Category Archives : PDC Bit


The Cuttings Conundrum: SplitBlade Enhances Cuttings Evacuation and Improves Efficiency

This article first appeared in the June 2018 Edition of Oilfield Technology. 

Chris Casad, Ulterra Drilling Technologies L.P., USA, discusses how new drill bit designs enhance cuttings evacuation and improve efficiency.

The push to address a longstanding problem has led to a new development in drill bit design.

The problem relates to the commonly held belief that the poor evacuation of cuttings from drilling operations can significantly limit bit performance, and ultimately the rate of penetration (ROP) – a major concern in drilling operations. This issue is due to the design of traditional drill bits, which do not provide an efficient means of evacuating cuttings, leaving them trapped on the tool face. When this happens, the cuttings continually recirculate around the drill bit cone, collecting around the cutters and junk slots. Energy that should be used for drilling is, instead, expended on recirculating these cuttings. In addition, when cuttings are not efficiently removed from the cutting face, tool face control and steerability is compromised, and the bit can be damaged as result of rising temperatures.

For all of these reasons, poor cuttings evacuation can be a major performance limiter in drill bit design.

An opportunity

While there has long been an awareness of the issue of cuttings evacuation as a serious limiter to drilling performance, the problem had never been effectively resolved by drill bit designers. Ulterra recognized the opportunity for a blade design that would address the critical issue of poor cuttings evacuation, and worked to develop a solution. The development work resulted in the invention of a new bit, the SplitBlade™. This name was based on the bit’s design, which features a split geometry in which the inner blade geometry is offset forward. One factor is the bit’s rotated shoulder design. The primary blades separate past the cone to free more area for the junk slot and prevent cuttings recirculation. This design creates specific large-volume flow channels that are capable of more readily carrying cuttings away from the face of the bit. Cuttings are therefore cleared from the cone up to seven times faster compared to conventional PDC designs, freeing up the bit’s significant drilling potential.

Additional Benefits

The SplitBlade design provides further improvement in cuttings evacuation through a significant increase in the maximum hydraulic dispersal rate, creating a ‘double-barrel’ hydraulics effect. The bit’s nozzles are positioned to create dedicated fluid channels, ensuring that a high volume of fresh hydration reaches the cone and shoulder cutters, adding to bit performance and longevity. The high-velocity, tilted nozzles are built into the bit, in order to channel more drilling fluid onto the cutters themselves. In addition, this advanced bit design breakthrough provides for significantly improved bit face cleaning, adding to its overall enhanced performance. The bit’s hydraulics are also designed to deliver additional benefits that expand the performance threshold. The increased hydraulic dispersal rate provides broader channels for the evacuation of cuttings, which prevents the cuttings from being recirculated, improving cutter performance and ROP. In addition, the bit’s improved tool face control offers more effective directional drilling in curves, with good tool steerability over long laterals. As a result of the versatility and durability of the new bit design, the number of trips in and out to change bits can be reduced.

The blade performs well in straighthole and lateral drills and has produced impressive dull grade scores after multiple runs. With less tripping, rig safety is improved, and expensive rig time is saved. One feature of SplitBlade is the ability to readily change the bit’s cutter placement. The PDC cutters also feature a layout that provides for greater radial freedom. These cutter layouts are engineered for optimal drilling performance, and can also be readily modified to meet specific application requirements. Working with an operating company in the Eagle Ford shale of South Texas, Ulterra provided a custom SplitBlade, featuring an altered diamond depth to achieve improved cutting control, steerability, and tracking. This modified design resulted in high ROP performance, and was able to complete drilling of straight-hole, curve, and long laterals with the same bit. The durability and versatility also reduced the number of trip-in and trip-outs, reducing rig time and drilling costs.

The Proof is In the Drilling

Initial field runs of the SplitBlade technology were performed in the Eagle Ford. Ulterra engineers worked closely with several operators to modify and improve the unique blade and nozzle design.
SplitBlade is a new development in PDC drill bit engineering, with a design that improves cuttings evacuation, ROP and tool face control. SplitBlade features separation of the primary blades, creating double barrel hydraulics that free up more area for the junk slot.

Case 1: Andrews County, Texas

In Andrews County, Texas an operator used an 8.5 in. SPL616 SplitBlade bit with a rotary steerable system (RSS) in the lateral section. The bit not only maintained a solid ROP, but set a record for most lateral footage drilled with one bit. The bit completed more than 10 000 ft in this section to a total depth beyond 21 000 ft. In fact, the bit holds 8 of the 10 longest lateral runs for this operator in the Permian basin over a 19 month period and continues to show improved performance in terms of footage drilled and penetration rates.

Case 2: Northwestern Alberta, Canada

A 12.25 in. SPL625 bit was used in northwestern Alberta, Canada to batch drill five surface holes. The bit, equipped with the SplitBlade technology, drilled more than 3000 m in less than 45 hrs for an ROP of 67.5 m/hr. Also important was the fact that the bit was pulled out of the last hole with a 0-0-NO-TD dull grade after five runs. The performance significantly enhanced the economics of batch drilling on multi-well pads, saving the operator considerable rig time and money.

Case 3: Central Oklahoma

In the STACK play (Sooner Trend Anadarko Canadian Kingfisher) of central Oklahoma, an 8.5 in. SPL616 SplitBlade was used to drill the lateral section. At upwards of 150 ft/hr, the blade not only set numerous records for ROP in this lateral, it also set this operator’s 24 hr footage record of more than 4300 ft. According to daily run records, the bit actually drilled faster deeper into the run. This was another rotary steerable application where the SplitBlade combined speed and durability for enhanced performance.

Conclusion

By addressing the problem of poor cuttings evacuation, the designers of SplitBlade have created a bit that is setting new performance benchmarks in a wide range of environments and applications. As a result of its improved cuttings evacuation and improved hydraulics, the design helps deliver enhanced levels of performance, versatility, and durability. By working in close collaboration with key operating company customers, the designers have been able to gain first-hand insight into the many application requirements and operational challenges faced by E&P companies, and introduce important productive innovations in PDC bit design.

Download a PDF of the article as it originally appeared in Oilfield_Technology. Used by permission.


Breakthrough PDC Bit Design Evacuates Cuttings 200% Faster

Ulterra Drilling Technologies (Ulterra.com) introduces its latest advancement in PDC bit engineering. The
patent-pending SplitBlade™ breakthrough design improves cuttings evacuation as much as 200 percent
faster than conventional PDC bits.

