united states patent and trademark …€™s chemical research and development section. ......

$: UNITED STATES PATENT AND TRADEMARK …€™s Chemical Research and Development section. ... cementing, water control, drilling fluids, fracturing, and material issues related to completion$
UNITED STATES PATENT AND TRADEMARK OFFICE

________________________________

BEFORE THE PATENT TRIAL AND APPEAL BOARD

________________________________

HALLIBURTON ENERGY SERVICES, INC.,PETITIONER,

v.

SCHLUMBERGER TECHNOLOGY CORPORATION,

PATENT OWNER.

________________________________

CASE IPR2017-01568PATENT 8,167,043

________________________________

DECLARATION OF BRADLEY LEON TODD UNDER 37C.F.R. § 1.68 IN SUPPORT OF PETITION FOR INTER

PARTES REVIEW OF U.S. PATENT NO. 8,167,043

Page 1 of 65 Halliburton Energy Services, Inc.Exhibit 1002

TABLE OF CONTENTS

I. Introduction......................................................................................................2

II. Background Qualifications ..............................................................................5

III. Understanding of Patent Law ........................................................................11

IV. Level of Ordinary Skill in the Pertinent Art..................................................13

V. The ‘043 Patent..............................................................................................15

VI. Background on State of Technology in the Field of the Invention ...............16

VII. Background on the Prior Art References.......................................................28

VIII. Broadest Reasonable Interpretation...............................................................32

IX. The Challenged Claims are Unpatentable .....................................................33

X. Conclusion .....................................................................................................64


I. Introduction

I, Bradley Leon Todd, declare as follows:

1. I have been retained on behalf of Halliburton Energy Services, Inc.

(“Petitioner” or “Halliburton”) to provide expert opinions in connection with

an inter partes review (“IPR”) of U.S. Patent No. 8,167,043 (“the ‘043

patent”).

2. I am over 18 years of age. I have personal knowledge of the facts and opinions

stated in this Declaration and could testify competently to them if asked to do

so.

3. I am being compensated for my time in connection with this IPR at my

standard consulting rate of $300 per hour. My compensation is not dependent

upon the opinions that I am providing in this declaration. While I own some

stock in Petitioner’s parent company, Halliburton Corporation, that stock does

not represent a substantial portion of my net worth, nor do I expect the

outcome of this proceeding to have any impact on my finances.

4. I have been asked to provide my opinions regarding whether claims 1-4, 6, 7,

13, 15, and 25-27 of the ‘043 patent (“the Challenged Claims”) are invalid as

anticipated or obvious to a person having ordinary skill in the art at the time of

the alleged invention. As indicated below, it is my opinion that a person


having ordinary skill in the art at the time of the alleged invention would find

all of these claims to be anticipated or rendered obvious.

5. The ‘043 patent was filed on August 8, 2008 as U.S. Application No.

12/126,501 and indicates that it is a division of U.S. Application No.

11/294,983, which was filed December 5, 2005.

6. For the purposes of this Declaration, I have been asked to assume that the date

of the alleged invention recited in the ‘043 patent is December 5, 2005, which

is the date U.S. Application No. 11/294,983 was filed. However, my opinions

that one of skill in the art would find claims 1-4, 6, 7, 13, 15, and 25-27 to be

rendered obvious would remain the same even if the date of the alleged

invention were later, including up to August 8, 2008, which is the date the

‘043 patent was filed.

7. The face of the ‘043 patent names Dean Willberg, Marina Bulova,

Christopher Fredd, Alexey Vostrukhov, Curtis Boney, John Lassek, Ann

Hoefer, and Philip Sullivan as the inventors for the ‘043 patent, and identifies

Schlumberger Technology Corporation as the named assignee.

8. In preparing this Declaration, my opinion is based, at least in part, on

reviewing the following documents, which I understand will be given the

exhibit numbers referenced below in this Proceeding:


Reference Exhibit # Name

U.S. Patent No. 7,775,278 1001 “ ‘278 patent”

Partial Prosecution File History of ‘278

patent1007 “ ‘278 File History”

U.S. Patent No. 4,716,964 to Erbstoesser 1004 “Erbstoesser”

U.S. Patent No. 3,353,604 to Gibson 1006 Gibson

White, Garland, “The Use of Temporary

Blocking Agents in Fracturing and

Acidizing Operations,” BJ Services

Spring Meeting of the Pacific Coast

District, Division of Production, Los

Angeles, CA, May 1958

1008 White

Harrison, N.W., “Diverting Agents –

History and Application,” Society of

Petroleum Engineers (SPE) Paper #

3653, May, 1972

1009 “Harrison”

“New ‘beads’ help acidizing, fracturing,”

The Oil and Gas Journal, August 30,

1965

1012 “Unibeads Article”

Gruesbeck, C., et al., “Particle Transport

Through Perforations,” Society of

Petroleum Engineers Journal, December

1982

1013 “Gruesbeck”

U.S. Application Pub. No. 2004/0152601

to Still.

1015“Still”


J. Frederic Walker, Formaldehyde, 2nd

Ed., Reinhold Publishing Corporation.

1016“Walker”

II. Background Qualifications

9. I am a mechanical engineer with over 35 years of experience in the oil and gas

industry. I received a BS in mechanical engineering from Oklahoma State

University in 1981. Attached to this declaration is a copy of my CV. See Ex.

1003.

10. From 1981 to 1986, I worked in the Instrumentation and Controls group and

in the Heavy Equipment group at Halliburton’s Duncan Technology Center

(DTC), in the Mechanical Research and Development (MRD) Section. At the

time, there were two main sections at DTC, Chemical Research and

Development (CRD) and MRD. MRD was made up of three groups, the

Instrumentation and Control Group, the Heavy Equipment Group, and the

Pump Group.

11. The Instrumentation and Controls Group dealt with sensors for pressure,

temperature, liquid flow rate, mass flow rate, viscosity, density, pH, proppant

concentration, as well as liquid and powder additive systems, engine and

pump controls, data recording and transmission, display screens and devices,

digital-to-analog conversion (and vice versa), proportional-integral-derivative

(PID) controllers, and the like.


12. The Heavy Equipment group worked on the design of pump trucks and skids,

blenders, manifolding, power trains, hydraulics, and bulk handling equipment.

13. The Pump Group worked on the design of high pressure fracturing and

cementing pumps as well as the low pressure transfer pumps (centrifugal

pumps).

14. Depending on the project, it was very common to work on product

development efforts that straddled one or more groups, or one or more

sections. For example, an engineer in the Instrumentation and Control Group

may be working on an additive pump for cementing that was timed off of the

pump input shaft. A project like this would require interfacing with CRD

regarding the liquid additive to be metered, such as viscosity, vapor pressure,

corrosiveness, etc. As well, it would likely be necessary to interface with the

Pump Group about input shaft rpm, pump displacement, suction manifold

pressure, etc.

15. During my period in the Instrumentation and Control Group, I worked on a

variety of projects. These included pressure sensors, densometers, flow

meters, metering skids, data recording, pump and engine controls, dry-

additive feeders, mass flow measurement, and data recording vans. These

projects involved applying engineering principles to slurry calculations, slurry

transport, hydraulic horsepower, friction calculation, orifice and nozzle flow,


fluid rheology, material science, stress calculations, electronic signaling and

transfer, and mathematical modeling.

16. During my time in the Heavy Equipment group, opportunities arose to work

on projects involving pump and blender skids/trailers, bulk storage equipment,

manifolding equipment, marine equipment, hydraulic power packs, lifting

equipment and cement handling equipment. These projects allowed the

application of stress calculations, hydraulic flow calculations, pneumatic

conveyance, pipe flow, and introduction into marine architecture calculations

(center of buoyancy, righting moment, etc.).

17. In late 1986, I became involved in a large project with Halliburton to deploy a

spread of equipment to Nigeria, where I obtained substantial experience

working in the field. My field engineering assignments included cementing,

acidizing, sand control, well testing, nitrogen/coil tubing, brine filtration, and

tool services, in addition to the lab responsibilities.

18. As a field engineer I was required to overcome many real world obstacles

through my knowledge of applied chemistry including viscosifying agents,

acid types and reactions, corrosion inhibitors, scale inhibitors, solvents for

wax, brines, surfactants, pH buffers, ion exchange, and all of the chemical

aspects of the formation rock and formation fluids.


19. During the next decade, the majority of my work was spent on international

assignments involving field work. This work required me to continue to

expand my knowledge of chemistry through practical experience, additional

education, and engaging with chemists at Halliburton on issues that arose. I

ultimately established a small chemistry lab at Halliburton’s Port Harcourt

base in Nigeria to assist in my field work.

20. In the 1990s, I worked with Halliburton’s sister company, Otis Engineering

as Regional Technology Advisor for their newly consolidated sand control

services. I was based in Singapore and had responsibility for the Asia/Pacific

and Middle East regions. During this period, I oversaw the deployment of

sand control technology involving gravel packing of vertical or horizontal

wells, as well as services like acid prepacking and hydraulic fracturing.

