EP2464820B1 - System for a direct drive pump - Google Patents
System for a direct drive pump Download PDFInfo
- Publication number
- EP2464820B1 EP2464820B1 EP10808786.7A EP10808786A EP2464820B1 EP 2464820 B1 EP2464820 B1 EP 2464820B1 EP 10808786 A EP10808786 A EP 10808786A EP 2464820 B1 EP2464820 B1 EP 2464820B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- drive
- pump
- production tubing
- drive tube
- tube
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Not-in-force
Links
- 238000004519 manufacturing process Methods 0.000 claims description 66
- 239000012530 fluid Substances 0.000 claims description 33
- 239000003381 stabilizer Substances 0.000 claims description 32
- 239000003921 oil Substances 0.000 description 46
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 29
- 239000000919 ceramic Substances 0.000 description 15
- 229920000642 polymer Polymers 0.000 description 12
- 239000007788 liquid Substances 0.000 description 11
- 238000009434 installation Methods 0.000 description 10
- 239000000314 lubricant Substances 0.000 description 9
- 230000008878 coupling Effects 0.000 description 8
- 238000010168 coupling process Methods 0.000 description 8
- 238000005859 coupling reaction Methods 0.000 description 8
- 238000000034 method Methods 0.000 description 7
- 239000004033 plastic Substances 0.000 description 7
- 229920003023 plastic Polymers 0.000 description 7
- 238000005461 lubrication Methods 0.000 description 6
- 238000012423 maintenance Methods 0.000 description 6
- 238000005086 pumping Methods 0.000 description 6
- 229910045601 alloy Inorganic materials 0.000 description 5
- 239000000956 alloy Substances 0.000 description 5
- 230000014759 maintenance of location Effects 0.000 description 5
- 238000001816 cooling Methods 0.000 description 4
- 229920001971 elastomer Polymers 0.000 description 4
- 230000002706 hydrostatic effect Effects 0.000 description 4
- 239000010687 lubricating oil Substances 0.000 description 4
- 229910000906 Bronze Inorganic materials 0.000 description 3
- 238000009825 accumulation Methods 0.000 description 3
- 230000035508 accumulation Effects 0.000 description 3
- 230000000712 assembly Effects 0.000 description 3
- 238000000429 assembly Methods 0.000 description 3
- 239000010974 bronze Substances 0.000 description 3
- KUNSUQLRTQLHQQ-UHFFFAOYSA-N copper tin Chemical compound [Cu].[Sn] KUNSUQLRTQLHQQ-UHFFFAOYSA-N 0.000 description 3
- 238000005260 corrosion Methods 0.000 description 3
- 230000007797 corrosion Effects 0.000 description 3
- 230000008021 deposition Effects 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 239000003129 oil well Substances 0.000 description 3
- 238000013022 venting Methods 0.000 description 3
- 229910000831 Steel Inorganic materials 0.000 description 2
- 230000005540 biological transmission Effects 0.000 description 2
- 238000009826 distribution Methods 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000010926 purge Methods 0.000 description 2
- 238000007789 sealing Methods 0.000 description 2
- 230000003068 static effect Effects 0.000 description 2
- 239000010959 steel Substances 0.000 description 2
- XQCFHQBGMWUEMY-ZPUQHVIOSA-N Nitrovin Chemical compound C=1C=C([N+]([O-])=O)OC=1\C=C\C(=NNC(=N)N)\C=C\C1=CC=C([N+]([O-])=O)O1 XQCFHQBGMWUEMY-ZPUQHVIOSA-N 0.000 description 1
- 239000004677 Nylon Substances 0.000 description 1
- 238000005452 bending Methods 0.000 description 1
- 230000015572 biosynthetic process Effects 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 229910003460 diamond Inorganic materials 0.000 description 1
- 239000010432 diamond Substances 0.000 description 1
- 230000003292 diminished effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 239000000806 elastomer Substances 0.000 description 1
- 239000012717 electrostatic precipitator Substances 0.000 description 1
- 230000002262 irrigation Effects 0.000 description 1
- 238000003973 irrigation Methods 0.000 description 1
- 230000001050 lubricating effect Effects 0.000 description 1
- 239000002991 molded plastic Substances 0.000 description 1
- 230000009972 noncorrosive effect Effects 0.000 description 1
- 229920001778 nylon Polymers 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000000750 progressive effect Effects 0.000 description 1
- 230000000135 prohibitive effect Effects 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 230000002829 reductive effect Effects 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 239000010935 stainless steel Substances 0.000 description 1
- 229910001220 stainless steel Inorganic materials 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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 OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
- E21B17/1071—Wear protectors; Centralising devices, e.g. stabilisers specially adapted for pump rods, e.g. sucker rods
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D13/00—Pumping installations or systems
- F04D13/02—Units comprising pumps and their driving means
- F04D13/06—Units comprising pumps and their driving means the pump being electrically driven
- F04D13/08—Units comprising pumps and their driving means the pump being electrically driven for submerged use
- F04D13/10—Units comprising pumps and their driving means the pump being electrically driven for submerged use adapted for use in mining bore holes
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D29/00—Details, component parts, or accessories
- F04D29/60—Mounting; Assembling; Disassembling
- F04D29/62—Mounting; Assembling; Disassembling of radial or helico-centrifugal pumps
- F04D29/628—Mounting; Assembling; Disassembling of radial or helico-centrifugal pumps especially adapted for liquid pumps
Definitions
- the present invention relates to a system and method for a direct drive pump to be used for moving liquids and/or quasi-liquids.
