SECOND DECLARATION OF ALI DANESHY
`
`1.
`
`My name is Ali Daneshy. I am over the age of twenty-one (21) years,
`
`of sound mind, and capable of making the statements set forth in this Declaration.
`
`I am competent to testify about the matters set forth herein. All the facts and
`
`statements contained herein are within my personal knowledge and they are, in all
`
`things, true and correct.
`
`2.
`
`I have been asked by Baker Hughes Incorporated (“Baker Hughes”) to
`
`submit this declaration to rebut certain arguments that I have been informed have
`
`been made by Rapid Completions and/or Mr. McGowen. This declaration will
`
`address the ’505, ’634, ’774, ’009, and ’451 Patents.
`
`3.
`
`I have reviewed Mr. McGowen’s two declarations – Ex. 2006 and Ex.
`
`2036. I have also reviewed the transcript of his deposition, the drawings he made
`
`at the deposition (Ex. 1033), the drawing he reviewed (Ex. 1032), and the
`
`references I discuss below. I have also reviewed the redacted version of the Patent
`
`Owner Response for the ’774 Patent, and the redacted version of the Patent Owner
`
`Response for the ’505 Patent.
`
`BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`I understand that Rapid Completions made the following arguments in
`EXHIBIT 1031
`BAKER HUGHES INCORPORATED
`Section V.C. of the Patent Owner Response for the ’505 Patent:
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC. v. PACKERS
`PLUS ENERGY SERVICES, INC.
`IPR2016-00596
`
`I.
`
`Thomson-Brown
`
`4.
`
`- 1 -
`
`Page 1 of 28
`
`
`
`1.
`
`My name is Ali Daneshy. I am over the age of twenty-one (21) years,
`
`of sound mind, and capable of making the statements set forth in this Declaration.
`
`I am competent to testify about the matters set forth herein. All the facts and
`
`statements contained herein are within my personal knowledge and they are, in all
`
`things, true and correct.
`
`2.
`
`I have been asked by Baker Hughes Incorporated (“Baker Hughes”) to
`
`submit this declaration to rebut certain arguments that I have been informed have
`
`been made by Rapid Completions and/or Mr. McGowen. This declaration will
`
`address the ’505, ’634, ’774, ’009, and ’451 Patents.
`
`3.
`
`I have reviewed Mr. McGowen’s two declarations – Ex. 2006 and Ex.
`
`2036. I have also reviewed the transcript of his deposition, the drawings he made
`
`at the deposition (Ex. 1033), the drawing he reviewed (Ex. 1032), and the
`
`references I discuss below. I have also reviewed the redacted version of the Patent
`
`Owner Response for the ’774 Patent, and the redacted version of the Patent Owner
`
`Response for the ’505 Patent.
`
`BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`I understand that Rapid Completions made the following arguments in
`EXHIBIT 1031
`BAKER HUGHES INCORPORATED
`Section V.C. of the Patent Owner Response for the ’505 Patent:
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC. v. PACKERS
`PLUS ENERGY SERVICES, INC.
`IPR2016-00596
`
`I.
`
`Thomson-Brown
`
`4.
`
`- 1 -
`
`Page 1 of 28
`
`
`
`SECOND DECLARATION OF ALI DANESHY
`
`1.
`
`My name is Ali Daneshy. I am over the age of twenty-one (21) years,
`
`of sound mind, and capable of making the statements set forth in this Declaration.
`
`I am competent to testify about the matters set forth herein. All the facts and
`
`statements contained herein are within my personal knowledge and they are, in all
`
`things, true and correct.
`
`2.
`
`I have been asked by Baker Hughes Incorporated (“Baker Hughes”) to
`
`submit this declaration to rebut certain arguments that I have been informed have
`
`been made by Rapid Completions and/or Mr. McGowen. This declaration will
`
`address the ’505, ’634, ’774, ’009, and ’451 Patents.
`
`3.
`
`I have reviewed Mr. McGowen’s two declarations – Ex. 2006 and Ex.
`
`2036. I have also reviewed the transcript of his deposition, the drawings he made
`
`at the deposition (Ex. 1033), the drawing he reviewed (Ex. 1032), and the
`
`references I discuss below. I have also reviewed the redacted version of the Patent
`
`Owner Response for the ’774 Patent, and the redacted version of the Patent Owner
`
`Response for the ’505 Patent.
