Multiple Interval Perforating and Fracturing Methods
A method for perforating and fracturing a wellbore in a single trip may include installing one or more reservoir access subs on a liner at pre-determined intervals. The method may also include running the liner into the wellbore, securing the liner to the wellbore, and running a bottomhole assembly into the wellbore. The method may further include activating at least one of the reservoir access subs so as to allow fluid communication between the liner and the wellbore, and fracturing at least one interval proximate the activated reservoir access sub. The steps of running the bottomhole assembly into the wellbore, activating the reservoir access subs, and fracturing the interval may be performed in a single trip into the wellbore.
The present invention relates perforating and fracturing methods and more particularly to single trip methods for multiple interval perforating and fracturing using straddle packer isolation.
Because it is generally economically advantageous to shoot all of the well intervals in a single operation, perforating guns have become extremely long and heavy. Deployment of these tool strings is complex due to the need to perform this operation as a live well intervention. Often, the entire tool string must be pulled into a lubricator at the surface before the casing valve can be closed and the spent guns removed from the wellbore. Long tool strings with sufficient lubricator section requires special cranes and generally are limited to 50-60 feet of lubricator length (40-50 feet of tool string length). Explosives are most commonly deployed via wireline, which allows for depth control and selectivity. However, the increasing trend toward longer and higher angle wells creates challenges for conventional perforating with electric wireline, particularly where the well inclination and the total weight of the guns increase. A tractor system may be used to aid getting the guns to depth, but can be very time consuming due to the need to make separate trips into the wellbore between fracture and stimulation treatments. Tubing conveyed perforating might be the only effective means of accessing some deep well applications. When coil tubing is used, the length of the lubricator may limit the number of guns deployed. Therefore, in multizone stimulation, it may be necessary to run multiple trips. In some applications, perforating with jointed pipe is a suitable option, offering more push and pull forces at the bottomhole assembly. However, when using jointed pipe, recovery of the guns after detonation may be a slow process with connections to break. Additionally, wellhead pressure and well control may require special equipment and handling provisions. Other approaches include leaving the perforating bottomhole assembly in the wellbore, by dropping the guns on detonation. However, without a suitable rat hole, the production flow paths become restricted.
Cobra Frac® includes processes and fracturing techniques using coiled tubing to stimulate multiple intervals using straddle packers. Conventionally, Cobra Frac® (which may include Cobra Frac® H) techniques have required that all zones be conventionally perforated prior to running in hole to isolate and pump the fracture treatment. The crushing and compaction of rock caused by conventional (i.e., explosive jet) perforating due to the super heating of gases may substantially impair the flow capacity of the hole by reducing near wellbore permeability. Many countries have restrictions regarding the import and use of explosives. Additionally, conventional perforating may plug the tip of the tunnel with formation debris and metal fragments. The effects of damage caused by conventional perforating may increase as the formation hardness increases, such as, for example in deeper well applications. Excessive perforation damage can mask true formation potential and lead to incorrect diagnosis and decision making. Conventional perforating can also result in significant fracture tortuosity, increasing formation breakdown pressure—occasionally beyond the capacity of surface equipment or design rating of the well.
SUMMARYThe present invention relates perforating and fracturing methods and more particularly to single trip methods for multiple interval perforating and fracturing using straddle packer isolation.
In some embodiments of the present invention a method for perforating and fracturing a wellbore in a single trip comprises (a) installing one or more reservoir access subs on a liner at pre-determined intervals, (b) running the liner into the wellbore, (c) securing the liner to the wellbore, (d) running a bottomhole assembly into the wellbore, (e) activating at least one of the reservoir access subs so as to allow fluid communication between the liner and the wellbore, and (f) fracturing at least one interval proximate the activated reservoir access sub. Steps (d), (e), and (f) may be performed in a single trip into the wellbore.
In other embodiments of the present invention a method for perforating and fracturing a wellbore in a single trip comprises (a) running a liner into the wellbore, (b) securing the liner to the wellbore, (c) running a bottomhole assembly into the wellbore, (d) establishing fluid communication between the liner and the wellbore, and (e) fracturing at least one interval proximate the fluid communication. Steps (c), (d), and (e) may performed in a single trip into the wellbore, and steps (d) and (e) may be repeated in the single trip into the wellbore.
