling fluids may become less available to drillers due to environmental regulations restricting their use. The development of new lubricating materials (e.g., solid beads) is currently being investigated as an effective means of reducing friction.

Also, with deeper wells the weight of the total amount of fluid moving through the drilling system can become a concern. New technology that can reduce the weight of drilling muds without compromising other characteristics will increase the efficiency of drilling operations. In particular, developing drilling fluids that can control subsurface pressures and maintain the stability of the wellbore without harming the permeability of productive formations is an important area for research.

Finally, although oil-based muds can perform better at greater depths, disposing of the used mud and the oil-soaked cuttings can be a challenge. Developing affordable synthetic-based drilling fluids that provide the performance characteristics of oil-based muds without the environmental drawbacks, and developing new techniques for treating or reclaiming mud and cuttings, are additional areas for research.
 

Evaluation of Tri-Cone Bit Performance on Limestone Formation

Evaluation of Tri-Cone Bit Performance on Limestone Formation

This study examines the characteristics of limestone formation as well as the performance of different tricone bits in limestone in Ewekoro. Rock samples were collected from different layers of limestone encountered in the quarry during drilling operation. These samples were tested in the laboratory for uniaxial compressive strength and the tensile strength. Also, the chemical compositions of the samples were determined using the X-Ray Fluorescence (XRF) Spectrometer and the results were used in the determination of the Equivalent Quartz Content (EQC). The length of the insert buttons on the surface of the drill bits were measured using digital vernier calliper at regular intervals. In addition, the tooth and bearing wear rates as well as the penetration rate were determined on the field. The results of the uniaxial compressive strength varied from 86.5MPa (medium strength) to 112 MPa (high strength). The Equivalent Quartz Content (EQC) of the rock samples varied from 17.37% to 36.676% while the Rock Abrasivity Index (RAI) varied from 15.03 to 43.317. The results of the drilling variables showed that higher wear rate was experienced when milled tooth tri-cone rock bits are used for drilling than using insert tri-cone bit for drilling limestone formation, hence the tri-cone bits performed optimally well in all the formations except in glauconite (GLAB) where its performance was low. However, the economic analysis indicated that the insert tri-cone bit drilling cost per metre varied from N660/m to N673/m while the milled tooth tri-cone bit drilling cost per metre varied from N684/m to N710/m. This will act as a data base for selection of drill bits and drilling equipment in limestone quarries.

Property Analysis for Correlation of Specific Energy with Penetration Rate and Bit Wear Rate

This study evaluates rock properties for correlation of specific energy with penetration rate and bit wear rate. In order to achieve these objectives five rock samples were obtained from the study area. These samples were tested in the laboratory for uniaxial compressive strength and tensile strength using 1100kN compression machine and point load tester respectively. Also, the mineral composition of the samples was determined by thin section examination. Bit deterioration was measured with digital vernier calliper at regular intervals. The specific energy was determined from field data using empirical equations. The results of the uniaxial compressive strength of the five rock samples varied from 165-320 MPa and were classified as having very high compressive strength characteristics. The point load strength index of the samples had values ranging from 5.50 – 10.67 MPa representing the tensile strength. The result of the statistical correlation matrix revealed that penetration rate and bit wear rate are dominant factors affecting the prediction of specific energy having high coefficient of correlation. The regression model had multiple coefficient of correlation of R2 = 0.893 which means that 89.3% of variation in specific energy could be attributed to variation in penetration rate and bit wear rate. Ultimately, computer programme DRILLING PROFESSIONAL 2009 was developed to compute penetration rate, wear rate and specific energy when necessary inputs are supplied. This gives quarry operators advance information on time of drilling and bit consumption.

Special purpose roller cone bit designs

Monocone bits

Monocone bits were first used in the 1930s. The design has several theoretical advantages but has not been widely used. Bit researchers, encouraged by advances in cutting structure materials, continue to keep this concept in mind, because it has the room for extremely large bearings and has very low cone rotation velocities, which suggest a potential for long bit life. While of a certain general interest, monocone bits are potentially particularly advantageous for use in small-diameter bits in which bearing sizing presents significant engineering problems.

