Breakthrough PDC Bit Design Evacuates Cuttings 200% Faster

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

Splitblade PDC Bit

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

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

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


Ulterra’s Leduc Manufacturing Facility Has No Recordable Injuries for Three Years

According to the Workers’ Compensation Board of Alberta, the manufacturing, processing, and packaging sector had the highest injury claim rates in 2016. In this sector, the odds of being injured were about every three out of 100 workers. Ulterra’s Leduc Manufacturing Facility has beat those odds, and are proud to announce that their Leduc manufacturing facility has had no recordable injuries for three years.

After completing a successful Health and Safety Management System audit, a certification of recognition (COR) was issued to Ulterra. This COR ensures that Ulterra’s safety standards are in compliance with Alberta’s audit standard for health and safety systems. Ulterra’s health and safety management system is a process that’s in place to eradicate injury and maximize safety. Although their safety standards meet the requirements of their provincial legislation, their desire for a safe workplace is what drives the effort to work incident-free.

The key to their success is the commitment of everyone at every level — from plant managers to their latest new hires. Another effort that has helped ensure safety is monthly inspections. An internal team composed of both plant managers and shop employees conduct these inspections. Manager of HSSE, Bryce Cook, said: “Everyone understands the importance of safety, both for their own welfare and for business operations.”

This is a huge accomplishment for the entire manufacturing team in Leduc, Canada, and for Ulterra as a whole. Ulterra’s Health, Safety, Security, and Environmental (HSSE) team works hard to ensure a safe workplace for all employees. This is all made possible by managing business operations through an HSSE Management System that is consistently improving, as well as the continuous effort of employees to be compliant every day they come to work.

On behalf of the entire Ulterra team, congratulations to all employees at Leduc.


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

By Colter Cookson

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

 

 

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

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

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

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

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

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

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

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

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

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

Download a PDF of the Article Here

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

 


Drilling At the Sharp End: Ulterra Featured in North American Shale Magazine

Born in the shale oil fields of Canada and the U.S., Ulterra Drilling Technologies emerged from the latest oil downturn stronger than ever. The Fort Worth firm is now a prime source of where drilling efficiencies come from.

North American Shale Magazine Article

In military circles, the soldiers in the field who see their enemies eye-to-eye and engage in fierce close-quarters combat are known as the sharp end of the spear. If there’s an oilfield technology equivalent for shale operators, it’s the drill bit.

The well-known challenge with shale oil and gas is to drill vertically through thousands of feet of hard rock and then transition to horizontal drilling through a formation where the drill bit is directionally steered to create the lateral where fracking occurs. A drill bit problem can compromise the entire operation.

Based in Fort Worth, Texas, Ulterra Drilling Technologies LP has described itself as “the rock destruction company.” It focuses on the sharp end of drilling technologies by designing, manufacturing and renting polycrystalline diamond compact (PDC) drill bits for oil and gas drilling operations around the world. It was formed in 2005 by combining two companies—Canada-based United Diamond located in Leduc, Alberta, and Ulterra in Texas.

“If the drill bit doesn’t work, you don’t make holes, you don’t drill,” says Aron Deen, Ulterra’s director of marketing and business development—who also has an engineering background. Since its founding, Ulterra has remained what Deen calls a “pure play” company, steadfastly focused on providing the industry with improved drill bits and downhole tools to drill faster and more efficiently while lowering costs. “It’s really about making sure we have the technology on the end of the drill string that allows all the rest of the technology in the string to do its job,” he explains.

“Something that costs so little in relative terms has a huge impact on the overall cost of drilling the well,” Deen notes. “It’s gotten a lot of attention the last couple of years, especially as everyone has become cost-conscious and as drilling engineers have really been able to focus on performance improvement.”

More to the point, the last couple of years is in reference to the low-oil-price environment which severely impacted the North American shale oil and gas industry.Ulterra not only weathered that storm but also emerged from it as one of the fastest growing drill bit manufacturers in the world.The company has continued its expansion into international markets, increasing its manufacturing output by 60 percent and last year doubling its workforce.It’sworkedwithmore than 600 different operators in the past year and has customers in 25 different countries.

