EP2920412B1 - Systèmes et méthodes de surveillance de fluides de puits de forage utilisant la microanalyse de données de pompage en temps réel - Google Patents
Systèmes et méthodes de surveillance de fluides de puits de forage utilisant la microanalyse de données de pompage en temps réel Download PDFInfo
- Publication number
- EP2920412B1 EP2920412B1 EP13703265.2A EP13703265A EP2920412B1 EP 2920412 B1 EP2920412 B1 EP 2920412B1 EP 13703265 A EP13703265 A EP 13703265A EP 2920412 B1 EP2920412 B1 EP 2920412B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- data
- wellbore
- fluid
- fluids
- sets
- 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
- 239000012530 fluid Substances 0.000 title claims description 199
- 238000000034 method Methods 0.000 title claims description 33
- 238000012544 monitoring process Methods 0.000 title claims description 6
- 238000005086 pumping Methods 0.000 title description 10
- 238000004452 microanalysis Methods 0.000 title 1
- 230000015572 biosynthetic process Effects 0.000 claims description 39
- 238000005259 measurement Methods 0.000 claims description 19
- 230000014759 maintenance of location Effects 0.000 claims description 13
- 238000004891 communication Methods 0.000 claims description 9
- 238000005755 formation reaction Methods 0.000 description 38
- 239000004568 cement Substances 0.000 description 25
- 238000005553 drilling Methods 0.000 description 25
- 230000008901 benefit Effects 0.000 description 9
- 239000000463 material Substances 0.000 description 9
- 230000006870 function Effects 0.000 description 6
- 229930195733 hydrocarbon Natural products 0.000 description 6
- 150000002430 hydrocarbons Chemical class 0.000 description 6
- 239000003129 oil well Substances 0.000 description 4
- 238000003860 storage Methods 0.000 description 4
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- 230000005534 acoustic noise Effects 0.000 description 3
- 230000002706 hydrostatic effect Effects 0.000 description 3
- 230000003287 optical effect Effects 0.000 description 3
- 230000000246 remedial effect Effects 0.000 description 3
- 238000011109 contamination Methods 0.000 description 2
- 238000005520 cutting process Methods 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- 238000011161 development Methods 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 238000012545 processing Methods 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- 229910000831 Steel Inorganic materials 0.000 description 1
- 230000002776 aggregation Effects 0.000 description 1
- 238000004220 aggregation Methods 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 230000004888 barrier function Effects 0.000 description 1
- 230000005540 biological transmission Effects 0.000 description 1
- 239000000969 carrier Substances 0.000 description 1
- 230000001413 cellular effect Effects 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 238000007796 conventional method Methods 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 238000001514 detection method Methods 0.000 description 1
- 238000009826 distribution Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000002708 enhancing effect Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 230000001050 lubricating effect Effects 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 239000002343 natural gas well Substances 0.000 description 1
- 239000013307 optical fiber Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000008439 repair process Effects 0.000 description 1
- 239000000523 sample Substances 0.000 description 1
- 238000007789 sealing Methods 0.000 description 1
- 230000007480 spreading Effects 0.000 description 1
- 238000003892 spreading Methods 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 238000004441 surface measurement Methods 0.000 description 1
- 238000011144 upstream manufacturing 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
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
-
- 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
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Definitions
- the present disclosure relates to subterranean operations and, more particularly, to an apparatus and methods for monitoring and characterizing fluids in a subterranean formation.
- drilling operations play an important role when developing hydrocarbon wells.
- a drill bit passes through various layers of earth strata as it descends to a desired depth.
- Drilling fluids are commonly employed during the drilling operations and perform several important functions including, but not limited to, removing the cuttings from the well to the surface, controlling formation pressures, sealing permeable formations, minimizing formation damage, and cooling and lubricating the drill bit.
- Maintaining fluid pressure in the wellbore is often critical to these and other subterranean operations in a wellbore.
- subterranean operations such as drilling or completing wells
- Fluids placed in a wellbore may migrate or flow into another portion of the subterranean formation other than their intended location, for example, in an area of the formation that is more porous or permeable.
- Fluid loss may result in, among other problems, incomplete or ineffective treatment of the formation, increased cost due to increased volumes of fluid to complete a treatment, and/or environmental contamination of the formation. While treatment fluids are often formulated and wells are often constructed so as to reduce the likelihood or amount of fluid loss into the formation, fluid loss still may occur, particularly in damaged or highly permeable areas of a subterranean formation or wellbore.
- Conventional methods of detecting fluid loss typically involve measuring the amount of fluid pumped into the wellbore and comparing that with the amount of fluid circulated out of the wellbore.