`
`I.
`
`Thomson-Brown
`
`4.
`
`I understand that Rapid Completions made the following arguments in
`
`Section V.C. of the Patent Owner Response for the ’505 Patent:
`
`Page 1 of 28
`
`
`
`Moreover, Petitioners fail to show that Thomson could be used
`with Brown’s movable mandrel packer. As shown below
`in
`Petitioners’ annotated Figures 1 and 2 (further annotated by Rapid
`Completions to identify the mandrel in orange), Brown’s packer
`includes a central mandrel 11 that supports an anchoring and sealing
`assembly 12. (Ex. 1005, Brown, 4:33–36.)
`
`[The annotated Brown Figures 1 and 2, which I repeat below,
`were included next.]
`
`Brown’s anchoring and sealing assembly 12 includes seal
`elements 13 and 14, slip elements 15, a piston ring 19 that moves over
`mandrel 11, and a retaining end piece 20 that is fixed to mandrel 11.
`(Brown, 4:38–39, 63–66.) Moving piston ring 19 towards end piece
`20 forces lower and upper cone spreaders 21 and 22 toward each
`other, wedging slip elements 15 outwardly into anchoring engagement
`with a casing C. (Brown, 4:68–5:6.) Once slip elements 15 are set,
`“the forces exerted by the setting fluid cause the mandrel 11 to move
`downwardly.” (Brown, 6:16–18.) Brown further describes “continued
`downward movement of the mandrel after the upper cone 22 engages
`the slips.” (Brown, 6:20–23.)
`
`Thomson, unlike Brown where the mandrels move, teaches
`away from using packers that have a movable mandrel, stating that
`packers with no mandrel movement is an “important requirement”:
`
`An important requirement in completions using multiple
`hydraulic-set packers is that no mandrel movement in relation
`to the slips of the packer should occur while setting. This
`enables any number of hydraulic-set packers to be set
`
`Page 2 of 28
`
`
`
`simultaneously without the requirement for expansion devices
`between the packers to account for mandrel movement.
`
`(Ex. 1002, Thomson, p. 98.) Thomson continues to emphasize
`the importance of no movement with the mandrels by identifying
`packers having no mandrel movement as a “key element”: “The key
`elements that contributed to these successful installations were . . . :
`[h]ydraulic
`[s]et
`[p]ackers with no
`[m]andrel
`[m]ovement.”
`(Thomson, p. 100 (emphasis added).)
`
`Because Thomson’s system requires a non-movable mandrel, a
`POSITA would not only have been discouraged, but would have been
`lead in a different direction. The teaching away means that the
`combination of Thomson, Echols and Brown is nonobvious. See KSR
`Int'l Co. v. Teleflex Inc., 550 U.S. 398, 416 (2007) (When the prior art
`teaches away from combining known elements, the combination is
`likely nonobvious); see also, In re Gurley, 27 F.3d 551, 553 (Fed. Cir.
`1994) (A prior art reference teaches away when a person of ordinary
`skill, after reading the prior art reference, would be (1) discouraged
`from following the path set out in the reference or (2) led in a
`direction divergent from the path that was taken by the applicant.)
`
`5.
`
`I do not agree that a packer like Brown’s could not be used in
`
`Thomson’s system, or that Thomson’s teachings would have discouraged a
`
`POSITA from using Brown’s packer.
`
`6.
`
`Thomson states: “An important requirement in completions using
`
`multiple hydraulic-set packers is that no mandrel movement in relation to the slips
`
`Page 3 of 28
`
`
`
`of the packer should occur while setting. This enables any number of hydraulic-set
`
`packers to be set simultaneously without the requirement for expansion devices
`
`between the packers to account for mandrel movement.” Thomson at 98, 100
`
`(“The use of these packers enabled any number of packers to be run in a one trip
`
`completion without having to run travel joints between them to ensure that all
`
`packers would be set at the same time.”).
`
`7.
`
`In other words, Thomson teaches avoiding packers—like tension
`
`operated packers that are set by pulling the tubing string rather than by hydraulic
`
`pressure—that require mandrel movement to set slips unless expansion joints or
`
`devices are included between them. Otherwise, such mandrel movement could set
`
`some slips before others, precluding simultaneous packer setting (Thomson’s
`
`stated goal); but that is not how Brown’s packer works.
`
`8.
