Bottom Hole Assembly 101

Bottom Hole Assembly or BHA

The Bottom Hole Assembly (BHA) is a key component of the drilling system, consisting of various components and tools (including the drill bit itself) which operate at the bottom of the wellbore and physically drill the rock. The BHA is connected to the drilling rig by the drill pipe, an extendable hollow tube which conveys the mechanical and hydraulic energy and movement from the surface rig systems to the bottom hole assembly. This complex arrangement of tools varies considerably depending on requirements, and can stack up to 1,000 ft long. The BHA has become more complex over time to suit the needs of drilling operations and to accommodate different tools that have been developed. This article will explain the desirable objectives of the BHA in both vertical and directional drilling. We will also highlight the different key components of a bottom hole assembly and their functions. The main purpose of a BHA is to effectively load and control the drill bit, but it also serves other functions that will be discussed below.

Designing the BHA

When designing the BHA, drillers must consider the operational objectives, characteristics of the rock being drilled, anticipated drilling parameters, and available tools. Operational objectives that should be considered include the angle being drilled, directional and depth targets, the expected ROP, and how to achieve designed build/drop rate. The geological characteristics that should influence the design of the BHA include the abrasiveness and competency of the rock, bed dip angles, and the pressure regime in the hole being drilled. The drilling parameters that must be anticipated to design the BHA include the applied RPM range, desired WOB, torque, and the anticipated shock or vibration pattern.

How an Optimized Bottom Hole Assembly Benefits the Driller

Since drilling cost is so dependent on time, employing drill bits and proper BHA tools is crucial for faster and less expensive drilling. Drilling time is greatly affected by both the rate of penetration (ROP) of the drill bit, and the number of times the BHA has to be retrieved from the bore hole. Every time a new bit is required, the entire drill string must be retrieved section by section to pull the bottom hole assembly to surface and change it out. This process is known as a round trip, or “trip” and requires time, money, and intervention from the drill crew which puts them at risk. If any part of the BHA is defective or fails, the drill string must also be pulled out from the borehole to replace or repair the defective component, an undesirable condition which we must try to avoid through careful selection of components.

It is crucial to review bottom hole assembly components, such as the drill bit, reamers, and stabilizers in terms of functionality and layout in order to limit possible damaging vibrations. Adjustments and additions to the BHA can lower the potential for vibration improving cost-effectiveness and reducing the risk of failure. To configure the bottom hole assembly, design optimization software is used to help in mitigating cost and eliminating ineffective drilling operations. Also, down hole tool measurements and data must be observed continuously to identify and record the behavior of the bottomhole assembly.

Components of the Bottomhole Assembly

The BHA is the business end of the drilling system that attaches to the drill string and is lowered down in to the hole. The threaded male and female ends of the drill pipe allow for more pipe and tools to be attached so that the drill string extends down to the thousands of feet required to drill an oil and gas well. Individual drill pipe segments, drill collars, and tools are all connected on the rig floor and then deployed downhole. These tools enhance the drilling operations and all serve different functions to work together to accomplish drilling objectives. The key structural components of the BHA are as follows:

  • Heavy-weight drill pipe – These pieces of pipe have thicker walls compared to the outer diameter of a regular drill pipe, and are used as a tapered transition between the drill collars and drill pipe while helping to add weight and stiffness. As previously mentioned the drill pipe functions to connect the rig surface equipment with the bottom hole assembly and the drill bit, allowing us to pump fluid to the bit and to move the bottom hole assembly as needed.
  • Drill collars – These are the large diameter and heavy pieces of pipe above the drill bit and below the drill pipe, which constitute the fundamental structure of the BHA. The weight of the drill collars applies compressional force (WOB) directly to the bit while keeping the more flexible drill pipe in tension to prevent buckling. This also conveys momentum and stiffness as the entire drilling assembly rotates, in order to keep the bit drilling smoothly and consistently.
  • Stabilizers – These are short components with larger diameter fins called “blades” which stick out close to the diameter of the hole being drilled and are used to centralize the drilling assembly within the hole. Stabilizers have these blades attached or integrated to their external surface and are distributed from above the bit and through the drill collars depending on what form of stabilization is required. As the components with the largest diameter in the BHA they often interact with the sides of the well, creating friction and a restriction on fluid flow, so their design and positioning is crucial.
  • Reamers – These are tools that enlarge, maintain or trim the side of the wellbore for various reasons, including easier electric logging, improved drilling performance and bit life, and reduced friction and vibration caused by a miss-shaped hole.
  • Various Subs – These are short components that are often used to connect other pieces of the BHA (crossover subs), or carry out specific functions. Some examples of the latter are subs which redirect or control the fluid flow (diverter and float subs), and subs which absorb movement and vibration to protect the assembly (shock subs and vibration dampening tools).

