Paper No. 1

UNITED STATES PATENT AND TRADEMARK OFFICE

BEFORE THE PATENT TRIAL AND APPEALBOARD

WEATHERFORD INTERNATIONAL, LLC;WEATHERFORD/LAMB, INC.;

WEATHERFORD US, LP; and WEATHERFORDARTIFICIAL LIFT SYSTEMS, LLC

Petitioners

v.

PACKERS PLUS ENERGY SERVICES,

INC., Patent Owner

Inter Partes Review No. IPR2017-01236

Patent 9,303,501

PETITION FOR INTER PARTES REVIEW UNDER 35 U.S.C.§ 312

ii

TABLE OF CONTENTS

I. INTRODUCTION.............................................................................................. 1

II. MANDATORY NOTICES................................................................................ 6

A. Real Party in Interest (37 C.F.R. § 42.8(b)(1)) .................................................. 6

B. Related Matters (37 C.F.R. § 42.8(b)(2))........................................................... 6

C. Lead and Back-Up Counsel (37 C.F.R. § 42.8(b)(3)) and Service Information

(37 C.F.R. § 42.8(b)(4)) ..................................................................................... 8

III. GROUNDS FOR STANDING .......................................................................... 9

IV. STATEMENT OF PRECISE RELIEF REQUESTED FOR EACH CLAIM

CHALLENGED................................................................................................. 9

A. Claims for Which Review Is Requested (37 C.F.R. § 42.104(b)(1)) ................ 9

B. Statutory Grounds of Challenge (37 C.F.R. § 42.104(b)(2))........................... 10

V. FIELD OF TECHNOLOGY............................................................................ 11

A. Drilling and Completing an Oil Well............................................................... 11

B. Fracturing an Open Hole Well ......................................................................... 14

C. Prior Art............................................................................................................ 18

1. Thomson........................................................................................................... 18

2. Ellsworth .......................................................................................................... 21

IPR2017-01236

iii

3. Halliburton ....................................................................................................... 24

VI. LEVEL AND KNOWLEDGE OF POSITA.................................................... 27

A. Level of Ordinary Skill .................................................................................... 27

B. A POSITA Knew of Available Combinations of Completion Tools .............. 27

C. Patent Owner Admissions: A POSITA Knew that Cased Hole Tools/Systems

Could be Used in Open Hole ........................................................................... 28

VII. THE '501 Patent ............................................................................................... 33

A. Prosecution History.......................................................................................... 38

B. Claim Construction (37 C.F.R. § 42.104(b)(3)) .............................................. 39

VIII. REASONS FOR THE RELIEF REQUESTED UNDER 37 C.F.R.

§§ 42.22(a)(2) AND 42.104(b)(4) – Ground 1 - Obvious over Thomson in

View of Ellsworth and Halliburton.................................................................. 40

A. It Would Have Been Obvious to Use Thomson in Open Hole........................ 40

B. Each of Claims 1-9 Would Have Been Obvious Over Thomson in View of

Ellsworth and Thomson ................................................................................... 43

IX. CONCLUSION................................................................................................ 68

IPR2017-01236

iv

TABLE OF AUTHORITIES

Cases

Chore-Time Equip., Inc. v. Cumberland Corp., 713 F.2d 774, 779 (Fed. Cir. 1983) 27

KSR Int'l Co. v Teleflex Inc., 550 U.S. 398, 417 (2007) ............................................ 42

Okajima v. Bourdeau, 261 F.3d 1350, 1355 (Fed. Cir. 2001) ................................... 27

Statutes

35 U.S.C. § 312 ............................................................................................................ 1

35 U.S.C. §102(b)....................................................................................................... 10

35 U.S.C. §103(a)....................................................................................................... 10

35 U.S.C. §311 ............................................................................................................. 1

Rules

37 C.F.R. § 42.104...................................................................................................... 40

37 C.F.R. § 42.22........................................................................................................ 40

37 C.F.R. § 42.8 (b)...................................................................................................... 9

37 C.F.R. § 42.8(b)................................................................................................... 6, 8

37 C.F.R. §42.100 et seq. ....................................................................................... 1, 39

IPR2017-01236

5

TABLE OF EXHIBITS

Exhibit Description1001 U.S. Patent No. 9,303,501 (“the '501 Patent”)1002 A.B. Yost, II, et al. Production and Stimulation Analysis of Multiple

Hydraulic Fracturing of a 2,000-ft Horizontal Well, SPE (Society forPetroleum Engineering) 19090 (1989) (“Yost”)

1003 D.W. Thomson, et al., Design and Installation of a Cost-EffectiveCompletion System for Horizontal Chalk Wells Where Multiple ZonesRequire Acid Stimulation, SPE (Society for Petroleum Engineering)37482 (1997) (“Thomson”)

1004 B. Ellsworth, et al., Production Control of Horizontal Wells in aCarbonate Reef Structure, 1999 Canadian Institute of Mining,Metallurgy, and Petroleum Horizontal Well Conference (“Ellsworth”)

1005 Declaration of Rebekah Stacha of the Society of Petroleum Engineers1006 Affidavit of Roberto Pellegrino1007 Declaration of Vikram Rao1008 Transcript of Continued Deposition of Daniel Jon Themig – 01/08/20071010 U.S. Patent No. 6,315,041 to Carlisle (“Carlisle”)1011 Affidavit of Kevin Trahan1012 Expert Report of Kevin Trahan1013 First Supplemental Expert Report of Kevin Trahan1014 Supplemental Engineering Report Prepared by Ronald A. Britton, P.E.1015 U.S. Provisional Application No. 60/404,783 filed on August 21, 20021016 U.S. Patent No. 3,062,291 to Brown1017 U.S. Patent No. 2,738,013 to Lynes1018 U.S. Patent No. 4,224,987 to Allen1019 U.S. Patent No. 6,006,838 to Whiteley et al.1020 Prosecution History of U.S. Patent No. 7,861,774 (“the '774 Patent”)1021 Prosecution History of U.S. Patent No. 7,543,634 (“the '634 Patent”)1022 Prosecution History of U.S. Patent No. 7,134,505 (“the '505 Patent”)1023 Prosecution History of U.S. Patent No. 6,907,936 (“the '936 Patent”)1024 U.S. Provisional Patent Application No. 60/331,491 filed on November

19, 20011025 Hart Petroleum Volume 71, Number 6, June 19981026 Declaration of Christopher D. Hawkes, Ph.D., P.Geo.1027 Declaration of Carrie Anderson1028 Halliburton Completion Products, Second Edition (1997)

(“Halliburton”)1029 Affidavit of Aileen Barr of Halliburton Energy Services, Inc., regarding

IPR2017-01236

6

Halliburton Completion Products, Second Edition (1997)1030 Prosecution History of U.S. Patent No. 9,303,5011031 Prosecution History of U.S. Patent No. 8,397,820 (including patent)1032 Prosecution History of U.S. Patent No. 8,746,343 (including patent)1033 Prosecution History of U.S. Patent No. 9,366,123 (including patent)1034 Overbey et al., Drilling, Completion, Stimulation, and Testing of Hardy

HW#1 Well, Putnam County, West Virginia, Final Report,DOE/MC/25115-3115 (1992) (indexed in Energy Research Abstracts,Vol. 18, No. 3, ISSN:0160-3604 (March 1993))

1035 U.S. Patent No. 6,253,856 to Ingram et al.1036 U.S. Patent No. 5,947,204 to Barton1037 U.S. Patent No. 4,330,039 to Vann et al.1038 Patrick J. McLellan, et al., A Multiple-Zone Acid Stimulation Treatment

of a Horizontal Well, Midale, Saskatchewan, April 1992 Journal ofCanadian Petroleum Technology at 71-82, and 42nd Annual TechnicalMeeting (“McLellan”)

IPR2017-01236

1

Pursuant to 35 U.S.C. §§311 & 312 and 37 C.F.R. §42.100 et seq.,

Weatherford International, LLC; Weatherford/Lamb, Inc.; Weatherford US, LP; and

Weatherford Artificial Lift Systems, LLC (“Petitioners” or “Weatherford”) request

inter partes review of claims 1-9 of U.S. Patent No. 9,303,501 (the “'501 Patent,”

Ex. 1001). The Board is authorized to deduct any required fees from Deposit

Account 500916.

I. INTRODUCTION

As shown in annotated Fig. 1a below, the '501 Patent's purported invention is a

method for fracturing a horizontal “open hole” oil well using a tubing string with

multiple “solid body” packers (“SBPs”) [red] to isolate the well into multiple zones,

and multiple sliding sleeves [blue] to open and close fluid injection ports in the

tubing string corresponding to respective zones, wherein a sliding sleeve [green] at a

lower end of the tubing string is hydraulically-actuated by applying a pressure within

the tubing string to shear pins holding the sleeve, and wherein the other sliding

sleeves are actuated by conveying fluid-conveyed sealing devices (e.g., balls)

through the tubing string.

IPR2017-01236

2

'501 Patent Figure 1a (annotated)

Petitioners' primary reference establishes that these concepts are not

patentable. For example, Thomson describes multi-zone fracturing, where each zone

includes a multistage acid fracture (“MSAF”) ball-actuated sliding sleeve between

two “solid body” packers: “[u]p to nine MSAF tools [blue] can be run in the

completion with isolation of each zone being achieved by hydraulic-set retrievable

packers [red]1 that are positioned on each side of an MSAF tool.” Ex. 1003 at 1.

1 In the depiction below, the packer on the left is a “permanent” packer and it is

colored red simply to show a sliding sleeve between two packers. As the quote makes

clear, the complete tubing string, which would extend to the right as shown in the

annotated and modified Figure 3 below in Section V.C.1, includes up to nine more

retrievable packers.

IPR2017-01236

3

Thomson also discloses a hydraulically-actuated pump out/cycle plug [green] that is

expelled to stimulate the lower zone after the packers are set. Id. The configuration

is shown in Thomson's annotated Figure 3 (see Ex. 1003 at 10):

Thomson Figure 3 (annotated)

Also in the context of horizontal open hole stimulations, Ellsworth discloses

IPR2017-01236

4

zonal isolation using sliding sleeves (blue) between multiple SBPs (red), and a plug

(green) at a lower end, as shown in the annotated Figure 11 (see Ex. 1004 at 9):

Ellsworth Figure 11 (annotated)

Furthermore, as shown in the annotated figure below, Halliburton discloses a

pump open plug with flow ports (yellow) and a pump open valve (i.e., hydraulically-

actuated sliding sleeve) (blue) that would have been an obvious alternative to

Thomson's and Ellsworth's plugs:

IPR2017-01236

5

Accordingly, as will be demonstrated below, and as illustrated in the

combination of Figures from Thomson and Halliburton, below, the purported

invention of the '501 Patent is nothing more than an obvious combination of known

elements from the prior art that have been combined according to their intended uses

and which would have yielded predictable results.

IPR2017-01236

6

II. MANDATORY NOTICES

A. Real Party in Interest (37 C.F.R. § 42.8(b)(1))

Weatherford International, LLC; Weatherford/Lamb, Inc.; Weatherford US,

LP; and Weatherford Artificial Lift Systems, LLC are the real parties-in-interest.

B. Related Matters (37 C.F.R. § 42.8(b)(2))

The following matters may affect, or be affected by, a decision in this

proceeding:

Rapid Completions LLC v. Baker Hughes Incorporated et al., Civil Action No.