21. In 1997, I took a position in Duncan, Oklahoma as a Technical Advisor in

Halliburton’s Chemical Research and Development section. During this time,

my work included sand control, acidizing, cementing, water control, drilling

fluids, fracturing, and material issues related to completion tools.

22. Around 2000, I began working on degradable materials, first for sand control

issues, and then on applying them as diverters in fracturing and acidizing

operations. Using degradable materials for sand control and fracturing relies

on the same basic principle of bridging an opening using appropriately sized


particles. From 2000-2010, a substantial portion of my work involved the

research and development of diverter products, including degradable diverting

agents.

23. I left Halliburton in 2012 when the Technology Center moved from Duncan,

Oklahoma to Houston, Texas. At this time, I started Completion Science LLC

to provide material science solutions for well completion applications. At

Completion Science, I oversee a team of engineers and chemists. Our work

focuses on any material science needs for well completion, including

degradable diverting agents and degradable tools.

24. In addition to my practical experience, I have authored or co-authored

numerous oil and gas papers and have been listed as an inventor on many

patents involving the oil and gas field. A selection of these papers and patents

are presented below. A more complete listing can be found in my CV. See Ex.

1003.

Papers

• SPE 39593, “Current Materials and Devices for Control of Fluid Loss,”

published in 1998.

• SPE 86494, “An Innovative System for Complete Cleanup of a Drill-In Fluid

Filter Cake,” published in 2004.


• SPE 102606, “Design and Field Testing of a Truly Novel Diverting Agent,”

published in 2006.

• SPE 149221, “Restim of Wells using Biodegradable Particulates as

Temporary Diverting Agents,” published in 2011.

• SPE 143147, “Fracture-Width Estimation for an Arbitrary Pressure

Distribution in Porous Media,” published 2011.

Patents

• U.S. Patent No. 6,209,646, “Controlling the release of chemical additives in

well treating fluids,” filed April 21, 1999.

• U.S. Patent No. 6,896,058, “Methods of introducing treating fluids into

subterranean producing zones,” filed October 22, 2002.

• U.S. Patent No. 6,971,448, “Methods and compositions for sealing

subterranean zones,” filed February 26, 2003.

• U.S. Patent No. 7,267,170, “Self-degrading fibers and associated methods of

use and manufacture,” filed on January 31, 2005.

• U.S. Patent No. 8,074,715, “Methods of setting particulate plugs in horizontal

well bores using low-rate slurries,” filed on January 15, 2009.

• U.S. Patent No. 8,67,612, “Increasing fracture complexity in ultra-low

permeable subterranean formation using degradable particulate,” filed on

January 15, 2011.


25. Other details concerning my background, professional service, and more, are

set forth in my curriculum vitae. See Ex. 1003.

26. In forming my opinion expressed in this report, I relied on my knowledge,

skill, training, education, and over thirty years of professional experience in

the oil and gas industry.

III. Understanding of Patent Law

27. I am not an attorney, though I have been provided with an understanding of

patent law sufficient to conduct the analysis given in this report. The

following represents my understanding of these issues.

28. A patent or printed publication with a filing date that predates December 5,

2005 is considered to be prior art.

29. A claim of a patent is invalid or unpatentable if that claim is either anticipated

or obvious in view of prior art.

30. I understand that in order to show anticipation of a claim, every element of a

claim must be disclosed expressly or inherently in a single prior art reference,

and arranged in the prior art reference as arranged in the claim. I understand

that, in order to show obviousness of a claim, the claim must be obvious from

the perspective of a person having ordinary skill in the relevant art at the time

the alleged invention was made. I understand that a claim may be obvious in


view of a single reference, or may be obvious from a combination of two or

more prior art references.

31. Obviousness, as I understand, can be established by (for example): combining

prior art elements according to known methods to yield predictable results;

simple substitution of one known element for another to obtain predictable

results; use of known techniques to improve similar devices in the same way;

applying a known technique to a known device ready for improvement to

yield predictable results; choosing from a limited number of identifiable,

predictable solutions with a reasonable expectation of success; known work in

one field of endeavor prompting variations of it for use in either the same field

or a different one based on design incentives or other market forces if the

variations are predictable to one of ordinary skill; or some teaching,

suggestion or motivation in the prior art that would have led one of ordinary

skill to modify the prior art reference or to combine prior art reference

teachings to arrive at the claimed invention.

32. I understand that the obviousness analysis need not seek out precise teachings

directed to the specific subject matter of the challenged claims, but can take

into account ordinary innovation and experimentation, and that one of skill in

the art is a person of ordinary creativity and is not an automaton.


33. Additionally, I understand that analysis of obviousness should not be done in

hindsight, but must be done using the perspective of one of ordinary skill in

the art at the time of the invention.

34. I also understand than an invention that might otherwise be considered

obvious may be considered non-obvious if one or more of the prior art

references provides a clear indication that it discourages or leads away from a

particular combination or modification.

35. Finally, I understand that the burden of proof applied in this proceeding is the

“preponderance of evidence” standard. I understand that this means that

obviousness must be proven to be “more likely than not” in view of the

evidence.

36. I have applied these standards as I understand them to my evaluation of

whether the claims of the ‘043 patent would have been obvious over the prior

art.

IV. Level of Ordinary Skill in the Pertinent Art

37. I understand that a “person of ordinary skill in the art” is a hypothetical person

who is presumed to have known the relevant art at the time of the invention. I

further understand that the relevant timeframe for assessing the ‘043 patent for

purposes of this declaration is prior to December 5, 2005. If I refer to the time

of the invention in this declaration, I am referring to this timeframe.


38. I have been advised that there are multiple factors relevant to determining the

level of ordinary skill in the pertinent art, including the educational level of

active workers in the field at the time of the alleged invention, the

sophistication of the technology, the type of problems encountered in the art,

and the prior art solutions to those problems.

39. The Challenged Claims pertain to a method of treating a well using a

degradable material as a temporary plugging agent.

40. It is my opinion that a person of ordinary skill in the art at the time of the

invention was typically a person who had at least a bachelor’s degree in

petroleum, mechanical, or chemical engineering, or three or more years of

experience using degradable materials with well treatments. I am directly

familiar with the capabilities of such persons of ordinary skill in the art

because I supervised and worked with such persons at the time of the

invention. At the time of the invention, I had at least this level of skill in the

art, having a B.S. in mechanical engineering and over 20 years of experience.

41. In forming the opinions expressed in this Declaration, I relied upon my

education and experience in the relevant field of the art, and have considered

the viewpoint of a person having ordinary skill in the relevant art, as of the

time of the invention.


V. The ‘043 Patent

A. The Prosecution History

42. From the face of the ‘043 patent, it was filed on August 8, 2008 as U.S.

Application No. 12/126,501 (“the ‘501 application”). Ex. 1001, ‘043 Patent.

43. I have reviewed the prosecution history of the ‘501 application, and I am of

the understanding that claims 38-40, 42, 43, 50, 52, 62-65 of the ‘517

application matured into Challenged Claims 1-4, 6, 7, 13, 15, and 25-27 of the

‘043 patent. See Ex. 1007, Prosecution History at 324-326 [12-12-11 claim

amendments].

44. Prior to the allowance of any of the Challenged Claims, however, I understand

that U.S. Patent Publication No. 2003/0060374 to Cooke in view of U.S.

Patent Application 2005/0230107 to McDaniel, among other tertiary

references was presented by the Examiner as having rendered obvious all of

the Challenged Claims. Ex. 1007, Prosecution History at 122-127 [March 25,

2010 Non-final Office action at 8-13].

45. I also understand the Applicant unsuccessfully attempted to argue that Cooke

did not disclose a slurry to form a plug, but rather “introducing a slurry of

polymer particles and tailoring the flow rate into the well to slow to zero or

near zero so that the slurry particles may settle and accumulate in the

wellbore.” Ex. 1007, Prosecution History at 212 [October 26, 2010, Response


at 5]. Further, the Applicant argued that McDaniel described drilling

operations and thus one would not look to such reference for the modification

of Cooke. Ex. 1007, Prosecution History at 212 [October 26, 2010, Response

at 5]; Ex. 1007, Prosecution History at 151 [July 26, 2010, Response at 12].

46. I understand the claims were only allowed after the Applicant amended the

independent claims to include the recitation “and an additive for accelerating

degradation of the degradable material.” Ex. 1007, Prosecution History at

324-326 [December 12, 2011, Response at 2-4], 311-316 [September 12, 2011

Non-final Office action at 2-7], 333-337 [January 24, 2012 Notice of

Allowance].

47. As discussed in detail below, it is my opinion that Erbstoesser in view of Still,

Gibson in view of Walker, and Gibson in view of Erbstoesser and Still teach

all of the limitations of the Challenged Claims, including “an additive for

accelerating degradation of the degradable material.”