Splitblade PDC Bit

In Lavaca County, Texas, an Ulterra SplitBlade demonstrated outstanding face control and speed, in
addition to cuttings evacuation, drilling an 11,652-foot curve and lateral in under 68 hours.
This bit’s ability to rapidly and efficiently evacuate cuttings is based on a combination of design and
hydraulic performance. One factor is the bit’s rotated blade shoulder design. The primary blades
separate past the cone to free more area for the junk slot and prevent cuttings recirculation. SplitBlade’s
second design enhancement is its high-velocity, focused nozzles. The nozzles increase the maximum
hydraulic dispersal rate, and the advanced bit hydraulics improve bit tool face cleaning. The dedicated
hydraulic flow sweeps the junk slot for reliable cuttings evacuation.

SplitBlade is a solution to cuttings clogging the bit and reduced cutter performance. Standard drill bits,
accumulate cuttings around the cutters and junk slot. Tool face cuttings accumulation wastes drilling
energy. By preventing cutting recirculation SplitBlade focuses all energy to making the hole. Operators
can increase ROP by pushing beyond the previous performance limitation.

For more information and SplitBlade images call 1-888- 858-3772.

SplitBlade was featured in E&P News:


Latest Bit Designs Drill Faster, Farther: Ulterra Featured in The American Oil & Gas Reporter

By Colter Cookson

Human beings are exploring deep space, eradicating diseases, designing pilotless planes and cars, and placing horizontal wells with multi-mile laterals on target. Psychologists say we do so much in part because we all share a desire to accomplish big things. For the humans in the oil and gas industry, that means celebrating even their greatest successes for only a few days, then getting to work on the next challenge.

 

 

Nowhere could that dynamic be more obvious than in the world of drill bits. Instead of resting after record-setting runs, bit engineers analyze their designs’ performance to identify and address the barriers that keep them from drilling even faster and farther.

Their efforts are paying off. PDC makers say their latest designs deliver significant improvements in speed and durability by optimizing hydraulics, enhancing back- up cutters, leveraging modern motors, and minimizing reactive torque. Meanwhile, the newest roller cone and hybrid bits employ advanced cutters and application-specific cutter configurations to set new standards for drilling efficiency and durability.

To drill faster, bits need to handle the additional cuttings generated by the extra speed, notes Chris Casad, innovation project manager at Ulterra. “As better PDC bits have unlocked faster penetration rates, it has become clear we need to take the next step in hydraulic performance,” he says. “Improving cuttings evacuation not only enables faster rates of penetration, but also keeps the cutters clean and cool. This minimizes thermal degradation and cutter damage, enabling the bits to maintain their high performance longer.”

According to Casad, Ulterra has advanced hydraulic performance through a new concept called SplitBladeTM. The primary blades in SplitBlade bits are divided into two parts, with the inner part offset from the outer part near the shoulder. “The offset creates a recess to put a second nozzle for each blade,” he explains. “Two nozzles create dedicated flow paths from the cone of the bit and from the shoulder outward. The focused flows energize the cuttings and ensure evacuation happens quickly and reliably.

“In addition, offsetting the blades gives bit designers the opportunity to try cutting structures that previously would have been impossible,” he comments. “For example, because the offset increases the distance between the cutters, we often can double the diamond volume in areas that are seeing a lot of wear without encroaching on an adjacent cutter.”

Casad adds that the offset gives the bit more points of contact with the formation, allowing it to distribute point loads more evenly and reduce torque fluctuations. He says the smoother torque improves tool face control, cutting the amount of time spent sliding in the curve and enabling the bit to stay on target once it is in the lateral.
He highlights one other benefit: Because they are so clean, SplitBlade bits do a great job of converting weight into energy. “Like a knife, a PDC bit works by applying force to a small area,” Casad notes. “When cuttings are recirculating or building up on the tool face, they spread the weight across a wider area, making the cutters less effective.”

By applying more weight to the bit, Casad says drillers can increase depth of cut to improve performance. “Fast rotation speeds and a low depth of cut cause the bit to turn and start eating into the well bore, creating bumps and undulations. A high weight and a lower rpm let the bit drill fast, clean and smooth, meaning the wellbore will be easier to complete and produce,” he says.

The SplitBlade concept has been tested on more than 300 runs and has drilled more than 2 million feet across North America and in China, Australia and South America, Casad reports.

“The field testing started in the Eagle Ford, where operators were looking for ways to drill 15,000 feet through the curve and lateral sections without steer- ability issues in the curve or tracking issues in the lateral,” he relates. “When we introduced SplitBlade, we were able to combine the sections more reliably while cutting drilling times by 30 percent. The bits came out with a dull grade of 1- 1 to total depth and drilled smoothly through both sections.”

While it is often used in curve and lateral bits, Casad says the enhanced hydraulics can be applied to large vertical bits as well. “This technology can translate across bit designs,” he concludes. “It will have the biggest benefit in applications with fast ROPs, but it is applicable almost anywhere.”

Download a PDF of the Article Here

Used by permission from The American Oil & Gas Reporter www.aogr.com

 


Drill Bit Innovations: Ulterra Featured in Drilling Contractor

Ulterra is pleased to have been featured in a recent Drilling Contractor article regarding emerging technologies and innovations in drill bits. 

 

drill bit technology

 

Manufacturers are developing new bits that address cuttings evacuation, vibration and thermal degradation while rearranging cutter layouts and seeking better understanding of failure mechanisms. 

Because of the significant role that bits play in drilling performance, operators are constantly on the hunt for new bits that can drill longer and further and provide a higher rate of penetration (ROP). They’re also looking for bits that provide better toolface control, which minimizes the readjustments that directional drillers have to make to the bit orientation so they can simply drill ahead.

The faster a bit drills, the more cuttings it produces in a given period of time. If those cuttings build up, it can reduce ROP and sap drilling energy. Additionally, cuttings buildup can insulate and create friction at the bit, resulting in higher temperatures around the bits and cutters. It’s not uncommon for stagnant cuttings to cause a rise in temperatures at the bit, which can cause degradation of the diamond and damage the cutter, said Chris Casad, Innovation Project Manager for Ulterra. “Having lower temperatures reduces damage, which means you have sharper cutters for longer, and that keeps you drilling at a high level for the entire duration of your well.”