6:16-cv-286 (E.D. Tex. 2016) (the “Litigation”), which involves the '501 Patent;

IPR2017-01232, addressing the '501 Patent and filed by Weatherford;

IPR2016-01380, addressing the '501 Patent, which was filed by other

defendants in the Litigation;

IPR2017-00247, addressing the '501 Patent, which was filed by other

defendants in the Litigation;

IPR2016-00596, addressing U.S. Patent No. 7,134,505 (“the '505 Patent”),

which was filed by other defendants in the Litigation;

IPR2017-01236

7

IPR2016-00597, addressing U.S. Patent No. 7,543,634 (“the '634 Patent”),

which was filed by other defendants in the Litigation;

IPR2016-00598, addressing U.S. Patent No. 7,861,774 (“the '774 Patent”),

which was filed by other defendants in the Litigation;

IPR2016-00650, addressing U.S. Patent No. 6,907,936 (“the '936 Patent”),

which was filed by other defendants in the Litigation;

IPR2016-00656, addressing U.S. Patent No. 8,657,009 (“the '009 Patent”),

which was filed by other defendants in the Litigation;

IPR2016-00657, addressing U.S. Patent No. 9,074,451 (“the '451 Patent”),

which was filed by other defendants in the Litigation;

IPR2016-01496, addressing the '505 Patent, which was filed by other

defendants in the Litigation;

IPR2016-01505, addressing the '634 Patent, which was filed by other

defendants in the Litigation;

IPR2016-01506, addressing the '774 Patent, which was filed by other

defendants in the Litigation;

IPR2016-01509, addressing the '774 Patent, filed by Weatherford;

IPR2016-01514, addressing the '634 Patent, filed by Weatherford;

IPR2016-01517, addressing the '505 Patent, filed by Weatherford;

U.S. Patent No. 7,571,765;

IPR2017-01236

8

U.S. Patent No. 7,832,472;

U.S. Patent No. 8,397,820;

U.S. Patent No. 8,746,343;

U.S. Patent No. 9,366,123;

U.S. Patent Application S.N. 15/149,742;

U.S. Patent Application S.N. 15/149,971; and

Rapid Completions LLC v. Baker Hughes Incorporated et al., Civil Action No.

6:15-cv-724 (E.D. Tex. 2015), which involves the '505, '634, '774, '936, '009, and

'451 Patents.

C. Lead and Back-Up Counsel (37 C.F.R. § 42.8(b)(3)) and ServiceInformation (37 C.F.R. § 42.8(b)(4))

Lead Counsel Back-Up Counsel

Jason Shapiro (Reg. # 35,354) Patrick Finnan (Reg. # 39,189)

Email: js@usiplaw.com pjf@usiplaw.com

Postal EDELL, SHAPIRO & FINNAN, LLC

9801 Washingtonian Blvd., Suite 750

Gaithersburg, MD 20878

Hand Del.: Same as Postal

Telephone: 301-424-3640

IPR2017-01236

9

Facsimile: 301-762-4056

Pursuant to 37 C.F.R. § 42.8 (b)(4), papers concerning this matter should be

served on either Jason Shapiro or Patrick Finnan as identified above.

III. GROUNDS FOR STANDING

Petitioners hereby certify that the '501 Patent for which review is sought is

available for IPR. Specifically: (1) the Petitioners are not an owner of the '501

Patent, see § 42.101; (2) before the date on which this Petition for review was filed,

none of Petitioners or Petitioners' real parties-in-interest filed a civil action

challenging the validity of a claim of the '501 Patent, see § 42.101(a); (3) Petitioners

requesting this proceeding have not filed this Petition more than one year after the

date on which the Petitioners, Petitioners' real party-in-interest, or a privy of

Petitioners were served with a complaint alleging infringement of the '501 Patent, see

§ 42.101(b); and (4) Petitioners, Petitioners' real parties-in-interest, or a privy of

Petitioners are not estopped from challenging the claims on the grounds identified in

this Petition, see § 42.101(c).

IV. STATEMENT OF PRECISE RELIEF REQUESTED FOR EACHCLAIM CHALLENGED

A. Claims for Which Review Is Requested (37 C.F.R. § 42.104(b)(1))

Petitioners request review and cancellation of the '501 Patent claims 1-9 (the

“Challenged Claims”).

IPR2017-01236

10

B. Statutory Grounds of Challenge (37 C.F.R. § 42.104(b)(2))

Ground 1: The Challenged Claims are invalid under 35 U.S.C. §103(a) based

on Thomson (Ex. 1003) in view of Ellsworth (Ex. 1004) and Halliburton (Ex. 1028).

Thomson (1997), Ellsworth (1999), and Halliburton (1997) are prior art under 35

U.S.C. §102(b) because each was published more than one year prior to November

19, 2002, the earliest priority date claimed in the '501 Patent.2 Ex. 1005 at ¶¶ 4-6; Ex.

1026 at ¶¶ 2-5; Ex. 1006 at ¶¶ 5-7; Ex. 1029 at ¶¶ 3-4; Ex. 1030 at 689.

Ground 1 of the present IPR is not cumulative with Ground 1 of IPR2017-

01232, also filed by Weatherford, because the two Petitions rely on different primary

references. Nor are the grounds asserted in the two Petitions cumulative to the

grounds raised by other parties in IPR2016-01380 and IPR 2017-00247 because they

2 Even though the '501 Patent claims priority to an earlier filing date based on

two provisional applications, Petitioner submits that claims 1-9 are not entitled to

priority before November 19, 2002 because the claims require a “hydraulically

actuated sliding sleeve [that] moves from the closed port position to the open port

position without the hydraulically actuated sliding sleeve engaging any fluid

conveyed sealing device,” and neither provisional application to which the '501

Patent claims priority discloses this feature. Even if the provisional applications did

disclose this feature, the cited references were published more than one year before

the earliest claimed priority date of November 19, 2001.

IPR2017-01236

11

each provide new evidence of unpatentability. For example, Ground 1 in the present

Petition presents material Patent Owner admissions from a prior litigation not

presented in other IPRs addressing the '501 Patent.

V. FIELD OF TECHNOLOGY

A. Drilling and Completing an Oil Well

Before the purported invention, drilling a well included drilling a hole to

construct a wellbore in a geological formation with oil or gas reserves. Oftentimes

the wellbore included horizontal sections. Ex. 1002; Ex. 1003; Ex. 1004; Ex. 1007 at

¶ 39. The wellbore was sometimes lined with tubing that was cemented in place,

referred to as a “casing,” to protect the wellbore during production. See, e.g., Ex.

1001 at 1:40-42; Ex. 1007 at ¶ 39. In some circumstances, however, the wellbore

was left uncased (called an “open hole”) to “expose porosity and permit unrestricted

wellbore inflow of petroleum products.” See, e.g., Ex. 1001 at 1:36-40; see also Ex.

1007 at ¶ 39. If a wellbore was cased, access to the formation was provided by

“perforating” (i.e., creating openings in the casing) to allow oil and/or gas to flow

from the formation into the wellbore. Ex. 1001 at 1:40-42; Ex. 1007 at ¶ 39.

After drilling a well, it needed to be completed before production. Whether

there was a cemented casing or not, completion typically involved running a tubing

string into the wellbore to deliver tools and/or stimulate the formation. See, e.g., Ex.

1001 at 1:43-57, 66-67, and 2:1-6; Ex. 1007 at ¶ 39. Stimulation often involved

IPR2017-01236

12

pumping acid or other fluids into the wellbore under pressure via ports or openings

in the tubing string. See, e.g., Ex. 1001 at 1:43-54 and 2:1-6; Ex. 1007 at ¶ 42. For

example, fracturing fluids were injected into the wellbore under pressure to

propagate natural fractures and/or to induce and propagate new fractures. See, e.g.,

Ex. 1002 at 1-5; Ex. 1003 at 1 and 3-5; Ex. 1004; Ex. 1007 at ¶ 48. Afterwards, the

tubing string was used as a conduit for production. See, e.g., Ex. 1002 at 1-5, 7, and

9; Ex. 1007 at ¶ 39.

Tools called “packers” were frequently used to seal the annulus around the

tubing string in order to isolate the wellbore into multiple zones for selective

treatment and/or production. See, e.g., Ex. 1001 at 1:52-57; Ex. 1007 at ¶ 40.

Various types of packers were employed in both cased and open hole wells,

including inflatable packers which deployed inflatable packing elements and solid

body packers which compressed and extruded outward resilient packing elements.

Ex. 1001 at 1:52-57; Ex. 1002 at 1-2; Ex. 1003 at 2 and 10; Ex. 1004 at 5; Ex. 1007

at ¶ 40. Such packers were set by pressurizing the tubing string. See, e.g., Ex. 1002

at 1-2; Ex. 1003 at 2 and 10; Ex. 1004 at 5; Ex. 1007 at ¶ 40.

Tubing strings typically included a plug at a bottom end to allow the tubing

string to be pressurized in order to set the packers. See, e.g., Ex. 1003 at 3-5, and Ex.

1004 at 5, 7, and 9-10; Ex. 1034 at 99-102; Ex. 1035 at 5:36-51, 8:32-47; Ex. 1007 at

¶ 41. Various types of plugs were available, including pump-out plugs, pump-open

IPR2017-01236

13

plugs, and disappearing plugs. See, e.g., Ex. 1028 at 56, 93, and 97; Ex. 1007 at

¶¶ 41, 50, 60-62, and 68-71. Disappearing plugs disintegrated after a predetermined

number of pressure cycles. Id. Pump-out plugs were expelled from the tubing string

at a pressure higher than the packer-setting pressure, and pump-open plugs included

sliding sleeves that were shifted in relation to ports (i.e., pumped open) at a pressure

higher than the packer-setting pressure. See, e.g., Ex. 1003 at 2-5; Ex. 1004 at 5, 7,

and 9-10; Ex. 1034 at 99-102; Ex. 1007 at ¶ 41. Thus, after the packers were set, it

was known that a higher pressure could be used to expose a port or opening in the

tubing string by actuating a “sliding sleeve” in the plug (e.g., in the case of a pump-

open plug) or expelling the plug (e.g., in the case of a pump-out plug), so that

stimulating fluids could be injected into the lower zone. See, e.g., Ex. 1003 at 3-4,

1028 at 93; Ex. 1034 at 99-102; Ex. 1007 at ¶ 41.

Tubing strings also included “sliding sleeves” above the plug that, when

actuated, exposed ports in the tubing string to permit selective stimulation of

individual zones between packers. See, e.g., Ex. 1002 at 1, 2 and 10; Ex. 1003 at 1-

5, 10 and 12; Ex. 1004 at 5-10; Ex. 1007 at ¶ 41. The sliding sleeves above the plug

were sometimes actuated by pumping balls or darts of varying sizes down the tubing

string. See, e.g., Ex.1003 at 1-5, 10 and 12; Ex. 1007 at ¶ 41.

It was also known to combine hydraulically-actuated sliding sleeve (i.e.,

pump-open) plugs with ball-actuated sliding sleeves to stimulate a formation. For

IPR2017-01236

14

example, a DOE report published in March 1992 disclosed multi-stage hydraulic

fracturing in a horizontal open hole well using a plugged port collar (i.e., a

hydraulically-actuated sliding sleeve) in a first stage at a bottom of the tubing string

and a ball drop actuated port collar in a second stage. Ex. 1034 at 98-102; see also

Ex. 1035 at 1:54-56, 5:13-19, and 6:15-21; Ex. 1007 at ¶¶ 44-45.

