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 IPR2017-01564PATENT 7,775,278
________________________________
DECLARATION OF BRADLEY LEON TODD UNDER 37C.F.R. § 1.68 IN SUPPORT OF PETITION FOR INTER
PARTES REVIEW OF U.S. PATENT NO. 7,775,278
Page 1 of 68 Halliburton Energy Services, Inc.Exhibit 1002
TABLE OF CONTENTS
I. Introduction......................................................................................................1
II. Background Qualifications ..............................................................................4
III. Understanding of Patent Law ........................................................................10
IV. Level of Ordinary Skill in the Pertinent Art..................................................12
V. The ‘278 Patent..............................................................................................14
VI. Background on State of Technology in the Field of the Invention ...............15
VII. Background on the Prior Art References.......................................................26
VIII. Broadest Reasonable Interpretation...............................................................30
IX. The Challenged Claims are Unpatentable .....................................................31
X. Conclusion .....................................................................................................66
Page 2 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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. 7,775,278 (“the ‘278
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, 2, 6, 7,
14, 17, 29, and 31 of the ‘278 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
Page 3 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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 ‘278 patent was filed on February 29, 2008 as Application No.
12/040,517, which indicates it is related to provisional application 60/606,270
filed September 1, 2004.
6. For the purposes of this Declaration, I have been asked to assume that the date
of the alleged invention recited in the ‘278 patent is September 1, 2004, the
date of the provisional application. However, my opinions that one of skill in
the art would find claims 1, 2, 6, 7, 14, 17, 29, and 31 to be anticipated or
rendered obvious would remain the same even if the date of the alleged
invention were later, including up to February 29, 2008, which is the date the
‘278 patent was filed.
7. The face of the ‘278 patent names Dean Willberg, Marina Bulva, Christopher
Fredd, Alexey Vostrukhov, Curtis Boney, John Lassek, Ann Hoefer, and
Philip Sullivan as the inventors for the ‘278 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:
Page 4 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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. 3,954,629 to Scheffel 1005 “Scheffel”
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”
U.S. Patent No. 3,500,929 to Eilers 1010 “Eilers”
“New ‘beads’ help acidizing, fracturing,”
The Oil and Gas Journal, August 30,
1965
1012 “Unibeads Article”
Page 5 of 68 Halliburton Energy Services, Inc.Exhibit 1002
Gruesbeck, C., et al., “Particle Transport
Through Perforations,” Society of
Petroleum Engineers Journal, December
1982
1013 “Gruesbeck”
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,
Page 6 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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
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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
Page 8 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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
Page 9 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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.
Page 10 of 68 Halliburton Energy Services, Inc.Exhibit 1002
• 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.
Page 11 of 68 Halliburton Energy Services, Inc.Exhibit 1002
• 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 that predates September 1, 2004 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
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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
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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 ‘278 patent would have been considered anticipated
or 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 ‘278 patent for
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purposes of this declaration is just prior to September 1, 2004. 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
Page 15 of 68 Halliburton Energy Services, Inc.Exhibit 1002
the viewpoint of a person having ordinary skill in the relevant art, as of the
time of the invention.
V. The ‘278 Patent
A. The Prosecution History
42. From the face of the ‘278 patent, it was filed on February 29, 2008 as U.S.
Application No. 12/040,517 (“the ‘517 application”). Ex. 1001, ‘278 Patent.
43. I have reviewed the prosecution history of the ‘517 application, and I am of
the understanding that claims 1, 2, 6, 7, 14, 17, 28, and 29 of the ‘517
application matured into Challenged Claims 1, 2, 6, 7, 14, 17, 29, and 31 of
the ‘278 patent. See Ex. 1007, Prosecution History at 125-128, 146.
44. Prior to the allowance of any of the Challenged Claims, however, I understand
that U.S. Patent Publication No. 2003/0060374 to Cooke was presented by the
Examiner as having anticipated all of the Challenged Claims. Ex.1007,
Prosecution History at 108.
45. I also understand the Applicant overcame this rejection by arguing in part:
Cooke does not describe allowing the degradable material to at least partially
degrade after a selected duration such that the plug disappears as recited in the
pending independent claims or claims dependent thereon. To be precise,
Cooke at paragraph 50 describes polymer degradation, but it requires new
flow through a damaged zone or new proppant bed and does not describe a
Page 16 of 68 Halliburton Energy Services, Inc.Exhibit 1002
plug disappearing as recited in the pending claims. Cooke recites a polymer
phase in a carrier fluid (paragraph 0021), not a slurry as recited in the pending
independent claims. Ex. 1007, Prosecution History at 129-130.
