Paper No. 1
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`
`UNITED STATES PATENT AND TRADEMARK OFFICE
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`______________
`
`BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
`
`BAKER HUGHES INCORPORATED
`and
`
`BAKER HUGHES OILFIELD OPERATIONS, INC.,
`
`Petitioners
`
`
`
`v.
`
`
`
`PACKERS PLUS ENERGY SERVICES, INC.,
`
`Patent Owner
`
`______________
`
`Inter Partes Review No. IPR2016-01380
`Patent 9,303,501
`______________
`
`
`
`PETITION FOR INTER PARTES REVIEW UNDER 35 U.S.C. § 312
`
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`27331867.4
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`Table of Contents
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`IPR2016-01380
`Patent 9,303,501
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`V.
`
`INTRODUCTION ........................................................................................... 1
`I.
`II. MANDATORY NOTICES ............................................................................. 3
`A.
`Real Party in Interest (37 C.F.R. § 42.8(b)(1)) ..................................... 3
`B.
`Related Matters (37 C.F.R. § 42.8(b)(2)) .............................................. 3
`C.
`Lead and Back-Up Counsel (37 C.F.R. § 42.8(b)(3)) ........................... 4
`D.
`Service Information (37 C.F.R. § 42.8(b)(4)) ....................................... 4
`III. GROUNDS FOR STANDING ........................................................................ 5
`IV. STATEMENT OF PRECISE RELIEF REQUESTED ................................... 5
`A.
`Claims for Which Review Is Requested (37 C.F.R. § 42.104(b)(1)).... 5
`B.
`Statutory Grounds (37 C.F.R. § 42.104(b)(2)) ...................................... 5
`FIELD OF TECHNOLOGY ........................................................................... 7
`A. Drilling an Oil Well ............................................................................... 7
`B. Well Stimulation and Selective Fluid Treatment .................................. 8
`C.
`Packers ................................................................................................. 12
`D.
`Plugs .................................................................................................... 13
`VI. LEVEL OF ORDINARY SKILL IN THE ART ........................................... 15
`VII. THE ’501 PATENT ....................................................................................... 18
`A. Admitted Prior Art and Perceived Shortcomings ............................... 19
`B.
`The ’501 Patent’s Asserted Improvement to the Prior Art ................. 19
`C.
`Claim Construction (37 C.F.R. § 42.104(b)(3)) .................................. 25
`1.
`“solid body packer” (claim 1) .................................................. 26
`2.
`“fracturing fluid” (claim 1) ...................................................... 27
`3.
`“piston” (claims 4-6) ................................................................ 27
`4.
`“sleeve” (claim 1) ..................................................................... 28
`Claims 1-9 Are Not Entitled to Priority before November 19,
`2002 ..................................................................................................... 28
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`D.
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`IPR2016-01380
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`VIII. REASONS FOR THE RELIEF REQUESTED UNDER 37 C.F.R.
`§§ 42.22(A)(2) AND 42.104(B)(4) ............................................................... 30
`A. Ground 1 – Obvious over Thomson, Ellsworth, and Halliburton ....... 30
`1.
`Thomson, Ellsworth, and Halliburton render claim 1 obvious 43
`2.
`Thomson, Ellsworth, and Halliburton render claims 2-9 obvious .. 56
`B. Ground 2 – Obvious over Thomson, Ellsworth, and Halliburton ....... 60
`C. Ground 3 – Obvious over Thomson, Ellsworth, and Kammerer ........ 63
`IX. CONCLUSION .............................................................................................. 70
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`Petitioner’s Exhibit List
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`IPR2016-01380
`Patent 9,303,501
`
`1003
`
`Description
`Exhibit
`1001 U.S. Patent No. 9,303,501 (“the ’501 Patent”)
`1002 D.W. Thomson, et al., Design and Installation of a Cost-Effective
`Completion System for Horizontal Chalk Wells Where Multiple Zones
`Require Acid Stimulation, SPE (Society for Petroleum Engineering)
`37482 (1997) (“Thomson”)
`B. Ellsworth, et al., Production Control of Horizontal Wells in a
`Carbonate Reef Structure, 1999 Canadian Institute of Mining,
`Metallurgy, and Petroleum Horizontal Well Conference (“Ellsworth”)
`1004 Affidavit of Aileen Barr of Halliburton Energy Services, Inc., regarding
`Halliburton Completion Products, Second Edition (1997)
`(“Halliburton”), “Attachment A” thereto
`1005 Declaration of Ali Daneshy, Ph.D.