B. Fracturing an Open Hole Well

Where oil wells do not produce sufficient oil and/or gas to make the well

economic, it is common to employ some method of stimulating an oil well to

improve the production, such as fracturing. Ex. 1001 at 1:44-45; Ex. 1007 at ¶ 42.

Open hole fracturing was a common method for stimulating wells before 2001. Ex.

1007 at ¶ 43. Numerous references show that it was known to use multistage, open

hole fracturing before 2001.

Yost, published in 1989, notes that fracturing as a form of stimulation in

horizontal wells has been used for decades: “The value of high angle drilling and

multiple hydraulic fracturing from an inclined or horizontal borehole for maximizing

production was recognized in 1969.” Ex. 1002 at 1. Yost describes multi-stage

fracturing of horizontal open hole wells using packers for zonal isolation and ported

sliding sleeves for injecting fracturing fluids:

An alternative approach is zone isolation accomplished by the

installation of external casing packers and port collars as an integral

IPR2017-01236

15

part of a casing string in the horizontal section. Such a completion

arrangement provided stimulation intervals with ready-made

perforations for injecting fracturing fluids in an open hole fracturing

condition behind pipe. This was the method of completion used in this

2000 foot horizontal well to avoid the problems of formation damage

associated with cementing and to eliminate the need for tubing-

conveyed perforating of numerous treatment intervals.

Ex. 1002 at 1 (emphasis added); see also id. at 2 (referencing “sliding sleeve ported

collars” between packers); Ex. 1007 at ¶ 43. Yost's “external casing packers” are

inflatable. Ex. 1002 at 2; Ex. 1007 at ¶ 43.

McLellan, published in 1992, also shows an example of multistage, horizontal

open hole fracturing:

Selective stimulation of the openhole section of Midale horizontal

C3-5 was performed with centralized inflatable straddle packers

separated by a 4.3 m long joint of 73 mm tubing. This configuration as

detailed in Figure 6 was run on conventional 73 mm tubing to the

desired depth. The advantage of the inflatable straddle packer assembly

lies in its ability to unseat, move location and reseat. The fact that it is a

hydraulic tool allows operation in highly deviated and horizontal wells.

Ex. 1038 at 6; Ex. 1007 at 46. McLellan explains that 27 separate acid injections

occurred “without a tool failure or leakage around the packer elements.” Id. And

McLellan explains that the acid injections were fracturing the wellbore: “Based on

[multiple data,] the authors believe that within each acid squeeze interval a small

IPR2017-01236

16

fracture was initiated at the weakest point along the wellbore.” Ex. 1038 at 8-9; Ex.

1007 at ¶ 46.

The Background section of the '501 Patent itself acknowledges this prior art:

In one previous method, the well is isolated in segments and each

segment is individually treated so that concentrated and controlled fluid

treatment can be provided along the wellbore. Often, in this method a

tubing string is used with inflatable element packers thereabout which

provide for segment isolation. The packers, which are inflated with

pressure using a bladder, are used to isolate segments of the well and the

tubing is used to convey treatment fluids to the isolated segment. Such

inflatable packers may be limited with respect to pressure capabilities as

well as durability under high pressure conditions. Generally, the

packers are run for a wellbore treatment, but must be moved after each

treatment if it is desired to isolate other segments of the well for

treatment.

Ex. 1001 at 1:49-61. Thus, the inventors of the '501 Patent themselves acknowledge

that the prior art includes multistage open hole fracturing similar to what is disclosed

in Yost and McLellan. Ex. 1007 at ¶ 47.

Finally, U.S. Patent No. 6,315,041 to Carlisle was filed on April 15, 1999 and

is prior art to the '501 Patent. Ex. 1010 at 1. Carlisle also describes examples of

horizontal, open hole fracturing. Carlisle's Background states that the invention

relates “more particularly, to isolating segments of a subterranean cased or open hole

well for stimulating and/or testing purposes. The invention is particularly well-

IPR2017-01236

17

suited for stimulating horizontal wellbores that extend through a naturally fractured

reservoir.” Ex. 1010 at 1:8-12. Carlisle's focus on naturally fractured reservoirs is

particularly relevant to open hole because the existence of natural fractures is a

motivation to leave a well open hole rather than casing and closing off natural

fractures. Ex. 1007 at ¶ 48. Carlisle concludes that “to effectively fracture a long

horizontal well, the well needs to be isolated into sections which can each be

independently stimulated.” Ex. 1010 at 1:22-34. Carlisle first mentions inflatable

packers as “[o]ne way to isolate horizontal sections of a well in anticipation of

fracturing.” Id. at 1:35-38. Carlisle describes a second method:

There is another tool, the Wizard Packer from Dresser, that

allows isolation of a horizontal well into preset lengths to facilitate

stimulation of the formation, but it requires sending darts into the

sections to open sliding sleeves which allow the treating fluid to enter

into the isolated section. Despite the isolation, there is sometimes still

no stimulation within the preset segment if one or more of the interval

sections does not contain a natural fracture to enhance.

Ex. 1010 at 1:43-50. Thus, in the context of open hole fracturing, Carlisle describes

a system using Wizard packers and sliding sleeves to accomplish horizontal, open

hole, multistage fracturing. Ex. 1007 at ¶ 48.

This collection of prior art makes clear that a person of ordinary skill in the art

in November, 2001 would have understood that multistage, horizontal, open hole

fracturing was known and practiced. Ex. 1007 at ¶ 49. Thus, a person of ordinary

IPR2017-01236

18

skill in the art would have been motivated to try open hole fracturing where the

economics or other factors favored the use of open hole fracturing as opposed to

cased hole fracturing. Ex. 1007 at ¶ 49.

C. Prior Art

The techniques described above were well known at the time of the purported

invention, as exemplified by the following prior art references:

1. Thomson

Thomson, published in 1997, discloses multi-stage fracturing in a horizontal

cased well. Thomson states “[a]n innovative completion design that allows multiple

acid fracs to be performed in horizontal subsea chalk-formation wells with a single

trip into the wellbore has recently been codeveloped . . . .” Ex. 1003 at 1; see also

Ex. 1007 at ¶ 51. This design's goal was to allow “multiple acid stimulations” “to be

efficiently performed in the shortest possible time.” Id. at 1; see also Ex. 1007 at

¶ 51.

Thomson describes alternating hydraulically set packers (an example of SBPs)

and MSAF tools (an example of ball-actuated sliding sleeves):

The key element of the system is a multi-stage acid frac tool

(MSAF) that is similar to a sliding sleeve circulating device and is run

in the closed position. Up to 9 MSAF tools can be run in the completion

with isolation of each zone being achieved by hydraulic-set retrievable

packers that are positioned on each side of an MSAF tool. Each sleeve

IPR2017-01236

19

contains a threaded ball seat with the smallest ball seat in the lowest

sleeve and the largest ball seat in the highest sleeve. With this system,

stimulation of 10 separate zones is accomplished in 12-18 hours by a

unique procedure that lubricates varying sized low-specific gravity balls

into the tubing and then pumps them to a mating seat in the appropriate

MSAF, thus sealing off the stimulated zone and allowing stimulation of

the next zone which is made accessible by opening the sleeve. 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.

Ex. 1003 at 1; see also Ex. 1007 at ¶ 52.

As stated, Thomson's system included “[u]p to 9 MSAF tools . . . with . . .

hydraulic-set retrievable packers . . . on each side.” Id.; see also Ex. 1007 at ¶ 52.

Referring to annotated and modified Figure 3 below, the lower end of such a tubing

string is shown with MSAF tool sizes taken from Table 1 (Ex. 1003 at 6, Table 1)3:

3 Figure 3 of Ex. 1003 [1003] has been modified and annotated below to show

a section of the up to 9 MSAF tools that can be run in the completion with isolation

of each zone being achieved by hydraulic-set retrievable packers positioned on each

side of an MSAF tool, with the MSAF tool sizes taken from Table 1 (Ex. 1003 at 6,

Table 1).

IPR2017-01236

20

Thomson Figure 3 (annotated and modified)

Thomson's ball-drop actuated sliding sleeve is shown in both open and closed

positions in annotated Figure 5 below. When in the closed position shown below,

the sleeve closes a port in the tubing, and when in the open position, the port opens

to allow communication between the tubing and the annulus:

Figure 5 (annotated)

Id. at 12; see also Ex. 1007 at ¶¶ 51-53.

Thomson also discloses a pump out/cycle plug at a bottom end of the tubing

IPR2017-01236

21

string. Id. at 3, 4; Fig. 3; see also Ex. 1007 at ¶ 56. Once the tubing string was at the

desired depth, pressure was applied to the tubing against the plug to set the packers.

Id.; see also Ex. 1007 at ¶ 57. The stimulation operation was then started by

“expelling the pump out/cycle plug and stimulating the lower zone (below the

bottom packer).” Id.; see also Ex. 1007 at ¶ 57. After stimulating the lower zone

(labeled “3rd Segment” in the annotated and modified Figure 3 above), the smallest

ball was pumped onto its mating seat in the lowest MSAF to seal-off the lower zone

and to allow stimulating fluid to be pumped into the next higher zone (labeled “2nd

Segment”), and so on. Id.; Ex. 1007 at ¶ 57.

Thus, Thomson discloses “single trip” multi-zone fracturing in a horizontal

well bore using the combination of hydraulic-set packers with compressible elements

(which are an example of SBPs), ball-drop actuated sliding sleeves, and a tubing

string plug that can be pumped out to treat the lower zone after the packers have been

set. Id. at 1, 3, 4, and 6; Ex. 1007 at ¶ 63.

2. Ellsworth

While the '501 Patent discloses inflatable packers as prior art (Ex. 1001 at

1:52-57), a POSITA knew that other options for sealing in open hole stimulations,

including “solid body” packers, were available. One such SBP was the Wizard II

packer, which was sold by Dresser/Guiberson and Halliburton in the late 1990s. Ex.

1004 at 5; Ex. 1007 at ¶ 64.

IPR2017-01236

22

Ellsworth, published in 1999, was co-authored by Dan Themig, a named

inventor of the '501 Patent and co-founder of Patent Owner (Packers Plus).

Ellsworth describes using Wizard SBPs in horizontal open hole for “stimulation”:

Historically, inflatable packers were used for water shut-off,

stimulation and segment testing. More recently, solid body packers

(SBP's) (see Figure 4) have been used to establish open hole isolation.

These tools provide a mechanical packing element that is hydraulically

activated. The objective of using this type of tool is to provide a long-

term solution to open hole isolation without the aid of cemented liners.

Although the expansion ratios for these packers are [sic: not] as large as

for inflatables, the carbonate formation in Rainbow Lake generally drills

very close to gauge hole, and effective isolation is possible with these

SBP's.

Ex. 1004 at 5 (emphasis added); Ex. 1007 at ¶ 64.

Ellsworth's Figure 4 is reproduced below. As shown, Figure 4 reiterates that

the Wizard is a “solid body packer . . . instead of inflatable,” and it identifies a “Five

Piece Packing Element” actuated by a “Setting Cylinder”:

IPR2017-01236

23

Ellsworth Figure 4

Ex. 1004 at 5; Ex. 1007 at ¶ 64.