- such methods are usually only performed after the operation using the fluid has been completed, and do not provide enough information during the operation to make adjustments to attempt to compensate for the fluid loss or otherwise remedy whatever is causing the loss of fluid. This may require performing the same treatment or operation on the same wellbore multiple times until it can be performed without significant fluid loss.
- such methods typically are not capable of identifying the specific fluid that was lost into the formation, the identity of which may be important in order to compensate for the lost fluid and/or remedy or prevent additional problems (e.g., formation damage, environmental problems, etc.) that may result from the loss of particular fluids into the formation.
- well logging instruments may be used to probe subsurface formations to determine formation characteristics.
- Sonic tools are an example of well logging tools that may be used to provide information regarding subsurface acoustic properties that can be used to analyze the formation.
- an acoustic logging instrument or tool is lowered into a wellbore that transverses a formation of interest.
- the acoustic logging tool may be mounted to the drill collar or other devices and directed downhole.
- the receiver(s) of the acoustic logging tool are typically sensitive to undesired acoustic noise that may result from normal drilling operations.
- the undesired acoustic noise may radiate with reduced attenuation through a hard steel drill collar.
- the acoustic noise may then couple to the receiver of the acoustic logging tool and be converted into electrical noise along with the desired signal.
- This background noise may be a result of the downhole operations or produced by other acoustic sources and therefore may introduce an error in the measurements by the acoustic logging tool.
- traditional logging tools often involve complex downhole equipment and sensors which may be expensive to operate and maintain.
- US 2012/0016587 A1 discloses a method for enhancing resolution of distributed optical measurements along a wellbore by acquiring optical signals during an acquisition time period, thereby producing a convolved profile along the wellbore, and deconvolving the profile using a first function corresponding to the acquisition time period, thereby determining a second function.
- Couple or “couples” as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical or mechanical connection via other devices and connections.
- upstream as used herein means along a flow path towards the source of the flow
- downstream as used herein means along a flow path away from the source of the flow.
- uphole as used herein means along the drillstring or the hole from the distal end towards the surface
- downhole as used herein means along the drillstring or the hole from the surface towards the distal end.
- oil well drilling equipment or "oil well drilling system” is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well.
- the terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface. This could also include geothermal wells intended to provide a source of heat energy instead of hydrocarbons.
- an "information handling system” may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes.
- an information handling system may be a personal computer or tablet device, a cellular telephone, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price.
- the information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory.
- Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display.
- the information handling system may also include one or more buses operable to transmit communications between the various hardware components.
- Computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time.
- Computer-readable media may include, for example, without limitation, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.
- storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory
- the present disclosure generally relates to subterranean operations. More particularly, the present disclosure relates to continuous or substantially continuous monitoring of fluids in well casing and/or tubing, fluid distribution inside and around a well, and/or cement layer integrity around a well.
- the present disclosure may be used to calculate the position of fluids in any subterranean pumping operation. For example, the disclosure may be applied in primary cementing, stimulation, remedial, and/or drilling operations.
- a drilling platform 102 supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108.
- a kelly 110 supports the drill string 108 as it is lowered through a rotary table 112.
- a drill bit 114 is driven by a downhole motor and/or rotation of the drill string 108. As drill bit 114 rotates, it creates a wellbore 116 that passes through an earth formation 130.
- a pump 120 may circulate drilling fluid through a feed pipe 122 to kelly 110, downhole through the interior of drill string 108, through orifices in drill bit 114, back to the surface via the annulus between the drill string 108 and the wellbore wall, and into a retention pit 124.
- the drilling fluid may transport cuttings from the borehole into the retention pit 124 and aids in maintaining the borehole integrity.
- the drilling fluid may also serve to lubricate the drill bit.
- the volume of drilling fluid pumped into the wellbore 116 may be measured in advance off-site or at the rig location. Alternatively, the volume of drilling fluid pumped into the wellbore 116 may be measured by one or more fluid measurement devices as it is being pumped downhole.
- the retention pit 124 may contain one or more fluid measurement devices 136 and 138. Fluid measurement devices may be located on a conduit 140 leading into the retention pit 124 or on the retention pit 124 itself. Fluid measurement devices may include, but are not limited to, sensors and flow meters. Sensors may be acoustic, level height, or any type appropriate to determine the height of fluid within the retention pit 124. Sensors and other surface collection equipment may be calibrated to convert the height of fluid within the retention pit 124 to fluid volume.
- Flow meters may include acoustic sensors, nuclear sensors, coriolis meters, Doppler radar, vortex flow meters or sensors, calorimetric flow meters or sensors, magnetic flow meters or sensors, electromagnetic flow meters or sensors, differential pressure meters or sensors, open channel meters or sensors, or any appropriate flow meter without departing from the spirit of this disclosure.
