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`
`(cid:20)
`
` 1 IN THE UNITED STATES PATENT AND TRADEMARK OFFICE
` BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
` 2
`
` BAKER HUGHES, A GE COMPANY, LLC )
` 3 and BAKER HUGHES OILFIELD )
` OPERATIONS, LLC. )
` 4 )
` Petitioners, ) IPR2017-00247
` 5 ) U.S. Patent No.
` vs. ) 9,303,501
` 6 )
` PACKERS PLUS ENERGY SERVICES, )
` 7 INC., )
` )
` 8 Patent Owner. )
`
` 9
`
` 10 -------------------------------------
`
` 11 ORAL AND VIDEOTAPED DEPOSITION OF
`
` 12 HAROLD E. MCGOWEN III
`
` 13 December 15, 2017
`
` 14 -------------------------------------
`
` 15
`
` 16 ORAL DEPOSITION of HAROLD E. MCGOWEN III, produced
`
` 17 as a witness the instance of the Petitioners, and duly
`
` 18 sworn, was taken in the above styled and numbered cause
`
` 19 on December 15, 2017, from 8:36 a.m. to 2:43 p.m.
`
` 20 before Jeff L. Foster, a Certified Shorthand Reporter
`
` 21 in and for the State of Texas, at the offices of
`BAKER HUGHES, A GE COMPANY, LLC AND
` 22 Caldwell, Cassady, Curry, 2101 Cedar Springs, Road,
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`Exhibit 1146
` 23 Suite 1000, Dallas, Texas 75201, pursuant to the
`BAKER HUGHES, A GE COMPANY, LLC AND
` 24 Federal Rules of Civil Procedure and the provisions
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`v. PACKERS PLUS ENERGY SERVICES, INC.
` 25 stated on the record.
`IPR2017-00247
`
`(cid:47)(cid:72)(cid:91)(cid:76)(cid:87)(cid:68)(cid:86)
`
`Page 1 of 146
`
`
`
`(cid:20)
`
` 1 IN THE UNITED STATES PATENT AND TRADEMARK OFFICE
` BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
` 2
`
` BAKER HUGHES, A GE COMPANY, LLC )
` 3 and BAKER HUGHES OILFIELD )
` OPERATIONS, LLC. )
` 4 )
` Petitioners, ) IPR2017-00247
` 5 ) U.S. Patent No.
` vs. ) 9,303,501
` 6 )
` PACKERS PLUS ENERGY SERVICES, )
` 7 INC., )
` )
` 8 Patent Owner. )
`
` 9
`
` 10 -------------------------------------
`
` 11 ORAL AND VIDEOTAPED DEPOSITION OF
`
` 12 HAROLD E. MCGOWEN III
`
` 13 December 15, 2017
`
` 14 -------------------------------------
`
` 15
`
` 16 ORAL DEPOSITION of HAROLD E. MCGOWEN III, produced
`
` 17 as a witness the instance of the Petitioners, and duly
`
` 18 sworn, was taken in the above styled and numbered cause
`
` 19 on December 15, 2017, from 8:36 a.m. to 2:43 p.m.
`
` 20 before Jeff L. Foster, a Certified Shorthand Reporter
`
` 21 in and for the State of Texas, at the offices of
`BAKER HUGHES, A GE COMPANY, LLC AND
` 22 Caldwell, Cassady, Curry, 2101 Cedar Springs, Road,
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`Exhibit 1146
` 23 Suite 1000, Dallas, Texas 75201, pursuant to the
`BAKER HUGHES, A GE COMPANY, LLC AND
` 24 Federal Rules of Civil Procedure and the provisions
`BAKER HUGHES OILFIELD OPERATIONS, LLC
`v. PACKERS PLUS ENERGY SERVICES, INC.
` 25 stated on the record.
`IPR2017-00247
`
`(cid:47)(cid:72)(cid:91)(cid:76)(cid:87)(cid:68)(cid:86)
`
`Page 1 of 146
`
`
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`
`(cid:20)
`
` 1 IN THE UNITED STATES PATENT AND TRADEMARK OFFICE
` BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
` 2
`
` BAKER HUGHES, A GE COMPANY, LLC )
` 3 and BAKER HUGHES OILFIELD )
` OPERATIONS, LLC. )
` 4 )
` Petitioners, ) IPR2017-00247
` 5 ) U.S. Patent No.
