CA2498984A1 - Apparatus and method for determining the position of an elongate member of a pump assembly - Google Patents
Apparatus and method for determining the position of an elongate member of a pump assembly Download PDFInfo
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- CA2498984A1 CA2498984A1 CA002498984A CA2498984A CA2498984A1 CA 2498984 A1 CA2498984 A1 CA 2498984A1 CA 002498984 A CA002498984 A CA 002498984A CA 2498984 A CA2498984 A CA 2498984A CA 2498984 A1 CA2498984 A1 CA 2498984A1
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- elongate member
- pump assembly
- measurement means
- rotation
- borehole
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- 238000000034 method Methods 0.000 title claims abstract description 29
- 238000005259 measurement Methods 0.000 claims abstract description 56
- 238000001514 detection method Methods 0.000 claims description 32
- 238000006073 displacement reaction Methods 0.000 claims description 29
- 230000007246 mechanism Effects 0.000 claims description 13
- 238000004891 communication Methods 0.000 claims description 7
- 230000004044 response Effects 0.000 claims description 7
- 239000012530 fluid Substances 0.000 abstract description 12
- 238000013459 approach Methods 0.000 abstract description 2
- 238000004441 surface measurement Methods 0.000 description 6
- 230000008901 benefit Effects 0.000 description 5
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- 238000005086 pumping Methods 0.000 description 2
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
- E21B47/092—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes by detecting magnetic anomalies
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
- E21B43/121—Lifting well fluids
- E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/008—Monitoring of down-hole pump systems, e.g. for the detection of "pumped-off" conditions
Abstract
An apparatus and method to measure the position of a portion of a pump assembly within a well particularly for use in an oil or gas well and for downhole pumps driven by a drive shaft running from a surface motor. The apparatus comprises at least one measurement device which senses the position of a portion of a pump assembly downhole. The information can be used to position a rotor of the pump assembly at an optimum position relative to a pump housing of the pump assembly to produce fluids from the well at an increased rate. Where two measurement devices are provided, they can count the number of revolutions of the drive shaft of the pump assembly at two spaced apart points. The strain or torsion within the drive shaft can then be calculated. If the torsion within the drive shaft approaches critical levels the speed of its rotation can be slowed in order to reduce the torsional strain in the drive shaft. The method and apparatus thus reduce the number of failures caused by fractured drive shafts. Since the torsion within the drive shafts can be determined, the speed of rotation of the drive shaft can be increased in normal operating conditions which allows an increased production rate from the well.
Description
1 "Apparatus and Method"
3 The present invention relates to an apparatus and 4 method for determining the position of an elongate member particularly but not exclusively within a 6 well.
8 Progressive cavity pumps (PCPs) pump fluids from a 9 well to the surface and their deployment in a well is common practice. Typically such a pump would be 11 driven by a mechanism comprising an electric motor 12 equipped with a speed reduction gearbox situated at 13 the top of the well bore. The power is transmitted 14 to the rotor of the PCP via an elongate member, known as a drive shaft, located within the 16 production tubing conduit of the well. The speed of 17 rotation of the drive shaft is selected to achieve 18 optimum production rates from the well. The faster 19 the rotation, the higher the rate of fluids produced but the greater the torsion and strain put on the 21 drive shaft.
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.
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.
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.
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 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.
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 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.
8 Progressive cavity pumps (PCPs) pump fluids from a 9 well to the surface and their deployment in a well is common practice. Typically such a pump would be 11 driven by a mechanism comprising an electric motor 12 equipped with a speed reduction gearbox situated at 13 the top of the well bore. The power is transmitted 14 to the rotor of the PCP via an elongate member, known as a drive shaft, located within the 16 production tubing conduit of the well. The speed of 17 rotation of the drive shaft is selected to achieve 18 optimum production rates from the well. The faster 19 the rotation, the higher the rate of fluids produced but the greater the torsion and strain put on the 21 drive shaft.
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.
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.
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.
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 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.
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 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.
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.
1 Said portion of the pump assembly may comprise a 2 rotor of a pump.
4 Said portion of the pump assembly may comprise a 5 drive shaft adapted to rotate a rotor.
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.
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.
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.
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.
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.