- the density of a fluid may be captured by a flow meter that includes nuclear, sonic, or similar devices. Similar measurements for fluid pumped into the wellbore may be collected.
- a cross-sectional view of a wellbore 216 that has been drilled with casing 228 and tubing 226 in accordance with certain embodiments of the present disclosure is denoted generally with reference numeral 200.
- the casing 228 and tubing 226 may be concentric tubes inside the wellbore 216.
- An annulus 232 is formed between the casing 228 and the formation 230.
- Cement 218 is pumped down the wellbore 216, e.g., through the interior of the casing 228 and up through the annulus 232 in order to hold the casing 228 in place.
- the cement 218 may be directed downhole using a cement pumping unit (not shown) or other types of rig pumping equipment (not shown), as appropriate. This equipment may include fluid measurement devices to measure the amount of cement being pumped downhole. Alternatively, the volume of cement to be directed downhole may be pre-measured based on the volume of the annulus to be filled.
- a filling material 214 may be directed downhole. Filling material 214 may be used fill the space in between casing 228 and tubing 226.
- the filling material 214 may be a mud, for example, but is not intended to be limited to such.
- spacing fluids may be directed downhole.
- a spacing fluid (not shown) may be directed downhole before and/or after the cement 218 is pumped. Spacing fluid may act as a barrier between the cement 218 and the filling material 214 to prevent contamination of the two fluids.
- An operator may detect how much cement 218 returned to the annulus after being pumped downhole by measuring the amount of spacing fluid that was displaced from the annulus and returned to the retention pit 124. If spacing fluid is not used, any fluid directed downhole immediately prior to the cement 218 may serve this purpose.
- a data system 202 may be coupled to the pump 120 using a hard-wired, digital, or wireless connection.
- the data system 202 and the pump 120 may be coupled by any known means without departing from the spirit of this disclosure.
- the data system may be coupled to fluid measurement devices that are located within the retention pit 124. Fluid measurement devices may include, but are not limited to, sensors and flow meters.
- fluid measurement devices may be coupled to the pump 120, and the pump 120 may be coupled to the data system 202 as shown in Figure 2 .
- the data system 202 may be coupled to fluid measurement devices, which are operable to measure fluid pressure, density, and volume, and are mounted in piping systems located downstream from the pump 120.
- the data system 202 functions to receive information about various fluids in the wellbore, such as cement 218, filling material 214, or spacing fluid. It may receive information about the volume of a fluid that is directed into and pumped out of the wellbore 116 via the pump 120.
- the data system 202 may be communicatively coupled to an external communications interface (not shown).
- the external communications interface may permit the data from the data system 202 to be remotely accessible by any remote information handling system communicatively coupled to the external communications interface via, for example, a satellite, a modem or wireless connections.
- the external communications interface may include a router.
- a first set and a second set of data may be received at the data system 202 over a period of time in short intervals, or in real time.
- the short intervals may be periods of minutes or substantially continuously.
- the first set of data may relate to one or more fluids directed into the wellbore 116 via the pump 120
- the second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120.
- Data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations.
- the first and second sets of data both may be actual, or measured, data sets, rather than theoretical data sets.
- the first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time.
- the first and second sets of data may be compared using a time-track or by performing a regression.
- any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
- a first set of data may be modeled based on a model wellbore that may have similar features to the wellbore 116.
- the first set of data which may relate to fluids expected to be directed into the wellbore 116, may be modeled based on an expected fluid volume to be pumped into the wellbore 116 with respect to time.
- the first set of data may be modeled over a period of time in short intervals. The short intervals may be periods of minutes or substantially continuously.
- the model may be based on a planned schedule of fluids to be directed into the wellbore 116.
- the first set of data may be a theoretical data set.
- a second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120.
- the second set of data may be an actual, measured data set, received at the data system 202.
- data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations.
- the first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time. For example, the first and second sets of data may be compared using a time-track or by performing a regression. However, any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
- a first set of data may relate to one or more fluids expected to exit the wellbore 116 over a period of time in short intervals.
- the short intervals may be periods of minutes or substantially continuously.
- a user may be able to predict a data set of fluids expected to exit the wellbore 116.
- a user may be able to collect or model a data set of fluids expected to exit the wellbore 116.
- the first data set may relate to fluids expected to exit the wellbore and may be a theoretical data set.
- a second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120.
- the second set of data may be an actual, measured data set, received at the data system 202.
- data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations.
- the first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time. For example, the first and second sets of data may be compared using a time-track or by performing a regression. However, any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
- the operator may be able to determine the location of each fluid in the wellbore 116 at any point in time. Comparisons may be used to deduce further information about the fluids in the wellbore 116 and about the stability of the casing 228 and formation 130.