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Step 10 of installing one or more reservoir access subs 102 on liner 104 may include threading with a thread type appropriate for the casing, or welding. Reservoir access subs 102 may be placed at predetermined intervals, which may be selected based on the position and spacing of the desired fractures required for a given completion. The number of fracture Targets is often optimized by numerical simulation. However, in some cases the number and position of each fracture target may be established through evaluation of well logs to optimize fracture placement based on reservoir quality. The spacing may vary tremendously depending, in part, on whether the annulus of the casing/wellbore is cemented or segmented with annular packer isolation or dynamic fluid deversion. If annular packers are used, the typical spacing between reservoir access subs may be as much as 500 ft. If the casing is cemented the spacing between subs could be as little as 90 ft or as much as 250 ft. In some embodiments, spacing between subs could be less than 50 ft. or greater than 250 ft. Project economics plays a substantial role in determining the number and spacing of these subs. Exemplary embodiments of reservoir access sub 102 are described in detail below, with respect to
Step 20 of running liner 104 may be accomplished conventionally, as known by those having ordinary skill in the art. Since the perforations may not be activated until after liner 104 has been run, liner 104 may be circulated into the openhole. Liner 104 may be run on drillpipe or coil tubing or otherwise and may be cemented conventionally, or may be secured by activating annular packers. Alternatively, there may be no annular isolation, in some embodiments. Additionally, step 20 of running liner 104 may include a step of activating a liner hanger after liner 104 is in position downhole.
Step 30 of securing liner 104 to wellbore 106 may include placing cement in annulus 114 formed between liner 104 and wellbore 106 and allowing the cement to set. In other embodiments, step 30 of securing liner 104 to wellbore 106 may include setting one or more packers (not shown) in annulus 114. The packers may be annular isolation packers, such as swell packers, or other isolation devices known to those having ordinary skill in the art.
Once liner 104, including reservoir access subs 102 has been deployed, bottomhole assembly 108 may be run. Step 40 of running bottomhole assembly 108 may include running on tubing or coiled tubing or a combination string of jointed pipe and coiled tubing. Bottomhole assembly 108 may be deployed to fracture and stimulate individual fractures in any sequence. Bottomhole assembly 108 may include straddle packer 116 connected to tubing 118 via threaded connections, clamp-on connections, slip on connections, or any other suitable connection. Straddle packer 116 may include packer elements, including conventional solid packer-ring elastomers, cup-type elastomers, inflatable elastomers, or combinations thereof, or any other straddle assembly. Bottomhole assembly 108 may include a Cobra Frac® bottomhole assembly, as illustrated in
Step 50 of activating at least one reservoir access sub 102 may include applying hydraulic pressure, applying acid, or any of a number of other methods for establishing fluid communication between liner 104 and wellbore 106, as described below with respect to the various embodiments.
Step 60 of fracturing at least one interval 110 may include a straddle pack technique such as a Cobra Frac® technique. For example, a zone may be sealed, multiple-intervals may be perforated, milling may be done via coil tubing, and fracturing may be done via pinpoint fracture service. The milling step, necessary in conventional perforating, may be omitted when using reservoir access subs 102. Conventionally, milling removes the “burrs” created by the explosives. These “burrs” may have a detrimental effect on packer elements, but are not be created when using reservoir access subs 102. Therefore, a separate trip into the well for milling may not be required when using reservoir access subs 102. Additionally, other methods of fracturing may be appropriate, depending on the particular circumstances and conditions. Optionally, a step of isolating interval 110 may precede step 60 of fracturing interval 110.
Referring now to the embodiment illustrated in
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Once bottomhole assembly 108 reaches the predetermined treatment depth, any of a number of methods may be employed for removing the soluble material from ports 202. For example, a solvent (e.g., acid 206) may be circulated (e.g., reverse circulated) into place and may remain for a predetermined amount of time to erode or dissolve or otherwise remove acid soluble material 204 from within ports 202, and activate reservoir access sub 102.