` vs. ) 9,303,501
` 6 )
` PACKERS PLUS ENERGY SERVICES, )
` 7 INC., )
` )
` 8 Patent Owner. )
`
` 9
`
` 10 -------------------------------------
`
` 11 ORAL AND VIDEOTAPED DEPOSITION OF
`
` 12 HAROLD E. MCGOWEN III
`
` 13 December 15, 2017
`
` 14 -------------------------------------
`
` 15
`
` 16 ORAL DEPOSITION of HAROLD E. MCGOWEN III, produced
`
` 17 as a witness the instance of the Petitioners, and duly
`
` 18 sworn, was taken in the above styled and numbered cause
`
` 19 on December 15, 2017, from 8:36 a.m. to 2:43 p.m.
`
` 20 before Jeff L. Foster, a Certified Shorthand Reporter
`
` 21 in and for the State of Texas, at the offices of
`
` 22 Caldwell, Cassady, Curry, 2101 Cedar Springs, Road,
`
` 23 Suite 1000, Dallas, Texas 75201, pursuant to the
`
` 24 Federal Rules of Civil Procedure and the provisions
`
` 25 stated on the record.
`
`(cid:47)(cid:72)(cid:91)(cid:76)(cid:87)(cid:68)(cid:86)
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`Page 1 of 146
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`
`(cid:21)
`
` 1 A P P E A R A N C E S
`
` 2 THE PETITIONERS:
`
` 3 Mr. Mark T. Garrett
` NORTON, ROSE, FULBRIGHT US, LLP
` 4 98 San Jacinto Boulevard, Suite 1100
` Austin, Texas 78701-4255
` 5 (512) 474-5201
` mark.garrett@nortonrosefulbright.com
`
` 6
`
` FOR THE PATENT OWNER:
`
` 7
`
` Mr. Justin Nemunaitis
` 8 CALDWELL, CASSADY, CURRY
` 2101 Cedar Springs Road, Suite 1000
` 9 Dallas, Texas 75201
` (241) 888-4853
` 10 jnemunaitis@caldwellcc.com
`
` 11 ALSO APPEARING
`
` 12 Mr. David Guerra, videographer
`
` 13
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` 14
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` 15
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` 16
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` 17
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` 18
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` 19
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`
`(cid:22)
`
` 1 I N D E X
`
` 2 PAGE
`
` 3 Appearances............................. 2
` HAROLD E. MCGOWEN III
` 4 Examination by Mr. Garrett 4
`
` 5 Signature Page.......................... 143
` Reporter's Certificate.................. 145
`
` 6
`
` 7
`
` 8
`
` 9
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` 10
`
` 11
`
` 12
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` 13
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` 14
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` 15
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` 16
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` 17
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` 18
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` 19
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`
`(cid:23)
`
` 1 P R O C E E D I N G S
`
` 2 THE VIDEOGRAPHER: We are on the record
`
` 3 at 8:36 a.m., December 15th, 2017 for the deposition of
`
` 4 Harold E. McGowen, III, in the matter of Baker Hughes,
`
` 5 et al., versus Packers Plus Energy Solutions
`
` 6 Incorporated, Case IPR 2017-00247.
`
` 7 Counsel, please state your appearances
`
` 8 and the court reporter will then administer the oath.
`
` 9 MR. GARRETT: Mark Garrett from Norton,
`
` 10 Rose, Fulbright for petitioners.
`
` 11 MR. NEMUNAITIS: Justin Nemunaitis for
`
` 12 the patent owner side.
`
` 13 HAROLD E. MCGOWEN III,
`
` 14 having been first duly sworn, testified as follows:
`
` 15 EXAMINATION
`
` 16 BY MR. GARRETT:
`
` 17 Q. Good morning.
`
` 18 A. Good morning.
`
` 19 Q. I am handing you Exhibit 2042, which is the
`
` 20 Emanuele paper. And this is one that you rely on in
`
` 21 your first declaration, which I'll also hand you, and
`
` 22 which is Exhibit 2050.
`
` 23 MR. GARRETT: Justin, I think I screwed
`
` 24 up.
`
` 25 MR. NEMUNAITIS: That's fine.
`
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`Page 4 of 146
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`
`(cid:24)
`
` 1 MR. GARRETT: Thank you.