46. As discussed in detail below, it is my opinion that Erbstoesser, Scheffel, and
Gibson all describe methods of including degradable polymers in a slurry,
where their respective polymers degrade over time due to existing well
conditions and without requiring a new flow of fluid.
VI. Background on State of Technology in the Field of the Invention
A. Fracturing
47. 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.
48. 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.
Page 17 of 68 Halliburton Energy Services, Inc.Exhibit 1002
49. 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.
50. 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.
51. 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.
52. 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.
Page 18 of 68 Halliburton Energy Services, Inc.Exhibit 1002
B. Creating a Plug, Bridge, Seal, or Block
53. 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.
54. 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.
55. 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.
56. 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.
Page 19 of 68 Halliburton Energy Services, Inc.Exhibit 1002
57. 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.
58. 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.
59. 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.
60. 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
Page 20 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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).
61. 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.
Page 21 of 68 Halliburton Energy Services, Inc.Exhibit 1002
62. 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
63. 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.
64. 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.
65. 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
Page 22 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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.
66. 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.
67. 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.
68. 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
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(e.g., by reducing the number of fractures to be performed during the
operation).
69. 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)
70. 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 at 19, left column.
71. In his paper, White describes a process whereby larger granular particles are
forced into a fracture until they form a bridge. Ex. 1008, White 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,
Page 24 of 68 Halliburton Energy Services, Inc.Exhibit 1002
White 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 at 20, left column.
72. An example of this process is illustrated in Figure 2, shown below.
Ex. 1008, White at 20, left column.
73. 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 at 20, right
column.
74. Next, the White details that the most used granular temporary diverting
materials in use in 1958 include naphthalene, walnut shell resin mixture,
Page 25 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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 at 20, right column to 21,
left column.
75. Finally, the White 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 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 at 24.
76. Thus, the White 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)
77. 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
Page 26 of 68 Halliburton Energy Services, Inc.Exhibit 1002
temporary sealing agent, plugging any opening in the well bore through which
fluid will pass.” Ex. 1012, Unibeads Article at 52.
78. 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.
79. 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.
80. 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)
81. 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
Page 27 of 68 Halliburton Energy Services, Inc.Exhibit 1002
additional years before the alleged date of invention of the ‘278 patent). Ex.
1009, Harrison at 593.
82. As Harrison explains, the earliest documented diverting agents were patented
by Halliburton in 1936. Ex. 1009, Harrison 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 at 595-97.
83. Like the Unibeads Article, the Harrison 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 at 597.
84. Thus, the Harrison documents the various options known for diverting
materials and some of the advantages of each.
VII. Background on the Prior Art References
85. 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
86. 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
Page 28 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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.
87. 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.
88. 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
Page 29 of 68 Halliburton Energy Services, Inc.Exhibit 1002
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 Scheffel
89. U.S. Patent No. 3,954,629 to Scheffel et al. (Ex. 1005, Scheffel) entitled
“Polymeric Diverting Agent” was filed on June 3, 1974 and lists John
Scheffel and Paul Fischer as inventors (hereinafter “Scheffel”). Scheffel was
issued on May 4, 1976.
90. Scheffel focused on the problem in the art of temporary plugging and particle
degradation in deep wells at temperatures above 350° F. Ex. 1005, Scheffel at
3: 2-7. Scheffel discloses that a prior art well treatment “commonly requires a
temporary plugging material capable of being formed into small particles . . .”
Ex. 1005, Scheffel at 1:55-65. However, these particles typically don’t
perform well at temperatures above 350° F, which was becoming an issue as
companies drilled wells deeper and deeper. Ex. 1005, Scheffel at 2:41-49.
91. Scheffel solved this problem by using a new, composite particle composition
that that could operate at the higher temperature range having the
composition: “(1) about 5 to 25 weight percent of polyethylene or a
copolymer of ethylene-vinyl acetate . . . ; (2) about 8 to 50 weight percent of a
Page 30 of 68 Halliburton Energy Services, Inc.Exhibit 1002
polyamide . . . ; and (3) about 40 to 70 weight percent of a softening agent
such as long chain aliphatic diamides . . . .” Ex. 1005, Scheffel at 3:14-40.
