Abrasive formations, shale wells drive new bit designs for hard-rock, high-temperature drilling

Posted on 30 April 2010

By Jerry Greenberg, contributing editor

The interface between the diamond table and carbide substrate on Baker Hughes’ Hughes Christensen Quantec FORCE PDC bit is optimized for greater durability and thermal stability. By employing finite element analysis, residual stresses were relocated away from the cutting edge.

The interface between the diamond table and carbide substrate on Baker Hughes’ Hughes Christensen Quantec FORCE PDC bit is optimized for greater durability and thermal stability. By employing finite element analysis, residual stresses were relocated away from the cutting edge.

With the growth of the North American shale plays, it’s not surprising that bit companies are aggressively working to meet the challenges of drilling in the these plays, with new designs or enhancements of existing designs for specific applications.

Several recent designs include new cutter materials for drilling in abrasive or high-temperature formations. Several also feature eight-bladed designs that incorporate new cutter technology and materials, as well as newer bit body materials to increase durability and performance. One result is lower drilling costs for operators.

“A lot of the (bit technology) is a matter of material technology in developing cutters to endure drilling extremely abrasive formations,” said Karl Rose, field engineering manager, Western Hemisphere, for Varel International. “The cutters can drill the transitions between hard and soft rock and interbedded formations without breaking.”

There also have been developments in the material properties of the bit itself, so as the bits become stronger, it allows the designer to push PDC bits into harder types of formations. “With stronger materials, the cutter density can be increased, basically making the bit tougher,” Mr Rose said, “allowing the operator to drill more footage in one bit run through hard and abrasive formations.”

Craig Fleming, technical communications manager with Smith International, agreed: “The better the cutters, the longer the bit can stay in the hole, the more hard and abrasive formation it can drill, and the lower the costs for the operator.”

“We have to begin with a cutter that can stand up to harder and more abrasive formations so we can expand the PDC envelope into those formations,” Mr Fleming said. “On the other side, the more blades on the bit, the more diamond volume can be put on the hole bottom.

“However, we are going to stop with the blade count when the bit is dynamically stable,” he continued. “Smith is at that point now where the focus is on cutter technology, not necessarily higher blade count.”

Reducing trips to change to a roller cone bit and then switch back to a PDC bit, or to replace a lighter-set bit with fewer blades with a heavy-set bit with more blades, saves time and money. Generally, with more blades, the more dense the cutters and the diamond volume, the more durable the bit and the longer it will perform, noted Garrett Pierce, global product champion for directional solutions, NOV Downhole.

“The bit will drill slower in the same rock (compared with a lighter set bit),” Mr Pierce said.

However, it can still save the operator time and money by not having to trip out of the hole to change bits. “For example, if the interval is 1,000 ft, and the bit lasts the entire interval but drills slower than a light-set bit that could only drill 500 ft, then it is less expensive for the operator to remain in the hole the entire section with one bit,” Mr Pierce explained.

Following is a review of several new bit designs and their field performance.

BAKER HUGHES

Baker Hughes’ Hughes Christensen Quantec FORCE PDC bit is the result of examining many bit parameters to improve ROP, durability, stabilization, steerability, ideal loading of the cutter structure and cutter material properties. Finite element analysis was used to guarantee structural and mechanical integrity, and computational fluid dynamics aided evaluation of hydraulic efficiency. Optimized force distribution maintains bit stability and drilling efficiency so all cutters engage the formation uniformly and consistently.

Multiple cutter rows can drill through a variety of lithologies without sacrificing performance. The company’s depth-of-cut control (DOCC) technology provides a stable, low-vibration bit for tool face control. Enhanced diamond volume management optimizes the cutting structure to customize the bit profile and cutter layout to a particular application.

Baker Hughes incorporates a proprietary bit dynamics model and force distribution practice to enhance bit stability. It allows the cutting structure to be loaded more consistently, requiring less energy to drill the hole, optimizing efficiency and stability even at low ROP. Its SmoothCut DOCC technology limits impact damage.

Two new application-specific cutters have been field-proven to be six times more wear-resistant than previous cutters, the company said. The interface between the diamond table and carbide substrate is optimized for greater durability and thermal stability. Residual stresses were relocated away from the cutting edge. Combined with stabilization technology, the risks of extreme and cutter-destroying loading are reduced.

Case history

In the Barnett shale, the new bit drilled 1,873 ft of Atoka sand and Bend conglomerate intervals at an average of 47 ft/hr while holding tangent to the kickoff point. The run saved the operator almost 35 hours and reduced costs by $58,000 compared with offset wells.