`
` 2 Q. (BY MR. GARRETT) Mr. McGowen, look at native
`
` 3 page 338 of Emanuele.
`
` 4 A. (The witness complied.)
`
` 5 Q. And the second column under the heading
`
` 6 "Hydraulic Fracture Design and Evaluation," do you see
`
` 7 that?
`
` 8 A. Yes.
`
` 9 Q. Near the bottom?
`
` 10 A. Right.
`
` 11 Q. After the maybe subheading "Real-Data
`
` 12 Approach"?
`
` 13 A. Yes.
`
` 14 Q. The author states, and I'll read it, "Over the
`
` 15 course of the three horizontal wells, real data
`
` 16 feedback was utilized to the maximum extent possible
`
` 17 for completion and fracture design evaluation and
`
` 18 refinement. Implicit in this approach is the
`
` 19 recognition that hydraulic fracture behavior is complex
`
` 20 and variable, severely limiting the usefulness of
`
` 21 traditional predictive mode or 'one size fits all'
`
` 22 approaches." Do you see that?
`
` 23 A. Yes.
`
` 24 Q. Isn't what the authors are saying there is
`
` 25 hydraulic fracture behavior is hard to predict?
`
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`
`(cid:25)
`
` 1 A. Well, they're saying that it's complex and
`
` 2 variable. I think there's -- there's predictability on
`
` 3 a macro scale and there's predictability on a micro
`
` 4 scale. So I think there's some things that are
`
` 5 predictable and some parts of the process that
`
` 6 are -- that are difficult to predict.
`
` 7 And then there's the issue with the
`
` 8 formation itself can be heterogenous and you can
`
` 9 encounter issues during the frac that may, you know,
`
` 10 cause an unexpected outcome. So there's -- you may
`
` 11 have outliers that you have to deal with. So I
`
` 12 wouldn't say it's completely unpredictable, but, you
`
` 13 know, there's some uncertainty involved. So I agree
`
` 14 with that statement.
`
` 15 Q. You agree with the statement I made or you
`
` 16 agree with the statement the authors made?
`
` 17 A. Well, I think you were saying that they're
`
` 18 saying it's unpredictable. I don't think that's what
`
` 19 he said. He said it's complex and variable, so they
`
` 20 may not be quite the same thing.
`
` 21 Q. And his qualification that that complex and
`
` 22 variable nature of it severely limits the usefulness of
`
` 23 traditional predictive mode or one size fits all
`
` 24 approaches, isn't that saying that it's hard to predict
`
` 25 how a frac job is going to go?
`
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`
`(cid:26)
`
` 1 A. I think he's saying that -- I think what he's
`
` 2 talking about is sort of what I would call a quality
`
` 3 management approach where you're using plan, do, check,
`
` 4 act. In other words, you do something, then you check
`
` 5 the results, and then you would adjust what you had
`
` 6 done and take -- create a lessons learned cycle, and
`
` 7 you can optimize.
`
` 8 And what here he's talking about is he's
`
` 9 got realtime data feedback, so he either has surface
`
` 10 data or in some cases now you can have down-hole data
`
` 11 that you can use to optimize the frac. But it's not
`
` 12 completely unpredictable. I mean, you know, certain
`
` 13 things are going to happen.
`
` 14 But I think he's saying -- the way I'm
`
` 15 reading this is instead of just continuing to do
`
` 16 exactly the same treatment on every stage regardless of
`
` 17 the feedback information you get, you would adjust the
`
` 18 job -- you'd use progressive elaboration to adjust and
`
` 19 refine the job on the fly or during the treatment.
`
` 20 Q. So he's saying that you need to be prepared to
`
` 21 make adjustments for what actually happens as you're
`
` 22 doing a frac, right?
`
` 23 A. Yeah, and I think he's -- what he's referring
`
` 24 to here with realtime data feedback, they have plots
`
` 25 you can do, for example, a Nolte plot and you're --
`
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`
`(cid:27)
`
` 1 you're watching the data pressures and rates and
`
` 2 you're -- there's certain behavior during the frac that
`
` 3 will tell you that you're going into screen-out mode or
`
` 4 you're -- or you're extending the fracture. So the
`
` 5 Nolte plot is one of the tools that you can use to
`
` 6 monitor that, and then if you see that you're about to
`
` 7 screen out you can change the fluid proppant mix or go
`
` 8 to flush and end the job or whatever the appropriate
`
` 9 response is.
