Note: Descriptions are shown in the official language in which they were submitted.
CA 02498984 2012-05-17
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"Apparatus and Method for determining the position of
an elongate member of a pump assembly"
The present invention relates to an apparatus and
method for determining the position of an elongate
member particularly but not exclusively within a well.
Progressive cavity pumps (PCPs) pump fluids from a well
to the surface and their deployment in a well is common
practice. Typically such a pump would be driven by a
mechanism comprising an electric motor equipped with a
speed reduction gearbox situated at the top of the well
bore. The power is transmitted to the rotor of the PCP
via an elongate member, known as a drive shaft, located
within the production tubing conduit of the well. The
speed of rotation of the drive shaft is selected to
achieve optimum production rates from the well. The
faster the rotation, the higher the rate of fluids
produced but the greater the torsion and strain put on
the drive shaft.
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1 The drive shaft is typically assembled from a number
2 of rods screwed together to give the overall drive
3 shaft length required, which may be many hundreds of
4 feet. It is known from engineering principles that
in such an arrangement the drive shaft will
6 experience torsional deflection (twisting) of a
7 magnitude directly proportional to the power
8 transmitted and to the shaft length.
9
Changes in the composition and condition of the
11 produced fluids affects the speed of rotation of the
12 pump in the production zone. Abrupt speed increases
13 can be caused by gas bubbles, due to the removal of
14 the resistance coincident with the passage of the
gas bubble through the pump rotor. Equally, abrupt
16 reductions in the speed of the pump can be caused by
17 slugs of high viscosity fluids or solids. These
18 abrupt changes to the freedom of the rotor to turn
19 in the pump cause drastic changes in the torque
applied to the drive shaft, and it has been found
21 that this can result in failure of the shaft.
22
23 Indeed, breaking of PCP drive shafts accounts for a
24 high percentage of failures in such production
systems, leading to large repair costs and
26 associated loss of production revenue.
27
28 In order to assemble the PCP in a well, a pump
29 housing is provided within the well, the drive shaft
is attached to clamps and lowered into the well with
31 the pump rotor connected to the bottom of the drive
32 shaft. The rotor is landed into the pump housing
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1 and is lowered to a position slightly spaced away
2 from the bottom of the housing by a certain
3 distance. If the rotor is too close to the bottom
4 of the pump housing, the in-use temperature can
increase past the operational design limits of the
6 pump, causing damage to and failure of the pump. If
7 the rotor is spaced too far away from the bottom of
8 the pump housing, the rate of the fluids produced by
9 the pump is reduced.
11 In order to position the rotor accurately, the drive
12 shaft and rotor are lowered into the pump housing
13 until the weight reduction on the hoist at the
14 surface indicates that the rotor is in contact with
the bottom of the housing. The drive shaft and
16 rotor are then raised by the required distance in
17 order to safely space the rotor away from the bottom
18 of the housing.
19
In practise it is difficult to accurately determine
21 the distance to raise the drive shaft at the surface
22 to correspond with the longitudinal displacement of
23 the rotor in the housing, due to the uncertain
24 amount of give provided in the individual rods of
the drive shafts and their interconnections. For
26 wells which are at a non-vertical angle, this is
27 even more difficult. Thus the positioning of the
28 rotor is approximate and can result in failure of
29 the pump or a reduced production rate from the well.
Moreover, during use of the pump and rotation of the
31 drive shaft, the give in the drive shaft may
32 increase under continued stress and the drive shaft
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1 may also slip in the clamps, causing a change in the
2 longitudinal displacement of the rotor, which can
3 also result in failure of the pump or a reduced
4 production rate.
6 According to a first aspect of the present invention
7 there is provided an apparatus for determining the
8 position of at least a portion of a pump assembly in
9 a borehole, the apparatus comprising:
a detection device adapted to detect the position of
11 the portion of the pump assembly within the
12 borehole, the detection device connectable to a
13 borehole;
14 a communication device adapted to relay information
on the position of the portion of the pump assembly
16 within the borehole to a controller.
