Patent Application
20100224413
This invention relates in general to earth-boring drilling operations, in particular to a method of selecting a drill motor for a casing drill string.
Most wells are drilled today utilizing a string of drill pipe. The drill pipe is made up of joints of pipe that are secured together by threads. The drill pipe is rotated either by a kelly bushing of the drilling rig or by a top drive of the drilling rig. Also, particularly in deviated wells, the operator may mount a drill or mud motor in the drill string just above the drill bit. The drill motor has a stator and a rotor, and drilling fluid pumped down the drill string causes the rotor to rotate the drill bit. While operating the drill motor, the operator may continue to rotate the drill string or may allow the drill string to remain stationary from time to time for steering the drill bit in a desired direction. At various depths and after the well is completed, the operator retrieves the drill string and runs casing into the well. The operator cements the casing in place.
Another type of drilling utilizes a casing string or a liner string as the drill string rather than a separate section of drill pipe. Casing and liner comprise pipes that are intended to be cemented in the wellbore to line the wellbore. A difference between casing and liner is that each string of casing installed will extend back to the wellhead; the upper end of a liner string normally extends up only a short distance past the lower end of the last string of casing installed in the wellbore. For the purposes herein, both casing and liner will be referred to as casing. Casing is larger in outer diameter and inner diameter than conventional drill pipe.
Typically, a bottom hole assembly latches to the lower end of the string of casing. When the casing has drilled to a desired depth, the operator may retrieve the bottom hole assembly from the casing and cement the string of casing in place. An operator may also utilize a drill motor mounted in the bottom hole assembly for rotating the drill bit relative to the bottom hole assembly and the string of casing.
Drill motors are used for a variety of reasons while drilling with casing. They may be used in a “steerable” configuration for drilling along a non-vertical trajectory. They may be used in a straight-hole configuration for minimizing casing wear or reducing casing vibrations by allowing the casing to be rotated at a slow speed while rotating the drilling assembly at a higher speed. Drill motors may also be used to improve the penetration rate by providing higher bit rotational speed than would otherwise be practical.
There are generally two types of drill motors, one being a positive displacement motor and the other a turbine. The positive displacement motor has an elastomeric stator with a central passage having a helical contour. A rotor, normally formed of metal, extends through the passage. The rotor has a helical contour containing a different number of lobes from the stator. The discussions herein deal only with the positive displacement motor and are not applicable to turbine drill motors.
Drill motors provide a linear output torque proportional to the pressure drop through the power section of the motor. The bit speed is typically proportional to the flow rate of drilling mud passing through the motor. However, there is a slight decrease in rotational speed as the drill motor is loaded at higher torques and drilling fluid bypasses between the rotor and stator. Drill motors can be designed to provide a wide range of performance characteristics by selecting the diameter of the power section, the power section lobe configuration, the number of stages and the pitch of the stages.
In general, the end user is faced with a choice of selecting the proper motor from a catalogue of many motors provided by a number of motor providers. These drill motors are usually described along with a power curve, which is a graph of the output torque versus the internal fluid pressure drop as the fluid passes through the motor. Two main parameters other than motor size are used to characterize a motor. One is the maximum torque that can be provided, and the other is the rotational speed, which may be defined in terms of rotations per gallon of fluid throughput. The end user first selects the group of motors defined by the appropriate, usually largest, diameter that will fit in the hole to be drilled. Next, the flow rate of the drilling fluid is selected to provide adequate transport of the cuttings back up the annulus around the drill pipe while allowing the pressure losses in the wellbore annulus to be limited for well control and bore hole stability. A group of motors is then identified that provides the appropriate rotational speed for the drilling tools that will be used in the well. Finally, a motor is selected from this group that has sufficient torque to turn the drilling tools at the maximum weight on the bit expected to be needed to drill the well.
When drilling with casing, the process of selecting a drill motor described above often does not lead the user to a selection that will power the drilling equipment effectively. The central bore of the casing drill string is much larger than the central bore or a drill pipe drill string, which includes drill pipe and drill collars. Selecting the drill motor as if one would select a drill motor for a drill pipe drill string can lead to motors that may do not drill efficiently.
In the method of this invention, the operator determines a delivery torque provided by a first candidate motor as a function of the pressure drop of drilling fluid flowing through the first candidate motor. The operator calculates a demand torque for the drill string based on the type of drill bit and the effect the pressure drop through the motor (“DP) has on the weight on the bit (“DWOB”). The operator compares the demand torque to the delivery torque and may choose the first candidate motor if the delivery torque exceeds the demand torque by a selected level.
In one embodiment, the demand torque is determined partly by empirical measurements based on the type of drill bit to be used. For example, if the bit is a fixed head bit as opposed to a rolling cone bit, it will require more torque than the rolling cone bit to turn. Alternately, the theoretical models can be employed to determine the relationship between bit torque and the weight on the bit. Normally, the relationship between the bit torque and the WOB is linear, thus the ratio of the two is a constant number. Also, the operator determines the increase in WOB as a function of the increase in pressure in the casing string. This function may be calculated based on the cross-sectional area of the casing and the type of material of the casing. The demand torque can be expressed as a function of the DP so that it can be compared to the delivery torque.
Referring to
A drill or mud motor 23 is connected into bottom hole assembly 17 just above reamer 21 for rotating reamer 21 and drill bit 19 relative to casing 11. Reamer 21 rotates in unison with drill bit 19 and may be considered to be a part of drill bit 19. Drill motor 23 is a conventional device that causes rotation of drill bit 19 in response to drilling fluid pumped down through casing 11 and bottom hole assembly 17. A schematic example of a drill motor 23 is shown in
Rotor 27 has a lower end coupled by a flexible shaft 31 to drill bit 19. The lower end of flexible shaft 31 is concentrically supported by bearings 29. The upper end of shaft 31 orbits with rotor 27. Drill bit 19 may be a conventional type, such as a rolling cone bit or a PDC bit. A PDC bit is a solid head bit having polycrystalline diamond cutters that scrape against the formation as bit 19 is rotated.
