DETAILED ACTION
This communication is a first office action on the merits. All currently pending claims have been considered below. The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Amendment
The amendments filed 12/4/2025 are sufficient to obviate all prior objections, 112(b) rejections, and prior art rejections. New grounds necessitated by amendment respectfully follow.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claims 1-3 & 17-19 are rejected under 35 U.S.C. 103 as being unpatentable over US 5,762,149 (Donovan) in view of US 5,868,210 (Johnson).
Independent claim 1. Donovan discloses a system (figs 11 & 15) comprising:
a fluid separator ("the branch well bore 176 that will have contained therein process equipment 178 such as water separator and injector" - col 12:28-30. ("Thus, the separator 250 [shown in figure 15] is operative in an environment similar to FIG. 6, but may also be placed within a branch well as seen in FIGS. 5, 7, 8, and 11. Further, the separator/pump 250 may be placed in either a vertical, deviated or horizontal inclination within a well" - col 13:53-57; i.e. the separator/pump 250 may be the detailed form of the separator/pump 178 in fig 11) disposed within a lateral bore ("branch well bore 176") of a multilateral well (fig 11), wherein the fluid separator is configured to receive formation fluid from a main bore of the multilateral well ("The branch well bore 30D will be completed to the hydrocarbon reservoir 12 via the completion 174 for producing the reservoir's 12 fluids and gas" - col 12:25-27. Fluid exiting "branch" 30D pass through the main bore as it flows to "branch well bore 176" via "diverter tubing 186" - fig 11) and separate the formation fluid ("water separator" - col 12:28-30) into formation water ("output tubing 292 for discharging the separated water" - col 15:8-9 & fig 15) and production fluid ("output tubing 304 so that the oil which has been separated may be pumped to the surface" - col 15:28-30), wherein the fluid separator is configured to output the production fluid to flow uphole ("…so that the oil which has been separated may be pumped to the surface" - ibid);
a lower lateral packer disposed within the lateral bore ("packer 244" - fig 15 & col 13:63 - through which "output tubing 292 for discharging the separated water" extends - col 15:8-9) in a position downhole from the fluid separator (ibid); and
a downhole pump disposed in the lateral bore ("a separate down hole reinjection pump is used to assist reinjection" - col 16:58-62), wherein the downhole pump is configured to receive the formation water from the fluid separator (ibid) and pump the formation water to flow into a portion of the lateral bore downhole from the lower lateral packer (No additional water line is taught or shown in fig 11 so it naturally follows that the "water separator and injector" 178 outputs hydrocarbons to 188 and injects water into the zone surrounding branch 176: fig 11).
While Donovan discloses "the lower end of the main access well bore may act as a completion without the need of a separate branch" (col 6:43-45) this does not necessarily equate to a fluid producing completion as opposed to an injection completion, and therefore Donovan does not explicitly disclose that the formation fluid is produced via a lower completion assembly disposed in a main wellbore of the multilateral well system, as required by the current amendments.
However Johnson discloses a multi-lateral well system (title, fig 7) where the main wellbore ("primary wellbore 20" - last full ¶ of col 12) has at its lower end a production completion assembly in a production zone ("reservoir 430" - last full ¶ of col 12; "Hydrocarbons from the formations 82, 84 and 420 may be produced in the manner described above or by any other known method. Such a method is useful when it is desired to drill the primary access wellbore into one or more reservoirs, such as reservoir 420, and avoid drilling it in to one or more reservoirs, such as reservoirs 82 and 84" - ibid. The examiner notes that (1) "lower completion assembly" is recited without any specific structure; (2) Johnson expressly teaches producing from the bottom of the main wellbore, and "may be produced in the manner described above or by any other known method", as cited above, which is enough for the level of generality of the claim; and (3) Johnson teaches generalized completion structure in figs 3-6: 162a, 162b, 164, 408a-408d, etc).