`
` 10 So instead of just pumping the frac away
`
` 11 and not monitoring it and looking at the realtime data
`
` 12 feedback, you would adjust it -- you'd adjust the frac,
`
` 13 the fluids that you're pumping and the rates you're
`
` 14 pumping at during the job is the way I read that.
`
` 15 Q. And he's saying this in the context of plug
`
` 16 and perf, right?
`
` 17 A. Let's see. I don't know that that would
`
` 18 be -- that that type of approach is limited to plug and
`
` 19 perf, but that may be what he's talking about here in
`
` 20 this paper. But a general -- the general idea of
`
` 21 getting feedback -- a feedback loop is -- has
`
` 22 applicability to many different operations.
`
` 23 Q. And this was true at the time of the
`
` 24 invention, right?
`
` 25 A. Yes.
`
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`
`(cid:28)
`
` 1 Q. So, I mean, is it true that going into a frac
`
` 2 at the time of the invention, you didn't have a way of
`
` 3 knowing exactly how everything was going to go, right?
`
` 4 A. That's true. Yeah, that there's -- like I
`
` 5 already said, there's uncertainty around the outcome.
`
` 6 Q. Sometimes fractures that are induced in a
`
` 7 formation that emanate from different zones of a
`
` 8 horizontal wellbore will grow into each other, right?
`
` 9 A. That's true.
`
` 10 Q. And that's something that can happen over the
`
` 11 productive life of the well, right?
`
` 12 A. No, I wouldn't think so. During the
`
` 13 production mode where you're flowing the well?
`
` 14 Q. Yeah.
`
` 15 A. I wouldn't think that you'd have fracture
`
` 16 growth during the flow-back stage.
`
` 17 Q. And so when I say "fracture growth," do you
`
` 18 understand that to mean the fractures that you induced
`
` 19 continue to grow and that's all you're attributing to
`
` 20 fracture growth, or could it also encompass the
`
` 21 connection of the fractures that you induce with
`
` 22 natural fractures in the formation?
`
` 23 A. Yes, you could -- your -- your primary induced
`
` 24 fracture can interact with natural fractures. But to
`
` 25 the point about during the life of the well, it would
`
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`
`(cid:20)(cid:19)
`
` 1 have to be when you're imparting fracture energy into
`
` 2 the formation, not when you're flowing it back.
`
` 3 Q. Okay. So if during the productive life of a
`
` 4 well two independent fractures from a plug-and-perf
`
` 5 well, if they wind up connecting to each other due to
`
` 6 natural fractures within the formation between them, I
`
` 7 mean, is that something that happens?
`
` 8 A. Yes.
`
` 9 Q. And is it something that operators plan for?
`
` 10 A. Well, you can -- it depends on what you're --
`
` 11 the nature of the formation. If you're -- in some
`
` 12 cases you may actually want that to happen and your
`
` 13 objective may be to create that complex interaction
`
` 14 between natural fractures and induced fractures.
`
` 15 And in some formations you may want to
`
` 16 control the leak-off into -- and fluid movement and
`
` 17 proppant movement into the natural fractures and create
`
` 18 a bi-wing transverse fracture that you're propping with
`
` 19 proppant.
`
` 20 So there might be two different -- two
`
` 21 different styles of hydraulic fracturing, but in some
`
` 22 cases that might be your objective and it might -- and
`
` 23 the formation that you're fracking may be conducive to
`
` 24 that effect.
`
` 25 Q. Was that true at the time of the invention?
`
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`
`(cid:20)(cid:20)
`
` 1 A. Yes.
`
` 2 Q. So let's talk about limited entry fracturing
`
` 3 at the time of the invention for a minute. There was
`
` 4 no way to do limited entry fracturing without casing,
`
` 5 right?
`
` 6 A. I'd say that's true, that the conventional
`
` 7 practice for limited entry was you limit the number of
`
` 8 perforations to create back pressure so you can
`
` 9 distribute pressure over a longer interval. So you're
`
` 10 typically trying to keep it down to something like two
`
` 11 barrels per minute per perforation. I'm not aware
`
` 12 if -- as I sit here of any other way of doing it
`
` 13 without cased hole and cement.
