EP1936113B1 - 2d well testing with smart plug sensor - Google Patents
2d well testing with smart plug sensor Download PDFInfo
- Publication number
- EP1936113B1 EP1936113B1 EP06126833A EP06126833A EP1936113B1 EP 1936113 B1 EP1936113 B1 EP 1936113B1 EP 06126833 A EP06126833 A EP 06126833A EP 06126833 A EP06126833 A EP 06126833A EP 1936113 B1 EP1936113 B1 EP 1936113B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- formation
- tool
- wellbore
- sensors
- pressure
- 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
- 238000012360 testing method Methods 0.000 title claims abstract description 26
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 71
- 230000035699 permeability Effects 0.000 claims abstract description 34
- 238000009530 blood pressure measurement Methods 0.000 claims abstract description 11
- 239000012530 fluid Substances 0.000 claims abstract description 8
- 238000000034 method Methods 0.000 claims description 18
- 238000004891 communication Methods 0.000 claims description 8
- 230000008878 coupling Effects 0.000 claims description 6
- 238000010168 coupling process Methods 0.000 claims description 6
- 238000005859 coupling reaction Methods 0.000 claims description 6
- 238000012546 transfer Methods 0.000 claims description 6
- 230000005540 biological transmission Effects 0.000 claims description 5
- 238000004458 analytical method Methods 0.000 claims description 3
- 238000005755 formation reaction Methods 0.000 description 58
- 238000005259 measurement Methods 0.000 description 7
- 239000000523 sample Substances 0.000 description 5
- 238000012512 characterization method Methods 0.000 description 4
- 238000012544 monitoring process Methods 0.000 description 2
- 230000001052 transient effect Effects 0.000 description 2
- 238000011156 evaluation Methods 0.000 description 1
- 230000005251 gamma ray Effects 0.000 description 1
- 238000003306 harvesting Methods 0.000 description 1
- 239000012585 homogenous medium Substances 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000003780 insertion Methods 0.000 description 1
- 230000037431 insertion Effects 0.000 description 1
- 238000012417 linear regression Methods 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 239000003550 marker Substances 0.000 description 1
- 239000002609 medium Substances 0.000 description 1
- 230000000149 penetrating effect Effects 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 230000002285 radioactive effect Effects 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
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
-
- 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
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
-
- 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
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
Definitions
- This invention relates to an apparatus for characterising the permeability of a formation surrounding a borehole well.
- permeability is determined by measuring the formation and borehole pressure in oil, gas or similar wells.
- a well test is usually performed to characterise the formation surrounding the borehole. Properties such as skin, permeability, porosity of a reservoir, and production capacity are some the properties used to characterise the formations. Knowing how fluids flow through a reservoir is important for managing hydrocarbons reserves. Fluid flow is governed by the permeability of the formations.
- a conventional well test can determine formation properties from pressure measurements obtained by a drillstem test (DST) tool as shown in Figure 1 .
- DST drillstem test
- transient well test conditions are applied to the well and the pressure below a tester valve is measured. The valve is shut off causing a pressure build up which is recorded. This build up is interpreted and can lead to the determination of a series of well/formation parameters such as: skin, permeability, reservoir pressure and distances to boundaries.
- formations are not homogenous in quality and will have layering features.
- the results obtained in terms of reservoir properties from testing the whole thickness, h is representative of some average of the individual layer permeability which is not really useful to a reservoir engineer for assessing the potential of the well or the field under evaluation.
- US6693553 describes deploying sensors into the formations as the wellbore is being drilled. An antenna that can communicate with the sensor is located on the downhole tool.
- US6070662 describes deploying sensors into the formations and placing an antenna in the casing to communicate with the sensor.
- WO2006/026311 discloses the preamble of claim 1, and describes a method of estimating permeability of a formation using a single probe having a flow rate and pressure sensors to make measurements to determine the vertical and horizontal permeabilities of the formation.
- US4890487 also described using a single probe inserted into the formation for making pressure and flow measurements to determine the permeability of the formation.
- US5265015 discloses determining vertical and horizontal permeabilities using a single probe. Measurements are made with two orientations of the probe, one with the axis of elongation parallel vertical and with the axis of elongation horizontal.
- WO2006008172 describes a method for estimating the permeability distribution of a formation surrounding a borehole.
- An acoustic emitter located either on the surface in the borehole excites a portion of the formation with an acoustic signal.
- An acoustic receiver located within the borehole measures the acoustic response. This acoustic response can be used to assess a formation pressure from which the permeability of the formation can be estimated. Conventional well test pressure measurements can also be taken to estimate the permeability of the formation.
- the object of the invention to provide an apparatus to characterise the permeability of the formation around a borehole.
- the invention proposes an apparatus and method for characterising the permeability of the formation in two dimensions, horizontally and vertically, by directly measuring both the borehole pressure and formation pressure.