92. Scheffel used his compounds as “plugging agents in treating and hydraulic
fracturing” and provides an example of such a use. Ex. 1005, Scheffel at 3:44-
50, 12:5-35. In wells at around 350° F, Scheffel’s compound would not
degrade for a short period, but prolonged exposure to oil at that temperature
would substantially degrade the particles so that “no solid residue remains to
plug the oil-bearing strata of the formation.” Ex. 1005, Scheffel at 4:7-15.
93. Scheffel’s particles would be dispersed into a carrier liquid and then injected
into the well to plug the formation prior to a treatment operation, such as
hydraulic fracturing. Ex. 1005, Scheffel at 7:13-38. Scheffel also disclosed
that one could use the particles of his invention in varying sizes and shapes.
Ex. 1005, Scheffel at 7:2-12, 7:56-8:3; 11:20-32.
C. Background of Gibson
94. 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.
95. 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,
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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.
VIII. Broadest Reasonable Interpretation
96. I understand that in an inter partes review proceeding, claims are given their
broadest reasonable interpretation consistent with the specification.
97. 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
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construction and believe it to be consistent with one of ordinary skill in the
art’s understanding of the ‘278 patent, which describes embodiments where
any one of a perforation, fracture, or wellbore are individually plugged. Ex.
1001, ‘278 Patent at 6:50-66 and 13:66-14:2.
IX. The Challenged Claims are Unpatentable
A. Claims 1, 2, 6, 7, 14, 17, 29 and 31 are anticipated or renderedobvious by Erbstoesser
1. Claim 1
A method of well treatment, comprising;
98. 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, providedthe degradable material is present in the slurry as a dispersedmaterial;
99. 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
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the presence of water at an elevated temperature. Ex. 1004, Erbstoesser at 4:6-
60; 3:10-13.
100. 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.
101. In addition to Erbstoesser using the word “dispersed” when referring to the
particles, one of skill in the art at the time of the invention would also
understand the concentration of 1 to 10 pounds of polymer particles to 100
barrels of wellbore fluid would result in a dispersion of the particles in the
wellbore fluid. Ex. 1004, Erbstoesser at 7:6-10.
102. 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.
Page 34 of 68 Halliburton Energy Services, Inc.Exhibit 1002
103. 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.
104. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “injecting a
slurry comprising a degradable material, provided the degradable material is
present in the slurry as a dispersed 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;
105. 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.
106. 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.
107. 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
Page 35 of 68 Halliburton Energy Services, Inc.Exhibit 1002
understands would mean plugging a fracture. Ex. 1004, Erbstoesser at 7:11-
13; see also 6:34-43.
108. 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 at 24 and Ex. 1013, Gruesbeck at 859.
109. 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 at 24 and Ex. 1013, Gruesbeck at 859.
110. 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
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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.
111. 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.
112. 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.”
Page 37 of 68 Halliburton Energy Services, Inc.Exhibit 1002
c) performing a downhole operation; and
113. 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.
114. In light of these disclosures, one of skill in the art at the time of the invention
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.
115. As previously discussed, Erbstoesser uses 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. “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.
116. 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.
Page 38 of 68 Halliburton Energy Services, Inc.Exhibit 1002
117. 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).
118. 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.
119. Thus, 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.
120. 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 for the plug to dissapear. Ex. 1004,
Page 39 of 68 Halliburton Energy Services, Inc.Exhibit 1002
Erbstoesser at 5:4-40. One of skill in the art at the time of the invention
would have altered the degradation rate using knowledge of these factors if
the well needed to be put back into production sooner than 1 day or the plug
was needed to last longer than 7 days.
121. 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 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.”).
122. 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 0 to 1 day 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 duration to ensure the treatment operation will be
completed before Erbstoesser’s plug made of his polymer disappears.
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.
Page 40 of 68 Halliburton Energy Services, Inc.Exhibit 1002
123. In light of these disclosures, one of skill in the art at the time of the invention
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.
124. As previously discussed, Erbstoesser uses 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. “Poly(D, L-lactide)” commonly
known as polylactic acid or PLA for short.
125. In light of these disclosures, one of skill in the art at the time of the invention
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 6
The method of claim 1, wherein the slurry furthercomprises a particulate material.
