EP2102451B1 - An apparatus for use when gathering parameters from a well flow and also a method of using same - Google Patents
An apparatus for use when gathering parameters from a well flow and also a method of using same Download PDFInfo
- Publication number
- EP2102451B1 EP2102451B1 EP07860914.6A EP07860914A EP2102451B1 EP 2102451 B1 EP2102451 B1 EP 2102451B1 EP 07860914 A EP07860914 A EP 07860914A EP 2102451 B1 EP2102451 B1 EP 2102451B1
- Authority
- EP
- European Patent Office
- Prior art keywords
- well
- semi
- rigid rod
- accordance
- flow
- 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
- 238000000034 method Methods 0.000 title claims description 19
- 239000012530 fluid Substances 0.000 claims description 29
- 239000000126 substance Substances 0.000 claims description 17
- 235000013619 trace mineral Nutrition 0.000 claims description 14
- 239000011573 trace mineral Substances 0.000 claims description 14
- 239000000835 fiber Substances 0.000 claims description 10
- 230000015572 biosynthetic process Effects 0.000 claims description 6
- 238000011156 evaluation Methods 0.000 claims description 6
- 239000003208 petroleum Substances 0.000 claims description 6
- 244000309464 bull Species 0.000 claims description 5
- 238000012545 processing Methods 0.000 claims description 3
- 238000004519 manufacturing process Methods 0.000 description 10
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 10
- 238000002347 injection Methods 0.000 description 5
- 239000007924 injection Substances 0.000 description 5
- 239000000243 solution Substances 0.000 description 3
- 238000004458 analytical method Methods 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 2
- 230000006870 function Effects 0.000 description 2
- 238000012544 monitoring process Methods 0.000 description 2
- 238000011002 quantification Methods 0.000 description 2
- 238000005070 sampling Methods 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 238000004891 communication Methods 0.000 description 1
- 238000004590 computer program Methods 0.000 description 1
- 238000001514 detection method Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005611 electricity Effects 0.000 description 1
- 238000003780 insertion Methods 0.000 description 1
- 230000037431 insertion Effects 0.000 description 1
- 239000013307 optical fiber Substances 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 230000035939 shock Effects 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
Description
- The present invention relates to an apparatus for, and a method of, gathering parameters from a well flow. More particularly, it relates to an apparatus and a method for gathering parameters along a petroleum well path in order thus to be able to evaluate the flow, fluid phases and productivity or injectivity of the well.
- In the oil and gas production industry, there is a need for being able to evaluate petroleum wells producing oil and/or gas and/or water in order to measure the inflow of oil, gas and water along well paths above the reservoir section from which oil, gas and water are produced. This is particularly challenging in horizontal wells, including both a horizontal branch and so-called multiple branches or multilaterals.
- Several apparatuses and methods for gathering data from a well are known for allowing evaluation of pressure and flow, and for allowing estimation of the fluid phases of the well flow, and the productivity or injectivity of the well.
- A familiar method is to install required sensors permanently along predetermined locations in the well path. The sensors communicate to the surface, for example to a rig, through one of, or a combination of, two or more of an electrical cable or a fibre cable. Data can also be communicated to the surface by means of wireless communication, or by means of so-called memory cards temporarily storing the gathered data in the well.
- Publication
US 2005/0269106 A1 discloses an apparatus and a method for conveying and operating a tool into a wellbore by means of a continuous rod according to the preamble ofclaim 1. - Electricity for electronic sensors is provided by means of batteries, or by means of cable to an energy source at the surface.
- In order to be able to gather data from a well, it is also known to insert required sensors into the well, for example by means of a cable or so-called wireline, or by means of coiled tubing.
- There are several disadvantages related to the above-mentioned prior art.
- When using permanently installed sensors, the placement thereof must be planned and installed before being inserted into the well. The additional rig time required to install the sensors depends on the number of cables to be fitted, the number of sensor units to be fitted/installed, and on the length of the well. Experience goes to show that it is very costly to install sensors on a permanent basis in a well.