Therefore it would have been obvious to one having ordinary skill in the art at the time of filing to produce from a lower completion of the main wellbore in a multilateral wellbore system as taught by Johnson, in the multilateral wellbore system taught by Donovan. First, as discussed above, Donovan already teaches "the lower end of the main access well bore may act as a completion without the need of a separate branch" (col 6:43-45) thus clearly suggesting to the reader that production from the completion in the main well bore is contemplated. Johnson expressly teaches it as known. The examiner also respectfully asserts it is well within the skill of PHOSITA to route production fluid from the main wellbore to the separation and disposal / injection lateral taught by Donovan, especially because Donovan suggests as much in cols 6:43-45 as quoted above.
2. The system of claim 1, further comprising a lower tubing (Donovan: "output tubing 292" - fig 15) extending between the downhole pump ("a separate down hole reinjection pump is used to assist reinjection" - col 16:58-62) and the lower lateral packer (Tubing 292 is shown extending through packer 244 and is taught as extending to "a separate down hole reinjection pump is used to assist reinjection" - col 16:58-62), wherein an upper end of the lower tubing is in fluid communication with a water outlet of the downhole pump (ibid; "fluid communication" is required for "output tubing 292 for discharging the separated water" to flow the water to "a separate down hole reinjection pump"), and wherein the formation water is directed to flow into the portion of the lateral bore downhole from the lower lateral packer via the lower tubing (ibid).
3. The system of claim 1, further comprising a fluid conduit (Donovan: "output tubing 292" - fig 15) extending between a water outlet of the fluid separator ("an opening 290 that has associated therewith an output tubing 292 for discharging the separated water" - col 15:7-9) and a water inlet of the downhole pump (necessary to communicate with "a separate down hole reinjection pump is used to assist reinjection" - col 16:58-62).
Independent claim 17. Donovan discloses a method of separating oil from water downhole (abstract) in a multilateral well (fig 11) comprising:
directing formation fluid ("The branch well bore 30D will be completed to the hydrocarbon reservoir 12 via the completion 174 for producing the reservoir's 12 fluids and gas" - col 12:25-27) from a main bore (fluid exiting "branch" 30D pass through the main bore as it flows to "branch well bore 176" via "diverter tubing 186" - fig 11) of a multilateral well (fig 11) to flow into a lateral bore ("branch well bore 176") of the multilateral well;
drawing the formation fluid into a fluid separator ("the branch well bore 176 that will have contained therein process equipment 178 such as water separator and injector" - col 12:28-30) from the lateral bore (fig 11), wherein the fluid separator is located in the lateral bore (fig 11), and wherein the formation fluid at least includes formation water produced fluid (abstract; "water separator" - col 12:28-30);
separating the production fluid from the formation water via the fluid separator (ibid);
outputting the production fluid from the fluid separator to flow uphole toward a surface ("The hydrocarbon fluid and gas will then be transferred via the diverter tubing 188" - fig 11 & col 12:49-51; "The diverter tubing will deliver the hydrocarbon stream to the production tubing 198 for transporting to the surface as is well known in the art" - col 12:58-61); and
injecting the formation water from the fluid separator ("the branch well bore 176 that will have contained therein process equipment 178 such as water separator and injector" - col 12:28-30") into a downhole formation disposed about the lateral bore (fig 11).
While Donovan discloses "the lower end of the main access well bore may act as a completion without the need of a separate branch" (col 6:43-45) this does not necessarily equate to a fluid producing completion as opposed to an injection completion, and therefore Donovan does not explicitly disclose that the formation fluid is produced via a lower completion assembly disposed in a main wellbore of the multilateral well system, as required by the current amendments.
However Johnson discloses a multi-lateral well system (title, fig 7) where the main wellbore ("primary wellbore 20" - last full ¶ of col 12) has at its lower end a production completion assembly in a production zone ("reservoir 430" - last full ¶ of col 12; "Hydrocarbons from the formations 82, 84 and 420 may be produced in the manner described above or by any other known method. Such a method is useful when it is desired to drill the primary access wellbore into one or more reservoirs, such as reservoir 420, and avoid drilling it in to one or more reservoirs, such as reservoirs 82 and 84" - ibid. The examiner notes that (1) "lower completion assembly" is recited without any specific structure; (2) Johnson expressly teaches producing from the bottom of the main wellbore, and "may be produced in the manner described above or by any other known method", as cited above, which is enough for the level of generality of the claim; and (3) Johnson teaches generalized completion structure in figs 3-6: 162a, 162b, 164, 408a-408d, etc).
