DECLARATION OF ALI DANESHY
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`1. My name is Ali Daneshy. I am over the age of twenty-one (21) years,
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`of sound mind, and capable of making the statements set forth in this Declaration.
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`I am competent to testify about the matters set forth herein. All the facts and
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`statements contained herein are within my personal knowledge and they are, in all
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`things, true and correct.
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`2.
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`I have been asked by Baker Hughes Incorporated (“Baker Hughes”) to
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`submit this declaration in support of its challenge to the validity of certain claims
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`of U.S. Patent No. 8,657,009 (“the ’009 Patent”).
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`I.
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`Education and Experience
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`3. My curriculum vitae is attached as Exhibit 1.
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`4.
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`I received a Master of Science Degree in Mining Engineering from
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`the University of Tehran in 19641, a Master of Science Degree in Mineral
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`Engineering (Rock Mechanics) from the University of Minnesota in 1968, and a
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`Ph.D. in Mining Engineering (Rock Mechanics) from the University of Missouri-
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`Rolla in 1969.
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`1 At that time, the University of Tehran did not offer a bachelor’s degree in
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`engineering.
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`1. My name is Ali Daneshy. I am over the age of twenty-one (21) years,
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`of sound mind, and capable of making the statements set forth in this Declaration.
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`I am competent to testify about the matters set forth herein. All the facts and
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`statements contained herein are within my personal knowledge and they are, in all
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`things, true and correct.
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`2.
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`I have been asked by Baker Hughes Incorporated (“Baker Hughes”) to
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`submit this declaration in support of its challenge to the validity of certain claims
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`of U.S. Patent No. 8,657,009 (“the ’009 Patent”).
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`I.
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`Education and Experience
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`3. My curriculum vitae is attached as Exhibit 1.
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`4.
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`I received a Master of Science Degree in Mining Engineering from
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`the University of Tehran in 19641, a Master of Science Degree in Mineral
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`Engineering (Rock Mechanics) from the University of Minnesota in 1968, and a
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`Ph.D. in Mining Engineering (Rock Mechanics) from the University of Missouri-
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`Rolla in 1969.
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`1 At that time, the University of Tehran did not offer a bachelor’s degree in
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`engineering.
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`5.
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`I have more than 45 years of industry experience as a geo-mechanical
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`engineer primarily in technology and operations of hydraulic fracturing. I began
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`my career with Halliburton Company in 1969 and held numerous technology and
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`management positions at Halliburton for the next 29 years in areas such as well
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`stimulation, geo-mechanics, produced water management, software development,
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`fluid mechanics, intelligent completions, under-balanced drilling, on-site data
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`acquisition systems, etc. Each of the management positions I held at Halliburton
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`was created as a result of the growth of my previous projects.
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`6.
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`I started at Halliburton’s Duncan, Oklahoma Research Center in 1969
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`as a research engineer performing research related to hydraulic fracturing. During
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`this time, I developed a fracture design software named PROP that became a
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`widely used fracture design program. PROP was used thousands of times annually
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`to assist operators all over the world in planning and executing successful
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`fracturing treatments.
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`7.
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`In 1972, I was promoted to Group Leader of a new research group.
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`As Group Leader, I led a team of 15-20 engineers in research related to hydraulic
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`fracturing and other related fields (e.g., reservoir engineering, fluid mechanics).
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`The success of this research justified greater resources and, in 1975, I was
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`promoted to Section Supervisor, where I led a team of 30-50 engineers. During
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`this time, our team focused on several main projects: (1) on-site fracturing data
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`acquisition software development, (2) engineering research, (3) computerized
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`equipment used in the oil and gas field, (4) reservoir engineering, and (5) hydraulic
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`fracturing.
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`8.
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`The third of these projects was considered by many to be
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`revolutionary at the time. It involved on-site, computerized data acquisition and
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`analysis during hydraulic fracturing operations, primarily in oil and gas -bearing
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`wells. The results of this data analysis could be given to the customer at the well
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`site. No other company was performing this service at the time. In addition to
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`these developments, I helped develop curriculum and materials for training
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`regarding hydraulic fracturing and stimulation at Halliburton, which were used to
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`train engineers primarily in the field.
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`9.