As shown in annotated Figure 11 in Section I above, Ellsworth also discloses

zonal isolation using sliding sleeves between multiple SBPs. Ex. 1004 at 5

(“Between the sets of packers was a 73mm (2-7/8") sliding sleeve”); see also id. at 7

(“A sliding sleeve was installed between the isolation points to allow an inflow point

for the middle well interval.”); see also Ex. 1007 at ¶ 65. Ellsworth provides

examples of using these SBPs for stimulation. Id. at 7-8 (“Prior to running the

production assembly, SBP's were run to acidize the toe of the well . . . . The initial

IPR2017-01236

24

acid job using SBP's indicated that the tools successfully provided isolation during

the job.”), 10 (“Lateral #2 was produced with oil cuts of 35-50%. The leg was then

acidized through the tubing string, and swabbed back.”); Ex. 1007 at ¶¶ 64-65.

Ellsworth further discloses the use of a pump-out plug at the bottom of the

tubing string to pressurize the tubing for setting the solid body packers. Ex. 1004 at

5, 7, 9 and 10; Fig. 11; see also, e.g., Ex. 1007 at ¶ 68.

3. Halliburton

Halliburton, published in 1997, discloses a pump open plug that can be run on

a tubing string below packers. Ex. 1028 at 93. As shown in the annotated figure

below, the pump open plug includes a tubular “Plug Body” with “Flow Ports” and a

“Pump Open Valve” (which is an example of a hydraulically-actuated sliding

sleeve), secured by “Release Pins” (which are an example of shear pins) in a first

position covering the Flow Ports. Id.; see also Ex. 1007 at ¶ 69.

IPR2017-01236

25

Closed Port Position

When the pump open plug is run below a “packer completion assembly,” and

the Pump Open Valve (hydraulically actuated sliding sleeve) is in the closed port

position shown above, the tubing string can be pressurized to set the packers. Ex.

1007 at ¶ 69. Increasing the pressure further causes the Release Pins to shear and the

Pump Open Valve to move downwardly to an open port position exposing the Flow

IPR2017-01236

26

Ports to fluid flow, as shown in the modified figure below, without engaging any

fluid-conveyed sealing device. Ex. 1007 at ¶ 69.

Opened Port Position

IPR2017-01236

27

VI. LEVEL AND KNOWLEDGE OF POSITA

A. Level of Ordinary Skill

A POSITA as of November 19, 2001—the earliest priority date claimed4—

would have had at least a Bachelor of Science degree in mechanical or petroleum

engineering or a similar technical discipline, such as metallurgy or material science

and engineering and at least 3 years of experience with oil or gas well drilling and

completion operations or in technical support of such operations. Ex. 1007 at ¶ 38.

Additional education in a relevant technical discipline can compensate for less

experience in the relevant field and vice versa. Id. This level of ordinary skill is

evidenced by prior art and the '501 Patent. Id. at ¶¶ 42-66; Chore-Time Equip., Inc.

v. Cumberland Corp., 713 F.2d 774, 779 (Fed. Cir. 1983); Okajima v. Bourdeau, 261

F.3d 1350, 1355 (Fed. Cir. 2001).

B. A POSITA Knew of Available Combinations of Completion Tools

The prior art described in Section V.C above establishes that a POSITA would

have been familiar with various completion/stimulation techniques. Ex. 1007 at

¶¶ 38, 71. Specifically, by the late 1990s, a POSITA understood that fracturing in

horizontal open hole or cased wells could be successfully performed with both some

type of packer for zonal isolation and some form of ported sleeve or port for

4 The level of ordinary skill in the art as of November 19, 2002 would be no

different. Ex. 1007 at ¶ 38.

IPR2017-01236

28

injection into the isolated zones. Id. A POSITA further understood that a selection

of tools was available for performing the zonal isolation, including inflatable packers

(e.g., Ellsworth and '501 Patent Background) and SBPs (e.g., Ellsworth's Wizards

and Thomson's hydraulic-set packers). Id. Similarly, a POSITA understood that a

selection of tools was also available for providing the injection capability, including

ball-drop actuated sliding sleeves (e.g., Thomson's MSAF tool), coiled tubing or

wireline actuated sliding sleeves (e.g., Ellsworth), and tubing plugs with

hydraulically-actuated sliding sleeves (e.g., the Halliburton pump-open plug). Id.

A POSITA also knew that inflatable packers were not always preferable, and

in some circumstances, hydraulically-set SBPs would be preferable in cased and

open hole wells. See, e.g., id. ¶¶ 51-68; see also Ex. 1004 at 5 (“Historically,

inflatable packers were used [but] [m]ore recently, solid body packers (SBP's) (see

FIG. 4) have been used to establish open hole isolation.”). A POSITA further knew

that tools like the Halliburton pump-open plug could be used for the same purpose as

the pump-out plugs and cycle plugs disclosed in Thomson and Ellsworth in a tubing

string with predictable results. Ex. 1007 at ¶¶ 45-46, 71, 72; see also, e.g., Ex. 1034

at 99-102.

C. Patent Owner Admissions: A POSITA Knew that Cased HoleTools/Systems Could be Used in Open Hole

A POSITA further understood that many tools (e.g., packers and sliding

IPR2017-01236

29

sleeves) and systems (e.g., completion systems) initially designed for or used with

cemented casing could also be used in open hole and that such use in open hole is not

a patentable advancement. Ex. 1007 at ¶¶ 64, 91. In fact, Patent Owner, through its

named inventor (Mr. Themig) and its technical experts from a prior litigation

(Messrs. Britton and Trahan), has made repeated admissions to this effect. These

admissions bear directly on the issues raised in this Petition. For example, the

admissions establish that a POSITA would know that the cased hole system of

Thomson could be used successfully in open hole.

As background, Patent Owner was accused of trade secret misappropriation in

a litigation brought by Halliburton Energy Services, Inc. regarding some of the

technology claimed in the '501 Patent. During that litigation, Mr. Themig testified on

behalf of Patent Owner about his prior employment at Dresser/Guiberson before

2000, during which time it became known to use cased hole tools in open hole wells:

Q: So are the design features of [Packer Plus' RockSeal] IIS a

“first” for the oil and gas industry?

A: Not necessarily.

Q: Why is that?

A: Well, part of the thing about the compression set elements

is, when I was at Guiberson, we learned that we could just take cased-

hole packers and put them in the open hole, and they would

function and they would work.

So the tandem hydraulic was never built for cased hole–or

IPR2017-01236

30

sorry, it was never built for open hole. But when we first decided to try

hydraulics at open-hole packers, we learned that we could set them in

open hole and that they would isolate and they would function. So

the elements were designed for casing, but they worked in open

hole.

When we designed the Wizard packer, which I was

involved in, we took all cased-hole elastomers and put them on a

hydraulic cylinder and we ran them, and again, they functioned in open

hole.

***

So, basically, as far as what we had discovered, I guess,

was that anything that we could run in casing, we could also run in

open hole, and it would function provided the open hole was

competent.

Q: You said anything that you run in casing can function

in open hole, correct?

A: Provided that the formation is competent.

Ex. 1008 at 498:12-500:1 (emphasis added).

Mr. Themig further testified that he expected the RockSeal, the preferred

embodiment SBP in the '501 Patent, to be successful because of the pre-2000 success

in open hole of the Wizard SBP. Ex. 1008 at 573:8-24. The Wizard packer success

is reflected in Ellsworth, which Mr. Themig co-authored.

These admissions illustrate that a POSITA would have known to use cased

hole tools like those found in Thomson in open hole. This very point was repeatedly

IPR2017-01236

31

confirmed by Patent Owner's technical expert, Mr. Trahan, in the prior Halliburton

litigation. Of interest, Mr. Trahan later became the CTO and even COO of Patent

Owner. For example, during prosecution of the '501 Patent, Patent Owner submitted

in an IDS a declaration of Mr. Trahan from the Halliburton litigation. Ex. 1020 at 35

(Doc. KKKKK). Opining on what was “understood” as of 1999, Mr. Trahan (on

behalf of Patent Owner) testified as follows in his declaration:

I am an expert in the field of oil and gas well drilling and

completion technology.

* * *

Packing Elements of many different configurations have been

used in cased hole as well as open hole. . . . It is a fact that packing

elements which were initially designed for cased hole have been

used in open hole. . . . Reliability is largely dependent on the

competence of the open hole formation in which the packer is set. . . .

Ex. 1011 at ¶¶ 2, 9.

Similarly, Mr. Trahan signed an expert report on behalf of Patent Owner in

which he acknowledged the long history of using cased hole tools in open hole,

which he deemed to be an “obvious,” i.e., non-patentable, application:

Cased hole tools, including packers, have been used in open hole

applications for many years. In my opinion use of a tool with Rockseal

type features in open hole does not pass the patentability standard of

novelty or nonobviousness. The open hole application of tools that

were originally designed for cased hole has been common place in

IPR2017-01236

32

the industry since I began working in the industry in 1992. There is

nothing novel or nonobvious about such an application.

Ex. 1012 at 10-11 (emphasis added).

Mr. Trahan reconfirmed these same points in his supplemental expert report

on behalf of Patent Owner:

The hard rock formations, once drilled, typically provide a

circular cross section conduit, just as a cased hole does. In these

types of hard formations a tool that was designed for use in cased

hole may be used in open hole. The fact is that many tools, including

anchoring mechanisms and packing elements, that were initially

designed for cased hole, with no contemplation of being used in

open hole, have been used in open hole successfully. It is a fact that

many tools which utilized compression set elastomeric solid packing

elements have been used in open hole . . . . In fact this is exactly what

Guiberson/Halliburton has done successfully for many years by use of

its original Wizard type packer designs. . . .

Ex. 1013 at 5 (emphasis added); see also id. at 12 (“Compression set elements have

long been used in both cased hole and open hole applications.”).

Finally, Patent Owner's other expert, Mr. Britton, made the same admissions

on behalf of Patent Owner. Based on his “years of direct field experience in the

operational side of the oil and gas industry” (Ex. 1014 at 3), Mr. Britton signed an

expert report stating:

Many tools that were originally designed as cased hole tools can

and have been used in open hole situations. . . . In many deep hole

IPR2017-01236

33

situations, a deep open hole acts in the same manner as a cased hole.

Consequently, many of the tools designed for cased hole

applications would be used in open hole applications.

Ex. 1014 at 4-5 (emphasis added).

Accordingly, during the Halliburton litigation, Patent Owner expressed the

view several times that it was well known before 2000 that many open hole

wellbores act in the same manner as a cased hole, and therefore, the use of cased hole

tools in open hole was “common place” and not patentable.

VII. THE '501 Patent

As annotated in Figure 1a below, the '501 Patent depicts an open hole

wellbore 12 drilled through a formation 10 and a tubing string assembly run in the

wellbore. Ex. 1001 at 6:11-19, 10:28-33; see also Ex. 1007 at ¶ 73.

IPR2017-01236

34

'501 Patent Figure 1a (annotated)

IPR2017-01236

35

The tubing string includes multiple ports 17 [blue], which are “opened through

the tubing string wall to permit access between the tubing string inner bore 18 and

the wellbore.” Id. at 6:8-12; see also Ex. 1007 at ¶¶ 73-74. Ported intervals 16a-e

are separated by packers 20a-f [red] to divide the formation into fluid treatment

zones isolated from each other. Id. at 6:13-28; see also Ex. 1007 at ¶¶ 73-74, 81.

When the tubing string is run into the wellbore, ported intervals 16a-e are

covered by sliding sleeves 22a-e [blue], annotated below in Figure 1b, to prevent

fluid from passing through ports 17. Id. at 6:37-49; see also Ex. 1007 at ¶ 77. To

open sliding sleeves 22a-e and permit flow through ports 17, a ball or plug 24 is

“dropped” into the tubing string and is carried to a corresponding sleeve 22, where

the ball or plug engages and seals against a seat 26 in the sleeve. Id. at 6:58-7:31;

see also Ex. 1007 at ¶ 78.