17
18 According to a second aspect of the present
19 invention, there is provided an apparatus for
determining the position of at least a portion of a
21 pump assembly within a borehole, the apparatus
22 comprising:
23 a portion of a pump assembly;
24 a detection device adapted to detect the position of
the portion of the pump assembly within the
26 borehole, the detection device being connectable to
27 a borehole; and,
28 a communication device adapted to relay information
29 on the position of the portion of the pump assembly
within the borehole to a controller.
31
CA 02498984 2005-03-01
1 Said portion of the pump assembly may comprise a
2 rotor of a pump.
3
4 Said portion of the pump assembly may comprise a
5 drive shaft adapted to rotate a rotor.
6
7 The pump assembly includes a pump normally having a
8 rotor and a pump housing and typically a drive shaft
9 extending from a motor provided at the surface to
the pump. The pump assembly may comprise other
11 components.
12
13 In a first embodiment of the invention the detection
14 device may be adapted to measure the extent of
rotation of the drive shaft or pump within the
16 borehole. Thus the position detected is the
17 rotational position of the portion of the pump
18 assembly, typically the drive shaft.
19
In a second embodiment the detection device may be
21 adapted to detect the longitudinal displacement of
22 the portion of the pump within the borehole. Thus
23 the position detected is the longitudinal position
24 of the portion of the pump assembly, typically the
rotor.
26
27 In preferred embodiments the detection devices are
28 adapted to measure the extent of rotation of the
29 pump or drive shaft within the borehole and detect
the longitudinal displacement of the rotor of the
31 pump assembly within the borehole.
32
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1 The pump housing may be provided within the
2 borehole. Thus, for embodiments which determine the
3 longitudinal displacement of the portion of the pump
4 within the borehole, they preferably determine the
longitudinal displacement of the pump rotor relative
6 to the pump housing.
7
8 'Longitudinal displacement' as used herein refers to
9 the longitudinal displacement or position of the
portion of the pump along the main axis of the
11 borehole. For example, when the borehole is
12 completely vertical the 'longitudinal displacement'
13 is the vertical displacement.
14
Preferably the detection device has a first part
16 which is connectable to the borehole and a second
17 part which is connectable to the portion of the pump
18 assembly.
19
Preferably the interaction of the first and second
21 parts of the detection device allows the detection
22 device to detect the position of the portion of the
23 pump assembly within the borehole.
24
The detection device may be an electromagnetic wave
26 detection device, such as a radioactive marker and
27 detector; it may alternatively be a physical
28 detection device with the first and second parts
29 physically contacting each other. Preferably
however the detection device is a magnetic detection
31 device.
32
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1 A plurality of detection devices may be provided.
2
3 The controller may be a computer controller or may
4 be a user.
6 The apparatus may comprise a movement mechanism,
7 adapted to vary the longitudinal displacement of the
8 portion of the pump assembly (typically the pump
9 rotor relative to the pump housing) optionally in
response to the longitudinal displacement detected
11 by the detection device. Thus the controller can be
12 connected to the movement mechanism.
13
14 The apparatus typically comprises a holding device
adapted to hold the drive shaft of the pump
16 assembly. The movement mechanism is preferably
17 adapted to move the holding device in order to vary
18 the longitudinal displacement of a portion of the
19 pump assembly, typically the rotor.
21 The movement mechanism may comprise a jack such as a
22 hydraulic jack adapted to move the holding device.
23
24 The holding device is typically a clamp.
26 Typically the detection device is provided proximate
27 to the operating depth of the pump of the pump
28 assembly; preferably within 50m of the pump, more
29 preferably within 30m of the pump, even more
preferably within 10m of the pump, most preferably
31 within 2m of the pump.
32
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1 The borehole is typically a well.
2
3 The detection device may comprise a measurement
4 means.
6 Thus the invention also provides an apparatus to
7 measure the torsion in an elongate member, the
8 apparatus comprising:
9 a first measurement means adapted to measure
the extent of rotation of an elongate member at a
11 first point;
12 a second measurement means adapted to measure
13 the extent of rotation of the elongate member at a
14 second point; and
a comparison means adapted to compare the
16 rotation measured by the first measurement means and
17 the rotation measured by the second measurement
18 means.
