Not applicable.
Not applicable.
Not applicable.
This disclosure relates to systems and methods for testing earth formations through a tubing string, and more particularly to a system for inflating a packer to isolate a formation and opening a formation flow path for formation testing and for opening a circulation flow path for removal of formation fluids from a tubing string after testing.
In drilling oil and gas wells, it is desirable to obtain information concerning potentially productive earth formations penetrated by the well as each such zone is drilled through. For example, it is desirable to obtain a sample of fluids produced from each formation to determine whether it is oil, gas or water. It is also desirable to measure the flow rate of the fluids and the temperature and pressure in the zone. Numerous systems and methods have been used for these purposes.
Early systems required that the drill string be removed from the borehole. Then a test system would be lowered back into the borehole, possibly on the end of the drill string from which the drill bit had been removed. Such drill stem test systems usually included a packer for isolating the zone to allow pressure testing. They usually included pressure and temperature sensors and recorders and chambers for collected fluid samples. While these are able to collect good information, they are expensive to operate because of the need to remove and replace the drill string twice in order to test and then return to drilling.
To reduce costs, various systems have been developed for performing formation testing through a drill string without pulling the drill string and without removing the drill bit. However, these systems tend to be complicated and therefore expensive and prone to failure. Systems for inflating and deflating packers to provide the necessary formation isolation have been complicated, often including down hole pumps and fluid reservoirs. Such systems typically occupy space in the normal mud flow path through the drill string and interfere with running test equipment through the mud flow path to the bottom hole location.
Therefore, there is a need for simple and robust systems suitable for use in a drill string for inflating and deflating formation isolating packers and for opening and closing flow paths for formation testing and for reverse circulation.
In one embodiment the present disclosure provides a borehole tubular element having a port from an internal flow path to the outer surface of the element, a sliding sleeve for controlling flow through the port and shifting tool for moving the sleeve to selectively open or close the port. The sleeve has a radially compressible portion which carries an external profile which mates with a complementary internal profile in the tubular element in a first sleeve position. The shifting tool has two shoulders for engaging and moving the sleeve. A first shoulder engages the upper end of the sleeve to drive the sleeve down to a second position. In the second position the sleeve external profile is forced out of the tubular element recessed profile compressing the sleeve. When compressed, an internal profile on the sleeve has an inner diameter smaller than the second shoulder on the shifting tool. Upon moving the shifting tool up hole, the second shoulder engages the sleeve internal profile and moves the sleeve up until its external profile enters the tubular element internal profile and the sleeve expands to its original diameter.
One embodiment of the present disclosure provides a drill string joint having an external inflatable packer for isolating a borehole zone. An internal packer inflation sleeve controls flow of fluid through a packer inflation port between the drilling fluid flow path in the joint and the inflatable packer. A packer inflation shifting tool transported down the drilling fluid flow path carries a seal for closing the drilling fluid flow path to the drill bit and a shoulder for shifting the sliding sleeve to open the packer inflation port so that drilling fluid pressure can inflate the packer. The packer inflation shifting tool includes a second shoulder for moving the sliding sleeve back to close the packer inflation port when the tool is transported back up the drilling fluid flow path.
In one embodiment, the inflatable packer has one end fixed to the drill string joint. The other end is connected to an external sliding sleeve. The joint includes a formation fluid port which is closed by the sliding sleeve when the packer is not inflated. Upon inflation of the packer, its length is reduced and the sliding sleeve moves to open the formation fluid port.
In one embodiment, a circulation port is provided above the packer. An internal circulation control sleeve controls flow of fluids between the mud flow path and the annulus between the drill string and the borehole. A circulation shift tool transported down the mud flow path has a first shoulder for shifting the circulation control sleeve to open the circulation port so that drilling fluid may be flowed down the annulus and up the drilling fluid flow path or vice versa. The circulation shift tool includes a second shoulder for moving the sliding sleeve back to close the circulation port when the tool is transported back to the drilling fluid flow path.
Four fluid flow paths are provided through the mandrel 36. A conventional drilling fluid flow path 42 is provided through the central axis of the mandrel 36. This path 42 allows drilling fluids to be pumped from up hole to drill bit 20 down hole from the assembly 24. The flow path 42 includes a reduced diameter portion 44 at its lower end, thereby forming a shoulder 46. The formation fluid port 30 of
The packer 26 is carried on the outside of mandrel 36. An upper end 52 of packer 26 is attached to the outer surface of mandrel 36 with a nonmovable fluid tight seal. That is, upon expansion and contraction of packer 26, its upper end 52 does not move relative to the mandrel 36. A lower end 54 of packer 26 is attached to a sliding sleeve 56. The sleeve 56 in this embodiment is manufactured as three separate sections 58, 60 and 62, which, when assembled, function as a single sliding sleeve. The attachment of the lower end 54 of packer 26 to section 58 of sleeve 56 is also a fluid tight seal which does not move relative to the sleeve 56, although the sleeve 56 moves relative to mandrel 36 upon inflation and deflation of the packer 26.