In addition to the main components listed above, the BHA typically includes a downhole motor or a Rotary Steerable System (RSS), and Measurement While Drilling (MWD), and Logging While Drilling (LWD) tools. These are the main drilling, steering, and recording components that, along with the bit itself, do the work of the bottom hole assembly:

  • Down Hole Motors – These motors provide additional power to the drill bit by converting the energy and flow of the drilling fluids to create additional rotation, and torque using a cavity pump system. This tool improves efficiency and power as it is connected directly to the bit. The housing of the motor also contains a fixed bend angle that can be pointed in a required direction to make the bit steer.
  • RSS – This will replace conventional down hole motor directional tools to help control wellbore trajectory in directional drilling. There are many different designs of tools but they all sit directly behind the bit and either push or point it in the required direction to make it steer. A rotary steerable tool is more expensive than a down hole motor but offers more precision and control.
  • MWD and LWD Tools – These tools are drill-collar-like components containing complex electronics and sensors. MWD tools measure and record the physical properties of the drilling process while LWD tools use electronics and sensors to log the properties of the rock and the drilling environment. These tools communicate this data to the drilling team on surface in real time so that they can adjust the drilling process to achieve objectives.

As mentioned earlier, the drilling parameters, and more importantly the direction of the wellbore, determine the necessary tools that make up the bottom hole assembly.

Vertical Drilling

A vertical hole is a hole that is drilled straight down in to the earth’s surface, with some minor vertical deviation allowed. There are many different layouts of BHA that are used to drill vertically, but most use little or no stabilization near the drill bit, combined with the weight of the drill collars, to allow the BHA to constantly drop back to vertical under gravity and maintain a vertical hole. A down hole motor with a straight housing is sometimes used to improve performance in vertical drilling by adding extra RPM and power directly to the bit.

Directional Drilling

Directional drilling is any type of drilling method that is intended to hit a predetermined subsurface target. These targets are precisely pre-planned so that the drilled well goes exactly where needed within the reservoir rock, often when the target reservoir cannot be accessed using a straight vertical hole from surface. This can occur if multiple wells are required from the same surface pad or platform, if the area is inaccessible for various reasons, or simply just to maximize the recovery potential by having more hole through the reservoir rock. A directional bottom hole assembly has almost an infinite number of layouts depending on what targets are required and what tools will be incorporated. Typically though, the BHA for a directional hole will incorporate either a down hole motor or a rotary steerable system in order to point, push, or steer the bit in the correct direction. The directional BHA will also contain an MWD tool which measures the angles and trajectories of the well bore and relays them back to surface to make sure the well is still on target.

Functions of the BHA

In drilling operations, the bottom hole assembly consists of components of the drilling system that act as penetrating, stabilizing, and maximizing tools to help aid in discovering hydrocarbons. The BHA provides the weight exerted on the drill bit to effectively break rock and so it also functions to provide the strength and stability needed to run in compression. The stabilizers that are in the bottom hole assembly help in preventing bit instability from the vibrations and wobbling that occur when shearing through rock formations. The BHA also helps in maximizing directional control by providing both stiffness and the precision tools necessary to steer the bit in the correct direction. Factors including hole shape, direction, and well characteristics are determined by the BHA, and so proper design of the bottom hole assembly must be made to control direction, ensure safety, and increase drilling efficiency.

Located at the end of the bottomhole assembly is the drill bit, which cuts through the rock structure to explore and exploit oil and gas reservoirs. Using a bit that is right for your drilling application is important, and having the right bottom hole assembly provides support, direction, weight, torque, and capabilities to maximize drilling performance. The bit design and the BHA layout should be carefully planned and matched in order to maximize the performance of both. Proper selection of the BHA and the drill bit help deliver drilling functionality, effectiveness, and overall results. Through examination of field results and research, our team works to constantly improve to ensure that our PDC bits and downhole tools are not the limiting factors in drilling operations.