`
`As Brown’s Figures 1 and 2 show (below), the movement of fluid
`
`pressure-driven cone spreader elements 21 and 22 sets slips 15, not pulling on the
`
`packer mandrel 11, which is denoted “PACKER BODY” below:
`
`Page 4 of 28
`
`
`
`PACKING
`ELEMENT #1
`
`PACKER
`BODY
`
`PACKING
`ELEMENT #2
`
`PISTON
`
`HYDRAULIC
`PORT
`
`RETRIEVING
`LINK
`
`PACKING
`ELEMENT #1
`
`SLIP
`ELEMENTS
`
`PACKING
`ELEMENT #2
`
`COMPRESSION
`RING
`
`PRESSURE
`CHAMBER
`
`Page 5 of 28
`
`See Brown at 4:49-5:6.
`
`
`
`9.
`
`Brown’s mandrel does move downward to a small degree relative to
`
`its slips, but that movement occurs after the slips are set. Brown at 6:11-23 (“Once
`
`the slips are [in] anchored [engagement with the casing C], the forces exerted by
`
`the setting fluid cause the mandrel 11 to move downwardly relative to the slips.
`
`Continued downward movement of the mandrel … radially expands the seal 13.”).
`
`In other words, such mandrel movement is not required to set the slips. Brown
`
`also explains that this movement is permitted by either stretching the tubing string
`
`T or moving it downward from the well surface. Brown at 6:23-26. Such
`
`stretching routinely arises from temperature changes in the tubing when lowered
`
`into a well (which is hotter at greater depths) or when fluids are pumped into the
`
`well (which can dramatically lower temperatures of the tubing).
`
`10.
`
`Furthermore, because Brown’s packers are set by hydraulic pressure
`
`rather than tension, the entire tubing string can be pressurized at once to set
`
`multiple ones of Brown’s packers simultaneously (in the same manner as
`
`Thomson’s hydraulically-set packers). As a result, the above-described mandrel
`
`movement would occur simultaneously in each of the packers, so expansion joints
`
`between packers would not be needed. To the extent the length of the tubing
`
`caused any asynchronies in the moment at which each Brown packer sets, such
`
`differences would be small and easily absorbed by stretching of the tubing itself,
`
`which Brown recognized was possible and which was common due to temperature
`
`Page 6 of 28
`
`
`
`changes as discussed above. Thus, a POSITA would have recognized that
`
`Brown’s packers are not subject to the same concerns that drove Thomson’s
`
`comment about mandrel movement, and that no expansion joints between Brown’s
`
`packers would be required if all of Thomson’s packers were replaced with Brown’s
`
`packers.
`
`II.
`
`Thomson’s Operational Issues
`
`11.
`
`Thomson discusses plug-setting issues experienced with the M1 and
`
`M3 wells.
`
`12.
`
`The completion assembly for the M1 well included a pump-out plug
`
`that failed after the packers were set. Thomson reported that, as a result, there
`
`were “problems in pressure testing of the completion and tubing hanger.”
`
`Thomson at 99. However, Thomson reports that testing did get completed and
`
`that, afterward, the pumping operations were “continuous.” Id. Thomson also
`
`reports that the completion assembly worked, and that all seven zones were
`
`stimulated. Id.
`
`13.
`
`Thomson then increased the number of stages from seven to ten for
`
`the last three wells, and replaced the pump-out plug with a cycle plug. Thomson at
`
`99-100. Thomson reports that the cycle plug on the completion assembly for M3
`
`could not be expelled, and that the assembly’s secondary pump-out shear ring also
`
`refused to shear. Thomson at 100. However, a leak developed somewhere below
`
`Page 7 of 28
`
`
`
`the top packer after numerous pressure cycles at the maximum allowable surface
`
`pressure, and that allowed the balls to be flowed down to their seats. Id. The
`
`bottom zone could not be stimulated because the plug did not expel, and the
`
`smallest ball did not seat, so the second zone was not stimulated, but the remaining
`
`eight zones were stimulated. Id.
`
`14.
`
`In a section entitled “Important Points to Be Considered for Future
`
`Completions,” Thomson points out that “the cycle/pump-out plug in the tail pipe is
`
`the one area in which problems did occur” and emphasized that “it is actually one
`
`of the most crucial” parts of the completion. Thomson at 100. “If the plug
`
`expends early, the packers cannot be set, and the completion cannot be tested. If it
`
`does not expend, there is no flow path to enable the balls to be pumped to their
`
`mating seat.” Thus, Thomson itself provides an explicit motivation to try other
`
`types of plugs in its tool string.