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`In 1983, I was promoted to Department Manager of Reservoir
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`Research and Engineering, and was responsible for the performance of 40-50
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`engineers who were in my department. Much of the research performed by my
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`department during this time related to improving the technology of hydraulic
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`fracturing, and the use of computer technology, in order to increase production of
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`oil and gas wells and the efficiency of fracturing operations. For example, my
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`team developed equipment for automated mixing of fracturing fluids—composed
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`of additives and other chemicals—via computer control rather than manually.
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`These developments increased the effectiveness and decreased the cost of
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`fracturing treatments.
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`10.
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`I also worked with Halliburton during this time to advise and develop
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`technologies used by oil and gas companies in performing the first commercial
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`hydraulic fracturing operations in horizontal wells, including the very first—drilled
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`by Maersk Oil in 1987. In this capacity, I became familiar with the pioneering
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`“Perforate, Stimulate, Isolate” (“PSI”) system developed by Baker Oil Tools,
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`which reduced the time to create multiple fractures in a single wellbore from weeks
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`to days.
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`11.
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`In 1989, I formed and led Halliburton’s European Research Center
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`dedicated to oil and gas operations in the Eastern Hemisphere. While in this
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`capacity, I continued to develop technologies used by Maersk and others to
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`improve the production and efficiency of hydraulic fracturing of horizontally
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`drilled wells, including those used to overcome logistical challenges.
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`12.
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`In 1993, I became the Regional Technical Manager for Halliburton in
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`Europe and Africa, while I also advised customers in the Middle East and Asia
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`Pacific regions. As Regional Technical Manager, I worked directly with
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`operations engineers and personnel to help them implement various Halliburton
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`services, including services related to stimulation methods in horizontal wells.
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`Some of my responsibilities included ensuring that new engineers were properly
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`trained and had access to the most up-to-date technology and resources, and
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`promoting development of new technologies and methods to increase production
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`from oil and gas reservoirs.
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`13.
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`In 1996, I was promoted to Vice President of Integrated Technology
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`Products and moved to Houston, Texas. While in this capacity, I was responsible
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`for integrating leading-edge technologies into the oil and gas services business,
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`including underbalanced drilling, multi-lateral wells, advanced data management
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`techniques, intelligent completions, water control, and more.
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`14.
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`I retired from working at Halliburton in 1999, and formed a private
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`engineering consulting company where I continue to work as a technical advisor
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`and consultant to oil and gas companies, and oil and gas services companies,
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`throughout the world. My services include consultations regarding production
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`stimulation and hydraulic fracturing of vertical and non-vertical wells, well
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`completions, unconventional and
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`low permeability reservoir planning and
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`development, and reservoir stimulation.
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`15. Shortly after retiring from Halliburton, in 2004 I became director of
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`the Petroleum Engineering Program at the University of Houston and, while in this
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`position, initiated the establishment of an undergraduate petroleum engineering
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`curriculum. I continue to teach as an adjunct professor at the University of
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`Houston to this day. I have also been a guest lecturer on topics related to well
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`completion and fracturing at many universities in the United States and abroad, and
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`have served on Ph. D. advisory boards and committees.
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`16. During my career, I have authored more
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`than 45
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`technical
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`publications and 15 papers related to technology management and creativity, which
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`are listed in my attached curriculum vitae, as well as book chapters, on the subject
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`of hydraulic fracturing. I am also the publisher and co-Editor-in-Chief of a
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`quarterly journal called “HFJ” (Hydraulic Fracturing Journal) dedicated entirely to
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`the dissemination of the latest hydraulic fracturing technologies.
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`17.
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`I have also received several awards and served in various positions—
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`including multiple chairman positions—on a large number of committees and
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`boards related to petroleum engineering. These positions and awards are listed in
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`my curriculum vitae. Notable positions include Director At Large on the Society
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`of Petroleum Engineers’ (“SPE”) Board of Directors, including two chair
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`positions, and Chairman of the Journal of Petroleum Technology Roundtable.
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`Notable awards include both the SPE Distinguished Member Award and the SPE
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`Distinguished Service Award for contributions to hydraulic fracturing, as well as
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`being named a SPE Distinguished Lecturer in 2004.
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`18. Having the above knowledge and experience, I am well qualified to
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`offer the opinions I express in this declaration.
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`II. Compensation
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`19.
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`In consideration for my services, my work on this case is being billed
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`to Baker Hughes at an hourly rate of $562.50 per hour, independent of the outcome
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`of this proceeding. I am also being reimbursed for reasonable expenses I incur in
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`relation to my services provided for this proceeding.