Interval 110 may then be isolated and fractured using a Cobra Frac® technique. Referring now to
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Interval 110 may then be isolated and fractured using a Cobra Frac® technique. Referring now to
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Reservoir access sub 102 may be installed on liner 104 (not shown in
In some instances, hydrajetting may be desired prior to fracturing. In those instances, jets 302 may be placed in ports 504, prior to running into wellbore 106. Once in place in wellbore 106, jets 302 may be removed with acid or removed by friction caused by abrasive fluid being pumped therethrough (or otherwise), to allow for a conventional fracturing treatment to be performed after the hydrajetting operation. Thus, in some embodiments, the steps may include isolating reservoir access sub 102, pressure activating shifting sleeve 502 to shift open reservoir access sub 102 to expose ports 504 with jets 302, pumping through jets 302 to hydrajet the formation, reverse circulating or circulating acid (or otherwise dissolve or erode) jets 302, and pumping fracture treatment through open ports 504.
After treating interval 110, straddle packer 116 may be placed across second interval 112 (not shown in
In any of the above-described embodiments, activating reservoir access sub 102 may allow fluid communication between liner 104 or casing and wellbore 106. Additionally, the step 50 of activating reservoir access sub 102 may be repeated as many times as desired for the particular application.
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A single run may allow for fracture stimulation of all intervals. Bottomhole assembly 108 may have a similar construction and be placed in a manner similar to that of the embodiment of
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Additional embodiments may combine features from the above-described embodiments. For example, but not by way of limitation, one liner may contain any combination of punch tools 702, activated charges 804, reservoir access subs 102 having ports 202, reservoir access subs 102 having jets 302, and/or reservoir access subs 102 having burst disks 402. In each of the embodiments described herein, the methods may additionally include a step of installing an interval locator (not shown) on liner 104 prior to running liner 104 into wellbore 106. The interval locator may be a ‘Mechanical Casing Collar Locator’ (where short joints can be run below each interval to be treated), ‘Hydraulic Casing Collar Locator’, ‘Coil Tubing Acoustic Tool’ (which is described in U.S. Pat. No. 6,880,634), ‘Tag’ bridge plug, or a Hydraulically Activated Interval Locator’ which is a tool that would activate a key that once on depth would ‘latch’ into an arm placed at the interval that would place the straddle over the zone of interest and offer a clear ‘positive’ indication on surface that the tool is on depth to perform treatment.
As used herein, the term “treatment fluid” describes any fluid useful for treatment in a wellbore. Treatment may include fracturing fluids, such as gelled fluids, foamed gels, water, potassium chloride water, acids, etc., or any other treatment useful in wellbore operations. As used herein, the term “shifting sleeve” generally refers to sleeves that move relative to a reference point, including axially, radially, rotably, or the like. As used herein, the term “tubing” refers to any conduit suitable for the purposes indicated herein, including, but not limited to coiled tubing, jointed pipe, and combinations thereof. As used herein, the term “liner” includes conventional liners, as well as casing, tubulars, and other conduit.
The methods of this disclosure may allow alternative perforating methods to be applied in conjunction with the Cobra Frac® processes to stimulate multiple intervals economically and efficiently. The methods of this disclosure may also allow for the use of a straddle packer system to perform multiple fracture treatments in a single trip via coil tubing, jointed pipe, or a hybrid unit. The methods of this disclosure may further enable pinpoint placement and isolation of the stimulation treatment. Additionally, the methods of this disclosure may eliminate the need to dedicate one or more trips in hole to perforate. The methods of this disclosure may further eliminate the need for explosives, and associated issues. The methods of this disclosure may remove the significant completion challenges associated with conventional perforating. The methods of this disclosure may offer alternative perforation techniques that will mitigate the effects of conventional perforating while creating an effective communication path to the pay zone. Some methods of this disclosure utilize hydrajetting in situations where it is more advantageous. The methods of this disclosure may be applicable in vertical, deviated, and horizontal wells and may be applied safely in uncemented and cemented applications. The methods of this disclosure may reduce cycle time without sacrificing production efficiency. The methods of this disclosure may reduce costs of multizone stimulations, and improve safety on location. The methods of this disclosure may eliminate the need for a mill run subsequent to a perforating run.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.