- Among other things, electronic units have proven very vulnerable to the high temperatures that might exist in a well, and also to impacts and shocks. Electronic sensors therefore have a limited operating time. Replacement of failed electronic sensors is both time-consuming and difficult.
- With respect to space in the well between a production tubing and a casing, passages for cables onward to the surface, and the clamping of a cable to the production tubing, permanently installed systems represent a challenge to the completion of wells.
- Within the industry, downhole monitoring is considered to represent a high degree of difficulty. This particularly applies to wells having well path angles between 65° and 95°.
- In order to reduce the above-mentioned disadvantages represented by the permanently installed monitoring- or logging systems, sensors may be inserted into the well after having been established.
- In order to insert logging systems into wells having high well path angles, i.e. well paths having an angle between 65° and 95°, coiled tubing or wireline with a well tractor is required.
- Coiled tubing, however, has a tendency to "buckle", i.e. it coils up and assumes the shape of a helical spring so as to stop, or it winds (becomes "helical"), i.e. the tubing assumes the shape of a helical spring so as not to stop. This is particularly a problem experienced upon repeated use of the coiled tubing. To remedy this problem, among other things, well tractors for coiled tubing have been developed. However, coiled tubing in the well will cause the effective pipe diameter to become reduced, and the production of the fluid to become slowed down due to increased friction between the production tubing and the coiled tubing. This friction results in the well not behaving in an optimum manner, and in some cases the result of the logging does not represent a correct image of the flow conditions within the well.
- Additionally, coiled tubing has a limited reach, insofar as there is a limit to how much coiled tubing may be reeled onto a drum to be used, for example, from a rig or a ship.
- Wireline requires a well tractor to push the logging tool in front of itself. A well tractor may also function as a throttle unit (choke). In some cases, it has been produced out of a horizontal well as a consequence of the production rate being too high.
- In some cases, this has resulted in the cable, which connects the well tractor to the surface, to become twisted. Such a situation has resulted in equipment being lost in the well in response to the cable being ruptured during attempts of retrieving the equipment from the well.
- It is also possible for a well tractor to get stuck in, for example, grooves in the well. This may result in not being able to retrieve the well tractor and the logging tool, instead being left in the well. Getting stuck with the well tractor has proven especially problematic in wells having valves or so-called "sleeves", and in well paths without any casing, so-called "open-hole solutions". Purpose-built well tractors for use in open-hole solutions have been developed, but they involve the same type of throttling problem as mentioned above.
- All types of logging involving insertion of the logging tools into the well by means of coiled tubing or wireline, require movement into and out of the well during production, and under so-called shut-in well conditions. During such movements, the sensors may stop functioning in the intended manner.
- High temperatures in the well, for example above 140 °C, oftentimes lead to problems related to reduced strength or loss of electrical signal in the transitional portion between the cable and the logging tool. Experience goes to show that pressure- and temperature data generally experience a lot of noise under such conditions, which may result in unreliable data from the well.
- Logging with a fibre cable is limited to the ability to measure temperature along the cable. As of today, flow can be measured only in permanently installed solutions in which fibre cables are used (and simultaneously are installed along the well path above the reservoir section), and both pressure and flow must be measured to evaluate the productivity or injectivity of the well. As of today, there are no logging sensors available for rigid fibre cable or semi-rigid rod capable of measuring the fluid phases of the well flow or capable of differentiating oil, water and gas in a well flow.
- The object of the invention is to remedy or reduce at least one of the disadvantages of the prior art.
- The object is achieved through features disclosed in the description below and in the subsequent claims.
- In the method according to the present invention, a measuring device is run into a desired portion of a well by means of a thin, rigid cable, hereinafter referred to as a semi-rigid rod. The well path may be both vertical and horizontal. The measuring devices are arranged for providing data for allowing estimation of the fluid phases oil, gas and water in the well flow, and to be able to provide data for allowing estimation of the productivity index, PI, or injectivity index, II, of the well. A person skilled in the art will know that the well's productivity index PI, or injectivity index II, represents flow rate per day per unit of pressure, for example BBL/d/psi. The corresponding term for the injectivity index II will be injection rate per day per unit of pressure, for example BBL/D/psi.