- the theoretical data sets may include a time track of the volume of fluid being pumped into the wellbore 116 against the volume being displaced out of the wellbore 116. If there are no cracks in the casing 228 or formation 130, the actual data set should match the theoretical data set.
- Deviations from the theoretical data set may indicate that fluid loss to the formation 130 due to cracks is occurring or that fluids from the wellbore 116 (i.e., hydrocarbons) are entering the fluid path. Additionally, regression models may be run to compare the data of the fluid expected to be directed into the wellbore 116, directed into the wellbore 116, or expected to exit the wellbore 116 with that of the fluid exiting the wellbore 116. Any other type of known modeling and analysis may be done on the data without departing from the scope of this disclosure.
- the crack may be located at the bottom of the wellbore 116, where the highest wellbore pressure is located. Pressure modeling may be performed to model the pressure variation along the wellbore 116. This information may be used to determine where fluid loss may be occurring. Additionally, other knowledge such as zones of weakness in the formation 130, may be applied to locate areas of potential fluid loss.
- the rate of pumping may be decreased in order to decrease the level of pressure in the wellbore 116 and prevent the crack in the casing 228 or formation 130 from spreading. Further, if the decreased pressure does not adequately address the crack in the casing 228 or formation 130, a well operator may be able to repair the crack in the casing 228 or formation 130 during drilling or cementing operations and before the crack creates additional problems.
- the height and/or relative position of each fluid in the wellbore 116 may be calculated as a function of the available volume between multiple components or between one or more components and the wellbore wall 234.
- the larger component may be the wellbore 116, and the smaller component may be the casing 228. The diameters of these components may be measured before they are inserted into the wellbore 116.
- the constant 1029.4 represents a constant derived from volumetric calculations to convert the difference in diameters between two pipes into a volumetric area.
- the fluid volume available for any given interval will determine the top and bottom of each fluid as pumped.
- the top and bottom of any fluid will form a vertical height of a fluid column component, which will determine the addition to the overall hydrostatic column of all fluids.
- Fluids of discrete density can be converted into a pressure as a result of pressure gradient calculations. Each fluid therefore applies a pressure over its column height.
- the operator may calculate the height, density, and pressure of each fluid column. Density data may be added into the model as well. For example, a fluid with higher density may be added into the wellbore 116 after a fluid of lower density. Even without pumping, the higher density fluid will naturally surpass the lower density fluid due to gravity until the pressures inside and outside the casing 228 are balanced. Due to this natural phenomenon, an operator may calculate how much fluid is being returned to the surface as a result of pumping and how much is being returned as a result of fluid density. This data may be added into the model to determine more information about the location of any cracks in the casing 228 or formation 130.
- the pumping data may be measured and analyzed in real time.
- real time may include time intervals of about one second between each data point.
- the pumping data may be measured and analyzed substantially continuously. The calculations may also account for the reverse flow of fluids from the annulus 232 into the casing 228 without departing from the spirit of the present disclosure.
- the systems and methods of the present disclosure may, among other benefits, provide a low-cost method of detecting fluid loss early in an operation based primarily on surface measurements that require little or no downhole intervention or measurements.
- the early detection of fluid loss also may increase the efficiency of certain subterranean operations by helping operators to correct fluid loss problems sooner, reducing the need to repeat unsuccessful operations or steps in those operations.
- the systems and methods of the present disclosure may facilitate more efficient remedial and/or clean-up operations.
- the fluid lost into the formation is identified as a cement, this may inform the operator of the reason why the cement did not cure or set in its intended location, and may, among other benefits, allow the operator to more efficiently correct the condition causing cement loss downhole so that the cementing operation may be performed properly.
- a data acquisition and control interface may also receive data from multiple rigsites and wells to perform quality checks across a plurality of rigs.
- each information handling system may be communicatively coupled through a wired or wireless system to facilitate data transmission between the different subsystems.
- each information handling system may include a computer-readable media to store data generated by the subsystem as well as preset job performance requirements and standards.
- the systems and methods of the present disclosure may be used to monitor fluids, characterize fluids, and/or detect fluid loss in conjunction any subterranean operation involving the applicable equipment.
- the systems and methods of the present disclosure may be used in cementing operations, stimulation operations (e.g., fracturing, acidizing, etc.), completion operations, remedial operations, drilling operations, and the like.
- stimulation operations e.g., fracturing, acidizing, etc.
- completion operations e.g., remedial operations, drilling operations, and the like.
- the systems and methods of the present disclosure also may be used to verify the placement and/or curing of cement in a wellbore.
- the system and method disclosed herein may be used to monitor the volume, temperature, and pressure of fluids exiting the wellbore to detect exothermic curing of a cement downhole.