According to Maria Mejia, Ulterra’s chief financial officer, this can be attributed to a company culture that stresses finding solutions for every customer individually, no matter how big or how small. Those customers range from national oil companies in the Middle East and Latin America to major global producers to top technology-focused, independent E&P companies in North America to companies that occasionally operate a drilling rig in one county of the U.S.

“Our only interest is to drill faster,” she explains. “We don’t have daily rental rates coming from anywhere else in the drill string. We have no other interest other than to help customers reach their goal faster and drill faster. That’s what helped us during the downturn. Capital efficiency and drilling efficiency has increasingly become a focus for all our E&P customers. Making sure they remain competitive has allowed us to become one of the market leaders, especially in the U.S. shale plays.”

Another aspect that’s helped Ulterra through difficult times has been maintaining low product inventories, which means it isn’t stuck trying to sell products the industry no longer needs. This enables the company to remain flexible and focused on developing new technologies specifically tailored to meet customers’ needs and solve problems as they arise.

“In some cases, the most forward-looking operators don’t come to us with a predefined problem,” Deen explains. “They come to us with a goal of wanting to drill faster and wanting to know what we think. Being primarily a drill bit company, we work collaboratively with directional companies and with mud companies. We’ve worked with a whole host of companies that are trying to develop more rotary steerable options that make sense in North American shale plays. We’ve become the drill bit of choice.”

Not all Ulterra solutions involve technology. “Some of the innovations that have popped up industry-wide in North American shale are new to the rest of the world,” Deen says. “We worked with an operator in another country to implement a rental model into their procurement method to really change the way they do things. They now rent drill bits and save millions of dollars annually because we converted them from a purchase model to a rental model. We really look at innovation holistically. It’s not just technology driven, it’s value driven.”

Using the latest in social networking and IT technology enables Ulterra to use its global reach to its advantage.

“Our engineers in Thailand can talk to our engineers in Fort Worth who are talking to people in the Delaware Basin or talking to people in-house working with engineers at Chevron,” Deen relates. “They can work on a

problem such as trying to drill an 8 3⁄4 inch hole with an AC top-drive rig through15,000PSI carbonate with dolomite collaborating with anyone who has dealt with these kinds of things.”

Bit Building

Ulterra has manufacturing centers in Fort Worth and Leduc. The company offers a suite of products that includes: Matrix PDC, a proprietary mold technology; steel PDC shankless, single-piece bits; TorkBuster, which reduces bit-related torque and stick-slip problems; and Tru-Gauge, a short,near-bit stabilizer that reduces hole spiraling and increases directional control.

Deen says Ulterra’s technology is developed to address drilling dysfunctions identified by its engineers and customers. Some of the most common problems relate to drilling vibration, lateral vibration and bit whirl. “We have applications engineers in most of the major basins around the world who really understand everything from the geology to the drilling application to the experience and abilities of the drilling engineers and the directional drillers,” he explains. “That’s key to unconventional shale in North America.”

Designed specifically to address drilling vibration, CounterForce is one of Ulterra’s more recent technologies. “Drilling vibration is a destructive energy loss that causes damage to expensive downhole tools and potential damage to the wellbore,” Deen says. “We designed and built a drill bit that actually harnesses otherwise wasted drilling vibration energy into proactively making hole and reducing vibrational damage on downhole tools. That’s been our showcase technology.We’re right at the threshold of drilling 100 million feet with CounterForce technology.”

As the speed of drilling continues to increase, another disfunction Ulterra identifies is cuttings evacuation from the well bore. “Shale laterals are being drilled at such fast penetration rates they’re at nearly an order of magnitude faster than they were ve or 10 years ago,”Deen relates.“Where they were drilling 20 to 40 feet an hour, now they’re drilling instantaneously at 200 or 300 feet per hour. Getting all those new cuttings and formation out of the hole requires new thinking.”

To deal with the problem, the company recently introduced its SplitBlade technology. “SplitBlade is completely focused on cuttings to increase the rate of penetration (ROP). We’ve seen case studies in multiple basins now where we’ve been able to increase instantaneous rates of penetration by 30 to 50percent—in some cases just by making sure the cuttings being generated are exiting the bit and removed from the hole efficiently.”