VI. Background on State of Technology in the Field of the Invention

A. Fracturing

48. At the time of the alleged invention, and still today, one of the most common

stimulation treatments of a well was hydraulic fracturing, where a fluid is

injected into a well at high pressure until a portion of the formation in contact

with the wellbore fractures under the high pressure. The fracturing fluid would


then be injected into the formation due to the high pressure in the wellbore,

which further extends the fracture.

49. After the fracture is open, proppant is added to the fracturing fluid forming a

slurry, so that the proppant will be injected into the formation as part of the

slurry. The proppant is intended to be distributed throughout the fracture so

that it can keep the fracture propped open once the well bore pressure is

reduced.

50. At some point, the pressure in the wellbore is no longer sufficient to further

extend the fracture or the operator of the well does not desire to extend the

fracture beyond a certain point, so the operator will reduce the pressure in the

wellbore and allow the fracture to partially close.

51. The fracture does not completely close when pressure is reduced because of

the proppants located within the fracture. In the industry, the creating and

propping open of fractures is sometimes referred to as increasing the

permeability of the formation. This increase in permeability through fracturing

allows hydrocarbons to more easily reach the well bore resulting in increased

production of hydrocarbons from a well.

52. To increase production even further, those of skill in the art at the time of the

invention would have known to create more than one fracture. However, a

significant hurdle in doing so is that the fracturing fluid will simply flow into


the existing fracture as it is the path of least resistance. This makes it a

challenge to create enough pressure in the wellbore to induce a second

fracture, let alone additional fractures.

53. By the time of the alleged invention, a well-known solution to this problem

was to block the fracturing fluid from entering existing fractures by using a

physical barrier or plug.

B. Creating a Plug, Bridge, Seal, or Block

54. Some in the art use the terms bridging, sealing, blocking, and plugging

interchangeably depending on the context. When I use these terms in this

declaration I understand them to mean substantially the same in the context

provided by the prior art.

55. At the time of the invention, it was known that a plug could block the entire

wellbore, which would prevent any fluid from entering a fracture beyond the

plug. While effective, this solution is generally too time consuming to

implement for every single fracture, which limits its usefulness.

56. Another solution known at the time of the invention was to plug individual

fracture or perforations in a well casing. This solution takes advantage of the

fact that since fracturing fluid will naturally flow into the most permeable

locations first, the fracturing fluid can be used to carry plugging material

directly to the fractures or perforations that need to be plugged. This solution


was also faster than plugging the entire wellbore since the plugging material

could simply be added to the fracturing fluid as needed.

57. At the time of the invention, applications of using solid particles to bridge

openings and form plugs had been well studied and thus solid particles were

often used to plug fractures and perforations in wells.

58. The basic concept is to choose a particle size such that when one, two or more

of the particles enter the opening at the same time they will get stuck in the

opening. Other particles then build up around these stuck particles until the

opening is completely blocked or plugged. This process is often referred to as

bridging in the art.

59. The physics of particle bridging is extremely well understood by a person of

skill in the art. The reason for this is that using particulates to bridge (and

plug) openings has wide applicability in the Oil & Gas industry. Particle

bridging (and plugging) is fundamental to drilling, fracturing, sand control and

acidizing -- among other applications.

60. The phenomenon of bridging (and plugging) is essentially governed by

geometric principles and relationships. A bridge created by a set of particles

having a given size will block much of an opening but often have small gaps

between particles through which some fluid might be able to flow depending

on the fluid characteristics (flow rate, viscosity, etc.). These gaps can then be


themselves bridged by smaller particles to improve the sealing of the bridge.

Further bridging of still smaller particles can occur to fill in the smallest

possible gaps between particles.

61. Because this particle bridging process is so fundamental to processes like

fracturing it has been the subject of a great deal of experimental study well

before the patent at issue. These experimental results confirmed that the two

most relevant factors affecting if a bridge will form are the ratio of hole size to

particle size and the concentration of the particles in the fluid. See e.g., Ex.

1013, Gruesbeck at 859 (describing the particle size and concentrations

needed to bridge a perforation).


62. It was also known that the most effective plugs would be formed by particles

having varying sizes so that spaces between larger particles can be bridged or

filled by smaller particles. This could be repeated with even smaller particles

to help the sealing effect of the plug. For this reasons, those of skill in the art

would generally use a range of differently sized particles when trying to create

a plug.

63. Thus, it was well-known at the time of the invention that in order to

effectively plug a fracture or a perforation, one of skill in the art at the time of

the invention would select particle sizes and concentrations depending on the

size of the fracture or perforation that needed to be plugged. The size of

fractures would be estimated based on properties of the formation and the size

of a perforation would be estimated based on the device use to create the

perforations.

C. Plug Degradation

64. Just as important as plugging existing fractures to permit the creation of

additional fractures is the removal of the plugs. Without removing the plugs,

the hydrocarbons in the fracture would not be able to enter the wellbore from

the formation for production.

65. At the time of the invention, it was known to be advantageous in terms of

time and cost to have a plug degrade, based on the conditions found in the


wellbore (fluid, temperature, pressure, etc.), rather than to require some

additional action, for example injecting a new fluid or additive, such as a

solvent or acid, to breakdown, dissolve, or otherwise degrade the plug.

66. However, it was also important for the plug to last long enough to complete

any desired downhole operations, such as subsequent fracturing. For example,

if an operator wanted to fracture a well in five different locations such a

process at the time of the invention could have reasonably taken eight hours.

Thus, the plug should not breakdown or disappear until after those eight

hours. Otherwise, the plug may cease to function as desired before all the

fractures are completed and prevent the operator from completing the job (as

without the plug the necessary pressure to initiate new fractures may not be

able to be obtained) or without the need to take costly further steps.

67. Much of the research into temporary plugging agents prior to the time of the

invention was in discovering new materials and testing how long it took those

materials to degrade under downhole conditions. There are numerous

publications available to those of skill in the art that give guidance as to what

materials are available and how those materials degrade. I discuss some of

these publications below.

68. Armed with the knowledge of how materials degrade, one of skill in the art at

the time of the invention could determine an approximate duration for how


long a plug formed of that material would last under a given set of well

conditions. One of skill in the art at the time of the invention would then select

a material that would form a plug that would not disappear until desired.

69. If a material was not available that could maintain a plug for longer than the

operation, then one of skill in the art at the time of the invention could have

modified the operation so that it would conclude before the plug disappeared

(e.g., by reducing the number of fractures to be performed during the

operation).

70. My understanding of what one of ordinary skill in the art would have known

about this technology is corroborated through extensive documentation

published by reputable trade organizations that those of skill in the art would

have been aware of and relied upon. A discussion of a selected set of such

sources is presented in the following section.

D. Documents Supporting Knowledge of One of Skill in the Art atthe Time of the Invention

1958 – “The Use of Temporary Blocking Agents in Fracturing andAcidizing Operations” (Ex. 1008, White Paper)

71. The concept of using degradable materials to plug perforations, fractures, or

the wellbore goes back to at least the 1950’s. In 1958, Garland White

published “The Use of Temporary Blocking Agents in Fracturing and

Acidizing Operations” which describes the use of temporary blocking agents


to isolate zones that have already been treated (e.g., a zone that was previously

fractured). See Ex. 1008, White Paper at 19, left column.

72. In his paper, White describes a process whereby larger granular particles are

forced into a fracture until they form a bridge. Ex. 1008, White Paper at 20,

left column. Then smaller particles fill the openings in between the larger

particles until all the openings are closed, producing an impermeable block.

Ex. 1008, White Paper at 20, left column. An impermeable block formed in a

fracture is understood by those of skill in the art to be a plugging of a fracture.

Ex. 1008, White Paper at 20, left column.

73. An example of this process is illustrated in Figure 2, shown below.

Ex. 1008, White Paper at 20, left column.


74. The paper then goes on to note that this granular material is mixed with the

treating or carrier fluid to form a slurry, which is pumped in ahead of a

treatment or pumped in between treatments. Ex. 1008, White Paper at 20,

right column.

75. Next, the White Paper details that the most used granular temporary diverting

materials in use in 1958 include naphthalene, walnut shell resin mixture,

ammonium-chloride pellets, and rock salt. Naphthalene and the walnut shell

resin mixture would degrade in oil while the ammonium- chloride pellets and

rock salt would degrade in water. Ex. 1008, White Paper at 20, right column

to 21, left column.

76. Finally, the White Paper details the factors to take into consideration when

choosing a temporary blocking agent, including type of formation, type of

opening to be blocked (e.g., the size of the fractures to be blocked),

temperature and pressure, local experience and type of completion (open hole

or perforated). Ex. 1008, White Paper at 24. Of particular note is that the

carrier fluid and temperature can have a great effect on the solubility of a

material, which would alter the degradation rate of that material. Ex. 1008,

White Paper at 24.

77. Thus, the White Paper explained, in 1958, a method of using degradable

materials to form a plug in a fracture wherein the size of the granules of the


degradable material should be selected based on the size of fractures to be

blocked and the duration after which the material degrades depends on the

presence of soluble fluids down hole as well as temperature.