- a first aspect of the invention comprises an apparatus for characterising the permeability of a formation surrounding a wellbore, comprising; a drillstem test (DST) tool comprising, a pressure gauge for detecting the pressure in the well bore, a valve for controlling fluid into and out of the zone via the drill string of the tool and a packer for isolating a zone of the wellbore; wherein the apparatus further comprises an array of at least two antennas arranged on the tool above the packer such that when in use each antenna of the array aligns with a corresponding pressure sensor placed in the formation to obtain pressure measurements and therefore allow horizontal and vertical permeability to be determined.
- DST drillstem test
- the distance between each individual antenna of the array is determined by the placement of the sensors in the formation. Differing lengths of pipes making up the drill string can be used to alter the distance between the individual antennas.
- the apparatus can further comprise an interrogating tool.
- the tool scans the array of antennas so that data obtained from each antenna is transmitted to the interrogating tool which conveys the information up to the surface.
- the array of antenna is mounted on the outside of the DST tool.
- the antennas can transmit and receive information from the sensors by wireless communication.
- the interrogating tool can also be used to transfer power to the sensors via the antennas.
- the wireless communication and the transfer of power can be based on electromagnetic coupling or acoustic transmission.
- a second aspect of the invention is a sensor system for characterising the permeability of a formation surrounding a wellbore in two dimensions, comprising: at least two sensors installed in the formation surrounding the wellbore; and an apparatus comprising, a drillstem test (DST) tool comprising, a packer for isolating a zone of the wellbore, a pressure gauge for detecting the pressure in the wellbore, a valve for controlling fluid into and out of the zone via the drill string of the tool, and an array of at least two antennas arranged on the DST tool above the packer such that each antenna of the array aligns with a corresponding pressure sensor in the formation.
- DST drillstem test
- a third aspect of the invention comprises a method for characterising the permeability of a formation surrounding a wellbore, comprising:
- the spacing between the sensors is recorded as the sensors are inserted into the formation.
- Preferably method further comprises positioning the antennas along the DST tool so that the spacing between the antennas is equal to the spacing between the sensors in the formation, before inserting the tool body down the wellbore.
- the method can further comprise scanning the array of antennas with an interrogating tool to transfer the information from the antenna to the tool and to power the sensors.
- the information from the interrogating tool is sent up-hole for surface recording and further analysis.
- Preferably transmitting the data between the sensors and antenna is done by wireless mode. This can be electro-magnetic coupling or acoustic transmission.
- the method is preformed using the system described above.
- Figure 1 shows a conventional drillstem test tool arrangement.
- Figure 2 shows a schematic of a two dimensional well test tool arrangement.
- Figure 3 shows a schematic of a sensor plug used to detect the pressure in the formation.
- Figure 4 shows an arrangement for data transmission between the sensor and array of antennas.
- Figure 5 shows a schematic of the test well arrangement used to carry out the example.
- Figure 6 shows the results of the wellbore and layers pressure responses of the test well.
- a conventional drill stem test tool 1 for measuring the wellbore pressure comprises a pressure gauge 2, a packer 3 and a tester valve 4.
- the DST tool 1 is lowered down into a wellbore 5.
- the packer 3 is inflated to isolate the zone of interest, h, of the wellbore.
- the valve 4 is initially open and fluid can flow into the drillstring of the DST tool.
- the valve 4 is then closed to stop the fluid flow through the wellbore.
- a build up occurs below the valve 4, and the pressure is monitored as a function of time.
- the permeability of the reservoir is then estimated from the well test measurement.
- the whole thickness, h, of the formation zone tested is often not homogenous in quality but instead comprises layering features, with separate layers of medium quality sands 6 and layers very good quality sands 7, surrounding the wellbore the result obtained merely indicates an average of the zone and does not characterise each individual layer component that may be present in the reservoir.
- This conventional test only provides a one dimensional horizontal characterisation of the permeability of the formation.
- the DST tool 26 comprises an array of antennas 21 located on the outside of the drill string of the tool, a pressure gauge 23, a valve 27 and packer 28.
- Each of the antennas 21 comprising the array are spaced apart to line up with a pressure sensor 24 in the formation 25 to receive data from the sensor.
- the pressure gauge 23 measures the pressure in the wellbore 22 in the perforated interval, h1, as for a conventional DST well test.
- the spacing between the pressure sensors 24 is recorded as the sensors are inserted into the formation at predetermined depths such that the spacing between each of the sensors 24 relative to each other is known.
- the distance between the sensors is recorded by differential measurements between the depths at which each sensor is inserted into the formation. This information is used to ensure that the antennas in the array are correctly spaced apart when preparing the tool for inserting down the wellbore so that the spacing between antennas on the array will be equal to the spacing between the sensors.
- These sensors 24, located at different depths of the formation record the pressure within the formation at each of their locations. The data obtained from these measurements at different depths allows for the permeability of the formation to be characterised along the wellbore axis.
- an example of a sensor plug 31, that can be inserted in the formation comprises a sensing element 32, an electronics platform 33 inside a protective housing and a communication element 34.
