METHODS AND TOOLS FOR MULTIPLE FRACTURE PLACEMENT ALONG A WELLBORE

Abstract

The invention discloses a tool for use in a wellbore, comprising: a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; and b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 61/346,306, filed May 19, 2010, which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The invention relates to methods for treating subterranean formations. More particularly, the invention relates to a tool for fracturing subterranean formations.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Hydrocarbons (oil, condensate, and gas) are typically produced from wells that are drilled into the formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs or damage to the formation caused by drilling and completion of the well, the flow of hydrocarbons into the well is undesirably low. In this case, the well is “stimulated” for example using hydraulic fracturing, chemical (usually acid) stimulation, or a combination of the two (called acid fracturing or fracture acidizing).

In hydraulic and acid fracturing, a first, viscous fluid called the pad is typically injected into the formation to initiate and propagate the fracture. This is followed by a second fluid that contains a proppant to keep the fracture open after the pumping pressure is released. Granular proppant materials may include sand, ceramic beads, or other materials. In “acid” fracturing, the second fluid contains an acid or other chemical such as a chelating agent that can dissolve part of the rock, causing irregular etching of the fracture face and removal of some of the mineral matter, resulting in the fracture not completely closing when the pumping is stopped. Occasionally, hydraulic fracturing can be done without a highly viscosified fluid (i.e., slick water) to minimize the damage caused by polymers or the cost of other viscosifiers.

It is an object of the present invention to provide an improved method of fracturing by using a new tool deployed in the well.

SUMMARY

In a first aspect, a tool for use in a wellbore, comprises a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: (a) fracturing the subterranean formation through a first stage at predefined first locations; and (b) fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations.

In a second aspect, a tool for use in a wellbore, comprises a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: (a) fracturing the subterranean formation through a first stage at predefined first locations; (b) fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; and (c) fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s).

In a second aspect, a tool for use in a wellbore, comprises a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: (a) fracturing the subterranean formation through a first stage at predefined first locations; (b) fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; (c) fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s); and (d) fracturing the subterranean formation through a n-stage at n locations wherein each location from the n locations is localized between the one of the preceding locations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1a, 1b, 1c, 1d and 1e are used as an example to illustrate the sequence of hydraulic fracturing according to embodiments disclosed herewith.

FIGS. 2a and 2b illustrate the symmetrical effect that result in the third stage fracture (numbered 3) of the previous embodiment in FIG. 1a.

FIGS. 3a, 3b and 3c illustrate schematically tools according to embodiments disclosed herewith.

FIGS. 4a, 4b, 4c and 4d show example of stages to illustrate the sequence of hydraulic fracturing according to embodiments disclosed herewith.

DESCRIPTION

At the outset, it should be noted that in the development of any actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system and business related constraints, which can vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The description and examples are presented solely for the purpose of illustrating embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range disclosed and enabled the entire range and all points within the range.

The application discloses a method of delivery for more closely spaced multiple hydraulic fracture treatments along a deviated, horizontal or extended reach well. These fractures are typically placed in sequence/stages starting from the toe of the well and moving towards the heel. It has been noted that increasing the number of hydraulic fracture treatments along horizontal wells, in particular for shale gas wells, results in significant increase of the production. Shale gas formation characteristics seem to favor closer spacing fracture treatments than economically advisable in more permeable reservoirs. However, there is a limit as to how closely the fractures can be placed as each fracture alters the stress state in the formations around it, which can interfere with the outcome of the subsequent fracturing treatment/stage aimed at propagating a fracture within the affected area and can impact negatively its intended initiation, propagation, orientation, etc.

A method of fracturing a subterranean formation in a wellbore, comprises: fracturing the subterranean formation through a first stage at predefined first locations; and fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations. Each location from the second location(s) may be localized in the middle between the predefined first locations. The method may further comprise fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s). Each location from the third locations may be localized in the middle between the one of the predefined first locations and one of the second location(s). The method may further comprise fracturing the subterranean formation through a n-stage at n locations wherein each location from the n locations is localized between the one of the preceding locations. Each location from the n locations may be localized in the middle between the one of the preceding locations. In one embodiment, the wellbore is horizontal and/or the subterranean formation contains at least partially rock material which is shale.

The tools and method outlined in this application enable the placement of more closely spaced fractures intersecting the wellbore. The method proposed consist of using specialized equipment, which enables alternating the fracture placement order so that in a first phase, fractures are placed far enough from each other to avoid interference and in a second phase another set of fractures are created half way between the fractures of the first phase. Symmetry allows the second set of fractures to propagate in the intended direction parallel to the first set.