After multiple years of development and testing, Ulterra will release SplitBlade, a PDC bit with optimized nozzle placement and fluid channeling, in late March. The placement of the nozzles and channels, which was determined through the use of computational fluid dynamics (CFD), improves the evacuation of the cuttings.

Additionally, the cutters on the bit’s inner blades are advanced forward, engaging the formation earlier and enabling better toolface control, Mr Casad said. This improves the blades’ grip on the formation, enabling better directional control.

Bits designed with SplitBlade technology have two dedicated channels of evacuation for each primary blade, as well as nozzles at the cone and shoulder of the bit. This allows SplitBlade to “separate the cutting evacuation from the cone of the bit and from the shoulder of the bit,” which are the two areas most prone to cuttings accumulation, Mr. Casad said. Keeping the cone clean enables better directional control and steering, and keeping the shoulder clean allows the bit to drill faster.

Read the complete Article at http://www.drillingcontractor.org/drill-bit-innovations-target-major-barriers-to-rop-durability-45969


Weight On Bit – WOB

What is Weight on Bit or WOB?

An essential part of the drilling process is adding force to the drill bit in order to successfully break the rock. Weight on the Bit, or WOB, is the amount of downward force exerted on the drill bit provided by thick-walled tubular pieces in the drilling assembly that are known as drill collars. The downward force of gravity on these steel tubes provide force for the drill bit in order to effectively break the rock. The weight of the drilling assembly is controlled and measured while the drill bit is just off the bottom of the wellbore. Then, the drill string is slowly and carefully lowered until it reaches the bottom. As the driller continues to lower the top of the drill string, more of the weight of the assembly is being applied to the bit and harmoniously less weight is hanging at the surface.

To put this into perspective, let us imagine a vertical drilling hole. If the surface measurement reads 1,000 kg less weight of the string while drilling than with the bit off the bottom, then there should be 1,000 kg of force transferred to the bit. This measurement is read using a hydraulic gauge at the surface that is directly connected to the hoisting equipment for maximum accuracy. This measured weight includes everything that exerts tension on the drill string. Weight transfer control can greatly decrease operating cost and time, and lead to a longer lasting drill bit.

Weight on bit is an essential part of drilling optimization to ensure that the well deepens as drilling moves forward. Finding the right amount of WOB per application is crucial to drilling operations. If the WOB is greater than the optimum value, the drill bit has a higher chance of wear or damage and there is even a chance for the drill string to buckle. On the contrary, if the WOB is less than optimal, the Rate of Penetration (ROP) slows down and drilling performance is subpar. The ROP is the speed at which a drill bit breaks the rock or sediment; ROP is typically measured either in feet or meters per hour. It is important to maximize the rate of penetration to reduce rig time and cost. In order to optimize penetration, drilling operators must pay close attention to Weight on bit and alter it as necessary. Finding the optimum WOB is determined by the design and parameters of the drill bit, as well as external factors such as mud weight, BHA, and the rock being drilled. There is no standard range of weight that should be applied to the bit. It can be anywhere between 1,000 lbs. to 100,000 lbs. depending on the size and type of bit, the rock being drilled, and the application. At Ulterra, recommended values for WOB to the customer are based purely on local knowledge and experience of the application.

Bit manufacturers specify the maximum WOB to avoid damage to the bit; each will have their own method that helps them determine this maximum weight. The stable zone for smooth drilling operations calls for moderate WOB and rotary speed. The recommended weight provided by bit manufacturers is determined by factors such as the structural integrity of the bit body and blades, cutter quantity and the cutter orientation, size, and shape. When we determine the maximum weight the design will take before failure, we then add in a 10-20% safety factor. This safety factor provides a guarantee that the bit will not break if the maximum specified Weight on bit is applied during drill operations.

WOB Measurement

Weight on bit is usually measured using a drillstring weight indicator located on the driller’s console and linked to the hoist equipment in the derrick. The more advanced and functional indicators have dual scales which consists of a primary scale indicating the suspended weight of the drilling assembly and the secondary scale for the drill bit weight. These weight indicators are hydraulic gauges that are attached to the dead line of the drilling line that take the actual force measurement. As the tension in the line increases, hydraulic fluid is forced through the instrument which turns the hands of the indicator, providing the operator with the weight suspended off the hoist. Before the driller measures the weight on the bit, they must make a zero offset adjustment to account for any weight other than the drillstring. Therefore, the measurement inclusively measures the weight of the drill string, which includes the drill pipe and bottomhole assembly. Other than these indicators on the surface, Measurement While Drilling (MWD) tools that are located down hole provide more accurate weight on bit measurements that are sent to the surface on a readout interface. Sensors inside the MWD tool measure the strain on the body of the tool, from which they can calculate the applied weight that is actually getting to the bit since the MWD tool typically sits very close in the drilling assembly.

 

Finding Optimum WOB & Rotary Speed

It is important to select the best bit weight and rotary speed to optimize the drilling operation, minimize cost, and increase bit life. The drilling environment, such as the lithology of the rock and drilling dysfunction, impacts the drilling conditions and can have a negative effect on drilling efficiency. Rotary speed and weight on bit can control vibration and ROP. It is important to be in control of drilling vibration in order to keep the bit in smooth contact with the rock, prevent damage and maximize efficiency by reducing wasted energy. A minimum WOB must be achieved in order to get the drilling started, which is considered the threshold weight. There are average values that have been determined for drilling weights, but proper weight can be determined for each application by increasing the bit weight in steps of 1,000-2,000 lbs., with an optimized rotary speed. Optimum weight has been reached when additional weight is not providing further penetration and the bit starts to founder.

Rotary speed and weight on bit cannot be continuously increased without causing extreme stress on the drill string and bit. If excessive force and weight are being applied to the drill string it can cause the drill pipe to buckle. Buckling at a minimum leads to decreased performance and increased stress on components, but it can even result in parting the string and losing your BHA, which means losing expensive high-tech logging equipment and directional drilling tools down the hole.

After a certain bit weight value is reached, it is normally observed that rate of penetration starts to reduce. The poor response of penetration is usually attributed to inefficient bottom hole cleaning and wear on the drill bit, but it is often actually the case that drilling dysfunction starts to kick in. At very high WOB the sheer amount of torque being produced by the bit starts to overload the drilling system leading to vibration and inefficiency. Likewise, after a certain value of rotary speed has been met, ROP decelerates as the bit starts skating on top of the rock rather than getting good penetration of the cutting structure, the speed is too high to get a good bite into the rock. This poor response of decreased penetration is likely due to loss of stability of the drilling assembly in the wellbore.