- the present invention also relates to a system and method for the installation of a direct drive pump, for example, for high volume lifts from deep wells.
- ESPs electrical submersible pumps
- GSPs geared centrifugal pumps
- Such pumps are the current, principal methods used as artificial lifts in high rate oil wells, where a multi-stage centrifugal pump is located downhole.
- a downhole electrical motor directly drives the pump, with electric power supplied to the motor via a cable extending from the surface to the motor's location downhole.
- the pump is driven via a rotating rod string extending from the surface to a speed increasing transmission system located downhole.
- the speed increasing transmission system is used to increase the relatively slow rotation of the rod string to a much faster rotation, as needed by the pump.
- the rod string is driven by a prime mover at the surface.
- the artificial lift system tends to be a bit burdensome.
- a 90 to 120 metre (300 to 400 foot) artificial pump is installed in 3 metre (10 foot) sections in assembly form.
- the entire section of the pump must be removed all at once before any maintenance can be made.
- Figs. 1A and 1B show example line shaft pumps.
- Fig. 1A shows a line shaft pump with water lubricated bearings.
- the drive shaft is running directly inside the production tubing, or column pipe. Unlike the example shown in Fig. 1B , this pump does not use an oil pipe. Instead, in Fig. 1A , the drive shaft is centered within the column pipe by water lubricated bearings and bearing retainers attached to the column pipe. Such bearings are typically made of rubber, due to use in water.
- the pump thrust, as well as the weight of the drive shaft itself, are carried by a thrust bearing located at the surface.
- Fig. 1B shows a line shaft pump with an oil pipe and oil lubricated bearings.
- an oil lubricated drive shaft rotates inside the oil pipe, or oil filled tubular housing.
- the drive shaft is supported by shaft bearings, e.g., bronze bushings, attached fixedly to the oil pipe.
- the bushings are spaced, e.g., 1.5 metre to 3 metre (5 feet to 10 feet), on the oil pipe and along the drive shaft depending upon the intended rotational speed of the drive shaft.
- the steel pump shaft forms the journals for the bronze bushings.
- the pump thrust, as well as the weight of the drive shaft itself, are carried by a thrust bearing at the surface. Accordingly, the oil pipe can be centered within the column pipe by elastomer centralizers spaced evenly along its length as shown in Fig. 1B .
- the pump systems can be installed in similar fashion. For example, if the bearing spacing is deemed to be 3 metres (10 feet), then all of the components including the column pipe, oil pipe, and drive shaft, are in 3 metre (10 foot) length segments. Thus, as the pump is lowered into a well, each of the 3 metre (10 foot) segments of the drive shaft, bearings and column or oil pipe, must be installed in 3 metre (10 foot) segments.
- Embodiments of the present invention provide for a relatively easy to install and maintain artificial lift pump for use in oil and water pump systems. More specifically, embodiments of the present invention may be used for deep well pumping of oil, water, or other fluid / quasi-fluid.
- Embodiments of the present invention provide for a deep well pump system which can be utilized at a greater depth and/or with a greater rotational speed than current pump systems allow.
- water wells tend to be relatively large in diameter, e.g., 25 centimetres (10 inches) to more than 41 centimetres (16 inches).
- available agricultural centrifugal pumps used in water wells require large diameter pump rotor which produce a large increase in pressure per stage. That is, pressure per stage is proportional to the square of the rotor diameter, and the square of the rotational speed.
- water well turbine pumps typically are operated at speeds between about 1200 RPM and 1800 RPM.
- oil wells tend to use an about 14 centimetres (5.5 inch) or 18 centimetres (7 inch) production casing having an inside diameter of about 12 centimetres (4.6 inches) to 15 centimetres (6 inches). Accordingly, available centrifugal pumps require a small diameter pump rotor, providing a small pressure increase per stage. This small pressure increase per stage results in the pump having to be operated at a high speed, e.g., about 3500 RPM. Even at such high speed, due to the small pressure increase per stage and the typically deep depth of oil wells, there can be as many as 250 or more stages required to bring the produced fluid to the surface or other desired location.
- Embodiments of the present invention provide for a pump installation in which larger sections of the pump may be installed than current pump systems allow.
- the drive shaft is stabilized by bearings that are fixed to either the tubular drive shaft housing, i.e., the oil pipe, or the column pipe.
- Each of these segments are made to be all the same length so that the bearings can be fixed to the column pipe or oil pipe at the junction of the segments of pipe as the pump is being installed into the well.
- bronze bushings are attached to the oil pipes, with a steel drive shaft forming the journal.
- the rubber bearing is held in the center of the column pipe by the bearing retainers.
- the drive shaft runs through the rubber bearing and is fitted with a stainless steel sleeve serving as journal.
- the bearing is affixed to the column pipe or oil pipe, respectively. Accordingly, as discussed above, the installation of such available systems require assembly of each 3 metres (10 feet) of pump system segments.
- Embodiments of the present invention provide for installations of larger pump system segments, e.g., 7.6 metre (25 foot) sections, 18 metre (60 foot) sections, and more.