In a Limestone County, Texas, well, a 7 7/8-in. Quantec Force Q507FX bit was used to drill through the ratty hard sand and soft shale sequences of the Travis Peak/Cotton Valley transition zone. The bit drilled 1,269 ft at 21.3 ft/hr, 31% faster than the offset well average and 122% more footage than the average of offset wells in a 6-mile radius. The run saved the operator more than 18 hours of drilling time, reducing costs by $24/ft.

HALLIBURTON DRILL BITS & SERVICES

Halliburton’s Drill Bits & Services division’s FX bit uses more erosion-resistant materials from matrix to binder to control fluid erosion with what the company believes is the highest thermal mechanical properties of any PDC cutter on the market. The redesigned blade geometries and nozzle positioning provide greater flow control.

The FX bits include the thermally stable and highly abrasion-resistant X3 cutters, which increases the bits’ ability to withstand extreme heat. A new treatment process significantly reduces breakdown of the diamond cutting structure to help maintain its cutting edge over greater footage, according to the company.

In directional applications, the FX fixed cutter bits complement Sperry Drilling’s Geo-Pilot rotary steerable system and SlickBore matched drilling system. Drilling slope control is enhanced while bit vibration is reduced through impact arrestors that reduce bit bounce and stabilize lateral vibration by tracking between formation ridges in the bottomhole patterns.

Halliburton Drill Bits & Services’ FX bit use more  erosion-resistant materials and advanced cutter technology for a highly  abrasion-resistant cutter.

Halliburton Drill Bits & Services’ FX bit use more erosion-resistant materials and advanced cutter technology for a highly abrasion-resistant cutter.

For drilling in harder formations, the bit features dual rows of cutters to increase the amount of diamond available to drill without reducing the open face volume of the bit.

Case study

In the Burgos Basin in Mexico, an operator drilling directional wells needed a bit that could increase ROP while drilling the 6 1/8-in. section in a single run. Halliburton recommended a 6 1/8-in. FMX453Z bit design with X3 cutters. It drilled the entire the 972-m section in a single run, establishing a field record ROP of 70.4 m/hr, 18% faster than the best offset. The section cost/foot dropped from $58.37/m to $21.31/m.

NOV DOWNHOLE

The challenge when running a bit and string reamer assembly is drilling though non-homogeneous formations. This is because the bit and reamer are often in different formations, which can cause the distribution of the applied weight on bit and torque at both the bit and the reamer to become erratic. Add to this lateral and torsional vibration challenges, as well as rig heave in deepwater applications, and correct selection of the bit and the reamer becomes critical.

Typical challenges include the transition of the bit and the reamer cutting structures when a harder formation, or stringer, is encountered. For example, when the bit enters a hard formation while the reamer is still in a softer formation, the majority of the weight indicated at surface is actually being applied to the bit. Similarly, most of the torque is being generated by the bit. As the bit starts to drill the hard rock, the cutting forces change radically, tending to generate lateral vibration. Stick-slip can also be initiated if the increase in torque at the bit is significant.

NOV Downhole’s SystemMatcher bit reamer selection software  optimizes the matching of bit and reamer aggressivity and stability.

NOV Downhole’s SystemMatcher bit reamer selection software optimizes the matching of bit and reamer aggressivity and stability.

As drilling continues and the reamer enters the harder rock, the applied weight and torque at the reamer will increase. Conversely, the bit’s weight and torque will decrease. The level of lateral vibration at the reamer tends to increase as the reamer cutting structure enters the higher compressive strength rock. Similarly, the level of torsional vibration (or stick-slip) at the reamer also increases.

The worst-case scenario comes when the bit is in the softer formation and the reamer is in hard rock. Here, most of the applied weight is being taken by the reamer, and the majority of the torque is generated at the reamer. Lateral vibration or whirl is often evident at the reamer. Additionally, the sudden increase in reamer torque can initiate stick-slip. The bit is left with a very low applied weight on bit, almost hanging below the reamer in some cases, a scenario that leads to low depth-of-cut with the associated risk of extreme bit whirl.

The selection of bit and reamer with high lateral stability is essential, as is matching the aggressivity of the two to reduce the magnitude of weight and torque variation between the bit and reamer, particularly where the application contains formations that are interbedded.

To address this, NOV Downhole developed the SystemMatcher bit reamer selection software that optimizes the matching of bit and reamer aggressivity and stability. The type of Anderreamer tool is selected from the database, and the variability of formation strength, expected RPM and ROP ranges for the specific application are entered. From these, SystemMatcher uses logic tables that describe the stability and aggressivity of the drill bit and the Anderreamer tool to match the bit to the selected reamer.

Case study

In the Gulf of Mexico, the ReedHycalog 14 ¾-in. seven-blade, 16-mm cutter bit was selected to match the 14 ½-in. x 16 ½-in. Anderreamer. The interval was drilled achieving all directional requirements with very low torsional and lateral vibration levels. Dull condition of the bit and the reamer showed little wear and no impact damage.

In another well, an operator used a 12 ¼-in. x 14 ½-in. hydraulic Anderreamer with an NOV 12 ¼-in. MSR813S ReedHycalog drill bit, drilling the complete section with very low vibrations. There were no tool failures, and all directional objectives were met.

SHEAR BITS

The Shear Bits 7 7/8-in. SD413E bit drilled the vertical, build  and horizontal sections of an entire well in one run. The bit posted a  record average ROP of 57 m/hr.

The Shear Bits 7 7/8-in. SD413E bit drilled the vertical, build and horizontal sections of an entire well in one run. The bit posted a record average ROP of 57 m/hr.

By moving quickly through the bit development process, significant improvements in drilling performance can be realized. One example of the success of this approach was recorded in the western Canadian market, drilling a demanding monobore horizontal well in the Spearfish oil shale play in record time.

The well profile in question included a relatively short vertical section, followed by a tight radius build and a horizontal leg, drilled in one run with a 7 7/8-in. PDC bit. When the Shear Bits team discussed the application with the operator, EOG Resources, the primary challenge was to maximize performance in each section without compromising performance in other sections. Previous PDC bits used in the application showed good performance in the vertical, build or horizontal sections, but never all three.

It was not uncommon to achieve an ROP of over 150 m/hr (500 ft/hr) in the vertical section, where the target build rates in the curve are 8-9°/30 m. Additionally, the horizontal section averages around 700 m in length and was commonly drilled with an ROP well over 50 m/hr. Therefore, a significant challenge existed to develop a bit that could drill the vertical section at a very high ROP, yet be able to record high build rates through the curve and hold angle in the horizontal section without requiring extensive steering.

One crucial aspect matching the design of the bit to the characteristics of the directional tools. Because Shear Bits is not affiliated with any directional company, the company said, it can work closely with many directional companies to achieve this.

Shear Bits custom-designed a 7 7/8-in. SD413E PDC drill bit for the application. The initial performance target was to maximize steerability in the build section while minimizing sliding time in the horizontal leg by inhibiting the tendency to drop or build angle. The design featured an extended, heavily spiraled gauge pad configuration to enhance the bit’s ability to maintain angle in the lateral section and an active cutting structure and gauge configuration for aggressive angle building in the curve.

Four runs were recorded with this initial design, all displaying excellent directional response, but an opportunity was identified to further improve ROP in the vertical section. Over the next six weeks, four designs were developed by building on the results of the previous designs. This led to a series of record wells, the best of which was completed, from spud to rig release, in 3.5 days, nearly doubling the average ROP for the entire interval compared with the first runs with the initial design.

At the beginning of the project, the SD413E was averaging 28-33 m/hr for the well, but after dialing in the optimal design configuration for the application, a record average ROP of 57 m/hr was achieved, including an instantaneous ROP of over 200 m/hr in the vertical section. The aggressive build rates of 9°/30 m were easily managed, and sliding time was held to less than 6% in the lateral portion of the hole.

SMITH INTERNATIONAL

Smith designed an eight-blade 12 ¼-in. bit fitted with backup  cutters and optimized blade and nozzle geometry for an abrasive  formation on a rotary steerable BHA for a challenging West Africa well.

Smith designed an eight-blade 12 ¼-in. bit fitted with backup cutters and optimized blade and nozzle geometry for an abrasive formation on a rotary steerable BHA for a challenging West Africa well.

Smith International analyzed the frictional heat generated at the rock/cutter interface, a critical factor that makes PDC drilling in hard and abrasive formations difficult. The company also analyzed thermal degradation and micro-chipping commonly experienced during long bit runs in deep, high-temperature boreholes.

The study revealed that different applications require different cutter properties. Generally, wear resistance and thermal stability are required to efficiently drill abrasive formations, while a more impact-resistant cutter is best suited for interbedded sections and formations with higher rock strength.

The ONYX cutter technology is the first PDC shearing element to address all three critical longevity issues, including thermal stability and wear/impact resistance, according to Smith. These cutters feature improved thermal properties for greater wear resistance and fatigue life than either standard or premium PDC cutters.