- the sensing element 32 senses the pressure in the formation and the communication element 34, such as an antenna, enables data to be received and transmitted from the sensor.
- the antenna transmits the pressure data recorded by the sensing element 32 to an antenna outside the formation located on tool placed down the wellbore.
- the power supply for electronics platform 33 is provided by embedded batteries or directly by antenna 34. To supply power via the antenna 34, the power is transferred from the tool antenna towards antenna 34 by electro-magnetic coupling between the two antennae. Rechargeable batteries can be used and recharged from the tool antenna.
- Energy harvesting techniques can also be used to collect energy available at the reservoir level. Vibrations induced by the downhole flow can be collected by electro-acoustic sensors and converted to electrical energy to supply the sensor electronics or recharge the battery cells. Further details of suitable sensors can be found in WO2006/005555 .
- each sensor 41 aligns with an antenna 42 of the array.
- the sensors 41 are inserted into the formation 44 through the casing 45 of the wellbore 46.
- the spacing of the sensors 41 is recorded during their insertion into the formation 44.
- the sensors 41 are installed in a hole through the casing so that the sensor extends between the inside and outside of the casing 45, with the sensing elements in the formation 44 surrounding the well and the communication antenna of the sensor able to communicate with the antennas in the well.
- An array of antennas 42 and its associated interrogating tool 47 are mounted on the outside of the drillstring 48 of the DST tool.
- the antennas 42 are positioned along the drillstring 48 so that their spacing is equal to the spacing between each sensor 41.
- the distance between each antenna 42 can be adjusted with pipes of various lengths.
- the drillstring 48 is inserted down into the wellbore 46 until the array of antennas 42 is proximate to the sensor 41.
- antenna coupling 49 occurs between the antenna 42 of the array located on the drillstring 48 and the antenna of the sensor 41.
- the sensors 41 may comprise a radioactive marker, such as a gamma ray pip-tag that allows their location in the wellbore to be sensed by the DST tool.
- Data is transmitted from the antenna in the sensor 41 to its corresponding antenna 42 mounted on the outside of the drillstring 48 of the DST tool by wireless communication such as by electro-magnetic coupling or acoustic transmission.
- the interrogating tool 47 scans the array of antennas 42 and all the data acquired by each antenna 42 is transferred to the interrogating tool 47. This allows the data to be sent up-hole for surface recording and further analysis.
- a vertical test well penetrating a three layer formation as shown in Figure 5 is constructed and pressure measurements are taken using the apparatus and method of the invention.
- the welltest consists of flowing layer 3 at 318m 3 /day (2000 bl/d) for 24 hours followed by 48 hours of build up.
- the pressure response is recorded at the wellbore by gauge 53 and within the formation layers 1 and 2 by monitoring gauges 51 and 52 respectively.
- Table 1 An analytic model is built to have the characteristics shown in Table 1.
- Table 1 Forward model values of test well Layer # Thickness (m) k h (mD) k z (mD) Skin 1 10.6 (35ft) 70 10 - 2 6.1 (20ft) 35 4 - 3 15.2 (50ft) 150 20 0.5
- the model is first run in a forward mode to simulate the pressure responses in the well bore and at the two monitoring gauges. The results are shown in Figure 6 .
Landscapes
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Remote Sensing (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geophysics (AREA)
- Chemical & Material Sciences (AREA)
- Acoustics & Sound (AREA)
- Analytical Chemistry (AREA)
- Electromagnetism (AREA)
- Measuring Fluid Pressure (AREA)
- Geophysics And Detection Of Objects (AREA)
- Arrangements For Transmission Of Measured Signals (AREA)
- Measuring And Recording Apparatus For Diagnosis (AREA)
- Coupling Device And Connection With Printed Circuit (AREA)
Abstract
Description
- This invention relates to an apparatus for characterising the permeability of a formation surrounding a borehole well. In particular permeability is determined by measuring the formation and borehole pressure in oil, gas or similar wells.
- Once a well has been drilled, a well test is usually performed to characterise the formation surrounding the borehole. Properties such as skin, permeability, porosity of a reservoir, and production capacity are some the properties used to characterise the formations. Knowing how fluids flow through a reservoir is important for managing hydrocarbons reserves. Fluid flow is governed by the permeability of the formations.
- A conventional well test can determine formation properties from pressure measurements obtained by a drillstem test (DST) tool as shown in
Figure 1 . In a conventional well test operation transient well test conditions are applied to the well and the pressure below a tester valve is measured. The valve is shut off causing a pressure build up which is recorded. This build up is interpreted and can lead to the determination of a series of well/formation parameters such as: skin, permeability, reservoir pressure and distances to boundaries. However often formations are not homogenous in quality and will have layering features. In such cases the results obtained in terms of reservoir properties from testing the whole thickness, h, is representative of some average of the individual layer permeability which is not really useful to a reservoir engineer for assessing the potential of the well or the field under evaluation. - Such a test only provides a one dimensional characterization that is only valid for perfectly homogenous medium. Because most formations are not homogenous but rather show a layering structure, a single pressure measurement does not sufficiently characterize each individual layer component. In addition it is not possible to obtain a characterization of the vertical permeability from the results of a single probe.
