UNITED STATES PATENT AND TRADEMARK OFFICE
`
`_______________
`
`BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
` _______________
`
`FMC TECHNOLOGIES, INC.,
`Petitioner,
`
`v.
`
`ONESUBSEA IP UK LIMITED
`Patent Owner.
`_______________
`
`Case IPR2016-00495
`
`Patent No. 8,066,076
`_______________
`
`
`
`DECLARATION OF GEORGE BOYADJIEFF
`
`1
`
`
`
`
`
`OSS Exhibit 2006, pg. 1
`FMC vs. OSS
`IPR2016-00495
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`
`
`_______________
`
`BEFORE THE PATENT TRIAL AND APPEAL BOARD
`
` _______________
`
`FMC TECHNOLOGIES, INC.,
`Petitioner,
`
`v.
`
`ONESUBSEA IP UK LIMITED
`Patent Owner.
`_______________
`
`Case IPR2016-00495
`
`Patent No. 8,066,076
`_______________
`
`
`
`DECLARATION OF GEORGE BOYADJIEFF
`
`1
`
`
`
`
`
`OSS Exhibit 2006, pg. 1
`FMC vs. OSS
`IPR2016-00495
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`I.
`
`INTRODUCTION
`
`
`
` My name is George Boyadjieff. I have been asked to opine on the 1.
`
`patentability of U.S. Patent 8,066,076 by Donald et al. (“the ’076 patent”), entitled
`
`“Connection System for Subsea Flow Interface Equipment” in response to the
`
`petition for inter partes review (“IPR”) filed by FMC Technologies, Inc. (“FMC”).
`
`My opinions are set forth herein. I make this declaration based on personal
`
`knowledge and I am competent to testify about the matters set forth herein. I
`
`submit this declaration in support of OneSubsea IP UK Limited’s (“OSS”) Patent
`
`Owner Response, which I have read and fully support as if my own.
`
`II. QUALIFICATIONS
`
`
`
` My academic credentials include a B.S. and M.S. in Mechanical 2.
`
`Engineering from the University of California at Berkeley. I am a Registered
`
`Professional Engineer in the State of California.
`
`
`3.
`
`For 35 years, I worked in the surface and subsea oil/gas production
`
`industry. I am a retired Chief Executive Officer of Varco International, a NYSE,
`
`diversified Oil Service Company. I joined Varco in 1959 as Chief Engineer and
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`was appointed CEO in 1991. I held numerous positions during a 33-year career at
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`Varco, including Vice President of Operations; Division President; Corporate
`
`President; and COO. During my extensive career, I worked with many subsea
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`completion systems. I am considered to be a leading developer of drilling
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`
`
`2
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`OSS Exhibit 2006, pg. 2
`FMC vs. OSS
`IPR2016-00495
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`equipment, both surface and subsea, during the last 35 years, including the Top
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`Drive Drilling System, a revolutionary new method of drilling now used on
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`virtually all existing drilling operations worldwide both onshore and offshore. I
`
`hold over 60 U.S. patents, and I have published numerous technical papers and
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`made many technical presentations throughout the world. I was selected as a
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`Society of Petroleum Engineers (SPE) distinguished lecturer for 1990-1991.
`
`
`4.
`
`I am the former Chairman of the National Ocean Industries
`
`Association (NOIA) and former Chairman of the Petroleum Equipment Suppliers
`
`Association (PESA). I am a member of the Society of Petroleum Engineers (SPE)
`
`and the American Society of Mechanical Engineers (ASME). I have been inducted
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`into the Ocean Energy Offshore Hall of Fame and I have been awarded the Ellis
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`Island Metal of Honor. My latest curriculum vitae (CV) is attached to this
`
`declaration as an Appendix A.
`
`III. BASIS OF OPINIONS
`
`
`5.
`
`I have reviewed the ’076 patent and its file history. I have also
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`reviewed FMC’s petition for IPR (including all exhibits), the supporting
`
`declaration of Mr. Herrmann and the transcript of his deposition, the prior art cited
`
`in FMC’s petition, the Board’s institution decision, and the other documents and
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`materials cited herein.
`
`
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`3
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`OSS Exhibit 2006, pg. 3
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`IV. UNDERSTANDING OF LEGAL STANDARDS
`
`
`6.