126. 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
Page 41 of 68 Halliburton Energy Services, Inc.Exhibit 1002
particle sizes could be the particulate material reited in claim 6 while the other
particle size is the degradable material recited in claim 1.
127. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “wherein the
slurry further comprises a particulate material.”
Claim 7
The method of claim 6, wherein the particulate material isdegradable.
128. 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.
129. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “wherein the
particulate material is degradable.”
Claim 14
The method of claim 1, wherein the well treatmentcomprises hydraulic fracturing.
130. 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
Page 42 of 68 Halliburton Energy Services, Inc.Exhibit 1002
time of the invention understands Erbstoesser’s usage of a “fracturing fluid”
to describing hydraulic fracturing. Ex. 1004, Erbstoesser at 6:46-50.
131. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “wherein the
well treatment comprises hydraulic fracturing.”
Claim 17
The method of claim 14, wherein hydraulic fracturing isapplied to more than one layer of a multilayer formation.
132. 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.
133. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “wherein
hydraulic fracturing is applied to more than one layer of a multilayer
formation.”
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Claim 29
134. Claim 29 is identical to claim 1, except in claim 29 “the degradable material is
present in the slurry as a finely divided material” whereas in claim 1 “the
degradable material is present in the slurry as a dispersed material.” Thus my
statements as to why claim 1 is anticipated by Erbstoesser are equally
applicable to claim 29 and are incorporated by reference. For the sole
limitation that is different from claim 1, I provide the additional statements
below.
a) injecting a slurry comprising a degradable material, thedegradable material is present in the slurry as a finelydivided material;.
135. Erbstoesser discloses three different particle size ranges for his polymer
including a size range from 0.1 micron to 100 microns that is described as
“finely divided particles.” Ex. 1004, Erbstoesser at 4:44-60.
136. Erbstoesser also discloses injecting the polymer into the formation, which one
of skill in the art at the time of the invention understands could be any of size
of his polymer, including the finely divided particles. Ex. 1004, Erbstoesser at
7:11-13; see also 6:34-43. The size of the polymer injected would depend on
the size of the opening to be plugged in the formation (e.g., the width of a
fracture) as was known in the art. Ex. 1008, White at 24. Small fractures that
would be plugged by 0.1 to 100 micron particles as well as large fractures that
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would be plugged by the one half inch to inch size particles were known in the
art.
137. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “injecting a
slurry comprising a degradable material, the degradable material is present in
the slurry as a finely divided material.”
Claim 31
138. Claim 31 is identical to claim 1, except in claim 31 it is recited that “injecting
a slurry comprising a degradable material, provided the degradable material
is not in a bulk form” whereas in claim 1 “injecting a slurry comprising a
degradable material, provided the degradable material is present in the slurry
as a dispersed material” is claimed.” Thus my statements as to why claim 1 is
anticipated by Erbstoesser are equally applicable to claim 31 and are
incorporated by reference. For the sole limitation that is different from claim
1, I provide the additional statements below.
a) injecting a slurry comprising a degradable material,provided the degradable material is not in a bulk form;
139. Erbstoesser discloses three different particle size ranges for his polymer. Ex.
1004, Erbstoesser at 4:44-60. These polymers are “dispersed” in the wellbore
fluid. Ex. 1004, Erbstoesser at 3:34-41 and 6:27-30. One of skill in the art at
the time of the invention understands solids dispersed in a liquid are not
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provided in a bulk form. This understanding is consistent with how the ‘278
patent differentiates dispersed solids from those provided in bulk form. Ex.
1001, ‘278 patent at 6:9-12 (“The degradable or dissolvable materials are
preferably present in the treatment fluid as a finely divided or dispersed
material, while not used as a bulk phase or solid bulk form.”).
140. In addition to using the word “dispersed”, one of skill in the art at the time of
the invention would also understand the concentration of 1 to 10 pounds of
polymer particles to 100 barrels of wellbore fluid would result in a dispersion
of the particles in the wellbore fluid that are not provided in bulk form. Ex.
1004, Erbstoesser at 7:6-10.
141. In light of these disclosures, one of skill in the art at the time of the invention
would understand Erbstoesser anticipates or renders obvious “injecting a
slurry comprising a degradable material, provided the degradable material is
not in a bulk form.”