19
According to a further aspect of the present
21 invention, there is provided an apparatus for
22 determining the torsion in an elongate member in a
23 well, the apparatus comprising:
24 an elongate member;
a first measurement means adapted to measure
26 the extent of rotation of the elongate member
27 at a first point;
28 a second measurement means adapted to measure
29 the extent of rotation of the elongate member
at a second point; and
31 a comparison means adapted to compare the
32 rotation measured by the first measurement
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1 means and the rotation measured by the second
2 measurement means.
3
4 The elongate member is typically suspended within a
well and may comprise a series of connected members.
6 Typically the elongate member connects an artificial
7 lift device, for example a submergible progressive
8 cavity pump, within the well to a motor at the
9 surface or at the top of the well close to the
surface. Typically, the elongate member is a drive
11 shaft.
12
13 The torsion of an elongate member is the degree of
14 strain placed on that elongate member by rotation of
forces acting in equal but opposite directions.
16
17 The first measurement means may be provided at the
18 surface. Preferably the first point is proximate to
19 the motor and preferably the second point is at the
opposite end of the shaft, preferably proximate to
21 the pump. In alternative embodiments, the first
22 measurement means can be adapted to measure the
23 output axle of the motor in order to measure the
24 extent of rotation of the elongate member at the
first point.
26
27 Each measurement means may each comprise a magnet
28 and a magnet sensing device, one being provided on
29 the elongate member and the other being provided
proximate to but not connected to the elongate
31 member such that one rotates with respect to the
32 other.
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2 Preferably a magnet is provided on the elongate
3 member and the magnetic sensing means is provided
4 proximate to but not connected to the elongate
5 member.
6
7 Preferably the magnetic sensing means of the first
8 measurement means is provided on a frame.
9
10 Preferably the magnetic sensing means of the second
11 measurement means is provided on a production tubing
12 or on a housing on the production tubing.
13
14 Preferably the comparison means is provided at the
15 surface. Typically each measurement means is
16 connected to the comparison means, by a cable or the
17 like. Typically each complete revolution of the
18 elongate member is sensed by each measurement means
19 and this information can be transmitted to the
20 comparison means by an electric current or any other
21 means.
22
23 The apparatus may comprise a third and fourth
24 measurement means which co-operate with the first
25 and second measurement means such that each half
26 revolution of the elongate member at each point is
27 sensed and this information is transmitted to the
28 comparison means. Thus the 'extent of rotation' can
29 be less than one complete revolution, equal to one
30 complete revolution or more than one complete
31 revolution.
32
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1 Similarly any number of further measurement means
2 may be provided to measure part-revolutions of the
3 elongate member.
4
The torsion of the elongate member is calculated by
6 comparison of the difference between the extent of
7 rotation of the elongate member at the first and
8 second points, the speed of rotation of the elongate
9 member and the length between the first and second
points of the elongate member. Other factors such
11 as temperature and pressure may also be taken into
12 account.
13
14 Preferably the apparatus further comprises alarms
which are adapted to activate should the torsion
16 determined by comparison of the extent of rotation
17 of the elongate member at the first and second
18 points exceed or approach a level indicative of
19 fracture or breakage of the elongate member.
Preferably means to manipulate the motor may be
21 activated when predetermined limits of torsion are
22 exceeded.
23
24 Preferably pre-determined acceptable values for all
parameters may be compared to monitored values for
26 the purpose of initiating such alarms, trips or
27 drive-shaft manipulation procedures.
28 The measurement means at the second point may be
29 combined with sensing means, such as temperature,
pressure or other sensors.
31
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1 The measurement means at the first point may be
2 combined with other sensing devices to monitor
3 additional drive-shaft parameters, for example, the
4 speed of rotation and the direction of rotation.
6 Preferably the apparatus further comprises a control
7 means connected to the elongate member, the control
8 means being adapted to vary the speed of the
9 elongate member, typically via the motor, in
response to the torsion calculated by the comparison
11 means.
12
13 Preferably the first and second points are spaced
14 apart from each other on the elongate member. There
can be at least 10m between the first and second
16 point, preferably at least 50m between the first and
17 second points, more preferably at least 100m between
18 the first and second points.