- Embodiments of the present invention provide for a high volume artificial lift system, i.e., a direct drive pump ("DDP"), in which a multi-stage downhole centrifugal pump is driven by a rod string extending from the surface to the downhole pump.
- the rod string is driven at the surface, e.g., ground level, by a prime mover, e.g., an electric motor.
- the motor may drive the rod string at a 3500 RPM pump operational speed. This speed can be decreased or increased, depending upon the situation needed, in embodiments of the present invention.
- Embodiments of the present invention provide for closely spaced bearings to provide rotational stability of the drive string.
- a plurality of stabilizers and/or bearings are attached to a drive string rod and serve as support for the drive string rod to ensure stable rotation during operation of the pump.
- the individual bearings are attached to the drive string, and are not fixed to the production casing or drive tube.
- Fig. 2 shows an embodiment of a direct drive pumping system 220 according to the present invention.
- a motor 200 is shown connected to the remaining elements of the pump via tubing hangers and at least one thrust bearing 201.
- the motor 200 is an electric motor which drives the rod string at full pump speed.
- the motor 200 is a direct drive motor, e.g., turning at 3500 RPM.
- the motor 200 has a low output RPM, i.e., lower than 3500 RPM, but with speed increasing capability gearing.
- the pressure of the pump system is monitored by a pressure regulator 202 situated between the pump and the flow line 203 to the pump.
- the pressure regulator 202 opens when the pressure differential between the drive tube and the production tubing exceeds a predetermined, set value.
- a wellhead 204 couples the well casing to the upper portion of the pump system which includes the motor 200 and the flow line pipe 203. Inside the protective well casing 205, a production tubing or pipe 207 is situated and houses a drive rod string 206.
- the lower portion of the pump system includes a receiver and thrust bearing(s) 208.
- the thrust bearing 208 carrying the weight of the drive rods is located in the surface drive head. Due to the high rotational speed, the rod string 206 is equipped with stabilizers or bearings closely spaced along the entire length of the rod string to assure stable rotation. Some example embodiments of such stabilizers are shown herein.
- Perforations 209 in the well casing in the pay zone 212 area i.e., where the water or oil or other liquid/quasi-liquid is located, allow for entry of the liquid or quasi-liquid into the well casing for pumping via the pump 210 having a pump inlet 211, up to the surface or other desired location.
- Fig. 3 shows an embodiment of a drive rod 304 having a drive tube 301 according to an embodiment of the present invention.
- the drive rod string 304 and stabilizers 305 rotate within a small diameter tubular housing called a drive tube 301.
- the drive tube 301 runs inside the production tubing 302.
- drive tube stabilizers 303 are spaced between the production tubing 302 and the drive tube 301.
- the drive rod string 304 is supported by drive rod stabilizers 305 to the drive tube 301.
- Fig. 4 shows an embodiment of a drive rod string 402 being encased directly in production tubing 401.
- the drive rod string 402 is supported by drive rod stabilizers 403 to the production tubing 401.
- Such an embodiment may be used in the situation of a relatively small diameter production tubing, where there is insufficient and/or no need for a drive tube.
- Figs. 5, 6, and 7 show embodiments of bearing assemblies or stabilizers for a direct drive pump embodiment which does not utilize a drive tube according to the present invention.
- the bearing assembly includes a bushing attached to a rod body, with a bearing mounted in a housing, e.g., a plastic or other type housing, that closely fits the internal diameter of the production tubing. The housing, and thus, the bearing, remain fixed relative to the tubing with the rod string rotating within the bearing.
- Fig. 5 shows a ceramic-polymer alloy bearing example embodiment.
- a polymer housing and bearing 500 are situated near a ceramic bushing 501, the ceramic bushing 501 being situated on the drive rod 502.
- Fig. 5A a polymer housing and bearing 500 are situated near a ceramic bushing 501, the ceramic bushing 501 being situated on the drive rod 502.
- FIG. 5B a front view of the assembly is shown in which inside the production tubing 503, a retention band 504 is used to hold the housing 500 which surrounds a portion of the drive rod 502.
- Fig. 6 shows a non-corrosive bearing example embodiment.
- a polymer housing and bearing 600 are situated near a molded stop 601, e.g., a molded plastic stop, the molded stop 601 being situated on the drive rod 602.
- Fig. 6B the polymer housing and bearing 600 surrounding the drive rod 602 are shown.
- a resulting flow area is available outside of the polymer housing 600.
- Fig. 6C a front view of the assembly is shown in which inside the production tubing 603, a retention band 604 is used to hold the housing 600 which surrounds a portion of the drive rod 602.
- Fig. 7 shows a ceramic bearing example embodiment.
- a plastic housing and bearing 700 are situated near a ceramic bushing 701, the ceramic bushing 701 being situated on the drive rod 702.
- Fig. 7B the plastic housing and bearing 700 surrounding the ceramic bushing 701 are shown.
- a resulting flow area is available outside of the plastic housing 700.
- Fig. 7C a front view of the assembly is shown in which inside the production tubing 703, a retention band 704 is used to hold the housing 700 which surrounds a portion of the drive rod 702.
