DEBRIS CONTROL SYSTEMS, APPARATUS, AND METHODS

A debris control system comprises a first ported sub and a second ported sub attached to a casing and disposed in a wellbore, such that the first ported sub is disposed at a depth that is deeper than the depth at which the second ported sub is disposed. The first ported sub is to move debris from the wellbore when it is actuated and a first fluid is pumped through it. The second ported sub is to enable conducting a diagnostic fracture injection test (DFIT) when a second fluid is pumped through it. Additional apparatus, methods, and systems are disclosed.

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Description
BACKGROUND

Diagnostic fracture injection tests (DFITs) are commonly used to obtain formation properties and determine fracture parameters associated with a wellbore. Typically, fluid is pumped horizontally through the toe or vertically through perforations of the wellbore. The pressure at the wellhead is then monitored for an extended period of time. Cementing residue, pipe dope, or other debris can obstruct the flow path from the wellbore to the formation, making pressure data uninterpretable, unreliable, or otherwise causing the DFIT to fail. The debris in the wellbore may further interfere with hydraulic fracturing treatments. The accumulated debris can be difficult, if not impossible, to remove without costly intervention.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure may be better understood, and its numerous features and advantages made apparent to those of ordinary skill in the art by referencing the accompanying drawings. The use of the same reference symbols in different drawings indicates similar or identical items.

FIG. 1 depicts an example debris control system, in accordance with some embodiments.

FIG. 2 depicts another example of the debris control system of FIG. 1, in accordance with some embodiments.

FIG. 3 depicts yet another example of the debris control system of FIG. 1, in accordance with some embodiments.

FIG. 4 depicts yet another example of the debris control system of FIG. 1, in accordance with some embodiments.

FIG. 5 is a flow diagram of an example method of debris control, in accordance with some embodiments.

FIG. 6 depicts an example completion system, in accordance with some embodiments.

 DETAILED DESCRIPTION

FIGS. 1-5 illustrate example methods, apparatus, and systems for debris control during well construction, and other operations, using a first ported sub and a second ported sub attached to a casing, so that when the casing is inserted into a wellbore, the first ported sub is positioned deeper in the wellbore than the second ported sub. The first ported sub is actuated to provide fluid communication between the wellbore and a formation, such that a fluid can be pumped through the first ported sub to move debris out of the wellbore and into the formation. The wellbore is then sealed and the second ported sub is actuated to allow fluid communication between the wellbore and the formation, such that a diagnostic fracture injection test (DFIT) or a hydraulic fracturing treatment may be performed without interference from the debris that has passed through the first ported sub.

FIG. 1 depicts an example debris control system 100, in accordance with some embodiments. The debris control system 100 generally comprises a first ported sub 102 and a second ported sub 104 attached to a casing 106 for use in a wellbore 108. In at least one embodiment, the debris control system 100 further comprises a first landing collar 110 and a second landing collar 112 attached to the casing 106. In some embodiments, a guide shoe 114 is attached to an end of the casing 106 to guide the casing 106 into the wellbore 108. In some embodiments, a float collar 116 is attached to the casing 106. In the illustrated embodiment, the debris control system 100 is installed on the casing 106 so that when the casing 106 is run into the wellbore 108, the guide shoe 114 is deeper than the float collar 116, which is, in turn, deeper than the first landing collar 110. The landing collar 110 is deeper than the first ported sub 102, which is, in turn, deeper than the second landing collar 112. The second landing collar 112 is, in turn, deeper than the second ported sub 104.

For the purposes of this disclosure, “depth” is relative to the casing 106 once inserted into the wellbore 108. That is, an element A having a “deeper” depth than element B indicates that element A has a position on the casing 106 that would be further into the wellbore 108 than element B, once the casing 106 is inserted into the wellbore 108.