To test bit performance, the driller can increase WOB by x amount and the drill rate will increase by y amount of ft/hr. If this bit is efficiently shearing the rock, the next x amount of weight on the bit should yield another y amount of ft/hr. If the drill rate does not increase by the same amount, the response is disproportionate. That increased weight could be damaging to the bit or the BHA. These tests of efficiency will help determine how proportionate the response is between WOB and ROP (ft/hr).

Rotary speed and weight are just two parameters that must be monitored and adjusted to improve drilling efficiency. Other drilling parameters such as torque, flow rate, bottom-hole temperature, and bottom-hole pressure can also be converted into ROP at the bit.

 

Lower WOB, Higher ROP

Ulterra assembled a team of material specialists, design engineers, and performance optimization experts to create a PDC bit platform that was superior to both traditional matrix and steel PDC bodies and that would allow the cutters to get deep into the formation to increase ROP. This team of experts ended up creating the FastBack™ series of bits, which are designed to drill faster with lower WOB. FastBack is designed to get the bit body out of the way so that the drilling is focused on the sharp, diamond edge of the PDC cutter. The energy provided by the PDC cutting structure in these designs requires less WOB while still providing a greater ROP than traditional bits.

Ulterra also offers CounterForce® technology which is focused on the cutter orientation to maximize rock failure and drilling efficiency. CounterForce cutters work synergistically to engage the formation and optimize crack propagation by re-directing resultant drilling forces back into the rock. The angles of the cutters are designed to shear rock more efficiently while keeping the cuttings moving away from the crucial sharp edge of the cutter. This helps reduce reactive torque and improves bit stability for better control and wellbore quality.

With both of these advanced technologies from Ulterra, less weight on bit is required to drill because the bits are more efficient at translating the energy from WOB into cutting action. This translates into a wider envelope of useable drilling parameters, less possibility for drilling dysfunction and overall reduced rates of damage to the bit.

 

 

 

 

 

 


PDC Drill Bit 101: What is a Polycrystalline Diamond Compact Drill Bit?

At the end of every drill string lies the most important part – the drill bit. The drill bit consists of man-made diamond cutters, blades, nozzles, and a bit body. Bit selection is crucial and has a vast impact on the overall cost of well construction operations. Today, we want to highlight the most dominant drill bit in the oil and gas industry, the PDC bit. It will focus mainly on the design principals that need to be determined by engineers and designers at Ulterra Drilling Technologies.

What is a Polycrystalline Diamond Compact Drill Bit?

The PDC bit is named after the Polycrystalline Diamond Compact cutting element that shears through the rock in order to drill the well.

There are four main parts to become familiar with when it comes to a drill bit:

  1. the cutters
  2. cutting structure,
  3. the blades,
  4. and the bit body.

Polycrystalline Diamond Compact cutters are typically cylindrical in shape with a thin, man-made, diamond layer on top of a tungsten carbide substrate. These cutters must remain intact to drive the bit’s performance and ensure it functions reliably, and are arranged into a 3D geometry called the cutting structure.

The cutting structure may seem simple, but it is commonly the most intricate part of a PDC bit design.
Typically, the cutters are aligned in rows in order to facilitate better cleaning of the rock cuttings. Each row sits along the top of a blade which protrudes from the bit body, supporting the cutting structure and holding it in place while effectively connecting the cutting structure to the end of the drill string.

In between the blades are junk slots which act as pathways for the drilling fluid to wash cuttings away from the bit face as it drills. The bit body consists of combinations of tungsten carbide matrix materials and steel, just depending on how much tungsten carbide is used and how they are manufactured.

Matrix PDC bit bodies are made of steel at the pin connection and transition to a tungsten carbide-composite material on the outer surfaces. Steel PDC bit bodies are made from raw steel and then coated with hard facing material to increase erosion resistance. Polycrystalline Diamond Compact bits can be designed with a nearly infinite combination of variables, and modified per drilling application.

The bit design and performance requirements are spelled out by the customer and then it is constructed and tweaked by engineers and designers to optimize performance.

There are a lot of factors that must be taken into consideration when designing the drill bit. The most important external factor of design is the size of the wellbore that needs to be drilled, which can be anything from 2 ½” to 36” (6cm to 90cm) in diameter. Other factors are more tailored to its desired use, we have to consider things like the rock and formation type, the operating environment, the capabilities of the other drilling equipment, and the angle of the wellbore.

How is a PDC Bit Designed?

To increase the potential for maximum drilling speed, or rate of penetration (ROP), there are quite a few features that must be considered on a per-bit basis.

Before the designing starts, we need a thorough understanding of the drilling application ranging from the drilling rig capabilities, RPM, weight on bit (WOB), flow rate, drilling tools in the BHA, the rock formation strength and hardness, and the distance drilled.

Once this information is gathered and analyzed, Ulterra takes into account previous applications that were similar and how the bits performed. They use this empirical data and all external factors to create the design and performance expectation before proceeding with the drill bit design portion.

During the design stage, the complete properties of the drill bit are created and adjusted such as cutter size, cutter orientation, cutter density, and nozzle placement. When designing the bit, it is important to let external factors and the specifics of the application guide the design.

The formation type, hardness, drilling parameters, and any directional aspects have a far greater influence on the success of the overall drilling project. It is also important to recognize that there are a lot of similarities in the manufacturing process regardless of the individual design.

There are five main design principals; cutting structure, PDC cutter type, bit body geometry, hydraulics, and body material.

 

Five Main PDC Bit Design Variables:

  1. Cutting Structure

The cutting structure is the part of the drill bit that actively engages the formation and the holistic layout of the active Polycrystalline Diamond Compact cutters in 3D space. The main variables that are taken into consideration when designing a PDC drill bit are the number of cutters, size, and cutter orientation.

Like the rest of the design variables, the drilling application determines the quantity and size of the PDC cutters, also known as the diamond volume. A lower diamond volume provides faster ROP for given WOB, a more responsive reaction to WOB adjustment, more torque for the rig, and low relative abrasion resistance. A higher diamond volume value provides slower ROP for a given WOB, the ability to withstand higher forces before damage occurs, less torque response for the rig, and higher abrasion resistance.

The cutters in the center of the bit are responsible for the aggressiveness of a PDC bit. Large cutters enable complete coverage with a lower cutter quantity as desired. These lower cutter counts increase bit aggressiveness and torque response. Smaller cutters allow for denser packing to increase cutter quantity as desired. Higher cutter counts increase durability and abrasion resistance and smaller cutters have less exposure.