- The sensors may include chemicals or so-called "tracers", which are arranged for allowing detection and quantification of fluids downhole, and also other sensor types of a type known per se.
- According to the invention, temperature, so-called DTS (distributed temperature sensing), is measured along a cable or a semi-rigid rod by means of an optical-fibre cable arranged in said cable or semi-rigid rod. Thus, the semi-rigid rod forms the logging unit for the temperature profile along the well. When the temperature profile is known, the flow rate of the well may be estimated.
-
PCT application WO 2006/00347 - In addition to the semi-rigid rod being enable to sense temperature, pressure sensors are preferably integrated along the cable and are also placed at an end portion of a rigid fibre cable or a semi-rigid rod.
- Thus, and according to the present invention, the sensors DTS, pressure and fluid identification method are combined in order to replace conventional logging methods wherein physical sensors for temperature, pressure and flow are connected as a tool string at the end of a cable.
- The apparatus and method according to the present invention represent particularly great advantages in horizontal wells which otherwise cannot be logged with conventional logging tools.
- According to the invention the cable is kept stationary during logging of a well under production/injection, or during logging of a shut-in well.
- A person skilled in the art will appreciate that the apparatus and method according to the invention imply that there is no need for physical depth correlation tools for allowing evaluation of the log. However, a depth correlation tool may be used in connection with checking whether a rigid fibre cable or semi-rigid rod "buckles" or has become "helical".
- According to a first aspect of the present invention, an apparatus for use when gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well is provided, the apparatus including:
- a semi-rigid rod arranged in a manner allowing it to sense the temperature profile of the well;
- at least two mutually spaced-apart measuring devices and/or fluid phase indicators attached to the semi-rigid rod; and
- at least one pressure sensor arranged in a manner allowing it to sense pressure in the well, whereby also the amounts of water, oil and gas from one or more formation sections may be quantified. When using more than two measuring devices and/or fluid phase indicators, water, oil and gas from more than two formation sections or zones may be quantified.
- In a preferred embodiment, the at least two mutually spaced-apart measuring devices and/or fluid phase indicators include one of, or a combination of, two or more of a sensor, a chemical or a trace element.
- In a preferred embodiment, the semi-rigid rod includes a fibre cable. In one embodiment, the semi-rigid rod is of the type described in
WO 2006/003477 . - In one embodiment, the semi-rigid rod includes a plurality of spaced-apart pressure sensors.
- In one embodiment, the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus in the well. Preferably, the additional pressure sensor is placed between the semi-rigid rod and a so-called "bull nose" placed at the end of the apparatus in the well. The main purpose of the bull nose is to guide the semi-rigid rod past sharp edges that may be present in a well, thereby functioning as a steering device for said rod.
- In a preferred embodiment, the apparatus is arranged in a manner allowing it to communicate measuring data through the fibre and out of the well while measuring is in progress.
- In a second aspect of the invention, a method of gathering parameters from a well flow in a petroleum well for allowing evaluation of the flow and productivity or injectivity of the well is provided, wherein the method includes the steps of:
- inserting an apparatus to a desired portion of the well, the apparatus including:
- a semi-rigid rod arranged in a manner allowing it to sense the temperature profile of the well;
- at least two mutually spaced-apart measuring devices and/or fluid phase indicators attached to the semi-rigid rod; and
- at least one pressure sensor arranged in a manner allowing it to sense pressure in the well; and
- keeping the apparatus substantially stationary within the well during gathering of parameters from one or more formation sections in the well.
- In one embodiment, the measuring results from the measuring devices and the semi-rigid rod are communicated to the surface for further processing. Elements liberated from a chemical or a trace element may be communicated to the surface in the same manner.