Casing string 11 is supported and rotated by a gripping mechanism 33. Gripping mechanism 33 has grapples that insert into the upper end of casing string 11. The grapples are stroked hydraulically into gripping engagement with either the inner diameter of casing 11 or the outer diameter. A top drive 35 supports gripping mechanism 33 and provides the rotational force. Top drive 35 is moved upward and downward along a derrick of the drilling rig. Drilling fluid is pumped through a hose 37 that is connected to the upper end of top drive 35. Gripping mechanism 33 has a flow tube that inserts into casing string 11 and seals against the inner diameter. Gripping mechanism 33 and top drive 35 may be conventional.
The slope of the curve in
Although the flow rate out of the mud pumps at the surface is constant, the pressure will increase if pressure restrictions occur. The consideration for flow rate will depend upon the type of mud pumps and the amount of fluid flow needed to return the cuttings to the surface. For example, if the mud pumps are set at 450 gpm, because of these considerations, the maximum torque output of the drill motor of
While drilling the operator will try to maintain a desired weight on bit 19 (“WOB”) depending on the type of formation being drilled. The WOB is typically controlled by controlling the brakes on the blocks that suspend the drill string. As the WOB is increased, the pressure drop across drill motor 23 increases because the additional weight requires drill motor 23 to exert more torque to turn bit 19. The increased pressure drop across drill motor 23 causes the internal pressure inside casing string 11 to increase, and the increased pressure or DP within casing string 11 tends to cause the casing string 11 to elongate. Because casing string 11 is supported in tension at the surface, and the downhole end of casing 11 is supported on the bottom borehole 13, the string of casing 11 actually does not elongate. What happens is the neutral point in the casing string 11 between compression and tension moves upward, which causes the compressive force or WOB to increase. Thus an increased DP within casing string 11 will cause an increased WOB.
The large internal diameter of casing string 11 causes an exaggerated elongation of casing string 11 compared to a drill pipe string as the pressure in the casing string 11 is increased. This tendency to elongate casing string 11 provides a positive feedback loop in the motor control process. That is, an increase in WOB increases the demanded torque, which increases the internal casing pressure DP and tends to elongate casing string 11. That tendancy to elongate in turn further increases WOB. Since an increased WOB requires more torque, it can eventually cause drill motor 23 to stall when drill motor 23 is unable to provide the additional torque.
From 16 to about 16.4 minutes, the fluid pressure, WOB and flow rates were generally constant with the fluid pressure being slightly under 1700 psi, the WOB being roughly 15,000 pounds, and the flow rate being about 400 gpm. During this time, the block position moved steadily downward along a linear slope. At around 16.45 minutes, the internal pressure at the mud pumps increased by about 800 psi. At the same time, the WOB increased by about 21,000 pounds, indicating that the drill motor was stalling. The graph shows that the operator then turned off one of the mud pumps in attempt to get the drill motor to again rotate. At 16.7 minutes, the operator turned off the second pump. During the time the drill motor was stalling, the block ceased to move downward and at 16.9, the operator picked up the blocks in order to reduce the WOB and get the drill motor to start rotating again.
The amount of the increased DWOB as a function of DP can be calculated according to the equation shown in
DWOB=DP*[Ai−(2Mu*AS/(OD/10)2−1)]
DP=change in casing pressure
DWOB=change in weight on bit
Ai=cross-sectional area of casing bore or inner diameter
As=cross-sectional area of the casing wall
OD=casing outside diameter
ID=casing inside diameter
Mu—Poisson's Ratio (normally 0.3)
As shown in the graph of
The torque required to rotate a bit or bit torque depends upon the type of drill bit as well as the weight on the bit. A rolling cone drill bit, for example, has bearings with cones that rotate as the bit is rotated. This type of bit demands much less torque to rotate than a fixed head bit. Fixed head or PDC bits are very commonly used and comprise a solid head bit with polycrystalline diamond cutters arranged to scrape and gouge the formation as the bit rotates. Theoretical models are available that predict a relationship between the weight on the bit and the torque for various bits.
The relationship between the change in internal pressure of the casing DP and the applied weight on the bit DWOB is linear, according to the equation in
Table 1 below provides an example of how to select a drill motor with this method:
In the example, Poissons Ratio is normally 0.3 for the type of steel employed in casing. Table 1 thus shows that for this particular string of casing, DWOB (increase in weight on bit) is proportional to 50 DP (increased in internal pressure in casing). DWOB=50 DP can be converted to TDm as a function of DP since it is known from
Assume for example, that the DP encountered is 300 psi as shown in Table 1 in order to operate the drill motor. The DWOB caused by this increase in pressure would be approximately 15,000 pounds. For this example, the 300 psi pressure difference was arbitrarily selected. The torque delivered by this drill motor at 300 psi would be 6,000 foot pounds. The bit torque demand TB would be 4500 foot pounds. The ratio of 6,000 foot pounds over 4500 foot pounds comes to the same ratio of 1.33.
Computations similar to those described above have been made for additional motors as set forth below in Table 2 below:
Using the prior art process to select a motor might lead one to choose a high performance motor, an example of which is illustrated in
The method thus described enables one to choose a suitable drill motor for casing drilling because it takes into account the stretch or tendency of the casing to elongate in response to pressure increases.
While the invention has been shown in only one of its forms, it should be apparent to those skilled in the art that it is not so limited and is susceptible to various changes without departing from the scope of the invention.