IPR2017-01236

36

FIG. 1b (annotated)

As shown below in annotated Fig. 3a (closed port position) and annotated Fig.

3b (open port position), increasing pressure against the ball [green]/seat [purple]

moves sleeve 22 [blue] to open ports 17 [orange]. Id.; see also Ex. 1007 at ¶ 78. To

selectively open one sleeve at a time, the seat of each sleeve has a different diameter.

“[T]he lower-most sliding sleeve 22e has the smallest diameter D1 seat and accepts

IPR2017-01236

37

the smallest sized ball 24e and each sleeve that is progressively closer to the surface

has a larger seat.” Id. at 7:14-19; see also Ex. 1007 at ¶ 78.

In the illustrated embodiment, a pump out plug assembly 28 is provided at

the lower end of the tubing string to close off the lower end during running in of the

tubing string and to permit actuation of the lower most sliding sleeve when expelled

by application of fluid pressure. Id. at 7:40-52; see also Ex. 1007 at ¶ 80. In an

alternate embodiment, not shown in the Figures, “the lower most sleeve can be

hydraulically actuated, including a fluid actuated piston secured by shear pins, so

that the sleeve can be opened remotely without the need to land a ball or plug

therein.” Id. at 7:52-56; see also Ex. 1007 at ¶ 81.

IPR2017-01236

38

The '501 Patent discloses packers of the “solid body-type.” Id. at 6:29-35;

see also Ex. 1007 at ¶ 75. As shown below in Fig. 2, SBP 20 includes two packing

elements 21a and 21b “formed of elastomer” like rubber and extruded outwardly

when set hydraulically or by “mechanical forces.” Id.; see also Ex. 1007 at ¶ 76.

FIG. 2 (annotated)

A. Prosecution History

In the Statement of Reasons for Allowance, the Examiner noted that “[t]he

prior art of record does not disclose or suggest all the claimed subject matter

IPR2017-01236

39

including applying a first pressure within the tubing string inner bore such that the

hydraulically actuated sliding sleeve moves from the closed port position to the open

port position without the hydraulically actuated sliding sleeve engaging any fluid

conveyed sealing device; conveying a fluid conveyed sealing device through the

tubing string to pass through the first sliding sleeve and to land in and seal against

the seat of the second sliding sleeve thereby moving the second sliding sleeve to the

open port position.” Ex. 1030 at 62-63.

B. Claim Construction (37 C.F.R. § 42.104(b)(3))

The broadest reasonable interpretation (BRI) applies in an inter partes review.

37 C.F.R. §42.100(b). Under the BRI, words of the claim must be given their plain

meaning, unless such meaning is inconsistent with the specification. Thus, solely for

this proceeding, the following list contains the proposed terms for construction and

Petitioner's proposed constructions. All other terms, not presented below, should be

given their plain meaning in light of the specification.

The BRI of “solid body packer” is “a tool to create a seal between tubing and

casing or the borehole wall using a packing element which is mechanically

extruded, using either mechanically or hydraulically applied force.” This is the

definition adopted by the Patent Owner in U.S. Provisional Application No.

60/404,783, to which the '501 Patent claims priority, and is consistent with the

understanding of a POSITA. Ex. 1015 at 4; Ex. 1007 at ¶¶ 40, 51, 64-64, 75-76;

IPR2017-01236

40

Ex. 1001 at 4:4-7, 6:29-30, 8:34-43, 9:1-4, 10:38-39.

VIII. REASONS FOR THE RELIEF REQUESTED UNDER 37 C.F.R.§§ 42.22(a)(2) AND 42.104(b)(4) – Ground 1 - Obvious over Thomson inView of Ellsworth and Halliburton

A. It Would Have Been Obvious to Use Thomson in Open Hole

The only differences between Thomson's fracturing method and the method of

the '501 Patent are that Thomson used a cased hole completion instead of an open

hole completion and that Thomson's lower most sliding sleeve cycle plug/shear out

assembly is not expressly disclosed as having ports. Ex. 1007 at ¶¶ 84-85.

Otherwise, the tools and techniques are identical. Id. The following admission by

Patent Owner's expert succinctly illustrates why the cased hole/open hole distinction

is not patentable: “The open hole application of tools that were originally designed

for cased hole has been common place in the industry since I began working in the

industry in 1992. There is nothing novel or nonobvious about such an application.”

Ex. 1012 at ¶¶ 10-11. Indeed, using the Thomson system in open hole would have

been obvious in any formation with sufficient structural integrity to maintain a

circular wellbore without casing, for at least the reasons set forth below. A POSITA

would also have been motivated to substitute Halliburton's pump-open plug for

Thomson's cycle plug to address the plug failure problems noted by Thomson and to

avoid the problems associated with expelling a plug into the wellbore. Ex. 1007 at

¶ 70. In fact, Overbey confirms that a POSITA considering the Thomson system

IPR2017-01236

41

would readily modify it to use a hydraulically actuated sliding sleeve (“bull plug”

port collar) at the toe of the well and a ball-actuated sliding sleeve when seeking to

optimize the Thomson system. Ex. 1034 at 99-102; Ex. 1007 at ¶¶ 44-45.

A POSITA, who would have been familiar with multistage, horizontal, open

hole fracturing, would have been motivated to use Thomson's system without casing

to minimize the time and expense of completing a well. Ex. 1007 at ¶¶ 87, 91; see

also Ex. 1004 at 10 (“[C]ost effective use of horizontals can be enhanced with the

ability to segment, and control production without the need to run and cement

liners.”). For example, the cost of completing and stimulating a well is driven, in

part, by the amount of time and the required materials. Ex. 1007 at ¶¶ 90-91. The

cost of cased wells, which require installing casing and cementing it in place, is an

added expense compared to open wells. Id.; see also Ex. 1003 at 5.

As shown in Sections V and VI, Thomson and Ellsworth also describe known

alternatives (cased and uncased) for well stimulation as of November 19, 2001. Ex.

1007 at ¶¶ 84-91. Also, as explained above, multistage, horizontal, open hole

fracturing was known in the art, including the use of packers and sliding sleeves to

accomplish it. Ex. 1007 at ¶¶ 84-91. Moreover, the use of the same cased hole tools

in open hole wells was known to yield predictable results as both Patent Owner's

experts/inventor (see Section VI.C) and Dr. Rao have opined. Ex. 1007 at ¶¶ 84-91.

Ellsworth confirmed that SBPs, like those used in Thomson's cased hole, worked in

IPR2017-01236

42

open hole wells for stimulation. Ex. 1007 at ¶ 86. Accordingly, the use of

Thomson's system in an uncased well would have been a straightforward task for a

POSITA at that time (Ex. 1007 at ¶¶ 84-91), and would have yielded nothing more

than predictable results (namely, a well that could be selectively fractured (Id.)).

Such an open hole application of Thomson, therefore, would have been obvious,

especially given a POSITA's knowledge about open hole fracturing. KSR Int'l Co. v

Teleflex Inc., 550 U.S. 398, 417 (2007).

Similarly, it was known from Ellsworth that open hole isolation and

stimulation could improve a cased hole system by eliminating the expense of casing.

Ex. 1007 at ¶ 91. Additionally, as shown above, it was well known to a POSITA to

fracture in open hole. Ex. 1007 at ¶ 91. Thus, using the claimed system in open hole

would have been simply applying the known techniques of open hole fracturing and

Ellsworth's open hole isolation and stimulation to a known device (the Thomson

system for fracturing a cased hole), which is ready for improvement to yield

predictable results.

Additionally, it would have been obvious to try the Thomson apparatus in

open hole wells because it represented a choice from a finite number of defined,

predictable solutions for zonal isolation in open hole with more than a reasonable

expectation of success according to Ellsworth, as well as Patent Owner's

experts/inventor and Dr. Rao. Ex. 1007 at ¶¶ 84-91. The claimed invention also

IPR2017-01236

43

would have been obvious because known work in the field of using SBPs and sliding

sleeves for zonal isolation for fracturing in horizontal cased wells (Thomson) could

easily prompt variations for use in the same field, such as use of the same system in

open hole wells based on design incentives or market forces, such as eliminating the

cost of casing. Ex. 1007 at ¶ 91. Such obvious variations are predictable to a

POSITA, as both Patent Owner's experts/inventor and Dr. Rao have opined. Ex.

1007 at ¶ 91.

Finally, as Patent Owner's experts/inventor and Dr. Rao have explained, it was

known to use cased hole tools in open hole and to expect success in competent open

hole wellbores. Ex. 1007 at ¶¶ 84-91. Thus, there existed in the art a teaching,

suggestion, and motivation to use Thomson's hydraulic-set packers and ball-drop

actuated sliding sleeves for the same purposes and to achieve the same results in

open hole. Ex. 1007 at ¶¶ 84-91.

B. Each of Claims 1-9 Would Have Been Obvious Over Thomson inView of Ellsworth and Thomson

Claim element 1[preamble]: “[a] method for fracturing a hydrocarbon-

containing formation accessible through a wellbore.” Thomson discloses a

“completion design that allows multiple acid frac[ture]s to be performed in

horizontal subsea chalk formation wells with a single trip into the wellbore.” Ex.

1003 at 1 (emphasis added); see also id. at 3, 5; Ex. 1007 at ¶ 92. Thomson's subsea

IPR2017-01236

44

chalk formation is an example of a hydrocarbon-containing formation, and it is

accessible through Thomson's wellbore. Ex. 1007 at ¶ 92.

Claim element 1[a]: “running a tubing string into an open hole and

uncased, non-vertical section of the wellbore.” It would have been obvious to use

the Thomson system in an open hole well, as explained in detail in this Section

VIII.A above. As shown and described in Section V.C.1, Thomson's tubing string is

run into a horizontal (i.e., non-vertical) section of the wellbore. See Ex. 1003 at 1

and Fig. 3. As explained above in Section V.B, a POSITA would have been well

aware of multistage, horizontal open hole fracturing methods. As explained above in

Section VI.C, using a system like the Thomson system in an open hole would have

been obvious based on the admissions of Patent Owner's experts and inventor. Dr.

Rao agrees with these repeated admissions that it was well known to use cased hole

tools in a substantially competent open hole well. Ex. 1007 at ¶¶ 93-100. Thus,

using the Thomson system in such an open hole would have achieved predictable

success and would have been a simple substitution. Ex. 1007 at ¶¶ 93-100.

Even setting aside Patent Owner's admissions, it would have been obvious to

use Thomson's system in open hole based on Ellsworth's teachings. Ex. 1007 at

¶¶ 98-100. First, Ellsworth teaches the use of SBPs (like Thomson's) to provide

zonal isolation for stimulation in open hole. Ex. 1007 at ¶¶ 98-100. Second,

Thomson's system includes sliding sleeves, and Ellsworth expressly teaches the use

IPR2017-01236

45

of sliding sleeves (between SBPs) to inject stimulation fluids into an open hole

formation. Id. at ¶¶ 98-100. These same teachings apply to every other element of

claim 1 of the '501 Patent reciting open hole and uncased wells. Id. at ¶¶ 98-100.