- An example of a preferred embodiment is described in the following and is depicted in the accompanying drawings, in which:
- Figure 1
- shows a principle drawing of a well, in which measuring devices have been inserted into the well by means of a semi-rigid rod, and in which the measuring devices are comprised of the semi-rigid rod and eight sensors;
- Figure 2a
- shows a graph illustrating the relationship between flow, pressure and time in a fluid-producing well.
- Figure 2b
- shows a graph illustrating the relationship between flow, pressure and time in a fluid-injecting well.
- A person skilled in the art will appreciate that
figure 1 is greatly distorted, and that the relative scales of the different elements shown are incorrect. -
Figure 1 shows a principle drawing of awell 1, in which anapparatus 3 according to the present invention has been inserted into thewell 1. - The
apparatus 3 includes asemi-rigid rod 5 ending up, at one end portion thereof, on areel 7 outside thewell 1, and ending up, at the other end portion thereof, at a bottom portion of thewell 1. - Preferably, the
semi-rigid rod 5 is of a self-straightening type. That is to say, when thesemi-rigid rod 5 is inserted into the well, therod 5 has substantially no curvature remaining from thereel 7. - Disposed on the
semi-rigid rod 5 are seven measuring devices in the form of sixchemical devices 9 and onepressure sensor 11. - The
chemical devices 9 are comprised of receptacles holding trace elements or so-called "tracers" of a type known per se. In a manner known per se, the trace elements are released into the fluid flow within which thechemical devices 9 are disposed. Preferably, the trace elements released into the fluid flow from each of thechemical devices 9 are arranged in a manner allowing them to be separated from each other. - The
chemical devices 9 offigure 1 are attached around thesemi-rigid rod 5. A person skilled in the art will appreciate that the chemical devices, in alternative embodiments, also may be arranged in a manner allowing them to be attached to, or merely be connected to, portions of thesemi-rigid rod 5. - Disposed at the end of the
semi-rigid rod 5 there is a so-called "bull nose" 13. As mentioned above, the main purpose of abull nose 13 is to guide thesemi-rigid rod 5 past sharp edges that may be present in a well. - The
well 1 is provided with casings/liners 15 andproduction tubing 17. At the end portion of the horizontal portion of thewell 1, thewell 1 is comprised of a so-called open hole. - The arrows in the figure illustrate the flow of fluids in through
perforations 18 in theliner 15 and flow of produced fluids. A person skilled in the art will appreciate that the arrows would have pointed in the opposite direction for a fluid-injection well. The straight, broken lines illustrate the division of the formation into different zones. - Upon having placed the measuring
device 3 illustrated infigure 1 in thewell 1, it may provide the following information directly or indirectly. - Pressure within the
well 1 may be measured directly by means of thepressure sensor 11, and possibly by means of pressure sensors (not shown) disposed along therod 5. - Temperature distribution or -profile, DTS, along the
semi-rigid rod 5 may be measured along the entire length thereof. Upon knowing the temperature profile, it is possible to derive a total fluid flow. From the total fluid flow, it is possible to estimate a flow profile in the well. Particular calculation models have been developed for this purpose. Preferably, the calculations are carried out by.means of a computer program. - By means of the
chemical devices 9 or tracers disposed along thesemi-rigid rod 5, it is possible to estimate water and gas inflow points. For example, consumption of a tracers or trace elements may be determined by measuring the amount of trace elements originally installed in thechemical device 9 versus the amount remaining upon retrieving thechemical device 9 to surface after a logging operation. The consumption is a function of fluid flow rate (water, for example) past thechemical device 9 holding the trace element. Moreover, surface equipment for detecting concentrations of the different trace elements or tracers in the producing well flow may be provided. - Consumption of trace elements may also provide an indication on the direction and extent of any cross-flow in the
well 1. - Upon knowing the pressure and flow of the
well 1, the productivity, or the so-called productivity index PI, of thewell 1 may be estimated. - When the above-mentioned information has been provided, a person skilled in the art will be able to estimate the flow contribution from each single zone or formation section in the well, so as to render possible to quantify the amounts of water, oil and gas.