  1. PDC Cutter Type

When referring to the cutter type, I’m referring to the makeup of the specific material of the diamond table itself, the diamond grit that is used, and the methods used to manufacture the cutters. A Polycrystalline Diamond Compact is a highly engineered part and all of these aspects are tightly controlled. PDC cutters consist of two bonded pieces – the polycrystalline diamond compact itself and a tungsten carbide substrate. Polycrystalline Diamond is a cluster of microscopic single crystal diamonds bonded together with a random orientation. The multiple orientations of the crystals in the lattice structures create grain boundaries which significantly increase its fracture toughness. Modern PDC cutters contain a mix of mesh diamond sizes to optimize packing density and void volume.

The exact construction, materials, and properties of the PDC cutter used in a design will depend on the properties required for the application. Typically the engineer must balance between the resistance to abrasive wear and the ability to withstand impact damage. Ulterra custom selects the type of cutter for each individual application depending on what performance is needed.

 

  1. Bit Body Geometry

The geometry of the bit is determined by factors such as the shape of the blades, the configuration of the gage area, the sizes of the flow paths, and all other factors pertaining to the shapes and sizes of the bit. The geometry is determined by external variables like the flow rate, ROP, conditions of the mud, etc. Different size blades, nozzle placements, number of blades all have drastic influences on drilling operations. Typically for a bit that has low diamond volume, the shoulder of the profile is shorter and more aggressive; and for a bit that has a high diamond volume, the shoulder area is longer. A longer bit shoulder will allow for more PDC cutters and increased diamond volume, more abrasion resistance, and less aggression. A shorter bit shoulder has fewer cutters, lower diamond volume, more aggression vertically and directionally, but less durable to abrasive wear.

The geometry of the bit is also determined by the blade count. The blades that extend to the center of the bit are called primary blades, and the blades that start closer to the outside of the bit are called secondary blades. In the center of the bit body profile is the cone area, which is important for keeping the bit stable while also affecting performance. A deeper cone angle allows for increased diamond volume, enhanced bit stability and a bit that is less prone to deviation from the required angle. A shallow cone angle allows for a more aggressive diamond volume, more efficient WOB transfer, and improved directional response.

  1. Hydraulics

The flow of drilling fluid through and over the PDC bit, known as the hydraulics, is incredibly important to the performance of the bit. The fluid flow cleans and cools the cutting structure while also evacuating drilled rock cuttings away from the bit face. To optimize bit hydraulics, changing the nozzle/port count, placement, size, and the vector will improve cuttings evacuation, help to cool the Polycrystalline Diamond Compact cutters, reduce bit erosion, and widen or narrow total flow area (TFA) for pressure concerns.

Computational Fluid Dynamics (CFD), a software simulation package that uses numerical analysis and algorithms, is used to model and optimize the flow and it can completely change the capabilities of the bit. CFD allows Ulterra to visualize the impact that nozzle orientation and placement may have on flow paths, erosion, cleaning the bit, etc. A typical bit will have one nozzle for each blade so that the cutting structure is cooled and cleaned as efficiently as possible. On smaller PDC bits there may not be enough space for this many nozzles but the modeling and design ensure that no part of the bit is “starved” of fluid.

  1. PDC Bit Body Material: Matrix vs. Steel

Matrix body bits are made from a tungsten carbide alloy, which provides improved resistance to abrasive formation wear and fluid erosion. These bodies can withstand relatively high compression loads and it can take formation wear and tear. Properties of a matrix blade, such as the height of the blade, are limited due to the lower impact toughness compared with steel since the material is relatively brittle. Typically, matrix style bodies are preferred for environments that have higher chances for body erosion.

Steel body bits are made of a high alloy steel. These bits can withstand high impact and are often designed with higher blade stand-off which gives more space for fluid and cuttings removal which can increase ROP potential. Steel is relatively soft and without protective features, such as hard facing material, would quickly fail due to abrasion and fluid erosion. Steel body material properties and manufacturing capabilities allow for complex bit profiles and hydraulic designs. The size of the blade that’s constructed from steel allows it to be larger because of its tough and ductile properties. Considering these properties, Ulterra is able to create geometry using steel that we normally wouldn’t be able to construct using matrix. We use these properties to our advantage to construct drill bits that deliver better performance.

How are external factors considered in PDC drill bit design?

Using the data of the conditions of external factors, the design and engineering team can manufacture the bit accordingly to suit the external environment and needs of the drilling operation. The properties of the rock that are being drilled into are a primary factor that determines the design of the bit. There are a variety of different rock types: such as limestone, sandstone, shale, etc. These consist of different minerals and structures that respond differently to torque, speed, force, and amounts of pressure. For example, if the rock is extremely hard and abrasive, there would need to be a greater number of cutters, which would result in an increased blade count. If drilling through a hard rock, these cutters would be slightly smaller, compared to drilling through rock that is relatively soft, in order to improve durability and reduce the risk of damage.

If a drill bit is customized for distance, we take extra precautions due to the different formations the drill bit will go through during drilling operations. For example, in West Texas, interbedded formations that consist of inconsistent rock formations require bit features that will be able to take on multiple rock properties. These rock formations require the bit to take on unconventional designs to provide a solution for both soft formations and hard stringers. While drilling through these transitions, this can be damaging to the drill bit leading to spikes in the load being taken by the Polycrystalline Diamond Compact cutters in the bit.

PDC bit technology changed drastically over recent years because of the increased knowledge of drilling vibrations and how they influence productivity. The highly dynamic drilling system generates undesired movement and impact through vibration patterns as it rotates. This translates into high impact forces which can be transferred to the bits cutting structure and cause damage. The engineers and designers must change and adapt the bit design in order to take into account and resist these impact forces. The bit should also be modeled and balanced so that it doesn’t cause its own vibration and damage while drilling.

The Ulterra Difference

Ulterra places applications engineers in direct communication with the customer to ensure a clear understanding of products required to help deliver the desired results. Using 3D modeling design tools (CAD) to accelerate the design process, Ulterra is then able to design premium performance into every PDC bit. When the designer’s intent is verified, the drawing package is automatically created for production. As mentioned earlier, Ulterra also utilizes CFD to optimize the hydraulics and to reduce erosion of the bit body. Every bit also undergoes a work and force analysis, which helps to model performance and reduce cutter imbalance. Cutter configuration is then designed to distribute work evenly among the cutters to increase the bits drilling efficiency. Although this design process is picked with a fine tooth comb, Ulterra is able to rapidly produce and manufacture new designs within just a few days.


