Well with two casings

Abstract

A well (10) in a geological structure (11), the well (10) comprising: a first casing string (12a) and a second casing string (12b) inside the first casing string (12a) and defining a first inter-casing annulus (14a) therebetween. A wirelessly controllable valve (16a), in the second casing string (12b) provides fluid communication between the first inter-casing annulus (14a) and a second casing bore (14b). The first or second casing string are less than 250 meters longer in length than the second or first casing string respectively and may be the same length. The distal ends of the first and second casing strings may be in a substantially impermeable formation (11). A number of benefits can be realised from such an arrangement. For example, in the event of a “blow-out”, kill fluid may be introduced into the well bore without the need to drill a relief well.

Claims

1. A well in a geological structure, the well comprising: a first and a second casing string, the second casing string inside the first casing string; the first and second casing strings defining a first inter-casing annulus therebetween, the second casing string defining a second casing bore therewithin; a primary fluid flow control device in the second casing string to direct a fluid introduced into the first inter-casing annulus to the second casing bore; wherein the first or second casing string is less than 250 meters longer in length than the second or first casing string respectively; and wherein the primary fluid flow control device comprises a wirelessly controllable valve; and in an open position, the primary fluid flow control device has a cross sectional fluid flow area of at least 100 mm.sup.2, the cross sectional fluid flow area being sufficient to enhance the fluid to flow from the first inter-casing annulus to the second casing bore.

2. A well according to claim 1, wherein the first or second casing string is less than 50 meters longer in length than the second or first casing string respectively.

3. A well according to claim 1, wherein the first and the second casing strings are the same length.

4. A well according to claim 1, further comprising at least one communication path providing fluid communication between the reservoir and the well, and wherein the primary fluid flow control device is within 1500 m from the communication path of the well between the reservoir and the well.

5. A well according to claim 1, wherein the primary fluid flow control device further comprises a rupture mechanism.

6. A well according to claim 1, wherein the primary fluid flow control device further comprises a check valve.

7. A well according to claim 1, wherein the wirelessly controllable valve includes a metal to metal seal.

8. A well according to claim 1, wherein the wirelessly controllable valve is moveable to a check position which is between a closed position and an open position.

9. A well according to claim 1, the well further comprising one or more sensors at, in or on one or more of a face of the geological structure, the well, an annulus, a casing bore, a production string, a completion string, a tubing string, a sub, and a drill string.

10. A well according to claim 9, wherein at least one of the one or more sensors is a wireless sensor.

11. A well according to claim 10, wherein at least one of the one or more sensors is an acoustic and/or electromagnetic wireless sensor.

12. A well according to claim 9, wherein at least one of the one or more sensors is electrically powered.

13. A well according to claim 1, wherein the valve of the primary fluid flow control device is at least one of an acoustic and electromagnetic wirelessly controllable valve.

14. A well according to claim 1, wherein the primary flow control device is electrically powered.

15. A well according to claim 1, wherein at least one of a transmitter, receiver or transceiver is attached to one or more of the first and second casing strings, a well internal tubular, a production tubing, a completion tubing, and a drill pipe, is electrically, optionally battery powered.

16. A well according to claim 1, wherein the first and second casing strings each having a proximal and a distal end, the proximal ends being the end closest to the surface.

17. A well according to claim 16, wherein the proximal end of the first casing string within 5 meters of the proximal end of the second casing string, the distal end of the first casing string within 50 meters of the distal end of the second casing string.

18. A well according to claim 16, wherein the distal ends of the first and second casing strings are in an impermeable or at least substantially impermeable formation.

19. A well according to claim 16, wherein the distal ends of the first and second casing strings are not in a permeable formation.

20. A well according to claim 16, wherein the distal end of the second casing string is inside the first casing string.

21. A well according to claim 16, wherein the primary fluid flow control device is within 500 m of the shallower of the distal ends.

22. A method of fluid management utilizing a well; the well comprising: a first and a second casing string, the second casing string inside the first casing string, the first and second casing strings each having a proximal and a distal end, the proximal ends being the end closest to the surface; the first and second casing strings defining a first inter-casing annulus therebetween, the second casing string defining a second casing bore therewithin; a primary fluid flow control device in the second casing string to provide fluid communication between the first inter-casing annulus and the second casing bore; wherein the first or second casing string is less than 250 meters longer in length than the second or first casing string respectively; and wherein the primary fluid flow control device comprises a wirelessly controllable valve; in an open position the primary fluid flow control device has a cross sectional fluid flow area of at least 100 mm.sup.2; and the method including the steps of introducing a fluid into the first inter-casing annulus; opening the primary fluid flow control device; and directing the fluid between the first inter-casing annulus and the second casing bore.