- It is also known to measure the pressure of formation surrounding the borehole using sensors placed into the formation.
US6693553 describes deploying sensors into the formations as the wellbore is being drilled. An antenna that can communicate with the sensor is located on the downhole tool.US6070662 describes deploying sensors into the formations and placing an antenna in the casing to communicate with the sensor. - However these methods only result in a single pressure measurement and do not simultaneously measure the pressure at different depths of the borehole and therefore are not sufficient to characterise each individual layer component of a formation in a single test.
WO2006/026311 discloses the preamble ofclaim 1, and describes a method of estimating permeability of a formation using a single probe having a flow rate and pressure sensors to make measurements to determine the vertical and horizontal permeabilities of the formation.US4890487 also described using a single probe inserted into the formation for making pressure and flow measurements to determine the permeability of the formation.US5265015 discloses determining vertical and horizontal permeabilities using a single probe. Measurements are made with two orientations of the probe, one with the axis of elongation parallel vertical and with the axis of elongation horizontal. -
WO2006008172 describes a method for estimating the permeability distribution of a formation surrounding a borehole. An acoustic emitter located either on the surface in the borehole excites a portion of the formation with an acoustic signal. An acoustic receiver located within the borehole measures the acoustic response. This acoustic response can be used to assess a formation pressure from which the permeability of the formation can be estimated. Conventional well test pressure measurements can also be taken to estimate the permeability of the formation. - It is the object of the invention to provide an apparatus to characterise the permeability of the formation around a borehole. The invention proposes an apparatus and method for characterising the permeability of the formation in two dimensions, horizontally and vertically, by directly measuring both the borehole pressure and formation pressure.
- A first aspect of the invention comprises an apparatus for characterising the permeability of a formation surrounding a wellbore, comprising; a drillstem test (DST) tool comprising, a pressure gauge for detecting the pressure in the well bore, a valve for controlling fluid into and out of the zone via the drill string of the tool and a packer for isolating a zone of the wellbore; wherein the apparatus further comprises an array of at least two antennas arranged on the tool above the packer such that when in use each antenna of the array aligns with a corresponding pressure sensor placed in the formation to obtain pressure measurements and therefore allow horizontal and vertical permeability to be determined.
- The distance between each individual antenna of the array is determined by the placement of the sensors in the formation. Differing lengths of pipes making up the drill string can be used to alter the distance between the individual antennas.
- The apparatus can further comprise an interrogating tool. The tool scans the array of antennas so that data obtained from each antenna is transmitted to the interrogating tool which conveys the information up to the surface.
- Preferably the array of antenna is mounted on the outside of the DST tool.
- Preferably the antennas can transmit and receive information from the sensors by wireless communication. The interrogating tool can also be used to transfer power to the sensors via the antennas. The wireless communication and the transfer of power can be based on electromagnetic coupling or acoustic transmission.
- A second aspect of the invention is a sensor system for characterising the permeability of a formation surrounding a wellbore in two dimensions, comprising: at least two sensors installed in the formation surrounding the wellbore; and an apparatus comprising, a drillstem test (DST) tool comprising, a packer for isolating a zone of the wellbore, a pressure gauge for detecting the pressure in the wellbore, a valve for controlling fluid into and out of the zone via the drill string of the tool, and an array of at least two antennas arranged on the DST tool above the packer such that each antenna of the array aligns with a corresponding pressure sensor in the formation.
- A third aspect of the invention comprises a method for characterising the permeability of a formation surrounding a wellbore, comprising:
- inserting sensors into the formation surrounding the wellbore at various depths;
- inserting an apparatus as described above in the wellbore;
- isolating a zone of the wellbore;
- changing the pressure in the zone by altering flow through the valve;
- measuring the pressure of the formation at the location of each sensor and transmitting the data obtained to the array of antenna;
- measuring the pressure in the zone with the pressure gauge; and
- determining the horizontal and vertical permeability of the formation using the pressure measurements obtained. The method may be conducted in openhole or cased wells.
- Preferably the spacing between the sensors is recorded as the sensors are inserted into the formation.
- Preferably method further comprises positioning the antennas along the DST tool so that the spacing between the antennas is equal to the spacing between the sensors in the formation, before inserting the tool body down the wellbore.
- The method can further comprise scanning the array of antennas with an interrogating tool to transfer the information from the antenna to the tool and to power the sensors.
- Preferably the information from the interrogating tool is sent up-hole for surface recording and further analysis.
- Preferably transmitting the data between the sensors and antenna is done by wireless mode. This can be electro-magnetic coupling or acoustic transmission.
- Preferably the method is preformed using the system described above.