`
`I understand that a claim is unpatentable if it is anticipated.
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`Anticipation of a claim requires that every element of a claim be disclosed
`
`expressly or inherently in a single prior art reference, arranged in the prior
`
`reference as arranged in the claim. I am informed that this standard is set forth in
`
`35 U.S.C. § 102.
`
`
`7.
`
`I understand that a patent claim is unpatentable as obvious if the
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`differences between the patented subject matter and the prior art are such that the
`
`subject matter as a whole would have been obvious at the time the invention was
`
`made to a person of ordinary skill in the relevant art. I am informed that this
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`standard is set forth in 35 U.S.C. § 103(a).
`
`
`8.
`
`I understand that a patent claim is unpatentable as obvious if the
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`subject matter of the claim as a whole would have been obvious to a person of
`
`ordinary skill as of the time of the invention at issue. I understand that the
`
`following factors must be evaluated to determine whether the claimed subject
`
`matter is obvious: (1) the scope and content of the prior art; (2) the difference or
`
`differences, if any, between the scope of the claim of the patent under
`
`consideration and the scope of the prior art; (3) the level of ordinary skill in the art
`
`at the time the patent was filed; and (4) so-called objective indicia of non-
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`obviousness, also known as “secondary considerations,” which are also to be
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`
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`4
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`OSS Exhibit 2006, pg. 4
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`IPR2016-00495
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`considered when assessing obviousness. Secondary considerations include the
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`following: (A) commercial success; (B) long-felt but unresolved needs; (C)
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`copying of the invention by others in the field; (D) initial expressions of disbelief
`
`by experts in the field; (E) failure of others to solve the problem that the inventor
`
`solved; and (F) unexpected results. I also understand that evidence of objective
`
`indicia of non-obviousness must be commensurate in scope with the claimed
`
`subject matter.
`
`
`9.
`
`I understand that prior art references can be combined to reject a claim
`
`under 35 U.S.C. § 103 when there was an apparent reason for a person of ordinary
`
`skill in the art, at the time of the invention, to combine the references, which
`
`includes, but is not limited to (1) identifying a teaching, suggestion, or motivation
`
`to combine prior art references; (2) combining prior art methods according to
`
`known methods to yield predictable results; (3) substituting one known element for
`
`another to obtain predictable results; (4) using a known technique to improve a
`
`similar device in the same way; (5) applying a known technique to a known device
`
`ready for improvement to yield predictable results; (6) trying a finite number of
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`identified, predictable potential solutions, with a reasonable expectation of success;
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`or (7) identifying that known work in one field of endeavor may prompt variations
`
`of it for use in either the same field or a different one based on design incentives or
`
`
`
`5
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`OSS Exhibit 2006, pg. 5
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`other market forces if the variations are predictable to a person of ordinary skill in
`
`the art.
`
`V. DESCRIPTION OF THE RELEVANT FIELD AND RELEVANT
`TIMEFRAME
`
`
`
` The ’076 patent was issued to Ian Donald et al. on November 29, 10.
`
`2011. I have been informed that the ’076 patent claims priority to U.S. Provisional
`
`Patent Application No. 60/548,727, which was filed on February 26, 2004. I have
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`been informed that I should assume that the ’076 patent’s earliest priority date is
`
`February 26, 2004.
`
`
`11.
`
`I have carefully reviewed the ’076 patent and its file history.
`
`
`
` Based on my review of this material, I believe that the relevant field 12.
`
`for the purposes of the ’076 patent is subsea well systems. I have been informed
`
`that the relevant timeframe is before February 26, 2004, which is the filing date of
`
`U.S. Provisional Patent Application No. 60/548,727.
`
` As described above and as shown in my CV, I have extensive
`13.
`
`experience in the relevant field. Based on my experience, I have a good
`
`understanding of the relevant field in the relevant timeframe and the skills
`
`possessed by those of ordinary skill at the time.
`
`
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`6
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`OSS Exhibit 2006, pg. 6
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`IPR2016-00495
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`VI. THE PERSON OF ORDINARY SKILL IN THE RELEVANT FIELD
`IN THE RELEVANT TIMEFRAME
`
`
`14.