- a system or method of the present disclosure may be used to detect fluid loss in a particular wellbore and to identify the specific fluid that has been lost into the formation. That same system or another system may use data regarding the volume, temperature, and pressure of fluids exiting the wellbore to determine that a cement did not cure in its intended location.
- the fluid lost into the formation is identified as a cement, this may inform the operator of the reason why the cement did not cure or set in its intended location, and may, among other benefits, allow the operator to more efficiently correct the condition causing cement loss downhole so that the cementing operation may be performed properly.
- the systems and methods of the present disclosure also may be used to, or in conjunction with certain systems and methods used to monitor hookload.
- a system or method of the present disclosure may be used to detect fluid loss in a particular wellbore and to identify the specific fluid that has been lost into the formation. That same system or another system may use data regarding the total effective weight of the apparatus attached to the hook (e.g., BHA, tubing, casing, etc.) to determine information about the volume, temperature, and pressure of fluids in the wellbore.
- An embodiment of the present disclosure is a method for obtaining information about one or more fluids in a wellbore in a subterranean formation that includes obtaining a first set of data relating to one or more fluids directed into the wellbore over a period of time in short intervals, obtaining a second set of data relating to one or more fluids exiting the wellbore over a period of time in short intervals; and in real time, determining the location of a fluid in the wellbore based on the first and second sets of data.
- the first and second sets of data may be compared by performing a regression.
- the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.
- the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.
- the method further directing two or more fluids downhole, wherein the two or more fluids are of different densities and wherein the second set of data includes fluid density data.
- Another embodiment of the present disclosure is a method for obtaining information about one or more fluids in a wellbore in a subterranean formation that includes modeling a first set of data relating to one or more fluids expected to be directed into or expected to exit the wellbore over a period of time in short intervals, obtaining a second set of data relating to one or more fluids exiting the wellbore over a period of time in short intervals; and in real time, comparing the first and second sets of data to determine the location of a fluid in the wellbore.
- the first and second sets of data may be compared by performing a regression.
- the location of a fluid in the wellbore is calculated based on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.
- the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.
- the method further includes directing two or more fluids downhole, wherein the two or more fluids are of different densities, and wherein the second set of data includes fluid density data.
- a fluid monitoring system that includes a data system, one or more fluid measurement devices communicatively coupled to the data system that are configured to detect amounts of fluids directed into or exiting the wellbore, wherein the data system receives a first set of data relating to one or more fluids directed into, expected to be directed into, or expected to exit the wellbore over a period of time, and a second set of data relating to one or more fluids exiting the wellbore over a period of time from the one or more fluid measurement devices, wherein the data system uses the first and second sets of data received to determine the location of one or more fluids in the wellbore in real time.
- the data system is coupled to an external communications interface that is remotely accessible.
- the first and second sets of data are compared by performing a regression.
- the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.
- the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.
Landscapes
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- Mining & Mineral Resources (AREA)
- Geophysics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
- Investigating Or Analysing Materials By The Use Of Chemical Reactions (AREA)
- Geophysics And Detection Of Objects (AREA)
Claims (14)
- Procédé d'obtention d'informations concernant un ou plusieurs fluides dans un puits de forage (116, 216) dans une formation souterraine (130, 230), comprenant :l'obtention d'un premier ensemble de données relatives à un ou plusieurs fluides dirigés dans le puits de forage (116, 216) sur une période de temps pendant de courts intervalles ;l'obtention d'un second ensemble de données relatives aux un ou plusieurs fluides sortant du puits de forage (116, 216) sur une période de temps pendant de courts intervalles ; eten temps réel, la détermination de la localisation des un ou plusieurs fluides dans le puits de forage (116, 216) en comparant les premier et second ensembles de données.
- Procédé selon la revendication 1, dans lequel les premier et second ensembles de données sont comparés en réalisant une régression.
- Procédé selon la revendication 1, dans lequel la localisation des un ou plusieurs fluides dans le puits de forage (116, 216) est déterminée d'après au moins en partie le volume disponible d'une pluralité de composants, dans lequel la pluralité de composants comporte au moins deux des éléments suivants : un tubage (228), une colonne de production (226), et le puits de forage (116, 216).
- Procédé selon la revendication 1, dans lequel les premier et second ensembles de données comportent un ou plusieurs des éléments suivants : hauteur, volume de fluide, pression de fluide, densité de fluide, et débit de fluide de chaque colonne des un ou plusieurs fluides.