Sleeve 56 sections 58 and 60 together define an annular space 64 around mandrel 36 in which may be carried a coil spring 66. The spring 66 is captured between a spring stop ring 68 attached to the outer surface of mandrel 36 and a shoulder 70 on the inner surface of sleeve section 60. The spring 66 aids in deflating and resetting the packer 26 as explained below. Since pressure differential should be sufficient to deflate and reset the packer 26, the spring 66 is not essential but is preferred. A high pressure sliding seal 72 is provided between shoulder 70 and the outer surface of mandrel 36. The annular space 64 is in fluid communication at its upper end with space between packer 26 and mandrel 36, but is sealed at its lower end by the sliding seal 72. The lowermost section 62 of sleeve 56 is carried on the lower end of section 60, and in this drilling configuration covers the formation flow ports 30. A pair of sliding seals 74 are carried between the sleeve 56 section 62 and the outer surface of mandrel 36 to seal the ports 30 in this drilling configuration.
The test assembly 24 includes two internal sliding sleeves carried in the drilling fluid flow path 42 for controlling fluid flow through ports 48 and 50. One sliding sleeve 76 acts as a packer inflation port 48 control valve. The upper end 78 of sleeve 76 is a hollow cylinder with a pair of sliding seals 80 between the sleeve 76 and the inner surface of mandrel 36, i.e. the wall of drilling fluid flow path 42. In this drilling configuration, the seals 80 are positioned on opposite sides of the packer inflation port 48 and prevent flow of fluids through port 48. A central portion 82 of sleeve 76 is axially slotted so that it is radially compressible. This structure is sometimes referred to as a collet. Near the center of central portion 82, an external profile 84 extends into a mating recessed profile 86 in the wall of flow path 42. The profiles 84 and 86 are complementary and designed to mate to enable external profile 84 to fit inside recessed profile 86. Complementary profiles are not required to be identical, although in some embodiments the profiles may be exact complements, but only required to have complementing shapes which may fit and engage (mate) in the desired positions. In the disclosed embodiment, each profile 84, 86 has an upper surface substantially at right angles to the axis of mandrel 36, so that when engaged they stop further up hole movement of the sleeve 76. Each profile 84, 86 has a lower surface slanted at an angle less than ninety degrees relative to the axis of mandrel 36, so that with sufficient down hole force on the sleeve 76, the profile 84 will move inward and out of the profile 86 allowing the sleeve 76 to move down hole. Until such force is applied, the mating profiles 84 and 86 hold the sleeve 76 in position to keep packer inflation port 48 closed. The sleeve 76 may also include an unslotted lowermost section 88.
In one embodiment, a second sliding sleeve 90 is positioned in the upper end of mandrel 36 and functions as a control valve for the circulation port 50. It is very similar in construction to the sleeve 76. An upper end of sleeve 90 is a hollow cylinder with a pair of sliding seals 92 between the sleeve 90 and the inner surface of mandrel 36, i.e. the wall of drilling fluid flow path 42. In this drilling configuration, the seals 92 are positioned on opposite sides of the circulation port 50 and prevent flow of fluids through port 50. A lower end of sleeve 90 is axially slotted so that it is radially compressible. On the lowermost end of sleeve 90, external profiles 94 extend from the sleeve 90 and mate with corresponding recessed profile 96 in the inner wall of flow path 42. These mating profiles 94 and 96 have upper and lower surfaces like those on profiles 84 and 86, which prevent up hole movement of sleeve 90, but allow down hole movement if sufficient down hole force is applied to the sleeve 90 to move the profiles 94 inward and out of profiles 96. Until such down hole force is applied, these mating profiles 94 and 96 hold the sleeve 90 in position to keep circulation port 50 closed.
In the
When the configuration of
If desired, the packer inflation port 48 could be positioned directly under the packer 26. This can be done by moving the shoulder 46 up the drilling fluid flow path 42 by the appropriate distance. The tool 100 would not need to be changed. However, the illustrated embodiment is preferred for several reasons. If the port 48 is placed directly under the packer 26, the packer may be damaged by fluids flowing through the port 48 and impacting the inner surface of packer 26, especially if any particulate matter is in the drilling fluid. Particulate matter may also be trapped under the packer 26 when it is deflated, preventing complete deflation and damaging the packer 26 during continued drilling operations. In the preferred embodiment, the drilling fluid travels up hole through the spring annulus 64 and around spring 66 before it enters the packer 26. This allows separation of particulates from the drilling fluid before it reaches the packer 26. Particulates may be trapped in the chamber 64 which is made of more rugged materials than the inflatable packer 26. In this manner chamber 64 and spring 66 may act as a rudimentary filter reducing contamination by larger particulate matter.