23. A method of fluid management according to claim 22, wherein the well further comprises a fluid port in the first inter-casing annulus, the method including the step of introducing a fluid into the first inter-casing annulus through the fluid port.

24. A method as claimed in claim 22, comprising directing fluids through the primary fluid flow control device whilst drilling.

Description

(1) Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

(2) FIG. 1 is a cross-sectional view of a well during construction;

(3) FIG. 2 is a cross-sectional view of the same well during drilling; and

(4) FIG. 3 is a cross-sectional view the same well when completed.

(5) FIG. 1 shows a well 10 in a geological structure 11. The well 10 has a first 12a and a second 12b casing string. The first and second casing string each having a proximal and distal end, the proximal ends are closest to the surface 15. The distal ends are closest to a permeable formation of the reservoir 13. The second casing string 12b is inside the first casing string 12a. The first 12a and second 12b casing strings define a first inter-casing annulus 14a therebetween. The second casing string 12b defines a second casing bore 14b therewithin. A primary fluid flow control device 16a in the second casing string 12b provides fluid communication between the first inter-casing annulus 14a and the second casing bore 14b. The distal ends of the first 12a and second 12b casing strings are in an impermeable formation 11, not a permeable formation 13 of the reservoir.

(6) A fluid (not shown) is introduced into the first inter-casing annulus 14a through a fluid port 18. The primary fluid flow control device 16a is then opened and the fluid (not shown) directed between the first inter-casing annulus 14a and the second casing bore 14b. The fluid has not been shown in any of the figures so as not to over complicate the drawings.

(7) The primary fluid flow control device 16a comprises a valve and a rupture mechanism.

(8) The bottom of both the first 12a and second 12b casing strings has been cemented 23h. The fluid, in this case a drilling mud (not shown), is sealed in the first inter-casing annulus 14a, at the top by a casing hanger 21 and at the bottom by the cement 23h.

(9) The second casing string 12b has sensors 20a to measure fluid pressure and density in the first inter-casing annulus 14a. Data from the sensors 20a is used to optimise properties of the fluid that is directed between the annulus 14a and casing bore 14b. Additionally, the sensors 20a on the second casing string 12b may be ported to measure fluid pressure and density in the first inter-casing annulus 14a and the second casing bore 14b.

(10) Using the sensors 20a the pressure and density of the fluid in the first inter-casing annulus 14a and second casing bore 14b are measured before opening the primary fluid flow control device 16a and directing the fluid from the first inter-casing annulus 14a into the second casing bore 14b.

(11) A wireless electromagnetic signal is transmitted through the well 10 to open the primary fluid flow control device 16a and direct the fluid between the first inter-casing annulus 14a and the second casing bore 14b. Alternatively the wireless signal is an acoustic wireless signal.

(12) In an open position, the primary fluid flow control device 16a has a cross-sectional fluid flow area of more than 100 mm.sup.2.

(13) The sensors 20a are coupled to acoustic transceivers (not shown). The sensors 20a measure the temperature, pressure and density of the fluid. Alternatively, the sensors are coupled to electromagnetic transceivers.

(14) It may be an advantage of the present invention that access and fluid control into and/or between the first inter-casing annulus 14a and the second casing bore 14b has now been made possible by use of the first fluid flow control device 16a. Conventionally, in a subsea well the first inter-casing annulus is sealed at the top and the bottom and circulation through this annulus is not possible.

(15) FIG. 1 shows an embodiment of the well that may be a subsea well and incorporating a non-conventional feature of the fluid port 18.

(16) The fluid port may be wirelessly controlled.

(17) FIG. 2 shows the same well during the operation of drilling through the reservoir. The drill string has been removed from the well 110. Features of the well shown in FIG. 1 that are also shown in FIG. 2 have been given the same reference number with a prefix 1, so the first casing string is 12a in FIGS. 1 and 112a in FIG. 2. Other well control structures may be present that are not shown.