- the bearing material to be used depends upon the wear and lateral load expected at the bearing's location within the well. For example, where high lateral loading is expected due to bore hole deviations, ceramic or even carbide bearings can be used. Or, for example, where not much side loading is expected, simpler and less expensive polymer alloy bearings can be used.
- the bearing housing material can be plastic, nylon, polymer alloy, or some other strong, chemically inert material.
- various types of bearings can be used. Determining which bearing type to use can depend upon the expected load, depth of the pump, use of a drive tube, and other considerations.
- the bearings differ in the provision for fluid flow around the bearing housing. For example, when a drive tube is not used, the bearings are exposed to the production fluid flow, thus the area open to flow between the bearing housing and the inside of the production tubing should be maximized to reduce pressure losses as the fluid flows past the bearings. See, e.g., Figs. 5 to 7 .
- the fluid in the tube is virtually stagnant, and the bearing housings need only be fluted enough to allow for a low rate flow communication throughout the drive string. See, e.g., Figs. 8 and 9 .
- Figs. 8 and 9 show embodiments of bearing assemblies or stabilizers for a direct drive pump embodiment having a drive tube according to the present invention.
- the bearing assembly includes a bushing attached to a rod body, with a bearing mounted in a housing, e.g., a plastic or other type housing, that closely fits the internal diameter of the drive tube housing.
- the housing, and thus, the bearing are situated to remain fixed relative to the drive tube housing with the rod string rotating within the bearing.
- Fig. 8 shows a ceramic-polymer alloy bearing example embodiment.
- a polymer housing and bearing 800 are situated near a ceramic bushing 801, the ceramic bushing 801 being situated on the drive rod 802.
- a drive tube 805 surrounds this assembly.
- the production tubing 803 surrounds the drive tube 805 which surrounds the bearing assembly.
- a front view of the assembly is shown in which within the drive tube 805, a retention band 804 is used to hold the housing 800 which surrounds a portion of the drive rod 802.
- Fig. 9 shows a ceramic bearing example embodiment.
- a plastic housing and bearing 900 are situated near a ceramic bushing 901, the ceramic bushing or bearing 901 being situated on the drive rod 902.
- a drive tube 905 surrounds this bearing assembly.
- the production tubing 903 is shown surrounding the drive tube 905 which surrounds the bearing assembly.
- a front view of the assembly is shown in which inside the drive tube 905, a retention band 904 is used to hold the housing 900 which surrounds a portion of the drive rod 902.
- the bearing assembly provides that the tubulars and the drive string can be run separately and sequentially, rather than simultaneously as done in currently available pump systems.
- the bearing assembly allows for individual segments of pipe and drive string to be much longer since the bearings are not attached to the tubulars' couplings.
- the couplings can be spaced much more widely, without having to adjust for the earlier necessary placement of bearings. Accordingly, this allows for relatively easier service and maintenance of the pump system.
- the tubing couplings are threaded, instead of having flange couplings, e.g., as shown in Figs. 1A and 1B , thus greatly improving seal integrity and speed of installation.
- mounting such bearing assemblies on a drive rod allows the bearings to be located optimally as required by the conditions in the well.
- such conditions may include rod tension and potential side loads in the well due to, e.g., borehole deviation.
- the rotational stability of a drive string is a function of rod tension. That is, the higher the tension, the more stably the rod will rotate. However, at the bottom of the hole, near the pump, the rod may have little tension. Thus, at this location of the pump in the well, the bearing spacing needs to be the closer in space in order to assure stable rotation. Likewise, proceeding up the hole toward the surface, the tension of the rod increases as the weight of the rod hanging below effectively is increased.
- an optimized drive rod string has bearings spaced according to the requirements dictated by the rod tension.
- a drive rod rotating within tubing with a small diameter may be forced to the side by deviations of the direction of the well, causing lateral loads on the bearings situated in and/or near the area of the deviation.
- the drive rod bearings are principally designed to keep the rod string rotating stably, and are normally expected to exposed to only small lateral loads.
- special bearings designed for side-load resistance can be installed in those areas where high lateral load is expected, e.g., the ceramic bearings as shown in Figs. 5 to 9 .
- the drive rod(s) can be removed without having to remove the other components.
- Such allows for relatively easy “tuning" or adjustment of the pump system for changing / changed operational conditions, or for normal maintenance. For example, if an operation condition such as pump speed is changed, the drive rod(s) can be replaced with other drive rod(s) having a more useful bearing type, configuration, and/or distribution. For example, if the pump speed is increased in order to increase liquid production, the drive rods can be easily replaced with one with a different distribution of bearings that is designed for the higher rotational speed. Likewise, if there is a failure in one or more of the drive rods, a replacement drive rod(s) can be quickly run downhole thus minimizing downtime.
- Embodiments of the present invention provide for pumping at greater depths.
- Presently available line shaft pump systems typically have a head capacity of less than 460 metres (1500 feet), and are run to depths of less than 300 metres (1000 feet).
- the relatively short length of the pipes and drive shaft results in a small amount of stretch by the components due to, e.g., water column weight and/or pump thrust, during operation.
- Such stretch allows the supporting thrust bearing for the drive shaft to be located at the surface. See, e.g., Figs. 1A and 1B , described above. This allows for small manual adjustments to the relative length of those components so that the pump impellers - which are fixedly attached both torsionally and axially to the drive shaft - turn freely.