B. Claims 1, 2, 6, 7, 14, 17, 29 and 31 are anticipated or renderedobvious by Scheffel
1. Claim 1
A method of well treatment, comprising;
142. Examples of well treatments that could be used with Scheffel’s invention
include “fracturing, well drilling, acidizing, or solvent treating process.” Ex.
1005, Scheffel at 7:19-22.
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a) injecting a slurry comprising a degradable material, providedthe degradable material is present in the slurry as a dispersedmaterial;
143. Scheffel describes using his invention with “solid particles” of a composite
composition of “(1) about 5 to 25 weight percent of polyethylene or a
copolymer of ethylene-vinyl acetate . . . ; (2) about 8 to 50 weight percent of a
polyamide . . . ; and (3) about 40 to 70 weight percent of a softening agent
such as long chain aliphatic diamides . . . .” Ex. 1005, Scheffel at 3:14-40.
This composite degrades in the presence of oil at temperatures above 350° F.
Ex. 1005, Scheffel at 3:44-50 and at 4:7-15.
144. Scheffel then states the particles being used as plugging agents are dispersed
in the carrier fluid at least when using less than 12 pounds of particles per
gallon of carrier fluid. Ex. 1005, Scheffel at 7:47-55. At this concentration the
suspended particles would be dispersed and not cause the liquid to lose its
fluid characteristics. Ex. 1005, Scheffel at 7:47-55. This carrier fluid can also
include other agents and “solid inorganic particles,” sand being one example.
Ex. 1005, Scheffel at 8:4-15, 12:15-24.
145. 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 Scheffel, his
carrier fluid would be considered a slurry when it contains either the solid
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particles of his degradable composite or the solid inorganic particles. Ex.
1005, Scheffel at 7:47-55, 8:4-15.
146. For hydraulic fracturing operations, the slurry of carrier fluid and dispersed
composite particles would be injected into fractures in the formation. Ex.
1004, Erbstoesser at 7:32-34.
147. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “injecting a slurry
comprising a degradable material, provided the degradable material is present
in the slurry as a dispersed 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;
148. Scheffel expressly states that his composite is used as a “plugging agent” in
hydraulic fracturing. Ex. 1005, Scheffel at 3:44-50. Scheffel then talks about
plugs being created and degrading in the “oil-bearing strata in the formation”
or “oil producing zone”, which are understood to be references to fractures as
fractures are the portion of the formation where the oil is produced before
entering the wellbore. Ex. 1005, Scheffel at 4:7-15 and 12:1:4.
149. Scheffel also states that his plugging step depends on the nature and structure
of the formation. Ex. 1005, Scheffel at 7:39-42; see also 11:39-43. The nature
and structure of the formation is only relevant if plugging a fracture, so it is
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further evidence that at least fractures are plugged by Scheffel’s solid
particles.
150. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel 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
151. Scheffel describes performing a number of downhole operations include
“fracturing, well drilling, acidizing, or solvent treating process.” Ex. 1005,
Scheffel at 7:19-22.
152. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel 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.
153. As previously discussed, Scheffel uses a composite of “(1) about 5 to 25
weight percent of polyethylene or a copolymer of ethylene-vinyl acetate . . . ;
(2) about 8 to 50 weight percent of a polyamide . . . ; and (3) about 40 to 70
weight percent of a softening agent such as long chain aliphatic diamides . . .
.” Ex. 1005, Scheffel at 3:14-40. This composite degrades in the presence of
oil at temperatures above 350° F. Ex. 1005, Scheffel at 3:44-50 and at 4:7-15.
Page 49 of 68 Halliburton Energy Services, Inc.Exhibit 1002
154. In the presence of oil at temperatures above 350° F then over 50% of the
volume of the solid particles forming the plug will degrade in 18 to 72 hours
with the plug being fully degraded after 72 hours. Ex. 1005, Scheffel at 4:2-
15.
155. In Table III, Scheffel provides detailed time frames for the duration when
various compositions of his solid particle composites would degrade. Ex.
1005, Scheffel at 9:61-10:18, Table III. As seen in this table, composite
example 2 would degrade by only 10% after 18 and 36 hours but then have
degraded by 70% after 54 hours. Ex. 1005, Scheffel at 9:61-10:18, Table III.
156. Thus, one of skill in the art at the time of the invention understands a plug
made of Scheffel’s composite would disappear after a selected duration of 18
hours in the well conditions Scheffel intended his composite to be used with,
such as wells having temperatures between around 350° F. Ex. 1005, Scheffel
at 4:2-15, 9:61-10:18, and Table III.