(18) FIG. 2 shows a casing bore 114b that can be managed and controlled by flowing fluid from the outside of the well to the inside, through the fluid port 118 into the first inter-casing annulus 114a, through the primary fluid flow control device 116a into the second casing bore 114b. The lowermost or distal end of the first casing string 112a is 40 meters from the interface 127 between the reservoir or permeable formation 113 and the impermeable formation 111. The interface 127 is also referred to as an upper communication path.

(19) Up-to-date data can be collected from the sensors 120a which provide information on the conditions in the first inter-casing annulus 114a, also referred to as the B annulus, and casing bore 114b. If the downhole conditions are monitored, usually via wireless data collection, the drilling mud density and volume required to be pumped into the well/formation(s) can be calculated to avoid the possibility of causing a subterranean blow-out by rupturing the casing string and surrounding formation(s).

(20) It may be an advantage of the present invention that the sensor 120a provides means of measuring the well bore pressure proximate to the reservoir 113. Conventionally this would not be possible when an internal string is not present in the well. This provides useful data for the method of fluid management.

(21) In this embodiment we have the option to reclose the inter-casing valve 116a to maintain the integrity of the casing string 112b.

(22) Embodiments of the present invention provide a feedback system which allows better management of a hazardous control and/or kill procedure, because it is based on sensor readings rather than estimates of for example the well pressure. Moreover, monitoring can continue as the well is being controlled and/or killed, so that the control/kill procedure is adjusted and optimised according to the information being received.

(23) It may be an advantage of the present invention that the well provides for significantly quicker control of a well compared to known methods, such as re-entering a well by capping and installing a new well internal tubular. The saving may be several days, weeks or even months, reducing the potential damage to the surrounding environment as well as saving a very significant amount of time and money.

(24) The primary fluid flow control device 116a is low and deep in the well. This is particularly useful for high temperature and/or high pressure wells.

(25) Internal tubulars (not shown in FIG. 2) may be present, such as a drill string. The well of the present invention provides the ability to circulate fluid in the well, particularly when a drill string is not present.

(26) FIG. 3 shows a completed well with an inner string, in this embodiment a tubular 225. The tubular 225 defines an inner bore 214d therewithin. Features of the well shown in FIGS. 1 and 2 that are also shown in FIG. 3 have been given the same reference number with a prefix 2, so the first casing string is 12a in FIGS. 1 and 212a in FIG. 3.

(27) FIG. 3 shows a well 210 in which fluid flow can be managed and controlled by flowing fluid in a cascade from the outside of the well to the inside, through the fluid port 218 into the first inter-casing annulus 214a, through the primary fluid flow control device 216a into the second casing bore 214b and back out the well through the fluid port 219.

(28) The well in the geological structure 211 comprises a reservoir 213 that contains hydrocarbons. There is an uppermost communication path 229, that is the communication path that is closest to surface (at the top of FIG. 3). The communication path 229 is a perforation created in a liner 212c by a perforating gun. The lowermost or distal end of the first casing string 212a is 45 meters from the uppermost communication path 229 of the well.

(29) The distal ends of the first 212a and second 212b casing strings are in an impermeable formation 211, not the permeable formation 213 of the reservoir. The impermeable formation may be and/or may be described as a substantially impermeable formation. The permeable formation may be and/or may be described as a substantially permeable formation.

(30) The first casing string 212a is less than 100 meters longer in length than the second casing string 212b. The proximal end of the first casing string 212a is within 5 meters of the proximal end of the second casing string 212b. The distal end of the first casing string 212a is within 50 meters of the distal end of the second casing string 212b.

(31) In one embodiment, the well of the present invention can be used to control fluid flow in the well in the event of the failure of the packer 224 or casing hanger 222.

(32) In a further embodiment a fluid port may be provided in the internal string and fluid managed via this port rather than port 219.

(33) In alternative embodiments the inner string may be any other tubular string, such as a drill string, a completion string, a production string, a test string, drill stem test (DST) string, a further casing string and liner.

(34) Devices such as fluid control devices and sensors associated with strings, such as casing strings, tubing strings, production strings, drilling strings, may be associated with a sub-component of the string such as tubular joints, subs, carriers, packers, cross-overs, clamps, pup joints, and collars etc.

(35) Improvements and modifications may be incorporated herein without departing from the scope of the invention.