Dealing With A Downturn

As Deen notes, the oil price downturn that hit the U.S.shale oil and gas industry primarily in 2015 and 2016 had a negative impact on producers and related businesses around the world. But it wasn’t the first time Ulterra had to cope with a downturn.It was around for and survived the oil price collapse of 2008 and 2009. The most recent downturn provided the company with an opportunity to demonstrate how its approach was not only different but also better.

“What a downturn does in oil and gas is separate the wheat from the chaff,” Deen says. “We were able to keep doing what we were doing. It’s a little bit of a different take on risk aversion.” In other words, rather than going the route with drilling solutions from what Deen refers to as “the big-box brands,” E&P companies began looking to the faster and nimbler Ulterra for solutions.

“One of the things that happened that we’re most proud of is that as we grew through the downturn, drilling engineers started to see us in a different light,” Deen notes. “These are individuals whose jobs may have been on the line when they had to make decisions based on what was best for them and what was best for their company. That’s when things really started swinging toward Ulterra. When drilling engineers had to make decisions, every single decision counted, and they started trusting us more.”

Mejia says it was Ulterra’s decentralized decision-making culture that enabled it not just to survive, but to thrive.

“If you look at our market share and financial performance through the downturn, that’s when we made our biggest strides,” she states. “It happened when it became important to realize efficiencies, drill faster and bring new products to the eld. When the majors were dealing with stopped production, layoffs and trying to sell what they had to conserve some cash, we were innovating and bringing the latest technologies to develop some economic value for the customer.

“The downturn was definitely helpful to us,” Mejia continues, “because decision making became a question of ‘Who can make a difference for me now?’ and not ‘Who can make a difference for me two months from now?’ When we could realize efficiencies faster and save money faster, that’s when we became one of the market leaders. We became a true partner with our customers to help them deliver efficiencies and savings at the local level.”

Last year’s uptick in oil and gas activity in North America helped Ulterra to further expand its business to overseas markets. “It’s made sense for us to do that in international markets where we sowed seeds up to 10 years ago,” Deen says. “A lot of that grow this really just a response to this. We’ve been very excited, not only keeping up with the market rebound and drilling activity in North America, but growing significantly faster in our own right.”

But, as Deen also notes, Ulterra’s success has provided it with new and different issues. “One of the things we’re struggling with is to scale up as fast as our customers are demanding while maintaining our culture. That’s really the biggest challenge that we’re facing right now.”

Mejia describes Ulterra’s new challenge as both fun and exciting. “The challenge from an administrative perspective becomes trying to keep up with the growth and trying to build the legal framework and infrastructure that we need to service the client with the same level of speed that we do in NorthAmerica,” she says.“That’s the goal. Once we penetrate a new market, we don’t want to sacrifice the quality. We want to make sure our manufacturing capabilities have the same ISO and API certificates in Saudi Arabia that we have in North America.”

Providing solutions to technical problems is the easy part because, according to Deen, it’s how Ulterra is hard-wired to operate. “The subterranean lithology doesn’t know the political boundaries that we’ve drawn up top,” Deen relates. “What’s harder to deal with are the corporate and geopolitical cultures. How do we do business with Saudi Aramco or the Kuwaiti Oil Co. or the Chinese National Oil Co. and do business with XTO and a small company that has one rig running three months out of the year? How do we serve each one of those clients in a way that makes sense to them and still be true to who we are? We struggle more on the side of dealing with really big, bureaucratic companies and very small companies and the challenges that go along with those.”

For 2018 and 2019, Deen says Ulterra plans to continue moving forward as the oil and gas markets catch up and recover from the most recent downturn. “We plan on doing more of the same,” he says. “To us, that means continually changing and evolving and solving the problems of today that didn’t exist yesterday.”

However, Deen’s also realistic about the future, knowing that it’s a matter of time before the industry experiences another market slump. Once again, he believes operators will look to Ulterra’s experience and technology to deliver the drilling optimization that’s yet to be done.

Author: Patrick C. Miller
Staff Writer, North American Shale magazine 701-738-4923 pmiller@bbiinternational.com

Download a PDF of the original article here.

 


Ulterra Completes the American Petroleum Institute (API) Recertification Audit of their Quality Management System (QMS)

On February 16, 2018, Ulterra completed the American Petroleum Institute (API) Recertification Audit of their Quality Management System (QMS) in Fort Worth, TX. Ulterra’s first API Certification was issued in 2012 and is set to expire in March 2018. Their 2018 audit of their QMS resulted in two minor findings and one opportunity for improvement. This audit was the most successful API audit that Ulterra has completed to date.