Therefore it would have been obvious to one having ordinary skill in the art at the time of filing to produce from a lower completion of the main wellbore in a multilateral wellbore system as taught by Johnson, in the multilateral wellbore system taught by Donovan. First, as discussed above, Donovan already teaches "the lower end of the main access well bore may act as a completion without the need of a separate branch" (col 6:43-45) thus clearly suggesting to the reader that production from the completion in the main well bore is contemplated. Johnson expressly teaches it as known. The examiner also respectfully asserts it is well within the skill of PHOSITA to route production fluid from the main wellbore to the separation and disposal / injection lateral taught by Donovan, especially because Donovan suggests as much in cols 6:43-45 as quoted above.
18. The method of claim 17, wherein the production fluid output from the fluid separator (Donovan: 178, fig 11) is configured to flow into a crossflow packer (packer uphole from 178, clearly shown but not individually numbered in fig 11; the same packer symbol in branch 176 is used for "packer 184" and "packer 192" also in fig 11), flow through production tubing ("diverter tubing 188" - col 12:49-51) extending between the crossflow packer and an upper main bore packer ("The main access well bore 2 will have disposed therein a packer 192" - col 12:55-56 & fig 11) and continue to flow uphole toward the surface ("The packer 192 will have extending therefrom the production tubing 198. The diverter tubing will deliver the hydrocarbon stream to the production tubing 198 for transporting to the surface as is well known in the art" - col 12:55-61).
19. The method of claim 17, wherein the production fluid is directed to flow uphole from the fluid separator toward the surface through an inner tubing ("The hydrocarbon fluid and gas will then be transferred via the diverter tubing 188" - fig 11 & col 12:49-51; "The diverter tubing will deliver the hydrocarbon stream to the production tubing 198 for transporting to the surface as is well known in the art" - col 12:58-61) disposed within a junction tubing (drawn to the conventional "main access casing 2" - col 10:3 - that lines the well, including across the junctions: col 7:9-12. See also col 7:33-41), and wherein the formation water is output from the fluid separator ("Thus, the separator 250 [shown in figure 15] is operative in an environment similar to FIG. 6, but may also be placed within a branch well as seen in FIGS. 5, 7, 8, and 11. Further, the separator/pump 250 may be placed in either a vertical, deviated or horizontal inclination within a well" - col 13:53-57; i.e. the separator/pump 250 may be the detailed form of the separator/pump 178 in fig 11) to flow through a lower lateral packer ("packer 244" - fig 15 & col 13:63 - through which "output tubing 292 for discharging the separated water" extends - col 15:8-9) and into a lower portion of the lateral bore (via "equipment 178 such as water separator and injector" - col 12:30-31. No additional water line is taught or shown in fig 11 so it naturally follows that the "water separator and injector" 178 outputs hydrocarbons to 188 and injects water into the zone surrounding branch 176: fig 11).
Claim 12 is rejected under 35 U.S.C. 103 as being unpatentable over the combination of US 5,762,149 (Donovan) & US 5,868,210 (Johnson), in further view of US 6,167,965 (Bearden).
Claim 12. The combination discloses all the limitations of parent claim 1 as described above, and while Donovan discloses a pump for injecting the separated water ("a separate down hole reinjection pump is used to assist reinjection" - col 16:58-62), Donovan discloses this generically and does not expressly disclose it is an electric submersible pump.
However Bearden discloses an electrical submersible pump (title) that may be used to inject water into the formation ("use of the improved ESP as a subsurface waste water injector" - col 2:33-34).