1965 – “New ‘beads’ help acidizing, fracturing” (Ex. 1012,Unibeads Article)

78. In the 1960’s, the Union Oil Company introduced a commercial product

called “Unibeads.” Ex. 1012, Unibeads Article at 52. “The beads function as a

temporary sealing agent, plugging any opening in the well bore through which

fluid will pass.” Ex. 1012, Unibeads Article at 52.

79. Plugging a fracture with Unibeads allowed the well operator to fracture

multiple times during the same operation. Ex. 1012, Unibeads Article at 52.

The beads then dissolve within hours after the fracturing operation is complete

to reopen all of the passages which have been plugged. Ex. 1012, Unibeads

Article at 52.

80. One could select a type of Unibead “for specific conditions to assure

dissolution within 8 to 48 hours.” Ex. 1012, Unibeads Article at 52. One could

also select a size of the Unibeads, including a large particle-size distribution,

which would aid in effective plugging. Ex. 1012, Unibeads Article at 54.

81. Thus, the Unibeads Article further illustrates that those of skill in the art were

well aware of the method and benefits of plugging fractures using dispersed


particles and allowing the plug to dissolve soon after the fracturing operation

is completed.

1972 – “Diverting Agents – History and Application” (Ex. 1009,Harrison Paper)

82. In 1972, the methodology and materials to plug holes and divert subsequent

treatment had become so ubiquitous that a paper was written detailing

diversion’s long history (a history which only became longer in the 30

additional years before the alleged date of invention of the ‘278 patent). Ex.

1009, Harrison Paper at 593.

83. As Harrison explains, the earliest documented diverting agents were patented

by Halliburton in 1936. Ex. 1009, Harrison Paper at 593. Then in the

subsequent decades new materials were used as diverting agents: emulsions in

the 1940’s; Dowell’s “Fixafrac” in 1951; naphthalenes in 1954; synthetic

polymers in 1962; Union Oil’s “Unibeads” in 1965; paraformaldehyde in the

late 1960’s; and Benzoic acid flakes in 1969. Ex. 1009, Harrison Paper at 595-

97.

84. Like the Unibeads Article, the Harrison Paper also noted the benefit of having

a blocking material that lasts long enough to divert fluid during the treatment

and then for the plug to become ineffective. Ex. 1009, Harrison Paper at 597.

85. Thus, the Harrison Paper documents the various options known for diverting

materials and some of the advantages of each.


VII. Background on the Prior Art References

86. Before providing a detailed analysis of how the prior art invalidates the

challenged claims, I will provide a brief summary of the asserted prior art.

A. Background of Erbstoesser

87. U.S. Patent No. 4,716,964 to Erbstoesser et al. (Ex. 1004, Erbstoesser) entitled

“Use of Degradable Ball Sealers to Seal Casing Perforations in Well

Treatment Fluid Diversion” was filed on December 10, 1986 with a claim of

priority and lists Steven Erbstoesser, Claude Cooke Jr., Richard Sinclair, and

Michael Esptein as inventors (hereinafter “Erbstoesser”). Erbstoesser was

issued on January 5, 1988. Ex. 1004, Erbstoesser.

88. Erbstoesser described the problem that during fracturing treatments certain

types of known degradable diversion materials could cause damage to the

production capabilities of the well after their use. Ex. 1004, Erbstoesser at

1:47-2:29 (describing problems in prior art). Erbstoesser further recognized

that rubber ball sealers, then in use, also would remain in the well after the

treatment operation. Ex. 1004, Erbstoesser at 2:30-47. Accordingly,

Erbstoesser attempted to improve the prior art by using different types of

degradable polymers that would cause less damage to the formation,

preferably poly(D,L-lactide) (also known as poly-lactic acid or PLA), as solid

particulate materials and/or ball sealers. Ex. 1004, Erbstoesser at 2:57-3:20.


89. Erbstoesser taught that after wellbore fluid with the degradable polymer

particulates is injected into the formation, the polymer plugs the formation and

diverts treating fluid (i.e., subsequent fracturing), until the polymer degrades,

usually in 1 to 7 days. Ex. 1004 Erbstoesser at 7:11-22. As to the time needed

to degrade the polymer, Erbstoesser notes that “selection of an appropriate

preferred polymer” depends in part on the conditions which exist in the

wellbore such as “[t]he rate of degradation of the preferred polymer of the

present invention depends, amongst other things, upon the temperature, the

solubility of the water in the surrounding fluid, the polymer particle size, [etc.

. . . ]”). Ex. 1004, Erbstoesser at 5:4-40.

B. Background of Still

90. U.S. Patent Pub. No. 2004/0152601 to Still et al. (Ex. 1015, Still) entitled

“Generating Acid Downhole in Acid Fracturing” was filed on October 27,

2003, and lists John Still, Keith Dismuke, and Wayne Frenier as inventors

(hereinafter “Still”). Still was published on August 5, 2004.

91. Still describes a method of acid fracturing using a solid acid precursor for

providing a controlled release of acid by hydrolysis. Ex. 1006, Still at ¶9. The

solid acid precursor is, among other things, PLA (lactide, glycolide, polylactic

acid, polyglycolic acid, a copolymer of polylactic acid and polyglycolic acid,

a copolymer of glycolic acid with other hydroxy-, carboxylic acid-, or


hydroxycarboxylic acid-containing moieties, a copolymer of lactic acid with

other hydroxy-, carboxylic acid or hydroxycarboxylic acid-containing

moieties). Ex. 1006, Still at ¶¶9, 12-13, 15.

92. The degradation of the solid acid-precursor (e.g., PLA) may be accelerated by

an additive. Ex. 1006, Still at ¶¶9, 16-18. This additive may be a solid or

soluble liquid. Ex. 1006, Still at ¶¶9, 16-18. For instance, the solid accelerant

may be magnesium hydroxide, magnesium carbonate, dolomite (magnesium

calcium carbonate), calcium carbonate, aluminum hydroxide, calcium oxalate,

calcium phosphate, aluminum metaphosphate, sodium zinc potassium

polyphosphate glass, and sodium calcium magnesium polyphosphate glass for

the purpose of increasing the rate of dissolution and hydrolysis of the solid

acid-precursor. Ex. 1006, Still at ¶17. The soluble liquid additives may be

acids, bases, or sources of acids or bases. Ex. 1006, Still at ¶18.

C. Background of Gibson

93. U.S. Patent No. 3,353,604 to Gibson et al. (Ex. 1006, Gibson) entitled

“Treatment of Subsurface Earthen Formations” was filed on October 13, 1965

and lists Daniel Gibson and Louis Eilers as inventors (hereinafter “Gibson”).

Gibson was issued on November 21, 1967.

94. Gibson identified the need for a new diverting agent that could divert well

treatment fluid to those portions of the formation that are less permeable,


rather than extending existing fractures or channels in the formation. Ex.

1006, Gibson at 2:12-37. Gibson discovered the use of solid particles of an

aldehyde polymer that should be dispersed as 0.1% to 6% by weight in the

aqueous treatment fluid. Ex. 1006, Gibson at 2:38-55. The particles of the

aldehyde polymer were preferably a mix of flakes and powder. Ex. 1006,

Gibson at 3:29-33. Gibson described injecting the aqueous fluid containing

the aldehyde polymer diverting agent down the well to temporarily plug the

first fractures created, thereby diverting subsequent fracturing elsewhere in the

formation. Ex. 1006, Gibson at 3:8-10 and 3:46-53. The aldehyde polymer

then would degrade with contact by water, either from the formation itself or

upon injection into the well. Ex. 1006, Gibson at 3:15-24. Gibson provides an

example of using his composition during a fracturing treatment for a well. Ex.

1006, Gibson at 3:69-4:45.

D. Background of Walker

95. J. Frederic Walker, Formaldehyde, 2nd Ed., American Chemical Society,

Monograph Series No. 120, was published in 1953 by Reinhold Publishing

Corporation.

96. Walker discusses formaldehyde polymers, including paraformaldehyde. Ex.

1016, Walker at 114-115, 119. In particular, Walker describes the hydrolytic

depolymerization of formaldehyde polymers. Ex. 1016, Walker at 124. In


particular, Walker discusses accelerators for degradation of formaldehyde

polymers. Ex. 1016, Walker at 124. These accelerants include acids or bases.

See Ex. 1016, Walker at 124 As discussed in Walker, under alkaline

conditions, the hydroxyl end groups are attached and degradation proceeds in

a step-wise fashion with successive splitting of the formaldehyde units from

the ends of the linear molecules. Ex. 1016, Walker at 124. Under acidic

conditions, the oxygen linkages within the chains may be attacked, with the

splitting of the large molecules into smaller fragments. Ex. 1016, Walker at

124.

VIII. Broadest Reasonable Interpretation

97. I understand that in an inter partes review proceeding, claims are given their

broadest reasonable interpretation consistent with the specification.

