Abstract Some of the latest developments include new cutting teeth for drilling abrasive formations and high temperature formations. Some 8-wing structural drills also use new cutting technology and new materials, as well as new bit body materials to improve the drill bit. Durability and improved performance, the result...
Some of the latest developments include new cutting-tooth materials for drilling abrasive and high-temperature formations. Some 8-wing structural drills also use new cutting technology and new materials, as well as new bit body materials to improve bit durability. One of the results is to enable drilling operators to reduce drilling costs. Many drill bit technologies are actually material technologies in the development of cutting teeth in order to enable the drill bit to be drilled in extremely abrasive formations that can penetrate the transition layer between the hard and soft formations as well as the mezzanine formation without A break will occur.
The material properties of the drill itself have also evolved to make the drill bit tougher and more durable, enabling design engineers to design PDC drill bits for drilling harder formations. The use of tougher materials increases the density of the teeth, which in turn makes the drill bit tougher and more durable, enabling drillers to use a drill bit to achieve greater footage in a hard and abrasive formation.
According to experts from Smith International, the better the cutting teeth, the longer the drill bit will be, and the harder and more abrasive the formation, the lower the drilling cost of the drilling operator. If you want a PDC bit to be able to drill effectively in such a formation, you must first adapt the cutting teeth on the bit. In addition, the greater the number of blades on the drill bit, the greater the amount of diamond placed on the drill bit. However, when the drill bit work is stable enough, we stop increasing the number of blades of the drill bit. At present, Smith's research and development focus is mainly on the cutting tooth technology.
Reduce the number of trips required to change to the roller cone bit and then switch back to the PDC bit, or reduce the number of blades to be replaced with a PDC bit with more blades and a higher density of teeth, and the teeth The number of drills for low-density PDC bits can save time and money. According to experts from National Oil Well Huagao Company, in general, the more blades on the PDC bit, the greater the density of the cloth teeth, the larger the amount of diamond on the drill bit, the more durable the drill bit, and the longer its working life. long. Of course, a drill with a high density of teeth has a lower rate of penetration in the same rock formation than a drill with a low tooth density. However, it can save time and cost for the drilling operator because it does not need to frequently drill down to change the drill bit. funds. For example, a well that is drilled is 1000 feet, and a bit with a high density of teeth can drill a complete section at a lower ROP, compared to a drill with a low density but only 500 feet. For the drilling contractor, the cost is still low, because the drill can always drill downhole and not need to carry out the drilling operation to replace the drill bit.
Below are some of the latest developments in PDC bit technology from several major US bit manufacturers.
The Quantec FORCE PDC drill from Hughes Christensen, a Baker Hughes company, is investigating a number of drill parameters to improve drill bit penetration, durability, stability, and maneuverability. Designed and manufactured based on the ideal cutting structure load and the nature of the cutting tooth material. The company used finite element analysis to ensure the structural and mechanical integrity of the drill bit during the bit design process, using computational fluid dynamics to evaluate the efficiency of the bit hydraulic structure. The optimized force distribution ensures the stability of the drill bit and the drilling efficiency, so that all the teeth on the drill bit can be uniformly and into the formation.
The drill's multi-toothed row structure allows it to drill into multiple formations without sacrificing its good drilling performance, and the company's depth of cut control (DOCC) technology makes the drill bit more stable and helps better Tool face control. Enhanced diamond volume management technology optimizes the cutting structure so that the drill profile and cutting profile can be tailored to the specific application. In order to improve the stability of the drill bit, Baker Hughes applied a proprietary bit dynamic model and force distribution method, which makes the cutting structure more consistent, requires less energy to drill, and Optimizes efficiency and stability at lower ROP.
The new special tooth used on the drill proves that the wear resistance is 6 times that of the previous cutting teeth. It also optimizes the interface between the diamond layer and the tungsten carbide base for better durability and thermal stability. The new process is used to keep the residual stress away from the cutting edge, and with the corresponding stabilization technique, the possibility of extreme or damaging loads on the cutting teeth is greatly reduced. In the Barnett shale formation, the company's new PDC bit drilled 1,873 feet of Atoka sandstone and Bend conglomerate wells, achieving an average of 47 feet per hour while maintaining a tangent to the point of manufacture. Speed, this drilling saved nearly 35 hours for drilling operators and reduced operating costs by $58,000 compared to adjacent wells.
In a limestone area of ​​Texas, a 7 7/8-inch Quantec Force Q507FX drill bit was used to drill hard sandstone and soft shale intervals in the Travis Peak/Cotton watershed transition zone. The 21.3-foot drilling rate drilled 1,269 feet, 31% faster than the average speed of the adjacent well, and increased the average footage of the adjacent well by 122% over the 6-mile radius. This drill saved the operator more than 18 hours and reduced costs. Up to $24 per foot.