- Fig. 10 an embodiment of the direct drive pump hole assembly having a drive tube according to the present invention is shown.
- the pump drive shaft thrust bearing can be placed immediately above or below the pump.
- the pump drive shaft and rotors are driven by the drive rod(s) 1000 via a spline coupling or spline rod connector 1005 that allows for significant relative vertical movement of production tubing and the drive rod(s) 1000 while allowing the pump drive shaft and rotors to remain axially fixed relative to the pump body.
- Fig. 2 See, e.g., Fig. 2 .
- the production tubing 1003 surrounds the drive tube 1001 which surrounds the drive rod 1000.
- Stabilizers 1002 are located on and spaced to support the drive rod 1000.
- Fig. 10 further shows the relationship and relative locations of a seal bore drive tube connection 1006, stab-in receiver 1007, stab-in receiver vent 1008, thrust bearing 1009, pump 1010, and pump intake 1011.
- Fig. 11 shows an embodiment of the present invention similar to that shown in Fig. 10 , except without a drive tube 1001.
- a spline coupling 1105 is still employed.
- a thrust bearing 1101 e.g., a polycrystalline diamond (PCD) thrust bearing, is shown situated below the pump and above the pump intake.
- PCD polycrystalline diamond
- Fig. 12 shows an embodiment of the present invention having a top vented drive tube.
- Fig. 12 shows an enlarged section of the pump system just below the wellhead 1201.
- a well casing 1208 surrounds the production tubing 1200, the production tubing 1200 surrounding the drive tube 1203.
- the drive tube 1203 is shown having vents 1202 in its upper area to allow for fluid flow.
- the drive rod stabilizers 1205 are located on and support the rod.
- fluid flow in the production tubing 1200, within the drive tube 1203, and from the drive tube 1203 moves upward toward the surface.
- various lubricants can be used for the bearings.
- a drive tube having a smaller diameter can be utilized to encase the drive rod.
- the drive tube may be centralized within the production tubing, and be used to essentially protect the drive rod from corrosion and scale deposition that might occur in the flow stream of a produced fluid.
- lubrication of the bearings must be chosen so as to not negatively affect other parts of the system, e.g., sealing between components, etc.
- oil is used as a lubricant.
- an oil lubricant can be useful at relatively shallow depths.
- a water lubricated drive shaft in an embodiment of the present invention provides the benefits of the oil lubricated system without the operation difficulties, lubricant costs, and/or pressure balancing issues.
- the water lubricated system involves the drive shaft turning within a small diameter drive tube, and equipped with closely spaced bearings to provide rotational stability, as discussed herein.
- the drive tube is not sealed off from the produced fluid.
- the produced fluid fills the drive tube and serves as the bearing lubricant.
- bearings designed for water lubrication can be used.
- Such bearings can designed using ceramic, carbide, or polymer alloy bearings, depending upon the load and wear requirements, as discussed herein.
- the drive tube is vented to the production flow line at the surface to expel oil or gas that collects in the tub, and to allow the rate of flow up the drive tube to be controlled.
- the drive tube is vented into the production tubing below the wellhead, allowing produced fluid to flow continuously up the drive tube. This can improve lubrication and/or improve the cooling of the bearings.
- using a produced fluid filled drive tube can provide both cost and reliability benefits.
- the drive shaft seals at the pump assembly are not needed. Instead, a bushing, e.g., carbide, is used to center the shaft at the bottom of the drive tube.
- the drive tube is vented at the bottom to allow the free movement of produced fluid into the drive tube, assuring that the drive shaft bearings are always immersed in fluid.
- the production line vented option can be used, as the flow rate up the drive tube could be closely controlled so that the fluid in the drive tube would be essentially stagnant.
- any potential for corrosion or scale formation on the drive string and/or bearings is greatly reduced.
- any remaining scale and corrosive components in the resulting stagnant column of water would have minimal effect given the lack of continuous movement.
- the drive tube is open to the pump outlet, thus, when it is completely filled with liquid, the pressure in the tube at the surface will be equal to the pump outlet pressure less the hydrostatic pressure exerted by a static liquid column.
- the pressure at the production tubing outlet at the surface will be equal to the pump outlet pressure less the hydrostatic pressure exerted by a static liquid column less the frictional pressure drop due to fluid flow in the production tubing.
- the pressure at the top of the drive tube will be greater than the surface production tubing pressure, the difference being the pressure drop due to flowing friction. This difference can be used to purge the gas that will naturally accumulate at the top of the drive tube.
- a drive tube can be fitted with vent line to the production tubing outlet, and the line can be equipped with a pressure regulator that opens when the pressure differential between the drive tube and the production tubing exceeds a set value.
- the pressure setting for the pressure regulator may need to be set after taking into account a higher than the expected friction loss pressure drop, so that the valve opens only after such accumulations occur.
- the pressure-regulated valve can be set to open periodically to vent some of the oil and gas from the tube, keeping a constant amount of water in the drive tube so that the bearings are always lubricated.
- the drive tube-venting embodiment can be used.
- the drive tube is vented at the bottom, but there is an additional drive tube vent into the production tubing just below the wellhead as shown in Fig. 12 .