`1006 KATE VAN DYKE, FUNDAMENTALS OF PETROLEUM ENGINEERING (4th
`ed. 1997)
`RON BAKER, A PRIMER OF OIL WELL DRILLING (5th ed. (revised) 1996)
`1007
`1008 U.S. Patent No. 4,099,563 (“Hutchison”)
`1009 U.S. Patent No. 5,375,662
`1010 U.S. Patent No. 6,257,338
`1011
`Excerpts of File History of the ’501 Patent
`1012 U.S. Provisional Application No. 60/404,783, to which the ’501 Patent
`claims priority
`1013 Declaration of Christopher D. Hawkes, Ph.D., P.Geo., regarding the
`proceedings of the 7th One-Day Conference On Horizontal Well
`Technology Operational Excellence (Canada November 3, 1999)
`(including Ex. 1003 at 102-110)
`1014 U.S. Patent No. 7,861,774 (“the ’774 Patent”)
`1015 U.S. Patent No. 5,947,204
`1016 U.S. Patent No. 4,434,854
`1017 Dictionary Definitions from WEBSTER’S THIRD NEW INTERNATIONAL
`DICTIONARY OF THE ENGLISH LANGUAGE (1986)
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`Excerpts of File History of U.S. Patent No. 6,644,411
`1018
`1019 U.S. Serial No. 60/331,491, to which the ’501 Patent claims priority
`1020 M.S. van Domelen, Enhanced Profitability with Non-Conventional IOR
`Technology, SPE 49523 (1998)
`1021 Declaration of Nancy Chaffin Hunter regarding the proceedings of the
`10th Middle East Oil Show & Conference (Bahrain March 15-18, 1997)
`(including Ex. 1002 at 97-108)
`1022 U.S. Patent No. 2,537,066
`1023 Affidavit of Nancy Chaffin Hunter, regarding the proceedings of the
`Production Operation Symposium (Oklahoma City, OK April 2-4,
`1995) (including R. Coon and D. Murray, Single-Trip Completion
`Concept Replaces Multiple Packers and Sliding Sleeves in Selective
`Multi-Zone Production and Stimulation Operations, SPE 29539 (1995))
`1024 U.S. Patent No. 3,306,365 (“Kammerer”)
`1025 U.S. Patent No. 5,181,569
`1026 U.S. Patent No. 6,230,811
`1027
`Excerpts of File History of U.S. Patent No. 6,435,282
`1028
`Excerpts of File History of ’774 Patent
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`IPR2016-01380
`Patent 9,303,501
`Petitioners request inter partes review of U.S.P.N. 9,303,501. The Board is
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`authorized to deduct any required fees from Norton Rose Fulbright US LLP
`
`Deposit Account 50-1212/11608051.
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`I.
`
`INTRODUCTION
`
`The ’501 Patent’s purported invention was a combination of ball-actuated
`
`sliding sleeves [blue] and multi-element packers [red] for selectively treating or
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`“stimulat[ing]” zones in an oil well, such as by “frac’ing” or “acidizing.”
`
`But these systems were known before 2001, the earliest claimed priority date.
`
`Petitioners’ primary reference, Thomson, described such a system in 1997:
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`
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`
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`While Thomson’s figure shows one ball-actuated sliding sleeve [blue] (which it
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`called a “MSAF tool”), its text is clear that “[u]p to 9 MSAF tools [blue] can be
`
`run in the completion with isolation of each zone being achieved by hydraulic-set
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`retrievable packers [red] that are positioned on each side of a MSAF tool [blue].”
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`IPR2016-01380
`Patent 9,303,501
`Patent Owner may attempt to rely on several purported distinctions over the
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`prior art—such as the use of its system in an open (i.e., uncased) hole, the “solid
`
`body” nature of its packers, or its use of a hydraulically-actuated sliding sleeve that
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`is not actuated by a ball—but all fail.
`
`First, it would have been obvious to use Thomson’s system in open holes.
`
`Ellsworth, for example, was already using a similar system in an open hole:
`
`
`Ellsworth explained that, by 1999, “[o]pen hole completions ha[d] been the
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`accepted practice for horizontal wells [in some regions].”