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.
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.
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.
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.
1 A plurality of detection devices may be provided.
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.
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.
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.
1 The borehole is typically a well.
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.
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 1 means and the rotation measured by the second 2 measurement means.
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.
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.
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.
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.
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.
7 Preferably the magnetic sensing means of the first 8 measurement means is provided on a frame.
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.
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.
1 Said portion of the pump assembly may comprise a 2 rotor of a pump.
4 Said portion of the pump assembly may comprise a 5 drive shaft adapted to rotate a rotor.
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.
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.
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.
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.
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.
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.
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.
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.
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.
1 A plurality of detection devices may be provided.
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.
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.
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.
1 The borehole is typically a well.
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.
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 1 means and the rotation measured by the second 2 measurement means.
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.
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.
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.
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.
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.
7 Preferably the magnetic sensing means of the first 8 measurement means is provided on a frame.
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.
14 Preferably the comparison means is provided at the 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 comparison means by an electric current or any other 21 means.
23 The apparatus may comprise a third and fourth 24 measurement means which co-operate with the first 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 complete revolution or more than one complete 31 revolution.
1 Similarly any number of further measurement means 2 may be provided to measure part-revolutions of the 3 elongate member.
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.
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.
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.
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.
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.
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.
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;
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.
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.
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.
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.
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 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.
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.
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.
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.
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.
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.
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:
23 The apparatus may comprise a third and fourth 24 measurement means which co-operate with the first 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 complete revolution or more than one complete 31 revolution.
1 Similarly any number of further measurement means 2 may be provided to measure part-revolutions of the 3 elongate member.
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.
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.
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.
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.
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.
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.
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;
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.
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.
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.
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.
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 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.
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.
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.
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.
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.
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.
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;
1 Fig. 5 is a diagrammatic view of the data 2 produced by measurement devices of the present 3 invention.
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.
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.
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 1 downhole measurement device can detect longitudinal 2 movement of the drive shaft 44 and can count the 3 number of revolutions of the drive shaft 44 near the 4 cavity pump 1. Such sensing devices are commercially available and can be obtained from a number of 6 suppliers, one being RS Components.
8 Power is supplied to the magnetic sensing device 18 9 via a cable 20 and the data gathered by the magnetic sensing device 18 is transmitted to the computer 24 11 via a transmission cable 25 (shown only in Fig. 1).
13 To assemble the pump 1, the housing 14 is first 14 lowered into the well with the production tubing 3.
A torque anchor 4 secures the housing 14 of the pump 16 1 to the well casing 2 in order to prevent it from 17 rotating with respect thereto.
19 The rotor 12 is then attached to the drive shaft 44 at the surface. The magnet 13 of the downhole 21 measurement device 31 is attached to the drive shaft 22 44. The rotor 12 and attached drive shaft 44 are 23 lowered into the production tubing 3. Additional 24 rods 17 of the drive shaft 44 are successively added thereto until the magnet 11 passes the magnetic 26 sensor 18. The magnetic sensor 18 senses the magnet 27 13 and relays this information to the surface via a 28 communication line 20. As the length of the rotor 29 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.
1 Thus embodiments of the invention benefit in that 2 the position of a rotor of a pump may be accurately 3 determined. This can provide an increased 4 production rate from the pump since the rotor can be positioned at a point to allow the pump to safely 6 produce at its maximum capacity.
8 In use, the rotor 12 of the pump 1 is rotated by the 9 drive shaft 44 which is suspended within the production tubing 3 from an electric motor 7 via a 11 drive mechanism 6 and a speed reduction gear box 8.
12 The drive shaft 44 connects to the rotor 12 via an 13 internal shaft 11.
During use, the downhole measurement device 31 16 continues to sense the vertical/longitudinal 17 displacement of the rotor 12 of the pump 1 and this 18 information may be continually relayed to the 19 surface where the longitudinal displacement of the rotor may be altered in response to this 21 information.
23 Figs. 3a and 3b show a compensating mechanism 40 24 which may be used to automatically correct the longitudinal displacement of the rotor 12, should 26 this change during use for any reason, for example 27 should the drive shaft 44 slip from its clamps or if 28 the give in the drive shaft 44 increases over time.