- Procédé selon la revendication 1, comprenant en outre :
le fait de diriger deux fluides ou plus vers le fond, dans lequel les deux fluides ou plus ont des densités différentes ; et dans lequel le second ensemble de données comporte des données de densité de fluide. - Procédé selon la revendication 1, comprenant en outre :
la modélisation du premier ensemble de données d'après un volume prévu des un ou plusieurs fluides à pomper dans le puits de forage (116, 216), et dans lequel le second ensemble de données concerne les un ou plusieurs fluides pompés hors du puits de forage (116, 216). - Système de surveillance de fluide comprenant :un système de données (202) ;un ou plusieurs dispositifs de mesure de fluide (136, 138) couplés en communication au système de données (202) qui sont configurés pour détecter des quantités de fluides dirigés dans ou sortant d'un puits de forage (116, 216) ;dans lequel le système de données (202) reçoitun premier ensemble de données relatives à un ou plusieurs fluides dirigés dans, prévus d'être dirigés dans, ou prévus de sortir du puits de forage (116, 216) sur une période de temps, etun second ensemble de données relatives aux un ou plusieurs fluides sortant du puits de forage (116, 216) sur une période de temps provenant des un ou plusieurs dispositifs de mesure de fluide (136, 138) ;dans lequel le système de données (202) compare les premier et second ensembles de données reçus pour déterminer la localisation des un ou plusieurs fluides dans le puits de forage (116, 216) en temps réel.
- Système selon la revendication 7, dans lequel le système de données (202) est couplé à une interface de communications externe qui est accessible à distance.
- Système selon la revendication 7, dans lequel les premier et second ensembles de données sont comparés en réalisant une régression.
- Système selon la revendication 7, dans lequel la localisation des un ou plusieurs fluides dans le puits de forage (116, 216) est déterminée d'après au moins en partie le volume disponible d'une pluralité de composants, dans lequel la pluralité de composants comporte au moins deux des éléments suivants : un tubage (228), une colonne de production (226), et le puits de forage (116, 216).
- Système selon la revendication 7, dans lequel les premier et second ensembles de données comportent un ou plusieurs des éléments suivants : hauteur, volume de fluide, pression de fluide, densité de fluide, et débit de fluide de chaque colonne des un ou plusieurs fluides.
- Système selon la revendication 7, dans lequel une pompe (120) fait circuler les un ou plusieurs fluides à travers le puits de forage (116, 216) dans une mine de rétention (124).
- Système selon la revendication 7, dans lequel les un ou plusieurs dispositifs de mesure de fluide (136, 138) sont situés sur un conduit (140) menant dans la mine de rétention (124) ou sur la mine de rétention (124) elle-même.
- Système selon la revendication 7, dans lequel les un ou plusieurs dispositifs de mesure de fluide (136, 138) comportent des capteurs acoustiques et/ou de hauteur de niveau et des débitmètres.
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
PCT/US2013/023413 WO2014116249A1 (fr) | 2013-01-28 | 2013-01-28 | Systèmes et méthodes de surveillance de fluides de puits de forage utilisant la microanalyse de données de pompage en temps réel |
Publications (2)
Publication Number | Publication Date |
---|---|
EP2920412A1 EP2920412A1 (fr) | 2015-09-23 |
EP2920412B1 true EP2920412B1 (fr) | 2018-05-23 |
Family
ID=47679085
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP13703265.2A Not-in-force EP2920412B1 (fr) | 2013-01-28 | 2013-01-28 | Systèmes et méthodes de surveillance de fluides de puits de forage utilisant la microanalyse de données de pompage en temps réel |
Country Status (5)
Country | Link |
---|---|
US (1) | US20150322775A1 (fr) |
EP (1) | EP2920412B1 (fr) |
BR (1) | BR112015015307A2 (fr) |
MX (1) | MX365398B (fr) |
WO (1) | WO2014116249A1 (fr) |
Families Citing this family (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10519764B2 (en) * | 2014-08-28 | 2019-12-31 | Schlumberger Technology Corporation | Method and system for monitoring and controlling fluid movement through a wellbore |
US20180363414A1 (en) * | 2015-12-16 | 2018-12-20 | Schlumberger Technology Corporation | System and method for performing a real-time integrated cementing operation |
US10036219B1 (en) | 2017-02-01 | 2018-07-31 | Chevron U.S.A. Inc. | Systems and methods for well control using pressure prediction |
EP3938658B1 (fr) * | 2019-03-15 | 2024-09-18 | Lavalley Industries, LLC | Pompe à fosse destinée à être utilisée dans un système de recyclage de fluide de forage |
US11821284B2 (en) | 2019-05-17 | 2023-11-21 | Schlumberger Technology Corporation | Automated cementing method and system |
US11118422B2 (en) | 2019-08-28 | 2021-09-14 | Schlumberger Technology Corporation | Automated system health check and system advisor |
US20240254857A1 (en) * | 2023-01-31 | 2024-08-01 | Halliburton Energy Services, Inc. | Hybrid Approach to Tailor Design Choices for Improved Risk Mitigation During Cement Job Design |
Family Cites Families (18)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO1999000575A2 (fr) * | 1997-06-27 | 1999-01-07 | Baker Hughes Incorporated | Dispositifs de forage munis de capteurs permettant de mesurer les proprietes des boues de forage en fond de puits |