98. I have been provided with a construction of the term “form a plug in one or

more than one of a perforation, a fracture, and a wellbore” as meaning “form a

plug in a perforation, form a plug in a fracture, form a plug in a wellbore, or

form a plug in more than one of these locations.” I agree with this

construction and believe it to be consistent with one of ordinary skill in the

art’s understanding of the ‘043 patent, which describes embodiments where

any one of a perforation, fracture, or wellbore are individually plugged. Ex.

1001, ‘043 Patent at 6:8-24 and 13:8-11.


IX. The Challenged Claims are Unpatentable

A. Claims 1-4, 6, 7, 13, 15, and 25-27 are rendered obvious byErbstoesser in view of Still

1. Claim 1

A method of well treatment, comprising;

99. Examples of well treatments that could be used with Erbstoesser’s invention

are fracturing, acidizing, perforating or gravel packing, which were all

commonly used treatment operations. Ex. 1004, Erbstoesser at 1:18-20 and

6:46-53.

a) injecting a slurry comprising a degradable material selectedfrom the group consisting of powder, beads and chips, and anadditive for accelerating degradation of the degradable material;

100. Erbstoesser describes using his invention with a wide array of polymers made

of glycolide and lactide, but expresses a preference for “poly(D, L-lactide),

crosslinked poly(D,L-lactide) and the copolymers of glycolide and D,L-

lactide.” Ex. 1004, Erbstoesser at 4:67-5:7 and 5:40-58. “Poly(D, L-lactide)”

is commonly known as polylactic acid or PLA for short. These polymers are

provided in the form of solid particles at ambient temperature that degrade in

the presence of water at an elevated temperature. Ex. 1004, Erbstoesser at 4:6-

60; 3:10-13.

101. In Erbstoesser, the wellbore fluid is also called a treating fluid as it is the fluid

that will be used during the treatments. Ex. 1004, Erbstoesser at 6:32-33. The


bulk of the liquid in the wellbore fluid can be any of a number of common

liquids used in well treatment operations including water, oil, or brines. Ex.

1004, Erbstoesser at 6:54-63. The wellbore fluid can contain other materials

including dispersed degradable polymer and other additives. Ex. 1004,

Erbstoesser 3:34-41, 6:27-30, and 6:64-68.

102. One of skill in the art would understand the 0.1 to 100 micron range particles

would be a powder while the larger ranges of 850 to 1500 microns and 0.5 to

1 inch are beads. Ex. 1004, Erbstoesser at 4:46-56, 8:39-43 (“small spheres

(approximately 1/2-inch diameter) of poly(D,L-lactide)(PLA)”); see also Ex.

1006, Gibson at 3:29-32 (describing 200 mesh particles, which equates to 75

micron particles, as a “powder”).

103. Those of skill in the art understand that a slurry is a broad term that would

encompass at least a fluid that contains solid particulates. In Erbstoesser, his

wellbore fluid would be considered a slurry when it contains solid particles,

such as solid particles of the degradable polymer. Ex. 1004, Erbstoesser at

4:44-60 and 3:10-13.

104. The slurry of wellbore fluid and dispersed polymer particles would be

injected into the wellbore and consequently the formation by applying

pressure at the wellhead. Ex. 1004, Erbstoesser at 6:32-34.


105. Erbstoeser also describes that the rate of degradation of his polymer depends

on the wellbore conditions as well as polymer particle size, polymer molecular

weight, degree of crystallinity of the polymer, solubility and diffusibility of

water in the polymer, and the reactivity of the ester bonds comprising the

polymer. Ex. 1004, Erbstoesser at 5:4-17.

106. Still describes increasing the rate of degradation and hydrolysis of polyesters

of the type used in Erbstoesser, including PLA, by the inclusion of solid

additives. Ex. 1015, Still at ¶16. A list of solid additives that would accelerate

the degradation of these polymers include magnesium hydroxide, magnesium

carbonate, dolomite (magnesium calcium carbonate), calcium carbonate,

aluminum hydroxide, calcium oxalate, calcium phosphate, aluminum

metaphosphate, sodium zinc potassium polyphosphate glass, and sodium

calcium magnesium polyphosphate glass. Ex. 1015, Still at ¶17.

107. Similarly, Still describes using liquid additives that would likewise accelerate

the degradation of the polymers used in Erbstoesser including acids, bases, or

sources of acids and bases. Ex. 1015, Still at ¶18.

108. A person of skill in the art would apply the teachings of Still’s accelerating

additive to accelerate the rate of degradation of the polymers taught by

Erbstoesser. One of skill in the art would have reason to use an additive for

accelerating degradation if wellbore conditions were not conducive to


degrading the polymer in a reasonable time (such as low temperature). See

Ex. 1004, Erbstoesser at 5:14-16. Erbstoesser also states his treatment fluid

can include additives known in the art, which would encompass the additives

in Still. Ex. 1004, Erbstoesser at 6:64-66. Erbstoesser also states the additives

added to the treatment fluid should not react with the polymer, but this

statement when read in the context of the specification indicates to one of skill

in the art to avoid using additives included for other purposes, such as

increasing the viscosity of the treatment fluid, that would react with the

polymer. Ex. 1004, 6:66-68 and 7:1-6 (discussing how viscosity of treatment

fluid affects amount of polymer needed). One of skill in the art at the time of

the invention would have read Erbstoesser’s discussion on how degradation

rates of his polymers can be modified and understood that one way to do so

within Erbstoesser’s teachings is to use known additives chosen specifically

for the purpose of modifying degradation rates of the polymers.

109. One of skill in the art would also have reason to use an additive for

accelerating degradation if the plug would delay the production of a well after

the treatment was completed. By the time of the invention, the benefits of

having a plug which would degrade soon after the treatment was completed

was well-known. See Ex. 1009, Harrison Paper at 597 (“The perfect blocking

material is one that lasts long enough to divert fluid during a treatment and


then becomes ineffective”); see also Ex. 1012, Unibeads Article at 52 (“The

beads then dissolve within hours after the fracturing operation is complete to

reopen all of the passages which have been plugged.”).

110. In light of these disclosures, one of skill in the art would understand

Erbstoesser in view of Still renders obvious “injecting a slurry comprising a

degradable material selected from the group consisting of powder, beads and

chips, and an additive for accelerating degradation of the degradable

material.”

b) allowing the degradable material to form a plug in one or morethan one of a perforation, a fracture, and a wellbore in a wellpenetrating a formation;

111. Erbstoesser discloses three different particle size ranges for his polymer. Ex.

1004, Erbstoesser at 4:44-60. Any of the particle sizes could be used to plug

perforations, fractures, or the wellbore depending on the size and shape of the

opening to be plugged.

112. Erbstoesser provides an experiment where a PLA ball sealer can be used to

“plug the perforation” in a casing. Ex. 1004, Erbstoesser at 11:35-64. One of

skill in the art at the time of the invention understands this experiment

demonstrates that the PLA ball sealer would plug casing perforations during

well treatment operations, such as fracturing or acidizing. Ex. 1004 at 1:16-20.


113. Erbstoesser also discloses injecting the polymer into the formation to divert

subsequent fluid flow, which one of skill in the art at the time of the invention

understands would mean plugging a fracture. Ex. 1004, Erbstoesser at 7:11-

13; see also 6:34-43.

114. At the time of the invention, one of skill in the art knew that the ratio of the

size of the particles to the size of the opening was one of the most important

considerations to take into account when trying to seal an opening. See Ex.

1008, White Paper at 24 and Ex. 1013, Gruesbeck at 859.

115. Depending on the size of the opening encountered, one of skill in the art at the

time of the invention would have plugged the opening, such as a perforation

or fracture, by selecting an appropriate particle size, including any of

Erbstoesser’s particle sizes or other comparable sizes. Ex. 1004, Erbstoesser at

4:44-60. In addition, one of skill in the art at the time of the invention knew

that using a range of different sizes would create the best seal, such as

including particles in more than one of the size ranges taught by Erbstoesser.

Ex. 1004, Erbstoesser at 7:11-13; see also 6:34-43. Plugging an opening in

this manner would have been a predictable application of using Erbstoesser’s

solid polymers according to known particle bridging techniques. See Ex.

1008, White Paper at 24 and Ex. 1013, Gruesbeck at 859.


116. One of skill in the art at the time of the invention would know that the 850 to

1500 micron and ½ inch to 1 inch particles would form a plug rather than a

filter cake. Even when considering the most porous rock formations known in

the world today, the maximum particle size to form filter cake on such a

porous formation would be around 200 microns. Forming a filter cake on

formations of more typically porosities would require particles sized less than

200 microns.

117. Erbstoesser also discloses plugging the wellbore when describing “a high

concentration slug of wellbore fluid may be placed at the appropriate location

of the wellbore” during perforating or gravel packing operations. Ex. 1004 at

6:50-53. One of skill in the art at the time of the invention understands the

slug in this description to be a portion of the wellbore fluid where particles are

relatively close together but dispersed in enough fluid to still be pumped down

the wellbore. When the slug reaches an existing perforation or gravel pack, the

wellbore fluid will leak off into the perforation or gravel pack and leave

behind a mass of solid particles plugging the wellbore at the site of the

perforation or gravel pack.