Ulterra PDC Bit and MORE Global Water Provision Story Part 2

We love the second chapter of this story and are proud to have played a part in MORE’s efforts to address the global water crisis. This story first appeared on the https://more-water.org site. It’s a great read from the perspective of an Ulterra PDC bit.

 

“Petey Goes Deep”

When we last heard from Petey, the PDC drill bit – and, no doubt, the sole drill bit blogger on the planet –  he had just arrived, by plane, into the Kenyan coastal resort town of Diani Beach, at the home of my American missionary friends, Chris and Lisa Moore.  While he was thrilled with the beauty of his new surroundings, what he didn’t know was that this was not his final stop – and certainly not his destination.  C’mon, he’s a drill bit, for crying out loud.  Their not supposed to have it soft.  Let’s catch up with him here:

So it didn’t take me long to get used to these new digs.  I was lounging around, while wondering what Bobu had in store for me. But I sure wasn’t stressing about it, I can tell you that.  One morning, just when I was planning to settle in, Bobu rolls me out of my new digs and sticks me in the back of a shiny blue pickup truck.  Then he takes off on some really bumpy dirt roads to – “I have no idea where”.  “Of course not,” I tell myself, “your a drill bit, remember?”  “Everything with you and Bobu is on a need to know basis.”  I’m sure that I’ll figure it out when we get there.  Along the way we stop and meet up with some more of his friends, who all seem happy to see Bobu.  There is lots of laughter and hugging and more of that gibberish that I simply cannot understand.  And Bobu’s joined in with it.  Great!

They fill the back of this pickup with lots of stuff and then connect this cute little drilling machine to the back of the truck.  “Surely”, I assume, “they’re not going to use me on THAT little drill, I hope!”  “Or are they?”  “Ha!”  “If that’s true, I gotta see this!”  We all take off for ‘who knows where’, with Bobu driving again.  Some of the guys pack into the back with me.  The rest ride up front, with Bobu.

Sure enough, after a not-so-long, but bumpy, dusty ride, we stop and all the men jump out and start unloading all the stuff from the back of the pickup, me included.  “Hey, watch how you handle me!”  “I’m a star, you know!”  Apparently they don’t.  Next thing they unhook their little drilling machine and roll it into a corner of this field.  After a lot of jabbering and animated discussion (yeah, I know about that.  I grew up on oil rigs, remember?), they come for me.  “Here we go,” I thought, “this outa be good!”   Sure enough, they connect me to a (really short) piece of drill pipe.  “Hey, I’m used to being at the end of three 30+ feet of connected drill pipes – like 100 feet, ya know!”  “Bobu, are you going to let them do this to me?”  Doesn’t seem to dissuade them from their follies, I see.  Come to think of it, he’s the one that brought me here.  I guess this is what he had in mind.  Fat chance they will get any oil out of this hole.  I’ll just go along with it.  This could actually be quite comical – and fun, who knows?

But what is this?  They didn’t install my nozzles.  They connected the drill pipe to the drilling machine and just began drilling me into the ground, with no water, no mud.  “What’s with that?”  I screamed.  But nobody heard me, evidently.  Oh yeah, I’m a drill bit.  Sometimes I forget that.  Needless to say I was just getting plugged with the topsoil layer.  And the drilling, if you want to call it that, wasn’t going very fast at all.  Finally they started pouring some water into the hole and that helped a little.  But it was obvious, these guys didn’t know anything about drilling oil wells.

After drilling only a few feet, they stopped and brought me back to the surface.  Then they all got together and pushed and tugged and moved the drilling machine. Yeah, by hand!  That’s how light it was.  But they only moved it about 10 feet.  Once the drill was anchored, they went through the same process of using me – a world class rock bit – to drill a couple feet through mud.  How peculiar.  I was actually getting embarrassed for Bobu.  As their apparent leader, it would help if he knew something  about drilling, don’t ya think?  Eventually the second shallow hole was complete – and I was, once again, laden in mud, my water cavities stuffed full of the heavy stuff.  When they raised me back to the surface and removed me from the drilling machine, at least they took the time to wash me.  They did a good job, too.  It felt good to be clean again.  Then they put me back in my box and left me for a couple days.

The next time that Bobu brought me back out, He did insert my nozzles.  Huh, maybe he does know what he’s doing.  Then they attached me to another of those cute little drill pipes, and inserted me onto the drill machine.  Just before I dropped below the surface, I saw those two shallow holes that they used me to drill a couple days before.  But now they were filled with concrete, it appeared, and a steel hook was sticking above the top of the concrete.  To that they had attached straps, which were wrapped around the drill machine’s outriggers.  “Oh, I get it now,” I thought.  These are used to anchor the light-weight drill machine – so that it could exert more force on the drill pipes – and on me.  Why, that’s rather ingenious.  Maybe these guys are smarter than I thought!

As I descended, I could see that they had actually drilled pretty deep.  Well, not thousands of feet, like I’m used to on those big Texas drill rigs.  But over a hundred feet, I bet.  That seemed pretty good for this little drilling machine.  As I continued down the hole, I could see that there were layers of various types of soil, and some occasional rock.  There were a number of layers with water coming out of them.  That happens a lot in oil drilling.  Most of the water is just a nuisance, I remember them saying once, when I emerged from a deep hole.  But these guys don’t seem to mind. That’s all they were talking about, later, when they brought me back out of the hole.  I wonder whats with that?

The drilling was so much slower than I’m used to on a mammoth oil rig.  But it was steady.  And it was probably all that this little drill rig could muster, as it didn’t seem very heavy.  But it sure was working hard.  Everyone was.  And they all seemed to like what they were doing and talked real nice to one another.  I was starting to feel better and better about this.  It was not hard work, really.  I just was not sure if this machine could ever drill me deep enough to hit oil.  I started to feel bad for them, because I didn’t want to see them disappointed.

The next morning they started the process all over again.  Connected me to the drill machine, which slowly lowered me down the hole, one small drill pipe section at a time.  And then it happened, something I never had experienced before.  About half way down the hole, or so, I plunged into water.  I wasn’t drilling yet, because they had not turned the mud pump on.  But I was submerging ever deeper into cool water.  Then when I got to the bottom of the hole, where we had stopped the night before, they turned on the mud and I started drilling again.  We drilled all day again, stopping from time to time. But not ever for very long.  It was still slow.  But it was steady.  Some of the rock that I was drilling through was really quite hard, I could tell.  But it was no match for my razor-sharp PDC -teeth.  Slowly, but surely, I was chewing right through it.