- This differential can be used to force a low rate fluid to flow up the drive tube and out the top vent, resulting in a continual circulation of produced fluid up the drive tube, lubricating and cooling the bearings. Any oil and/or gas entering the drive tube would also pass through the top vent, eliminating the chance of gas accumulation causing lack of adequate lubricant, as described above.
- an effective cooling and lubrication of the stabilizer bearings is provided by the constant flow of water. See, e.g., Fig. 12 .
- Such cooling and lubrication may be critical in deviated well situations, since the stabilizer bearings experience heavier side loads due to the bending of the drive string.
- the production line venting also can provide continuous flow of produced fluid up the drive tube to both cool the bearings situated in that area. Further the production line venting can provide for continuous purging of any oil and/or gas that accumulates in the drive tube by merely opening a control valve to allow the desired amount of liquid to continuously flow up the drive tube and into the production flowline.
- Embodiments of the present invention facilitate easier installation of a well pump.
- Fig. 13 shows an example method for installing a direct drive pump, the direct drive pump having a drive tube and a drive rod such as the embodiments illustrated in Figs. 2 and 7 .
- a pump assembly is installed in a well using a well service rig.
- the well service rig has a derrick, draw works, and accessory equipment that allows the running in and pulling out of tubulars and other equipment for use in a well.
- the bottom hole assembly including a multi-stage pump, thrust bearing, and drive rod and drive tube receiver, is attached via a connection, e.g., a threaded connection, to a length of production tubing 1301.
- the length of production tubing typically includes two joints of tubing, each 9 metres (30 feet) in length, and connected together via, e.g., a threaded connection, thus forming a stand of tubing that is about 18 metres (60 feet) long.
- the pump assembly and single stand of tubing are lowered into the well 1302 via the well service rig for about 18 metres (60 feet), and the tubing is secured in the wellhead 1303.
- Another 18 metre (60 foot) stand of tubing is attached 1304, via, e.g., a threaded connection, to the stand that is secured in the wellhead and which is attached to the bottom hole assembly.
- the entire assembly is lowered 1305 a further 18 metres (60 feet) and another stand is attached to the production tubing.
- the drive tube which consists of 18 metre (60 foot) stands (two 9 metre (30 foot) joints joined via a threaded connection) of smaller diameter tubing is inserted into the production tubing 1307, and run to bottom in a similar fashion as the production tubing and bottom hole assembly was run and secured in the wellhead 1308.
- the drive string tube is equipped with centralizers to locate it concentrically inside the production tubing See, e.g., Figs. 2 , 3 .
- the drive string is also equipped with a close fitting male stab-in member at the bottom, which fits into the drive tube seal bore receiver in the bottom hole assembly.
- This seal bore assembly locates the drive tube so that it is centered around the drive rod receiver within the bottom hole assembly (see, e.g., Fig. 10 ), while also allowing relative vertical movement between the drive tube and bottom hole assembly.
- the drive rods with stabilizers, in 15 to 23 metre (50 to 75 foot) stands, are then run inside of the drive tube, in a manner similar to how the drive tube was run 1309.
- the drive rods are typically 7.6 metres or 9 metres (25 feet or 30 feet) in length, and are attached to one another via threaded connections.
- the drive rod string is run to bottom and the splined rod connector is stabbed into the drive rod stab-in receiver in the bottom hole assembly. See, e.g., Fig. 10 .
- This splined connection allows the rod to rotationally drive the centrifugal pump but provide for relative vertical movement between the drive rods and the bottom hole assembly.
- the direct drive pump which does not use a drive tube is installed in the same manner. The difference being that no drive tube is installed in the direct drive pump. Instead, the drive rod string is run directly after the bottom hole assembly and production tubing string are run to the proper depth and secured in the well head. The drive head is then installed such that the drive rod can be turned by the electric motor (see, e.g., Fig.2 ), thus driving the multi-stage centrifugal pump in the bottom hole assembly 1310.
- the surface flow line is attached to the well head 1311 and the pump is ready for operation. The surface flow line can then be used to transport well fluids lifted by the pump to any desired location, e.g., nearby storage container, etc.