Halliburton's Halliton's FX PDC drills use a more erosion-resistant material from the carcass material to the binder to prevent liquid erosion. The company believes that its PDC teeth are currently on the market. The best performing teeth. Redesigned blade geometry and nozzle positioning also provide better fluid control.
X3 teeth with excellent thermal stability and exceptional wear resistance are also used on the FX drill bit, which improves the stability of the drill under extreme heat conditions. The company also uses a new process that significantly reduces the fracture of the diamond cutting structure, helping to keep the cutting edge sharper for larger footage. In directional drilling applications, the FX fixed-cutting drill bit effectively complements the Periple Drilling's Geo-Pilot rotary guide and the matching SlickBore drilling system, while enhancing the drill skew control while also The anti-shock damping teeth reduce the vibration of the drill bit, and the anti-shock damping teeth can reduce the jump drill and stabilize the lateral vibration by tracking the movement between the bottom ridges.
If used for hard formation drilling, the drill bit can be designed as a double-row tooth structure to increase the amount of diamond required for drilling without reducing the open face volume of the drill bit.
In the Burgos Basin area of ​​Mexico, a drilling contractor needs a bit that can increase the rate of ROP when drilling a 6 1/8 inch section in a horizontal well, which Halliburton recommends. The 6 1/8-inch FMX453Z PDC drill with X3 teeth drilled a 972-meter-long section at a time, creating a mechanical drilling rate of 70.4 meters per hour, which is faster than the highest mechanical penetration rate in the adjacent well. 18%, reducing the cost per ton of drilling in this section from $58.37 per meter to $21.31 per meter.
NOV's downhole company uses drill bits and drill string reamer for drilling. The challenge is to drill in a heterogeneous formation because the drill bit and reamer are often in different formations, which can result in the addition of drill bits and reaming. Drilling pressure and torque instability on the machine, in addition to such lateral and torsional vibration challenges, the installation of drilling rigs in deep water drilling is also quite difficult, so the correct choice of drill bit and reaming machine is particularly important.
The specific challenge is reflected in the transition of the bit and reamer cutting structure when encountering a harder formation or interlayer, for example, when the bit has entered the hard formation and the reamer is still in the softer formation, on the ground. The main weight-on-pressure shown is actually the weight-on-bit pressure applied to the drill bit; likewise, most of the torque is also produced by the drill bit. When the drill bit begins to drill in a hard formation, the cutting force changes rapidly and is prone to lateral vibration. If the torque on the drill bit increases greatly, it will also cause stick-slip.
As the drilling continues, the reamer enters the harder formation and the weight and torque applied to the reamer increases. Conversely, the torque and the weight on the drill bit decrease, as the reamer is cut. When entering a rock layer with a large compressive strength, the lateral vibration at the reamer will increase, and the torsional vibration (or stick-slip phenomenon) at the reamer will also increase. The worst case occurs when the drill bit is in a softer formation and the reamer is in a harder formation. At this point, most of the weight-on-bit is absorbed by the reamer, and most of the torque will also be generated by the reamer. Therefore, lateral vibration or swirling often occurs at the reamer. In addition, the sudden increase of torque at the reamer may also cause stick-slip phenomenon. At this time, the drilling pressure on the drill bit will be small, sometimes almost hanging. Below the reamer, this phenomenon tends to result in a very low depth of cut and extreme whirling of the drill bit.
Therefore, it is important to select a bit with a good lateral stability and a reamer to match the aggressiveness between the drill bit and the reamer to reduce the magnitude of the weight-on-bit and torque vibration between the drill bit and the reamer. Equally important, especially when the stratum being drilled is a mezzanine stratum.
To solve this problem, NOV (National Oil Well) Downhole Company has specially developed the SystemMatcher drill/reamer selection software to optimize the match between the drill and the reamer's aggressiveness and stability. First select the type of Anderreamer tool from the database and enter the variability of the formation strength and the desired rotational speed (RPM) and ROP (ROP) range for the specific drilling application. Based on this, SystemMatcher will use the logic table to describe The stability and aggressiveness of the drill bit and Anderreamer tool to match the drill bit to the selected reamer.
In the Gulf of Mexico, Reed Haikalog's 143â„4-inch 7-blade drill with 16mm diameter PDC teeth was selected for use with the 141â„2-inch x 161â„2-inch Anderreamer reamer, which is fully compliant with directional well requirements. And the torsion and lateral vibration during drilling are very low, and the passivation state of the drill bit and the reamer shows little wear and no impact damage.