- A person skilled in the art will appreciate that the measuring
device 3 must be kept stationary relative to thewell 1 while measuring is in progress. - In the following, the main features of performing a logging operation by means of the measuring
device 3 according to the present invention are described. For simplicity, some of the required features obvious to a person skilled in the art have been left out completely or partially. Similarly, the processing of the measuring results undertaken during and after the logging operation is not included either. - After having prepared the measuring
device 3 on a rig or a ship, for example, and after having shut in thewell 1 by means of one or morepressure control valves 19 in the so-called X-mas tree, a portion of the measuringdevice 3 is inserted into the so-calledinjection head 21. Theinjection head 21 is then placed on top of said X-mas tree, and pressure control testing is carried out. - Logging of the depth of the
measuring tool 3 is activated by means of a depth control unit (not shown). In its simplest form, such a depth control unit may be comprised of a device for measuring the length of thesemi-rigid rod 5 being inserted into thewell 1, but it may also be comprised of a depth-measuring device (not shown). Measuring results from said depth-measuring device are compared with the measured length of therod 5 inserted into thewell 1. This makes possible to establish whether thesemi-rigid rod 5 is rigid, "buckles" or is "helical". - Having opened the pressure control valve(s) 19, the
semi-rigid rod 5 is inserted into thewell 1 at a controlled speed, for example 20 metres/min, until reaching the desired position. Infigure 1 , the desired position is reached at the end of thewell 1. Due to the inherent properties of thesemi-rigid rod 5, it will straighten out, but still adapt to the well path. - The measuring
tool 3 is kept at rest, and logging is started while thewell 1 is shut in. - The
well 1 is opened to a first flow denoted "flow 1" infigure 2 , the flow of which is assumed to be 50 % of maximum flow capacity. Thewell 1 is flowed towards a test separator (not shown) until the well flow has stabilized. Experience goes to show that this may take between six and twelve hours, however differing from well to well. Upon assuming a stable well flow, thewell 1 is flowed for twelve hours, for example, after which logging is performed until achieving satisfactory data quality. Any surface sampling for analysis of trace elements being released from thechemical devices 9 is carried out regularly, for example every hour. - The
well 1 is opened to a second flow depicted "flow 2" infigure 2 , the flow of which is 100 % of maximum flow capacity, and the well is allowed to flow for another twelve hours, after which logging is performed until achieving satisfactory data quality. Any surface sampling for analysis of trace elements being released from thechemical devices 9 is carried out regularly, for example every hour. - The well is shut in by closing one or more
pressure control valves 19 and, if desired, pressure build-up after production is measured. Such measuring of pressure build-up may be carried out substantially continuously over, for example, twelve hours. Upon finishing the logging, theapparatus 3 is retrieved from thewell 1. -
Figure 2b shows the same procedure for a fluid-injectingwell 1. - Thus, the present invention provides an apparatus which surprisingly may allow for quantification of more than one fluid phase in a well flow, simultaneously allowing measuring of the productivity or injectivity of the well.
- As compared with prior art coiled tubing units, the invention will result in simpler logistics with respect to heavy lifting from, for example, a ship to a platform.
- Also with respect to safety, the present invention exhibits considerable advantages relative to the prior art. Upon having run a rigid cable or semi-rigid rod in a controlled manner into the well when shut in, it will remain "parked" until the job is finished. Thus, no activity is carried out in order to move the apparatus during the operation. Any risk to personnel in the area around the logging unit is greatly reduced owing to the fact that the operation is limited only to monitoring that the signals from the fibres in the cable are of good quality. All other work takes place in an approved area, the equipment used being a PC and an interface for converting raw signals into readable data lines providing pressure, temperature, fluid phase and time indication.