`
`I have been informed that a person of ordinary skill in the art is a
`
`hypothetical person to whom an expert in the relevant field could assign a routine
`
`task in that field with reasonable confidence that the task would be successfully
`
`carried out. I have been informed that the level of skill in the art is evidenced by
`
`prior art references. The prior art that I discuss below demonstrate that a person of
`
`ordinary skill, at the time the ’076 patent was effectively filed, would have been
`
`someone with at least a bachelor’s degree in mechanical engineering and at least 5
`
`years of experience in the field of subsea well systems.
`
` Based on my experience, I have an understanding of the capabilities
`15.
`
`of a person of ordinary skill in the art. I have supervised and directed many such
`
`persons over the course of my career. Further, I had at least those capabilities
`
`myself at the time the patent was effectively filed.
`
`VII. TECHNOLOGY BACKGROUND FOR THE ’076 PATENT
`
`A. Location of Oil and Gas
`
`
`
` Oil and gas deposits are located in the earth typically one to three 16.
`
`miles below the surface. The earth is made up of many layers of rock and soil.
`
`Pictures of the Grand Canyon best illustrate what these layers look like. Contrary
`
`to popular belief, the oil and gas does not collect in underground pools of liquid or
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`pockets of gas. Instead, oil and gas deposits are dispersed throughout a porous
`
`
`
`7
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`OSS Exhibit 2006, pg. 7
`FMC vs. OSS
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`layer such as sand. When a sand layer is capped above and below by rock layers,
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`the oil and gas is trapped in the sand layer and the sand layer is called a reservoir.
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`Because there are many layers of earth piled on top of a reservoir, the oil or gas in
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`the reservoir is under a lot of pressure.
`
` Reservoirs vary in size from small ones to giant ones. Companies
`17.
`
`typically will not drill into a reservoir unless it is big enough to pay for the cost of
`
`getting the oil and gas to the surface. Generally, companies need to drill multiple
`
`wells throughout the reservoir to collect the oil and gas because the sand
`
`containing the oil or gas resists the flow of the oil and gas toward a single well. A
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`single well can only drain a small part of the reservoir. On land, the wells are
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`spread out over the land area of the reservoir and connected by individual small
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`pipelines, called flowlines, to a main pipeline going to a refinery or harbor terminal
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`for exporting. Offshore the wells are clustered in a small area and drilled at an
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`angle to various parts of the reservoir. This is because pipelines cost a lot more to
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`build on the ocean floor, hence it is desirable to limit the length of the pipelines
`
`connecting each well.
`
`B. Drilling a Well
`
`
`
` To get the oil and gas out of its reservoir, a hole, called a well, is 18.
`
`drilled in the ground from the earth’s surface to the reservoir. If the well is drilled
`
`
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`8
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`OSS Exhibit 2006, pg. 8
`FMC vs. OSS
`IPR2016-00495
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`in the ocean, the well is called an offshore well. If the well is connected to an
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`underwater pipeline on the ocean floor, it is called a subsea well.
`
`
`
` Drilling a well consists of digging a hole from the surface to the 19.
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`reservoir. Because the hole can be very long (miles) in relationship to its diameter,
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`one cannot reach in and shovel out the earth. Instead, a pipe called a drill pipe is
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`used to feed a digging tool called a drill bit through the earth to the reservoir. The
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`drill bit is attached to the bottom end of the pipe and the drill pipe is rotated
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`causing the drill bit to dig. To get the dug earth, called cuttings, out of the hole,
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`fluid, called drilling fluid, is pumped down the inside of the pipe to wash the
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`cuttings up the outside of the pipe to the surface.
`
`DRILL BIT
`
` Once drilling is completed, the well is lined with hollow steel pipe
`20.
`
`
`
`called a casing. In turn, the space between the outside of the casing and the earth
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`is filled with cement. The cement seals off all the layers on the way down to the
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`
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`9
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`OSS Exhibit 2006, pg. 9
`FMC vs. OSS
`IPR2016-00495
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`reservoir so that the oil or gas in the reservoir cannot leak into other layers on its
`
`way to the surface. The casing also prevents the earth from collapsing onto itself.
`
`OILWELL CASING
`
`
`
`
`C. Wellheads
`
`
`
` Attached to the top of the casing is a coupling called a wellhead. A 21.