`
`Second, Thomson’s packers are solid body packers, and, even if found not to
`
`be, could be obviously substituted with Ellsworth’s solid body packers.
`
`Finally, Halliburton disclosed a hydraulically-actuated sliding sleeve, pump-
`
`open plug that was an obvious alternative to Thomson’s plug. Furthermore,
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`Kammerer disclosed a hydraulically-actuated sliding sleeve that was an obvious
`
`addition to Thomson’s system.
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`IPR2016-01380
`Patent 9,303,501
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`II. MANDATORY NOTICES
`A. Real Party in Interest (37 C.F.R. § 42.8(b)(1))
`Baker Hughes Incorporated and Baker Hughes Oilfield Operations, Inc. are
`
`the real parties-in-interest.
`
`B. Related Matters (37 C.F.R. § 42.8(b)(2))
`(1) Rapid Completions LLC v. Baker Hughes Incorporated et al., Civil
`
`Action No. 6:16-cv-286 (E.D. Tex. 2016) (the “Litigation”), which involves the
`
`’501 Patent;
`
`(2)
`
`(3)
`
`(4)
`
`(5)
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`IPR2016-00596 against U.S.P.N. 7,134,505 (the ’505 Patent);
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`IPR2016-00597 against U.S.P.N. 7,543,634 (the ’634 Patent);
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`IPR2016-00598 against U.S.P.N. 7,861,774 (the ’774 Patent);
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`IPR2016-00650 against U.S.P.N. 6,907,936 (the ’936 Patent);
`
`(6)
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`IPR2016-00656 against U.S.P.N. 8,657,009 (the ’009 Patent);
`
`(7)
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`IPR2016-00657 against U.S.P.N. 9,074,451 (the ’451 Patent);
`
`(8)
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`IPR2016-01496 against the ’505 Patent;
`
`(9)
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`IPR2016-01505 against the ’634 Patent;
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`(10) IPR2016-01506 against the ’774 Patent;
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`(11) IPR2016-01517 against the ’505 Patent;
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`(12) IPR2016-01514 against the ’634 Patent;
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`(13) IPR2016-01509 against the ’774 Patent;
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`(14) U.S.P.N. 7,571,765;
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`(15) U.S.P.N. 7,832,472;
`
`(16) U.S.P.N. 8,397,820;
`
`(17) U.S.P.N. 8,746,343;
`
`(18) U.S.P.N. 9,366,123;
`
`(19) U.S.P.A.N. 15/149,742;
`
`(20) U.S.P.A.N. 15/149,971; and
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`(21) Rapid Completions LLC v. Baker Hughes Incorporated et al., Civil
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`Action No. 6:15-cv-724 (E.D. Tex. 2015), which involves the ’505, ’634, ’774,
`
`’936, ’009, and ’451 Patents.
`
`Lead and Back-Up Counsel (37 C.F.R. § 42.8(b)(3))
`
`C.
`Lead counsel: Mark T. Garrett (Reg. No. 44,699)
`
`Back-up counsel: Eagle H. Robinson (Reg. No. 61,361)
`
`Service Information (37 C.F.R. § 42.8(b)(4))
`
`D.
`Email: mark.garrett@nortonrosefulbright.com
`
`Post: Mark T. Garrett, Norton Rose Fulbright US LLP, 98 San Jacinto
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`Boulevard, Suite 1100, Austin, TX 78701
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`Phone: 512.536.3031
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`Fax: 512.536.4598
`
`Petitioners consent to electronic service.
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`III. GROUNDS FOR STANDING
`Pursuant to 37 C.F.R. § 42.104(a), Petitioners certify that the ’501 Patent is
`
`available for inter partes review, and that Petitioners are not barred or estopped
`
`from requesting an inter partes review challenging the Challenged Claims on the
`
`grounds identified in this Petition. The ’501 Patent has not been subject to a
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`previous estoppel-based proceeding of the AIA, and Petitioners were served with
`
`the original complaint in the Litigation within the last 12 months.
`
`IV. STATEMENT OF PRECISE RELIEF REQUESTED
`A. Claims for Which Review Is Requested (37 C.F.R. § 42.104(b)(1))
`Claims 1-9 (the “Challenged Claims”) of the ’501 Patent.