At Ulterra, we develop groundbreaking technology to suit our customer’s drilling operations. Our patent-pending CounterForce® technology is a true advancement in PDC bit design. Unlike conventional PDC bits, CounterForce technology has a unique cutter orientation that allows the cutters to work together and force the bit to grasp the bottom hole pattern. Our CounterForce technology reins-in lateral forces and redirects them from the hole to effective

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.







Ulterra’s Leduc Facility Achieved 1,000 Days with No Recordable Incidents

Tuesday, January 16, 2018, marked 1,000 days since a recordable incident within Ulterra’s Leduc Manufacturing Plant! This milestone is a reminder of Ulterra’s hard-working team, safe working environment, and effective Health, Safety, Security, and Environmental (HSSE) policies.

“Phonebook size safety manuals don’t make a safe workplace.” Said Bryce, Manager of HSSE. “The choice we make every day to work safely and look out for our coworkers as well as quickly and effectively addressing hazards when they arise creates a solid foundation that allows a culture of safety to be created.”

Ulterra has pride in achieving a shared vision of excellence, by managing business activities through a fully integrated Health, Safety, Security, and Environmental Management System. This vision includes properly inspected and maintained premises, plant, and equipment to ensure safety to all employees. It is also Ulterra’s vision to ensure that we provide our team with a suitable environment by providing adequate information, training, and the required supervision. We also make it our obligation to be constantly improving our HSSE processes by reviewing and revising policies, as well as monitoring the compliance and performance of our employees using our HSSE Management System.

At Ulterra, we work to empower our employees to immediately stop work when they encounter any unsafe working conditions and to immediately seek help to correct the problem. We also consider ourselves as responsible corporate citizens and we actively work to minimize our environmental impact.

On behalf on the entire Ulterra team, thank you to our HSSE Team, as well as all employees at the Leduc Manufacturing Plant. Congratulations to everyone who helped make this milestone possible. Here’s to 1,000 more days!

Oil Demand Peak: Have We Seen It Yet?

The topic of oil supply and demand has always ridden a roller coaster of speculation. Lately, the discussion has shifted from peak oil supply – the idea that we have reached or are reaching the maximum level of oil production possible – to peak demand. However, most view the topic and commodity that is ‘oil’ much differently than they do the broader concept of energy. In this article, Spears does a good job of suggesting ways, albeit taken for granted, that energy use is rapidly increasing and likely to for decades to come. For now, that means hydrocarbon production must keep up, and it is critical that we find new ways to do so that are safer, more environmentally friendly, and more economical, which is exactly what Ulterra attempts to do every day by designing ever-more advanced PDC drill bits and drilling technology.

Peak Ahead?

Lost in the discussion about when oil demand might peak due to the adoption of electric vehicles is the broader, long-term outlook for global energy demand. Indeed, while one camp of energy forecasters see overall energy demand as continually rising, other groups such as the World Energy Council believe that global energy demand is destined to peak. Read the rest of the article Peak Ahead? from Spears Research.


Ulterra Featured at Fort Worth Mayor’s International Luncheon

Ulterra Drilling Technologies is based in the heart of downtown Fort Worth which is considered one of the fastest growing cities in the United States. Fort Worth has continued to grow within the last two years making it 7th in U.S. population growth leaving tons of room for economic development. There are many big name companies that call Fort Worth home like Ulterra. With Fort Worth being centrally located between DFW Airport and Alliance Airport, it makes international business on logistics for local businesses a lot easier. There are currently 56 international flights out of DFW every day making it convenient for business leaders to have better access to international markets. Alliance airport is the only international commercial airport in the area which opens the door for quicker import and export practices.

It’s predicted by the next census date that Fort Worth will become the 12th largest city in the United States. As Fort Worth’s population grows it’s vital that business in domestic and international markets continue to rise and create job opportunities to support the increase in population. A luncheon was organized by the Fort Worth Chamber of Commerce to discuss how companies in the Fort Worth area are contributing to the success of international business and making Fort Worth an international business hub. The Mayor of Fort Worth, Betsy Price looked to Ulterra to sit among other key players in select industries to discuss the potential for Fort Worth to become an international hub of innovation. Mayor Betsy Price remarked “Ulterra represents both Fort Worth’s history in energy and our future in technology.”