The compensating mechanism 40 comprises a clamp 41 31 and tapered slips 42 both mounted on a bearing unit 32 43, a hydraulic jack 44 and a hollow piston 47. The 1 hydraulic jack 45 is provided above the wellhead 5 2 and below the drive motor 7, mounted on a supporting 3 framework 46.
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.
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.
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 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.
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.
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.
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.
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 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.
18 The calculation of such torque can be computed using 19 established and known mathematical equations. One suitable equation is:
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.
1 An acceptable level of torsional shear stress may 2 also be calculated using known mechanical 3 engineering principles:
Ta =SZp 7 wherein 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:
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.
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.
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.
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.
2$
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 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.
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.
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.
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.
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.
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;
1 Fig. 5 is a diagrammatic view of the data 2 produced by measurement devices of the present 3 invention.
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.
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.
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 1 downhole measurement device can detect longitudinal 2 movement of the drive shaft 44 and can count the 3 number of revolutions of the drive shaft 44 near the 4 cavity pump 1. Such sensing devices are commercially available and can be obtained from a number of 6 suppliers, one being RS Components.
8 Power is supplied to the magnetic sensing device 18 9 via a cable 20 and the data gathered by the magnetic sensing device 18 is transmitted to the computer 24 11 via a transmission cable 25 (shown only in Fig. 1).
13 To assemble the pump 1, the housing 14 is first 14 lowered into the well with the production tubing 3.
A torque anchor 4 secures the housing 14 of the pump 16 1 to the well casing 2 in order to prevent it from 17 rotating with respect thereto.
19 The rotor 12 is then attached to the drive shaft 44 at the surface. The magnet 13 of the downhole 21 measurement device 31 is attached to the drive shaft 22 44. The rotor 12 and attached drive shaft 44 are 23 lowered into the production tubing 3. Additional 24 rods 17 of the drive shaft 44 are successively added thereto until the magnet 11 passes the magnetic 26 sensor 18. The magnetic sensor 18 senses the magnet 27 13 and relays this information to the surface via a 28 communication line 20. As the length of the rotor 29 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.
1 Thus embodiments of the invention benefit in that 2 the position of a rotor of a pump may be accurately 3 determined. This can provide an increased 4 production rate from the pump since the rotor can be positioned at a point to allow the pump to safely 6 produce at its maximum capacity.
8 In use, the rotor 12 of the pump 1 is rotated by the 9 drive shaft 44 which is suspended within the production tubing 3 from an electric motor 7 via a 11 drive mechanism 6 and a speed reduction gear box 8.
12 The drive shaft 44 connects to the rotor 12 via an 13 internal shaft 11.
During use, the downhole measurement device 31 16 continues to sense the vertical/longitudinal 17 displacement of the rotor 12 of the pump 1 and this 18 information may be continually relayed to the 19 surface where the longitudinal displacement of the rotor may be altered in response to this 21 information.
23 Figs. 3a and 3b show a compensating mechanism 40 24 which may be used to automatically correct the longitudinal displacement of the rotor 12, should 26 this change during use for any reason, for example 27 should the drive shaft 44 slip from its clamps or if 28 the give in the drive shaft 44 increases over time.
The compensating mechanism 40 comprises a clamp 41 31 and tapered slips 42 both mounted on a bearing unit 32 43, a hydraulic jack 44 and a hollow piston 47. The 1 hydraulic jack 45 is provided above the wellhead 5 2 and below the drive motor 7, mounted on a supporting 3 framework 46.
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.
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.
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 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.
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.
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.
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.
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 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.
18 The calculation of such torque can be computed using 19 established and known mathematical equations. One suitable equation is:
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.
1 An acceptable level of torsional shear stress may 2 also be calculated using known mechanical 3 engineering principles:
Ta =SZp 7 wherein 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:
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.
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.
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.
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.
2$
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 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.
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.
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.
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.
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.
Claims (33)
1. An apparatus for determining the position of at least a portion of a pump assembly in a borehole, the apparatus comprising:
a detection device adapted to detect the position of the portion of the pump assembly within the borehole, the detection device connectable to a borehole;
a communication device adapted to relay information on the position of the portion of the pump assembly within the borehole to a controller.
a detection device adapted to detect the position of the portion of the pump assembly within the borehole, the detection device connectable to a borehole;
a communication device adapted to relay information on the position of the portion of the pump assembly within the borehole to a controller.