-
Figure 1 shows a conventional drillstem test tool arrangement. -
Figure 2 shows a schematic of a two dimensional well test tool arrangement. -
Figure 3 shows a schematic of a sensor plug used to detect the pressure in the formation. -
Figure 4 shows an arrangement for data transmission between the sensor and array of antennas. -
Figure 5 shows a schematic of the test well arrangement used to carry out the example. -
Figure 6 shows the results of the wellbore and layers pressure responses of the test well. - Referring to
Figure 1 a conventional drillstem test tool 1 for measuring the wellbore pressure comprises apressure gauge 2, a packer 3 and atester valve 4. During a conventional well test, for determining properties of a formation surrounding awellbore 5, theDST tool 1 is lowered down into awellbore 5. The packer 3 is inflated to isolate the zone of interest, h, of the wellbore. Thevalve 4 is initially open and fluid can flow into the drillstring of the DST tool. Thevalve 4 is then closed to stop the fluid flow through the wellbore. A build up occurs below thevalve 4, and the pressure is monitored as a function of time. The permeability of the reservoir is then estimated from the well test measurement. As the whole thickness, h, of the formation zone tested is often not homogenous in quality but instead comprises layering features, with separate layers ofmedium quality sands 6 and layers verygood quality sands 7, surrounding the wellbore the result obtained merely indicates an average of the zone and does not characterise each individual layer component that may be present in the reservoir. This conventional test only provides a one dimensional horizontal characterisation of the permeability of the formation. - With reference to
Figure 2 theDST tool 26 according to an embodiment of the invention comprises an array ofantennas 21 located on the outside of the drill string of the tool, a pressure gauge 23, avalve 27 andpacker 28. Each of theantennas 21 comprising the array are spaced apart to line up with apressure sensor 24 in theformation 25 to receive data from the sensor. The pressure gauge 23 measures the pressure in thewellbore 22 in the perforated interval, h1, as for a conventional DST well test. - The spacing between the
pressure sensors 24 is recorded as the sensors are inserted into the formation at predetermined depths such that the spacing between each of thesensors 24 relative to each other is known. The distance between the sensors is recorded by differential measurements between the depths at which each sensor is inserted into the formation. This information is used to ensure that the antennas in the array are correctly spaced apart when preparing the tool for inserting down the wellbore so that the spacing between antennas on the array will be equal to the spacing between the sensors. Thesesensors 24, located at different depths of the formation, record the pressure within the formation at each of their locations. The data obtained from these measurements at different depths allows for the permeability of the formation to be characterised along the wellbore axis. - When the measurements from the
sensors 24 in the formation are taken in combination with the pressure measurements obtained from the conventional DST test preformed by the pressure gauge 23 a two dimensional characterisation of the permeability of the formation, in the horizontal and vertical direction, can be determined. - With reference to
Figure 3 an example of asensor plug 31, that can be inserted in the formation comprises asensing element 32, anelectronics platform 33 inside a protective housing and acommunication element 34. Thesensing element 32 senses the pressure in the formation and thecommunication element 34, such as an antenna, enables data to be received and transmitted from the sensor. The antenna transmits the pressure data recorded by thesensing element 32 to an antenna outside the formation located on tool placed down the wellbore. The power supply forelectronics platform 33 is provided by embedded batteries or directly byantenna 34. To supply power via theantenna 34, the power is transferred from the tool antenna towardsantenna 34 by electro-magnetic coupling between the two antennae. Rechargeable batteries can be used and recharged from the tool antenna. Energy harvesting techniques can also be used to collect energy available at the reservoir level. Vibrations induced by the downhole flow can be collected by electro-acoustic sensors and converted to electrical energy to supply the sensor electronics or recharge the battery cells. Further details of suitable sensors can be found inWO2006/005555 . - With reference to
Figure 4 eachsensor 41 aligns with anantenna 42 of the array. Thesensors 41 are inserted into theformation 44 through thecasing 45 of thewellbore 46. The spacing of thesensors 41 is recorded during their insertion into theformation 44. Thesensors 41 are installed in a hole through the casing so that the sensor extends between the inside and outside of thecasing 45, with the sensing elements in theformation 44 surrounding the well and the communication antenna of the sensor able to communicate with the antennas in the well. An array ofantennas 42 and its associated interrogatingtool 47 are mounted on the outside of thedrillstring 48 of the DST tool. Theantennas 42 are positioned along thedrillstring 48 so that their spacing is equal to the spacing between eachsensor 41. The distance between eachantenna 42 can be adjusted with pipes of various lengths. Thedrillstring 48 is inserted down into thewellbore 46 until the array ofantennas 42 is proximate to thesensor 41. When theantennas 42 are aligned with theirrespective sensor 41,antenna coupling 49 occurs between theantenna 42 of the array located on thedrillstring 48 and the antenna of thesensor 41. Thesensors 41 may comprise a radioactive marker, such as a gamma ray pip-tag that allows their location in the wellbore to be sensed by the DST tool. - Data is transmitted from the antenna in the
sensor 41 to its correspondingantenna 42 mounted on the outside of thedrillstring 48 of the DST tool by wireless communication such as by electro-magnetic coupling or acoustic transmission. The interrogatingtool 47 scans the array ofantennas 42 and all the data acquired by eachantenna 42 is transferred to the interrogatingtool 47. This allows the data to be sent up-hole for surface recording and further analysis. - A vertical test well penetrating a three layer formation as shown in
Figure 5 is constructed and pressure measurements are taken using the apparatus and method of the invention. - The welltest consists of flowing layer 3 at 318m3/day (2000 bl/d) for 24 hours followed by 48 hours of build up. The pressure response is recorded at the wellbore by
gauge 53 and within the formation layers 1 and 2 by monitoringgauges - An analytic model is built to have the characteristics shown in Table 1.