In the illustrated embodiment, the second landing collar 112 comprises an inner diameter that is greater than an inner diameter of the first landing collar 110, such that a wiper dart 120 inserted into the casing 106 passes through the inner diameter of the second landing collar 112, and lands in the first landing collar 110, substantially sealing the casing 106 at the first landing collar 110 against the incursion of fluid.

In at least one embodiment, at least one of the first ported sub 102 and the second ported sub 104 comprises a sliding sleeve. Further, in some embodiments, at least one of the first ported sub 102 and the second ported sub 104 comprises a hydraulically activated sliding sleeve. In some embodiments, at least one of the first ported sub 102 and the second ported sub 104 can be actuated to facilitate fluid communication between the wellbore 108 and a formation 118. In some embodiments, at least one of the first ported sub 102 and the second ported sub 104 establishes the fluid communication between the wellbore 108 and the formation 118 independently, without intervention of a perforating gun or some other ancillary mechanism. In some embodiments, at least one of the first ported sub 102 and the second ported sub 104 only requires the imposition of absolute casing pressure (applied pressure and hydrostatic pressure) to be actuated.

In some embodiments, at least one of the first ported sub 102 and the second ported sub 104 comprises a variable-sized inner mandrel to create a piston area and atmospheric chamber inside a ported housing. The piston area and atmospheric chamber generate a hydraulic force on the inner sleeve as the inner diameter of the ported sub (102, 104) is exposed to pressure (both hydrostatic and applied).

The inner mandrel is fastened in place by shear fasteners, for example, shear pins, shear screws, or the like. The number of shear fasteners can be manipulated to achieve different pressure requirements for actuation. When the total internal pressure generates the predetermined hydraulic force, the shear fasteners are sheared and the inner mandrel is allowed to move, exposing the ports of the ported sub (102, 104) and facilitating fluid communication between the wellbore 108 and the formation 118. In the illustrated embodiment, both the first ported sub 102 and the second ported sub 104 are in a closed position, such that the ports of the ported subs 102, 104 do not facilitate fluid communication between the wellbore 108 and the formation 118.

FIG. 2 depicts another example of the debris control system 100 of FIG. 1, in accordance with some embodiments. In the illustrated embodiment, the wiper dart 120 has passed through the wellbore 108 and the inner diameter of the second landing collar 112 to control the amount of debris in the wellbore 108, and landed in the first landing collar 110 to seal the wellbore 108. Further, in the illustrated embodiment, the first ported sub 102 has been actuated such that it is in an open position to facilitate fluid communication between the wellbore 108 and the formation 118. In at least one embodiment, hydraulic pressure is used to open the first ported sub 102.

In some embodiments, a fluid is pumped through the wellbore 108 to move debris from the wellbore 108 to the formation 118, via the first ported sub 102. The debris may comprise, for example, cementing residue, pipe dope, solids, or the like. In at least one embodiment, the fluid comprises primarily water. In at least one embodiment, the fluid comprises a solvent cleaning fluid, for example, a solvent acid, acids, organic acids, aromatic solvents, paraffinic solvents, soaps, detergents, a combination of these, or the like. In some embodiments, the fluid is chosen to treat specific anticipated pipe debris.

In the illustrated embodiment, the second ported sub 104 has not been actuated and remains in a closed position, such that the second ported sub 104 does not facilitate fluid communication between the wellbore 108 and the formation 118. That is, the actuation of the first ported sub 102 does not result in actuation of the second ported sub 104. For example, in at least one embodiment, the second ported sub 104 is actuated by application of a greater pressure than is required to actuate the first ported sub 102. In at least one embodiment, both the first ported sub 102 and the second ported sub 104 comprise hydraulically actuated sliding sleeves with shear fasteners, and the shear fasteners on the second ported sub 104 comprise greater shear strength than those on the first ported sub 102.