Claims (12)
- An apparatus (3) for use when gathering parameters from a well flow in a petroleum well (1) for allowing evaluation of the flow and productivity or injectivity of the well (1), the apparatus (3) including:- a continuous, semi-rigid rod (5) arranged in a manner allowing it to sense the temperature profile of the well (1);- at least two mutually spaced-apart measuring devices and/or fluid phase indicators (9) attached to the continuous, semi-rigid rod (5); and- at least one pressure sensor (11) arranged in a manner allowing it to sense pressure in the well (1), characterized in that the at least two mutually spaced-apart measuring devices and/or fluid phase indicators (9) are disposed around the semi-rigid rod (5); and- wherein the apparatus (3) is placed in a stationary manner in the well (1) when gathering parameters from the well flow.
- The apparatus in accordance with claim 1,
characterized in that the at least two mutually spaced-apart measuring devices and/or fluid phase indicators (9) are one of, or a combination of, two or more of a sensor, a chemical or a trace element. - The apparatus in accordance with claim 1,
characterized in that the semi-rigid rod (5) includes a fibre cable. - The apparatus in accordance with claim 1,
characterized in that the semi-rigid rod (5) includes a plurality of spaced-apart pressure sensors (11). - The apparatus in accordance with any one of the preceding claims, characterized in that the apparatus includes an additional pressure sensor for compression-measuring of the end portion of the apparatus (3) in the well (1), the additional pressure sensor being placed between the semi-rigid rod (5) and a bull nose (13) placed at the end of the apparatus (3) in the well (1).
- The apparatus in accordance with any one of the preceding claims, characterized in that the apparatus (3) is arranged in a manner allowing it to communicate measuring data through the fibre and out of the well (1) while measuring is in progress.
- Apparatus in accordance with claim 6,
characterized in that measuring data from the semi-rigid rod (5) and elements from the fluid phase indicators (9) are conveyed from the well (1) independently of each other. - Apparatus in accordance with any one of the preceding claims, characterized in that the apparatus (3) includes a depth-measuring device.
- A method of gathering parameters from a well flow in a petroleum well (1) for allowing evaluation of the flow and productivity or injectivity of the well (1),
characterized in that the method includes the steps of:- inserting an apparatus (3) according to claim 1 to a desired portion of the well (1); and- keeping the apparatus (3) substantially stationary within the well (1) during gathering of parameters from one or more formation sections of the well (1). - The method in accordance with claim 9,
characterized in that the at least two measuring devices and/or fluid phase indicators (9) include one of, or a combination of, two or more of a sensor, a chemical or a trace element. - The method in accordance with claim 9 or 10,
characterized in communicating results from the measuring devices and elements from the fluid phase indicators to the surface for further processing while the measuring devices and/or fluid phase indicators (9) are stationary in the well (1). - The method in accordance with claim 11,
characterized in conveying measuring data from the semi-rigid rod (5) and elements from the fluid phase indicators (9) independently of each other from the well (1).
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
NO20065913A NO333962B1 (en) | 2006-12-19 | 2006-12-19 | Apparatus for use in obtaining parameters from a well stream and method of using the same. |
PCT/NO2007/000446 WO2008091155A1 (en) | 2006-12-19 | 2007-12-17 | An apparatus for use when gathering parameters from a well flow and also a method of using same |
Publications (3)
Publication Number | Publication Date |
---|---|
EP2102451A1 EP2102451A1 (en) | 2009-09-23 |
EP2102451A4 EP2102451A4 (en) | 2015-10-21 |
EP2102451B1 true EP2102451B1 (en) | 2016-10-12 |
Family
ID=39644678
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP07860914.6A Not-in-force EP2102451B1 (en) | 2006-12-19 | 2007-12-17 | An apparatus for use when gathering parameters from a well flow and also a method of using same |
Country Status (4)
Country | Link |
---|---|
US (1) | US20100059220A1 (en) |
EP (1) | EP2102451B1 (en) |
NO (1) | NO333962B1 (en) |
WO (1) | WO2008091155A1 (en) |
Families Citing this family (6)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8944170B2 (en) * | 2008-11-18 | 2015-02-03 | Ziebel As | Real time downhole intervention during wellbore stimulation operations |