`
`typical wellhead is illustrated below. Connected to the top of the casing is a ring
`
`called a casing hanger. The casing hanger sits on steps inside the wellhead to
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`provide support for the casing prior to cementing it in place. The wellhead outer
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`housing, called a casing head, is generally cylindrical in shape. It can be one piece
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`called a unitized wellhead or it can be made up of several pieces as shown in the
`
`typical wellhead drawing below. If the wellhead is located on the surface, it is
`
`simply called a wellhead. If it is located on the ocean floor, it is called a subsea
`
`
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`10
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`OSS Exhibit 2006, pg. 10
`FMC vs. OSS
`IPR2016-00495
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`wellhead. There is no fundamental difference between a subsea wellhead and a
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`surface wellhead.
`
`
`
`TYPICAL WELLHEAD
`
`
`
`D. Drilling a Subsea Well
`
`
`22.
`
`In the case of a subsea well, as opposed to a surface well, unique
`
`subsea equipment is used. Drilling is accomplished with a machine called a
`
`Drilling Rig mounted on a floating ship called a drillship, or barge like structure
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`called a Semisubmersible shown below. Drillships and Semisubmersibles are
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`referred to as floaters. Initially, subsea wells were drilled in relatively shallow
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`water (a few hundred feet) but by the mid-1990s, wells were being drilled
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`thousands of feet below the ocean’s surface.
`
`
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`11
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`OSS Exhibit 2006, pg. 11
`FMC vs. OSS
`IPR2016-00495
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`DRILLING RIG
`
`RISER
`
`BOP
`
`
` During drilling, an assembly of valves called a Blowout Preventer or
`23.
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`
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`BOP stack is installed on top of the subsea wellhead. A BOP is a safety device
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`with multiple, redundant valves (to provide additional safety) that can be closed if
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`excessive pressures are encountered during the drilling process, thereby preventing
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`what is called a blowout. The BOP is typically removed after the well has been
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`pressure tested and is ready for production.
`
` The top of the BOP is connected to the Drilling Rig by a long pipe
`24.
`
`called a Riser. The Riser acts as a conduit for passing equipment between the
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`Drilling Rig and the well. Everything including casing and the casing hangers pass
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`
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`12
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`OSS Exhibit 2006, pg. 12
`FMC vs. OSS
`IPR2016-00495
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`through the inside of the riser. During drilling, the drill bit and drill pipe pass
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`through the inside of the riser to the seabed. The drilling fluid passes through the
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`drill pipe and drill bit, picking up (by mixing with) the cuttings coming from
`
`drilling action of the drill bit, and then flows up the riser around the outside of the
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`drill pipe to the drilling rig where the cuttings are collected.
`
`E. Completing a Well
`
`
`
` Once the well reaches the reservoir layer, the well is usually drilled 25.
`
`through this layer and the last casing string is cemented in the reservoir. Next, a
`
`device called a perforating gun is lowered, via a cable, from the surface through
`
`the inside of the casing to the reservoir area. The perforating gun has explosive
`
`charges that are set off to punch holes at regular intervals into the casing and
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`cement so that the oil or gas can flow into the well. Next, a string of pipe called a
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`tubing string is lowered inside the casing. The tubing string connects the reservoir
`
`to the top of the well for bringing the oil or gas to the surface. The tubing string is
`
`designed to be removed if the well has a problem.
`
` At the bottom of the tubing string, located just above the reservoir, is
`26.
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`a seal called a packer. The packer seals the space between the tubing and the
`
`casing so that the oil and gas are forced into the tubing and not up around the
`
`outside of it. The space around the outside of the tubing and inside the casing is
`
`called the annulus. The annulus reaches from the wellhead to the packer. At the
`
`
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`13
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`OSS Exhibit 2006, pg. 13
`FMC vs. OSS
`IPR2016-00495
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`beginning of the wells life, when the well has enough pressure to bring the oil or
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`gas to the surface, the annulus is used to detect leaks in the tubing or casing by
`
`monitoring the pressure inside it.
`
` However, the annulus can also be used to help bring the oil/gas to the
`27.
`
`surface when the reservoir loses its pressure and the oil/gas no longer flows to the
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`surface on its own. This is more of a problem with oil wells than with gas wells.