The illustrated embodiment further depicts a wiper plug 202 passing through the casing 106 of the wellbore 108. The wiper plug 202 is dimensioned to land and latch into the second landing collar 112 to seal the wellbore 108 at a lesser depth than the depth of the first ported sub 102. In at least one embodiment, the debris control system 100 does not include the second landing collar 112, and instead the wiper plug 202 is dimensioned to land and latch into the first ported sub 102 to seal the wellbore 108. In some embodiments, the debris control system 100 does not use the wiper plug 202. In at least one embodiment, the first ported sub 102 is plugged, for example, by debris, sealing the wellbore 108 from the formation 118 where the debris has been disposed.

FIG. 3 depicts yet another example of the debris control system 100 of FIG. 1, in accordance with some embodiments. In the illustrated embodiment, the wiper plug 202 has landed and latched into the second landing collar 112, to seal the wellbore 108 from the formation 118. In at least one embodiment, the sealed wellbore creates a “disposal zone” of sorts, such that debris is trapped between the wiper plug 202, the wiper dart 120 and the formation 118. In at least one embodiment, the wellbore 108 is sealed from the formation 118 by debris plugging the first ported sub 102.

In the illustrated embodiment, the second ported sub 104 has been actuated, such that the second ported sub 104 facilitates fluid communication between the wellbore 108 and the formation 118. In at least one embodiment, hydraulic pressure is used to open the second ported sub 104. The second ported sub 104 may be used for at least one of: a DFIT or a hydraulic fracturing treatment without interference from the debris that has passed through the first ported sub 102, or is otherwise trapped below the wiper plug 202.

FIG. 4 depicts yet another example of the debris control system 100 of FIG. 1, in accordance with some embodiments. In the illustrated embodiment, the debris control system 100 does not include the second landing collar 112 of the wiper plug 202. Instead, the first ported sub 102 is actuated in accordance with FIG. 2 to facilitate fluid communication between the wellbore 108 and the formation 118 to pass debris to the formation 118. Debris eventually plugs the first ported sub 102 to seal the wellbore 108 from the debris that has passed through the first ported sub 102 to the formation 118. The second ported sub 104 is then actuated to facilitate fluid communication between the formation 118 and the wellbore. In the illustrated embodiment, the second ported sub 104 is in the open position to facilitate a DFIT or a hydraulic fracturing treatment without interference from the debris that was passed to the formation 118 via the first ported sub 102.

FIG. 5 is a flow diagram of an example method 500 of debris control, in accordance with some embodiments. For the purposes of clarity, the method 500 is described with reference to the debris control system 100 of FIGS. 1-4. At block 502 a plurality of tools comprising components of the debris control system 100 are installed on the casing 106. In at least one embodiment, the debris control system 100 is installed at the toe of the casing 106. In at least one embodiment, the first ported sub 102 is disposed at a first depth that is deeper than a depth at which the second ported sub 104 is disposed. In at least one embodiment, the first landing collar 110 is disposed at a depth that is deeper than a depth at which the first ported sub 102 is disposed. In at least one embodiment, the second landing collar 112 is disposed between the first ported sub 102 and the second ported sub 104.

At block 504, one or more well completion operations are performed. The casing 106 is run into the wellbore 108. In some embodiments, the completion operations comprise pumping cement down the casing 106 to the guide shoe 114, where it continues to flow up the annulus between the casing 106 and the wellbore 108, isolating the wellbore from the formation 118. In at least one embodiment, the wiper dart 120 is landed in the first landing collar 110 to prevent u-tubing of cement (e.g., the return of cement into the wellbore) during the completion operations. The second landing collar 112 has an inner diameter that is greater than an inner diameter of the first landing collar 110, such that the wiper dart 120 passes through the second landing collar 112 to seat in the first landing collar 110 and seal the wellbore 108.