Table 1 - Forward model values of test well Layer # Thickness (m) kh (mD) kz (mD) Skin 1 10.6 (35ft) 70 10 - 2 6.1 (20ft) 35 4 - 3 15.2 (50ft) 150 20 0.5 - The model is first run in a forward mode to simulate the pressure responses in the well bore and at the two monitoring gauges. The results are shown in
Figure 6 . - A non-linear regression routine is used to match the pressures transient that are previously established and to recover the individual layer permeabilities along the horizontal and vertical directions (kh, kz). The results are shown in Table 2.
Table 2 - Inverted values (in italics) Layer # Thickness (m) kh(mD) kz (mD) Skin 1 10.6 (35ft) 72 9 - 2 6.1 (20ft) 38 4 - 3 15.2 (50ft) 148 20 0.44 - The results obtained with regards to horizontal and vertical permeabilities and skin values compare well (within 10%) with the forward model values of Table 1.
Claims (14)
- An apparatus for characterising the horizontal and vertical permeability of a formation (25) surrounding a wellbore (22), comprising:a drillstem test (DST) tool (26) comprising, a packer (28) for isolating a zone of the wellbore (22), a valve (27) for controlling fluid into and out of the zone via the drill string of the tool (26) and, a pressure gauge (23) for detecting the pressure in the zone;characterized in that the apparatus further comprises an array of at least two antennas (21) arranged on the tool (26) above the packer such that when in use each antenna (21) of the array aligns with a corresponding pressure sensor (24) placed in the formation (25) to obtain pressure measurements and therefore allow horizontal and vertical permeability to be determined.
- An apparatus according to claim 1 wherein the distance between each individual antenna (21) of the array is determined by the placement of the sensors (24) in the formation.
- An apparatus according to any of claims 1 or 2 which further comprises an interrogating tool (47) that can scan the array of antenna (21) to commute the information to the surface.
- An apparatus according to any of claims 1, 2, or 3, wherein the array of antenna (21) is mounted on the outside of the DST tool (26).
- An apparatus according to any of claims 1-4, wherein the antennas (21) can transmit and receive information from the sensors by wireless communication and transfer power to the sensors (24).
- An apparatus according to claim 5, wherein the wireless communication and power transfer is based on electromagnetic coupling or acoustic transmission.
- A sensor system for characterising the permeability of a formation (25) surrounding a wellbore (22) in two dimensions, comprising:at least two sensors (24) in the formation (25) surrounding the wellbore (22); and an apparatus as claimed in any of claims 1-6.
- A method for characterising the horizontal and vertical permeability of a formation (25) surrounding a wellbore (22), comprising:inserting sensors (24) into the formation (25) surrounding the wellbore (22) at various depths;inserting an apparatus as claimed in any of claims 1-6 in the wellbore (22); isolating a zone of the wellbore (22);changing the pressure in the zone by altering flow through the valve (27); measuring the pressure of the formation (25) at the location of each sensor (24) and transmitting the data obtained to the array of antenna (21);measuring the pressure in the zone with the pressure gauge (23); anddetermining the horizontal and vertical permeability of the formation (25) using the pressure measurements obtained.
- A method according to claim 8 comprising recording the spacing between the sensors (24) as the sensors are inserted into the formation (25).
- A method according to any of claims 8 or 9, comprising positioning the antennas (21) along the DST tool (26) so that the spacing between the antennas (21) is equal to the spacing between the sensors (24) in the formation (25), before inserting the DST tool (26) down the wellbore (22).
- A method according to any of claims 8, 9, or 10, comprising scanning the array of antennas (21) with an interrogating tool (47) to power the sensors (24) and transfer the information from the antennas (21) to the tool (47).
- A method according to claim 11 comprising sending the information from the interrogating tool (47) up-hole for surface recording and further analysis.
- A method according to any of claims 8-12, when transmitting the data between the sensors (24) and antenna (21) is done by wireless mode.
- A method according to any one of claims 8-13 when performed using the system according to claim 7.