Therefore it would have been obvious to one having ordinary skill in the art at the time of filing to use the ESP taught by Bearden to reinject the water as taught by Donovan. First, Donovan expressly teaches a pump, but does not disclose details, thus forcing the reader to look elsewhere for a more detailed disclosure. ESPs are exceedingly well known in the art, and Bearden teaches specifically that they are known as a subsurface waste water injector (ibid). The ESP taught by Bearden has increased internal monitoring (first full ¶ of col 19; first full ¶ of col 21; ¶ bridging cols 21 & 22) and increased fluid monitoring (¶ bridging cols 20 & 21).
Claim 13 is rejected under 35 U.S.C. 103 as being unpatentable over US 5,762,149 (Donovan) & US 5,868,210 (Johnson), in further view of US 2023/0066633 (Trisal).
Claim 13. The combination discloses all the limitations of the parent claim, but does not expressly disclose those of the present. However Trisal discloses a multilateral well system (title, fig 2) comprising a lower completion assembly (portion of the completion below "lateral borehole 36" holding "lower completion equipment 44" - fig 2 & ¶ 14) disposed within the main bore (fig 2) in a position downhole from a completion deflector ("lateral deflection device 80" - ¶ 21), wherein the lower completion assembly includes:
a lower main production tubing ("tubing 48" in fig 1; clearly shown in fig 2 but not individually numbered in fig 2; "The lower completion equipment 44 also may comprise a tubular component 116, e.g. a polished bore receptacle, to receive a lower completion seal assembly and latch system 118 of intermediate completion 66. In this embodiment, the lower completion seal assembly and latch system 118 may be connected into intermediate completion 66 via a stinger 120. The lower completion seal assembly and latch system 118 is sealingly received by tubular component 116 of lower completion equipment 44 and latched thereto when intermediate completion 66 is deployed downhole" - ¶ 31);
a plurality of completion packers ("the lower completion equipment 44 may comprise a plurality of flow control valves 112 which can be controlled to provide sub-zonal flow control along the primary borehole 34. The sub-zones may be isolated using corresponding packers 114" - ¶ 31) disposed about the lower main production tubing (fig 2; "a plurality of flow control valves 112" are taught and shown, and "corresponding packers 114" are taught for "the sub-zones" - ¶ 31) and configured to isolate production zones in the main bore (ibid, as is well understood for the zonal isolation taught by Trisal);
at least one screen disposed within between [sic] adjacent packers of the plurality of completion packers ("sand screen assemblies, positioned along tubing 48 and sometimes separated by packers" - ¶ 14; " a plurality of completion assemblies 46, e.g. sand screen assemblies or other suitable assemblies, positioned along tubing 48 and separated by a plurality of isolation devices 58, e.g. isolation packers" - ¶ 15), wherein the at least one screen is configured to filter production fluid flowing into the lower main production tubing ("sand screen assemblies" - ¶ 14; "various types of sand screens or other filtering devices in combination with various types of sealing devices" - ¶ 34); and
a flow control device ("the lower completion equipment 44 may comprise a plurality of flow control valves 112 which can be controlled to provide sub-zonal flow control along the primary borehole 34" - ¶ 31) configured to control flow of formation fluid into the lower main production tubing (ibid).
Therefore it would have been obvious to one having ordinary skill in the art at the time of filing to use the sand screen zonal isolation completion taught by Trisal at the bottom of the main wellbore taught by Donovan. First, Trisal shows that it is known to have a production zone at the bottom of a main wellbore of a multilateral wellbore system as is already present in both references of the combination, as discussed above. However the combination does not disclose the details of that completion. Second, the use of sand screens, zonal isolation, and inflow control devices is replete and exceedingly well understood in the art. It allows the prevention of sand production, increased production control, and the ability to shut off poorly production zones.
Allowable Subject Matter
Claim 16 is allowed.
Claim 4-11, 14, 15, & 20 are objected to as being dependent upon a rejected base claim, but would be allowable if rewritten in independent form including all of the limitations of the base claim and any intervening claims.
Conclusion
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). 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 Blake Michener whose telephone number is (571)270-5736. The examiner can normally be reached Approximately 9:00am to 6:00pm CT.
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If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Tara Schimpf can be reached at 571.270.7741. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/BLAKE MICHENER/
Primary Examiner, Art Unit 3676