Landscapes
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Environmental & Geological Engineering (AREA)
- Physics & Mathematics (AREA)
- Fluid Mechanics (AREA)
- Mechanical Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- General Engineering & Computer Science (AREA)
- Structures Of Non-Positive Displacement Pumps (AREA)
- Jet Pumps And Other Pumps (AREA)
- Pressure Vessels And Lids Thereof (AREA)
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US23348809P | 2009-08-12 | 2009-08-12 | |
US23382609P | 2009-08-13 | 2009-08-13 | |
US12/552,806 US8336632B2 (en) | 2009-09-02 | 2009-09-02 | System and method for direct drive pump |
PCT/US2010/045377 WO2011019958A2 (en) | 2009-08-12 | 2010-08-12 | System and method for a direct drive pump |
Publications (3)
Publication Number | Publication Date |
---|---|
EP2464820A2 EP2464820A2 (en) | 2012-06-20 |
EP2464820A4 EP2464820A4 (en) | 2015-11-04 |
EP2464820B1 true EP2464820B1 (en) | 2017-09-27 |
Family
ID=43586850
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP10808786.7A Not-in-force EP2464820B1 (en) | 2009-08-12 | 2010-08-12 | System for a direct drive pump |
Country Status (10)
Country | Link |
---|---|
EP (1) | EP2464820B1 (es) |
CN (1) | CN102741498B (es) |
AR (1) | AR079097A1 (es) |
AU (1) | AU2010282441B2 (es) |
BR (1) | BR112012003240A2 (es) |
CA (1) | CA2770853C (es) |
MX (1) | MX2012001735A (es) |
PE (1) | PE20110174A1 (es) |
RU (1) | RU2554380C2 (es) |
WO (1) | WO2011019958A2 (es) |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US11982286B2 (en) | 2021-04-20 | 2024-05-14 | Ormat Technologies, Inc. | Well pumping apparatus and methods |
Families Citing this family (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10151341B2 (en) * | 2015-08-27 | 2018-12-11 | General Electric Company | Load-limiting thrust bearing system and an associated method thereof |
DE102018104015A1 (de) * | 2018-02-22 | 2019-08-22 | Nidec Gpm Gmbh | Kühlmittelpumpe mit optimierter Lageranordnung und verbessertem Wärmehaushalt |
CN112940866B (zh) * | 2021-02-19 | 2023-06-16 | 广州三井化妆品有限公司 | 一种用于植物精油提取的油水分离装置 |
Family Cites Families (14)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US1746889A (en) * | 1926-11-06 | 1930-02-11 | Louis A Fitzer | Rotary pump |
US1647386A (en) * | 1927-06-01 | 1927-11-01 | Pacific Pump Works | Deep-well column joint |
US2171171A (en) * | 1938-06-09 | 1939-08-29 | Brauer Walter | Well pump |
US4448551A (en) * | 1978-04-19 | 1984-05-15 | Murphy Reuel A | Method and apparatus for shaft support for turbine pumps |
US5069284A (en) * | 1990-11-14 | 1991-12-03 | Joe C. McQueen, Jr. | Wear resistant rod guide |
US5309998A (en) * | 1992-11-19 | 1994-05-10 | Intevep, S.A. | Pumping system including flow directing shoe |
US5960886A (en) * | 1997-01-30 | 1999-10-05 | Weatherford International, Inc. | Deep well pumping apparatus |
US6796390B1 (en) * | 1999-09-21 | 2004-09-28 | Shell Oil Company | Method and device for moving a tube in a borehole in the ground |
US6454010B1 (en) * | 2000-06-01 | 2002-09-24 | Pan Canadian Petroleum Limited | Well production apparatus and method |
US6523624B1 (en) * | 2001-01-10 | 2003-02-25 | James E. Cousins | Sectional drive system |
RU2237197C1 (ru) * | 2002-12-27 | 2004-09-27 | Общество с ограниченной ответственностью "Поиск" | Скважинная насосная установка |
US6830108B2 (en) * | 2003-05-01 | 2004-12-14 | Delaware Capital Formation, Inc. | Plunger enhanced chamber lift for well installations |
GB0404458D0 (en) * | 2004-03-01 | 2004-03-31 | Zenith Oilfield Technology Ltd | Apparatus & method |
CA2605914C (en) * | 2005-04-25 | 2013-01-08 | Weatherford/Lamb, Inc. | Well treatment using a progressive cavity pump |
-
2010
- 2010-08-12 CA CA2770853A patent/CA2770853C/en not_active Expired - Fee Related
- 2010-08-12 PE PE2010000514A patent/PE20110174A1/es active IP Right Grant
- 2010-08-12 BR BR112012003240A patent/BR112012003240A2/pt not_active Application Discontinuation
- 2010-08-12 AR ARP100102959A patent/AR079097A1/es active IP Right Grant
- 2010-08-12 AU AU2010282441A patent/AU2010282441B2/en not_active Ceased
- 2010-08-12 CN CN201080034115.2A patent/CN102741498B/zh not_active Expired - Fee Related
- 2010-08-12 RU RU2012106458/06A patent/RU2554380C2/ru active
- 2010-08-12 WO PCT/US2010/045377 patent/WO2011019958A2/en active Application Filing
- 2010-08-12 MX MX2012001735A patent/MX2012001735A/es active IP Right Grant
- 2010-08-12 EP EP10808786.7A patent/EP2464820B1/en not_active Not-in-force
Non-Patent Citations (1)
Title |
---|
None * |
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US11982286B2 (en) | 2021-04-20 | 2024-05-14 | Ormat Technologies, Inc. | Well pumping apparatus and methods |
Also Published As
Publication number | Publication date |
---|---|
CN102741498A (zh) | 2012-10-17 |
RU2012106458A (ru) | 2013-08-27 |
BR112012003240A2 (pt) | 2017-03-21 |
WO2011019958A3 (en) | 2012-03-01 |
CA2770853A1 (en) | 2011-02-17 |
CN102741498B (zh) | 2016-05-04 |
EP2464820A2 (en) | 2012-06-20 |
AR079097A1 (es) | 2011-12-28 |
AU2010282441A1 (en) | 2012-02-09 |
CA2770853C (en) | 2017-12-12 |
WO2011019958A2 (en) | 2011-02-17 |
AU2010282441B2 (en) | 2016-06-02 |
MX2012001735A (es) | 2012-03-29 |
PE20110174A1 (es) | 2011-04-15 |
RU2554380C2 (ru) | 2015-06-27 |
EP2464820A4 (en) | 2015-11-04 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US8336632B2 (en) | System and method for direct drive pump | |
US9470075B2 (en) | System and method for direct drive pump | |
US9175554B1 (en) | Artificial lift fluid system | |
AU2019232819B2 (en) | Lubricating downhole-type rotating machines | |
US20230184036A1 (en) | Lubricating downhole-type rotating machines | |
US20120224985A1 (en) | Electric submersible pump floating ring bearing and method to assemble same | |
EP2464820B1 (en) | System for a direct drive pump | |
US20240133278A1 (en) | Downhole Lubrication System | |
US4669961A (en) | Thrust balancing device for a progressing cavity pump | |
CA2956837C (en) | Abrasion-resistant thrust ring for use with a downhole electrical submersible pump | |
CA2764929C (en) | Improved down hole delivery system | |
US5842521A (en) | Downhole pressure relief valve for well pump | |
AU2014201348B2 (en) | High-speed rod-driven downhole pump | |
WO2022159884A1 (en) | Lubricating downhole-type rotating machines | |
CA2285035A1 (en) | Dual tubing system for producing wells |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
PUAI | Public reference made under article 153(3) epc to a published international application that has entered the european phase |
Free format text: ORIGINAL CODE: 0009012 |