Priority Applications (6)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
DE602006010226T DE602006010226D1 (en) | 2006-12-21 | 2006-12-21 | 2D borehole test with smart plug sensors |
EP06126833A EP1936113B1 (en) | 2006-12-21 | 2006-12-21 | 2d well testing with smart plug sensor |
AT06126833T ATE447661T1 (en) | 2006-12-21 | 2006-12-21 | 2D HOLE TESTING WITH SMART PLUG SENSORS |
CA2612357A CA2612357C (en) | 2006-12-21 | 2007-11-26 | 2d well testing with smart plug sensors |
US11/957,585 US20090020283A1 (en) | 2006-12-21 | 2007-12-17 | 2D Well Testing with Smart Plug Sensor |
RU2007147655/03A RU2450123C2 (en) | 2006-12-21 | 2007-12-20 | Testing wells in two dimensions by intelligent insert sensor |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
EP06126833A EP1936113B1 (en) | 2006-12-21 | 2006-12-21 | 2d well testing with smart plug sensor |
Publications (2)
Publication Number | Publication Date |
---|---|
EP1936113A1 EP1936113A1 (en) | 2008-06-25 |
EP1936113B1 true EP1936113B1 (en) | 2009-11-04 |
Family
ID=37946134
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP06126833A Not-in-force EP1936113B1 (en) | 2006-12-21 | 2006-12-21 | 2d well testing with smart plug sensor |
Country Status (6)
Country | Link |
---|---|
US (1) | US20090020283A1 (en) |
EP (1) | EP1936113B1 (en) |
AT (1) | ATE447661T1 (en) |
CA (1) | CA2612357C (en) |
DE (1) | DE602006010226D1 (en) |
RU (1) | RU2450123C2 (en) |
Families Citing this family (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CN101878350B (en) * | 2007-11-30 | 2015-03-11 | 普拉德研究及开发股份有限公司 | Downhole, single trip, multi-zone testing system and downhole testing method using such |
WO2011163602A2 (en) * | 2010-06-24 | 2011-12-29 | Schlumberger Canada Limited | Systems and methods for collecting one or more measurements in a borehole |
CN101963056B (en) * | 2010-08-19 | 2014-04-09 | 中国石油大学(北京) | Method for predicting carbonate formation pore pressure by using log information |
US20130319102A1 (en) * | 2012-06-05 | 2013-12-05 | Halliburton Energy Services, Inc. | Downhole Tools and Oil Field Tubulars having Internal Sensors for Wireless External Communication |
WO2015178883A1 (en) * | 2014-05-19 | 2015-11-26 | Halliburton Energy Services, Inc. | Nuclear magnetic resonance sensors embedded in cement |
US10359525B2 (en) * | 2015-09-09 | 2019-07-23 | Halliburton Energy Services, Inc. | Methods to image acoustic sources in wellbores |
CN110824580B (en) * | 2019-11-27 | 2024-06-04 | 中国电建集团贵阳勘测设计研究院有限公司 | Inclined hole interhole model geophysical prospecting test device |
CN111594158A (en) * | 2020-06-11 | 2020-08-28 | 中国石油集团渤海钻探工程有限公司 | Cased well stratified drainage test process pipe column and test method |
WO2024110292A1 (en) * | 2022-11-22 | 2024-05-30 | Shell Internationale Research Maatschappij B.V. | A method of installing a permanent downhole sensor |
Family Cites Families (13)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4890487A (en) | 1987-04-07 | 1990-01-02 | Schlumberger Technology Corporation | Method for determining horizontal and/or vertical permeability of a subsurface earth formation |
SU1513136A1 (en) * | 1987-07-07 | 1989-10-07 | Государственный Геофизический Трест "Татнефтегеофизика" | Device for determining permeability of rock traversed by well |
US5265015A (en) | 1991-06-27 | 1993-11-23 | Schlumberger Technology Corporation | Determining horizontal and/or vertical permeability of an earth formation |
US6070662A (en) | 1998-08-18 | 2000-06-06 | Schlumberger Technology Corporation | Formation pressure measurement with remote sensors in cased boreholes |
US6693553B1 (en) | 1997-06-02 | 2004-02-17 | Schlumberger Technology Corporation | Reservoir management system and method |
NO315725B1 (en) * | 1998-06-18 | 2003-10-13 | Norges Geotekniske Inst | Device for measuring and monitoring resistivity outside a well pipe in a petroleum reservoir |
EG22206A (en) * | 2000-03-02 | 2002-10-31 | Shell Int Research | Oilwell casing electrical power pick-off points |
US6577244B1 (en) * | 2000-05-22 | 2003-06-10 | Schlumberger Technology Corporation | Method and apparatus for downhole signal communication and measurement through a metal tubular |
US7032661B2 (en) * | 2001-07-20 | 2006-04-25 | Baker Hughes Incorporated | Method and apparatus for combined NMR and formation testing for assessing relative permeability with formation testing and nuclear magnetic resonance testing |
US7261168B2 (en) * | 2004-05-21 | 2007-08-28 | Halliburton Energy Services, Inc. | Methods and apparatus for using formation property data |
US7140434B2 (en) * | 2004-07-08 | 2006-11-28 | Schlumberger Technology Corporation | Sensor system |
EP1619520A1 (en) | 2004-07-21 | 2006-01-25 | Services Petroliers Schlumberger | Method and apparatus for estimating a permeability distribution during a well test |
US7181960B2 (en) | 2004-08-26 | 2007-02-27 | Baker Hughes Incorporated | Determination of correct horizontal and vertical permeabilities in a deviated well |
-
2006
- 2006-12-21 DE DE602006010226T patent/DE602006010226D1/en not_active Expired - Fee Related
- 2006-12-21 EP EP06126833A patent/EP1936113B1/en not_active Not-in-force
- 2006-12-21 AT AT06126833T patent/ATE447661T1/en not_active IP Right Cessation
-
2007
- 2007-11-26 CA CA2612357A patent/CA2612357C/en not_active Expired - Fee Related
- 2007-12-17 US US11/957,585 patent/US20090020283A1/en not_active Abandoned