Claims
1. A method for perforating and fracturing a wellbore in a single trip comprising:
- (a) installing one or more reservoir access subs on a liner at pre-determined intervals;
- (b) running the liner into the wellbore;
- (c) securing the liner to the wellbore;
- (d) running a bottomhole assembly into the wellbore;
- (e) activating at least one of the reservoir access subs so as to allow fluid communication between the liner and the wellbore; and
- (f) fracturing at least one interval proximate the activated reservoir access sub;
- wherein steps (d), (e), and (f) are performed in a single trip into the wellbore.
2. The method of claim 1, wherein at least one of the reservoir access subs comprises one or more ports at least partially filled with a soluble material, and wherein activating the reservoir access subs comprises reverse circulating a solvent to dissolve the soluble material in the ports.
3. The method of claim 1, wherein at least one of the reservoir access subs comprises one or more jets at least partially filled with a soluble material, and wherein activating the reservoir access subs comprises reverse circulating a solvent to dissolve the soluble material in the jets.
4. The method of claim 1, wherein at least one of the reservoir access subs comprises one or more ports with burst disks, and wherein activating the reservoir access subs comprises isolating at least one of the reservoir access subs with a straddle packer and applying pressure to burst the disks.
5. The method of claim 1, wherein at least one of the reservoir access subs comprises at least one shifting sleeve, and wherein activating the reservoir access subs comprises applying pressure to open the shifting sleeve to expose fracports, jets, and/or soluble jets.
6. The method of claim 1, comprising repeating step (e) for additional reservoir access subs.
7. The method of claim 1, comprising installing an interval locator on the liner prior to running the liner into the wellbore.
8. The method of claim 1, wherein securing the liner to the wellbore comprises placing cement in an annulus formed between the liner and the wellbore, and allowing the cement to set.
9. The method of claim 1, wherein securing the liner to the wellbore comprises setting one or more packers in an annulus formed between the liner and the wellbore.
10. The method of claim 1, wherein fracturing comprises using a straddle technique.
11. The method of claim 1, comprising repeating steps (e)-(f) for one or more additional intervals.
12. The method of claim 1, wherein the bottomhole assembly comprises at least one straddle packer.
13. The method of claim 1, wherein the bottomhole assembly comprises a Cobra Frac® bottomhole assembly.
14. The method of claim 1, comprising isolating the interval, wherein isolating is performed prior to fracturing.
15. A method for perforating and fracturing a wellbore in a single trip comprising:
- (a) running a liner into the wellbore;
- (b) securing the liner to the wellbore;
- (c) running a bottomhole assembly into the wellbore;
- (d) establishing fluid communication between the liner and the wellbore; and
- (e) fracturing at least one interval proximate the fluid communication;
- wherein steps (c), (d), and (e) are performed in a single trip into the wellbore; and
- wherein steps (d) and (e) are repeated in the single trip into the wellbore.
16. The method of claim 15, comprising installing at least one punch tool on the bottomhole assembly prior to running the bottomhole assembly into the wellbore, wherein establishing fluid communication between the liner and the wellbore comprises activating the punch tool.
17. The method of claim 15, comprising installing one or more subs on the liner at pre-determined intervals prior to running the liner into the wellbore, wherein the subs comprise comprising hydraulically activated charges, and wherein establishing fluid communication between the liner and the wellbore comprises isolating at least one of the subs with a straddle packer, and applying hydraulic pressure to activate the charges.
18. The method of claim 17, wherein the hydraulically activated charges comprise at least one gun.
19. The method of claim 15, comprising installing an interval locator on the liner prior to running the liner into the wellbore.
20. The method of claim 15, wherein securing the liner to the wellbore comprises placing cement in an annulus formed between the liner and the wellbore, and allowing the cement to set.
21. The method of claim 15, wherein securing the liner to the wellbore comprises setting one or more packers in an annulus formed between the liner and the wellbore.
22. The method of claim 15, wherein fracturing comprises using a Cobra Frac® technique.
23. The method of claim 15, comprising repeating steps (d)-(e) for one or more additional intervals.
24. The method of claim 15, wherein the bottomhole assembly comprises at least one straddle packer.
Type: Application
Filed: Jan 6, 2010
Publication Date: Jul 7, 2011
Inventors: Troy F. Palidwar (Langdon), Brock W. Miller (Calgary), Fraser McNeil (Houston, TX), Loyd E. East, JR. (Tomball, TX)
Application Number: 12/683,338
International Classification: E21B 43/11 (20060101);