In
As noted above, after formation testing, the drill string is typically filled with produced fluids. It is usually desirable to collect these fluids with little or no mixing with drilling fluids or other fluids which may be produced elsewhere in the borehole. As a result, it is normal practice to reverse circulate the well, i.e. pump drilling fluid down the annulus 34 instead of down the drill string, and drive the produced fluids to the surface through the drill string. However, it is also normal to have a float collar 22 as shown in
In
Before closing the port 50, and with the shifting tool 130 in position as shown in
In the embodiment described above, the circulation port 50 and its control sleeve 90 are part of the same joint or sub on which the packer 26 and other elements are assembled. It is apparent that the port 50 and sleeve 90 could be part of a separate joint or sub and could be assembled as part of a drill string at any distance up hole from the packer 26.
The test assembly 24 of the present disclosure provides a simple and cost effective system for testing earth formations through a drill string while drilling wells. The test assembly 24 may be included in a drill string as shown in FIG. 1. After a potentially productive zone 18 has been drilled through, drilling is stopped. The packer inflation tool 100 is then run down the drill string to close the drilling fluid path to the drill bit 20 and open the packer inflation port 48. Drilling fluid pressure is then increased to inflate the packer 26, isolating the zone 18 and opening the formation test port 30. The inflation tool 100 is then removed from the drill string, which closes the packer inflation port 48. Formation testing is then performed. When testing is completed, the inflation tool 100 is run back to the assembly 24, where it opens the port 48, deflating the packer 26. Deflation of packer 26 moves sleeve 56 and closes the formation port 30. The tool 100 is then withdrawn, again closing the inflation port 48. The circulation tool 130 is then run down to the circulation sleeve 90 to open the circulation port 50. Produced fluids in the drill string are then recovered by reverse circulation of drilling fluid. Once the fluids are recovered, the circulation tool 130 is withdrawn, closing the circulation port 50.
After such a test cycle has occurred, drilling can be continued. When another potentially productive zone has been drilled through, the same testing procedure may be repeated. The test process can be repeated as often as desired, without removing and reinstalling the drill string.
While the test assembly 24 has been shown in use as part of a drill string, it is apparent that the apparatus of the present disclosure may be used in other tubular goods commonly used in boreholes. For example, it could be used as part of a separate work string, test string or production string for setting a packer. The string could be run into a cased well and the packer deployed to seal the annulus between the string and the casing. All parts of the assembly 24 do not necessarily need to be used together. For example, the circulation port 50 and its control sleeve 90 are preferred if the tubing string has a float valve which prevents reverse circulation of drilling fluid. But, even if such a valve is in the string, it is possible to use normal circulation to pump produced fluids out of the well and the reverse circulation port would not be needed. The combination of the inflatable packer 26 with the external sliding sleeve 56 and port 30 may be useful in various down hole systems without the rest of the test assembly 24. For example, the port 30 could be used for injecting fluids into the formation, as opposed to producing fluids from the formation. In such injection processes, it is often necessary that a packer be set above the injection point to prevent the fluids from flowing up the annulus. The sleeve 56 would prevent the injection of fluids until the packer is set.
In another embodiment, the present system may be employed to perform a formation integrity or formation leak off test. For example, a test may be conducted after cementing the surface pipe and may also be conducted after the intermediate casing if the well profile calls for an intermediate casing to be used. After cementing the casing in place and waiting an appropriate time, an additional 5-10 feet of drilling is performed below the casing. The string is then preferably positioned so that the inflatable packer inflates against the casing sealing off the open hole area below the casing. With the formation flow port opened, the mud is pressured up on the open hole slowly and the mud flow monitored to note the pressure at which the open hole starts to take fluid into the formation. This pressure is than calculated back to a specific fluid weight to define a maximum fluid weight which can be used while drilling the well with reduced risk of forcing drilling fluid into the formation itself. Using tools disclosed herein, an operator should be able to drill and then test without having to make a trip to run a casing packer. In another embodiment a similar test may be run further down in the drilling process to check any formations that might be of concern. In this embodiment the inflatable packer would likely be inflated in the open hole rather than in the cased formation.
It is apparent that various changes can be made in the apparatus and methods disclosed herein, without departing from the scope of the invention as defined by the appended claims.
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Number | Date | Country | |
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20040206496 A1 | Oct 2004 | US |