Ulterra was called on by the Fort Worth Chamber of Commerce to discuss their experience in doing business not only on a domestic level but also in international markets. The Chambers main business function is to recruit and retain business, provide a skilled and educated workforce and provide resources for business owners and employees. Mayor Betsy Price talked about the importance of making Fort Worth a destination for global business development, attraction and retention. Fort Worth has a very diverse workforce and many have chosen to operate their corporate headquarters in the heart of it, such as BNSF Railways, Pier1imports, American Airlines and Ulterra Drilling Technologies. “We are much more than just the aviation, defense and energy industry. We are a very multicultural and multinational city with major corporations with huge international presences,” said Mayor Betsy Price.

Ulterra’s CFO Maria Mejia was among a few selected to join Mayor Betsy Price along with Raanan Horowitz, President and CEO of Elbit Systems of America and Phil White, Co-Founder of Cervelo Cycles for the annual international luncheon. Maria sat on a panel in front of 250 plus attendees and took a deeper dive into the success stories of companies with an international presence that are local to Fort Worth. The Chamber looked to Ulterra to gain insight on how to successfully attract international business and retain healthy business relationships in international markets. Ulterra is currently the leading PDC Bit Company in the United States having the most market share driven from innovation, solid work ethic and the resilience to win.

Many of the attendees at the luncheon were top players in their industries looking to gain insight on how to drive their business’s into international markets. The goal is to make Fort Worth a more attractive place to do business on an international level. Fort Worth has a cross-industry workforce and is full diverse cultures, businesses, and lifestyles making it an attractive place to not only live but also to do business in. “International employees, partners and customers appreciate visiting our facilities in Fort Worth. Hosting international oil and gas conferences such as the SPE (Society of Petroleum Engineers) and the IADC (International Association of Drilling Contractors) allows us to showcase our home turf to the entire industry,” Said Maria Mejia, Senior Vice President and CFO of Ulterra Drilling Technologies.

Maria continued talking about some of the obstacles as well as the triumphs Ulterra has faced going into new markets beyond the United States. “When expanding globally it can be hard to replicate Ulterra’s culture. Our business model requires a deep understanding of the customer, their needs and the culture in which they operate. We have to prove that we are able to deliver value internationally just as much as we can deliver locally,” says Mejia. Understanding international markets and how they differ is a key to gaining market share internationally. There are times when consumer education has to be put into play just to market your products in other countries, it’s all about the hierarchy of effects when it comes to selling in international markets.

The Mayor touched on key initiatives that have the potential to make Fort Worth stand out in DFW as its own entity. Idealistically the larger business community could come together to better define Fort Worth’s commercial brand both to attract like-minded businesses and startups and to help them market themselves by association. Having stronger business relationships within the Fort Worth area could make international business ventures more collaborative and less daunting. The Chamber strives to develop country targets for new businesses based on current industry clusters, skill set and local relationships. “I was very intrigued by the Mayor’s determination to bring more international business ventures to the Fort Worth area. As Fort Worth gains more recognition good things will happen for the people and businesses in our area,” Says Angela Schlemmer, Vice President of Tax and Treasury of Ulterra Drilling Technologies.

Ulterra is recognized for its unique culture, which consists of doing things better and faster. International success depends on the ability of a company to meet the demands of the customer and being able to efficiently adapt to the changing needs of customers across borders. The future of international business depends on being competitive on a global scale, this means Ulterra would have to continue dominating in the U.S. and continue gaining new market share through technological advancements and innovation in the oil and gas industry as a whole. For customers to adopt new companies and products in international markets you have to adapt to the culture of purchasing in those areas. “It’s a combination of relationship selling, technical ability, know-how, backup, and support function. It’s normally something cool and established that people can latch onto like our CounterForce® technology,” Says Chris Gooch, Application Engineering Manager of Ulterra Drilling Technologies

In the oil and gas industry, Ulterra is known for its speed, quality, technology, and trustworthy business acumen. This has led to Ulterra achieving better business relationships internationally as well as in the U.S. Being a successful entity in international marketplaces is not an overnight process. Ulterra takes the time to assess cultural differences and align them through technology and innovation all while delivering what the customer needs and keeping Ulterra’s competitive advantage, which begins with their speed of delivery. Ulterra started in the U.S. with the belief of becoming viable and is now thriving in the most competitive market on the planet making them the fastest growing drill bit company in the world.

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.

