Multiple zones frac tool

[0001] The disclosures herein relate generally to a device and a method for the hydraulic fracturing, also referred to as fracing, of multiple zones in a well bore.

[0002] During the production of oil from an oil well, one of the well bore operations involves fracing multiple zones of the well bore. The term frac means introducing a fluid into a sub-surface area of earth which is likely to yield a hydrocarbon product. The frac fluid facilitates collection of the product by creating a conduit in the zones in which the product is trapped. The product can then flow through the conduit into the well bore where the product can be collected. The fracing operations are often conducted after the well has been placed into production, therefore it is important that the fracing operation be conducted as quickly and efficiently as possible.

[0003] Some of the known methods to accomplish this involve retrievable methods where all elements or tools used in the fracing process are removed from the well bore. One method includes a bridge plug and a packer used with either jointed tubing or coiled tubing. A frac port is located between the bridge plug and the packer. Another method involves using at least two cups opposing each other with a frac port located between the cups. Still another method uses a straddle packer which straddles a zone. A cup is positioned above the zone. The frac port is located between the straddle packer and the cup.

[0004] Disadvantages of the retrievable methods are that the tools are complex and could become stuck in the well. A stuck tool would require fishing the tool out, drilling through the tool, or leaving the tool in the well. Drilling through the tool is difficult because the tool is formed of heat treated steel.

[0005] A more recent method involves the use of drillable tools, i.e., tools that are made of softer material and can be drilled out of the well. However, use of this method involves a first trip down the well to set a bridge plug below the frac zone and a second trip down the well to do the frac job. However, this process must be repeated for each zone. Therefore, if there are ten zones to be treated, twenty trips down the well are required. This is disadvantageous because it is time consuming and each trip causes wear on the coiled tubing. Therefore, cost and complexity of the operation are major disadvantages.

[0006] FIGS. 1-3 are diagrammatic views illustrating an embodiment of packers sequentially positioned in a well for treating zones in the well.

[0007] FIG. 4 is a cross-sectional side view illustrating a packer and stinger.

[0008] FIGS. 5-8 are cross-sectional side views partially illustrating portions of the packer and stinger of FIG. 4.

[0009] A service tool is provided for individually isolating and pumping fluid into multiple zones in a well or subterranean formation. A single trip downhole (into the well bore) is required to treat one or more zones. A second trip may be required to drill out drillable packers left behind in the casing. An advantage of this tool is that it can be used with either jointed tubing or coiled tubing.

[0010] The tool includes a packer assembly 10 located in a well bore 12, FIG. 1. The well bore 12 can be either a cased completion as shown in FIG. 1 or an openhole completion. The packer assembly 10 includes a stinger 16 carrying a plurality of packers 18a, 18b, 18c in series. Each packer 18a, 18b, 18c is separably connected to each adjacent packer at a surface F. The stinger 16 is sequentially removable from the packers 18a, 18b, 18c so that after each packer 18a, 18b, 18c is sequentially secured by a securing means 22 to the well bore 12 and the zone below the packer is treated, the stinger 16 is withdrawn from the most distal secured packer, which remains in the well bore 12. For example, packer 18a is secured in well bore 12 by securing means 22 and zone 20a below packer 18a is treated by pumping fluid into the zone 20a. The stinger 16 is withdrawn from secured packer 18a which remains in well bore 12, thus continuing to isolate zone 20a, and the next packer 18b is sequentially secured to the well bore 12, FIGS. 2 and 3, and the zone 20b between packers 18a and 18b is treated. The stinger 16 is further withdrawn from secured packer 18b which remains in well bore 12, and so on, until each packer 18a, 18b, 18c is positioned adjacent a respective treated zone 20a, 20b, 20c and the stinger 16 is eventually completely withdrawn from the well bore 12. If the hole is not suitable, then in some instances, the first zone to be treated may be between packers 18a and 18b.

[0011] The stinger 16 is elongated and includes an outer diameter 24 slidably mounted in a passage formed in respective packer 18a, FIG. 4. An inner fluid passage 26 extends through stinger 16. A generally cylindrical wall of stinger 16 defines a ported mandrel 28 having a plurality of ports 28a and 28b. A collet mandrel 30 is formed on stinger 16 adjacent a distal open end 32 and includes a collet 34 and a plurality of elongated slots 36 adjacent the collet 34. The elongated slots 36 provide for radial compressibility of the collet mandrel 30. A ball seat 38 is also provided adjacent distal open end 32, for use in connection with a ball 40, discussed below.