`
`Statutory Grounds (37 C.F.R. § 42.104(b)(2))
`B.
`Ground 1: Claims 1-9 are invalid under § 103(a) based on Thomson (Ex.
`
`1002), Ellsworth (Ex. 1003), and Halliburton (Ex. 1004), which all published over
`
`one year before November 19, 2002, the priority date to which the claims are
`
`entitled. See Ex. 1021 at ¶¶ 1-6 and appendices, including Thomson as Appendix
`
`A (showing Thomson published in a bound proceedings volume dated 1997 and
`
`catalogued in CSU Libraries in 2000)1; Ex. 1013 at ¶¶ 1-5 and 102-110 (showing
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`Ellsworth published
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`in 1999); Ex. 1004 at ¶¶ 1-6 and Attachment A
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`1 See also Ex. 1020 at 605, n. 28 (referencing, in 1998, Thomson).
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`(“Halliburton”) (showing—along with indicia on the last page—Halliburton
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`published in 1997). Thomson, Ellsworth, and Halliburton are thus § 102(b) art.
`
`Pages from Halliburton were also submitted in IDSs in other cases, further
`
`proving Halliburton is prior art. See Ex. 1027 at 73-85/126 (1/31/2001 IDS citing
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`“Halliburton; Completion Products, Second Edition; 1997; Pages 5-5 thru 5-9, 5-
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`22,” identical to Ex. 1004 pages 4/155, 155/155, 120-125/155, and 137/155); Ex.
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`1018 at 45-57/176 (7/17/2001 IDS citing “Halliburton and Otis, Inc: Completion
`
`Products, Second Edition, Chapter 5: Subsurface Safety Equipment, pp. 5-1-5-5
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`and 5-18, Halliburton Energy Services, Inc., 1997,” identical to Ex. 1004 pages
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`116-120/155 and 133/155). Ex. 1027 became publicly-accessible in August 2002
`
`(when Ex. 1027’s patent issued) and Ex. 1018 became publicly-accessible in
`
`October 2002 (when Ex. 1018’s application published), reinforcing that Ex. 1004
`
`is at least § 102(a) art, though the knowledge of Ex. 1018’s inventors (POSITAs,
`
`given the subject of their patent) at assignee Kvaerner Oilfield Products, Inc. as of
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`July 2001 reinforces that Halliburton is § 102(b) art.2
`
`Ground 2: Claims 1-9 are invalid under § 103(a) based on Thomson,
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`Ellsworth, and Halliburton. Ground 2 is not cumulative because it combines these
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`2 Citations in the XX/XX format are to the Petitioner-added “Page XX of XX”
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`numbering at the lower right-hand corner of the referenced exhibit.
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`references differently to address any argument that Thomson’s packers are not
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`solid body packers.
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`Ground 3: Claims 1-9 are invalid under § 103(a) based on Thomson,
`
`Ellsworth, and Kammerer (Ex. 1024), which is § 102(b) art.
`
`V.
`
`FIELD OF TECHNOLOGY
`
`The ’501 Patent describes selectively stimulating or treating segments of an
`
`oil well using ball-actuated sleeves to open ports in a tubing string. See, e.g., Ex.
`
`1001 at 1:21-24, 2:39-3:7; Ex. 1005 at ¶¶ 54-63.
`
`A. Drilling an Oil Well
`Drilling a well generally includes drilling a hole to construct a wellbore in a
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`geological formation with oil or gas reserves. The wellbore is normally lined with
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`pipe or “casing” to protect the wellbore during production operations. See Ex.
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`1005 at ¶ 28; see also Ex. 1006 at 108. In some circumstances, however, a
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`wellbore may be left uncased (referred to as an “open hole”) to “expose porosity
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`and permit unrestricted wellbore inflow of petroleum products.” Ex. 1001 at 1:28-
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`32; see also Ex. 1005 at ¶ 29. If a wellbore is cased, access to the formation is
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`provided by “perforating” or creating openings in the casing to allow oil and/or gas
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`to flow from the formation into the wellbore. Ex. 1001 at 1:32-34.