Launching SplitBlade for Improved ROP Through Cuttings Evacuation

Ulterra Drilling Technologies has proudly launched SplitBlade™ as the new SPL product line. Ulterra’s objective is to bring attention and focus to all of their differentiating technologies and the value they create to customers. This nomenclature will help further cement Ulterra’s reputation as an industry leader in innovation, new technology, and performance in the field. Also, the nomenclature will help with the easy identification of advanced pdc bit technology. SplitBlade now joins CounterForce® as named Utechnology product lines, and choosing SPL as the designation for instances where these products are combined for maximum performance. Now, these advanced technology products can be simply identified by technology, blade count, and cutter size (mm).

cutting evacuations SplitBlade by UlterraIn preparation for this launch, Ulterra has successfully made use of dedicated SplitBlade focused product designers to help manage this growth with integrity. This approach of using a dedicated resource is to ensure high initial quality and future consistency of the product as it grows to meet customer demand.  Additionally, the dedicated designer was tasked with understanding and exploring the limits and capabilities of the SplitBlade technology.

SplitBlade looks different because it is different. The Utechnology uses a unique physical disruption of the typically straight blades to unleash maximum drilling performance with improved hydraulic efficiency. The aesthetics of SplitBlade keeps cuttings separated and provides an exceptional cleaning for the cutting structure. Using CFD, the engineering team decided that splitting the shape of the primary blades with an angular offset would provide designated flow to channels for the fluid and cuttings. This cutting structure allows for cuttings to be evacuated up to seven times faster, compared to conventional designs. The physical separation of the inner and outer cutting structure provides steadfast flow to difficult areas while reducing the risk of balling up the bit.

Ulterra SplitBlade nomenclature stands for quality, credibility, and consistency to improve awareness of the technology, and to improve performance to our valued customers. Ulterra’s team is always striving to create and deliver new innovative technologies that lead to actual improvements. Launching SPL is the next step as Ulterra continues to deliver value leading oil field technologies.


Directional Drilling – Where to Begin

Most people would assume that when drilling for water, oil, natural gas, or other subsurface objects that they are targeted vertically — drilled straight down into the earth. However, this traditional method of drilling has been largely replaced. In the current day, drilling a hole in the ground can consist of complex geometry including builds, turns, and tangents to construct a well. The well can be either geometrically or geologically steered. Geometric steering involves adjusting the position of the wellbore based on a pre-arranged plan and then using complex measurements and surveys to stay on that plan. Geological steering involves orienting the wellbore based on the properties of the lithology being drilled into to “find” the right reservoir rock.

It is important to discuss why directional or horizontal drilling can be not only beneficial but necessary, reasons include:

  • Unreachable deposits: it may be sometimes deemed obligatory to go around obstacles by using directional or horizontal drilling. There could be a variety of barriers that prevent access, such as difficult rock formations, utility lines under the surface, residential areas, or sensitive ecosystems. This allows oil companies to drill away from these obstacles or hazards to make it a more sensible, practical, or environmentally friendly option.
  • Increased operational efficiency: Having the ability to access and drain larger parts of the reservoir from a single pad is a huge advantage of directional drilling. This decreases surface disturbances and also saves money and time with the reduction of well pad setups. Grouped wellheads also allow for fewer rig moves, which in turn saves more time and money.
  • Increased reservoir production: Directional or horizontal drilling can expose the well to the maximum amount of the reservoir or allow the well to cross the largest number of fractures to increase production.
  • Relieve pressure: Directional drilling can help relieve the pressure from out of control wells. Pressure can be relieved from one well by tapping the same well at an angle with another well. These relief wells are drilled at a safe distance away from the blowout but come in to intersect the troubled wellbore.

Directional drilling can cost up to 300% more than vertical drilling, but the potential increases in efficiency along with lowered production cost makes this drilling technique more financially viable.

Ulterra Drilling Minute Video: Directional Drilling Operations

Directional Drilling: A Brief History

Directional drilling dates back to the 1920’s with the advent of techniques for surveying the angle and direction of a drilled well. Prior to this, wells were intended to be constructed vertically but were subsequently found to have deviated quite far from that. The first intentionally deviated wells were drilled in the late 1920’s into the 1930’s by using hardwood, and then steel wedges called whip stocks that were lowered into the hole at a specific angle to force the drill bit in a certain direction. Through the 1940’s and 50’s, various techniques that still exist today were developed, including designing the drilling assembly to bend in a particular way and also jetting (using an oriented large nozzle on the bit to wash away rock in the preferred direction).