`
`15.
`
`These were plug issues, not issues with either Thomson’s MSAF tools
`
`(the ball-activated sliding sleeves) or Thomson’s packers, and a person of ordinary
`
`skill in the art would not have been dissuaded from using Thomson’s tool string as
`
`a result of them, though such a person would have considered using a different
`
`plug.
`
`16.
`
`Thomson also planned on using a “conventional shear-pinned
`
`PBR/seal assembly” in its M1 completion assembly. Thomson at 98. PBR stands
`
`Page 8 of 28
`
`
`
`for polished bore receptacle, a special piece of tubing for landing a seal assembly.
`
`But a change was made, based on concerns over induced torque (which could have
`
`occurred during installation into the horizontal section of the liner, as explained on
`
`page 99), to use a special, annular pressure release that fitted on top of the
`
`PBR/seal assembly. Id. at 98. Thomson explained that, in the closed (running)
`
`position, the PBR and seal assembly were clutched together to handle applied or
`
`induced torque. Id. Thomson also explained that, as a backup, the assembly had a
`
`secondary shear-screw release mechanism that was isolated from any torque that
`
`could be applied or induced. Id.
`
`17.
`
`Thomson described the change as occurring “at the last minute.”
`
`Thomson at 99. And instead of running the M1 assembly as a single completion,
`
`Thomson ran the assembly from the PBR downward, as described in the
`
`“Completion Installation – M1” section. Once that was on depth, the packers were
`
`set by pressuring up against the pump-out plug, and the upper half of the assembly
`
`was then spaced out and stung into the PBR. Thomson at 99.
`
`18.
`
`For the next three assemblies, which were designed for ten zones,
`
`Thomson explains that an annular pressure release assembly was fitted to each
`
`PBR/seal assembly so that the main completion could be run in one trip, without
`
`fear of premature release of the PBR/seal assembly. Thomson at 100.
`
`Page 9 of 28
`
`
`
`19.
`
`Thomson does not state that there was an actual failure due to the
`
`premature release of the PBR/seal assembly when any of the M3, M4, or M5
`
`completion assemblies were run in.
`
`20. As a result, a person of ordinary skill in the art would not have been
`
`dissuaded from using Thomson’s MSAF tools and packers, even if the same
`
`PBR/seal assembly and annular pressure release assembly were used.
`
`21.
`
`The fact that Thomson’s system was used several times and that the
`
`authors considered the use of the system worth publishing is an endorsement of the
`
`usefulness of the system. The authors’ listing of these plug-setting issues and the
`
`addition of a pressure release assembly to the PBR/seal assembly to proactively
`
`address the possibility of induced torque during insertion into the horizontal
`
`segment indicates thoroughness, and it reflects that authors’ preparedness to
`
`overcome the kinds of issues that inevitably come up in the period during which a
`
`new system is first used.
`
`22.
`
`These types of issues are very common in the oil and gas industry,
`
`even when the operations involve very common and well-proven tools and
`
`systems. The fact remains that the benefits of the system were important enough
`
`for Thomson to repeat its application in several other wells. One strong indication
`
`of the usefulness of the system is the following quotation from the Abstract of the
`
`paper:
`
`Page 10 of 28
`
`
`
`This technique provided a substantial reduction in the operational time
`normally required to stimulate multiple zones and allowed the
`stimulations to be precisely targeted within the reservoir. The case
`history data will provide comparisons in operational times between
`traditional stimulations and this new method as well as the significant
`enhancements
`to cost efficiency
`that resulted from
`its use.
`Additionally, this completion method allowed the stimulations to be
`designed and matched to the requirements of each reservoir zone,
`which provided the most cost efficient treatments possible.
`
`Furthermore, the authors state in the Conclusions section:
`
`The successful installation of four multiple packer/MSAF completions
`in chalk formation in the North Sea proved that the system was not
`only feasible but highly efficient, both from an operational standpoint
`and from a reservoir treatment standpoint, since the stimulations could
`be designed and matched to the requirements of each reservoir zone.
