Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
The amended claims filed 10/15/25 are acknowledged; claims 1-7, 9-14, 16-18, and 20-23.
Claim Rejections - 35 USC § 102
The text of those sections of Title 35, U.S. Code not included in this action can be found in a prior Office action.
Claim(s) 1-3, 9-14, 16-18, and 20-23 is/are rejected under 35 U.S.C. 102(a)(2) as being anticipated by Martysevich et al. (US 20190264552).
CLAIM 1: Martysevich discloses a method of indirect hydraulic fracturing as shown in part by Fig. 4B below:
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The method comprises steps of: a) providing at least a first wellbore interval (410) and a second wellbore interval (420), different from the first wellbore interval (see Fig. 4B), in a subterranean formation (130), wherein the first wellbore interval has a casing or liner therein (paragraph 0024, shown in other embodiment as 310) and openings are provided through the casing or liner (perforations, paragraph 0024). The first wellbore interval has a single wellhead which serves the first wellbore interval for production from the first wellbore interval (top of the wellbore). The second wellbore interval is positioned and oriented with respect to the first wellbore interval so that hydraulic fractures (425) initiated through at least some of the openings of the first wellbore interval will propagate toward and will at least reach the second wellbore interval (see Fig. 4B), the hydraulic fractures which reach the second wellbore interval being interacting hydraulic fractures, and the second wellbore interval has a single wellhead which serve the second wellbore interval for production from the second wellbore interval (at the top of the wellbore). The single wellhead which serves the first wellbore interval is the same as or different from the single wellhead which serves the second wellbore interval (this limitation does not limit the scope of the claim as the two options cover the entirety of potential options). B) isolating one or more longitudinal sections of a predicted interaction zone of the second wellbore interval in which it is predicted that the interacting hydraulic fractures initiated from the first wellbore interval will interact with the second wellbore interval, the one or more longitudinal sections being isolated by positioning a series of two or more isolation devices in the second wellbore interval (sections made by packers 450, making sections discussed in paragraph 0030). C) pumping a fracturing fluid into the first wellbore interval, via the single wellhead which serves the first wellbore interval, to produce the interacting hydraulic fractures and propagate the interacting hydraulic fractures at least as far as the second wellbore interval (see paragraph 0030), at least a portion of the fracturing fluid pumped in step (c) being received in the second wellbore interval via the interacting hydraulic fractures (see Fig. 4B above, showing fractures reaching each bore; paragraph 0029 discussing “connection” between the bores). At least one of the isolation devices positioned in the second wellbore interval in step (b) being positioned between the predicted interaction zone of the second wellbore interval and the single wellhead which serves the second wellbore interval to (i) prevent the portion of the fracturing fluid which is received in the second wellbore interval from flowing to the single wellhead which serves the second wellbore interval and (ii) prevent pressure loss in the predicted interaction zone of the second wellbore interval, without interfering with the pumping of the fracturing fluid into the first wellbore interval in step (c) via the single wellhead which serves the first wellbore interval (see paragraph 0028 discussing packers in upper wellbore, including dealing with pressurization).
CLAIM 2: The first wellbore interval being a wellbore interval of a first well and the second wellbore interval being a wellbore interval of a second well which is different from the first well (see Fig. 4B). The single wellhead which serves the first wellbore interval being different from the single wellhead which serves the second wellbore interval (see Fig. 4B).
CLAIM 3: The first wellbore interval being at least a portion of a lateral wellbore of the first well and the second wellbore interval being at least a portion of a lateral wellbore of the second well (see Fig. 4B).
CLAIM 9: The openings (perforations) provided through the casing or liner of the first wellbore interval being a longitudinal series of two or more of the clusters of openings; there being a cluster spacing distance between each adjacent pair of the clusters of openings in the longitudinal series of two or more clusters of openings in the first wellbore interval; at least one said cluster spacing distance between an adjacent pair of the clusters of openings being a maximum cluster spacing distance (see Fig. 4B showing cluster of perforations for each connection 425); the series of two or more isolation devices positioned in the second wellbore interval in step (b) being a series of at least three of the isolation devices; and no adjacent ones of the isolation devices in the series of at least three of the isolation devices being spaced a distance apart which is more than the maximum cluster spacing distance (see Fig. 4B).