`
` 14 Q. And so we're clear, the casing had to be
`
` 15 perforated for that type of fracture treatment, right?
`
` 16 A. Yes.
`
` 17 Q. There were no packers involved that
`
` 18 mechanically diverted fluid to the different
`
` 19 perforations, right?
`
` 20 A. I mean, there might be some configuration that
`
` 21 I'm -- I'm not thinking of right now, but, I mean,
`
` 22 typically you could do -- you can do limited entry
`
` 23 between two stages. You know, if you're doing plug and
`
` 24 perf, you can do limited entry. Let's say you've got a
`
` 25 600-foot interval and you put fracture -- I mean, you
`
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`
`(cid:20)(cid:21)
`
` 1 put perforation clusters within that interval, you
`
` 2 might want to do limited entry within that interval.
`
` 3 So I guess there would be a plug on one end involved in
`
` 4 that scenario.
`
` 5 Q. Okay. And whoever designed the limited entry
`
` 6 treatment, whether it was for an open wellbore segment
`
` 7 or one that was bounded by packers as you just
`
` 8 described, they need to know the distance between the
`
` 9 fractures that they're going to be creating, right?
`
` 10 A. That is -- yes, that's one advantage of the
`
` 11 plug and perf is you can place the clusters -- you can
`
` 12 do individual perforation clusters and put those far
`
` 13 enough apart that you have a higher probability of not
`
` 14 growing one fracture into the other one or -- or
`
` 15 inadvertently combining fractures and then leaving some
`
` 16 gap in the reservoir that you didn't treat. So you can
`
` 17 discretely place those clusters within a stage and then
`
` 18 at least you know where it initiated and you start the
`
` 19 growth away from the wellbore within that cluster, if
`
` 20 that's answering your question.
`
` 21 Q. Well, I tell you what, to make it simple let's
`
` 22 just take the -- maybe the more traditional version of
`
` 23 limited entry where you have an open horizontal
`
` 24 wellbore segment that you've cased and perfed. What I
`
` 25 was trying to make sure I understood was you -- the
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` 1 person who is designing that kind of frac job needs to
`
` 2 know basically the distance between those perforations
`
` 3 so that they can make sure that the perforations see
`
` 4 the right volume of fluid?
`
` 5 A. Okay. For limited entry it's really about the
`
` 6 number of perforations and the pressure drop across
`
` 7 each one of those. It's sort of like a sprinkler
`
` 8 system in your yard, if you put too many sprinkler
`
` 9 heads on it, you bleed off all the pressure and it's
`
` 10 not evenly distributed.
`
` 11 So if -- in a horizontal application you
`
` 12 typically put the perforations in clusters, and, I
`
` 13 mean, there's two ways you could do it. You could
`
` 14 perforate the entire -- let's say it's a 300-foot
`
` 15 interval. You could perforate the entire interval with
`
` 16 the same perforation density, like, say, four shots per
`
` 17 foot or six shots per foot, maybe in a helical pattern,
`
` 18 shoot the whole thing. You could put enough
`
` 19 perforations in it that there wouldn't be hardly any
`
` 20 pressure drop and you'd just let the fluid find the
`
` 21 weak spot.
`
` 22 Or the way it's more typically done is
`
` 23 you do clusters that are spaced, you know, within that
`
` 24 300-foot section, maybe you're putting them 50 feet
`
` 25 apart, with the idea that you're trying to make sure
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` 1 that you've stimulated that whole interval and you
`
` 2 don't miss part of it, you don't have it all grow in
`
` 3 one end or the other of the interval. Am I answering
`
` 4 your question?
`
` 5 Q. I think so. So you don't need to know the
`
` 6 precise distance between the perforation clusters in
`
` 7 order to make sure that --
`
` 8 A. You do. You need to know the distance between
`
` 9 perforation clusters.
`
` 10 Q. Okay. That's what I was getting at.
`
` 11 A. Yeah, in order to -- if you're going to get
`
` 12 the control, to avoid the fractures growing into each
`
` 13 other you do need to know where -- the distance between
`
` 14 those clusters. But that's not necessarily just a
`
` 15 limited entry issue. Limited entry is about the
`
` 16 pressure drop and creating that back pressure inside
`
` 17 the wellbore.