`This ensured that the most cost efficient treatments possible were
`applied and that there would be no compromise to the effectiveness of
`the procedures to enhance production. Also, since this completion
`technique substantially reduces operational time normally required to
`stimulate multiple zones, cost savings are realized from the time
`reduction. As more experience is obtained with the system, increased
`efficiency will undoubtedly be generated, allowing additional time
`reduction and even greater cost savings when compared to traditional
`stimulation procedures.
`
`Page 11 of 28
`
`
`
`The above Thomson paragraphs are strong endorsements of the system and would
`
`have been a motivating factor for a person of ordinary skill in the art to consider
`
`using the Thomson system in other applications.
`
`23.
`
`In Mr. McGowen’s deposition, he explains at 53:9-24 that he believes
`
`that a person of ordinary skill in the art would have had “ultimate responsibility”
`
`for a completion assembly they suggested:
`
`Q. Is it possible that a POSITA would be able to solve problems
`conceptually and then rely on experts around him or her to work
`out the operational details?
`
`A. So could the -- let me see if I understand the question. Could the
`POSITA create a design and then he’s relying on other people to
`make that design function? Is that the question?
`
`Q. Well, the question is, the POSITA makes decisions and relies on
`other people with more operational experience to carry out those
`decisions or to give feedback about the feasibility of those
`decisions?
`
`A. I think the POSITA has ultimate responsibility for the outcome.
`So relying on other individuals to clean up your mess, so to speak,
`doesn't seem like something that a POSITA would do to me.
`
`Mr. McGowen discusses his views on such ultimate responsibility at 56:17-58:10.
`
`24. Mr. McGowen ascribed an unreasonably high level of risk aversion to
`
`a POSITA. This is reflected in his testimony at a number of places, including at
`
`40:8-41:20, 43:7-44:21, and 53:16-24. For example, in his testimony at 40:8-
`
`Page 12 of 28
`
`
`
`41:20, Mr. McGowen indicated that, based on Thomson’s plug setting issues and
`
`the potential induced-torque issue with the PBR/seal assembly, he thought that a
`
`POSITA would find the entire Thomson system—including apparently the
`
`unaffected MSAF tools and packers—to be an experimental system that is
`
`untested, and that is not functioning as planned, causing the operator to have to “on
`
`the fly to try to figure out how to make it work,” and that should not be used over
`
`“the tried and true plug and perf methodology” because to use it would be to
`
`attempt “to break new ground with an untested system.”
`
`25. Mr. McGowen even indicated at 43:7-22 that a person who suggested
`
`using Thomson’s new tool string would have been fired over the results in
`
`Thomson, because they are in a position of “extreme risk”:
`
`Q. So I’m just asking you whether you think that a POSITA, who’s in
`possession of Thomson and who’s read what happened in the four
`completion trips that are described, would have the ability based
`on their education and experience level to make similar adaptations
`when they face similar issues?
`
`A. Okay. So we’re assuming that he still has a job, right? Because he
`screwed up the first one? That he wasn’t fired for the problem that
`he had before? Because the POSITA is in a position of extreme
`risk. He’s only three years out of school, as I understand it. The
`gentlemen that are doing this work I don’t think are positas. I don't
`know how much experience they had at this point. But it’s a big
`
`Page 13 of 28
`
`
`
`leap, I think, to think that somebody at that level of skill would be
`able to figure out all these complex fixes on the fly.
`
`I do not share Mr. McGowen’s views.
`
`Specifically, based on the explanation I provided in the section of my
`
`26.
`
`27.
`
`first declaration entitled “A Person of Ordinary Skill in the Art,” a POSITA would
`
`not have had ultimate responsibility for a completion project, even if the POSITA
`
`were the one who suggested the use of a new system like Thomson’s.
`
`28.
`
`That responsibility would have rested with someone at a much higher
`
`level, such as a senior executive in the division where the POSITA worked. I have
`
`personally been such an executive and, in the oil and gas industry at the relevant
`
`time, a POSITA would have been part of a larger team engineering the use of such
`
`a system. Neither such a team nor any of its individual members would have been
`
`summarily fired if such a system failed. If engineering teams had been ruled with
`
`such an iron fist, the oil and gas industry would have ceased to innovate long ago.
`
`29.
`
`Thus, a POSITA would not have been a person who felt like they
`
`were in a position of “extreme risk,” as Mr. McGowen put it. They would not, as a
`
`result, have been as risk averse to using Thomson’s system as Mr. McGowen
`
`asserts.