Accordingly, based on Ellsworth, a POSITA would know to use the SBPs of

Thomson (and other components, like sliding sleeves) in open hole, which would

have yielded predictable results, namely, fracturing effectively based, in part, on the

zonal isolation created by the open hole SBPs taught by Ellsworth. Id. at ¶¶ 93-100.

It would also have been obvious to substitute the Wizard packers of Ellsworth

for the packers of Thomson to successfully use the Thomson system/method in an

open hole environment. Ex. 1007 at ¶ 98. After explaining that “effective isolation

is possible with these SBP's” in open hole horizontal wells, Ellsworth states,

“[e]ffective isolation in open hole greatly increases the capability to incorporate

horizontal wells into the producing strategy for the Rainbow Lake field.” Ex. 1004

at 5; Ex. 1007 at ¶ 99. Ellsworth also explains, “[t]he ability to establish long-term

zonal isolation in open hole producers opens the door to many new well producing

configurations. The goal of cost effective use of horizontals can be enhanced with

the ability to segment, and control production without the need to run and cement

liners.” Ex. 1004 at 10; Ex. 1007 at ¶ 99. Ellsworth finally notes, “[w]hen designing

a producing installation, minimizing intervention costs is an important

consideration.” Ex. 1004 at 11; Ex. 1007 at ¶ 99. Thus, one of ordinary skill in the

IPR2017-01236

46

art would have been motivated to use the SBPs of Ellsworth with the system and

method of Thomson to avoid the need to case and cement the horizontal section of

the wellbore. Ex.1007 at ¶¶ 93-100. Such a strategy would reduce costs (by

avoiding the need to provide casing and cement and the need to perforate the casing),

which Ellsworth teaches is an important consideration in designing a well. Id.

Claim element 1[b]: “the tubing string having a long axis and an inner

bore.” As shown and described in Section V.C.1 above, particularly annotated

Figure 3, Thomson's tubing string has a long axis and necessarily includes an inner

bore. Ex. 1007 at ¶¶ 101-103; see also Ex. 1003 at Figs. 4 & 5.

Claim element 1[c]: “a first port opened through a wall of the tubing

string.” As described and shown (see annotated and modified Figure 3 and

annotated Figure 5) in Section V.C.1, Thomson's MSAF tool, which forms part of

the tubing string, has ports opened through the tubing string wall as depicted in

Figure 5, which was reproduced above in annotated form. Ex. 1003 at 1-2; Ex. 1007

at ¶¶ 51-53, 104-106. Thus, the sliding sleeve of the 1.75-inch diameter MSAF tool

(labeled as the first sliding sleeve/port in annotated and modified Figure 3 in Section

V.C.1) is movable relative to a first port (contained in the same MSAF tool) in the

string. Ex. 1003 at 3; Ex. 1007 at ¶¶ 51-53, 104. Any MSAF tool in the Thomson

tubing string above the last two packers could be the first port required by claim

IPR2017-01236

47

element 1[c].5 Ex. 1007 at ¶ 104.

Claim element 1[d]: “a second port opened through the tubing string

wall.” As described and shown (see annotated and modified Figure 3 and

annotated Figure 5) in Section V.C.1, Thomson's sliding sleeve of the second

diameter (1.5-inch) MSAF tool (labeled second sliding sleeve/port in annotated and

modified Figure 3 above in Section V.C.1) is movable relative to a second port in

the tubing string. Ex. 1003 at 3; Ex. 1007 at ¶¶ 51-54, 107-109. Also, any MSAF

tool in the Thomson tubing string between second and third packers could be the

second port required by claim element 1[d].6 Ex. 1007 at ¶ 107.

Claim element 1[e]: “the second port downhole from the first port along

the long axis of the tubing string.” Thomson's MSAF tools, and their respective

ports, are spaced or offset from each other along the string's long axis. Ex. 1003 at

1. As annotated in modified Figure 3 above, the second port of the 1.5-inch MSAF

tool is downhole from the first port of the 1.75-inch MSAF tool. Ex. 1007 at

¶¶ 110-112. Also, any of the exemplary second ports can be downhole from the

5 For example, depending on which packers are considered the first and second

packers, any port between those packers could be considered the first port.

6 It will be appreciated that various combinations of MSAF tools in Thomson

can be considered the first and second ports, depending upon which packers are

selected as the first, second, and third packers.

IPR2017-01236

48

exemplary first ports. Ex. 1007 at ¶¶ 110-111.

Claim element 1[f]: “a third port opened through the tubing string wall.”

As noted above, the Halliburton pump-open plug includes ports opened through a

wall of the plug. Ex. 1028 at 93; Ex. 1007 at ¶¶ 69-71, 113-114. Thomson and

Ellsworth teach using a plug at a bottom end of the tubing string to permit the

tubing string to be pressurized so that the packers can be set. Ex. 1003 at 3-4; Ex.

1004 at 5, 7, and 9-10; Ex. 1007 at ¶¶ 113-114; see also Ex. 1034 at 99-102

(explaining how a plug like the Halliburton pump-open plug can be used to set

packers). It would have been obvious to use the Halliburton pump-open plug for

the same purpose as the pump-out and cycle plugs of Thomson, or the pump-out

plug of Ellsworth, since it would have involved a simple substitution of one known

plug for another to obtain predictable results (i.e., pressurization of the tubing string

to set the packers followed by opening of a port to permit fluid communication

between the inner bore and the annulus). Ex. 1007 at ¶¶ 113-114; see also Ex.

1034 at 99-102. In fact, Halliburton discloses that its pump-open plug can be used

“to isolate perforations when run below [a] packer completion assembly.” Ex.

1028 at 93. Furthermore, it would have been obvious to try the Halliburton pump-

open plug in the combination of Thomson and Ellsworth in view of the problems

with pump-out and cycle plugs described by Thomson and the finite number of

defined, predictable solutions for plugging the bottom of a tubing string. Ex. 1003

IPR2017-01236

49

at 3-4; Ex. 1007 at ¶¶ 113-114.

When used in the combination of Thomson and Ellsworth, the Halliburton

pump-open plug forms part of the tubing string and provides a third port opened

through the tubing string wall. Ex. 1007 at ¶ 114.

Claim element 1[g]: “the third port downhole from the second port along

the long axis of the tubing string.” With the Halliburton plug at the bottom of the

tubing string, the third port in the plug is downhole from any of Thomson's

exemplary second ports along the longitudinal axis of the tubing string. Ex. 1007 at

¶ 115.

Claim element 1[h]: “a first sliding sleeve having a seat with a first

diameter, the first sliding sleeve positioned relative to the first port and moveable

relative to the first port between (i) a closed port position wherein fluid can pass

the seat of the first sliding sleeve and flow downhole of the first sliding sleeve and

(ii) an open port position permitting fluid flow through the first port from the

tubing string inner bore and sealing against fluid flow past the seat of the first

sliding sleeve and downhole of the first sliding sleeve.” As described and shown

IPR2017-01236

50

(see modified and further annotated Figure 3, reproduced below and annotated

Figure 5 in Section V.C.1), Thomson discloses ball-actuated sliding sleeves that

teach this element. The sliding sleeve of the 1.75-inch MSAF tool is positioned

relative to the first port and has a seat with a first diameter (1.61-inches). Ex. 1003

at 6, Table 1 (listing ball/seat sizes for MSAF tools). This sliding sleeve is movable

relative to the first port between the claimed closed and open port positions. Id. at

3; Ex. 1007 at ¶¶ 51-53, 116-120. For example, in the closed position shown in the

upper part of Figure 5 of Thomson, ports in the sleeve and the tubing string are not

aligned and fluid can pass through the seat of the sliding sleeve because no ball is

seated; and, when in the open position shown in the lower part of Figure 5, the

ports are aligned to permit fluid flow through the first port from the inner bore and

the ball and seat form a seal against fluid flow past the seat and downhole. Ex.

1003 at 2 (“[t]he ball and seat form a seal”), 10; Ex. 1007 at ¶¶ 116-120.

Thomson Figure 3 (annotated and modified)

IPR2017-01236

51

Ex. 1003 at 10 (annotated Figure 3 of Ex. 1003 has been modified above to show a

section of the up to 9 MSAF tools that can be run in the completion with isolation

of each zone being achieved by hydraulic-set retrievable packers positioned on

each side of an MSAF tool, with the MSAF tool sizes taken from Table 1 (Ex. 1003

at 6, Table 1)).

Also, any of the first ports of Thomson will have a corresponding first sliding

sleeve as required by this claim element because of the design of the MSAF tools

used for the ports. Ex. 1007 at ¶ 116.

Claim element 1[i]: “a second sliding sleeve having a seat with a second

diameter smaller than the first diameter, the second sliding sleeve positioned

relative to the second port and moveable relative to the second port between (i) a

closed port position wherein fluid can pass the seat of the second sliding sleeve

and flow downhole of the second sliding sleeve and (ii) an open port position

permitting fluid flow through the second port from the tubing string inner bore

and sealing against fluid flow past the seat of the second sliding sleeve and

downhole of the second sliding sleeve.” As described and shown (see annotated

and modified Figure 3 on the previous page and annotated Figure 5 in Section

V.C.1), Thomson discloses that the sliding sleeve of the 1.5-inch MSAF tool is

positioned relative to the second port and has a seat with a second diameter (1.36-

inches) that is smaller than the first diameter (1.61-inches) of the 1.75-inch tool.

IPR2017-01236

52

Ex. 1003 at 6, Table 1. And, as with the first sliding sleeve (the 1.75-inch tool), the

1.5-inch tool's sliding sleeve is movable relative to the second port between the

claimed closed and open port positions. See element 1[f]; Ex. 1007 at ¶¶ 51-53,

121-124.

Also, any of the second ports of Thomson will have a corresponding second

sliding sleeve as required by this claim element because of the design of the MSAF

tools used for the ports and the relative ball seat sizes disclosed by Thomson. Ex.

1007 at ¶ 121.

Claim element 1[j][i]: “a first solid body packer mounted on the tubing

string to act in a position uphole from the first port along the long axis of the

tubing string.” Thomson's retrievable packers are described and depicted in

Section V.C.1 and meet the definition of SBP. Ex. 1007 at ¶¶ 54-55, 125-129.

These packers are “hydraulic-set” with “no mandrel movement in relation to the

slips . . . while setting” such that “any number of hydraulic-set packers [can] be set

simultaneously.” Ex. 1003 at 2; Ex. 1007 at ¶ 55. As further shown below in

annotated Figure 3, Thomson's retrievable packer has packing elements extruded by

mechanical force imparted by a hydraulic actuation mechanism (Ex. 1007 at ¶¶ 54-

55, 126):

IPR2017-01236

53

Fig. 3 of Thomson (annotated and zoomed-in)

Ex. 1003 at 10 (Fig. 3).

Once extruded, the packing elements seal the annulus between the tool string

and the casing/borehole. And as previously shown, Thomson's system includes

SBPs on either side of each MSAF tool to seal about the tubing string. Ex. 1003 at

1. As further shown in modified and annotated Figure 3 of Thomson above in

connection with claim element 1[f], the packer between the 2-inch and 1.75-inch

MSAF tools corresponds to the claimed first packer and is uphole from the first port

along the long axis of the tubing string. Also, any packer in the Thomson tool

string uphole from any selected first port could be a first solid body packer as

required by claim element 1[j][i].