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`While it is sometimes possible for formation fluids such as oil and gas to
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`flow up the wellbore when left open or once casing has been perforated, a small-
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`diameter pipe called “production tubing” is typically run into the well as a conduit
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`for petroleum products to flow to the surface. Ex. 1007 at 147. Traditionally, oil
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`wells relied on natural formation pressure and permeability to flow petroleum
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`products to the surface. Ex. 1006 at 23. But when natural flow is insufficient or
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`not economical, “well stimulation” techniques are employed to enlarge existing
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`channels or create new ones in the formation, thereby increasing permeability to
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`help oil and gas flow into the wellbore. See id. at 162; Ex. 1001 at 1:35-36.
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`B. Well Stimulation and Selective Fluid Treatment
`Stimulation typically involves pumping acid or other fluids into a wellbore
`
`under pressure. Ex. 1006 at 162; Ex. 1001 at 1:35-39. If pumped at a high enough
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`pressure, the fluid fractures or “fracs” the formation, creating cracks that radiate
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`outward from the wellbore. Id. at 162-163. These “frac’ing” fluids usually include
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`a “proppant,” such as sand, to hold open the cracks. Id. Related to frac’ing is acid
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`stimulation or “acidizing,” in which acid is pumped into the formation and also
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`chemically reacts with the formation to create similar cracks. Id. at 164.
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`A wellbore may cross multiple formation zones, only some of which contain
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`desirable petroleum products. See, e.g., Ex. 1003 at Figures 7 and 11. Other
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`zones, for example, may include water. Id. at 2-3 (“[W]ater or gas breakthrough
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`can be a problem for some of these wells. . . . The ability to establish long term
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`isolation of segments within the reservoir is key to controlling and optimizing
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`production from these horizontal wells.”). As such, it is often desirable to isolate
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`and stimulate only certain zones within a formation with tools called “packers”
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`which seal the annulus around the production tubing in the wellbore to direct the
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`fluid into the formation zone and protect tubing above and below the zone from
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`produced fluids, which are often corrosive. See Ex. 1007 at 148.
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`Once packers are deployed in the wellbore and set to seal around the
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`production tubing to isolate the desired zones, fluid may be pumped into the
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`isolated zones for stimulation. Ex. 1005 at ¶¶ 31-39. One example of such a
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`completion is described in Hutchison (Ex. 1008), which is listed on the face of the
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`’501 Patent. See Ex. 1001. As annotated in Figure 1 below, Hutchison’s tubing
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`string 19 includes a series of sliding sleeve flow control devices 20 and 21 [blue] to
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`inject treatment fluids into zones isolated by cup-type packers 22, 23, 24, and 25
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`[red]. Ex. 1008 at 2:51-58.
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`Packer
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`Packer
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`Packer
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`Sleeve
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` Sleeve
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` Packer
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`As further annotated in Figures 2 and 4 below, the lower sleeve 20 [blue] has
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`a seat 44 [purple] that is sized to be sealed by a ball 48 [green]. Id. at 3:64-4:59.
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`Upper sleeve 21 [blue], in turn, is sized to mate with a larger ball. Id. at 4:60-5:5.
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`Sleeve [blue]
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`
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`Seat (44)
`[purple]
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`Seat (44)
`[purple]
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`Ball (48) [green]
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` Sleeve [blue]
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`To open the lower sleeve 20, the ball 48 [green] is “dropped” into the tubing string,
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`passes through the upper sleeve 21, and seals against seat 44 of the lower sleeve
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`20. Id. at 4:49-59. This seal prevents fluid from passing through the seat, and
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`increasing pressure shifts the lower sleeve 20 down to open the port (annular
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`chamber 36) and allow fluid to flow from the tubing string into the annulus. Id.
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`After treating the zone between packers 22 and 23, a larger ball is dropped to
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`seal the larger seat of upper sleeve 21 (otherwise identical to lower sleeve 20), and
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`the process is repeated to treat the upper zone between packers 24 and 25. Id. at
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`4:60-6:17. Hutchison thus enables individual treatment of each zone. Ex. 1005 at
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`¶¶ 36-38.
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`Packers
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`C.
`While Hutchison employed cup-type packers for isolation of zones (Ex.
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`1008 at 2:51-58), various other types of packers were also known. Ex. 1005 at
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`¶¶ 40-41. Inflatable packers, for example, were often used in uncased or open
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`wells. See, e.g., Ex. 1009 at 1:43-44 (“Inflatable packers are preferred for use in
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`sealing an uncased well bore.”); Ex. 1023 at 912 (discussing use of external casing
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`packers (ECPs), which are inflatable, in open hole under “ECP AND SLIDING
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`SLEEVES, IN OPEN HOLE”); see also Ex. 1001 at 1:49-51 (“inflatable packers
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`may be limited with respect to pressure capabilities as well as durability”); Ex.