157. One of skill in the art at the time of the invention could also have relied on the
teachings in Scheffel’s Table III to select a duration after which the plug
would dissapear by choosing amongst the different composites. For example,
while a plug formed of composite #2 in Table III only degrades by 10%
within 18 hours, a plug formed of composite #14 would degrade by 75%
within 18 hours. Ex. 1005 at Table III. One of skill in the art at the time of
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the invention would have selected a composite with a specific degradation rate
using Table II if the well needed to be put back into production sooner than 18
hours or the plug was needed to last longer than 18 hours.
158. 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 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.”).
159. In light of Scheffel’s teaching that it can take 18 to 72 hours for a plug made
of his composite particles to dissapear, one of skill in the art at the time of the
invention would have reason to select a duration of 0 to 18 hours for a
treatment operation, such as a fracturing operation, to ensure the operation
will be completed before Scheffel’s plug made of his composite material
degrades. One of skill in the art at the time of the invention would have reason
to select such a duration to ensure the treatment operation will be completed
before Scheffel’s plug made of his solid particle composite disappears.
Otherwise, if the plug disappears before the treatment operation is completed,
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it would prevent diversion of wellbore fluid to create new fractures and
treatment fluid would be lost to existing fractures.
160. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel 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, polylactic acid,polyglycolic acid, amide, and mixtures thereof.
161. As previously discussed, Scheffel uses a composite of “(1) about 5 to 25
weight percent of polyethylene or a copolymer of ethylene-vinyl acetate . . . ;
(2) about 8 to 50 weight percent of a polyamide . . . ; and (3) about 40 to 70
weight percent of a softening agent such as long chain aliphatic diamides . . .”
Ex. 1005, Scheffel at 3:14-40. This composite degrades in the presence of oil
at temperatures above 350° F. Ex. 1005, Scheffel at 3:44-50 and at 4:7-15.
162. Because the composite contains a polyamide, it is a polymer of amide or at
least a mixture made up in part of a polymer of amide.
163. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “wherein the
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degradable material is selected from a polymer of lactide, glycolide, polylactic
acid, polyglycolic acid, amide, and mixtures thereof.”
Claim 6
The method of claim 1, wherein the slurry furthercomprises a particulate material.
164. Scheffel describes incorporating other components or additives, such as “solid
inorganic particles,” in the carrier fluid. Ex. 1005, Scheffel at 8:4-15. As one
example of an inorganic particle, the carrier fluid can contain 20 to 40 mesh
sand particles as a proppant. Ex. 1005, Scheffel at 12:15-24.
165. Scheffel also discloses different sizes and shapes of his composite can be used
at the same time, including flat buttons, 8 to 10 mesh particles, and 1 micron
to 100 mesh particles. Ex. 1005, Scheffel at 11:26-38. One of these particle
sizes or shapes could be the particulate material reited in claim 6 while the
other particle size or shape is the degradable material recited in claim 1.
166. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “wherein the slurry
further comprises a particulate material.”
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Claim 7
The method of claim 6, wherein the particulate material isdegradable.
167. The differently shaped and sized particles of Scheffel’s particles are all
degradable in oil. Ex. 1005, Scheffel at 3:44-50 and 4:7-15. One of these
particle sizes or shapes could be the degradable particulate material reited in
claim 7 while the other particle size or shape is the degradable material recited
in claim 1.
168. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “wherein the
particulate material is degradable.”
Claim 14
The method of claim 1, wherein the well treatmentcomprises hydraulic fracturing.
169. Scheffel explicitly discloses the use of his composite “plugging agents in
treating and hydraulic fracturing.” Ex. 1005, Scheffel at 3:44-50 and 7:31-38.
170. In addition, 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
Scheffel’s example using a “fracturing fluid” to also describe hydraulic
fracturing. Ex. 1005, Scheffel at 12:6-35.
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171. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “wherein the well
treatment comprises hydraulic fracturing.”
Claim 17
The method of claim 14, wherein hydraulic fracturing isapplied to more than one layer of a multilayer formation.
172. Scheffel describes an example where the hydraulic fracturing occurs in a well
“with a total productive interval of 352 feet perforated with two holes per foot
at the depths of 17,205 and 17,357 feet and 17,412 to 17,612 feet.” Ex. 1005,
Scheffel at 12:7-14.