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`III. Legal Considerations
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`20. My understanding of the law is based on information provided by
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`counsel for Baker Hughes.
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`21.
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`I understand that a claimed invention is obvious and, therefore, not
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`patentable if the subject matter claimed would have been considered obvious to a
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`person of ordinary skill in the art at the time that the invention was made. I
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`understand that there must be some articulated reasoning with some rational
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`underpinning to support a conclusion of obviousness. I further understand that
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`exemplary rationales that may support a conclusion of obviousness include:
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`(1) simply arranging old elements in a way in which each element performs the
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`same function it was known to perform, and the arrangement yields expected
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`results, (2) merely substituting one element for another known element in the field,
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`and the substitution yields no more than a predictable result, (3) combining
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`elements in a way that was “obvious to try” because of a design need or market
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`pressure, where there was a finite number of identified, predictable solutions,
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`(4) whether design incentives or other market forces in a field prompted variations
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`in a work that were predictable to a person of ordinary skill in the art, and (5) that
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`some teaching, suggestion, or motivation in the prior art would have led one of
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`ordinary skill in the art to modify the prior art reference or to combine prior art
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`references to arrive at the claimed invention, among other rationales.
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`IV. Task Summary
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`22.
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`I have been asked to review the challenged U.S. patent: the ’009
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`Patent. I have been asked to provide my opinions from the perspective of a person
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`of ordinary skill, having knowledge of the relevant art, as of August 21, 2002, and,
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`with the exception of the below explanation of Flores, which I have been asked to
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`consider as of July 5, 2010, the opinions stated in this declaration are from that
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`perspective. The qualifications and abilities of such a person are described in
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`paragraphs 45-55 below. I have also been asked to consider whether any of my
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`opinions would change if the date were, for all purposes, July 5, 2010 instead of
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`August 21, 2002. The considerations on which my opinions are based would have
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`only changed in ways that further reinforce my opinions as explained in this report.
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`For example, any changes during this intervening time period would have only
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`increased the knowledge of a POSITA and therefore made the des cribed
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`combinations and modifications of prior references more straightforward rather
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`than less so.
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`23.
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`In preparing this declaration, I have considered this patent in its
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`entirety and the general knowledge of those familiar with the field of oil and gas
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`completion and stimulation, and specifically systems for completion and
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`stimulation, as of August 21, 2002.
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`24.
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`I have also reviewed the references in their entirety that form the basis
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`for Baker Hughes’ challenge to the ’009 Patent, including the publications listed in
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`the following table:
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`Short Title
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`Publication
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`’009 Patent U.S. Patent No. 8,657,009
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`Thomson
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`D.W. Thomson, et al., Design and Installation of a Cost-
`Effective Completion System for Horizontal Chalk Wells Where
`Multiple Zones Require Acid Stimulation, SPE (Society for
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`Petroleum Engineering) 37482 (1997)
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`Hartley
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`U.S. Patent No. 5,449,039
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`Ellsworth
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`B. Ellsworth, et al., Production Control of Horizontal Wells in
`a Carbonate Reef Structure, 1999 Canadian Institute of
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`Mining, Metallurgy and Petroleum Horizontal Well Conference
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`Echols
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`U.S. Patent No. 5,375,662
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`Flores
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`U.S. Patent No. 8,215,411
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`Hutchison
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`U.S. Patent No. 4,099,563
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`Lagrone
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`K.W. Lagrone, et al., A New Development in Completion
`Methods, SPE 530-PA (1963)
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`Kilgore
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`U.S. Patent No. 6,257,338
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`Weitz
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`U.S. Patent No. 4,279,306
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`Whiteley
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`U.S. Patent No. 6,006,838
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`Eberhard
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`
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`M.J. Eberhard, et al., Current Use of Limited-Entry Hydraulic
`Fracturing in the Codell/Niobrara Formations—DJ Basin, SPE
`(Society for Petroleum Engineering) 29553 (1995)
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`V.
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`Field of Technology
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`25. The ’009 Patent describes a method and apparatus for selectively
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`stimulating or treating multiple segments of an oil well using ball-actuated sleeves
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`to open and close ports through a tubing string. See ’009 Patent at 1:21-24, 2:34-
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`3:9. Stimulation or treatment of a well generally involves injecting fluid at
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`sufficiently high pressure into a well to create fractures in the formation, which
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`increase the flow of oil and gas from the formation into the wellbore.