Claim element 1[j][ii]: “the first solid body packer operable to seal about

the tubing string and against a wellbore wall in the open hole and uncased, non-

IPR2017-01236

54

vertical section of the wellbore.” See claim elements 1[a]-[b], 1[j][i]. As Dr. Rao

explains and as expressly taught by Ellsworth, a POSITA knew to use SBPs (like

those in Thomson) to seal about the tubing string and against a wellbore wall in the

horizontal open hole and to do so specifically for stimulation treatments. Ex. 1007

at ¶¶ 130-132; see also Ex. 1004 at 3, 5 (“More recently, solid body packers

(SBP’s) . . . have been used to establish open hole isolation. . . . The secondary

consideration is the mechanical sealing of the SBP’s”). In fact, as explained above,

there were numerous reasons why it would have been obvious to use Thomson's

SBPs in open hole for stimulation, including fracturing. Additionally, the

admissions of Patent Owner's experts and inventor further confirm that it was well

known and would have been obvious to use Thomson's packers in open hole, which

would have been “common place” at the relevant time. Ex. 1007 at ¶ 131. Thus, it

would have been obvious to use Thomson's packers to seal about the tubing string

and against a horizontal open hole and uncased wellbore.

Claim element 1[k][i]: “a second solid body packer mounted on the tubing

string to act in a position between the first port and the second port along the

long axis of the tubing string.” See claim element 1[j][i]. As annotated in

modified Figure 3 (e.g., in Section V.C.1), Thomson's SBP between the 1.75-inch

MSAF tool and the 1.5-inch MSAF tool corresponds to the claimed second packer

mounted on the tubing string between the first port and the second port along the

IPR2017-01236

55

long axis of the tubing string. Ex. 1007 at ¶¶ 133-135. Additionally, any packer

in the Thomson tool string between any selected first port and any selected second

port could be a second solid body packer as required by claim element 1[k][i]. Ex.

1007 at ¶ 133.

Claim element 1[k][ii]: “the second solid body packer operable to seal

about the tubing string and against the wellbore wall in the open hole and

uncased, non-vertical section of the wellbore.” See claim elements 1[a]-[b], 1[h],

1[j][ii], and 1[k][i]; see also Ex. 1007 at ¶¶ 136-137. For at least the same reasons

as for the first solid body packer, it would have been obvious to use Thomson's

second SBP to seal about the tubing string and against a horizontal open hole and

uncased wellbore. Ex. 1007 at ¶¶ 136-137.

Claim element 1[l][i]: “a third solid body packer mounted on the tubing

string to act in a position offset from the second port along the long axis of the

tubing string and on a side of the second port opposite the second solid body

packer.” See elements 1[a]-[b], 1[j][i]-[ii], 1[k][i]-[ii]. As annotated in modified

Figure 3, Thomson's SBP between the 1.5-inch MSAF tool and the “cycle

plug/shear out sub” corresponds to the claimed third packer. Ex. 1007 at ¶¶ 138-

140. Additionally, any packer in the Thomson tool string downhole from any

selected second port could be a third solid body packer as required by claim

element 1[l][i]. Ex. 1007 at ¶¶ 138-140.

IPR2017-01236

56

Claim element 1[l][ii]: “the third solid body packer operable to seal about

the tubing string and against the wellbore wall in the open hole and uncased,

non-vertical section of the wellbore.” See claim elements 1[a]-[b], 1[j][i]-[ii],

1[k][i]-[ii], 1[l][i]; see also Ex. 1007 at ¶¶ 141-142. For at least the same reasons as

the first and second solid body packers, it would have been obvious to use

Thomson's third SBP to seal about the tubing string and against a horizontal open

hole wellbore. Ex. 1007 at ¶¶ 141-142.

Claim element 1[m][i]: “a hydraulically actuated sliding sleeve in a

position offset from the third solid body packer along the long axis of the tubing

string on a side of the third solid body packer opposite the second port.” As noted

above, the Halliburton pump-open plug includes a pump open valve, which is an

example of a hydraulically actuated sliding sleeve. Ex. 1028 at 93; Ex. 1007 at

¶¶ 69-71, 143-144. When used in the combination of Thomson and Ellsworth, the

Halliburton pump-open plug would have been located at the bottom of the tubing

string, below the packers like the plugs disclosed in Thomson and Ellsworth. Ex.

1007 at ¶ 144. Thus, the hydraulically actuated sliding sleeve in the Halliburton

pump-open plug would have been in a position offset from the third solid body

packer along the long axis of the tubing string. Ex. 1007 at ¶ 144. Since, as noted

above, the exemplary second port of Thomson would have been uphole from the

third solid body packer, and the Halliburton pump-open plug would have been

IPR2017-01236

57

downhole of the third solid body packer, the hydraulically actuated sliding sleeve in

the Halliburton plug would also have been on a side of the third solid body packer

opposite the second port. Ex. 1007 at ¶ 144.

Claim element 1[m][ii]: “the hydraulically actuated sliding sleeve being

positioned relative to the third port and moveable relative to the third port

between (i) a closed port position in which the hydraulically actuated sliding

sleeve covers the third port and (ii) an open port position in which the

hydraulically actuated sliding sleeve exposes the third port to the tubing string

inner bore to permit fluid flow through the third port from the tubing string inner

bore.” As shown in the annotated and modified figures in Section V.C.3 above, the

pump open valve (i.e., hydraulically actuated sliding sleeve) of Halliburton's pump-

open plug is positioned relative to the flow port (i.e., the third port), and is

moveable relative to the third port between (i) a closed port position in which the

hydraulically actuated sliding sleeve covers the third port and (ii) an open port

position in which the hydraulically actuated sliding sleeve exposes the third port to

the tubing string inner bore to permit fluid flow through the third port from the

tubing string inner bore. Ex. 1007 at ¶ 145.

Claim element 1[n]: “wherein the tubing string is run into the wellbore

with the first, second, and third solid body packers each in an unset position.”

All of the Thomson SBPs are run into the wellbore in the unset position. Ex. 1003

IPR2017-01236

58

at 2-3 (“The completion was run in one trip to the safety valve, and the packers

were set simultaneously….”); Ex. 1007 at ¶¶ 146-148. Ellsworth also teaches that

the SBPs are run into a wellbore in the unset position. Ex. 1004 at 5 (“The

assembly was run into the well, and tubing pressure was applied to selectively set

all of the open hole packers.”); Ex. 1007 at ¶ 147. It would also have been obvious

to run the tubing string into the wellbore with the packer in an unset position to

avoid damaging the packers and to allow the tubing string to be run into the

wellbore. Ex. 1007 at ¶¶ 146-148. When Thomson's packers are run in an unset

position, the annular space between the tubing string and the wellbore wall remains

open. Ex. 1007 at ¶ 147.

Claim element 1[o][i]: “expanding radially outward the first, second, and

third solid body packers until each of the first, second, and third solid body

packers sets and seals against the wellbore wall in the open hole and uncased,

non-vertical section of the wellbore.” See claim elements 1[j][i]-[ii], 1[k][i]-[ii],

and 1[l][i]-[ii]. As shown in Thomson's modified and annotated Figure 3 above in

connection with claim element 1[j][i], each SBP is set and seals against the

casing/wellbore wall through radial expansion. Ex. 1003 at 3; Ex. 1007 at ¶¶ 149-

154. For the numerous reasons set forth above, including the teachings of

Ellsworth to use SBPs in open hole and the admissions of Patent Owner's experts

and inventor, it would have been obvious to set Thomson's packers in an open hole

IPR2017-01236

59

and uncased section of the wellbore so they seal. Ex. 1007 at ¶¶ 149-154.

Claim element 1[o][ii]: “wherein the first, second, and third solid body

packers, when expanded, secure the tubing string in place in the wellbore and

create a first annular wellbore segment between the first and second solid body

packers, a second annular wellbore segment between the second and third solid

body packers, and a third annular wellbore segment downhole of the third solid

body packer.” As annotated in modified Figure 3, the Thomson first, second, and

third packers, when expanded, secure the tubing string in place in the wellbore and

create first, second, and third annular wellbore segments, in which the third annular

wellbore segment is downhole of the third solid body packer. See claim elements

1[j][i]-[ii], 1[k][i]-[ii], 1[l][i]-[ii], and 1[o][i]; Ex. 1007 at ¶¶ 155-161.

The limitation “secure the tubing string in place in the wellbore” lacks

written description support, and thus, has an uncertain scope. To the extent the

limitation is given any meaning based on the dual-element packers in the

specification of the '501 Patent, the packers in Ellsworth and/or Thomson provide

as much securing as those packers, or even more in the case of Thomson where the

packers have slips. Ex. 1007 at ¶¶ 54-55, 64-65.

Claim element 1[o][iii]: “wherein the first annular wellbore segment is

substantially isolated from fluid communication with the second annular

wellbore segment by the second solid body packer, wherein the second annular

IPR2017-01236

60

wellbore segment is substantially isolated from fluid communication with the

third wellbore segment by the third solid body packer.” As shown in annotated

and modified Figure 3, Thomson's second SBP isolates the first annular wellbore

segment from fluid communication with the second annular wellbore segment, and

Thomson's third SBP isolates the second annular wellbore segment from fluid

communication with the third annular wellbore segment. Ex. 1003 at 3; Ex. 1007

at ¶¶ 162-163. Additionally, as shown in annotated Figure 11 and explained in

elements 1[j][i]-[ii], 1[k][i]-[ii] and 1[l][i]-[ii], Ellsworth teaches that a second SBP

isolates the first and second annular segments, and a third SBP isolates the second

and the third annular segments, respectively. See also, e.g., Ex. 1004 at 10 (“The

build section of the well was segmented into two separate intervals using two

SBP's.”); Ex. 1007 at ¶ 64.

Claim element 1[o][iv]: “wherein the first, second, and third annular

wellbore segments provide access to the hydrocarbon-containing formation along

the wellbore wall in the open hole and uncased, non-vertical section of the

wellbore.” For the numerous reasons discussed above, including the teachings of

Ellsworth (e.g., in Section V.C.2) and the admissions of Patent Owner's experts and

inventor (e.g., in Section VI.C), it would have been obvious to run Thomson's

tubing string into a horizontal open hole and uncased wellbore that provides access

to the hydrocarbon-containing formation. Ex. 1007 at ¶¶ 164-167.

IPR2017-01236

61

Claim element 1[p]: “applying a first pressure within the tubing string

inner bore such that the hydraulically actuated sliding sleeve moves from the

closed port position to the open port position without the hydraulically actuated

sliding sleeve engaging any fluid conveyed sealing device.” As explained above

in Section V.C.3, the pump open valve (i.e., hydraulically actuated sliding sleeve)

of Halliburton's pump-open plug is moved from the closed port position shown in

the annotated figure to the open port position shown in the modified figure by

applying a first pressure within the tubing string inner bore and without engaging

any fluid conveyed sealing device. See also Ex. 1007 at ¶ 168; and Ex. 1034 at 99-

102.