In the 1950’s, downhole drilling motors, or mud motors, were developed. These mud motors use fluid flow through the assembly, converting hydraulic energy into mechanical energy to drive the drill bit independently from the rest of the drilling string. A fixed angle could then be put into the assembly which could be oriented and held in the desired direction while the bit still drills ahead. Using a mud motor with the use of a measuring while drilling tool (MWD), a directional driller has the capability to steer the drill bit to the desired zone. The data collected from the MWD tool helps the operator monitor and manage the direction of the bit, obtain records, and generate survey reports. By the time the 1970’s rolled around, mud motors had taken over directional drilling and they firmly remain as the preferred method of directionally drilling a well.

The next major advancement in directional drilling was the creation of rotary steerable (RSS) tools, which allow 3D control and steering of the drill bit without stopping the drill rotation. These tools are directly controlled from the surface using advanced communication techniques, and they either push the bit or point the bit in the required direction in real time. Directional drilling has vastly improved with technological advancements, especially toward a less time-consuming drilling process. These advances have also allowed for greater success and precision in the drilling process. New digital technology has made the collection of data much easier and allowed drilling operations to be better planned beforehand and controlled during the drilling process.

Types of Direction Drilling

When speaking about directional drilling, it is commonly assumed that one is referring to horizontal well drilling, which is a method of deviating the well until it is at, or close to a 90° angle from the vertical in order to drill out sideways and along a specific layer of rock. There are a few other directional drilling methods that will be discussed below.

  • Horizontal Drilling: The trajectory of a wellbore starts vertically then steers horizontally at depth for thousands of feet. This allows increased contact between the well and the reservoir to increase productivity. It also provides access to reservoirs that are too thin to be accessed by vertical drilling.
  • Multilateral Drilling: A single wellbore creates a trunk and then many branches stem from it, increasing production from a single drilling site. This drilling technique increases the contact area and allows for many branches to produce from the same well. These can be horizontal, curved slightly to one side, or turned sharply to form a J-type well. Multilateral drilling can occur in either new or existing oil and gas wells and typically includes two laterals. The main benefit of using this drilling approach is the increased efficiency and reduced cost of tapping multiple reservoir locations from a single point.
  • Extended Reach Drilling (ERD): To figure out if the well is considered an ERW, calculate the ratio of horizontal departure to vertical depth. If the depth ratio is greater than 2, the well is considered an Extended Reach Well (ERW). An ERW can be relatively long and deep, short and shallow, or something in between. The benefit of ERD is the increase in efficiency by exposing the open hole to long sections of the reservoir rock, or by crossing through multiple reservoirs in one long wellbore. It is expensive and risky but it is sometimes the best option available. With advances in technology, these wells are getting longer and longer as we get better at overcoming the challenges of managing downhole pressure, managing and controlling the mechanical loads on the drill string, and hole cleaning.
  • Coiled Tubing Drilling (CTD): Coiled tubing refers to a specific type of small diameter, long, continuous metal pipe rolled on to a giant reel (the coil) that can be used as a drilling assembly to reenter and extend a previously drilled hole, drill out from it in a different direction, or perform remedial work to get the well flowing efficiently again. Although drilling using a small flexible pipe has its own challenges, particularly when it comes to directional control, it can be done relatively inexpensively and fast.
  • Through Tubing Rotary Drilling: This is an expensive way to create a shorter length sidetrack of an existing well. This can be done after a well has already been constructed and used, but requires more reservoir to increase production. This is a great method to revitalize old reservoirs that were previously tapped using vertical holes that could also benefit from the horizontal exposure of the reservoir. A hole is cut in the steel pipe that lines the wellbore and then a steel whip stock is set in place and used to push the drilling assembly sideways out of the side of the well. This technique is also used to explore deep layers of rock below the target reservoir, before casing it off and using the same wellbore to access the main target.

Path of a Drill Bit

Directional wells carry various economic and safety benefits. Economically speaking, directional drilling increases the access to a reservoir, increases hydrocarbon recovery, increases the well count number from one location, and reduces rig move costs. Although directional drilling could be as much as three times more expensive than vertical wells, the higher production rates and efficiencies offset the expensive process. The combination of fracking with cutting-edge technologies and horizontal drilling has caused a huge surge in the oil and natural gas production in the United States, particularly in major oil and gas regions such as the Permian Basin, Eagle Ford Shale, and the Bakken Shale.