CN102041994A (en) * | 2010-11-12 | 2011-05-04 | 上海科油石油仪器制造有限公司 | Hydrogen sulfide early-warning measuring method |
RU2563855C1 (en) * | 2014-06-16 | 2015-09-20 | Алик Нариман Оглы Касимов | Method to deliver geophysical instruments into horizontal well |
US11118443B2 (en) * | 2019-08-26 | 2021-09-14 | Saudi Arabian Oil Company | Well completion system for dual wellbore producer and observation well |
US11261720B2 (en) | 2020-05-11 | 2022-03-01 | Saudi Arabian Oil Company | Methodology to maximize net reservoir contact for underbalanced coiled tubing drilling wells |
US11636352B2 (en) | 2020-05-13 | 2023-04-25 | Saudi Arabian Oil Company | Integrated advanced visualization tool for geosteering underbalanced coiled tubing drilling operations |
Family Cites Families (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5234058A (en) * | 1990-03-15 | 1993-08-10 | Conoco Inc. | Composite rod-stiffened spoolable cable with conductors |
FR2712628B1 (en) * | 1993-11-15 | 1996-01-12 | Inst Francais Du Petrole | Measuring device and method in a hydrocarbon production well. |
GB9610574D0 (en) * | 1996-05-20 | 1996-07-31 | Schlumberger Ltd | Downhole tool |
NO305181B1 (en) * | 1996-06-28 | 1999-04-12 | Norsk Hydro As | Method for determining the inflow of oil and / or gas into a well |
CA2293686C (en) * | 1997-06-09 | 2008-07-29 | Baker Hughes Incorporated | Control and monitoring system for chemical treatment of an oilfield well |
US7513305B2 (en) | 1999-01-04 | 2009-04-07 | Weatherford/Lamb, Inc. | Apparatus and methods for operating a tool in a wellbore |
NO309884B1 (en) * | 2000-04-26 | 2001-04-09 | Sinvent As | Reservoir monitoring using chemically intelligent release of tracers |
CA2313919C (en) * | 2000-07-17 | 2008-09-23 | C-Tech Energy Services Inc. | Downhole communication method and apparatus |
GB0415223D0 (en) * | 2004-07-07 | 2004-08-11 | Sensornet Ltd | Intervention rod |
-
2006
- 2006-12-19 NO NO20065913A patent/NO333962B1/en not_active IP Right Cessation
-
2007
- 2007-12-17 US US12/520,457 patent/US20100059220A1/en not_active Abandoned
- 2007-12-17 WO PCT/NO2007/000446 patent/WO2008091155A1/en active Application Filing
- 2007-12-17 EP EP07860914.6A patent/EP2102451B1/en not_active Not-in-force
Also Published As
Publication number | Publication date |
---|---|
WO2008091155A1 (en) | 2008-07-31 |
NO333962B1 (en) | 2013-10-28 |
NO20065913L (en) | 2008-06-20 |
US20100059220A1 (en) | 2010-03-11 |
EP2102451A1 (en) | 2009-09-23 |
EP2102451A4 (en) | 2015-10-21 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA2620016C (en) | Methods, systems and apparatus for coiled tubing testing | |
US10465471B2 (en) | Treatment methods for water or gas reduction in hydrocarbon production wells | |
US7565834B2 (en) | Methods and systems for investigating downhole conditions | |
US7159653B2 (en) | Spacer sub | |
EP2102451B1 (en) | An apparatus for use when gathering parameters from a well flow and also a method of using same | |
US6082454A (en) | Spooled coiled tubing strings for use in wellbores | |
CA2921495C (en) | Intelligent cement wiper plugs and casing collars | |
NO339196B1 (en) | Use of fiber optics in coiled tubing in wells in the underground | |
WO2016089523A1 (en) | Energy industry operation characterization and/or optimization | |
EP3517726A1 (en) | Control systems and methods for centering a tool in a wellbore | |
EP3497304B1 (en) | Segmented wireless production logging | |
EP2715035A1 (en) | Optimized pressure drilling with continuous tubing drill string | |
Taggart et al. | New real-time data communication system enhances coiled tubing operations | |
NO20170576A1 (en) | Downhole health monitoring system and method | |
US10822942B2 (en) | Telemetry system including a super conductor for a resource exploration and recovery system | |
US9133665B2 (en) | Detecting and mitigating borehole diameter enlargement | |
CA2802320C (en) | Detecting and mitigating borehole diameter enlargement | |
US20200232318A1 (en) | Wireless Link To Send Data Between Coil Tubing And The Surface | |
GB2525199A (en) | Method of detecting a fracture or thief zone in a formation and system for detecting |
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: 20090709 |
|
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 MT NL PL PT RO SE SI SK TR |
|
RIN1 | Information on inventor provided before grant (corrected) |
Inventor name: WILBERG, TERJE |
|
DAX | Request for extension of the european patent (deleted) | ||
RA4 | Supplementary search report drawn up and despatched (corrected) |