`
`30.
`
`Instead, a POSITA would have had enough education, training, and
`
`experience to recognize the potential benefits of using Thomson’s system, and
`
`Page 14 of 28
`
`
`
`would have been encouraged to recognize such potential benefits. And, given that
`
`they possessed only a few years of experience, a POSITA would not have had so
`
`much responsibility for the outcome of a given completion project that they would
`
`have refused to even consider a system like Thomson’s, solely due to past
`
`operational issues that did not concern the main tools in the assembly (the MSAF
`
`tools and hydraulically-settable packers). This is especially true given the amount
`
`of time that Thomson reports having saved with their completion assembly.
`
`III. Conventional Wisdom
`
`31.
`
`I have considered the arguments in Mr. McGowen’s Ex. 2036 Section
`
`9.3 “Convention Wisdom Regarding Fracture Initiation Teaches Away from 774
`
`Patent.” The Emanuele paper that he cites (Ex. 2042) concerns, in part, three
`
`horizontal wells drilled in the Lost Hills diatomite formation in California. Ex.
`
`2042 at 335. During the completion of the wells, which involved plug and perf,
`
`“hydraulic fracture growth behavior was characterized using surface tiltmeter
`
`fracture mapping and real-time fracture pressure analysis.” Id. The authors
`
`explain that downhole tiltmeter fracture mapping was also used in the third well.
`
`The authors also explained:
`
`This combination of fracture diagnostics provided significant
`insights into hydraulic fracture behavior, allowing diagnosis of
`anomalous fracture growth behavior and evaluation of remediation
`measures. Fracture diagnostics during the first horizontal well
`
`Page 15 of 28
`
`
`
`revealed an unexpectedly complex near-wellbore fracture geometry, a
`result of fracture initiation problems. These problems slowed the
`completion process and severely harmed the effectiveness of the
`fracture-to-wellbore connection. In the subsequent horizontal wells, a
`number of design and execution changes were made which resulted in
`simpler near-wellbore fracture geometry and a greatly improved
`production response.
`
`The paper provides an overview of the completion and
`stimulation of all three horizontal wells, describes the lessons learned
`along the way, and discusses the implications for future Lost Hills
`horizontal well development.
`
`32. Mr. McGowen quotes a sentence of Emanuele that begins on page 343
`
`and that states, “Unfavorable fracture initiation may cause problems with both
`
`fracture execution (screen-out) and with production response, by harming the
`
`wellbore-to-fracture connection.” The paper then explains that, “Due to proppant
`
`plugging during fracture initiation, well #1 had the worst fracture initiation
`
`problems, but well #2 and well #3 also had some degree of near-wellbore
`
`complexity (tortuosity or multiple fractures).” The authors had earlier expounded
`
`on the proppant plugging problem for well #1 on pages 339-340, explaining it was
`
`due to several problems, including the crossover from 5-1/2” to 7” production
`
`casing, and insufficient wellbore cleanout between stages.
`
`Page 16 of 28
`
`
`
`33.
`
`The authors took steps to deal with some of these issues for wells 2
`
`and 3 (see 340-342), but “well #2 and well #3 also had some degree of near-
`
`wellbore complexity (tortuosity or multiple fractures).” Page 344.
`
`34. Mr. McGowen also cites to a Crosby paper (Ex. 2039) on page 25 of
`
`his declaration, as supporting his argument that “[m]any operators thought that the
`
`way to minimize fracture tortuosity was to control the fracture initiation process
`
`through the use of decreased perforation density (limited entry).”
`
`35.
`
`Like Emanuele, Crosby recognized the near-wellbore tortuosity issues
`
`that arose from fracturing through perforations in a cemented casing. As Crosby
`
`explained in the Abstract, “Multi-stage, transversely fractured horizontal wellbores
`
`have the potential to greatly increase production from low permeability formations.
`
`Such completions are, however, susceptible to problems associated with near-
`
`wellbore tortuosity, particularly multiple fracturing from the same perforated
`
`interval.”
`
`36. Crosby was studying the “wellbore pressures required to initiate
`
`secondary multiple transverse hydraulic fractures in close proximity to primary
`
`fractures.” Abstract and page 2 (addressing “the horizontal wellbore fluid
`
`pressures required to initiate additional, closely-spaced transverse multiple
`
`fractures from horizontal wellbores”).
`
`Page 17 of 28
`
`
`
`37. And like the Emanuele paper, the Crosby paper recognized the near-
`
`wellbore tortuosity problems that fracturing through perforations in cemented
`
`casing caused:
`
`Unfortunately, transversely fractured horizontal wellbores are
`still plagued by a number of problems, most of which stem from the
`complex fracture geometries connecting the wellbore to the main
`fracture. These complex fracture geometries usually take the form of
`multiple fractures, twisted fractures, H- or S-shaped fractures( 8, 9).
`
`The above complex fracture geometries are more commonly
`collectively known as “near wellbore tortuosity,” and result in
`narrower than anticipated fracture widths. Near-wellbore tortuosity
`ultimately leads to unacceptably high fracture treatment pressures,
`proppant bridging and pre-mature near-wellbore screenout, shorter
`than expected final fracture lengths, and poor fracture conductivities.
`The origin of these fracture complexities may be traced back to
`the manner in which hydraulic fractures initiate from the
`wellbore. (Page 2 – emphasis mine).
`
`38.
`
`The Ellis paper (P.D. Ellis, et al., Application of Hydraulic Fractures
`
`in Openhole Horizontal Wells, SPE/Petroleum Society of CIM 65464 (2000)
`
`(“Ellis”)) explains what the Emanuele and Crosby papers reflected: restricting
`
`access to the formation through perforations in cemented casing caused the kind of
`
`near-wellbore fracture tortuosity, sometimes described as complex near-wellbore
`
`Page 18 of 28
`
`
`
`fracture geometry, that resulted in stimulation issues like an increased risk of
`
`screen-out.
`
`39. At the time of the invention, and as the Ellis paper reflects, it was
`
`known that completing horizontal wells open allowed stimulation fluid to have full
`
`access to the wellbore. See Ellis at page 1 under “Common Uses.” This allowed
`
`for a fracture to initiate at a natural weak point in the formation, instead of through
`
`a perforation that may not be aligned with the natural weak point.
`
`40. As Ellis explained, “Typically, the most common method of isolation
`
`[of undesired gas/water] is cementing the casing in the horizontal. Unfortunately,
`
`this isolates not only the problem but also the reservoir from the wellbore.” Ellis
`
`goes on to explain that “selective perforating may re-establish communication with
`
`the reservoir, restoring production usually is more difficult.” Ellis also explains
`
`that “if the production comes primarily from natural fractures, perforating into the
`
`natural fractures to restore production is highly unlikely.” Page 2.
`
`41.
`
`Ellis explains that for propped fracture treatments, cemented casing
`
`that is perforated is typical. Ellis states that concerns about wellbore stability,
`
`isolation between stages, and fishing stuck pipe in an openhole environment are the
`
`primary reasons for cementing casing in the horizontal wellbore. He also explains
`
`that, “when pumping a propped fracture treatment in a cased, cemented, and
`
`perforated horizontal well, high breakdown and treating pressures have been
`
`Page 19 of 28
`
`
`
`reported and are prone to premature screenouts if not mitigated. These problems
`
`have generally been attributed to tortuosity (turning of the fracture), multiple
`
`competing fractures, or a poor cement job.” Ellis reports some “common
`
`techniques to minimize the near wellbore effects include pumping proppant slugs,
`
`breaking down the formation with cross-linked gel, and extreme overbalanced
`
`perforating prior to pumping the main fracture treatment.” Page 2.
`
`42. However, as Ellis reported in his “Near-Wellbore Connection
`
`Problems” section on pages 3-4, the use of some such techniques—like proppant
`
`slugs and cross-linked gels—even in a cemented and cased segment in which
`
`perforations were placed “to reduce the possibility of developing multiple
`
`competing fractures in the interval” still did not avoid near-wellbore connection
`
`problems, which resulted in screen-out. See the discussion of the first stage in
`
`“Red Oak” on pages 3-4.
`
`43.
`
`Ellis explained that the “costs and subsequent production results” in
`
`the Red Oak and another project (Gallup) required a different approach, and he
`
`stated that their new approach dramatically reduced near-wellbore effects. See
`
`“New Approach Required” on page 4.
`
`44.