CLAIM 10: The isolation devices being hard plugs (“physical diverting agents”, paragraph 0030).
CLAIM 11: The second wellbore interval being an open wellbore interval with no casing or liner therein or the second wellbore interval having a casing or liner therein with perforations, slots, or other openings provided through a wall of the casing or liner (see paragraph 0024 stating casing is optional).
CLAIM 12: The second wellbore interval having a liner therein (see paragraph 0024); the liner of the second wellbore interval having one or more sections of slots or other openings provide through a wall of the liner of the second wellbore interval; positioning a first swell-packer (i) between an exterior of the liner of the second wellbore interval and a borehole wall of the second wellbore interval and (ii) at or beyond a first longitudinal end of the one or more sections of slots or other openings provided through the wall of the liner of the second wellbore interval; and positioning a second swell-packer (i) between the exterior of the liner of the second wellbore interval and the borehole wall of the second wellbore interval and (ii) at or beyond a second longitudinal end, opposite the first longitudinal end, of the one or more sections of slots or other openings provided through the wall of the liner of the second wellbore interval (see Fig. 4B).
CLAIM 13: The fracturing fluid including a proppant material during at least a portion of step (c) (see paragraph 0019).
CLAIM 14: The portion of the fracturing fluid received in the second wellbore interval via the interacting hydraulic fracturs acting to propagate hydraulic fractures from and beyond the second wellbore interval (see paragraph 0023, via pump and blender system 250).
CLAIM 16: Placing a proppant material in one or more of the one or more longitudinal sections of the second wellbore interval which are isolated in step (b) and the proppant material placed in the one or more sections of the second wellbore interval being carried by the portion of the fracturing fluid received in the second wellbore interval into the hydraulic fractures which are propagated from and beyond the second wellbore interval (see Fig 4B, proppant moving in the hydraulic connection 425).
CLAIM 17: Providing a third wellbore interval, different from the first wellbore interval and the second wellbore interval, in the subterranean formation and the third wellbore interval being positioned and oriented with respect to the second wellbore interval so that at least some of the hydraulic fractures propagated from and beyond the second wellbore interval by the portion of the hydraulic fracturing fluid propagate toward and at least reach the third wellbore interval, the hydraulic fractures which reach the third wellbore interval being secondary interacting hydraulic fractures and an amount of the portion of the hydraulic fracturing fluid is received in the third interval via the secondary interacting hydraulic fractures (see Figs. 5A, B showing numerous wellbores).
CLAIM 18: Prior to the propagation of hydraulic fractures from and beyond the second wellbore interval, isolating one or more longitudinal sections of a predicted interaction zone of the third wellbore interval in which it is predicted that the secondary interacting hydraulic fractures from the second wellbore interval will interact with the third wellbore interval, the one or more longitudinal sections of the predicted interaction zone of the third wellbore interval being isolated by positioning a series of two or more isolation devices in the third wellbore interval (see Figs. 5A/B, paragraph 0031 discussing using the same procedure on more wells). At least one of the isolation devices positioned in the third wellbore interval in step (b) being positioned between the predicted interaction zone of the third wellbore interval and a single wellhead which serves the third wellbore interval to (i) prevent the amount of the portion of the fracturing fluid received in the third wellbore interval from flowing to the single wellhead which serves the third wellbore interval and (ii) prevent pressure loss in the predicted interaction zone of the third wellbore interval, without interfering with the pumping of the fracturing fluid into the first wellbore interval in step (c) via the single wellhead which serves the first wellbore interval (see discussion above with respect to two boreholes; paragraph 0031).
CLAIM 20: The amount of the portion of the fracturing fluid received in the third wellbore interval via the secondary interacting hydraulic fracture acting to propagate hydraulic fractures from and beyond the third wellbore interval (see Fig. 5B showing reach of fluid).