19
The distance between the first and second points on
21 the elongate member can be at least 25% of the total
22 length of the elongate member, preferably more than
23 50%, more preferably more than 75%, even more
24 preferably more than 90% of the total length of the
elongate member.
26
27 According to a further aspect of the present
28 invention there is provided a method for determining
29 the position of at least a portion of a pump
assembly in a borehole, the method comprising:
31 providing a detection device within the borehole;
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1 detecting a position of the portion of the pump
2 assembly within the borehole,
3 relaying the information on the position of the
4 portion of the pump assembly within the borehole via
a communication device to a controller.
6
7 Preferably the method is performed using apparatus
8 in accordance with the first and optionally second
9 and optionally other earlier aspects of the
invention.
11
12 In one embodiment the method determines the
13 longitudinal displacement of the portion of the pump
14 assembly, typically the rotor. In another
embodiment the method determines the extent of
16 rotation of the portion of the pump assembly,
17 typically the drive shaft. In preferred
18 embodiments, the method determines both the
19 longitudinal displacement of the portion of the pump
assembly and the extent of rotation of the portion
21 of the pump assembly.
22
23 The method may include moving the pump rotor with
24 respect to the pump housing, detecting the
longitudinal displacement of the rotor with respect
26 to the pump housing, and optionally adjusting the
27 longitudinal displacement of the rotor in response
28 to the longitudinal displacement detected.
29
The movement mechanism preferably moves the pump
31 rotor such that the longitudinal distance between
32 the rotor and the bottom of the pump housing
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1 corresponds to an optimum longitudinal distance
2 between the rotor and the bottom of the pump
3 housing, that is typically where the rate of flow
4 from the pump is at a maximum, typically without
surpassing the operational design limits of the
6 pump.
7
8 The communication device may be an electrical cable
9 extending from the well to the surface.
11 The invention also provides a method for determining
12 the torsion of an elongate member, the method
13 comprising:
14 rotating at least a portion of an elongate
member;
16 measuring the extent of rotation of the elongate
17 member at a first point;
18 measuring the extent of rotation of the
19 elongate member at a second point;
comparing the extent of rotation of the
21 elongate member at the first and second points.
22
23 Preferably the method according to the third aspect
24 of the present invention is utilised with the
apparatus according to the first aspect of the
26 present invention.
27
28 The speed of rotation of the elongate member may be
29 varied as a consequence of the torsion determined in
order to reduce the likelihood of or preferably
31 avoid the elongate member from fracturing or
32 breaking.
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2 Preferably the method is used to determine the
3 torsion of an elongate member suspended within a
4 well. Preferably the method is used to determine
5 the torsion of a drive shaft extending from a motor
6 to a pump within the well.
7
8 Preferably the measurement device senses each
9 revolution of the elongate member. Preferably
10 therefore, the measurement device counts the number
11 of revolutions of the elongate member.
12
13 An embodiment of the present invention will now be
14 described, by way of example only, with reference to
15 the accompanying drawings in which:
16 Fig. 1 is a diagrammatic sectional view of a
17 well having a progressive cavity pump and
18 torsion detecting apparatus according to the
19 present invention installed therein;
Fig. 2 is an enlarged diagrammatic sectional
21 view of the lower end of the Fig. 1 well;
22 Fig. 3a is a diagrammatic view of a
23 compensating mechanism provided for certain
24 embodiments of the present invention, in a
first position;
26 Fig. 3b is a diagrammatic view of the
27 compensating mechanism of Fig. 3a, in a second,
28 raised position;
29 Fig. 4 is an enlarged view of components
attached to a wellhead of the well shown in
31 Fig. 1;
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1 Fig. 5 is a diagrammatic view of the data
2 produced by measurement devices of the present
3 invention.
4
Fig. 1 shows an oil producing well comprising a well
6 casing 2 and a submergible progressive cavity pump 1
7 suspended therein by production tubing 3. The
8 cavity pump 1 pumps well fluids through the
9 production tubing 3 to a wellhead 5 at the surface
where it is recovered by conventional means (not
11 shown). It will be understood that the production
12 well casing 2, production tubing 3 and a drive shaft
13 44 can extend for hundreds of metres depending on
14 the depth of the well and so Fig. 1 is not to scale.