US6980940B1 (en) * | 2000-02-22 | 2005-12-27 | Schlumberger Technology Corp. | Intergrated reservoir optimization |
US7197398B2 (en) * | 2005-03-18 | 2007-03-27 | Halliburton Energy Services, Inc. | Method for designing formation tester for well |
US7398680B2 (en) * | 2006-04-05 | 2008-07-15 | Halliburton Energy Services, Inc. | Tracking fluid displacement along a wellbore using real time temperature measurements |
GB2472519A (en) * | 2008-03-10 | 2011-02-09 | Schlumberger Holdings | System and method for well test design, interpretation and test objectives verification |
US20100082258A1 (en) * | 2008-09-26 | 2010-04-01 | Baker Hughes Incorporated | System and method for modeling fluid flow profiles in a wellbore |
US9309731B2 (en) * | 2009-10-06 | 2016-04-12 | Schlumberger Technology Corporation | Formation testing planning and monitoring |
US20110088462A1 (en) * | 2009-10-21 | 2011-04-21 | Halliburton Energy Services, Inc. | Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing |
US8930143B2 (en) * | 2010-07-14 | 2015-01-06 | Halliburton Energy Services, Inc. | Resolution enhancement for subterranean well distributed optical measurements |
GB2500332B (en) * | 2010-12-30 | 2018-10-24 | Schlumberger Holdings | System and method for performing downhole stimulation operations |
US9441149B2 (en) * | 2011-08-05 | 2016-09-13 | Halliburton Energy Services, Inc. | Methods for monitoring the formation and transport of a treatment fluid using opticoanalytical devices |
US9134291B2 (en) * | 2012-01-26 | 2015-09-15 | Halliburton Energy Services, Inc. | Systems, methods and devices for analyzing drilling fluid |
US9567852B2 (en) * | 2012-12-13 | 2017-02-14 | Halliburton Energy Services, Inc. | Systems and methods for measuring fluid additive concentrations for real time drilling fluid management |
US20140080223A1 (en) * | 2012-09-14 | 2014-03-20 | Halliburton Energy Services, Inc. | Systems and Methods for Inspecting and Monitoring a Pipeline |
EP2900904A1 (fr) * | 2012-09-26 | 2015-08-05 | Halliburton Energy Services, Inc. | Systèmes et procédés de complétion multizone à parcours simple |
US9000358B2 (en) * | 2012-12-13 | 2015-04-07 | Halliburton Energy Services, Inc. | Systems and methods for real time drilling fluid management |
US8575541B1 (en) * | 2012-12-13 | 2013-11-05 | Halliburton Energy Services, Inc. | Systems and methods for real time monitoring and management of wellbore servicing fluids |
US20140262245A1 (en) * | 2013-03-15 | 2014-09-18 | Hytech Energy, Llc | Fluid Level Determination Apparatus and Method of Determining a Fluid Level in a Hydrocarbon Well |
-
2013
- 2013-01-28 US US14/763,404 patent/US20150322775A1/en not_active Abandoned
- 2013-01-28 MX MX2015007613A patent/MX365398B/es active IP Right Grant
- 2013-01-28 WO PCT/US2013/023413 patent/WO2014116249A1/fr active Application Filing
- 2013-01-28 EP EP13703265.2A patent/EP2920412B1/fr not_active Not-in-force
- 2013-01-28 BR BR112015015307A patent/BR112015015307A2/pt not_active Application Discontinuation
Non-Patent Citations (1)
Title |
---|
None * |
Also Published As
Publication number | Publication date |
---|---|
MX365398B (es) | 2019-05-31 |
US20150322775A1 (en) | 2015-11-12 |
EP2920412A1 (fr) | 2015-09-23 |
WO2014116249A1 (fr) | 2014-07-31 |
MX2015007613A (es) | 2015-10-29 |
BR112015015307A2 (pt) | 2017-07-11 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
EP2920412B1 (fr) | Systèmes et méthodes de surveillance de fluides de puits de forage utilisant la microanalyse de données de pompage en temps réel | |
AU2017424961B2 (en) | Methods and systems for wellbore integrity management | |
Arop | Geomechanical review of hydraulic fracturing technology | |
US10125569B2 (en) | Systems and methods for monitoring and validating cementing operations using connection flow monitor (CFM) systems | |
US10551523B2 (en) | Evaluating and imaging volumetric void space location for cement evaluation | |
US20050194184A1 (en) | Multiple distributed pressure measurements | |
US20110220350A1 (en) | Identification of lost circulation zones | |
US20150315894A1 (en) | Model for strengthening formations | |
US10087746B2 (en) | Well treatment design based on three-dimensional wellbore shape | |
US10753193B2 (en) | Heterogeneity profiling analysis for volumetric void space cement evaluation | |
US10753203B2 (en) | Systems and methods to identify and inhibit spider web borehole failure in hydrocarbon wells | |
US7770639B1 (en) | Method for placing downhole tools in a wellbore | |
EP2923036B1 (fr) | Systèmes et méthodes de surveillance et de caractérisation de fluides dans une formation souterraine utilisant la charge au crochet | |
NO20190260A1 (en) | Logging of fluid properties for use in subterranean drilling and completions | |
CN113767210B (zh) | 用于施工决策的侧钻井的实时生产率评估 | |
US8756018B2 (en) | Method for time lapsed reservoir monitoring using azimuthally sensitive resistivity measurements while drilling | |
Kessler et al. | A Synergistic Approach to Optimizing Hydraulic Fracturing | |
Upchurch | Near-wellbore halo effect resulting from Tip-Screenout Fracturing: Direct Measurement and Implication for sand control | |
NO347602B1 (en) | Intelligent well testing system | |
BR112020006928B1 (pt) | Método para executar operações de fundo de poço em um campo que tem uma pluralidade de poços e sistema para conduzir operações de fundo de poço em uma escala para campo |
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: 20150618 |
|
AK | Designated contracting states |