Customers can be reassured when working with quality-certified vendors, which is why Ulterra holds both certifications for quality management and quality products. Ulterra’s standards are in compliance with The International Organization of Standardization (ISO) and The American Petroleum Institute (API). Ulterra holds three quality certifications: ISO 9001:2015, API Q1 9th Edition, and API 7-1.

  1. Ulterra’s API Certification guarantees that they are meeting the standards specified in ISO 9001:2015. ISO 9001 is a universal Quality Management System (QMS) standard for all industries to ensure that products and services are consistently meeting customer’s requirements and steadily working to improve their quality. The ISO 9001:2015 has replaced the ISO 9001:2008. This upgraded version has placed a major emphasis on risk-based thinking. It has also placed an importance on guaranteeing companies’ objectives align with the context of their organization. The new QMS also highlights a leadership commitment, making sure top managers and business leaders are involved in planning and implementation of the QMS in their organization.
  2. Ulterra’s QMS also conforms to the requirements detailed in the API Q1 9th Edition API is the governing body specific to the Oil and Gas industry that dictates the requirements needed to be an API registered organization.
  3. Ulterra’s manufactured products conform to the technical requirements specified in API 7-1 for both Matrix and Steel body PDC bits. This certification also allows Ulterra to stamp their product with the API monogram.

Shortly following the audit, Ulterra was recertified to API Q1 and API Spec 7-1. Additionally, Ulterra’s certifications for ISO 9001 are now upgraded to the enhanced 2015 version. These certificates became effective on March 15, 2018.

Ulterra’s Quality Engineering Manager, James Stevens, said: “Maintaining our QMS to these API/ISO standards enables Ulterra to utilize consistent, repeatable processes in order to deliver the best quality product to our customers.”

Ulterra PDC Bits are the most reliable PDC Bits in the industry because they are the only ones designed, manufactured, and repaired at one API registered facility. All Ulterra PDC Bits go through a thorough inspection process, including at least five separate quality inspections between runs. Every single cutter is inspected, photographed, and dispositioned on every repair.

The combination of these certifications differentiates Ulterra from their competitors and guarantees dependable quality for manufactured and repaired PDC bits. The implementation of an ISO 9001 QMS has provided Ulterra with internal benefits that have led them to better operations, improved performance, and increased profitability. The implementation of API Spec Q1 has provided Ulterra with the minimum requirements to effectively manage processes, prevent defects, and minimize any variations and waste in manufacturing. Ulterra’s QMS and product certifications help communicate to their customers their continued commitment to quality. Furthermore, some international customers require these API/ISO Certifications as a prerequisite in order to enter into a business relationship.

James Stevens, Quality Engineering Manager, was particularly impressed with the entire team at Ulterra and their ability to utilize consistent, repeatable processes in order to deliver the best quality product to their customers. Stevens said: “I am thankful for and continually impressed with the talent, experience, and hard work put forth by the entire Ulterra team.” Said James, “This is a huge accomplishment for the entire Ulterra team.”

 


73 Rigs Today are More Efficient Than 105 Rigs Several Years Ago?

According to RigZone, the total count of US oil rigs reached 799 which is the highest count since April 2015. Although this number has been steadily increasing for the past five weeks, the drilling industry has not seen a rig count that can compare to the peak of 2014. While the industry yearns to get back to higher rig counts, the advancement of technology has replaced the need for it. Drilling times have been reduced by more than half compared to a decade ago with the advancement of drill bits, mud motors, drilling fluids, and pressure pumps. Drilling technologies have simply made drilling operations become much more efficient helping to save time and money. The constant need for innovation has helped drive the oil and gas industry allowing it to survive in today’s business environment. The question is, has the industry become so advanced that we have worked ourselves out of jobs? Read this article to dive deeper into the impacts of the industry becoming older and wiser.

Read the full Pipeline News Article regarding the increased performance of current technology.


Drill Bit Innovations: Ulterra Featured in Drilling Contractor

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

 

drill bit technology

 

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

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

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

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

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

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

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


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!