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`1005 at ¶ 40. It was also known that solid body packers—which compress and
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`extrude outward resilient packing elements—could successfully provide effective
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`isolation in open holes that were drilled in the right way and/or through the right
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`formation. See Ex. 1003 at 3 (“Although the expansion ratios for [solid body
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`packers] are [not] as large as for inflatables, the carbonate formation in Rainbow
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`Lake generally drills very close to gauge hole, and effective isolation is possible
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`with these SBP’s.”); see also Ex. 1010 at 4:35-42 (“sealing devices 30, 32, 34 are
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`representatively and schematically illustrated . . . as inflatable packers . . . [o]f
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`course, other types of packers, such as production packers settable by pressure,
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`may be utilized for the packers 30, 32, 34”); Ex. 1005 at ¶¶ 41-42. Ellsworth’s
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`description of “very close to gauge hole” refers to the borehole being round instead
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`of oval, and very close in size to the drill bit, characteristics that can be achieved in
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`mechanically competent formations. Ex. 1005 at ¶ 42. Ellsworth illustrates a
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`principle that had been known and applied in the industry for decades, that tools—
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`such as solid-body packers historically used in cased holes—can also be used, and
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`often were tried and used successfully, in open-hole completions as they became
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`more common. Id. Solid-body packers were often hydraulically “set” via the
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`application of hydraulic pressure to compress the packing element(s). See Ex.
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`1005 at ¶ 41 (citing Ex. 1003 at 3; Ex. 1010 at 4:35-42).
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`Plugs
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`D.
`Tubing strings with inflatable or hydraulically set packers that are activated
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`with tubing pressure often include a “plug” in the tubing string below the
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`lowermost packer. Ex. 1005 at ¶ 43; see also Ex. 1002 at FIG. 3. Such plugs
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`block fluid flow to allow fluid pressurization in the tubing to set the packers and
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`thereby isolate zones in the wellbore. Ex. 1005 at ¶ 43. This use of plugs to
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`pressurize tubing to hydraulically set solid-body packers was known prior to 2001.
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`See Ex. 1002 at 99 (“[P]ressure was applied down the tubing against the pump-out
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`plug . . . to set all seven packers simultaneously”), 100, 101; Ex. 1003 at 3, 5, 7, 8
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`(each of four case histories set production string SBPs using “tubing pressure” held
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`by a pump-out plug).
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`After setting the pressure-activated packers, such plugs are typically
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`removed to permit well treatment and/or production through the tubing. Ex. 1005
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`at ¶ 43; see also Ex. 1002 at 99 (“[T]he stimulation operation was started by
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`expelling the pump out/cycle plug and stimulating the lower zone (below the
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`bottom packer).”). Depending on design, the plug may be retrieved or milled out
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`with a wireline or coiled tubing tool run into the tubing. Ex. 1005 at ¶ 43.
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`Alternatively, some plugs are “pumped out” or expelled from the bottom of the
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`tubing string after setting the packers. Id.; see also Ex. 1002 at 99 (“After all the
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`surface equipment had been rigged up and tested, the stimulation operation was
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`started by expelling the pump out/cycle plug . . . .”); Ex. 1003 at 7-8 (discussing
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`case history #3 in which production string SBPs were set and then plug expended)
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`and 8 (same for case history #4); cf. Ex. 1002 at 100 (“If the plug expends early,
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`the packers cannot be set.”). Such a “pump-out plug” typically employs shear pins
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`that prevent plug release below a threshold pressure. Ex. 1005 at ¶ 43; Ex. 1002 at
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`99 (“Once the lower half of the completion was on depth, pressure was applied
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`down the tubing against the pump-out plug (conventional shear screw release) to
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`set all seven packers simultaneously.”).