`
` 18 Q. And to that point, it's not just distance in
`
` 19 order to keep the fractures from growing into each
`
` 20 other, you need to know that distance so you can
`
` 21 calculate that pressure drop, right?
`
` 22 A. Not really.
`
` 23 Q. Not really?
`
` 24 A. It's the -- it's the size of the
`
` 25 perforation -- what you use is the orifice equation, so
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` 1 you treat each perforation like a -- as if you had like
`
` 2 an orifice meter where you measure fluid flow.
`
` 3 Q. Uh-huh.
`
` 4 A. The equation uses the diameter of the
`
` 5 perforation and then you calculate the pressure drop
`
` 6 across each perf. So it's more about the number of
`
` 7 perfs then it is about the spacing. There might be --
`
` 8 if you had a really long bore hole, maybe friction
`
` 9 along the bore hole would enter into that. But
`
` 10 typically people ignore that in my experience, they
`
` 11 just worry about the perforation back pressure across
`
` 12 the -- because the interval is usually pretty short in
`
` 13 these applications.
`
` 14 Q. Do you place the perforations with the larger
`
` 15 diameter farther away from the fluid source?
`
` 16 A. You could if you thought that was going to
`
` 17 make a difference. But the pressure drop along a piece
`
` 18 of pipe that's 300 feet long is going to be pretty
`
` 19 small. So the pressure drop across the perforation
`
` 20 tunnel or, you know, orifice is going to be -- is going
`
` 21 to dominate the calculation. Because you want to be
`
` 22 super precise and you could take into account friction
`
` 23 along the bore hole. I haven't seen anybody actually
`
` 24 adjust the perforation size to -- for that distance,
`
` 25 but I suppose you could.
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` 1 Q. I'm going to hand you the Austin reference,
`
` 2 which is Exhibit 2098. Limited entry is the technique
`
` 3 that Austin advocates using, right?
`
` 4 A. Just a sec. Let me kind of scan this.
`
` 5 (Pause.)
`
` 6 Q. (BY MR. GARRETT) I tell you what, as you scan
`
` 7 it, if you will read to yourself the abstract, --
`
` 8 A. Yes.
`
` 9 Q. -- that will, I think, be helpful.
`
` 10 A. That's what I was doing.
`
` 11 Q. Okay.
`
` 12 A. So I'm sorry, could you repeat the question?
`
` 13 Q. I haven't even gotten to one yet.
`
` 14 A. Okay.
`
` 15 Q. I was sort of letting you familiarize yourself
`
` 16 with it. So just let me know when you're finished with
`
` 17 the abstract.
`
` 18 A. Okay.
`
` 19 (Pause.)
`
` 20 A. I've kind of read the first part there.
`
` 21 Q. (BY MR. GARRETT) Actually, I was wrong.
`
` 22 There was -- there was a question pending. It was
`
` 23 limited entry is the technique that Austin advocates
`
` 24 using in his paper here, right?
`
` 25 A. Let's see. Maybe let me look at that. I
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` 1 didn't see him say that in the abstract.
`
` 2 Q. He describes it as --
`
` 3 A. Is it one, two, three -- the fourth paragraph
`
` 4 he talks about properly applied controlled entry
`
` 5 techniques at several fracture initiation points.
`
` 6 Q. I think his term for it is multiple entry
`
` 7 fracturing treatment.
`
` 8 A. That's not necessarily limited entry. Limited
`
` 9 entry requires creating back pressure by limiting the
`
` 10 number of perforations. So the thing that you're
`
` 11 really limiting is how many holes you have in the pipe
`
` 12 and that in turn creates this back pressure that then
`
` 13 spreads the -- distributes the pressure over the
`
` 14 section that you're stimulating.
`
` 15 Comprehensive -- let's see.
`
` 16 Q. Well, one of the things that also
`
` 17 characterizes limited entry is the fact that you're
`
` 18 doing the stimulation at once, right?
`
` 19 A. On a particular section.
`
` 20 Q. Yes.
`
` 21 A. I mean, either -- you could try to treat the
`
` 22 entire bore hole with limited entry. At some point the
`
` 23 pressures required might become impractical for a given
`
` 24 length bore hole. But I've kind of lost track of the
`
` 25 question. I'm sorry.
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` 1 Q. That's all right. Go to native page 815.