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`In the case of oil wells that have lost some of their natural pressure, gas can be
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`pumped down the annulus and mixed with the oil to lighten the oil. This lighter oil
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`will take less pressure to bring it to the surface. This is called artificial lift.
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`Another way of getting the oil to flow out of the well when the pressure has
`
`decreased is to force water into the reservoir to push the oil out. This is usually
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`accomplished by using a separate well called an injection well to pump the water
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`into the reservoir.
`
`F. Controlling the Flow of Oil and Gas
`
`
`
` As the oil and gas comes to the surface, it is desirable to control the 28.
`
`flow and pressure of the oil and gas or to shut off the well completely. These
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`actions are done with a series of valves connected to the tubing string and the
`
`annulus. The assembly that includes these valves is called a Christmas tree or
`
`Xmas Tree.
`
`
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`14
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`OSS Exhibit 2006, pg. 14
`FMC vs. OSS
`IPR2016-00495
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` As shown below, a Christmas tree comprises an assembly of
`29.
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`universally known pipes, valves, and fittings (each with a specific name and
`
`function) to control the flow of oil/gas from the well.
`
`
`
`Production
`Crown Valve
`
`Production
`Wing Valve
`
`Production
`Branch
`
`Production
`Master Valves
`
`Production
`Bore
`
`Annulus
`Bore
`
`
`
`
`
`
`(EX2013, Fig. 2, annotated).1
`
`
` A subsea tree has two types of piping: bores and branches. The bores
`30.
`
`are the vertical passages between the wellhead and the top of the tree and the
`
`
`1 To help explain the figures in my declaration, various annotations have been
`
`added in blue and green. All red annotations are FMC’s.
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`
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`15
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`OSS Exhibit 2006, pg. 15
`FMC vs. OSS
`IPR2016-00495
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`branches are the horizontal passages that extend from the bore towards the side of
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`the tree. There are typically two vertical bores that extend from the wellhead to the
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`top of the tree that are called the production bore and annulus bore. The
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`production bore is the main fluid pathway for the oil/gas while the annulus bore is
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`used for well-maintenance functions, such as pressure testing. The vertical bores
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`of the tree are sealed with a removable cap that is called the tree cap. Each of the
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`bores includes a pipe that extends horizontally from the tree’s main body called a
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`branch, sometimes also referred to as a production line or wing. In summary, the
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`piping within a tree is either a bore or a branch.
`
` The branch goes from the bore toward the side of the tree where it
`31.
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`connects to an external pipe called a flowline. In the field of oil/gas production, a
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`person of ordinary skill in the art would call all the pipes that extend outside the
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`tree “flowlines.” There are different types of flowlines such as jumpers (which are
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`local pipes on the ocean floor that connect trees to a manifold) and gathering lines
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`(which run from the ocean floor to the ocean surface), but they are all considered
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`“flowlines.” Sometimes a flowline is also referred to as a production discharge
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`line. For the technology at issue in this proceeding, there are three different types
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`of piping: bores (annulus or well), branches, and flowlines. Although sometimes
`
`different names are used, each pipe at issue in this proceeding fits into one of these
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`three categories.
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`
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`16
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`OSS Exhibit 2006, pg. 16
`FMC vs. OSS
`IPR2016-00495
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` The tree also includes a series of valves that are used to control and
`32.
`
`direct the flow of oil/gas. A conventional tree’s production bore includes at least
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`one master valve, a crown valve (also known as a swab valve), and a wing valve.
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`The master valve is located below the branch and serves as a primary fluid barrier.
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`The crown valve is located above the branch but below the tree cap and serves as a
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`secondary barrier. The wing valve is located on the branch and serves a secondary
`
`barrier but also is the valve that is opened/closed to control the flow of production
`
`fluid out of the branch. These valves and their names are industry standards and
`
`establish two barriers of protection between the well and the open sea, which is a
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`requirement of all subsea trees. (EX2017, pp. 13-14, 18, 73).
`
`
`33.
`
`In another type of tree design, known as a horizontal tree, the
`
`protection provided by the master valve and crown valves is replaced by a series of
`
`plugs installed in the well bore.
