Tag Archives : PDC drill bits

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!” 


Leading oilfield PDC bit company partners with Childhood Cancer Canada Foundation

There are currently more than 10,000 children battling cancer in Canada right now. The Childhood Cancer Canada Foundation is dedicated to creating victories for Canadian children with cancer. On average, only 5% of cancer research funding worldwide is put toward childhood cancer. The Childhood Cancer Canada Foundation has helped raise awareness and generate donations to be put towards childhood cancer research becoming the leading foundation funding national research on pediatric cancer.

Ulterra, LP is a PDC bit company that is partnering with the Childhood Cancer Canada Foundation to help raise awareness for those battling with the diagnosis of childhood cancer and to further research efforts. “At Ulterra we create long lasting relationships with our customers that extend well beyond the works of the field or office. Once it was brought to my attention that one of our customers was dealing with the effects of this awful disease I knew it was our job to help in any way we could. We decided to partner with the Childhood Cancer Canada Foundation to help raise awareness and show our support in funding research for childhood cancer,” said Jason Cunningham, Ulterra Vice President of Canada Operations.


With September being National Childhood Cancer Awareness Month Ulterra will be painting all of their iconic teal bits coming out of Canada’s manufacturing facility purple to further help their efforts in raising awareness. “Most people don’t even know that childhood cancer exists and when they hear about it they are very surprised. Childhood cancer is really underfunded so awareness to get the word out becomes very important,” Says Lorena Muñoz, Childhood Cancer Canada Foundation Senior Manager.

In addition to raising awareness, Ulterra will also be donating $25,000 to the Childhood Cancer Canada Foundation on August 25, 2017, in Leduc, Canada to help fund childhood cancer research as well as contribute to the amazing programs they have. Ulterra will extend their efforts into the field by handing out purple t-shirts, as well as educational pamphlets in support of childhood cancer awareness throughout Canada.

Ulterra chose to partner with the Childhood Cancer Canada Foundation due to its commitment and experience when it comes to helping those who have benefited from childhood cancer research and their many other programs. “Our ultimate goal here is not only to raise awareness and funds but to get rid of childhood cancer all together. When we no longer need to be here, that’s when our job is done,” states Muñoz.

In the last 10 years alone the childhood cancer research community has decreased the mortality rate by 25% in children battling cancer. Through various programs, the Childhood Cancer Canada Foundation is able to help many of those who have had to deal with the effects of childhood cancer.

Jason Cunningham states, “This is the reason why organizations like The Childhood Cancer Canada Foundation are so important. So many kids are being affected by this awful disease, it’s not only our duty but an honor to help these families fight the good fight.”

To learn how you can help visit http://www.childhoodcancer.ca/

Hart’s E&P June 2017

Featured in the June issue of Hart’s E&P, Ulterra discusses how new bit designs are pushing drilling boundaries. Over the past year, Ulterra has looked critically at bit design, blade geometry, cutter reinforcement and hydraulics and has been testing new materials, which has resulted in its XP™ line of polycrystalline diamond compact (PDC) bits. With the increased energy going through the bit, it is Ulterra’s goal to make sure the bits do not become the limiting factor in performance.

Hart’s E&P June 2017

Read the full article from Hart’s E&P here.

Ulterra’s Leduc Manufacturing Facility Achieved 2 Years with No Recordables

Ulterra continues to set new standards in all areas of operations with safety being no exception. On April 21, 2017, Ulterra surpassed another safety milestone with the Leduc Manufacturing Facility achieving 2 years with no recordable injuries. “Safety performance like this is important in keeping a competitive edge in an ultra-competitive market. More importantly, the effort and dedication of our employees toward health and safety are critical in going home the same way they arrived at work, injury free” states Bryce Cook, HSSE Manager.

We would like to extend a very special thank you to all of the Leduc employees who continue to make safety a priority every day. While the team acknowledges that this is a great accomplishment to take pride in, they are not ready to stop here.