118. In light of these disclosures, one of skill in the art at the time of the invention

would understand Erbstoesser anticipates or renders obvious “allowing the


degradable material to form a plug in one or more than one of a perforation, a

fracture, and a wellbore in a well penetrating a formation.”

c) performing a downhole operation; and

119. Erstoesser describes performing a number of downhole operations including

fracturing, acidizing, perforation or gravel packing while using his polymer

particles. Ex. 1004, Erbstoesser at 1:18-20 and 6:46-53.


would understand Erbstoesser anticipates or renders obvious “performing a

downhole operation.”

d) allowing the degradable material to at least partially degradeafter a selected duration such that the plug disappears.

121. As previously discussed, Erbstoesser uses a wide array of polymers made of

glycolide and lactide, but expresses a preference for “poly(D, L-lactide),


lactide.” Ex. 1004, Erbstoesser at 4:67-5:7. “Poly(D, L-lactide)” is commonly

known as polylactic acid or PLA for short. These polymers degrade in the

presence of water, including water that is present in the formation fluids. Ex.

1004, Erbstoesser at 4:6-24.

122. In the presence of water at elevated temperatures the polymers will

substantially degrade within 1 to 7 days. Ex. 1004, Erbstoesser at 4:6-9 and

7:17-21. The elevated temperature range, including 45° C to 200° C, reflects


the reality of downhole conditions which are generally elevated compared to

surface temperatures. Ex. 1004, Erbstoesser at 4:12-15.

123. Erbstoesser also provides charts in Figures 1 and 2 which illustrate the time

for a ½ inch diameter PLA and crosslinked PLA ball sealer to degrade in a

150°-160° F brine environment. Ex. 1004, Erbstoesser at 11:35-64 and

Figures 1 and 2. One of skill in the art at the time of the invention looking at

Figures 1 and 2 would understand the ball sealer plugged the perforation

starting on day 1 of the Figures as that is the first data point indicated (the

time from day 0 to day 1 was likely to establish the initial permeability

values).

124. Erbstoesser notes that some flow was re-established in 1-2 days after sealing

the perforation with the ball sealer (which would be day 2 and 3 in the

Figures) and the plug was nearly completely degraded four days after sealing

the perforation such that effective permeability is nearly restored to the initial

level. Ex. 1004, Erbstoesser at 11:65-12:7 and Figures 1 and 2.

125. Thus, if no additive to accelerate the degradation were used, a plug made of

Erbstoesser’s polymers would disappear after a selected duration of 1 day in

the well conditions Erbstoesser intended his polymer to be used with, such as

wells having temperatures between 45° C to 200° C. Ex. 1004, Erbstoesser at

4:12-15, 11:65-12:7.


126. Erbstoesser also teaches factors that control the degradation rate of his

polymers so that one of skill in the art at the time of the invention can select

durations other than 1 to 7 days after which the plug disappears. Ex. 1004,

Erbstoesser at 5:4-40. One of skill in the art at the time of the invention

would have used an additive to accelerate the degradation rate, such as

magnesium hydroxide as taught by Still, to put the well back into production

sooner than 1 day. Depending on what additive and what concentration is

used, one of skill in the art could accelerate the degradation of Erbstoesser’s

polymer to shorten the time until the plug made of the polymer disappears to a

matter of hours, such as 18 hours, 12 hours or 6 hours. Determining the

concentration of an additive to use in order to achieve a desired degradation

rate requires only routine experimentation and optimization.

127. In addition, it was well known by the time of the invention to choose a

material that would not degrade until after the duration of a selected treatment

operation but that would degrade shortly thereafter. See Ex. 1009, Harrison

Paper at 597 (“The perfect blocking material is one that lasts long enough to

divert fluid during a treatment and then becomes ineffective”); see also Ex.

1012, Unibeads Article at 52 (“The beads then dissolve within hours after the

fracturing operation is complete to reopen all of the passages which have been

plugged.”).


128. In light of Erbstoesser’s teaching that it takes 1 to 7 days for his polymer to

degrade, one of skill in the art at the time of the invention would have reason

to select a duration of 6 hours for a treatment operation, such as a fracturing

operation. One of skill in the art at the time of the invention would have

reason to select such a short duration to ensure the treatment operation will be

completed before Erbstoesser’s plug disappears in light of the accelerated

degradation of Erbstoesser’s polymers by Still’s additive. Otherwise, if the

plug disappears before the treatment operation is completed, it would prevent

diversion of wellbore fluid to create new fractures and treatment fluid would

be lost to existing fractures.


would understand Erbstoesser anticipates or renders obvious “d) allowing the

degradable material to at least partially degrade after a selected duration such

that the plug disappears.”

Claim 2

The method of claim 1, wherein the degradable material isselected from a polymer of lactide, glycolide,polylacticacid, polyglycolic acid, amide, and mixtures thereof.

130. As previously discussed, Erbstoesser uses a wide array of polymers made of

glycolide and lactide, but expresses a preference for “poly(D, L-lactide),



lactide.” Ex. 1004, Erbstoesser at 4:67-5:7. “Poly(D, L-lactide)” commonly

known as polylactic acid or PLA for short.


would understand Erbstoesser anticipates or renders obvious “wherein the

degradable material is selected from a polymer of lactide, glycolide, polylactic

acid, polyglycolic acid, amide, and mixtures thereof.”

Claim 3

The method of claim 2, wherein the well treatmentcomprises chemical stimulation.

132. Erbstoesser states that acidizing was a known form of treatment used with

diversion materials in order to divert acid to less permeable strata in the

formation. Ex. 1004, Erbstoesser at 1:19-33. One of skill in the art would have

understood Erbstoesser to describe using his invention and degradable

diversion material for acidzing treatments, which are a chemical stimulation.


Erbstoesser renders obvious “wherein the well treatment comprises chemical

stimulation.”


Claim 4

The method of claim 1, wherein the degradable material ispresent at a concentration of no less than 40 lbm/1,000 gal(4.8 g/L).

134. Erbstoesser states that the amount of polymer required “will vary widely

depending” on the characteristics of the formation and provides an exemplary

concentration of “about 1 to about 10 pounds of polymer per 100 barrels of

wellbore fluid.” Ex. 1004, Erbstoesser at 7:1-10. As acknowledged by

Erbstoesser, one of skill in the art would have varied the amount of polymer

according to the situation and would have reason to use a concentration no

less than 40 lbm/1,000 gallons depending on the number of openings to be

plugged, the size of those openings, the temperature in the well bore, etc.

135. For example, Erbstoesser gives an example of a “high concentration” slug

when trying to plug the wellbore, which is a large opening. Ex. 1004,

Erbstoesser at 6:50-53. One of skill in the art would understand a high

concentration would exceed 40 lbm/1,000 gal.

136. The selection of concentration of degradable material is a design choice

dictated primarily by the conditions of the particular well to be treated and

opening to be plugged and that a concentration of 40lbm/1,000 gal. or more

would be reasonably expected under normal conditions.



Erbstoesser renders obvious “wherein the degradable material is present at a

concentration of no less than 40 lbm/1,000 gal. (4.8 g/L).”

Claim 6

The method of claim 1, wherein the slurry furthercomprises a particulate material.

138. Erbstoesser describes using both the finely divided and intermediately sizes

particles together in a slurry. Ex. 1004, Erbstoesser at 7:6-10. One of these

particle sizes could be the particulate material reited in claim 6 while the other

particle size is the degradable material recited in claim 1.



slurry further comprises a particulate material.”

Claim 7

The method of claim 6, wherein the particulate material isdegradable.

140. The polymeric material used to make Erbstoesser’s variously sized particles

are all degradable in water. Ex. 1004, Erbstoesser at 4:6-60. One of these

particle sizes could be the degradable particulate material recited in claim 7

while the other particle size is the degradable material recited in claim 1.




particulate material is degradable.”

Claim 13

The method of claim 1, wherein the well treatmentcomprises hydraulic fracturing.

142. Hydraulic fracturing is the use of fluid to fracture a formation, generally done

by applying a high pressure to the fracturing fluid. One of skill in the art at the

time of the invention understands Erbstoesser’s usage of a “fracturing fluid”

to describing hydraulic fracturing. Ex. 1004, Erbstoesser at 6:46-50.



well treatment comprises hydraulic fracturing.”

Claim 15

The method of claim 13, wherein hydraulic fracturing isapplied to more than one layer of a multilayer formation.

144. One of skill in the art at the time of the invention understands Erbstoesser’s

description of a formation with at least two strata having different

permeabilites to be describing a formation with more than one layer as each

strata in the formation corresponds to a different layer. Ex. 1004, Erbstoesser

at 6:27-50. In addition, one of skill in the art at the time of the invention


understands the “treament” being discussed in this context includes

“fracturing treatments.” Ex. 1004, Erbstoesser at 6:27-50.


would understand Erbstoesser anticipates or renders obvious “wherein

hydraulic fracturing is applied to more than one layer of a multilayer

formation.”