[0012] Each packer 18a, 18b, 18c is identical and therefore, only one packer 18a is described in detail. In order to better illustrate the details of packer 18a, FIGS. 5-7 each include a portion of packer 18a as illustrated in its entirety in FIG. 4.

[0013] A first or distal portion A, FIGS. 4 and 5, of packer 18a is adjacent distal open end 32 of stinger 16. Distal portion A includes a mule shoe 42 fixedly connected to a packer mandrel 44. An o-ring seal 46 is seated in packer mandrel 44 and sealingly engages outer diameter 24 of stinger 16. A shoulder 43 is provided on mule shoe 42 for engaging collet 34.

[0014] A second portion B, FIGS. 4 and 6 of packer 18a includes the securing means 22 mounted on the packer mandrel 44 and comprising an upper slip 46 and a lower slip 48. The upper slip 46 is provided to ride on a surface 50a of an upper wedge 50. Similarly, the lower slip 48 is provided to ride on a surface 52a of a lower wedge 52. Each slip 46 and 48 includes a plurality of teeth 53 for gripping engagement with well bore 12. A plurality of resilient packer elements 54 are mounted between the upper wedge 50 and the lower wedge 52. Also, an upper extrusion limiter 56 is between the upper wedge 50 and the packer elements 54, and a lower extrusion limiter 58 is between the lower wedge 52 and the packer elements 54. The elements referred to by the term lower are meant to be adjacent to the distal portion A.

[0015] A third portion C, FIGS. 4 and 7 of packer 18a includes the packer mandrel 44 having a setting sleeve 60 sealingly mounted on packer mandrel 44 by a pair of o-ring seals 62 and 64. Also, an o-ring seal 66 is seated in packer mandrel 44 and sealingly engages outer diameter 24 of stinger 16. A flapper valve 68 is mounted on a flapper valve body 61, and is maintained in an open position 0 by engagement with outer diameter 24 of stinger 16. However, flapper valve 68 is biased by a spring 69 to pivot at a pivot point 70 to a closed position S, shown in phantom outline, upon removal of stinger 16 from packer element 18a.

[0016] A port 72 is formed in packer mandrel 44 adjacent the ports 28b of stinger 16. A chamber 76 is in fluid communication with port 72. Fluid pressure in chamber 76 moves the setting sleeve 60 to set the packer 18a.

[0017] In operation, ball 40, FIGS. 4-8, sealingly engages ball seat 38 to seal distal open end 32 of inner fluid passage 26. Pressurized fluid exits ports 28a and 28b and enters port 72 and chamber 76. Pressure acting on the differential area of setting sleeve 60 defined between o-ring seals 62 and 64 in a direction D1, activates upper slip 46 to ride on surface 50a and extend radially into engagement with well bore 12. Pressure also acts on the differential area between the o-ring seals 62 and 64 to move packer mandrel 44 relative to setting sleeve 60 in a direction D2, opposite D1. Movement of packer mandrel 44 also moves mule shoe 42 in direction D2 and thus activates lower slip 48 to ride on surface 52a, and extend radially into engagement with well bore 12. Movement of slips 46 and 48 urges wedges 50 and 52, respectively, to move toward each other which also moves upper extrusion limiter 56 and lower extrusion limiter 58 toward each other, thus compressing packer elements 54 and radially extending packer elements 54 and extrusion limiters 56 and 58. Packer elements 54 are thus radially extended into sealing engagement with well bore 12.

[0018] After a packer is set, stinger 16 is moved so that ports 28b are below a bottom end E of mule shoe 42. The fluid used for hydraulic fracturing is released under high pressure through the ports 28a and 28b. After fracturing is completed, removal of stinger 16 from the secured packer as stated above, permits flapper valve 68 to pivot and seal and the remaining packers are separated from the secured packer. The process is then repeated as the remaining packers are sequentially secured and separated. The flapper valve 68 provides the advantage that the operator can let the well produce immediately after fracing, and drill out the drillable packers at a convenient time.

[0019] Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims.