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.
`
`3.
`
`I have reviewed redacted versions of Mr. McGowen’s two declarations
`
`and redacted versions of the Patent Owner Response for the ’501 Patent involving
`
`the Lane-Wells reference (IPR2017-00247). I have also reviewed the transcripts of
`
`McGowen’s three depositions, and the references I discuss below.
`
`I.
`
`Thomson’s Operational Issues
`
`4.
`
`Thomson discusses plug-setting issues experienced with the M1 and
`
`M3 wells.
`
`5.
`
`The completion assembly for the M1 well included a pump-out plug
`BAKER HUGHES, A GE COMPANY, LLC AND
`that failed after the packers were set. Thomson reported that, as a result, there were
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`Exhibit 1139
`“problems in pressure testing of the completion and tubing hanger.” Thomson at 99.
`BAKER HUGHES, A GE COMPANY, LLC AND
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`However, Thomson reports that testing did get completed and that, afterward, the
`v. PACKERS PLUS ENERGY SERVICES, INC.
`IPR2017-00247
`
`- 1 -
`
`Page 1 of 23
`
`

`

`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.
`
`3.
`
`I have reviewed redacted versions of Mr. McGowen’s two declarations
`
`and redacted versions of the Patent Owner Response for the ’501 Patent involving
`
`the Lane-Wells reference (IPR2017-00247). I have also reviewed the transcripts of
`
`McGowen’s three depositions, and the references I discuss below.
`
`I.
`
`Thomson’s Operational Issues
`
`4.
`
`Thomson discusses plug-setting issues experienced with the M1 and
`
`M3 wells.
`
`5.
`
`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
`
`- 1 -
`
`Page 1 of 23
`
`

`

`pumping operations were “continuous.” Id. Thomson also reports that the
`
`completion assembly worked, and that all seven zones were stimulated. Id.
`
`6.
`
`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 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.
`
`7.
`
`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
`
`the tool string.
`
`- 2 -
`
`Page 2 of 23
`
`

`

`8.
`
`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 he/she 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.
`
`9.
`
`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 40:8-41:20,
`
`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
`
`- 3 -
`
`Page 3 of 23
`
`

`

`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.”
`
`10. 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 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.
`
`11.
`
`I do not share Mr. McGowen’s views.
`
`- 4 -
`
`Page 4 of 23
`
`

`

`12.
`
`Specifically, based on the explanation I provided in the section of my
`
`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.
`
`13.
`
`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.
`
`14.
`
`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.
`
`15.
`
`Instead, a POSITA would have had enough education, training, and
`
`experience to recognize the potential benefits of using Thomson’s system, and 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
`
`- 5 -
`
`Page 5 of 23
`
`

`

`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.
`
`II. Conventional Wisdom
`
`16.
`
`In Section IV.A.2. of its Patent Owner Response, Rapid Completions
`
`discusses the creation of what it terms disc-shaped “bi-wing” fractures in the context
`
`of cemented casing that has been perforated. See page 12. I am not sure if Rapid
`
`Completion is suggesting that such fractures could be generated only through
`
`perforations in cemented casing. Such a suggestion is not correct. At the time of
`
`the invention, such fractures could also be generated in open holes. Mr. McGowen
`
`acknowledged this. See December 15, 2017 deposition transcript at 68:14-69:17
`
`(discussing figure on page 18 of 94 of Ex. 2051).
`
`17. On page 13, Rapid Completions suggests that testimony from my first
`
`deposition (page 30, lines 6-16) supports its argument that a POSITA would have
`
`believed that “precise control” of perforation location was critical to ensuring
`
`“fractures are properly spaced apart.” Rapid Completions also suggests some of my
`
`other testimony (page 30, line 17 to page 31, line 3) supports its argument that
`
`“[i]mproper or poorly designed fracture spacing could cause a significant loss of
`
`production from the well as portions of the reservoir will go undrained, or drain so
`
`slowly that the well becomes uneconomic.” Rapid Completions is not correct. I was
`
`- 6 -
`
`Page 6 of 23
`
`

`

`not answering a question about a time period in 2001 or earlier, or what a POSITA
`
`would have understood. Counsel’s questions were about fracture placement and
`
`production, and I answered based on what I knew as an expert as of the date of my
`
`deposition (November 9, 2016). At the time of the invention, while a POSITA would
`
`have found it desirable to introduce multiple, spaced-apart fractures in a horizontal
`
`wellbore, as they would have done with the Lane-Wells system, they would not have
`
`appreciated what I explained to such an extent that it would have dissuaded them
`
`from using the Lane-Wells system to acid or hydraulic fracturing an open, stable,
`
`near-gauge wellbore in a formation suited to such stimulation. This is because, at
`
`the time of the invention, fracturing in horizontal wellbores was still relatively new,
`
`and the industry had not amassed the amount of experience that I based my answers
`
`on.
`
`18.
`
`I have considered the arguments in Mr. McGowen’s Ex. 2051 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
`
`- 7 -
`
`Page 7 of 23
`
`

`

`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 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.
`
`19. 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
`
`- 8 -
`
`Page 8 of 23
`
`

`

`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.
`
`20.
`
`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.
`
`21. 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).”
`
`22.
`
`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.”
`
`23. 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
`
`- 9 -
`
`Page 9 of 23
`
`

`

`required to initiate additional, closely-spaced transverse multiple fractures from
`
`horizontal wellbores”).
`
`24. 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).
`
`25. Near-wellbore tortuosity and the issues it can cause, which are
`
`discussed in Emanuele and Crosby, results from the perforations in cemented casing
`
`being mis-aligned with the fracture plane, as described generally in the following
`
`references: Venditto at 4:9-33 and 4:56-5:3; Surjaatmadja at 1:62-2:1; Almaguer at
`
`- 10 -
`
`Page 10 of 23
`
`

`

`3:7-20. In general, the direction of minimum principal stress within the formation
`
`is generally horizontal. Hydraulic fractures propagate more or less radially outward
`
`relative to the length of a borehole, in a plane perpendicular to the orientation of the
`
`minimum principal stress. As a result, in nearly all oil and gas industry applications,
`
`the fractures generated by hydraulic fracturing lie in a plane that is nearly vertical.
`
`As a result, fractures around a horizontal wellbore typically form a generally circular
`
`or elliptical shape around the wellbore.
`
`26. Near-wellbore tortuosity is an issue that typically arises when
`
`fracturing from a cased, cemented, and perforated wellbore. The reason this is so is
`
`that the relatively small size of the perforations restricts the flow of fluid out of the
`
`casing into the formation and, as a result, a single perforation is not sufficient for
`
`injection of fracturing fluid at rates commonly used for fracturing (at least not at
`
`pressures that are within the safe limitation of typical wells). Therefore, a grouping
`
`of multiple perforations is needed, and commonly used, to allow the injection of
`
`fracturing fluid at a sufficient rate to generate a fracture of a size considered
`
`satisfactory. However, in 2001, the industry did not have a tool system that allowed
`
`placing multiple perforations in a single circular or elliptical plane (i.e., fracture
`
`plane perpendicular to orientation of minimum principal stress) inside the well and,
`
`as a result, a given grouping of perforations contributing to a common fracture would
`
`necessarily be dispersed, and most of the perforations not aligned with the plane of
`
`- 11 -
`
`Page 11 of 23
`
`

`

`fracture. The stream of fluid from each individual perforation creates its own small,
`
`narrow fracture extending from the casing. As these narrow fractures get farther into
`
`the formation, the streams of fluid and the resulting narrow fractures will naturally
`
`coalesce along a plane perpendicular to the orientation of minimum horizontal stress
`
`to form the desired larger fracture. This physical phenomenon (network of small,
`
`narrow fractures adjacent the perforations) is referred to as near-wellbore tortuosity.
`
`27.
`
`The references noted in paragraph 26 above describe many of the same
`
`problems resulting from near-wellbore tortuosity that Crosby described and that I
`
`cited above: Almaguer at 3:23-31 (higher pumping pressures); Venditto at 5:4-7 and
`
`5:46-50 (same); Venditto at 5:4-26 and 5:32-34 and 5:51-56 (narrow fracture
`
`widths); Venditto at 5:27-41 (proppant bridging); Surjaatmadja at 2:1-4
`
`(screenouts). These problems arise in near-wellbore tortuosity because, between the
`
`coalesced larger fracture and the perforations, the network of smaller, narrow
`
`fractures restrict flow to or from the coalesced, larger fracture. As a result, while
`
`fluid may flow through the network of smaller, narrow fractures for a time, proppant
`
`(e.g., sand) can become trapped by the smaller fractures and further restrict or block
`
`flow (e.g., “screen out”) entirely between the casing and the larger, coalesced
`
`fracture farther out.
`
`28. A POSITA would have known that fracturing in an open hole would
`
`not cause the same degree of near-wellbore tortuosity issues as fracturing in cased
`
`- 12 -
`
`Page 12 of 23
`
`

`

`and cemented wells. This is because the flow of fracturing fluid out of an open hole
`
`is not restricted by perforations. As a result, a greater amount of fracturing fluid can
`
`flow out through natural weaknesses in the formation and naturally connect with a
`
`relatively large fracture, without having to first generate a network of smaller,
`
`narrow fractures (as required when fracturing through perforations in cased
`
`wellbores). The tendency of fractures in open-hole fracturing to naturally align with
`
`the fracture plane would have been known to a POSITA prior to 2001. For example,
`
`Venditto in 1992 recognized in the context of a microfrac test involving open-hole
`
`fracturing (to determine the direction of fracture propagation) that fractures from an
`
`open wellbore will tend to naturally align with the direction of fracture propagation:
`
`Generally speaking, during an open hole microfrac test, microfractures
`
`are induced in an open hole wellbore by pumping a relatively small
`
`amount of fracturing fluid into the wellbore. Since this technique is
`
`employed in an open wellbore, these fractures will naturally align
`
`with the direction of fracture propagation, i.e., perpendicular to the
`
`minimum principle horizontal stress existing within the formation.
`
`Venditto at 6:29-41 (emphasis mine).
`
`29. A POSITA would have known what is described above, that an open
`
`wellbore permits fracturing fluid to flow out of the natural weak points in a formation
`
`in volumes large enough to create fractures of a desired size, and therefore generally
`
`- 13 -
`
`Page 13 of 23
`
`

`

`did not encounter the tortuosity issues of cased holes. Therefore, rather than avoid
`
`open-hole fracturing out of a concern for wellbore tortuosity and the associated
`
`problems, a POSITA would have appreciated from Venditto that open-hole
`
`fracturing could have been used to avoid such issues.
`
`30. Neither paper cited by Mr. McGowen in his first declaration is
`
`inconsistent with this. In particular, Mr. McGowen cites a sentence from Emanuele
`
`(Ex. 2042 (1998)) expressing that unfavorable fracture initiation may cause
`
`problems with both fracture execution (screen-out) and production response by
`
`harming the wellbore-to-fracture connection. Emanuele at 9-10/13. But Emanuele
`
`is not stating that open-hole fracturing is causing such problems. Instead, it
`
`discusses fracture initiation problems with three subject wells—which were
`
`cemented and cased. Id. at 10-11/13 and 3-4/13. Like Emanuele, Crosby (Ex. 2042
`
`(2001)), cited by Mr. McGowen on page 25 of his first declaration, does not attribute
`
`the near wellbore tortuosity issues it describes as being related to open-hole
`
`fracturing. See Crosby at Abstract.
`
`31.
`
`The Murray reference that Mr. McGowen cites in his second
`
`declaration includes a description of an experiment that was performed in one of my
`
`labs at Halliburton by one of my engineers (Dr. Hazim Abass). The description
`
`states, “It has been documented in literature and field proven that a smaller focused
`
`perforated interval (2 to 3 feet) enables a major fracture system to be initiated rather
`
`- 14 -
`
`Page 14 of 23
`
`

`

`than several minor fractures which compete for fracturing fluid and ultimately are
`
`unable to propagate and extend.” The reference to a smaller perforated interval is a
`
`reference to a test in which my engineers tested the fracture response through a short
`
`perforated interval against the fracture response through a perforated interval that
`
`was longer. It is not a reference that involved testing open-hole fracturing, or that
`
`would suggest to a POSITA that open-hole fracturing should be avoided or would
`
`produce the kind of fracture response that was seen in the longer interval.
`
`32. On page 18 of its Patent Owner Response, Rapid Completions states
`
`that “a POSITA would have believed that disc-shaped ‘bi-wing’ fractures should be
`
`carefully spaced apart by using perforated casing,” and that such “conventional
`
`thinking” is described by the following:
`
`A 1988 paper written by Halliburton explains: “To be effectively fracture
`stimulated, a horizontally drilled well must be cased and cemented through
`the horizontal producing section of the well. Casing and cementing the
`horizontal section allows fracture initiation points to be controlled in placing
`multiple fractures.” Ex. 2098 at 1. A 1992 paper written by Halliburton and
`Maersk (“Owens”) notes: “A horizontal well that is to be fracture stimulated
`over multiple zones must be cased and cemented.” Ex. 2099 at 2. That
`sentiment is echoed in Damgaard, another paper written in 1992: “Successful
`liner installation and cementation is considered a prerequisite to ensure
`adequate zonal isolation for multiple fracture treatments in horizontal
`wells.” Ex. 2079 (emphasis added). Three years later, Halliburton and
`Pennzoil published a paper (“Abass”) describing various discoveries related
`to multistage fracturing. Abass specifically mentions the Yost experiments.
`Ex. 2078 at 2. Nonetheless, it found that “[c]asing and cementing a
`horizontal well is essential to provide zone selectivity and isolation during
`fracture stimulation.” This is because “[p]erforations play a crucial role in
`achieving a successful fracturing treatment in horizontal wellbores.” Id.
`(emphasis added).
`
`- 15 -
`
`Page 15 of 23
`
`

`

`33.
`
`The above sections of the Austin, Owens, Damgaard, and Abass papers
`
`cited by Rapid Completions would not have dissuaded a POSITA from all multi-
`
`stage open-hole fracturing at the time of the invention.
`
`34.
`
`The Austin paper from 1988 focuses on limited entry, which is a
`
`stimulation technique that requires perforations in cemented casing. It discusses
`
`open-hole matrix acidizing, but it does not discuss open-hole fracturing, and a
`
`POSITA at the time of the invention would not have read it as warning against all
`
`open-hole fracturing.
`
`35.
`
`The Owens paper from 1992 addresses hydraulic fracturing horizontal
`
`wellbores in the Dan Field, which is offshore in the North Sea. By the time of the
`
`invention, I had significant experience with hydraulic fracturing in the Dan Field.
`
`The Tertiary Danian and Cretaceous Maastrichtian chalks in the Dan Field were
`
`considered not to be strong enough rocks for open hole completions. If the open
`
`wellbore collapsed, the large expenses of drilling, completing and stimulating the
`
`well would be lost. A POSITA at the time of the invention would have appreciated
`
`this, or their team members would have. As a result, all of the horizontal wellbores
`
`in the Dan Field of which I was aware at the time of the invention were cased and
`
`cemented. I think this explains why the authors indicated that cemented casing was
`
`required.
`
`- 16 -
`
`Page 16 of 23
`
`

`

`36.
`
`Like Owens, the Damgaard paper (also from 1992) also described
`
`hydraulic fracturing in horizontal wellbores in the Dan Field. I think the authors
`
`advocated using cemented casing for the same reasons as in the Owens paper.
`
`37.
`
`I do not agree with what Rapid Completions suggests about the Abass
`
`paper. Rapid Completions seems to argue that because the Abass paper references
`
`multi-stage open-hole fracturing (the Overbey paper) but includes a statement in the
`
`Conclusions section that cemented casing is “essential,” a POSITA would read the
`
`Abass paper as indicating that open-hole multi-stage fracturing should never be
`
`performed. I do not believe a POSITA would have reached that conclusion.
`
`38.
`
`The authors of the Abass paper explain that the goal of the Overbey
`
`paper was to “propagate natural fractures and induce fractures at each interval.” The
`
`authors recognize that the Overbey paper sought to take advantage of natural
`
`fractures intersecting the wellbore and induce multiple fractures in each zone defined
`
`by packers. But in the single well at issue in Abass, the authors sought “[t]o prevent
`
`the natural fractures intersecting the wellbore from initiating and propagating
`
`multiple fractures.” Abass at 7; see also id. at 9. While they took a different
`
`approach than was presented in Overbey, the Abass authors did not state that the
`
`Overbey approach should never be used in any formation, or that the Madison
`
`formation of the Williston formation in which the subject well was drilled had the
`
`same properties as the formation in the Overbey paper.
`
`- 17 -
`
`Page 17 of 23
`
`

`

`39.
`
`I have been asked to provide some basic information about fractures at
`
`different depths and pressures, and whether a matrix acidizing pressure at one
`
`vertical depth would be great enough to cause a fracture at a shallower vertical depth
`
`in the same or a similar formation.
`
`40. Generally, fracturing pressure increases with depth, and this was known
`
`at the time of the invention by people who would qualify as a POSITA. This is also
`
`what allows those in the industry to generate ratios known as fracture gradients.
`
`41. As a result, a POSITA would have known at the time of the invention
`
`that, in a single formation or in similar formations, a matrix acidizing pressure at one
`
`vertical depth (which was a pressure that did not exceed fracturing pressure) may be
`
`greater than a fracturing pressure at a shallower vertical depth.
`
`42.
`
`I have been asked to provide some basic information about how people
`
`of ordinary skill in the art prepared for acidizing jobs. At the time of the invention,
`
`packers that could be used in acidizing operations (whether those were matrix
`
`acidizing operations or acid fracturing operations) were not rated for matrix
`
`acidizing vs. acid fracturing per se. Instead, they were rated for pressures commonly
`
`encountered for different likely well operations in a given area.
`
`43.
`
`I am not aware of a standard practice at the time of the invention for
`
`matrix acidizing to occur at a specific percentage of frac’ing pressure. In fact, such
`
`a standard does not exist even today. While the general practice is to inject the
`
`- 18 -
`
`Page 18 of 23
`
`

`

`matrix acidizing fluid at a pressure that is below fracturing pressure at the given
`
`depth, a POSITA would have recognized that initiating acid injection often requires
`
`pressurization of acid in the wellbore to a pressure that exceeds the fracture gradient
`
`and, thus, necessarily fracturing the formation. Thereafter, acid injection can
`
`continue at below fracturing pressure.
`
`III. Lane-Wells
`
`44. On page 40 of the Patent Owner Response, Rapid Completions argues,
`
`“The fact that a POSITA would be willing to acid frac a particular formation
`
`provides no reason for a POSITA to do so in multiple stages without casing as
`
`required by the claims. It is entirely consistent with the teachings in Lane-Wells for
`
`a POSITA to use the port valve to pump non-frac acid treatments into open hole
`
`segments, and to install casing when actually performing multi-stage fracturing with
`
`acid.” I do not disagree with their second sentence – a POSITA could have used the
`
`Lane-Wells tubing port valves in both open and cased holes. But I disagree that a
`
`POSITA would have had no reason to use the Lane-Wells system to acid frac in an
`
`open hole, or that I did not provide such a reason. I did. In my first declaration, I
`
`explained that, in any formation suited to acid fracturing, a POSITA would have
`
`found it desirable to perform such stimulation, and increase production, using the
`
`Lane-Wells system because acid fracturing was known to create fissures in the rock
`
`and thereby increase the flow of hydrocarbon into the wellbore.
`
`- 19 -
`
`Page 19 of 23
`
`

`

`45. On page 41 of the Patent Owner Response, Rapid Completions argues
`
`that the Coon reference “warns against” the use the Lane-Wells system for low-
`
`volume sand fracturing where Coon states, “The next evolutionary step of the ECP
`
`and sliding sleeve completion is the addition of a cased and cemented hole. (Fig. 2)
`
`This is required where zonal isolation is necessary. The cement prevents the
`
`formation from leaking around the ECPs.” I do not agree.
`
`46.
`
`These Coon sentences teach only that the ECP and sliding sleeve open-
`
`hole fracturing system should not be used where “zonal isolation is necessary,”
`
`which Coon explains is in “extremely porous formations (i.e. sandstone)” where the
`
`formation leaks around