Claims 25 and 26

146. Claim 25 is identical to claim 1, except claim 25 recites in part b) “degradable

material selected from the group consisting of powder, beads, chips, fibers, or

any combination thereof” whereas claim 1 recites “degradable material

selected from the group consisting of powder, beads and chips.”

147. Additionally, claim 25 omits step d) from claim 1 which recites “allowing the


that the plug disappears” which is instead moved to dependent claim 26.

148. Thus my statements as to why claim 1 is rendered obvious by Erbstoesser in

view of Still are equally applicable to claims 25 and 26 which are

incorporated by reference. In particular, one of skill in the art would

understand the 0.1 to 100 micron range particles would be a powder while the

larger ranges of 850 to 1500 microns and 0.5 to 1 inch are beads. Ex. 1004,

Erbstoesser at 4:46-56, 8:39-43 (“small spheres (approximately 1/2-inch


diameter) of poly(D,L-lactide)(PLA)”); see also Ex. 1006, Gibson at 3:29-32

(describing 200 mesh particles, which equates to 75 micron particles, as a

“powder”).

Claim 27

149. Claim 27 is identical to claim 1, except claim 27 omits step d) which in claim

1 recites “allowing the degradable material to at least partially degrade after a

selected duration such that the plug disappears.” Thus my statements as to

why claim 1 is rendered obvious by Erbstoesser in view of Still are equally

applicable to claim 27 which are incorporated by reference.

B. Claims 1-4, 6, 7, 13, 15 and 25-27 are rendered obvious by Gibsonin view of Walker

1. Claim 1

A method of well treatment, comprising;

150. Gibson describes treating a well and gives hydraulic fracturing as one

example. Ex. 1006, Gibson at 1:29-58 and 3:34-53.

a) injecting a slurry comprising a degradable material selectedfrom the group consisting of powder, beads and chips, and anadditive for accelerating degradation of the degradable material

151. Gibson describes using his invention with solid polymer of aldehyde such as

paraformaldehyde, metaldehyde, or trioxane. Ex. 1006, Gibson at 2:56-70.

These polymers degrade at least in the presence of water at 18° to 25° C. Ex.


1006, Gibson at 2:20-37, 2:56-70; see also Ex. 1009, Harrison Paper at 597

(“Paraformaldehyde is temperature degradable and is soluble in both water

and oil.”)

152. Gibson states the solid particles of the aldehyde polymer are added to the

aqueous fluid “to make a dispersion.” Ex. 1006, Gibson at 2:20-37. This

aqueous fluid can also include other solid particulates including sand. Ex.

1006, Gibson at 4:8-13.

153. The preferred solid particles of Gibson are “a 5 to 200 mesh powder” so one

of skill in the art would understand Gibson’s polymer to at least be a powder.

Ex. 1006, Gibson 3:29-33.

154. Those of skill in the art understand a slurry is a broad term that would

encompass at least a fluid that contains solid particulates. In Gibson, his

carrier fluid would be considered a slurry when it contains solid particles of

his degradable aldehyde polymer or other particles such as sand. Ex. 1006,

Gibson at 4:8-13.

155. Gibson states that the slurry made of the aqueous fluid with solid aldehyde

and other particles is injected into the formation. Ex. 1006, Gibson at 2:20-37,

3:8-13.

156. Walker describes hydrolytic depolymerization of formaldehyde polymers,

which are the polymers used in Gibson. Walker states that providing a base or


acid accelerates the degradation of formaldehyde polymers. See Ex. 1016,

Walker at 124.

157. As described by Walker, under alkaline conditions, the hydroxyl end groups

of the formaldehye polymers are attacked and degradation proceeds in a step-

wise fashion with successive splitting of the formaldehyde units from the ends

of the linear molecules. Ex. 1016, Walker at 124. Under acidic conditions, the

oxygen linkages within the chains may be attacked, with the splitting of the

large molecules into smaller fragments. Ex. 1016, Walker at 124.

158. A person of skill in the art would apply the teachings of Walker’s

accelerating additive to accelerate the rate of degradation of the aldehyde

polymers taught by Gibson. This possibility was acknowledged by Gibson

when directing readers to learn “[a]dditional characteristics” of his polymers

in chemistry handbooks. Ex. 1006, Gibson at 2:63-70. One of skill in the art

would have reason to use an additive for accelerating degradation if wellbore

conditions were not conducive to degrading the polymer in a reasonable time

(such as to low temperature).



the treatment was completed. See Ex. 1009, Harrison Paper at 597 (“The

perfect blocking material is one that lasts long enough to divert fluid during a


treatment and then becomes ineffective”); see also Ex. 1012, Unibeads Article

at 52 (“The beads then dissolve within hours after the fracturing operation is

complete to reopen all of the passages which have been plugged.”).

160. In light of these disclosures, one of skill in the art would understand Gibson in

view of Walker renders obvious “injecting a slurry comprising a degradable

material selected from the group consisting of powder, beads and chips, and

an additive for accelerating degradation of the degradable material.”

b) allowing the degradable material to form a plug in one or morethan one of a perforation, a fracture, and a wellbore in a wellpenetrating a formation;

161. Gibson described using his polymer to temporarily plug an existing fracture

so that the fracturing fluid will then be diverted elsewhere in the formation to

create new fractures. Ex. 1006, Gibson at 3:46-53. Gibson also states how his

polymer remains lodged in the formation to divert subsequently injected fluid

to less permeable portions of the formation, which is another description for

how his polymer forms a plug. Ex. 1006, Gibson at 2:20-37.


would understand Gibson anticipates “allowing the degradable material to

form a plug in one or more than one of a perforation, a fracture, and a

wellbore in a well penetrating a formation.”


c) performing a downhole operation; and

163. Gibson describes using his plug to divert subsequent fluid for either fracturing

or acidizing operations. Ex. 1006, Gibson at 2:20-37, 3:69-4:45, 4:46-5:40.

The fracturing or acidizing operations would be downhole operations.


would understand Gibson anticipates “performing a downhole operation.”

d) allowing the degradable material to at least partially degradeafter a selected duration such that the plug disappears.

165. As previously discussed, Gibson describes using his invention with a solid

polymer of aldehyde such as paraformaldehyde, metaldehyde, or trioxane.”

Ex. 1006, Gibson at 2:56-70. These polymers degrade at least in the presence

of water at 18° to 25° C and are used to “temporarily” plug fractures. Ex.

1006, Gibson at 2:20-37, 2:56-70, 3:15-24, and 3:50-53; see also Ex. 1009,

Harrison Paper at 597 (“Paraformaldehyde is temperature degradable and is

soluble in both water and oil.”).

166. Gibson also provides a table comparing test results of the effectiveness of his

plugs in different wells and differing paraformaldehyde volumes. Ex. 1006 at

5:4-40. In the description of these test results, Gibson states that his temporary

plug dissolved seven days after the well treatment, which is confirmed by the

Table which shows significant injection rate increases in each treated well

seven days after treatment. Ex. 1006, Gibson at 5:4-40.


167. One of skill in the art at the time of the invention would have used an additive

to accelerate the degradation rate, such as an acid as taught by Walker, to put

the well back into production sooner than 1 day. Depending on what additive

and what concentration is used, one of skill in the art could accelerate the

degradation of Gibson’s polymer to shorten the selected duration until the

plug made of the polymer degrades to a matter of hours or days, such as 1 day,

18 hours, 12 hours or 6 hours. Determining the concentration of an additive to

use in order to achieve a desired degradation rate requires only routine

experimentation and optimization.

168. In addition, it was well known by the time of the invention to choose a

material that would not degrade until after the duration of a selected treatment

operation. See Ex. 1009, Harrison Paper at 597 (“The perfect blocking





169. In light of Gibson’s teaching that it takes 7 days for his polymer to degrade

without an additive, and the knowledge that an additive could shorten that

time to 6 hours, one of skill in the art would have reason to select a duration of

6 hours for a treatment operation, such as a fracturing operation, to ensure the


operation will be completed before Gibson’s plug made of his polymer

degrades and that the plug will degrade soon after the treatment. One of skill

in the art at the time of the invention would have reason to select such a short

duration to ensure the treatment operation will be completed before Gibson’s

plug disappears in light of the accelerated degradation of Gibson’s polymers

by Walker’s additive. Otherwise, if the plug disappears before the treatment

operation is completed, it would prevent diversion of wellbore fluid to create

new fractures and treatment fluid would be lost to existing fractures.


view of Walker renders obvious “d) allowing the degradable material to at

least partially degrade after a selected duration such that the plug disappears.”

Claim 4

The method of claim 1, wherein the degradable material ispresent at a concentration of no less than 40 lbm/1,000 gal(4.8 g/L).