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`A. Wellbore Construction and Completion
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`26. A well is formed by drilling a hole into a geological formation with
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`oil or gas reserves to form a “wellbore.” Such wellbores include at least one
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`vertical portion descending downward from the earth’s surface, and may include
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`one or more horizontal portions that extend outward from the vertical portion to
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`maximize the length of the wellbore that is within and able to receive oil and gas
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`from an oil-bearing formation.
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`27. Horizontal drilling became widespread in the 1990s and has been one
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`of the primary drivers behind the increased production of oil and gas in the United
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`States over the past two decades. Oil and gas reservoirs (e.g., shale plays) are
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`typically found in horizontal strata. Horizontal drilling allows drillers to reduce the
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`footprint of oil and gas field development and increase the length of the “pay zone”
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`that is intersected by the wellbore so that the overall production of the well would
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`increase. Horizontal drilling is particularly useful in shale formations, which do
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`not have sufficient permeability to produce economically with a vertical well.
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`28. After a wellbore is formed, it is often lined with pipe or “casing” that
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`can help to protect the wellbore from erosion and maintain its stability during
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`various well operations, such as when oil and gas is extracted from the formation
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`and/or when fluids are injected into the wellbore as described in more detail below.
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`In cased completions, casing (or liner) is cemented—the annulus between the
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`casing and the wall of the wellbore is filled with cement—to (i) protect the
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`environment and near-surface formations from leakage of reservoir fluids,
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`(ii) improve wellbore stability, (iii) control the location of fracture initiation, as
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`described below, and (iv) provide greater well serviceability, among other benefits.
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`Casing also provides a smooth, round surface that devices called “packers” can
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`seal against to isolate segments of the wellbore, as also described below. After
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`casing is installed in a wellbore, openings through the casing are created within
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`hydrocarbon-bearing strata—in a process known in the art as “perforating”—to
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`allow oil and/or gas to flow from the formation into the wellbore. See, e.g., ’009
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`Patent at 1:32-34 (Background of the Invention section).
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`29.
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`In some applications, a portion of a wellbore in a production zone is
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`not cased. Such an uncased wellbore is often referred to as an “open hole” and,
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`due to the absence of casing, provides direct access to a hydrocarbon-containing
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`formation. As explained in the Background of the Invention section of the ’009
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`Patent, the lack of casing “expose[s] porosity and permit[s] unrestricted wellbore
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`inflow of petroleum products.” ’009 Patent at 1:28-32. At least as early as 1999,
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`such “[o]pen hole completions ha[d] been the accepted practice for horizontal
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`wells” in at least some areas. See B. Ellsworth, et al., Production Control of
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`Horizontal Wells in a Carbonate Reef Structure, 1999 Canadian Institute of
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`Mining, Metallurgy and Petroleum Horizontal Well Conference (“Ellsworth”) at
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`p. 1, Abstract; U.S. Patent No. 5,375,662 (“Echols”) at 1:25-34. In certain
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`formations, the zone might be left entirely bare, or alternatively include some sand -
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`control and/or flow-control equipment. See, e.g., Echols at 1:25-34. Unlike cased-
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`hole completions, open-hole completions generally do not require perforating of
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`the wellbore wall prior to stimulation operations. Such open-hole completions
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`tend to be popular in horizontal wells, in which cemented installations are more
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`expensive and technically more difficult. See Echols at 1:25-34; Ellsworth at 9
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`(“The goal of cost effective use of horizontals can be enhanced with the ability to
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`segment, and control production without the need to run and cement liners.”).
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`30.
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`It is common in both cased and “open hole” completions for a small-
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`diameter pipe generally referred to in the art as “production tubing” to be installed
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`or “run” into the well to provide a path for petroleum products to flow to the
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`surface.
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`31. Historically, petroleum products were produced from a formation
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`thanks to the formation’s high natural formation pressure and permeability. More
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`recently, when natural formation permeability is not high enough, a well may be
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`stimulated to enlarge or create new channels within the formation to allow oil and
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`gas to flow through the formation and into the wellbore. See ’009 Patent at
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`1:35-36.