The drive shaft 44 is typically made up of a series
16 of drive rods 17.
17
18 Cavity pumps function by the provision of helical
19 rotor 12 in a housing 14. The helical rotor 12
drives fluid into the production tubing 3 and
21 upwards to the surface. Such pumps are known in the
22 art and can be obtained from Schlumberger or
23 Weatherford for example.
24
A downhole measurement device 31 is provided
26 proximate to the operating depth of the cavity pump
27 1, as shown in Fig. 2. A magnet 13 is attached to
28 the drive shaft 44 and a magnetic sensing device 18
29 is provided in a housing 32 provided on the
production tubing 3. The downhole measurement
31 device 31 can detect when the magnet 13 is aligned
32 with the magnetic sensing device 18. Thus the
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downhole measurement device can detect longitudinal
movement of the drive shaft 44 and can count the number
of revolutions of the drive shaft 44 near the cavity
pump 1. Such sensing devices are commercially available
and can be obtained from a number of suppliers, one
being RS Components.
Power is supplied to the magnetic sensing device 18 via
a cable 20 and the data gathered by the magnetic
sensing device 18 is transmitted to the computer 24 via
a transmission cable 25 (shown only in Fig. 1).
To assemble the pump 1, the housing 14 is firstlowered
into the well with the production tubing 3.A torque
anchor 4 secures the housing 14 of the pump 1 to the
well casing 2 in order to prevent it from rotating with
respect thereto.
The rotor 12 is then attached to the drive shaft 44 at
the surface.The magnet 13 of the downholemeasurement
device 31 is attached to the drive shaft 44. The rotor
12 and attached drive shaft 44 are lowered into the
production tubing 3. Additional rods 17 of the drive
shaft 44 are successively added thereto until the
magnet 13 passes the magnetic sensor 18. The magnetic
sensor 18 senses the magnet 13 and relays this
information to the surface via a communication line 20.
As the length of the rotor 12 is known, a simple
calculation can be performed to position the rotor 12
at the optimum distance 31 from the bottom of the
housing 14.
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Thus embodiments of the invention benefit in that the
position of a rotor of a pump may be accurately
determined. This can provide an increased production
rate from the pump since the rotor can be positioned at
a point to allow the pump to safely produce at its
maximum capacity.
In use, the rotor 12 of the pump 1 is rotated by the
drive shaft 44 which is suspended within the production
tubing 3 from an electric motor 7 via a drive mechanism
6 and a speed reduction gear box 8.The drive shaft 44
connects to the rotor 12 via an internal shaft 11.
During use, the downhole measurement device 31continues
to sense the vertical/longitudinal displacement of the
rotor 12 of the pump 1 and thisinformation may be
continually relayed to thesurface where the
longitudinal displacement of the rotor may be altered
in response to thisinformation.
Figs. 3a and 3b show a compensating mechanism 40 which
may be used to automatically correct the longitudinal
displacement of the rotor 12, should this change during
use for any reason, for example should the drive shaft
44 slip from its clamps or if the give in the drive
shaft 44 increases over time.
The compensating mechanism 40 comprises a clamp 41 and
tapered slips 42 both mounted on a bearing unit 43, a
hydraulic jack 45 and a hollow piston 47. The
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1 hydraulic jack 45 is provided above the wellhead 5
2 and below the drive motor 7, mounted on a supporting
3 framework 46.
4
The drive shaft 44 is held by the clamp 41 and
6 passes through the bearing unit 43 and hollow piston
7 47. The clamp 41 transfers the weight of the drive
8 shaft 44 and attached rotor 12 to the slips 42 which
9 also holds the drive shaft 44 and attached pump 1.
Thus movement of the piston 47 will cause movement
11 of the drive shaft 44. The bearing unit 43 allows
12 for free rotation of the drive shaft 44 through the
13 hollow piston 47 of the hydraulic jack 45.
14
Thus when the downhole measurement device 31 relays
16 information that the longitudinal displacement of
17 the rotor 12 has changed, the piston 47 of the
18 hydraulic jack 45 is activated to move, which via
19 the bearing unit 43 and slips 42 moves the drive
shaft 44 vertically and the connected rotor 12
21 vertically/longitudinally. Thus the rotor 12 may be
22 repositioned to its optimum distance from the bottom
23 of the housing 14.