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`A “cycle plug” is a variation of a “pump-out plug” that requires the
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`threshold pressure to be applied multiple times to release the plug. Ex. 1005 at
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`¶ 43; Ex. 1002 at 99 (“cycle type plug . . . allowed up to ten pressure cycles to be
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`applied to the tubing before it was expelled”). Upon release, such “pump-out
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`plugs” are expelled into the wellbore (Ex. 1005 at ¶ 43; Ex. 1002 at 99), and “may
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`cause problems during the life of the well.” See Ex. 1015 at 1:29-44; Ex. 1003 at
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`5, 7, 8 (discussing desirability of eliminating equipment debris (the expended plug)
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`in the borehole). Another type of plug, discussed below, is a “pump-open plug”
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`(Ex. 1004 at 96/155), which opens without being expelled. See Ex. 1005 at ¶ 43.
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`VI. LEVEL OF ORDINARY SKILL IN THE ART
`A person of ordinary skill in the art (“POSITA”) relevant to the ’501 Patent
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`as of November 19, 20013—the earliest claimed priority date claimed—would
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`have had at least a Bachelor of Science degree in mechanical, petroleum, or
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`chemical engineering and at least 2-3 years of experience with downhole
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`completion technologies related to fracturing. See id. at ¶ 44. This level of
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`3 All statements in this Petition about the knowledge and skills of, and what would
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`have been obvious to, a POSITA are offered from this perspective as of this date
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`and would be no different as of November 19, 2002. See Ex. 1005 at ¶ 22.
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`ordinary skill is also evidenced by prior art and the ’501 Patent itself. See id. at
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`¶¶ 45-53; Chore-Time Equip., Inc. v. Cumberland Corp., 713 F.2d 774, 779 (Fed.
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`Cir. 1983); Okajima v. Bourdeau, 261 F.3d 1350, 1355 (Fed. Cir. 2001). Here, the
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`prior art described in Section V above demonstrates that a POSITA would have
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`been familiar with various completion systems and stimulation techniques. See Ex.
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`1005 at ¶ 45 (citing declaration Section V, which includes ¶¶ 25-43); see also id. at
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`¶¶ 44, 46-53.
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`A POSITA also would have recognized that cup-type and inflatable packers
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`were not always preferable and, in at least some circumstances, hydraulically set
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`solid body packers would be preferable in cased and open hole wells. See, e.g., id.
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`¶¶ 41-42, 45, 52; see also Ex. 1003 at 3 (“Historically, inflatable packers were used
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`for water shut-off, stimulation, and segment testing. More recently, solid body
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`packer (SBP’s) (see FIG. 4) have been used to establish open hole isolation.”); Ex.
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`1010 at 3:67-4:4 (“the [selective isolation and treatment] method 10 may be
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`performed in wells including both cased and uncased portions, and vertical,
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`inclined and horizontal portions ”); see also Ex. 1001 at 1:29-32. A POSITA
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`would have also recognized that many tools initially designed or used with casing
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`could also be used in uncased wellbores in at least some formations, for both
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`production and stimulation. Ex. 1005 at ¶¶ 42, 47-53; Ex. 1003 at 5 (“SBP’s were
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`run to acidize . . . .”) and 6 (“acid job using SBP’s indicated that the [SBPs]
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`successfully provided isolation”); Ex. 1022 at 3:6-10 (“[W]here the producing
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`formation is firm, it is sometimes possible to set packers directly against the
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`formation and to do away with casing through the productive section with cement
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`behind.”); Ex. 1023 at 912 (section under “ECP AND SLIDING SLEEVES, IN
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`OPEN HOLE”—“ option of acid or low-volume sand fracturing”), FIG. 1.
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`Patent Owner agrees and, during prosecution of the ’501 Patent, submitted in
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`an IDS a report of its own expert witness from Patent Owner’s litigation against
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`Halliburton. See Ex. 1011 at 21/50 (First Supplemental Expert Report of Kevin
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`Trahan (NPL40)).4 In it, Patent Owner’s expert explained that “hard rock
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`formations, once drilled, typically provide a circular cross section conduit, just as a
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`cased hole does. In these types of hard formations a tool that was designed for use
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`in cased hole may be used in open hole.” Ex. 1028 at 34/57.
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`Mr. Trahan further explained that “many tools, including anchoring
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`mechanisms and packing elements, that were initially designed for cased hole, with
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`no contemplation of being used in open hole, have been used in open hole
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`successfully.” Id. An earlier affidavit of Mr. Trahan also explained that: “Packing
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`Elements of many different configurations have been used in cased hole as well as
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`4 Ex. 1028 contains a copy of the report from the file history of the ’774 Patent.
