簡介：滑動鉆進提速，提升了井底控制能力。
頂驅在提升旋轉鉆井效率方面至關重要。對于定向鉆井來說，動力系統是帶有彎性套管的操控定向馬達。該馬達在馬達牽引下滑向鉆進，通過旋轉鎖定油管，利用
泥漿系統液壓動力來驅動
鉆頭鉆進。
Top drives have played a major role in improving rotary drilling efficiencies. For directional drilling, the workhorse has been the steerable directional motor with a bent housing. This type of motor is used for slide drilling, which is done by orienting the motor, locking the drillpipe from rotation, and using the hydraulic horsepower of the mud system to rotate the bit and make hole.
Common problems associated with slide drilling are setting the toolface before going on bottom; controlling the toolface setting while on bottom; and dealing with the reduced rate of penetration (ROP) compared to rotary drilling. Canrig’s Rockit directional steering control system addresses these problems using one integrated touch screen control panel. This directional steering control software converts the top drive from a valuable drilling asset to a valuable directional drilling asset, alleviating many of the problems associated with slide drilling.
Effective slide drilling
Setting the toolface before initiating a slide drilling interval can be challenging due to trapped torque in the drillpipe. Other difficulties include making accurate angular changes to the toolface or high side of the motor when it is in a deviated well bore. The traditional method is to make a chalk mark on the drillpipe at surface as a reference and use the rotary table or top drive to rotate the pipe to a new position estimated by the directional driller. This process is by nature error prone and time consuming.
Controlling the toolface while slide drilling is another challenge. Formation changes, unwanted variations of weight on bit, and reactive torque (which forces the motor to rotate against bit rotation) all combine to keep the directional driller busy. Again, the traditional method of steering control involves using the chalked pipe and estimation to obtain the required toolface downhole. Many times this cannot be achieved while drilling on bottom, so the drillstring has to be picked off bottom to work the trapped torque out of the string so the procedure of setting the toolface can be repeated.
In traditional slide drilling with no pipe rotation, friction forces on the sidewall and low side of the well bore make it increasingly difficult to deliver effective weight on bit. This problem reaches extreme proportions in horizontal wells where 30% or more of the drillstring and bottomhole assembly (BHA) are lying on the low side of the well bore. Without effective weight on bit, slide drilling can often slow to a crawl with ROPs less than 2 ft/hr (0.6 m/hr).
Software solution
With the directional control software, the above problems are effectively tackled in these three solutions areas:
Toolface setting before a slide. Using the top drive bearing offset control, the drillpipe can be rotated to any specific angular offset, right or left. This angular offset is exact and is controlled by the top drive’s programmable logic controller (PLC). Inputs to the PLC can be specified in degrees or in full or partial pipe revolutions.
Toolface control while sliding. The bearing offset control can be used during the slide to keep the toolface angle in the required range.
Friction reduction. Drillpipe oscillation can be set up through the touch screen to the PLC. Once a program of oscillation is defined by specifying pipe revolutions clockwise, counterclockwise or both, and the oscillation RPM, oscillation is simply switched on. The PLC maintains this oscillation until instructed differently. Oscillation magnitude and speed can be adjusted dynamically without stopping pipe movement.
An important point to note is that the toolface can still be steered while the oscillation program is running. Bearing offsets can be input and are applied in conjunction with the oscillation program and are passed down hole to the BHA.
The system can also track torque trapped in the drillpipe. The directional driller can reset the system when tagging bottom to initiate a slide. This provides a reference point from which to measure further pipe revolutions applied to the drillstring for steering purposes, and it solves another problem of slide drilling ? tracking trapped torque.
Without an accurate measurement of trapped torque, there are dangers associated with picking up off bottom with wraps still in the drillpipe. It can cause backspin on the pipe with unwanted results, such as back-off or damage to top drive brake systems.
Using the system, the driller can read on screen the number of wraps in the drillpipe and use the bearing offset control to back out these wraps before picking up off bottom, alleviating problems associated with trapped torque.
Decreased drilling time
Six wells in the Barnett Shale near Fort Worth, Texas, were drilled using both conventional methods and the directional control system for the curve and lateral sections.
These medium radius horizontal wells had pay zones at 5,500 to 6,000 ft (1,678 to 1,830 m) total vertical depth (TVD) and each had lateral sections of between 1,500 and 2,000 ft (458 and 610 m), with total measured depths (MDs) of approximately 9,500 to 10,000 ft (2,898 to 3,050 m). For the curve and lateral sections, conventional slide drilling toolface control methods were used in wells A through C. The directional control system was used in D through F.
The drilling performance with the directional control system showed a marked improvement in ROP from the previous three wells drilled in the same location and formations. The operator analyzed the performance data in house and determined that the directional control system significantly reduced drilling time in the curve and lateral sections. The operator’s objective of cutting at least a day from the drilling time for curve and the lateral was achieved.
The rig, bit selection, mud program, general BHA design, and hydraulics were not changed significantly across the batch of wells analyzed.
Improved ROP
Improvements in ROP were made on a well drilled in the Cotton Valley sandstone and James Lime areas of northeast Texas using the directional control system. The well had a medium radius horizontal well bore with a kickoff point slightly above 9,000 ft (2,745 m) TVD, a build to 91º inclination at 15º/ 100 ft (31 m), and a lateral section of approximately 3,000 ft (915 m).
In this well, 56 slides were identified from the log data and analyzed. All slide ROPs were compared against ROP in the follow-on rotary drilled section. Slide ROPs were averaged across the total directional interval from 9,042 to 12,792 ft (2,758 to 3,902 m) MD. Separate averages were calculated for the lateral section alone, from 9,952 to 12,792 ft (3,035 to 3,902 m) MD.
Over the total directional interval, slide drilling ROP averaged 9.6 ft/hr (2.9 m/hr), compared with a rotary drilling ROP of 25.2 ft/hr (7.7 m/hr), representing 38% of the average rotary ROP. Over the lateral directional interval only, slide drilling ROP averaged 12.4 ft/hr (3.8 m/hr), compared with a rotary drilling ROP of 27.9 ft/hr (8.5 m/hr), representing 45% of the average rotary ROP. An estimated additional time savings of 4.7 hours was delivered, using five minutes per orientation as an average time savings value.
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