173. One of skill in the art at the time of the invention understands the two
different intervals indicate that two different layers in a formation are being
fractured. The break with no perforations between the two interval signifies
the separation of two oil producing layers with a non-oil producing layer
between them.
174. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “wherein hydraulic
fracturing is applied to more than one layer of a multilayer formation.”
Claim 29
175. Claim 29 is identical to claim 1, except in claim 29 “the degradable material is
present in the slurry as a finely divided material” whereas in claim 1 “the
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degradable material is present in the slurry as a dispersed material.” Thus my
statements as to why claim 1 is anticipated by Scheffel are equally applicable
to claim 29 and are incorporated by reference. For the sole limitation that is
different from claim 1, I provide the additional statements below.
a) injecting a slurry comprising a degradable material, thedegradable material is present in the slurry as a finelydivided material;.
176. Scheffel states that “[t]he solid particle particules used in the practice of this
invention vary widely in size and shape . . . particles having mean diameters
of from about 1 to 50 microns.” Ex. 1005, Scheffel at 7:2-12.
177. Particles in the size range of 1 to 50 microns would have formed a powder and
were considered to be finely divided particles to those of skill in the art. See
Ex. 1004, Erbstoesser at 4:44-60 (“finely divided materials preferably have a
size range from about 0.1 to about 100 microns”).
178. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “injecting a slurry
comprising a degradable material, the degradable material is present in the
slurry as a finely divided material.”
Claim 31
179. Claim 31 is identical to claim 1, except in claim 31 it is recited that “injecting
a slurry comprising a degradable material, provided the degradable material
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is not in a bulk form” whereas in claim 1 “injecting a slurry comprising a
degradable material, provided the degradable material is present in the slurry
as a dispersed material” is claimed.” Thus my statements as to why claim 1 is
anticipated by Scheffel are equally applicable to claim 31 and are incorporated
by reference. For the sole limitation that is different from claim 1, I provide
the additional statements below.
a) injecting a slurry comprising a degradable material,provided the degradable material is not in a bulk form;
180. Scheffel gives an example where the particles are dispersed in the carrier fluid
using less than 12 pounds of particles per gallon of carrier fluid. Ex. 1005,
Scheffel at 7:47-55. At this concentration the solid particles make up a
suspension in the liquid and do not cause the liquid to lose its fluid
characteristics. Ex. 1005, Scheffel at 7:47-55.
181. One of skill in the art at the time of the invention understands solids dispersed
in a liquid are not provided in a bulk form. This understanding is consistent
with how the ‘278 patent differentiates dispersed solids from those provided
in bulk form. Ex. 1001, ‘278 patent at 6:9-12 (“The degradable or dissolvable
materials are preferably present in the treatment fluid as a finely divided or
dispersed material, while not used as a bulk phase or solid bulk form.”)..
182. In light of these disclosures, one of skill in the art at the time of the invention
would understand Scheffel anticipates or renders obvious “injecting a slurry
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comprising a degradable material, provided the degradable material is not in a
bulk form.”
C. Claims 1, 6, 7, 14, 29 and 31 are anticipated by Gibson
1. Claim 1
A method of well treatment, comprising;
183. 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 a well comprising a degradable material,provided the degradable material is present in the slurry as adispersed material;
184. 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 at 597
(“Paraformaldehyde is temperature degradable and is soluble in both water
and oil.”)
185. 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.
186. 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
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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.
187. 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.
188. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “injecting a slurry comprising a
degradable material, provided the degradable material is present in the slurry
as a dispersed 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;
189. 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.
190. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “allowing the degradable material to
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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
191. 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.
192. In light of these disclosures, one of skill in the art at the time of the invention
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.
193. 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. Ex. 1006, Gibson at 2:20-37 and 2:56-70; see also
Ex. 1009, Harrison at 597 (“Paraformaldehyde is temperature degradable and
is soluble in both water and oil.”).
194. 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
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Table which shows significant injection rate increases in each treated well
seven days after treatment. Ex. 1006, Gibson at 5:4-40.
195. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “d) allowing the degradable material to
at least partially degrade after a selected duration such that the plug
disappears.”
Claim 6
The method of claim 1, wherein the slurry furthercomprises a particulate material.
196. 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.
197. 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.
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198. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “wherein the slurry further comprises a
particulate material.”