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`B. Well Stimulation and Treatment
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`32. A well may be stimulated by pumping a mixture of fluid and
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`additives, such as acid, into the wellbore under pressure. At sufficiently high
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`pressures, the stimulation fluid fractures or “fracs” the formation, which forms
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`cracks radiating outward from the wellbore into the formation. In “frac’ing,” the
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`stimulation fluid typically includes a “proppant” to “prop” open the cracks. Sand
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`is one type of proppant. Other proppant types include ceramic particles. In a
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`related technique for well stimulation, which may be referred to in the art as
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`“acidizing,” an appropriate acid is pumped into the formation which chemically
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`reacts with the formation to create similar conductive channels.
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`33. A wellbore will typically intersect or cross multiple sections or
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`“zones” of a formation. Not all intersected zones include oil and gas. See, e.g.,
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`Ellsworth at Figures 7 and 11. Some zones include fluids like water that can be
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`problematic if they enter the wellbore. Ellsworth at 2-3 (“[W]ater or gas
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`breakthrough can be a problem for some of these wells. . . . The ability to establish
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`long term isolation of segments within the reservoir is key to controlling and
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`optimizing production from these horizontal wells.”). Some zones may be too
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`small to justify the expense of attempting to produce oil and gas from the zone. It
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`is therefore often better to isolate the wellbore from these types of undesirable
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`zones and stimulate only desirable zones.
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`34. One example of a stimulation technique that is commonly used in
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`horizontal wells with cemented casings is known as “Plug & Perf.” This technique
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`involves pumping down the wellbore a bridge plug and perforating guns to a
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`targeted location in the well, typically starting near the bottom or “toe” and moving
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`toward the “heel”—where the wellbore transitions from horizontal to vertical. The
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`perforating guns are fired to punch small holes in the casing to allow fluid
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`communication between the casing and the formation. The perforating guns are
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`then removed from the wellbore, and a ball is pumped down to close the pre-set
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`bridge plug. Once the plug is closed, fracture stimulation fluid (including
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`proppant) is pumped into the wellbore, where the plug seals lower portions of the
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`well and diverts the fracture fluids through the perforations to create fractures in
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`the formation. After each zone (or stage) is completed, the operation is
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`sequentially repeated up-hole until all desired wellbore zones are fractured. The
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`bridge plugs and balls are then milled to open the wellbore and allow oil and gas to
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`flow to the surface. In this “Plug & Perf” approach, the bridge plugs are used to
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`isolate zones within the wellbore.
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`35. Other approaches use “packers” instead of bridge plugs for isolating
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`zones. Packers are tools that seal around production tubing or liner in the wellbore
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`(whether cased or uncased) to direct stimulation fluid into a desired zone and
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`prevent its entry into other zones. A single tubing string can include multiple
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`packers as it is run into the wellbore, making it easier to isolate multiple zones at
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`once and then stimulate those zones.
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`36. One example of a system for stimulating or treating zones of a
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`formation using packers is described in U.S. Patent No. 4,099,563 (“Hutchison”).
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`As shown in Hutchison’s Figures 2 and 4, inset below, Hutchison injects treatment
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`fluids through sleeves 20, 21 [blue], each of which includes a seat 44 [purple] that
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`is designed to mate with and be sealed by a specific sized ball [green]. Hutchison
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`at 3:64-4:59. The sleeve 20 is opened by “dropping” the correspondingly sized
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`ball 48 into the tubing string to seal against seat 44. Hutchison at 4:49-59. This
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`seal prevents fluid from passing through the seat, and the resulting buildup of fluid
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`pressure shifts the lower sleeve 20 down into the open position, as shown in Figure
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`4, to open the port (annular chamber 36) and allow stimulation fluid (steam) to
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`flow into the tubing string. Hutchison at 4:49-59.
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`Sleeve [blue]
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`
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`Seat (44)
`[purple]
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`Seat (44)
`[purple]
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`Ball (48) [green]
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` Sleeve [blue]
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`37. As shown in Hutchison’s FIG. 1, inset below, upper and lower sleeves
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`20 and 21 are positioned to inject stimulation fluid into corresponding zones that
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`are isolated with cup-type packers 22, 23, 24, and 25 to isolate zones within the
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`formation. See Hutchison at FIG. 1 and 2:51-58.
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`38. A ball is first dropped
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`into the tubing string to open lower
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`sleeve
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`20
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`[blue]
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`to
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`allow
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`Packer
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`stimulation fluid to be injected into
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`the
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`lower zone
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`that is isolated
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`between packer cups 22 and 23
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`[red]. Once the lower zone is
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`treated, a larger ball 48 is dropped
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`Packer
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`Packer
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`Sleeve
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`into the tubing string to open upper
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`sleeve 21 [blue] (which differs from
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`sleeve 20 only in that sleeve 21
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`includes a larger diameter seat 44)
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`to allow the upper zone between
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`packer cups 22 and 23 to be treated.