At block 506, the first ported sub 102 is actuated, enabling fluid communication between the wellbore 108 and the formation 118 via ports on the first ported sub 102. In at least one embodiment, hydraulic pressure is used to actuate the first ported sub 102. In at least one embodiment, pressure is applied to shear one or more shear fasteners of the first ported sub 102 to actuate the first ported sub 102. The second ported sub 104 has not been actuated and remains in a closed position at this point, such that the second ported sub 104 does not facilitate fluid communication between the wellbore 108 and the formation 118. That is, the actuation of the first ported sub 102 does not result in actuation of the second ported sub 104. For example, in at least one embodiment, the second ported sub 104 is actuated by application of a greater pressure than is required to actuate the first ported sub 102. In at least one embodiment, both the first ported sub 102 and the second ported sub 104 comprise hydraulically actuated sliding sleeves with shear fasteners, and the fasteners on the second ported sub 104 comprise greater shear strength than the fasteners on the first ported sub 102.

At block 508, fluid is pumped through the wellbore 108 to pass debris from the wellbore 108 and provide a cleaned wellbore 108. In some embodiments, the fluid passes the debris from the wellbore 108 to the formation 118 via the first ported sub 102. The debris may comprise, for example, cementing residue, pipe dope, solids, or the like. In at least one embodiment, the fluid comprises primarily water. In some embodiments, the fluid comprises a solvent. In at least one embodiment, the fluid comprises a solvent cleaning fluid. In some embodiments, the fluid is chosen to treat specific anticipated pipe debris.

At block 510, it is determined whether the first ported sub 102 is plugged by debris. For example, in at least one embodiment, this determination is made by increasing excessive pressure, based on an inability to maintain injection rate, or a combination of these.

If, at block 510, it is determined that the first ported sub 102 is not plugged by debris, the method proceeds to block 512, whereby a wiper plug 202 is landed and latched into the second landing collar 112. The wiper plug 202 seals the wellbore 108 between the first ported sub 102 and the second ported sub 104, so as to separate the cleaned wellbore from the debris that has been passed through the first ported sub 102 to the formation 118. In at least one embodiment, the wiper plug 202 is landed and latched into the first ported sub 102, such that the wellbore 106 is sealed by the wiper plug 202 at the first ported sub 102.

If, at block 510, it is determined that the first ported sub 102 is plugged by debris, then the wellbore 108 is sealed (by the plugged first ported sub 102) from the debris that has passed through the first ported sub 102 to the formation 118. After the wellbore 108 is sealed by debris or by the wiper plug 202, the method 500 proceeds to block 514, whereby the second ported sub 104 is actuated, enabling fluid communication between the wellbore 108 and the formation 118 via ports on the second ported sub 104. In at least one embodiment, hydraulic pressure is used to actuate the second ported sub 104. In at least one embodiment, pressure is applied to shear one or more shear fasteners of the second ported sub 104 to actuate the second ported sub 104.

At block 516, a diagnostic fracture injection test (DFIT) or a hydraulic fracturing treatment is performed using the second ported sub 104. In at least one embodiment, a second fluid is pumped through the second ported sub 104. For example, in at least one embodiment, the fluid comprises non-damaging treated water, a compatible field brine, oil, gas, foam, a combination of these, or the like. In some embodiments, data is collected, and a DFIT analysis is performed on the data. In at least one embodiment, the DFIT comprises a small volume, cost-effective, short duration and low-rate injection test followed by an extended shut-in period. In at least one embodiment, the DFIT comprises breaking down the formation 118 and estimating fracture pressure, closure pressure, pore pressure, and permeability. In some embodiments, the DFIT is performed in an effort to optimize a hydraulic fracturing treatment.

The debris control system 100 allows the DFIT or hydraulic fracturing treatment to be performed/applied using the second ported sub 104 without interference from the debris that has passed through the first ported sub 102 to the formation 118, or that is otherwise separated by the wiper plug 202. Without the debris control system 100, cementing residue, pipe dope, or other debris might obstruct the flow path from the wellbore to the formation, making collected data uninterpretable, unreliable, or otherwise causing the DFIT to fail. The debris in the wellbore would further interfere with hydraulic fracturing treatments. Without the debris control system 100, accumulated debris requires costly intervention to remove.