FIGS. 1a, 1b and 1c are used as an example to illustrate the sequence of hydraulic fracturing according to embodiments disclosed herewith. A downhole equipment is deployed in the wellbore and allows a non-consecutive sequence for fracturing. Instead of pumping stages 1-5 sequentially along the wellbore starting from the toe (FIG. 1a—prior art), we would pump stages 1, 2, 3 with longer spacing and then go back and pump stages 4 and 5 between the fractures 1-2 and 2-3 respectively (FIG. 1b). We can also place additional fractures between 1 and 4, then between 4 and 2 . . . if economics are positive for such action, as long as higher fracturing pressures could be handled in practice (FIG. 1c). FIGS. 1d and 1e show another type of stimulation starting at the heel.

FIG. 2 illustrates the symmetrical effect that result in the third stage fracture (number 3) being able to propagate parallel to stages 1 and 2. Placing fracture 3 before fracture 2 would result in fracture 3 moving away from fracture 1 and tending to initiate along the wellbore due to the stress regime created by fracture 1.

According to a first embodiment, downhole sliding sleeves 32 or other devices with similar functionality are deployed on a pipe 30 that is equipped with packers 31 that isolate the annulus space 34 between the pipe and the wellbore around each set of sliding sleeves/devices. The wellbore could be open hole 40, cased/un-cemented (slotted, pre-perforated, etc) or cased/cemented & perforated in multiple clusters that would be grouped to fall between the isolation packers. Optionally, the cased hole could be pre-perforated in clusters. The space between packers could contain multiple clusters of perforations. In one or more embodiments, the opening of the valve/sliding sleeve could detonate charges deployed simultaneously with the valves, which would perforate the casing. The packer elements could be simply swellable packers or could be activated by mechanical, hydraulic and electrical means or a combination. A fracture 50 is generated. In general the well comprises a casing 10 and a production packer 11. The frac valve operating tool 12 may be deployed in the wellbore with a coiled tubing 13. FIG. 3a is a view of such configuration.

The downhole sliding sleeves tool can include one or more subs and/or sections threadably connected to form a unitary body/mandrel having a bore or flow path formed therethrough. In one or more embodiments, the tool can include one or more valve sections, one or more sliding sleeves, one or more sealing devices and/or one or more openings or radial apertures formed therethrough to provide fluid communication between the inner bore and external surface of the tool. The tool comprises a lower end (localized at the toe of the wellbore) and an upper end. In one or more embodiments, the lower end can be adapted to receive or otherwise connect to a drill string, a similar tool or other downhole tool, while the upper end can be adapted to receive or otherwise connect a similar tool, a coiled tubing, a drill string or other types of downhole tools. In one or more embodiments, the tool can be fabricated from any suitable material, including metallic, non-metallic, and metallic/nonmetallic composite materials. In one or more embodiments the tool may be done from a drillable material. In one or more embodiments, the end of the tool can include one or more threaded ends to permit the connection of a casing string or additional combination tool sections as described herein.

In one or more embodiments, the sealing devices positioned on the outside surface from the unitary body are swellable packers. The swellable packers are localized on both side of the radial openings (lower and upper front) as shown on FIG. 3a. When the swellable packers are activated the zone of the wellbore between both packers is isolated. The swellable packers may be activated with oil based, water based, or alternative fluids. The packers may also be set by mechanical or thermal means.

In the fracturing process, fluid communication between the interior and exterior of the tool is permitted. Such fluid communication is advantageous for example when it is necessary to fracture the hydrocarbon bearing zones surrounding the tool by pumping a slurry at high pressure through the casing string, into the bore of the tool. The high pressure slurry passes through the tool and exits the tool via the radial openings when the valve or the sliding sleeve is opened.

In one or more embodiments, the tool deployed could be manipulated via coiled tubing. The coiled tubing could be equipped with a retractable key that engages the devices selectively to mechanically open or close them as needed to affect the sequence described above. The coiled tubing could be left in the wellbore during the fracture treatments and could carry monitoring equipment including pressure/temperature/optical/geophysical sensors. It could also be used to deliver specialty materials that are used to better monitor the treatments or modify properties of pumped materials.

In one or more embodiments, these tools can be designed and deployed so that they can be controlled electrically or hydraulically via a control cable 16 or hydraulic line (FIG. 3b). The elongated pipe may be a tubing 15. They could also be designed to be operated wirelessly via acoustic or electromagnetic signals. The signals could be sent remotely from surface or using a downhole signal generator/transmitter. The electromagnetic or acoustic triggers of the devices could also be deployed via wireline with/without tractor or via coiled tubing. Also some sensor 60 can be used to monitor parameters of the wellbore for example to control efficiency of the fracture. In one or more embodiments, the tools can be operated open or closed via pressure signals applied from surface that are uniquely coded for each devices. The operator would thus be able to selectively open or close the appropriate device to allow the fracture treatments to be placed as per the sequence described above. In one or more embodiments, the signal can be transmitted to tool by pumping a RFID tag to open or close the tool. Each tool could be uniquely coded and pumped RFID tag will have corresponding code.