In another well, a 12-inch by 14-inch hydraulic Anderreamer reamer was used with NOV Reed Haikarlog's 12-inch MSR813S drill bit, which smoothly drilled the entire section. The vibration during the drilling process is very small, no drill failure occurs, and all the requirements of the orientation target are met.
As the proven reserves of shale formations in North America increase, major drill manufacturers focus on meeting the challenges of drilling in such formations, or developing new structures for drill products, or based on existing bit structures. The strengthening treatment is carried out to make it suitable for specific drilling applications. In the previous issue, the latest developments of PDC bits from Baker Hughes, Halliburton and NOV Underground were introduced. This issue continues to introduce the technological developments of the three US companies.
Shear Bits quickly considered the bit development process to significantly improve the drilling performance of the drill bit. A successful example of this approach occurred in the Western Canadian market, where it was difficult to drill in a record (short) time in the Spearfish oil shale block. Single eye horizontal section.
The contour of the well consisted of a relatively short straight section, followed by a small radius slant and a horizontal branch, drilled once with a 7-7/8 inch PDC bit. The PDC bit used in the previous stage can obtain good drilling performance in the vertical section, the inclined section or the horizontal section, but no drill can obtain the best performance in all three sections simultaneously.
It is more common to drill a mechanical drilling rate of 150 meters per hour in a vertical section during drilling in the area. The target slope in the curved section is 8° to 9° per 30 meters. In addition, the average length of the horizontal section is At about 700 meters, the usual mechanical drilling rate is more than 50 meters per hour. Therefore, a big challenge is to develop a high mechanical drilling rate and a high build-up slope in the curved section. A good stability effect can be achieved in horizontal well sections without the need for excessive PDC drill bits to manipulate the drill bit. Another important aspect is to match the drill bit structure to the features of the orientation tool.
Shear Bits designed a 7-7/8-inch SD413E PDC drill for this purpose. The initial performance goal of the drill bit is to maximize the maneuverability of the drill bit in the inclined well section, while minimizing the slippage time in the horizontal branch by limiting the tendency to create a slope or a downward slope. The drill bit is characterized by an elongated spiral gauge pad structure to enhance the ability of the drill bit to stabilize in a horizontal well section, as well as an active cutting structure and a gauge shape to enhance its ability to bend in a curved section.
This initial structure of the drill bit was used four times, and the directional response was good every time it was drilled, but the company's technicians found an opportunity to increase the ROP in the vertical section, so In the following six weeks, the company developed four types of drill bits based on the previous structure. The four new drills set a series of records during drilling, the best record of which was from It took only 3.5 days to disassemble the rig after drilling, and the average penetration rate of the entire section almost doubled compared to the initial drilling of the original structural drill.
At the beginning of the project, the company's SD413E PDC drills had an average ROP of 28 to 33 meters per hour, but after optimizing the drills for specific applications, the average ROP was 57 meters per hour. The instantaneous ROP of the vertical section reached 200 meters per hour. The new drill bit makes it easy to achieve a 9°/30m skew rate, keeping the sliding time in the lateral portion of the wellbore below 6%.
Smith International, Inc., conducted a detailed analysis of the frictional heat generated at the rock/cutting interface, which is a major factor in making PDC bits difficult to drill in hard rock and abrasive formations. The company also conducted a rigorous analysis of the thermal degradation and micro-dropping that PDC drills typically experience when drilling in deep and high temperature wells. The company's research shows that different applications require different cutting performance. In general, if you want to drill into the abrasive formation efficiently, you need the cutting teeth to have better wear resistance and thermal stability; while the better impact resistance is used to drill the interlayer and the rock is stronger. The formation is most suitable. The company's ONYX cutting technology is the world's first shear cutting component that fully considers three key factors related to the life of PDC cutting teeth. These three key factors include thermal stability, wear resistance and impact resistance. Sex. Whether compared to previous standard teeth or high quality PDC teeth, this new cutting tooth exhibits better thermal stability, better wear resistance and longer fatigue life.
The production of this new type of cutting tooth is divided into two steps. First, a high quality polycrystalline diamond (PCD) layer is produced by a conventional high temperature and high pressure process, and then the diamond layer is acid treated to obtain a catalyst-free diamond piece. The diamond pieces are assembled onto a tungsten carbide (WC) base and then subjected to another high temperature and high pressure treatment. The final product is further processed to remove the infiltrated material from the second high temperature and high pressure process.