- 2007-12-20 RU RU2007147655/03A patent/RU2450123C2/en not_active IP Right Cessation
Also Published As
Publication number | Publication date |
---|---|
CA2612357A1 (en) | 2008-06-21 |
US20090020283A1 (en) | 2009-01-22 |
DE602006010226D1 (en) | 2009-12-17 |
ATE447661T1 (en) | 2009-11-15 |
RU2007147655A (en) | 2009-06-27 |
EP1936113A1 (en) | 2008-06-25 |
RU2450123C2 (en) | 2012-05-10 |
CA2612357C (en) | 2015-08-04 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
EP1936113B1 (en) | 2d well testing with smart plug sensor | |
US6987463B2 (en) | Method for collecting geological data from a well bore using casing mounted sensors | |
CA2627431C (en) | Monitoring formation properties | |
US7178607B2 (en) | While drilling system and method | |
CA2521151C (en) | Apparatus and methods for conveying and operating analytical instrumentation within a well borehole | |
US9063250B2 (en) | Interference testing while drilling | |
US9249658B2 (en) | Downhole data communication and logging system | |
WO1999063202A1 (en) | Method and arrangement for monitoring well related parameters |
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 |
|
AK | Designated contracting states |
Kind code of ref document: A1 Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IS IT LI LT LU LV MC NL PL PT RO SE SI SK TR |
|
AX | Request for extension of the european patent |
Extension state: AL BA HR MK RS |
|
17P | Request for examination filed |
Effective date: 20081202 |
|
RAP1 | Party data changed (applicant data changed or rights of an application transferred) |
Owner name: SCHLUMBERGER TECHNOLOGY B.V. Owner name: SERVICES PETROLIERS SCHLUMBERGER Owner name: SCHLUMBERGER HOLDINGS LIMITED Owner name: PRAD RESEARCH AND DEVELOPMENT N.V. |
|
17Q | First examination report despatched |
Effective date: 20090114 |
|
AKX | Designation fees paid |
Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IS IT LI LT LU LV MC NL PL PT RO SE SI SK TR |
|
GRAP | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOSNIGR1 |
|
RTI1 | Title (correction) |
Free format text: 2D WELL TESTING WITH SMART PLUG SENSOR |
|
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): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IS IT LI LT LU LV MC NL PL PT RO SE SI SK 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 |
|
REF | Corresponds to: |
Ref document number: 602006010226 Country of ref document: DE Date of ref document: 20091217 Kind code of ref document: P |
|
NLV1 | Nl: lapsed or annulled due to failure to fulfill the requirements of art. 29p and 29m of the patents act | ||
LTIE | Lt: invalidation of european patent or patent extension |
Effective date: 20091104 |
|
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: 20100304 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: 20091104 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: 20100304 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: 20091104 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: 20100215 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: 20091104 |
|
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: 20091104 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: 20091104 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: 20091104 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: 20091104 |
|
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 FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT Effective date: 20091104 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: 20091104 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20091104 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: 20091104 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: 20091104 Ref country code: MC Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20100701 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: 20100204 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20091104 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: 20091104 |
|
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 |
|
26N | No opposition filed |
Effective date: 20100805 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20100205 Ref country code: IE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20091221 |
|
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: 20100701 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: FR Payment date: 20101201 Year of fee payment: 5 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20091104 |
|
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: 20091221 |
|
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 Effective date: 20100505 |
|
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: 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: 20091104 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: LI Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20101231 Ref country code: CH Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20101231 |
|
REG | Reference to a national code |
Ref country code: FR Ref legal event code: ST Effective date: 20120831 |
|
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: 20091104 |
|
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: 20120102 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: GB Payment date: 20161221 Year of fee payment: 11 |
|
GBPC | Gb: european patent ceased through non-payment of renewal fee |
Effective date: 20171221 |
|
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: 20171221 |