FIG. 6 depicts a well completion system 600, in accordance with some embodiments. Well completion occurs after the wellbore 602 has been drilled, but before the well 604 can be put into production. Well completion can include many operations, such as casing, cementing, perforating, gravel packing, production tree installation, DFIT, hydraulic fracturing, among others.

Casing operations help ensure that the wellbore 602 will not collapse when drilling fluids are removed from the wellbore 602 and protect the drilling fluids from contamination by other materials of the wellbore 602. The casing operations generally comprise joining sections of tube (or joints), for example steel or other metal, to form a casing 606. The casing 606 is then run into the wellbore 602. Different diameters of casing 606 may be used at different locations within the wellbore 602. For example, a casing program may include production casing, intermediate casing, surface casing, conductor casing, or the like, each comprising a different diameter tube for the casing 606. An accurate casing program is essential to ensuring that the well can flow properly given the wellbore conditions.

The well completion system 600 further comprises the debris control system 100 of FIGS. 1-3 installed at the toe of the casing 606. The guide shoe 114 guides the first joint of the casing 606 into the wellbore 602. After the debris control system 100 and any other tools have been installed on the casing 606, the casing 606 is run to depth into the wellbore 602 and cementing operations begin. Cement is pumped down the casing 606 to the guide shoe 114, where it continues to flow up the annulus between the casing 606 and the wellbore 602, isolating the wellbore from the formation.

The space between the guide shoe 114 and the float collar 116 (e.g., an auto-fill float collar) define a shoe track 612. The purpose of the shoe track 612 is to avoid over-displacing cement during cementing operations. The float collar 116 (e.g., an auto-fill float collar) and the guide shoe 114 prevent reverse flow of cement back into the casing after placement. The shoe track 612 may comprise a single section of the casing 606 or multiple joints of the casing 606. In some applications, one or more centralizers 614, 615 keep the casing 606 off the wall of the wellbore 602 to ensure proper cementing operations. Some applications may further utilize scratchers to remove wall cake and ensure that the cement bonds to the wall of the wellbore 602. In at least one embodiment, the well completion system 600 comprises an open-hole completion.

In at least one embodiment, the wiper dart 120 is used during the initial cementing operation, to pass through the inner diameter of the second landing collar 112, and landing at the first landing collar 110. The wiper dart 120 activates the first landing collar 110 and prevents cement slurry from flowing back into the wellbore 602 (e.g., u-tubing) by sealing the wellbore 602 at the first landing collar 110. The debris control system 100 may then be used to clean the wellbore 602 and to facilitate performing DFITs or hydraulic fracturing treatments.

In the foregoing Detailed Description, it can be seen that various features are grouped together in a single embodiment for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed embodiments require more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed embodiment. Thus the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment.

Note that not all of the activities or elements described above in the general description are required, that a portion of a specific activity or device may not be required, and that one or more further activities may be performed, or elements included, in addition to those described. Still further, the order in which activities are listed are not necessarily the order in which they are performed. Also, the concepts have been described with reference to specific embodiments. However, one of ordinary skill in the art appreciates that various modifications and changes can be made without departing from the scope of the present disclosure as set forth in the claims below. Accordingly, the specification and figures are to be regarded in an illustrative rather than a restrictive sense, and all such modifications are intended to be included within the scope of the present disclosure.

Benefits, other advantages, and solutions to problems have been described above with regard to specific embodiments. However, the benefits, advantages, solutions to problems, and any feature(s) that may cause any benefit, advantage, or solution to occur or become more pronounced are not to be construed as a critical, required, or essential feature of any or all the claims. Moreover, the particular embodiments disclosed above are illustrative only, as the disclosed subject matter may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. 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 embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the disclosed subject matter. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. A method, comprising:

pumping a first fluid through a first ported sub to remove debris from a wellbore in which a casing attached to the first ported sub is disposed, to provide a cleaned wellbore;
sealing the wellbore at a first depth; and
pumping a second fluid through a second ported sub to conduct a diagnostic fracture injection test in the cleaned wellbore, wherein the first depth is deeper than a second depth at which the second ported sub is attached to the casing.