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`Ex. 1028 at 31-57/57.
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`open hole.” See Ex. 1011 at 27/50 (Affidavit of Kevin Trahan (NPL94)5); Ex.
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`1028 at 18/57. Due to imperfections in uncased wellbores, “the longer the packing
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`element, the more opportunity there is that some section of the packing element
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`will be located over a portion of the wellbore that has continuity” and that
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`“[a]nother idea used in the industry for increasing reliability of packers in open
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`hole is redundancy . . . .” Ex. 1028 at 18-19/57. In particular, “[i]f more packing
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`elements are employed there is a greater opportunity for at least one of the packing
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`elements to seal in a portion of the borehole that has continuity.” Id. at 19/57. Mr.
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`Trahan explained that it “[was] not a new, unique, or innovative concept to use this
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`approach for sealing in open hole” because “[r]edundant packers have been used
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`on many occasions to increase reliability in open hole applications.” Id.; see also
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`Ex. 1003 at 3 (“When possible, the packers are run in pairs to minimize the chance
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`of failure due to setting in a vug [a type of void.]”).
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`VII. THE ’501 PATENT
`The ’501 Patent is entitled “Method and Apparatus for Wellbore Fluid
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`Treatment,” and discloses “a method and apparatus for selective communication to
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`a wellbore for fluid treatment.” Ex. 1001 at 1:1-2 and 1:29-32.
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`5 Ex. 1028 contains a copy of the Affidavit from the file history of the ’774 Patent.
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`Id. at 14-22/57.
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`A. Admitted Prior Art and Perceived Shortcomings
`As the BACKGROUND OF THE INVENTION section reflects, methods of
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`selective fluid treatment were well known in the prior art: “In one previous
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`method, the well is isolated in segments” by packers and each segment is thereafter
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`“individually treated so that concentrated and controlled fluid treatment can be
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`provided along the wellbore.” Id. at 1:49-52.
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`The ’501 Patent asserts that “inflatable element packers” were often used in
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`this previous method, and criticizes such packers as “limited with respect to
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`pressure capabilities as well as durability under high pressure conditions.” Id. at
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`1:52-59. The ’501 Patent also asserts that this previous method was “expensive
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`and time consuming” because the packers must generally “be moved after each
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`treatment if it is desired to isolate other segments of the well for treatment” and
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`because stimulation pumping equipment is required “to be at the well site for long
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`periods of time or for multiple visits.” Id. at 1:59-65.
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`The ’501 Patent’s Asserted Improvement to the Prior Art
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`B.
`To address these perceived shortcomings, the ’501 Patent provides “for the
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`running in of a fluid treatment string, the fluid treatment string having ports
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`substantially closed against the passage of fluid therethrough but which are
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`openable when desired to permit fluid flow into the wellbore.” Id. at 2:38-42. The
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`’501 Patent notes that such a method may be used in various borehole conditions
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`including open holes, cased holes [and] horizontal holes . . . .” Id. at 2:42-46.
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`As annotated in Figure 1a below, the ’501 Patent depicts a wellbore 12
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`drilled through a formation 10 and a tubing string assembly run in the wellbore.
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`Id. at 6:11-19. The borehole is not cased. See id. at 10:28-32.
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`TO SURFACE
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`PACKER
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`WELLBORE
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`PACKER
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`PACKER
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`PACKER
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`PACKER
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`LOWER
`END
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`TOOL
`STRING
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`PORTED
`INTERVALS
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`FIG. 1a
`(annotated)
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`
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`The tubing string 14 includes ports 17 [blue] in each of multiple ported intervals
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`16a-e, which are “opened through the tubing string wall to permit access between
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`the tubing string inner bore 18 and the wellbore.” Id. at 6:15-19. Ported intervals
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`16a-e are separated by packers 20a-f [red] to divide the formation into zones for
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`fluid treatment through ports 17 and thereby prevent treatment fluids from entering
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`a different formation segment once outside the tubing string. Id. at 6:20-35.
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`Prior to running the tubing string into the wellbore, lower end 14a can be
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`“fitted in various ways, depending on the [desired] operational characteristics,”
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`such as with a pump out plug assembly 28, as shown in FIG. 1a.