Monocone bits drill differently from three-cone rock bits. Drilling properties can be similar to both the beneficial crushing properties of roller-cone bits and the shearing action of PDC bits. Cutting structure research thus focuses partly on exploitation of both mechanisms encouraged by the promise of efficient shoe drillouts and drilling in formations with hard stingers interrupting otherwise “soft” formations. Modern ultrahard cutter materials properties can almost certainly extend insert life and expand the range of applications in which this design could be profitable. The design also provides ample space for nozzle placements for efficient bottomhole and cutting structure cleaning.

Two-cone bits

The origin of two-cone bit designs lies in the distant past of rotary drilling. The first roller-cone patent, issued in August 1909, covered a two-cone bit. As with monocone bits, two-cone bits have available space for larger bearings and rotate at lower speeds than three-cone bits. Bearing life and seal life for a particular bit diameter are greater than for comparable three-cone bits. Two-cone bits, although not common, are available and perform well in special applications (Fig 9). Their advantages cause this design to persist, and designers have never completely lost interest in them.

• 

  Fig. 9—Two-cone bit.

The cutting action of two-cone bits is similar to that of three-cone tricone bits, but fewer inserts simultaneously contact the hole bottom. Penetration per insert is enhanced, providing particularly beneficial results in applications in which capabilities to place WOB are limited.

The additional space available in two-cone designs has several advantages. It is possible to have large cone offset angles that produce increased scraping action at the gauge. Space also enables excellent hydraulic characteristics through room for placement of nozzles very close to bottom. It also allows the use of large inserts that can extend bit life and efficiency.

Two-cone bits have a tendency to bounce and vibrate. This characteristic is a concern for directional drilling. Because of this concern and advances in three-cone bearing life and cutting structures, two-cone bits do not currently have many clear advantages. As with many roller-cone bit designs, however, modern materials and engineering capabilities may resolve problems and again underscore their recognized advantages.

The Hughes Drill Bit

Remember when Howard Hughes was the richest man in the world? This wastebasket-size piece of equipment is the reason. It costs $3,500, weighs 78 pounds, and can turn up to a hundred times a minute. It’s called a tricone rotary rock drill bit and is used to drill oil wells. It’s made by the Hughes Tool Company, of Houston.

This bit’s ancestor, the two-cone rotary rock drill bit, was invented by Howard Robard Hughes, Sr., an Iowa boy who drifted to southeast Texas in the wake of the Spindletop discovery and started a drilling company in 1902 in partnership with a man named Walter Sharp. Like everyone who drilled for oil, Hughes had trouble getting holes through underground rock formations, because the drill rock bits then in use—a flat, sharp-edged piece of metal called a fishtail, which scraped its way through the rock—wore down too quickly. In 1906 he began experimenting with the idea of a bit consisting of two toothy, rotating steel cones that would pulverize the rock. He first tested his bit at Goose Creek in 1908, patented it in 1909, and immediately quit the drilling business and started the Sharp-Hughes Tool Company.

In 1912 Sharp died and Hughes bought up his interest in the company. In 1924, 54 years old and with 75 patents to his name, Howard Senior dropped dead at the office, and Howard Junior, his only child, dashing and 18, inherited the company. Legend has it that Howard Junior actually visited the Hughes Tool office only once in his life; the company listed his title as “owner.”

The secret of Hughes Tool’s success was that everybody who drills an oil well wants the best possible bit—running a rig is extremely expensive ($250 or more an hour), and the better the bit, the faster it goes. Hughes Tool made the best possible bit. In 1933 two Hughes engineers invented the tricone bits, which drilled holes straighter and faster, and for the seventeen years that the patent on it ran—1934 through 1951—Hughes’s market share approached 100 per cent. The bit found virtually all the oil discovered in the glory days of wildcatting, and Howard Junior got to be the richest man in the world. In 1972 he took the tool company public and made $150 million in cash the day it went on sale. The money from the drill bit made dozens of movies, took over Trans World Airways, and built a good chunk of Las Vegas, among other things. Even now half of Houston is fighting for a piece of the Hughes fortune.

Ever since 1952 it has been legal for other companies to sell tricone bits, but Hughes Tool has done just fine. The bit still has three cones, though the most advanced models (like the one shown here, the J-22) have bullet-shaped teeth made of tungsten carbide instead of pointed ones made of steel. Even without a corner on the tricone market, Hughes has about 40 per cent of the drill bit business in the world