Kind code of ref document: A1 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 RS SE SI SK SM TR |
|
AX | Request for extension of the european patent |
Extension state: BA ME |
|
DAX | Request for extension of the european patent (deleted) | ||
GRAP | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOSNIGR1 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: GRANT OF PATENT IS INTENDED |
|
INTG | Intention to grant announced |
Effective date: 20180215 |
|
RIN1 | Information on inventor provided before grant (corrected) |
Inventor name: MARLAND, CHRISTOPHER Inventor name: MITCHELL, IAN Inventor name: LOVORN, JAMES RANDOLPH |
|
GRAS | Grant fee paid |
Free format text: ORIGINAL CODE: EPIDOSNIGR3 |
|
GRAA | (expected) grant |
Free format text: ORIGINAL CODE: 0009210 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: THE PATENT HAS BEEN GRANTED |
|
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 RS 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: IE Ref legal event code: FG4D |
|
REG | Reference to a national code |
Ref country code: AT Ref legal event code: REF Ref document number: 1001670 Country of ref document: AT Kind code of ref document: T Effective date: 20180615 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R096 Ref document number: 602013037766 Country of ref document: DE |
|
REG | Reference to a national code |
Ref country code: NO Ref legal event code: T2 Effective date: 20180523 |
|
REG | Reference to a national code |
Ref country code: NL Ref legal event code: MP Effective date: 20180523 |
|
REG | Reference to a national code |
Ref country code: LT Ref legal event code: MG4D |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20180523 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: 20180523 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: 20180823 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: 20180523 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: 20180523 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20180523 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: 20180824 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: 20180523 Ref country code: RS 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: 20180523 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: 20180523 |
|
REG | Reference to a national code |
Ref country code: AT Ref legal event code: MK05 Ref document number: 1001670 Country of ref document: AT Kind code of ref document: T Effective date: 20180523 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20180523 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: 20180523 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: 20180523 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: 20180523 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: 20180523 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: 20180523 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: 20180523 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R097 Ref document number: 602013037766 Country of ref document: DE |
|
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: 20180523 Ref country code: IT 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: 20180523 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: GB Payment date: 20181109 Year of fee payment: 7 |
|
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 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: NO Payment date: 20181227 Year of fee payment: 7 |
|
26N | No opposition filed |
Effective date: 20190226 |
|
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: 20180523 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R119 Ref document number: 602013037766 Country of ref document: DE |
|
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: 20180523 |
|
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: 20190128 |
|
REG | Reference to a national code |
Ref country code: BE Ref legal event code: MM Effective date: 20190131 |
|
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: FR Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20190131 Ref country code: DE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20190801 |
|
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: 20180523 Ref country code: BE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20190131 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: CH Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20190131 Ref country code: LI Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20190131 |
|
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: 20190128 |
|
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: 20180523 |
|
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: 20190128 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: 20180924 |
|
REG | Reference to a national code |
Ref country code: NO Ref legal event code: MMEP |
|
GBPC | Gb: european patent ceased through non-payment of renewal fee |
Effective date: 20200128 |
|
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: 20200128 Ref country code: NO Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20200131 |
|
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: 20180523 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20180923 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20130128 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: MK 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: 20180523 |