2. The method of claim 1, further comprising:

running the casing into the wellbore prior to pumping the first fluid.

3. The method of claim 1, further comprising:

enabling fluid communication between the wellbore and a formation via ports on the first ported sub prior to pumping the first fluid.

4. The method of claim 1, further comprising:

enabling fluid communication between the wellbore and a formation via ports on the second ported sub prior to pumping the second fluid.

5. The method of claim 1, wherein the first fluid comprises a solvent cleanout fluid.

6. The method of claim 1, wherein the second fluid comprises formation compatible fluid.

7. A system, comprising:

a first ported sub attached to a casing and disposed at a first depth in a wellbore, wherein the first ported sub is to pass debris from the wellbore when the first ported sub is actuated and a first fluid is pumped through the first ported sub; and
a second ported sub disposed at a second depth in the wellbore, wherein the first depth is deeper than the second depth, the second ported sub to enable conducting a diagnostic fracture injection test when a second fluid is pumped through the second ported sub.

8. The system of claim 7, further comprising:

a first landing collar disposed at a third depth that is deeper than the first depth.

9. The system of claim 8, further comprising:

a wiper dart to pass through the wellbore to control the amount of debris in the wellbore.

10. The system of claim 9, further comprising:

a second landing collar disposed at a fourth depth that is between the first and second depths, wherein the second landing collar has an inner diameter greater than an inner diameter of the first landing collar, such that the wiper dart passes through inner diameter of the second landing collar.

11. The system of claim 10, further comprising:

a wiper plug to land in the second landing collar so as to create a seal in the wellbore.

12. The system of claim 7, wherein at least one of the first ported sub or the second ported sub comprises a hydraulically actuated sliding sleeve.

13. A method, comprising:

installing a plurality of tools on a casing, the plurality of tools comprising a first ported sub and a second ported sub;
running the casing into a wellbore;
performing a completion operation; and
opening the first ported sub to pass debris from the wellbore, prior to opening the second ported sub to conduct a diagnostic fracture injection test.

14. The method of claim 13, wherein opening the first ported sub comprises:

applying hydraulic pressure to the first ported sub, so as to shear one or more shear fasteners.

15. The method of claim 13, further comprising:

pumping a solvent into the wellbore to pass debris from the wellbore through the first ported sub.

16. The method of claim 13, further comprising:

opening the second ported sub after the first ported sub is plugged.

17. The method of claim 13, further comprising:

sealing the wellbore at a first depth, wherein the first ported sub is located at a second depth that is equal to, or deeper than, the first depth.

18. The method of claim 17, wherein sealing the wellbore comprises:

landing a wiper plug at a landing collar disposed at the casing between the first ported sub and the second ported sub, wherein the plurality of tools comprises the landing collar.

19. The method of claim 17, further comprising:

opening the second ported sub after sealing the wellbore, wherein the second ported sub is disposed at a third depth, wherein the first depth is deeper than the third depth.

20. The method of claim 17, further comprising:

performing a diagnostic fracture injection test or a hydraulic fracturing treatment using the second ported sub.
Patent History
Publication number: 20170247981
Type: Application
Filed: Dec 16, 2014
Publication Date: Aug 31, 2017
Applicant: Halliburton Energy Services, Inc. (Houston, TX)
Inventors: Andrew Michael Smith (Odessa, TX), Kenneth Lee Borgen (Midland, TX), Clifford Lynn Talley (Midland, TX)
Application Number: 15/516,843
Classifications
International Classification: E21B 37/00 (20060101); E21B 34/10 (20060101); E21B 37/10 (20060101); E21B 43/26 (20060101); E21B 34/06 (20060101); E21B 33/12 (20060101); E21B 49/00 (20060101);