|
17P | Request for examination filed |
Effective date: 20120321 |
|
AK | Designated contracting states |
Kind code of ref document: A2 Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO SE SI SK SM TR |
|
DAX | Request for extension of the european patent (deleted) | ||
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R079 Ref document number: 602010045609 Country of ref document: DE Free format text: PREVIOUS MAIN CLASS: E21B0043000000 Ipc: E21B0043120000 |
|
A4 | Supplementary search report drawn up and despatched |
Effective date: 20151002 |
|
RIC1 | Information provided on ipc code assigned before grant |
Ipc: F04D 13/10 20060101ALI20150928BHEP Ipc: F04D 29/62 20060101ALI20150928BHEP Ipc: E21B 17/10 20060101ALI20150928BHEP Ipc: E21B 43/12 20060101AFI20150928BHEP |
|
17Q | First examination report despatched |
Effective date: 20161018 |
|
GRAP | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOSNIGR1 |
|
INTG | Intention to grant announced |
Effective date: 20170302 |
|
GRAS | Grant fee paid |
Free format text: ORIGINAL CODE: EPIDOSNIGR3 |
|
GRAA | (expected) grant |
Free format text: ORIGINAL CODE: 0009210 |
|
AK | Designated contracting states |
Kind code of ref document: B1 Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO SE SI SK SM TR |
|
REG | Reference to a national code |
Ref country code: GB Ref legal event code: FG4D |
|
REG | Reference to a national code |
Ref country code: CH Ref legal event code: EP |
|
REG | Reference to a national code |
Ref country code: AT Ref legal event code: REF Ref document number: 932154 Country of ref document: AT Kind code of ref document: T Effective date: 20171015 |
|
REG | Reference to a national code |
Ref country code: IE Ref legal event code: FG4D |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R096 Ref document number: 602010045609 Country of ref document: DE |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: NO Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20171227 Ref country code: SE Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: HR Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: FI Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: LT Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
REG | Reference to a national code |
Ref country code: NL Ref legal event code: MP Effective date: 20170927 |
|
REG | Reference to a national code |
Ref country code: LT Ref legal event code: MG4D |
|
REG | Reference to a national code |
Ref country code: AT Ref legal event code: MK05 Ref document number: 932154 Country of ref document: AT Kind code of ref document: T Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: BG Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20171227 Ref country code: GR Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20171228 Ref country code: LV Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: NL Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: RO Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: CZ Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: ES Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: SM Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: SK Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: IS Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20180127 Ref country code: AT Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: EE Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R097 Ref document number: 602010045609 Country of ref document: DE |
|
REG | Reference to a national code |
Ref country code: FR Ref legal event code: PLFP Year of fee payment: 9 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: DK Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PLBE | No opposition filed within time limit |
Free format text: ORIGINAL CODE: 0009261 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: PL Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
26N | No opposition filed |
Effective date: 20180628 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: SI Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: MC Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
REG | Reference to a national code |
Ref country code: CH Ref legal event code: PL |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: LU Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180812 Ref country code: LI Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180831 Ref country code: CH Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180831 |
|
REG | Reference to a national code |
Ref country code: BE Ref legal event code: MM Effective date: 20180831 |
|
REG | Reference to a national code |
Ref country code: IE Ref legal event code: MM4A |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: IE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180812 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: BE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180831 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: DE Payment date: 20190730 Year of fee payment: 10 Ref country code: FR Payment date: 20190815 Year of fee payment: 10 Ref country code: IT Payment date: 20190821 Year of fee payment: 10 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: GB Payment date: 20190808 Year of fee payment: 10 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: MT Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20180812 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: TR Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: PT Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: HU Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO Effective date: 20100812 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: CY Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 Ref country code: MK Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20170927 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: AL Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20170927 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R119 Ref document number: 602010045609 Country of ref document: DE |
|
GBPC | Gb: european patent ceased through non-payment of renewal fee |
Effective date: 20200812 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: DE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20210302 Ref country code: FR Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20200831 Ref country code: IT Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20200812 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: GB Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20200812 |