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`Hutchison at 4:60-6:17. A person
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`of ordinary skill in the art would
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`have recognized that this process
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`could be repeated for any suitable
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`number of zones, limited only by
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`the number of different sized balls
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`that can fit into the tubing string. In this way, Hutchison permits zones to be
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`selectively treated one at a time.
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`39. Halliburton developed another example of this system in the late
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`1990s in which multiple sliding sleeves were isolated between packers that could
`
`be simultaneously run into the wellbore. See, e.g., D.W. Thomson, et al., Design
`
`and Installation of a Cost-Effective Completion System for Horizontal Chalk Wells
`
`Where Multiple Zones Require Acid Stimulation, SPE (Society for Petroleum
`
`Engineering) 37482 (1997) (“Thomson”). Relative to approaches like Plug & Perf,
`
`described above, Thomson’s ball-actuated, sliding-sleeve “technique provided a
`
`substantial reduction in the operational time normally required to stimulate
`
`multiple zones and allowed the stimulations to be precisely targeted within the
`
`reservoir.” Thomson at 97, Abstract.
`
`C. Limited Entry
`
`40.
`
`In some applications, it is desirable to stimulate a single zone in
`
`multiple places, or multiple zones, simultaneously. Simultaneous stimulation can
`
`be achieved with a technique known as “limited entry” that involves selecting the
`
`number and size of clusters of perforations spaced along a tubing string to create a
`
`desired distribution of fluid as it is injected simultaneously through the tubing
`
`string. When injecting fluid through multiple perforations spaced along the length
`
`of the tubing string (rather than through a single perforation or multiple
`
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`Page 19 of 58
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`
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`perforations at a single point along the length), friction can cause fluid to enter all
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`or most of the perforations. Used since at least as early as 1963, the number and
`
`size of perforations can be balanced with the injection rate to create high
`
`perforation friction and wellbore pressures if most perforations are not accepting
`
`fluid. A New Development in Completion Methods, SOCIETY OF PETROLEUM
`
`ENGINEERING, Paper 530-PA (1963) (“Lagrone”) (stating that proper stimulation
`
`“can be accomplished by limiting the number and diameter of the perforations in
`
`the casing”). A greater number of perforations results in a larger cross-sectional
`
`area through which fluid can flow at one point along the length of the tubing string,
`
`relative to the cross-sectional areas through which fluid flows at another point
`
`along the length of the wellbore (via fewer or smaller perforations or ports). As
`
`recognized in the Background of the Invention section of the related U.S. Patent
`
`No. 7,134,505 (the “’505 Patent”), it was also known to combine limited entry with
`
`selective treatment methods. See ’505 Patent at 1:53-57 (“Other procedures for
`
`stimulation treatments use foam diverters, gelled diverters, and/or limited entry
`
`. . . .” (emphasis added)); see also U.S. Patent No. 6,006,838 (“Whiteley”) at 5:43-
`
`47 (“The number and size of nozzle ports 58 may vary from module to module
`
`depending on the fluid flow characteristics required for the stimulation treatment at
`
`each desired producing zone.”); see also ’009 Patent at 1:62-2:9 (describing
`
`limited entry procedures in Background Of The Invention section).
`
`
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`
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`41. When employing simultaneous or selective stimulation methods, a
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`tubing string is often run into the wellbore with its ports closed. See, e.g.,
`
`Thomson at 97 (“The key element of the system is a multi-stage acid frac tool
`
`(MSAF) that is similar to a sliding sleeve circulating device and is run in the closed
`
`position.”). In particular, in selective stimulation, sliding sleeves have often been
`
`used to prevent fluid communication with the wellbore during run-in of the tubing
`
`string. See, e.g., Hutchison at 4:49-6:17. Similarly, in simultaneous stimulation,
`
`an unperforated liner was often run into the tubing string and perforated after being
`
`set using methods such as “Plug & Perf,” described above.