Manufacture of the new cutter technology is a two-step process. First, a premium polycrystalline diamond (PCD) table is made using a conventional HPHT process. The table is then treated in acid to render a catalyst-free diamond disc. This disc is assembled with a tungsten carbide (WC) substrate and subjected to another HPHT process. The end product is treated again to remove infiltrate material from the second HPHT process.

The new cutters’ wear-flats are significantly less per unit rock drilled compared with standard premium cutters. Under cooled conditions, the new cutters removed approximately 130% more rock than the standard premium cutter and finished the test with a better dull grade, the company said. For a similar test without cooling, ONYX cutters drilled 85% more rock than a standard premium cutter with comparative dulls.

Case study

Drilling a 12 ¼-in. hole section in West Africa with PDC bits was producing unacceptable results. The section contained hard/abrasive interbedded sand/shale with compressive strengths over 20,000 psi. Typically, the 12 ¼-in. section requires four to eight bits/runs to complete. In most cases, PDCs were pulled in poor dull condition suffering from ring-out and worn cutters. The initial goal was to drill the section in one run or eliminate as many trips as possible.

Smith engineers designed and manufactured the eight-blade 12 ¼-in. MDSi816 fitted with back-up cutters and optimized blade and nozzle geometry. It was run in a highly abrasive formation on a rotary steerable BHA on wells #2 and #5.

On well #2, the bit drilled the entire hole section from shoe to TD for the first time in field history. The reduction in trip time saved the operator six days, reducing costs by $2 million.

On well #5, the total footage and ROP of the bit more than doubled the ROP and facilitated LWD data capture, eliminating the time needed for post-well logging. Compared with the three-well offset average (six bit runs), the new bit drilled 165% more meters (1,702 m) with an ROP (21.18 m/hr) increase of 122% in addition to completing the hole section in one run.

VAREL INTERNATIONAL

Varel’s six-blade Tough-Drill bit design with full PowerCutter  structure successfully drilled the abrasive Hosston formation at an  average ROP of 37 ft/hr.

Varel’s six-blade Tough-Drill bit design with full PowerCutter structure successfully drilled the abrasive Hosston formation at an average ROP of 37 ft/hr.

Recently, Varel International has focused on modifying its PDC bit designs to better compete in the Haynesville Shale, with highly abrasive and transitional formations that can lead to early bit failure due to increased wear. A majority of the bit designs in the area face the double-edged trade-off of durability versus ROP.

Varel studied dull analysis of current field-deployed designs and bit records, producing evidence of many bits in the area being pulled for ROP issues. Extensive wear was noted on critical areas of the cutting structure. This investigation led field engineers and bit designers to develop two designs for hard and abrasive formations.

Hard rock applications

For hard rock applications, Tough-Drill bits have proven to reduce impact damage and improve cleaning and cutter-cooling efficiencies.

Based on cutting structure analysis using proprietary software, the PowerCutter cutting structure was deemed the best arrangement for drilling this rock type without sacrificing ROP. This cutting structure provides additional exposure and cutter density on the critical shoulder area of the bit for maximum ROP through hard rock formations, then continue to penetrate harder sand or limestone beds without excessive wear or damage.

Tough-Drill designs are subjected to elaborate computational fluid dynamics evaluations that assist in the elimination of re-grinding and re-circulation of drilled cuttings, common when drilling hard and abrasive applications.

Abrasion-resistant cutters are quality-tested to ensure the proper diamond grain size and thermal stability necessary for these applications.

Case study

Varel was asked by an operator in Louisiana to develop an eight-blade bit with 16-mm cutters for the completion of the 9 7/8-in. interval. The total depth of the interval required drilling through the tough and abrasive Hosston and Cotton Valley formations, where bits commonly wear down quickly. The final 600 ft of the application was through the Bossier formation – a soft shale/limestone where an intact cutting structure would excel.

The main objective was to increase ROP without sacrificing the durability of the current Varel design which had been successful in drilling this formation. Engineers also worked to exploit the benefits of the cutters when entering the shale/limestone formation.

The design incorporated a partial PowerCutter structure with backup cutters situated on the primary blades and tungsten carbide shock studs on secondary blades. This layout provided stability and protection of the main cutting structure for the abrasion and transitional challenges.

For a sharper bit, the cutting structure was loaded with a more abrasion-resistant cutter in order to survive the damaging formations and then benefit from the cutter size in the latter portion of the run.

The bit achieved the objective of drilling 2,339 ft of the section to TD at 10,945 ft with an average ROP of 29.1 ft/hr. The area’s closest offset was pulled for ROP issues after drilling just 600 ft into the Cotton Valley formation. The Varel performance showed an approximate 30% improvement in cost/ft and ROP.

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