Compared with standard high-quality cutting teeth, the new type of teeth has a much reduced flatness per unit of rock drilled. In the case of good cooling conditions, the new type of tooth removes approximately 130% of the traditional teeth. The passivation condition after the test is also better. In a similar test without cooling, the new ONYX cutting teeth drilled 85% more rock than conventional high-quality teeth, and the passivation condition was comparable to that of conventional teeth.
The early 12-1/4-inch section with PDC bits in West Africa was highly undesirable. The section contained a hard and abrasive sandstone/shale sandwich formation with a compressive strength greater than 20,000 psi. Drilling the well section usually requires 4 to 8 drill bits. In most cases, the PDC drill bit has poor passivation when it is lifted, which has both a diameter reduction phenomenon and a severe wear phenomenon of the teeth. The initial goal of improving drilling in the area is to drill through the well or reduce the number of drills as much as possible.
To this end, Smith International designed and built an 8-blade 12-1/4 inch MDSi816 PDC drill with reinforced teeth and optimized blade and nozzle shape for rotary guidance in Wells 2 and 5. The drill assembly was successfully drilled into a highly abrasive formation.
In Well No. 2, the drill drilled the entire section from the drilling slope to the total depth (TD), which is the first time in the field. The reduction in the number of drills reduced the drill operator by 6 days and the cost was reduced. Two million dollars.
In Well 5, both the footage and the ROP were doubled and also contributed to the data capture of the LWD (log while drilling), eliminating the need for logging after drilling. Compared with the average data of 3 adjacent wells (6 drill bit drilling), the new drill has a 165% increase in footage (1,702 meters) and a 122% increase in the rate of penetration (21.18 meters per hour). The drill was completed and the section was drilled.
Varel International, Inc., is currently working to improve its PDC bit structure to better drill in the Haynesville shale formation, which contains highly abrasive transitional rock formations. Early bit wear due to excessive wear. Most drill bits used in such formations have a balance between durability and ROP.
The company's technicians analyzed the passivation status of the drill bits used in the area and the drill bit usage records. It was found that many drill bits were pulled out of the wellbore due to the low penetration rate of the drill bit, and the key to the cutting structure of the drill bit. Serious wear and tear on the site, through this investigation, led field engineers and drill designers to finally develop two bit structures suitable for hard formation drilling and abrasive formation drilling. For hard formation drilling, the company's Tough-Drill series drills have been proven on site to reduce impact damage, improve bit cleaning and cooling efficiency of the cutting structure. By using specialized software to analyze bit cutting, the company developed the PowerCutter cutting structure that is best suited for hard formation drilling without sacrificing the drill ROP. This cutting structure is designed for critical bit shoulders. Larger tooth height and cloth density allow drilling in hard rock at maximum mechanical ROP, and continue to drill into harder sandstone or limestone formations without excessive wear or damage. The Tough-Drill bit structure was analyzed using dynamic fluid dynamics theory during the design process to help eliminate repetitive grinding and repetitive cycles of drilling cuttings during hard rock and abrasive formation drilling. Two kinds of bad phenomena that often occur. Varel's technicians also conducted several tests against the quality of the grinding teeth to ensure proper diamond grain size and thermal stability when used in abrasive formation drilling. An operator drilling in Louisiana, USA, asked Varel to develop an 8-blade drill with 16mm diameter PDC teeth for drilling 9-7/8-inch sections. Drilling this section requires the passage of the very hard-to-drill and highly abrasive Hosston and Cotton Valley rock formations, which often wear very quickly when drilling wells. The last 600 feet of the section is to pass through the Bossier Formation, a softer shale/limestone combination formation that requires drilling without a worn cutting structure.
The main goal of the bit design is to increase its rate of penetration while at the same time not sacrificing the durability of existing bit structures. In addition, the designer also studied the superiority of cutting teeth as they drilled into shale/limestone formations.
The new drill uses a partial PowerCutter cutting structure with stiffening teeth on the main blade and tungsten carbide anti-vibration teeth on the auxiliary blade. This structure provides for drilling in abrasive and transitional formations. Better stability and protection of the main cutting structure.
For sharper bit cutting structures, the company designed and installed teeth with better wear resistance on the drill bit to prevent such formation damage to the bit cutting structure, while also making full use of the cutting teeth in the later stages of the drilling operation. The advantages brought by the size. The company's new drills achieved a 2,339-foot footage and a total depth of 10,945 feet, with an average penetration rate of 29.1 feet per hour. One of the other drill bits used in a recent adjacent well was pulled out because the mechanical drilling rate was too low, and only 600 feet were drilled in the Cotton Valley formation. Varel International's new drills increase the rate of penetration by nearly 30% and save about 30% of drilling costs per foot.
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