Effective date: 20150921 |
|
RIC1 | Information provided on ipc code assigned before grant |
Ipc: E21B 47/00 20120101ALI20150915BHEP Ipc: E21B 47/06 20120101ALI20150915BHEP Ipc: E21B 49/08 20060101AFI20150915BHEP Ipc: E21B 47/01 20120101ALI20150915BHEP Ipc: E21B 17/20 20060101ALI20150915BHEP |
|
17Q | First examination report despatched |
Effective date: 20160115 |
|
GRAP | Despatch of communication of intention to grant a patent |
Free format text: ORIGINAL CODE: EPIDOSNIGR1 |
|
INTG | Intention to grant announced |
Effective date: 20160527 |
|
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 MT 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: AT Ref legal event code: REF Ref document number: 836712 Country of ref document: AT Kind code of ref document: T Effective date: 20161015 |
|
REG | Reference to a national code |
Ref country code: IE Ref legal event code: FG4D |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R096 Ref document number: 602007048329 Country of ref document: DE |
|
REG | Reference to a national code |
Ref country code: LT Ref legal event code: MG4D |
|
REG | Reference to a national code |
Ref country code: NL Ref legal event code: MP Effective date: 20161012 |
|
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: 20161012 |
|
REG | Reference to a national code |
Ref country code: AT Ref legal event code: MK05 Ref document number: 836712 Country of ref document: AT Kind code of ref document: T Effective date: 20161012 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20161012 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: 20161012 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: 20170113 |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20161012 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: 20161012 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: 20170213 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: 20161012 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: 20161012 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: 20170212 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: 20161012 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: 20161012 |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: R119 Ref document number: 602007048329 Country of ref document: DE |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
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: 20161012 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: 20161012 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: 20161012 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: 20161012 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: 20161012 |
|
REG | Reference to a national code |
Ref country code: CH Ref legal event code: PL |
|
PLBE | No opposition filed within time limit |
Free format text: ORIGINAL CODE: 0009261 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT |
|
PG25 | Lapsed in a contracting state [announced via postgrant information from national office to epo] |
Ref country code: 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: 20170112 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: 20161012 |
|
26N | No opposition filed |
Effective date: 20170713 |
|
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: 20161012 |
|
REG | Reference to a national code |
Ref country code: FR Ref legal event code: ST Effective date: 20170831 |
|
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: 20170102 Ref country code: LU Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20161217 Ref country code: LI Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20161231 Ref country code: CH Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20161231 |
|
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: 20161012 Ref country code: DE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20170701 Ref country code: IE Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES Effective date: 20161217 |
|
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: 20071217 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: 20161012 |
|
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: 20161012 |
|
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: 20161217 |
|
PGFP | Annual fee paid to national office [announced via postgrant information from national office to epo] |
Ref country code: GB Payment date: 20191220 Year of fee payment: 13 |
|
GBPC | Gb: european patent ceased through non-payment of renewal fee |
Effective date: 20201217 |
|
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: 20201217 |