Claim 7
The method of claim 6, wherein the particulate material isdegradable.
199. 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 reited in claim 7 while the other particle
type is the degradable material recited in claim 1.
200. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “wherein the particulate material is
degradable.”
Claim 14
The method of claim 1, wherein the well treatmentcomprises hydraulic fracturing.
201. 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.
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Gibson also claims using his invention for “hydraulic fracturing.” Ex. 1006,
Gibson at 6:20-35.
202. 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.
203. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “wherein the well treatment comprises
hydraulic fracturing.”
Claim 17
The method of claim 14, wherein hydraulic fracturing isapplied to more than one layer of a multilayer formation.
204. 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.
205. One of the treatments Gibson describes in this context of diverting fluid to
less accessible portions is “hydraulic fracturing” which would be understood
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as fracturing different layers in a multilayer formation. Ex. 1006, Gibson at
6:20-35.
206. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “wherein hydraulic fracturing is applied
to more than one layer of a multilayer formation.”
Claim 29
207. Claim 29 is identical to claim 1, except in claim 29 “the degradable material is
present in the slurry as a finely divided material” whereas in claim 1 “the
degradable material is present in the slurry as a dispersed material.” Thus my
statements as to why claim 1 is anticipated by Gibson are equally applicable
to claim 29 and are incorporated by reference. For the sole limitation that is
different from claim 1, I provide the additional statements below.
a) injecting a slurry comprising a degradable material, thedegradable material is present in the slurry as a finelydivided material;.
208. Gibson states that the aldehyde polymer is preferably “a mixture of about 5%
by weight flake and the balance to make 100% of a 5 to 200 mesh powder.”
Ex. 1006, Gibson at 3:29-33.
209. Particles in the size range of 1 to 100 microns would have formed a powder
and were considered to be finely divided particles to those of skill in the art.
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210. This understanding is further corroborated by other patents which refer to
Gibson as employing “finely divided aldehyde particles.” Ex. 1010, Eilers at
1:65-70 (“Other advantages over compositions now employed, including the
composition disclosed in US Patent No. 3,353,604 [to Gibson], are (a) larger
aldehyde polymer particles are employed thus alleviating handling and
irritation problems caused by the toxic nature of finely divided aldehyde
powders . . . ”).
211. This understanding is also corroborated by other prior art before the time of
the alleged invention which describe 0.1 to 100 micron solid particles as
finely divided materials. See Ex. 1004 at 4:44-60 (“finely divided materials
preferably have a size range from about 0.1 to about 100 microns”).
212. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “injecting a slurry comprising a
degradable material, the degradable material is present in the slurry as a finely
divided material.”
Claim 31
213. Claim 31 is identical to claim 1, except in claim 31 it is recited that “injecting
a slurry comprising a degradable material, provided the degradable material
is not in a bulk form” whereas in claim 1 “injecting a slurry comprising a
degradable material, provided the degradable material is present in the slurry
Page 65 of 68 Halliburton Energy Services, Inc.Exhibit 1002
as a dispersed material” is claimed.” Thus my statements as to why claim 1 is
anticipated by Gibson are equally applicable to claim 31 and are incorporated
by reference. For the sole limitation that is different from claim 1, I provide
the additional statements below.
a) injecting a slurry comprising a degradable material,provided the degradable material is not in a bulk form;
214. 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.
215. One of skill in the art at the time of the invention understands solids dispersed
in a liquid are not provided in a bulk form. This understanding is consistent
with how the ‘278 patent differentiates dispersed solids from those provided
in bulk form. Ex. 1001, ‘278 patent at 6:9-12 (“The degradable or dissolvable
materials are preferably present in the treatment fluid as a finely divided or
dispersed material, while not used as a bulk phase or solid bulk form.”).
Gibson also provides a concentration of “[b]etween 0.1% and 6.0% by weight
of the portion of the aqueous fluid with which the aldehyde polymer is
admixed is recommended,” indicating a concentration where that the aldehyde
particles are not provided in a bulk form. Ex. 1006 at 2:45-55.
216. In light of these disclosures, one of skill in the art at the time of the invention
would understand Gibson anticipates “injecting a slurry comprising a
degradable material, provided the degradable material is not in a bulk form.”
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D. Claim 2 is rendered obvious by Gibson in view of Erbstoesser
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.
217. 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.”).
218. 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.
219. 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
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