`
`D. Types of Packers
`
`42. While Hutchison used cup-type packers to isolate zones within a
`
`formation (Hutchison at 2:51-58), other types of packers have also been known for
`
`many years. For example, inflatable packers have long been used in both open
`
`hole and cased completions. See, e.g., Echols at 1:43-44 (“Inflatable packers are
`
`preferred for use in sealing an uncased well bore.”); see also ’009 Patent at 1:48-50
`
`(Background “[I]nflatable packers may be limited with respect to pressure
`
`capabilities as well as durability under high pressure conditions.”).
`
`43. Other alternatives include various “solid body packers.” Solid body
`
`packers (SBPs) extrude one or more resilient packing elements outward by
`
`compressing the packing element(s) along the length of the tubing string, thereby
`
`
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`Page 21 of 58
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`
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`causing the packing element(s) to be squeezed radially outward to seal the annulus
`
`around the tubing string within the wellbore. As explained in Ellsworth,
`
`“[a]lthough the expansion ratios for [solid body packers] are [not] as large as for
`
`inflatables, the carbonate formation in Rainbow Lake generally drills very close to
`
`gauge hole, and effective isolation is possible with these SBPs.” Ellsworth at 3. In
`
`another example, U.S. Patent No. 6,257,338 (“Kilgore”) explains that its packers,
`
`“sealing devices 30, 32, 34 are representatively and schematically illustrated . . . as
`
`inflatable packers . . . [o]f course, other types of packers, such as production
`
`packers settable by pressure, may be utilized for the packers 30, 32, 34 . . . .” See
`
`Kilgore at 4:35-42. Many such solid-body packers are hydraulically “set” by
`
`delivering hydraulic fluid under pressure to a piston that compresses the packing
`
`element(s). See, e.g., Ellsworth at 3; Kilgore at 4:35-42.
`
`44. Ellsworth also explains that even though “[h]istorically, inflatable
`
`packers were used for water shut-off, stimulation, and segment testing,” “[m]ore
`
`recently, solid body packers (SBP’s) (see Figure 4) have been used to establish
`
`open hole isolation.” Ellsworth at 3. Ellsworth’s solid body packers “provide a
`
`mechanical packing element that is hydraulically actuated . . . to provide a long-
`
`term solution to open hole isolation without the need of cemented liners.”
`
`Ellsworth at 3 (emphasis added). “Although the expansion ratios for these packers
`
`are [not] as large as for inflatables, the carbonate formation in Rainbow Lake
`
`
`
`- 22 -
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`Page 22 of 58
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`
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`generally drills very close to gauge hole, and effective isolation is possible with
`
`these SBP’s.” Ellsworth at 3. The description of “very close to gauge hole” means
`
`that the borehole is round instead of oval, and very close in size to the drill bit,
`
`which characteristics can be achieved in formations that are mechanically
`
`competent. Ellsworth illustrates a principle that had been known and applied in the
`
`industry for decades, that tools—such as solid-body packers used in the historically
`
`more-prevalent cased holes—can also be used, and often are tried and used
`
`successfully, in open-hole completions as they have become more common.
`
`VI. A Person of Ordinary Skill in the Art
`
`45.
`
`It is my opinion that a person of ordinary skill in the art as of
`
`November 19, 2001 is a person who earned a bachelor of science degree in
`
`mechanical, petroleum, or chemical engineering, or similar degree and had at least
`
`two to three years of experience with downhole completion technologies related to
`
`fracturing.
`
`46. Such a person would have been familiar with the options and
`
`considerations described in Section V above. Such a person would have further
`
`understood that certain of these options were better suited to some formation or
`
`wellbore types than others, and would have known to consider different types of
`
`completions, tools, and configurations depending on formation or wellbore types
`
`and characteristics, such as the ones described in Section V above. Such a person
`
`
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`- 23 -
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`Page 23 of 58
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`
`
`would have understood the various stimulation methods, types and uses of packers
`
`to perform selective fluid treatment of wellbores, and flow control techniques such
`
`as limited entry—and the use of those methods and techniques in combination with
`
`or as substitutes for one another. For example, a person of ordinary skill in the art
`
`would have appreciated the possibility of using acidizing systems to fracture
`
`certain carbonate formations, and would have recognized how tools and
`
`components could function and that certain components, such as hydraulically set
`
`solid-body packers, may work better under certain conditions than other
`
`components, such as inflatable packers.
`
`47. Such a person would have usually worked in a team environment and,
`
`in addition to his or her own skills and experiences and those of other team
`
`members, would also have had access to (and been trained and enco
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