Each time that they brought me back to the surface, I noticed that there were a lot of people watching.  Women and children, as well as men and young boys.  They always seemed excited to see me.  I was experiencing something new.  I never had drawn a crowd of onlookers before.  On the oil rigs it was always just a few rig workers, who never said much.  Just gave orders to one another.  But these people were different.  They really seemed to like me, as they would point and jabber quickly, whenever I emerged from the hole – even if I was covered in a layer of crushed rock particles.  When Bobu or one of the workers would wash me off, several of the onlookers would come close to watch.  Some even came over and ran their fingers over my teeth and many curves and grooves.  They seemed fascinated with me, even as I was with them.  I could not tell what they were saying, but they would talk excitedly to one another.  I must say that I was enjoying my return to center stage.

That night I started thinking more about the water in the well – how cool it felt – and how unusual.  Then I remembered hearing some of the stories that several of the drill bits that went through the “spa treatment” with me back at the Ulterra shop.  Some of them said that they didn’t drill oil wells, but water wells.  How peculiar, I thought.  Whats the purpose?  Its the oil that everyone is fighting over, right?  Not water. Water’s cheap.  And besides, it just gets in the way and becomes a nuisance, right?   But I could see that this was all starting to make more sense – in a weird sort-of way.  What if it’s the water that these people are all milling around and talking excitedly about?  Maybe there is no oil here – only water.  So, maybe now I’m a water well drill bit?  Like some of those bits back at the spa.  I’ll have to think about that some more.  But hey, if it makes them this excited – and helps me retain my “rock star image”, then I could live with that.  Live with it, huh! – I answered myself – I could downright revel in it. “Hey everybody, I’m a water well-drilling rock star!”  Ya know what?  I like that.  If these people want water – then I want to help them get it.  That night I went to sleep feeling really good about my new role.

And that’s how Petey came to be in Africa, drilling water wells.  I can report to you that he really does like his new job – and the people he serves.  He is doing an awesome job and truly is – a “rock star drill bit!” 

 


New Drilling Bit Design from Ulterra featured in World Oil Article

The following extract on drilling bit design is from World Oil October 2017 and is used by permission.

Uptick in Activity Spurs Development of New Bit Technologies

 

DRILLING BIT DESIGN

Increased drilling activity associated with improving commodity prices is driving drill bit manufacturers to develop more efficient hydraulics for cuttings evacuation in softer formations, in addition to technologies designed to improve one-run success rates in challenging directional applications, and in hard/abrasive formations.

By CRAIG FLEMING, Technical Editor

With continuing advances in PCD cutter technology and improved bit body stability, PDC bits have become the dominant force in the worldwide drilling theater, practically replacing the venerable roller cone product. Their high ROP potential and unparalleled durability make PDC bits the tool of choice in both high- and low-cost environments. Even in the toughest applications traditionally reserved for roller cones, PDCs have virtually eliminated the situations where operators are forced to fall back on these types of bits. Today’s PDC bit technologies will positively impact performance and drive down the real cost/ft.

IMPROVED CUTTINGS EVACUATION

drilling bit designUlterra Drilling Technologies’ latest innovation is the patent-pending SplitBlade PDC bit (Fig. 4) that is increasing ROP and reducing drilling time with reconfigured cuttings evacuation, cutter cleaning, and bit cooling.

Typically, with most PDC technology, recirculated rock cuttings become trapped at the toolface, and the build-up clogs the junk slots. Trying to recut old cuttings that should have been evacuated quickly wastes energy, in addition to degrading the bit.

The company’s research team examined the physical restraints of a basic PDC drill bit. The engineers proposed a new pattern that would maintain the cutters in a cleaner, cooler state. The improved thermal management of the bit face would support the goal of extending bit durability and lead to higher performance.

Using CFD, the team created a distinctive bit body, with new blade geometry, nozzle placement, and cutter layout. By splitting the shape of the primary blades with an angular offset, designers created designated flow channels for the fluid and cuttings. Two nozzles are positioned to support the cutters in the critical area to capitalize on this advancement in bit body construction and hydraulic control. While drilling, cuttings from SplitBlade technology can be evacuated up to seven times faster, compared with conventional designs.

CASE STUDIES

In the LaSalle County portion of the Eagle Ford shale in South Texas, an operator was experiencing poor cuttings removal and plugged nozzles. To solve the issues, an 8½-in. SplitBlade PDC was run, and it drilled the curve 27% faster than offsets. This run set a company formation footage record of nearly 14,000 ft, MD, for the curve and lateral. The ROP of more than 150 ft/hr was 8% faster than the offset average in wells over 10,000 ft. In the eastern Eagle Ford, another operator wanted to reduce the instances of nozzle plugging to improve ROP, and selected an 8½-in. SplitBlade bit. The plan was to improve lateral and overall ROP with better directional control and cuttings removal. The bit was run, and it set a rig footage and ROP record, drilling the lateral at 400 ft/hr instantaneously and, overall, just less than 12,000 ft in under 68 hr. The average ROP of 172 ft/hr was 56% faster than the average run on this rig.

View the original Article here:
Original World Oil Oct 2017 Article PDF

 


Ulterra PDC Bit and MORE Global Water Provision Story

We love this story and are proud to have played a part in MORE’s efforts to address the global water crisis. This story first appeared on the https://more-water.org site. It’s a great read from the perspective of an Ulterra PDC bit. 

What?  You don’t think a drill bit can have a story? Well, I have one.  And it’s a pretty cool story, I think – if anyone cares to listen!  You see, it all started in a factory in Texas, at a company called Ulterra  They are manufacturers of all kinds of drill bits.  But they specialize in PDC Bits.  So, what is a PDC Bit, you may be asking.  Good question.  It stands for Polycrystalline Diamond Compact. That’s a real tongue twister, eh?  All it means is that they use small particles of manufactured diamonds – not the super expensive natural ones that are made into rings and other fine jewelry.  But just as hard. These particles are integrated into randomly oriented crystals to form a thin matrix that is effectively bonded with a tungsten “table”.  These tables can then be easily be brazed onto the steel drill head.  It is only the PDC “table tops” that contact the formation during drilling.  Eventually these cutter heads wear down and have to be replaced.