Directional wells should be meticulously planned in advance and flawlessly executed in order to manage the additional costs. A directional plan is created prior to drilling commences, which outlines the position of the well precisely under the surface of the earth. It typically contains specific targets in 3D space that the drilling assembly must hit in order to contact the reservoir at the optimum point, as well as specific changes in angle required to hit those targets. The directional plan is optimized to try and reduce drastic changes in angle, called DogLeg Severity or DLS, and to minimize the complexity of the well.

The directional plan also includes careful selection of the directional tools, mud motors, and the rotary steerable system that will be required in order to hit the directional targets in the best way possible. To help these tools guide the well path to the optimum position, careful selection of the drill bit is required to ensure that it is compatible with the tools, the formation being drilled, and the directional change requirement, or Build Up Rate (BUR).

By selecting a drill bit that achieves the best compatibility possible with the directional tools, the tool can better guide the well path to the optimum position for the formation being drilled and any directional change requirements or build up rates (BUR) that may be encountered.

Ulterra specializes in creating custom drill bit designs which are compatible with all aspects of the application and the directional drilling requirements. Our knowledge and expertise of directional drilling applications mean that we can offer bespoke solutions that convert to high rates of success in this high-cost environment, where success is the only option!

Please browse all the other educational Drilling Minute Videos and email with any comments, questions, or concerns.

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 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!” 


Ulterra’s Showcase at LAGCOE 2017

Ulterra was pleased to attend and showcase at the Louisiana Gulf Coast Oil Exposition, or LAGCOE. LAGCOE is one of the world’s premier oil and gas expositions featuring innovative equipment, services, technology, and presentations from worldwide leaders. This event happens biennially and Ulterra was able to make their first attendance a groundbreaking one.

The Ulterra team traveled to Lafayette, Louisiana, from October 24-26, 2017. They were amongst the 17,000+ visitors from 43+ countries and approximately 420 exhibitors that came together for this event. Visitors had the opportunity to attend daily keynote sessions, as well as dozens of technical and international sessions. LAGCOE hosted a notable group of international visitors and exhibitors, including the following countries: Canada, Mexico, Saudi Arabia, Ghana, Ukraine, Brazil, and United Arab Emirates.

LAGCOE awarded five companies as New Technology Showcase Winners to present on their innovations. The winning technologies that presented an overview of their innovation included:
• Louisiana CAT — Product Health Connect® Panel
Ulterra Drilling Technologies — PDC drill bit cutting structure: CounterForce®
• Frank’s International — Combination Drillpipe/Casing Spider & Elevator
• HydraLIFT — Rod string lifting device
• Expro — 30,000 psi perforating and drill stem test tool package

Ulterra at LAGCOE 2017

Louisiana Gulf Coast Oil Exposition Ulterra Drilling Technologies at LAGCOE

Ulterra was honored to be picked as a New Technology Showcase Winner from a large group of submissions. Ulterra felt that attending LAGCOE and showcasing their technology would help boost their offshore presence and increase awareness of their already proven successful technology. International Engineering Manager, Matt Case, presented on CounterForce to help further increase their awareness of the technology, particularly the deepwater offshore market. CounterForce was chosen to be the entry of choice due to it meeting the criteria needed to be considered as a submission. CounterForce has been around since 2013 but is still new to the offshore market, and has a proven track record, which made it a largely considerable nominee.

Mitch Dunham, Regional Sales Manager, Eastern US, raved about the success of this event. “Having everyone together there, representing Ulterra, made this event so successful,” said Dunham.
Mitch also believes that Ulterra’s attendance at LAGCOE made them gain positive recognition, especially with potential customers from the Gulf of Mexico and internationally.

Ulterra’s CounterForce technology is designed to take on hard and abrasive geology. The design of the bit causes less vibration on the PDC cutting structure, which allows the bit to be more durable and long-lasting, while improving efficiency, saving drilling time and money. This CounterForce technology is incorporated into many of Ulterra’s PDC bit designs and has very successful field results. As of October 30, 2017, CounterForce has drilled enough footage to go through the planet twice, which is 131,477,280 feet.

During this show, Ulterra was also awarded 1st place for the First Time Exhibitor award. This award was presented to the team on behalf of the LAGCOE committee for their knowledge, engagement, and overall look of their booth.