`
` Shown below is a typical surface Xmas tree and subsea Xmas tree.
`34.
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`
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`17
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`OSS Exhibit 2006, pg. 17
`FMC vs. OSS
`IPR2016-00495
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`Swab
`valve
`
`Choke
`
`Upper
`master
`valve
`
`Annulus
`wing
`valve
`
`Production
`Wing valve
`Lower
`master
`valve
`
`SURFACE XMAS TREE
`
` SUBSEA XMAS TREE
`
`
` Although at first glance there seems to be a big difference between the
`35.
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`
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`surface Xmas tree and the subsea Xmas tree figure, there really isn’t. Shown
`
`below next to the surface Xmas tree is an inside view of the subsea Xmas tree,
`
`which illustrates the same control valves used on the surface Xmas tree. These
`
`valves can shut down the well, block areas of the Xmas tree, and provide access to
`
`the tubing and annulus independently.
`
`
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`18
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`OSS Exhibit 2006, pg. 18
`FMC vs. OSS
`IPR2016-00495
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`Swab
`valve
`
`Choke
`
`Upper
`master
`valve
`
`Annulus
`wing
`valve
`
`Production
`Wing valve
`Lower
`master
`valve
`
`Upper
`master
`valve
`
`Annulus
`wing
`valve
`
`Wellhead
`
`Swab
`valve
`Production
`wing valve
`
`Choke
`
`Lower
`Master
`valve
`
`
`
`SURFACE XMAS TREE
`
` SUBSEA XMAS TREE
`
`
`
` One of the main difference between a surface Xmas tree and a subsea
`36.
`
`Xmas tree is that the valves on the surface Xmas tree have handles for manually
`
`opening and closing them, whereas the subsea Xmas tree’s valves have
`
`attachments called actuators for remotely controlling them.
`
`
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`19
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`OSS Exhibit 2006, pg. 19
`FMC vs. OSS
`IPR2016-00495
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`Swab Valve Actuator
`
`Choke
`Actuator
`
`Choke
`
`Connection for
`the Flowline
`
`Master Valve Actuator
`Wing Valve Actuator
`
`INSIDE VIEW OF A BASIC SUBSEA TREE
`
`
`
` The actuators are controlled from the surface or by using a submarine
`37.
`
`
`
`device, as shown below, called an ROV, which stands for Remotely Operated
`
`Vehicle. Typically, actuators are hydraulic operated.
`
`
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`20
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`OSS Exhibit 2006, pg. 20
`FMC vs. OSS
`IPR2016-00495
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`G. Subsea Xmas Tree Design
`
`
`
` Shown below is a typical subsea Xmas tree. As can be seen in the 38.
`
`image below, subsea Xmas trees are generally quite large (and expensive) and
`
`weigh many tons. Once put in production, these Christmas trees (and their
`
`associated well) will remain in service for a very long time, even decades, in order
`
`to recover the large initial drilling costs (upwards of $100 million). The subsea
`
`Xmas tree also has a strong structure surrounding it to protect the well from fishing
`
`nets, dragging anchors from ships and heavy objects that may fall on it. The
`
`structure also protects the Xmas tree from damage during transport and
`
`installation. The tree has to be loaded on a heaving boat for transport to the
`
`wellsite and installed through the drilling opening of a drillship that is also swaying
`
`back and forth.
`
`
`
`21
`
`OSS Exhibit 2006, pg. 21
`FMC vs. OSS
`IPR2016-00495
`
`
`
`
`
`
`
`
`39.
`
`Illustrated below is a cross section of a subsea Xmas Tree. The
`
`
`
`illustration below shows the flow of oil and gas from the wellhead to the flowline.
`
`The main vertical flow path from the wellhead to the top of the Xmas tree is called
`
`the production bore of the Xmas tree. The horizontal flowpath branching off of
`
`the production bore is simply called the production branch or sometimes the
`
`productionn wing. Not shown would be a second vertical bore and branch for the
`
`annulus on the other side of the production branch.
`
`
`
`22
`
`OSS Exhibit 2006, pg. 22
`FMC vs. OSS
`IPR2016-00495
`
`
`
`Production Bore
`
`Tree Cap
`
`Branch
`
`Wellhead
`
`
`In subsea trees, the production bore and the annulus bore extend to the
`
`
`
`
`40.