Anyway, I can’t remember how many holes I drilled as part of a large stable of similar PDC bits, in all shapes and sizes, while working on large drilling platforms in South Texas.  But eventually, me and some of my bit buddies in our group, were cleaned up, packed up and shipped back to the Ulterra factory.  Some of the old timer bits told me not to worry, that I would be back.  I was just going in for my “spa treatment” at Ulterra’s fancy “salon”.  Nothing more than a “wash and perm” they said – and maybe a pedicure!  “Sweet!” I thought.  I could use some R & R. Here I would have my worn PDC cutters removed and brand new ones brazed back into place.  Quickly my trepidation turned to excitement.

But after my visit to the salon – which was wonderful, as expected – and with my brand new sparkling diamond matrix cutting heads, I was not returned back to the oil drill rig.  Instead they took me to some new shop, where some guy came and picked me up.  He seemed really excited when he saw me, which nearly made me blush!  Then he held me up for show while he and his friends took pictures – of me!  I was thinking, “wow, maybe I’m going to get some kind of award, or something!”  But for what, I was trying to reason with myself, while not trying to act too “puffed up”.  Then, of all things, the guy takes me home and sticks me in a corner in his tiny apartment.  “Hey”, that’s no way to treat I star!” I wanted to tell him.  But I didn’t.

Oh, but that’s when it really starts getting weird.  One day he brings home this plastic box on wheels.  Then he sprays some kind of stinky liquid that starts growing into this crazy foam.  While it is still forming he drops me into this gooie quagmire and sprays some more of this gross stuff, all around me.  When it hardens in a short time, he tries, but can’t even move me.  I’m stuck.  But he doesn’t seem to care.  In fact, he actually seems quite impressed with my predicament.  He even shows me off to his neighbor, I remember.

The next thing I know (a few days later), he rolls me into an airport, where they weigh me.  Then after sitting there for the longest time, he takes me over to a corner and cuts off the plastic ties that he used to secure the top of the rolling box.  What now, I thought.  This is getting weirder by the moment.  Before I had the words out of my “mouth”, he starts cutting away at the hardened foam around my body, with this really big pocket knife.  I thought for sure he was going to cut me up, but he was very careful to only cut the foam.  So how did he get this big knife into an airport, I was thinking.  Geez, is he some kind of terrorist, or something.  Oh no!  Better be quiet about that, I figured.

So then he pulls me loose from the container and unscrews this fancy steel connector thing that he had made at another factory, before he put us into the ice chest and sprayed the foam – all around us.  I didn’t tell you about that trip – to the other factory – to have this “skirt thing” fabricated.  Mainly because it’s just too weird, but also because I heard them talking at that factory when they were measuring my “bottom”.  They said I was “too big” to fit on the guy’s pipes.  While they said, “too big”, I know that they really meant “too fat”!  How do you think that made me feel? No way to treat a rising star in the oil and gas drilling arena, right?  Geez, I really don’t get any respect.

Okay, so, we’re back at the airport. When he gets me loose, he unscrews the skirt thing from my “bottom” and lays me back into the ice chest.  But not before taking “skirt guy” and wrapping him in bubble wrap and putting him into his checked bag.  “Oh man!” I thought, “I was enjoying that bubble wrap.”  It was cozy, like a comforter – for wherever we were heading off to.  But it did feel good to have that skirt thing off my bottom, I had to admit.  Then he closed the top and secured it again – for my journey to “who knows where”.

In what seemed like days later, and several plane rides and airport transports, before I once again saw the light of day, but had no idea where I was – only that I couldn’t wait to get out of this box.  (It was, actually three days, as there was a huge mess-up by the folks at Delta-KLM, in getting both me and my drill bit from Houston to Nairobi, after overnights in Atlanta and Amsterdam.  My bags actually didn’t arrive in Nairobi until a day later.)  When finally, my box lid was opened, I was confronted with several quite different-looking folks (different than my traveling friend, anyway).  They were jabbering in a language, also totally different than my friend, while pointing at me.  Evidently they had never seen a high-classed PDC bit like me before, I thought.

Finally, after a lot of turmoil and more jabbering, some nice, quiet-speaking lady, who was talking in a language somewhat similar to my friend – but sweeter, and prettier-sounding, she must have helped my friend work it all out.  She eventually re-closed my box lid and I was rolled out of that building and into a car, apparently.  A short time later – much shorter than the plane rides, I was handed over to my new friend, who seemed excited beyond belief to see me again.  I could see he was beaming as he showed me off to his friends – who looked more like him, I noted.  Once again I’m sure that I blushed.  I couldn’t help it!  He then rolled me into this house and I found myself in my own room.  Awesome, I thought, this is where this guy really lives – in this lovely large house – and not that tiny, cramped apartment.  Good for him, I thought.  Maybe he’s not a looser, after all, I conjectured.

But no, it was not to be, I soon found out.  The next day he again secured me in my box and we went on another car ride – to yet another airport.  “Oh no, not again,” I thought.  But this time I was loaded onto a much smaller plane, I could tell.  I knew that because I could still hear people talking, even as me and my luggage companions were nestled into our own compartment and the plane took off.  Actually it was more like crammed-in than “nestled”.  But this time, no sooner had we taken off, I could tell, but we were landing again.  Then he rolled me out and packed me into another car.  By now I was learning that his name must be Bobu, because that’s what I heard everyone calling him here – and in the US, as I now recall.  In fact a pretty young lady, along with three really cute kids, all called him that as she was helping him finish packing me into my traveling box, before our trip to the airport, I remembered.  Now he was rolling me into another house.  Here, he, once again, opened my box and showed me off to two more of his friends – both of whom looked like him.  But not exactly.

This time I don’t remember blushing.  I was too busy taking in my surroundings.  “Oh my”, I thought, I don’t know if he lives here or his friends do, but this is more like it.  There were beautiful palm trees and flowering tress and plants – everywhere.  I saw more people splashing around in some well-fashioned watering hole and the sky was bright blue and the sun was beaming down.  You have to understand, having spent my whole existence hanging around oil drilling rigs or being screwed deep into rock formations below the surface, this was all quite amazing to me. Surely, this must be drill bit heaven, I concluded.  Finally, a surrounding worthy of my beauty and elegance as a star-studded PDC bit – I justified, if not even somewhat indignantly. Yes – finally, I had arrived!