Claim element 1[q]: “conveying a fluid conveyed sealing device through

the tubing string to pass through the first sliding sleeve and to land in and seal

against the seat of the second sliding sleeve thereby moving the second sliding

sleeve to the open port position and permitting fluid flow through the second

port.” Thomson discloses actuating sliding sleeves by conveying a ball, which

constitutes a “fluid conveyed sealing device.” Ex. 1007 at ¶ 169. As shown in

annotated and modified Figure 3 and annotated Figure 5 above, the second 1.5-inch

MSAF tool includes a 1.36-inch seat sized to receive and be sealed by a 1.5-inch

ball to move the second sliding sleeve from the closed port position to the open

position. Ex. 1003 at 1-3 and 6 (Table 1); Ex. 1007 at ¶¶ 169-170. The 1.5-inch

IPR2017-01236

62

ball is smaller than the 1.61-inch seat of the first MSAF tool and thus passes

through it on its way to mate with the second MSAF tool's seat. Ex. 1003 at 6

(Table 1); Ex. 1007 at ¶¶ 169-170. The same would be true of any other exemplary

second sliding sleeve chosen on Thomson's tubing string because the ball seats

decrease in size when moving downhole on the tubing string as Thomson shows in

Table 1. Ex. 1007 at ¶¶ 169-170

Claim element 1[r]: “pumping fracturing fluid through the second port

and into the second annular wellbore segment to fracture the hydrocarbon-

containing formation.” Stimulation (acid fracturing) of Thomson's second annular

segment occurs once the sleeve of the 1.5-inch MSAF tool is moved to the open

position. Ex. 1003 at 3 (referencing selective opening of ports “until all zones had

been stimulated”); see also claim element 1[m]; Ex. 1007 at ¶ 171. Stimulation of

the well results from fracturing the hydrocarbon-containing formation. Ex. 1003 at

1 (referencing “multiple acid frac[ture]s”); Ex. 1007 at ¶ 171.

Claim 2: “method of claim 1, wherein each of the first, second, and third

solid body packers is a hydraulically actuated packer, and wherein the expanding

radially outward each of the first, second, and third solid body packers comprises,

before moving the hydraulically actuated sliding sleeve to the open port position,

applying a packer setting pressure within the tubing string inner bore to actuate

each of the first, second, and third solid body packers.” See claim elements 1[f],

IPR2017-01236

63

1[j][i], 1[k][i] and 1[l][i]. As noted above in Sections V.C.2 and V.C.1, the SBPs of

Ellsworth and Thomson are hydraulically set, which causes radial expansion of the

packing elements. Ex. 1004 at 5; Ex. 1003 at 2; Ex. 1007 at ¶¶ 173-175.

As also noted above, Thomson and Ellsworth both teach pressurizing the

tubing string against a plug to set the packers. Ex. 1003 at 3; Ex. 1004 at 5.

Thomson further teaches expelling the plug to stimulate the lower zone of the

wellbore after the packers are set. Ex. 1003 at 3. Because the original pump-out

plug described by Thomson was a “conventional shear-out shoe” that simply

expends by the application of tubing pressure, Thomson disclosed that the packer

setting pressure was below the pump-out plug actuation pressure because “the pump

out plug failed during the packer setting procedure, (luckily just after the packers

were set) . . . .” Ex. 1003 at 3. If the pump-out plug were set to expel at the packer

setting pressure or below, Thomson could not have viewed its expulsion just after

setting the packers as a failure. Ex. 1007 at ¶ 173. Moreover, a POSITA would

have known to configure the plug to expel at a pressure higher than the packer

setting pressure because, otherwise, the plug would be expelled too early and the

tubing string could not be pressurized to the set the packers. Ex. 1003 at 4 (“If the

plug expends early, the packers cannot be set . . .”); Ex. 1007 at ¶ 173. For the

same reason, it would have been obvious to configure Halliburton's pump-open

plug so that the hydraulically actuated sliding sleeve does not move until after the

IPR2017-01236

64

packers are set. Ex. 1007 at ¶ 173; see also Ex. 1034 at 99-102; and Ex. 1036 at

4:33-5:58.

Claim 3: “method of claim 2, wherein the first pressure used to actuate the

hydraulically actuated sliding sleeve is greater than the packer setting pressure.”

See Claim 2. A POSITA would have known to configure the pump open valve

(i.e., hydraulically actuated sliding sleeve) in Halliburton's pump-open plug to

actuate (i.e., move from the closed port position to the open port position) at a

pressure higher than the packer setting pressure because, otherwise, the plug's port

would open too early and the tube could not be pressurized to set the packers. Ex.

1003 at 4 (“If the plug expends early, the packers cannot be set . . .”); Ex. 1007 at

¶¶ 176-178; see also Ex. 1034 at 99-102 (explaining how a plug like the Halliburton

plug can be used to set packers before moving to an open port position); and 1036

at 4:33-5:58.

Claim 4: “method of claim 1, wherein the hydraulically actuated sliding

sleeve comprises a fluid actuated piston.” As noted above in Section V.C.3, the

pump open valve in Halliburton's pump-open plug is an example of a hydraulically

actuated sliding sleeve. As shown in the annotated and modified figures in Section

V.C.3, the valve comprises a cylindrical structure with a closed bottom that is an

example of a fluid actuated piston because it is moveable under the influence of a

fluid pressure differential on opposite sides of the valve. Ex. 1007 at ¶¶ 179-181.

IPR2017-01236

65

Claim 5: “method of claim 4, wherein the fluid actuated piston is secured

by a shear pin having a shear threshold.” See claim 4. The pump open valve in

Halliburton's pump-open plug is secured by release pins, each of which is an

example of a shear pin. Ex. 1028 at 93; Ex. 1007 at ¶¶ 182-184. A POSITA

would have known that the release pins have a shear threshold above which the

pump open valve is released to move because otherwise the valve would move

prematurely, exposing the flow ports and preventing the packers from being set.

Ex. 1003 at 4 (“If the plug expends early, the packers cannot be set . . .”); Ex.

1007 at ¶¶ 182-184; see also Ex 1035 at 6:31-48, and 6:49-60; Ex. 1036 at

abstract, 2:62 – 3:3, 3:52-57, 4:53-63, and Figs. 1-4; Ex. 1037 at abstract, 3:20-23,

4:29-33, 4:54-60, and Fig. 2 (explaining how hydraulically actuated sliding

sleeves may include shear pins having a shear threshold).

Claim 6: “method of claim 5, wherein the applying the first pressure is

sufficient to establish a force exerted on the shear pin that exceeds the shear

threshold of the shear pin.” See claim 5. A POSITA would have known that the

first pressure to move the pump open valve in Halliburton's pump-open plug would

be sufficient to establish a force exerted on the shear pin that exceeds the shear

threshold of the shear pin because, otherwise, the valve could not be moved from

the closed port position shown in the annotated figure in Section V.C.3. Ex. 1007

at ¶¶ 185-187; see also Ex 1035 at 6:31-48, and 6:49-60; Ex. 1036 at abstract, 2:62

IPR2017-01236

66

– 3:3, 3:52-57, 4:53-63, and Figs. 1-4; Ex. 1037 at abstract, 3:20-23, 4:29-33, 4:54-

60, and Fig. 2 (explaining how hydraulically actuated sliding sleeves may include

shear pins having a shear threshold).

Claim 7: “method of claim 1, further comprising, after the hydraulically

actuated sliding sleeve is moved from the closed port position to the open port

position, pumping fracturing fluid through the third port and into the third

annular wellbore segment to fracture the hydrocarbon-containing formation.”

See claim elements 1[f], 1[g], 1[m][i], and 1[m][ii]. Thomson discloses pumping

fracturing fluid through each of the ports. Stimulation of the formation in Thomson

begins with the lowest zone (i.e., third annular wellbore segment) once the plug is

expelled. Ex. 1003 at 3 (“[S]timulation of the lowest zone (below the bottom

packer) was carried out.”), 4 (“Once all ten zones had been individually stimulated,

all nine balls were flowed back to surface where they were caught in a special ball

catcher.”). Ellsworth also describes stimulating out the lowest zone of the well

through the pump-out plug once the plug is expelled. Ex. 1004 at 10. With

Halliburton's pump-open plug substituted for Thomson's and Ellsworth's plugs at

the lower end of the tubing string below the third packer, a POSITA would

understand that fracturing fluid would be pumped through the third port in the plug

and into the lowest (i.e., third) wellbore segment after the hydraulically actuated

sliding sleeve in the plug is moved from the closed port position to the open port

IPR2017-01236

67

position as expressly taught by Thomson. Ex. 1007 at ¶¶ 188-190. It would have

been obvious to pump fracturing fluid through the third port to fracture the

hydrocarbon-containing formation. Id.

Claim element 8: “method of claim 1, wherein the fluid conveyed sealing

device comprises a ball.” In Thomson, the first sleeve of the 1.5-inch MSAF tool is

moved by a 1.5-inch ball, which is an example of a fluid-conveyed sealing device.

Ex. 1007 at ¶¶ 191-193. In fact, every MSAF tool in Thomson is actuated by a fluid

conveyed sealing device that is a ball. Id.

Claim element 9: “method of claim 1, wherein the third port is proximate

to a lower end of the tubing string.” As noted above in Sections V.C.1 and V.C.2,

Thomson and Ellsworth disclose using a plug at the lower end of the tubing string

to allow the tubing string to be pressurized. It would have been obvious to

substitute Halliburton's pump-open plug for Thomson's and Ellsworth's plugs. Ex.

1007 at ¶¶ 194-196. Thus, the third port defined by Halliburton's pump-open plug

would have been proximate to a lower end of the tubing string. Id.

IPR2017-01236

68

IX. CONCLUSION

Accordingly, there is a reasonable likelihood that all of the Challenged Claims

are unpatentable and thus this Petition for inter partes review of the '501 Patent

should be granted.

Dated: April 4, 2017 Respectfully submitted,

/Jason Shapiro/Jason Shapiro

Counsel for Petitioners

IPR2017-01236

69

CERTIFICATE OF SERVICE

I certify that the foregoing Power of Attorney, Petition to Institute an

Inter Partes Review for U.S. Patent No. 9,303,501 under 35 U.S.C. § 312 and

accompanying EXHIBITS were served April 4, 2017 by Priority Mail Express or

equivalent on the following:

MICHAEL BAYSTERNE, KESSLER, GOLDSTEIN & FOX PLLC1100 NEW YORK AVENUE, N.W.WASHINGTON, D.C. 20005-3934

Courtesy copies have been sent via email to the following counsel of record

in the related proceedings before the office:

HAMAD M. HAMADBRADLEY W. CALDWELL

JUSTIN NEMUNAITISCALDWELL CASSADY CURRY P.C.

hhamad@caldwellcc.combcaldwell@caldwellcc.com

jnemunaitis@caldwellcc.com

DR. GREGORY J. GONSALVESGONSALVES LAW FIRM

gonsalves@gonsalveslawfirm.com

Dated: April 4, 2017 Respectfully submitted:EDELL, SHAPIRO & FINNAN, LLC /Jason Shapiro/9801 Washingtonian Blvd., Suite 750 Jason Shapiro, Reg. No. 35,354Gaithersburg, MD 20878 Counsel for Petitioners

Telephone: 301.424.3640Customer No. 27896

IPR2017-01236

70

CERTIFICATION OF WORD COUNT

I hereby certify that this petition conforms with the word count limits of 37

C.F.R. § 42.24(a)(i). This brief contains 13,458 words, excluding the parts of the

petition exempted by 37 C.F.R. § 42.24(a), as calculated using Microsoft Word

2010.

The undersigned further certifies that this petition complies with the

requirements of 37 C.F.R. § 42.6. This brief has been prepared in a proportionally

spaced typeface using Microsoft Word 2010 in Times New Roman 14 point font.

Dated: April 4, 2017 Respectfully submitted:EDELL, SHAPIRO & FINNAN, LLC /Jason Shapiro/9801 Washingtonian Blvd., Suite 750 Jason Shapiro, Reg. No. 35,354Gaithersburg, MD 20878 Counsel for Petitioners

Telephone: 301.424.3640Customer No. 27896