`
`Ellis’s approach was to use a series of spaced-apart ported subs (one
`
`such sub being shown in Fig. 8) on a single tool string, through which a single
`
`treatment stage was pumped in a horizontal, open hole. This is discussed on pages
`
`Page 20 of 28
`
`
`
`5 and 6. Ellis reports: “A single treatment was used for the entire horizontal
`
`section and no near-wellbore problems were observed.”
`
`45.
`
`The result was that the complex near-wellbore fracture geometry that
`
`caused problems in the cased and cemented wellbores (and which occurred in
`
`Emanuele) were eliminated. See Ellis at 6, under “Results”: “This process has
`
`been used successfully for matrix and fracture stimulation of over 100 laterals in
`
`fields throughout Texas, New Mexico, Utah, California, and Illinois. Acid and
`
`water fractures as well as propped fractures have been successfully pumped as a
`
`single stage in openhole completions with no near-wellbore problems as were
`
`seen in conventional cased, cemented, and perforated completions. Both
`
`longitudinal and transverse fractures have been successfully generated. While the
`
`process was initially developed for wells in carbonate formations, it has been used
`
`in over eight wells in four different fields for propped fractures. No fracture to
`
`wellbore connectivity problems have been observed and no screenouts have
`
`occurred.” (Emphasis mine).
`
`46.
`
`In the Conclusions section, Ellis explained that “1. Hydraulic
`
`fractures in cased, cemented, and perforated horizontal wells can experience
`
`wellbore to fracture connection problems. This results in high treating pressures
`
`and propped treatment are prone to premature screenouts if these problems are not
`
`mitigated. 2. Hydraulic fractures in openhole horizontal wells have shown little or
`
`Page 21 of 28
`
`
`
`no wellbore to fracture connection problems. This results in lower treating
`
`pressures and the ability to pump high (>10 ppg) proppant concentrations.”
`
`47. A POSITA would have appreciated from Ellis’s paper that cemented
`
`casing was the cause of fracture-to-wellbore connection problems, not the solution
`
`to them. While cemented casing was sometimes necessary where wellbores were
`
`not stable or issues like unwanted water control could not be addressed any other
`
`way, cemented casing was not required or even desirable for avoiding near-
`
`wellbore fracture complexity issues. Instead, leaving the wellbore open and
`
`stimulating directly into the formation through the open wellbore solved those
`
`problems.
`
`IV. The FIG. 6 Embodiment of the ’009 and ’451 Patents
`
`48.
`
`I discuss the operation of this embodiment in my earlier declaration. I
`
`have read Mr. McGowen’s section “7 Priority Date Analysis” in his Ex. 2006
`
`declaration, and I have considered his deposition testimony about it (167:5 to the
`
`end). I do not agree with his explanation of what a POSITA would have allegedly
`
`recognized from FIG. 6.
`
`49. As explained in my earlier declaration section “A Person of Ordinary
`
`Skill in the Art,” such a person would have had a bachelor in science degree in
`
`mechanical, petroleum, or chemical engineering, or similar degree and had at least
`
`Page 22 of 28
`
`
`
Accessing this document will incur an additional charge of $.
After purchase, you can access this document again without charge.
Accept $ Charge
Still Working On It
This document is taking longer than usual to download. This can happen if we need to contact the court directly to obtain the document and their servers are running slowly.
Give it another minute or two to complete, and then try the refresh button.
A few More Minutes ... Still Working
It can take up to 5 minutes for us to download a document if the court servers are running slowly.
Thank you for your continued patience.
This document could not be displayed.
We could not find this document within its docket. Please go back to the docket page and check the link. If that does not work, go back to the docket and refresh it to pull the newest information.
Your account does not support viewing this document.
You need a Paid Account to view this document. Click here to change your account type.
Your account does not support viewing this document.
Set your membership
status to view this document.
With a Docket Alarm membership, you'll
get a whole lot more, including:
- Up-to-date information for this case.
- Email alerts whenever there is an update.
- Full text search for other cases.
- Get email alerts whenever a new case matches your search.
One Moment Please
The filing “” is large (MB) and is being downloaded.
Please refresh this page in a few minutes to see if the filing has been downloaded. The filing will also be emailed to you when the download completes.
Your document is on its way!
If you do not receive the document in five minutes, contact support at support@docketalarm.com.
Sealed Document
We are unable to display this document, it may be under a court ordered seal.
If you have proper credentials to access the file, you may proceed directly to the court's system using your government issued username and password.
Access Government Site