`
` 2 A. I wish you guys had a lamp or print this stuff
`
` 3 on 11 by 17 for me. Okay. Go ahead.
`
` 4 Q. If you look at the first column right above
`
` 5 the cost effectiveness section at the bottom, the
`
` 6 paragraph right above that states, "A well with 2,000
`
` 7 feet of horizontal section was fracture stimulated with
`
` 8 proppant using the procedures presented in this paper.
`
` 9 Surface indications (designed rate and treating
`
` 10 pressure) were positive that all nine initiation points
`
` 11 were fractured and propped simultaneously at a total
`
` 12 rate of 108 barrels a minute with a delayed
`
` 13 cross-linked gel carrying a maximum proppant
`
` 14 concentration of six pounds per gallon." Do you see
`
` 15 that?
`
` 16 A. Yes.
`
` 17 Q. I mean, isn't that a description of what we've
`
` 18 been describing as limited entry?
`
` 19 A. Yeah, I would assume that he had to use
`
` 20 limited entry to achieve that.
`
` 21 Q. And then if we go over to the second column of
`
` 22 that same page, the first full paragraph, it reads, "If
`
` 23 stimulation treatments are performed one at a time in
`
` 24 horizontal well completions, the cost is the same as if
`
` 25 each treatment was similar to a vertical well. One way
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` 1 to reduce cost is to perform all the treatments by
`
` 2 using simultaneous multiple entry fracture techniques.
`
` 3 For example, one well has had nine fractures created
`
` 4 and treated at one time. Other wells have been planned
`
` 5 that will have three sets of three fractures performed
`
` 6 simultaneously. Whenever multiple simultaneous
`
` 7 fracture treatments are performed, the total cost of
`
` 8 stimulating will be less compared to performing
`
` 9 multiple individual treatments."
`
` 10 A. I see that, yes.
`
` 11 Q. I mean, is that giving you more comfort that
`
` 12 the technique that he's describing and advocating using
`
` 13 is limited entry?
`
` 14 A. Well, he doesn't really say that that's
`
` 15 limited entry, but -- does he use the term limited
`
` 16 entry in here somewhere?
`
` 17 Q. I don't think he uses it in this paper. And
`
` 18 so it sounds like the only distinction that you're
`
` 19 making between what he's describing -- the only
`
` 20 potential distinction -- and limited entry as you know
`
` 21 it is the -- it has to do with the principle that
`
` 22 you're limiting the number of perforations, right?
`
` 23 A. Correct. I mean, you could also have multiple
`
` 24 entry fracture points -- fracture entry points if you
`
` 25 used ball sealers or some other kind of diversion
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` 1 method. So you wouldn't have to do limited entry to
`
` 2 have multiple fracture entry points, but that would be
`
` 3 one way to do it.
`
` 4 Q. Well, but to do them all at once as he's
`
` 5 talking about doing, I mean, you couldn't achieve that
`
` 6 with ball sealers, right?
`
` 7 A. Well, actually you drop the balls as
`
` 8 you -- during the job and they're going to go to the
`
` 9 perforations that are taking the most fluid first
`
` 10 theoretically and ball out those and then go to the
`
` 11 next one and then go to the next one. So there's -- it
`
` 12 can be a continuous operation where you're just
`
` 13 dropping balls during the treatment. I mean, you just
`
` 14 vary the stages -- you create stages within that where
`
` 15 you say I'm going to pump this type of fluid, then I'm
`
` 16 going to drop some balls and pump this type of fluid
`
` 17 and drop some balls. That's another --
`
` 18 Q. Go ahead, finish your thought.
`
` 19 A. That's another way you could achieve -- you
`
` 20 could have a fracture -- you could have your clusters
`
` 21 that you put in the well and then you could drop balls.
`
` 22 Technically you're stimulating all of them, but then
`
` 23 you're trying to divert fluid more to one than the
`
` 24 other on the fly by dropping the balls.
`
` 25 Q. And I may not understand where those balls are
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` 1 going. Where are the balls going in what you're
`
` 2 describing?
`
` 3 A. Well, theoretically they should go wherever
`
` 4 the highest velocity is. So whatever is taking the
`
` 5 most fluid, that's where the ball should gravitate to.
`
` 6 You know, there might be some debate as to whe
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