24
Embodiments of the present invention benefit in that
26 the rotor 12 can be maintained in the optimum
27 longitudinal position for safely pumping fluids at
28 its maximum capacity. Thus the production rate from
29 the well can be increased.
31 Certain embodiments of the present invention also
32 comprise a surface measurement device 30, shown in
CA 02498984 2005-03-01
1 Fig. 4. The surface measurement device comprises a
2 magnet 16 provided on a coupling 15 of the drive
3 shaft 44 and a magnetic sensing device 21 provided
4 on a frame 34 adjacent to the coupling 15. The
5 magnetic sensing device 21 can sense the magnet each
6 time it passes close to the sensing device 21 and
7 thereby counts the number of rotations of the drive
8 shaft 44 above the surface. The data from the
9 magnetic sensing device 21 is transmitted to a
10 computer 24 via the cable 26. Power is supplied to
11 the magnetic sensing device 21 by means of the cable
12 23.
13
14 Thus in use, the surface measurement device 30
15 counts the number of rotations of the drive shaft 44
16 at the surface and sends this data to the computer
17 24.
18
19 Activation of the motor 7 will put the drive shaft
20 44 under strain/torsion due to the drag on the pump
21 1 caused by the production fluids, and to a lesser
22 extent the temperature and pressure within the well
23 casing. The amount of torsion is also dependent on
24 the length of the drive shaft 44 between the surface
and downhole measurement devices 30, 31. Thus,
26 after the motor 7 is activated and the drive shaft
27 44 begins to rotate at the surface as detected by
28 the surface measurement device 30, the drive shaft
29 44 will twist and there will be a delay before the
drive shaft 44 rotates close to the cavity pump 1.
31
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1 The downhole measurement device 31 counts the number
2 of rotations of the drive shaft 44 at the opposite
3 end which, due to this torsion, will typically be
4 different from that at the top of the elongate
member. This data will also be sent to the computer
6 24 for comparison with data received from the
7 surface measurement device 31. Other parameters,
8 such as the speed at which the motor rotates the
9 drive shaft 44 and the distance between the surface
30 and downhole 31 measurement devices will also be
11 sent to the computer 24.
12
13 The computer continuously calculates and provides
14 real time data on the amount of
twisting/torsion/rotational deflection on the drive
16 shaft 44. This can vary in time due to the
17 different types of fluids encountered by the pump 1.
18 For example, at one point in time, the pump can be
19 pumping liquids to the surface whereas at another
point in time, the pump may encounter sand or
21 viscous liquids which will cause extra drag and
22 increase the torsion on the drive shaft 44. The
23 computer 24 thus monitors, displays and reports the
24 torsion in the drive shaft 44. Should this level be
approached or exceeded, the computer can be adapted
26 to activate alarms or reduce the speed of rotation
27 of the drive shaft by reducing the speed of the
28 motor 7 by for example, manipulating the gearbox 8
29 to ensure that it does not exceed a predetermined
safety level which could cause the drive shaft 44 to
31 fracture or break due to its torsional strain. As
32 noted above, the torsion in the drive shaft 44 is
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1 also proportional to the speed of rotation of the
2 drive shaft and so reducing the speed of the motor
3 results in a reduction of the torsion in the drive
4 shaft 44.
6 Suppliers of the rods 17 indicate the torsional
7 modulus of elasticity (G) when supplying the rods.
8 It depends on the rod thickness and the material
9 used to make the rod.
11 For example, if a drive rod 17 is rated to withstand
12 10001bs of torque, an alarm can be set to sound when
13 it is calculated that the rod 17 is experiencing
14 8001bs of torque and the motor 7 can be set to
automatically shut down when the torque the rod 17
16 is experiencing is calculated to be 9501bs.
17
18 The calculation of such torque can be computed using
19 established and known mathematical equations. One
suitable equation is:
21
22 Df = 584TaL/D4G
23 wherein
24 Df = Angular
deflection in degrees
Ta = Torsional Moment Applied (That is the radial
26 force applied by
motor) in ftlbs
27 L = Rod Length in
feet
28 D = diameter of
shaft in feet
29 G = Torsional
Modulus of Elasticity in lbs/feet2.