CLAIM 21: Steps a-c are discussed above in claim 1. Martysevich further discloses continuing to pump the fracturing fluid into the first wellbore into the first wellbore interval so that the portion of the fracturing fluid received in the second wellbore interval via the interacting fractures acts to propagate further hydraulic fractures from and beyond the second wellbore interval (see paragraph 0030 stating the fractures can be “throughout the target area 440”, which extends above the upper wellbore).
CLAIM 22: Placing a proppant material in one or more of the one or more longitudinal sections of the second wellbore interval which are isolated in step (b) and the proppant material placed in the one or more sections of the second wellbore interval being carried by the portion of the fracturing fluid received in the second wellbore interval into the hydraulic fractures which are propagated from and beyond the second wellbore interval (see discussion of claim 16 above).
CLAIM 23: Providing a third wellbore interval, different from the first wellbore interval and the second wellbore interval, in the subterranean formation (see Fig. 5B showing plurality of bores). The third wellbore interval being positioned and oriented with respect to the second wellbore interval so that at least some of the hydraulic fractures propagated from and beyond the second wellbore interval by the portion of the hydraulic fracturing fluid propagate toward and reach the third wellbore interval (see Fig. 5B). The hydraulic fractures which reach the third wellbore interval being secondary interacting hydraulic fractures and an amount of the portion of the hydraulic fracturing fluid being received in the third wellbore interval via the secondary interacting hydraulic fractures; prior to the propagation of hydraulic fractures from and beyond the second wellbore interval, isolating one or more longitudinal sections of a predicted interaction zone of the third wellbore interval in which it is predicted that the secondary interacting hydraulic fractures from the second wellbore interval will interact with the third wellbore interval; and continuing to pump the fracturing fluid into the first wellbore interval so that the amount of the portion of the fracturing fluid received in the third wellbore interval via the secondary interacting hydraulic fractures acts to propagate further hydraulic fractures from and beyond the third wellbore interval (see discussion above, same methods applied to two wellbores would apply to three).
Claim Rejections - 35 USC § 103
The text of those sections of Title 35, U.S. Code not included in this action can be found in a prior Office action.
Claim(s) 4-7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Martysevich.
Martysevich discloses the elements of claim 1 as discussed above.
Martysevich fails to disclose a single well which includes both the first wellbore interval and the second wellbore interval and the single wellhead which serves the first wellbore interval being the same as the single wellhead which serves the second wellbore interval (claim 4); the first wellbore interval being at least a portion of a first lateral of the single well and the second wellbore interval being at least a portion of a second lateral of the single well different from the first lateral (claim 5); the first wellbore interval and the second wellbore interval being located in opposite laterals of a horseshoe well (claim 6); or the first wellbore interval and the second wellbore interval being positioned together in a plain of symmetry (claim 7).
Examiner takes official notice that the claimed wellbore geometries are well known in the art as common wellbore shapes based on the features of the geological area.
It would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to modify the method of Martysevich to utilize on alternative wellbore geometries with a reasonable expectation of success as Martysevich teaches that the wellbores can be placed in various relative positions as long as they are in the target area (see paragraph 0032).
Response to Arguments
Applicant's arguments filed 10/15/25 have been fully considered but they are not persuasive.
Applicant asserts that the prior art fails to disclose an isolation device as described in the claims. Martysevich teaches packers 450 in the second wellbore interval. The packers are used to “seal off sections of the wellbore” (paragraph 0030). This seal would sequester the wellhead from the pressure and the fluid contained within the interval. While there is a pressure differential between the upper and lower wellbores (paragraph 0028), that does not extend to the wellhead as Applicant asserts.
Applicant further asserts that Martysevich fails to disclose specific wellbore orientation. However, as discussed above in the previous action, while those orientations are not taught by Martysevich, they are well known in the art and would be obvious to one of ordinary skill in the art.
The language of claims 14, 17, and 20-23 are discussed above.
Conclusion
THIS ACTION IS MADE FINAL. Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to PATRICK F LAMBE whose telephone number is (571)270-1932. The examiner can normally be reached M-Th 10-4.
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/PATRICK F LAMBE/Examiner, Art Unit 3679
/TARA SCHIMPF/Supervisory Patent Examiner, Art Unit 3676