171. Gibson states in Example 1 of providing 49 barrels of water for 25 pounds of

formaldehyde which equates to 12.14 lbm/1000 gal. Ex. 1006, Gibson at 3:69-

4:31. Gibson indicates this concentration is 0.15%. Ex. 1006, Gibson at 3:69-

4:31. However, Gibson states more generally that his aldehyde polymer can

be provided in concentrations of 6.0% or more, which is 40 times greater than

the concentration used in Example 1. Ex. 1006, Gibson at 2:45-55. If a


concentration of 6.0% had been used in Example 1, then it would indicate a

concentration of 496 lbm/1,000 gal. to one of skill in the art. Therefore,

Gibson teaches using concentration of no less than 40 lbm/1,000 gal. to those

of skill in the art.


view of Walker renders obvious “wherein the degradable material is present at

a concentration of no less than 40 lbm/1,000 gal. (4.8 g/L).”

Claim 6

The method of claim 1, wherein the slurry furthercomprises a particulate material.

173. Gibson’s fluid can contain both particles of aldehyde polymer and particles of

sand. Ex. 1006, Gibson at 4:8-13 (“59 barrels of water containing 50 pounds

of particulated paraformaldehyde and 2,526 pounds of 20 to 40 mesh sand

dispersed therein.”). The sand would be a particulate material in Gibson’s

slurry.

174. In addition Gibson states the best results are obtained when using both flakes

and a 5 to 200 mesh powder. Ex. 1006, Gibson at 3:29-33. Both flakes and

mesh powders are types of particulate materials. One of these particle types

could be the particulate material reited in claim 6 while the other particle type

is the degradable material recited in claim 1.



view of Walker renders obvious “wherein the slurry further comprises a

particulate material.”

Claim 7

The method of claim 6, wherein the particulate material isdegradable.

176. Both flakes and mesh powders are types of particulate materials which are

degradable. Ex. 1006, Gibson at 3:29-33. One of these particle types could be

the degradable particulate material recited in claim 7 while the other particle

type is the degradable material recited in claim 1.


view of Walker renders obvious “wherein the particulate material is

degradable.”

Claim 13

The method of claim 1, wherein the well treatmentcomprises hydraulic fracturing.

178. Hydraulic fracturing is the use of fluid at high pressure to fracture a formation.

One of skill in the art at the time of the invention understands Gibson’s

statements that using “fracturing fluids” and reaching “fracturing pressure”

describes hydraulic fracturing. Ex. 1006, Gibson at 1:41-58 and 3:46-53.


Gibson also claims using his invention for “hydraulic fracturing.” Ex. 1006,

Gibson at 6:20-35.

179. Gibson also provides an example where he uses a slurry of water, particulated

paraformaldehyde, and sand as fracturing fluid. Ex. 1006, Gibson at 3:69-

4:45.


view of Walker renders obvious “wherein the well treatment comprises

hydraulic fracturing.”

Claim 15

The method of claim 13, wherein hydraulic fracturing isapplied to more than one layer of a multilayer formation.

181. Gibson describes using his aldehyde polymer to plug a more accessible

portion of the formation so that subsequent fluid will be diverted to less

accessible portions of the formation. Ex. 1006, Gibson at 2:20-37, 6:20-34.

One of skill in the art at the time of the invention would understand the

differently accessible portions of the formation to be describing different

layers in the same formation because a single layer would not have differently

accessible portions.

182. One of the treatments Gibson describes in this context of diverting fluid to

less accessible portions is “hydraulic fracturing” which would be understood


as fracturing different layers in a multilayer formation. Ex. 1006, Gibson at

6:20-35.


view of Walker renders obvious “wherein hydraulic fracturing is applied to

more than one layer of a multilayer formation.”

Claims 25 and 26

184. Claim 25 is identical to claim 1, except claim 25 recites in part b) “degradable

material selected from the group consisting of powder, beads, chips, fibers, or

any combination thereof” whereas claim 1 recites “degradable material

selected from the group consisting of powder, beads and chips.” The

preferred solid particles of Gibson are “a 5 to 200 mesh powder” so one of

skill in the art would understand Gibson’s polymer to at least be a powder. Ex.

1006, Gibson 3:29-33.

185. Additionally, claim 25 omits step d) from claim 1 which recites “allowing the


that the plug disappears” which is instead moved to dependent claim 26.

186. Thus my statements as to why claim 1 is rendered obvious by Gibson in view

of Walker are equally applicable to claims 25 and 26 which are incorporated

by reference.


Claim 27

187. Claim 27 is identical to claim 1, except claim 27 omits step d) which in claim

1 recites “allowing the degradable material to at least partially degrade after a

selected duration such that the plug disappears.” Thus my statements as to

why claim 1 is rendered obvious by Gibson in view of Walker are equally

applicable to claim 27 which are incorporated by reference.

C. Claims 2 is rendered obvious by Gibson in view of Erbstoesserand Still

Claim 2

The method of claim 1, wherein the degradable material isselected from a polymer of lactide, glycolide, polylactic acid,polyglycolic acid, amide, and mixtures thereof.

188. As previously discussed, Gibson describes using his invention with solid

polymer particles of aldehyde such as paraformaldehyde, metaldehyde, or

trioxane to form temporary plugs. Ex. 1006, Gibson at 2:56-70, 3:46-53.

These polymers degrade at least in the presence of water at 18° to 25° C. Ex.

1006, Gibson at 2:20-37, 2:56-70; see also Ex. 1009 at 597

(“Paraformaldehyde is temperature degradable and is soluble in both water

and oil.”).

189. By the time of the alleged invention, new particulate materials had been

discovered to use as temporary plugging agents including the lactide,

glycolide, and polylactic acid polymers disclosed in Erbstoesser. Ex. 1004,


Erbstoesser at 4:67-5:2. Erbstoesser’s polymers would degrade in water at 45°

to 200° C. Ex. 1004, Erbstoesser at 4:12-15.

190. Thus, both Gibson’s and Erbstoesser’s materials degrade in water, but

Erbstoesser’s degrade at higher temperatures. Ex. 1006, Gibson at 2:20-37,

2:56-70; Ex. 1004, Erbstoesser at 4:12-15. One of skill in the art at the time of

the invention would have reason to use Erbstoesser’s degradable polymers in

the method of Gibson when trying to temporarily plug wells having downhole

temperatures in the range of 45° to 200° C, which would have become more

common by the time of the invention as wells were being drilled deeper at the

time of the invention compared to wells drilled in 1965 when Gibson was

filed. In addition, one of skill in the art would have used Erbstoesser’s

polymer to reduce formation damage compared to Gibson’s formaldehyde

polymer. Ex. 1004, Erbstoesser at 2:11-16.

191. While the rejection of claim 1 was Gibson in view of Walker, Walker was

only relied on to teach an additive that would accelerate the degradation of

Gibson’s aldehyde polymers. However, when Gibson’s polymers are

substituted with Erbstoesser’s polymers, then Walker’s teaching of an additive

to degrade Gibson’s polymers is no longer needed. Instead, one of skill in the

art at the time of the invention would look for an additive that would

accelerate degradation of Erbstoesser’s polymers. As discussed previously, a


teaching of additives that would accelerate Erbstoesser’s polymers is found in

Still.

192. Still describes increasing the rate of degradation and hydrolysis of polyesters

of the type used in Erbstoesser, including PLA, by the inclusion of solid

additives. Ex. 1015, Still at ¶16. A list of solid additives that would accelerate

the degradation of these polymers include magnesium hydroxide, magnesium

carbonate, dolomite (magnesium calcium carbonate), calcium carbonate,

aluminum hydroxide, calcium oxalate, calcium phosphate, aluminum

metaphosphate, sodium zinc potassium polyphosphate glass, and sodium

calcium magnesium polyphosphate glass. Ex. 1015, Still at ¶17.

193. Similarly, Still describes using liquid additives that would likewise accelerate

the degradation of the polymers used in Erbstoesser including acids, bases, or

sources of acids and bases. Ex. 1015, Still at ¶18.

194. A person of skill in the art would apply the teachings of Still’s accelerating

additive to accelerate the rate of degradation of the polymers taught by

Erbstoesser. One of skill in the art would have reason to use an additive for

accelerating degradation if wellbore conditions were not conducive to

degrading the polymer in a reasonable time (such as low temperature).




the treatment was completed. By the time of the invention, the benefits of

having a plug which would degrade soon after the treatment was completed

was well-known. See Ex. 1009, Harrison Paper at 597 (“The perfect blocking






view of Erbstoesser renders obvious “wherein the degradable material is

selected from a polymer of lactide, glycolide, polylactic acid, polyglycolic

acid, amide, and mixtures thereof.”

Claim 3

The method of claim 2, wherein the well treatmentcomprises chemical stimulation.

197. Gibson describes the use of acidization treatments including for example the

use of HCL to stimulate a well. Ex. 1006, Gibson at 3:54-61, 4:16-21.

Erbstoesser likewise discusses acidizing as a known treatment operation. Ex.

1004, Erbstoesser at 1:16-31.

198. One of skill in the art understands that acidizing treatments are chemical

stimulations used with the methods of Gibson and the degradable polymers of

Erbstoesser.



SRAMI

Text Box