`
`top of the tree and terminate at the tree cap. The tree cap provides a convenient
`
`connection point for attaching a BOP stack and riser system to the Xmas tree and
`
`at a later date for operations such as working over the well. Connected to the side
`
`of the production and annulus bores are the branches which in turn connect to the
`
`flowlines.
`
`
`
`23
`
`OSS Exhibit 2006, pg. 23
`FMC vs. OSS
`IPR2016-00495
`
`
`
`H. Chokes
`
`
`
` Connected to the end of the production branch on most every Xmas 41.
`
`tree is a valve called the choke that can restrict the flow of oil and gas. The choke
`
`is a critical piece of equipment. The choke provides a controlled and regulated
`
`flow of oil/gas to the surface. Without a choke installed, there is a risk that the
`
`flow rate of production fluids could be more than the processing equipment on the
`
`surface can handle. Another more serious risk is that too much flow can
`
`permanently damage the reservoir, reducing the amount of oil or gas that can be
`
`ultimately recovered. The choke functions in the same way as a sink faucet at
`
`home. You can adjust its opening to regulate how fast the oil will flow from the
`
`well. In the case of a subsea well, you can’t see how fast the oil or gas is flowing
`
`from the well like you can see the water coming out of a faucet. Instead, you could
`
`install instrumentation to determine the flowrate of the oil through the choke. The
`
`instrumentation could be a flowmeter, pressure meter, or temperature meter. When
`
`installed, the instrumentation allows the operator to measure the flow rate through
`
`the choke. Once the operator knows the flow rate, the operator could adjust the
`
`choke to control the flow out of the well.
`
` Shown below is a crosssection of a typical surface choke.
`42.
`
`
`
`24
`
`OSS Exhibit 2006, pg. 24
`FMC vs. OSS
`IPR2016-00495
`
`
`
`Cage
`
`Flow
`Inlet
`
`Bonnet
`
`Body
`
`Sleeve
`
`Flow Outlet
`
`BASIC CHOKE DESIGN
`
` Shown below are a subsea choke and a surface choke. The only
`
`
`
`
`43.
`
`difference between a subsea choke and a surface choke is the method of operation.
`
`The surface choke is operated with a manual operating handle and the subsea
`
`choke is operated with an actuator that can be remotely controlled from the surface
`
`or controlled with a ROV.
`
`
`
`25
`
`OSS Exhibit 2006, pg. 25
`FMC vs. OSS
`IPR2016-00495
`
`
`
`Subsea Choke
`
`Surface Choke
`
`
`
`
` The cage and sleeve inside the choke are called the choke trim. The
`44.
`
`oil and gas coming out of a well is not a clean fluid. Gas can be mixed with oil,
`
`both can be mixed with water, and usually both are mixed with sand from the
`
`reservoir. This sand results in accelerated wear and tear on the choke trim. Shown
`
`below is what happens to the trim of a choke when the sand mixed with the oil or
`
`gas passes through it.
`
`
`
`
`
`26
`
`
`
`OSS Exhibit 2006, pg. 26
`FMC vs. OSS
`IPR2016-00495
`
`
`
`I. Retrievable Subsea Chokes
`
`
`
` Given the difficulties of replacing the choke trim in a subsea 45.
`
`environment, the industry developed and began using retrievable subsea chokes.
`
`On land, it is relatively easy to shut the well down and replace the choke’s trim. In
`
`subsea chokes, the replacement of the choke trim has to be accomplished remotely
`
`with an ROV, which makes the process much more difficult, time-consuming, and
`
`expensive. Shown below is a typical Subsea retrievable choke. The choke trim is
`
`secured to the choke actuator so that it comes out of the choke body with the
`
`actuator. The choke actuator can be attached to the choke body via a variety of
`
`well-known methods, such as with a ROV operated clamp mechanism. Removing
`
`the retrievable choke actuator and trim leaves a completely empty choke body.
`
`Choke
`Actuator
`
`Clamp
`ROV
`Interface
`
`Choke
`Trim
`
`Choke Body
`
`
`
`Choke
`Body
`Flange
`
`Typical Clamp
`
`
`
`
`
`27
`
`OSS Exhibit 2006, pg. 27
`FMC vs. OSS
`IPR2016-00495
`
`
`
`
`46.