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1 An acceptable level of torsional shear stress may
2 also be calculated using known mechanical
3 engineering principles:
4
Ta =SZp
6
7 wherein
8
9 S = Allowable
Torsional Stress
Ta = Torsional Moment Applied (That is the radial
11 force applied by
motor) in ftlbs
12 Zp = Polar
Sectional Modulus of the Shaft
13 However, Allowable Torsional Stress used in practice
14 are 6000 lb/sq.in. The formula above may therefore
be transposed as:
16
17 Ta = 6000 x Zp
18 Published data provided by the supplier of the
19 proprietary drive rods, such as the rods 17, and/or
data obtained from mechanical testing of such drive
21 rod units may be used in the evaluation of specific
22 units employed in a drive string, such as the drive
23 shaft 44.
24
Typically, a drive shaft string, such as the drive
26 shaft 44, transmitting power to a progressive cavity
27 pump such as the pump 1 will be made up of multiple
28 drive shafts, such as the drive rods 17 of common
29 geometry, each transmitting the same torque and
undergoing the same amount of twisting.
31
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1 The amount of acceptable twisting can therefore be
2 calculated for any given drive shaft string at a
3 pre-determined acceptable level of torsional shear
4 stress.
6 Twisting in excess of that determined acceptable for
7 any individual drive shaft string can be measured as
8 described herein and protective measures initiated
9 to prevent catastrophic failure of that drive shaft
string.
11
12 Reference can also be made to "Machinery's
13 Handbook", 21st edition, pages 450-453 for more
14 detail on such calculations.
16 Typically the data sent from the measurement devices
17 30, 31 will be in a square wave form, such as that
18 shown in Fig. 5 and the torsion will be discernible
19 by comparison of the wave form 27 produced by the
surface measurement device 30 and the wave form 28
21 produced by the downhole measurement device 31. The
22 amount of twisting in the drive shaft 44 may be
23 compared by automatic electronic processing methods
24 to pre-determined acceptable values. Automatic
electronic processing may also be used to protect
26 the drive shaft 44 from damage by initiation of
27 alarm, trip and/or system adjustment procedures.
28
29 In certain embodiments of the present invention it
is not necessary to provide the information to the
31 user as to the extent of rotation of the elongate
32 member at the two points, such as the surface and
CA 02498984 2005-03-01
1 near the cavity pump 1, but only the difference
2 between the extent of rotation of the elongate
3 member at these two points. Similarly, for the
4 embodiments where a computer, such as the computer
5 24, is adapted to manipulate the speed of the motor
6 7 to ensure the torsion in the drive shaft 44 is
7 kept below a certain level, it does not need to know
8 the extent of rotation of the drive shaft at the
9 first and second points but it does need to know the
10 difference between these values.
11
12 Thus embodiments of the present invention benefit
13 from being able to determine when the drive shaft 44
14 is undergoing a critical torsional strain and reduce
15 the likelihood of such a strain resulting in the
16 fracture or breakage of the drive shaft 44 by taking
17 appropriate action, such as reducing the speed of
18 rotation of the drive shaft 44.
19
20 Certain embodiments of the present invention thus
21 benefit from reduced failure and thus avoid the
22 large repair costs and loss of production revenue.
23
24 Certain embodiments of the present invention also
25 benefit from allowing the cavity pumps to be run at
26 a far higher speed, which increases the rate of
27 recovery of the production fluids, and can be slowed
28 down when the torsion detection apparatus indicates
29 a critical torsional strain on the drive shaft.
Certain prior art systems were generally operated at
31 a much lower speed in case of fracture or breakage
32 of the drive shaft.
CA 02498984 2005-03-01
26
1
2 Improvements and modifications may be made without
3 departing from the scope of the invention. For
4 example, a plurality of magnets may be provided in
each of the sensing devices, particularly the
6 downhole sensing device. These magnets may be
7 spaced away from each other longitudinally or
8 rotationally. When spaced away from each other
9 longitudinally, they can provide more information on
the longitudinal position of the pump downhole.