In one or more embodiments, the tool can be run with liner 19 and cemented in place (FIG. 3c). A liner hanger 17 connects the liner 19 to the casing 10. The cement 18 provides isolation between zones or frac valves. The cemented frac valves or sleeves would operate in the same manner.

In one or more embodiments, the technique could be applied to dual lateral (could also be expanded to tri-lateral, quad-lateral or more complex wellbores. As well the very similar process could be applied to multiple horizontal wellbores. FIG. 4 shows a graphical representation how this type of process could be applied. Please note that for simplicity of explanation in the figures the fractures for each stage are only shown propagating in one direction. In line with hydraulic fracturing theory it is normally the case that a second “wing” of the fracture will propagate at approximately 180-degrees.

In one or more embodiments, the technique could be applied in conjunction for simultaneous multistage stimulation of long horizontal wells. In an open hole environment, the formation is notched using mechanical means, water jetting, or perforating charges to create fracturing initiation sites in such a manner as to enable simultaneous propagation of multiple fractures along the horizontal wells. More than one set of notches may be used and the fracturing treatment may be performed in two stages or more. The first stage treats the first set of notches placed far enough from each other such that the stress changes induced by the propagating fractures do not create interference. Following the first stage, a new set of notches are created half way between the notches/fractures of the first stage and a second stage/treatment is pumped to propagate a new set of fractures. Depending on geometry of the fractures created in the first stage, the level and orientation of local stress alteration will be different. Therefore, the geometry of the second set of the notches will be designed based on the stress alteration created by the first set of fractures and by taking into account the mechanical properties of local rock so that the fracturing pressure required to initiate new set of fractures can be managed. The new notches could be wider and deeper than the previous set, or the notch tips could be sharper. The tools will have focus injection ports pin pointed at the notch locations narrowly packed off by the packers to ensure that the fractures are controllably initiated from the notches. The process can be repeated if a higher density of fractures intersecting the wellbore is economically desirable.

The possibilities for creating the activation of the mechanism(s) to create fracture initiation points and provide isolation for the stimulation can range all the way from the simplest, more time-consuming methods (aka “dumb completion”) to the most technically complex and continuous methods (aka “intelligent or smart completion”). One skilled in the art could envision a number of ways to achieve the overall intent of the invention.

The foregoing disclosure and description of the invention is illustrative and explanatory thereof and it can be readily appreciated by those skilled in the art that various changes in the size, shape and materials, as well as in the details of the illustrated construction or combinations of the elements described herein can be made without departing from the spirit of the invention.

Claims

1. A tool for use in a wellbore, comprising:

a tubular elongated member;

openings on the tubular member able to be close with a valve or a sleeve;

swellable packers positioned between said opening on the tubular member; and

a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; and b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations.

2. The tool of claim 1, wherein the wellbore has a section substantially deviated or horizontal.

3. The tool of claim 1, wherein the wellbore has a horizontal section where the tool is placed.

4. The tool of claim 1, wherein the control unit is a downhole tool, a coiled tubing or a drill string.

5. The tool of claim 1, wherein the tool is deployed during completion.

6. The tool of claim 1, wherein the swellable packers are activated with oil based, water based, or alternative fluids.

7. The tool of claim 1, wherein the swellable packers set by mechanical or thermal means.

8. A tool for use in a wellbore, comprising:

a tubular elongated member;

openings on the tubular member able to be close with a valve or a sleeve;

swellable packers positioned between said opening on the tubular member; and

a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; and c. fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s).

9. The tool of claim 9, wherein the wellbore has a section substantially deviated or horizontal.

10. The tool of claim 9, wherein the wellbore has a horizontal section where the tool is placed.

11. The tool of claim 9, wherein the control unit is a downhole tool, a coiled tubing or a drill string.

12. The tool of claim 9, wherein the tool is deployed during completion.

13. The tool of claim 9, wherein the swellable packers are activated with oil based, water based, or alternative fluids.

14. The tool of claim 9, wherein the swellable packers set by mechanical or thermal means.

15. A tool for use in a wellbore, comprising:

a tubular elongated member;

openings on the tubular member able to be close with a valve or a sleeve;

swellable packers positioned between said opening on the tubular member; and

a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; c. fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s); and d. fracturing the subterranean formation through a n-stage at n locations wherein each location from the n locations is localized between the one of the preceding locations.

16. The tool of claim 15, wherein the wellbore has a section substantially deviated or horizontal.

17. The tool of claim 15, wherein the wellbore has a horizontal section where the tool is placed.

18. The tool of claim 15, wherein the control unit is a downhole tool, a coiled tubing or a drill string.

19. The tool of claim 15, wherein the tool is deployed during completion.

20. The tool of claim 15, wherein the swellable packers are activated with oil based, water based, or alternative fluids.

21. The tool of claim 15, wherein the swellable packers set by mechanical or thermal means.