`
`Inserting a diverter into the empty choke body is taught by the
`
`OneSubsea patents. Installing a diverter in an installed subsea Xmas tree, using
`
`simple, safe choke retrieval methods, offers a unique way of diverting the flow of
`
`oil and gas from a subsea well at significantly lower cost compared to any other
`
`method.
`
`J. Collecting the Oil and Gas
`
`
`
` As mentioned in paragraph 17, for economic reasons, several subsea 47.
`
`wells are generally clustered into a small area. Show below is a typical subsea
`
`installation. The large structure in the middle is called a gathering manifold. Each
`
`well (six are shown) is connected to the manifold with a flowline jumper. The
`
`manifold in turn is connected to a pipeline going up to the surface of the sea into a
`
`ship called a Floating Production Storage and Offloading vessel or FPSO for
`
`collecting the oil and gas or alternatively, the pipeline can go all the way to shore.
`
`
`
`28
`
`OSS Exhibit 2006, pg. 28
`FMC vs. OSS
`IPR2016-00495
`
`
`
`Flowlines
`to surface
`
`Manifold
`
`Wellhead
`& Xmas
`tree
`
`Xmas tree
`Control
`lines
`
`K. Keeping the Oil and Gas Flowing
`
`
`
`Flowline
`Jumper
`
`
`
`
`
` As an oil or gas well ages over time, problems begin to occur and 48.
`
`technology advances. The most common problem is loss of pressure at the
`
`wellhead over a number of years. A point is reached where the oil or gas can no
`
`longer reach the surface on its own. At this point, a pump is typically installed on
`
`the seabed to assist the flow to the surface. Installing such a pump at the beginning
`
`of the life of the well makes no sense as the pump many not be needed for 10 or
`
`more years. The ’076 patent’s invention permits installing the pump when needed
`
`at minimal cost.
`
` A second common problem of older oil and gas wells is what is called
`49.
`
`produced water. Historically, a processing apparatus called a separator, installed
`
`
`
`29
`
`OSS Exhibit 2006, pg. 29
`FMC vs. OSS
`IPR2016-00495
`
`
`
`on the surface, is used to separate the water from the oil and gas. Shown below is
`
`such an apparatus:
`
`
`
` Over time, as more and more water mixes with the oil, water takes up
`50.
`
`
`
`more of the valuable space in the flowlines, which results in less oil or gas
`
`recovery. As technology progressed, separators were designed and made available
`
`for subsea installation. However, they were very difficult and costly to install in
`
`existing fields, necessitating cutting into flowlines, shutting down wells, and re-
`
`testing the complete installation. The ’076 patent’s invention significantly reduces
`
`the cost of installing a subsea separator.
`
` At the time of the ’076 patent, technology advances made it desirable
`51.
`
`to conduct other processing operations on the extracted oil/gas. These processing
`
`operations varied depending on the specific characteristics of the environment
`
`from which the oil/gas is extracted. As briefly discussed above, examples of well-
`
`
`
`30
`
`OSS Exhibit 2006, pg. 30
`FMC vs. OSS
`IPR2016-00495
`
`
`
`known processing operations include: adding chemicals to the oil/gas, using a
`
`booster pump to increase the flow, separating water and sand from the oil/gas, or
`
`taking fluids from one well and injecting a component of those fluids into another
`
`well or into the same well. These processing operations required specialized
`
`equipment not found on the subsea tree. This specialized equipment could be
`
`located either on a surface vessel or on the ocean floor with the tree.
`
` However, at the time of the ’076 patent, locating the processing
`52.
`
`equipment at either location was problematic. If on a surface vessel, the sand and
`
`water that is mixed with the oil/gas or the fluids to be injected into the well needed
`
`to travel great distances. Transporting any non-oil/gas product was a wasteful use
`
`of resources because it was time consuming, expensive, and used a lot of energy.
`
`Installing the processing equipment on the ocean floor with the tree was also
`
`problematic. Due to their location on the ocean floor, reaching the Christmas tree
`
`to install new equipment was time consuming, costly, and dangerous. It required
`
`breaking the installed pipework attached to the outlet of the tree so that new
`
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