2. Apparatus as claimed in claim 1, wherein the detection device has a first part which is connectable to the borehole and a second part which is connectable to the pump assembly.
3. Apparatus as claimed in either preceding claim, wherein the detection device comprises a magnet and a magnet sensing device.
4. Apparatus as claimed in any preceding claim, wherein the detection device is adapted to detect the longitudinal displacement of the portion of the pump assembly within the borehole.
5. Apparatus as claimed in claim 4, comprising a movement mechanism, adapted to vary the longitudinal displacement of the portion of the pump assembly.
6. Apparatus as claimed in claim 5, wherein the movement mechanism is adapted to vary the longitudinal displacement of the portion of the pump assembly in response to the longitudinal displacement of the portion of the pump assembly detected by the detection device.
7. Apparatus as claimed in any preceding claim, wherein the portion of the pump assembly comprises an elongate member and the detection device comprises a first measurement means adapted to measure the extent of rotation of the elongate member at a first point and the apparatus further comprises a second measurement means adapted to measure the extent of rotation of the elongate member at a second point and a comparison means adapted to compare the rotation measured by the first measurement means and the rotation measured by the second measurement means.
8. Apparatus as claimed in claim 7, wherein the elongate member is adapted to connect a rotatable device, which in use, is provided in a well, to a rotating device which in use, is provided at the top of or above the well.
9. Apparatus as claimed in claim 8, wherein the rotatable device is an artificial lift device.
10. Apparatus as claimed in claim 8 or claim 9, wherein the rotating device is a motor.
11. Apparatus as claimed in any one of claims 7 to 10, wherein each measurement means is connected to the comparison means and is adapted to transmit information thereto.
12. Apparatus as claimed in any one of claims 7 to 11, wherein each measurement means is adapted to sense each complete revolution of the elongate member.
13. Apparatus as claimed in any one of claims 7 to 12, wherein each measurement means counts the number of revolutions of the elongate member.
14. Apparatus as claimed in any one of claims 7 to 13, further comprising a control means connected to the elongate member, the control means being adapted to vary the speed of the elongate member in response to the torsion calculated by the comparison means.
15. Apparatus as claimed in any one of claims 7 to 13 comprising more than two measurement means
16. Apparatus as claimed in claim 15, comprising a third and fourth measurement means which co-operate with the first and second measurement means such that the apparatus is adapted to sense each half-revolution of the elongate member at the first and second points.
17. Apparatus as claimed in any one of claims 7 to 16, wherein the measurement means at the first point comprise at least one sensing device adapted to monitor at least one of the speed of rotation and the direction of rotation of the elongate member.
18. A method for determining the position of at least a portion of a pump assembly in a borehole, the method comprising:
providing a detection device within the borehole;
detecting a position of the portion of the pump assembly within the borehole, relaying the information on the position of the portion of the pump assembly within the borehole to a controller.
providing a detection device within the borehole;
detecting a position of the portion of the pump assembly within the borehole, relaying the information on the position of the portion of the pump assembly within the borehole to a controller.
19. A method as claimed in claim 18, used to determine the longitudinal displacement of the portion of the pump assembly.
20. A method as claimed in claim 19, wherein the longitudinal displacement of the portion of the pump assembly is adjusted in response to the detected longitudinal displacement of the portion of the pump assembly.
21. A method as claimed in any one of claims 18 to 20, wherein the portion of the pump assembly comprises an elongate member and the method comprises:
rotating at least a portion of the elongate member;
measuring the extent of rotation of the elongate member at a first point;
measuring the extent of rotation of the elongate member at a second point;
comparing the extent of rotation of the elongate member at the first and second points.
rotating at least a portion of the elongate member;
measuring the extent of rotation of the elongate member at a first point;
measuring the extent of rotation of the elongate member at a second point;
comparing the extent of rotation of the elongate member at the first and second points.
22. A method as claimed in claim 21, wherein the method is used to determine the torsion of an elongate member suspended within a well.
23. A method as claimed in claim 22, wherein the method is used to determine the torsion of a drive shaft extending from a motor to a pump within the well.
24. An apparatus for determining the position of at least a portion of a pump assembly within a well, the apparatus comprising:
a portion of a pump assembly;
a detection device adapted to detect the position of the portion of the pump assembly within the borehole, the detection device being connectable to a borehole; and a communication device adapted to relay information on the position of the portion of the pump assembly within the borehole to a controller.
a portion of a pump assembly;
a detection device adapted to detect the position of the portion of the pump assembly within the borehole, the detection device being connectable to a borehole; and a communication device adapted to relay information on the position of the portion of the pump assembly within the borehole to a controller.
25. Apparatus as claimed in claim 24, wherein the portion of the pump assembly comprises an elongate member and the detection device comprises a first measurement means adapted to measure the extent of rotation of the elongate member at a first point; the apparatus further comprising a second measurement means adapted to measure the extent of rotation of the elongate member at a second point; and a comparison means adapted to compare the rotation measured by the first measurement means and the rotation measured by the second measurement means.
26. Apparatus as claimed in claim 25, further comprising a motor and a rotatable device.
27. Apparatus as claimed in claim 25 or 26, wherein the first measurement means is provided above the well.
28. Apparatus as claimed in any one of claims 25 to 27, wherein the second measurement means is provided in the well.
29. Apparatus as claimed in any one of claims 25 to 28, wherein the first point is proximate to the motor and the second point is proximate to the rotatable device.
30. Apparatus as claimed in any one of claims 25 to 29, wherein each measurement means comprises a magnet and a magnet sensing device at least one being provided on the elongate member and the other being provided proximate to but not connected to the elongate member such that one is rotatable with respect to the other.
31. Apparatus as claimed in claim 30, wherein the magnet is provided on the elongate member and the magnetic sensing means is provided proximate to but not connected to the elongate member.
32. Apparatus as claimed in any one of claims 25 to 31, further comprising production tubing and wherein the magnetic sensing means of the second measurement means is provided on the production tubing.
33. Apparatus as claimed in any one of claims 25 to 32, wherein the comparison means is provided at the surface.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GB0404458.2 | 2004-03-01 | ||
| GBGB0404458.2A GB0404458D0 (en) | 2004-03-01 | 2004-03-01 | Apparatus & method |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2498984A1 true CA2498984A1 (en) | 2005-09-01 |
| CA2498984C CA2498984C (en) | 2015-04-28 |
Family
ID=32051042
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2498984 Expired - Fee Related CA2498984C (en) | 2004-03-01 | 2005-03-01 | Apparatus and method for determining the position of an elongate member of a pump assembly |
Country Status (3)
| Country | Link |
|---|---|
| US (1) | US20060000605A1 (en) |
| CA (1) | CA2498984C (en) |
| GB (3) | GB0404458D0 (en) |
Families Citing this family (10)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US7347261B2 (en) * | 2005-09-08 | 2008-03-25 | Schlumberger Technology Corporation | Magnetic locator systems and methods of use at a well site |
| GB2450157B (en) * | 2007-06-15 | 2011-12-21 | Baker Hughes Inc | System for determining an initial direction of rotation of an electrical submersible pump |
| US8336632B2 (en) * | 2009-09-02 | 2012-12-25 | Harrier Technologies, Inc. | System and method for direct drive pump |
| PE20110174A1 (en) * | 2009-08-12 | 2011-04-15 | Harrier Technologies Inc | SYSTEM AND METHOD FOR A DIRECT DRIVE PUMP |
| US9470075B2 (en) | 2009-09-02 | 2016-10-18 | Harrier Technologies, Inc. | System and method for direct drive pump |
| US8322428B2 (en) * | 2009-10-09 | 2012-12-04 | Vetco Gray Inc. | Casing hanger nesting indicator |
| US9140113B2 (en) | 2012-01-12 | 2015-09-22 | Weatherford Technology Holdings, Llc | Instrumented rod rotator |
| US9212544B2 (en) | 2012-02-08 | 2015-12-15 | Ormat Technologies Inc. | Apparatus and method for preventing damage to a downhole pump impeller |
| CA2936219C (en) | 2016-07-15 | 2020-12-15 | Geo Pressure Systems Inc. | Progressive cavity pump (pcp) monitoring system and method |
| US10648246B2 (en) | 2018-07-13 | 2020-05-12 | Norris Rods, Inc. | Gear rod rotator systems |
Family Cites Families (18)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US2340609A (en) * | 1940-08-03 | 1944-02-01 | Kobe Inc | Apparatus for determining displacements |
| US3843923A (en) * | 1973-07-05 | 1974-10-22 | Stewart & Stevenson Inc Jim | Well pipe joint locator using a ring magnet and two sets of hall detectors surrounding the pipe |
| US4206810A (en) * | 1978-06-20 | 1980-06-10 | Halliburton Company | Method and apparatus for indicating the downhole arrival of a well tool |
| US4176436A (en) * | 1978-09-12 | 1979-12-04 | Baker International Corporation | Method and apparatus for counting turns when making threaded joints |
| CA1306618C (en) * | 1987-03-25 | 1992-08-25 | Normand Guay | Torquemeter |
| US4965774A (en) * | 1989-07-26 | 1990-10-23 | Atlantic Richfield Company | Method and system for vertical seismic profiling by measuring drilling vibrations |
| TW227601B (en) * | 1993-01-25 | 1994-08-01 | Gen Electric | |
| US5323856A (en) * | 1993-03-31 | 1994-06-28 | Halliburton Company | Detecting system and method for oil or gas well |
| GB9419031D0 (en) * | 1994-09-21 | 1994-11-09 | Sensor Dynamics Ltd | Apparatus for sensor location |
| JPH0915067A (en) * | 1995-06-29 | 1997-01-17 | Kubota Corp | Torque meter for pump |
| US5666050A (en) * | 1995-11-20 | 1997-09-09 | Pes, Inc. | Downhole magnetic position sensor |
| US5823261A (en) * | 1996-09-25 | 1998-10-20 | Sandia Corporation | Well-pump alignment system |
| US5941305A (en) * | 1998-01-29 | 1999-08-24 | Patton Enterprises, Inc. | Real-time pump optimization system |
| AU2001235767A1 (en) * | 2000-02-22 | 2001-09-03 | Weatherford/Lamb Inc. | Artificial lift apparatus with automated monitoring characteristics |
| DE20008413U1 (en) * | 2000-05-11 | 2001-09-13 | Cameron Gmbh | Measuring device |
| US6478087B2 (en) * | 2001-03-01 | 2002-11-12 | Cooper Cameron Corporation | Apparatus and method for sensing the profile and position of a well component in a well bore |
| US6585041B2 (en) * | 2001-07-23 | 2003-07-01 | Baker Hughes Incorporated | Virtual sensors to provide expanded downhole instrumentation for electrical submersible pumps (ESPs) |
| US7168924B2 (en) * | 2002-09-27 | 2007-01-30 | Unico, Inc. | Rod pump control system including parameter estimator |
-
2004
- 2004-03-01 GB GBGB0404458.2A patent/GB0404458D0/en not_active Ceased
-
2005
- 2005-03-01 CA CA 2498984 patent/CA2498984C/en not_active Expired - Fee Related
- 2005-03-01 US US11/069,247 patent/US20060000605A1/en not_active Abandoned
- 2005-03-01 GB GB0504159A patent/GB2411673C/en not_active Expired - Fee Related
- 2005-03-01 GB GB0716851A patent/GB2439476B/en not_active Expired - Fee Related
Also Published As
| Publication number | Publication date |
|---|---|
| GB0404458D0 (en) | 2004-03-31 |
| GB2439476B (en) | 2008-05-07 |
| GB2439476A (en) | 2007-12-27 |
| GB0716851D0 (en) | 2007-10-10 |
| GB2411673C (en) | 2010-01-04 |
| GB2411673A (en) | 2005-09-07 |
| GB2411673B (en) | 2007-12-05 |
| GB0504159D0 (en) | 2005-04-06 |
| CA2498984C (en) | 2015-04-28 |
| US20060000605A1 (en) | 2006-01-05 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKLA | Lapsed |
Effective date: 20220301 |