Expert Declaration for the OSES Motion to Amend
`in IPR2014-00216 for U.S. Patent No. 6,179,053 by Dallas for
`Lockdown Mechanism for Well Tools Requiring Fixed-Point Packoff
`
`
`
`Prepared by:
`
`Gary R. Wooley
`
`Wooley & Associates, Inc.
`
`3100 S. Gessner, Suite 325
`Houston, Texas 77063
`Phone 713.781.8974
`Email gary@wooley.com
`
`
`
`
`
`Prepared for:
`
`Mr. C. Erik Hawes
`
`Morgan, Lewis & Bockius LLP
`
`1000 Louisiana St., Suite 4000
`Houston, Texas 77002-5006
`Phone 713.890.5165
`
`27 August 2014
`
`
`Greene’s Energy Group, LLC v. Oil States Energy Services, LLC, IPR2014-00216, Ex. 2017
`Wooley & Associates, Inc.
`
`

`
`I.
`II.
`
`TABLE OF CONTENTS
`
`Introduction .................................................................................................. 1
`Basic Fracturing and Wellhead Protection Processes ............................. 2
`1.
`Drilling ................................................................................................. 3
`2.
`Completion ........................................................................................... 4
`3.
`Fracture Stimulation ............................................................................. 5
`4. Wellhead Protection ............................................................................. 8
`III. Overview of U. S. Patent 6,179,053 to Dallas .......................................... 10
`1.
`Dallas ’053 Patent Concepts .............................................................. 10
`2.
`Dallas ’053 Patent Claim 1 ................................................................. 16
`3.
`Dallas ’053 Patent Claim 22 ............................................................... 18
`IV. Proposed Amended Claims of the ’053 Patent ....................................... 20
`V.
`Legal Standards and Claim Construction ............................................... 23
`1.
`Law of Invalidity ................................................................................ 23
`2.
`Person of Ordinary Skill in the Art .................................................... 25
`3.
`Claim Construction............................................................................. 25
`VI. The Scope and Content of the Prior Art ................................................. 27
`VII. The Proposed Amended Claims Are Novel ............................................. 30
`1.
`The Dallas ’118 Application .............................................................. 30
`2.
`The Herricks Patent ............................................................................ 33
`VIII. The Proposed Amended Claims Would Not Have Been Obvious
`to One of Ordinary Skill in the Art at the Time the ’053 Invention
`Was Made ................................................................................................... 34
`1.
`The Scope and Content of the Prior Art ............................................. 34
`2.
`Level of Ordinary Skill in the Art ...................................................... 35
`3.
`Differences Between the Claimed Invention and the Prior Art ......... 36
`4.
`Objective Evidence of Nonobviousness ............................................. 37
`5.
`Analysis of Obviousness Factors ....................................................... 63
`IX. Basic Facts and Conclusions ..................................................................... 67
`
`
`
`

`
`X.
`X.
`
`1.
`
`References Cited ............................................................................... ..68
`
`Appendix ..................................................................................................... 68
`Appendix .....................................................................................................68
`1.
`References Cited ................................................................................. 68
`2.
`References Considered ....................................................................... 68
`3.
`Resumé for Gary R. Wooley .............................................................. 73
`Resumé for Gary R. Wooley ............................................................ ..73
`4.
`List of Recent Wooley Testimony ..................................................... 75
`List of Recent Wooley Testimony ................................................... ..75
`
`References Considered ..................................................................... ..68
`
`2.
`
`3.
`
`4
`
`
`
`ii
`
`

`
`I.
`
`Introduction
`
`1.
`
`Stinger Wellhead Protection Inc. of Oklahoma City, OK was
`
`incorporated in Texas in August 1988 to provide wellhead protection service to the
`
`oil and gas industry. Stinger provides services in the U.S., Canada and
`
`internationally. On 30 January 2001, L. Murray Dallas of Fairview, Texas, an
`
`executive with Stinger, was awarded U.S. Patent 6,179,053 (“the ’053 Patent”)
`
`(Ex. 1001), which related to Stinger’s wellhead protection services. In May 2005
`
`Oil States International, Inc., now Oil States Energy Services (OSES), acquired
`
`Stinger, including rights to its patents.
`
`2.
`
`OSES filed a lawsuit against Petitioner Greene’s Energy Group, LLC
`
`(“Greene’s” or “Petitioner”) for infringement of the ’053 Patent in 2012. On
`
`December 3, 2013, Petitioner filed the instant inter partes review challenging the
`
`validity of the ’053 Patent. OSES retained the law firm Morgan, Lewis & Bockius,
`
`LLP of Houston, Texas to handle both the litigation and the inter partes review.
`
`Morgan, Lewis & Bockius, LLP contacted Wooley & Associates, Inc. to assist
`
`with certain technical issues and to provide expert opinions.
`
`3.
`
`This report contains facts, opinions and conclusions based on my
`
`training and experience and the information reviewed at the time of this writing.
`
`The Appendix lists the documents that were provided to me. My resumé is also
`
`presented in the Appendix along with my recent testimony.
`
`
`
`

`
`4.
`
`This report contains my general opinions, but obviously not all details
`
`are included. If asked questions on these facts and opinions or other subjects, I may
`
`have opinions not specifically listed herein. There may be documents and
`
`testimony that support my opinions that are not included herein.
`
`5.
`
`As additional information is examined, these facts, opinions and
`
`conclusions may be changed and/or supplemented. Upon review of additional
`
`documents and testimony I may supplement or revise my opinions. Also, after
`
`reading any opinions submitted by Greene’s expert, I may have opinions to rebut
`
`those opinions.
`
`II. Basic Fracturing and Wellhead Protection Processes
`
`6.
`
`For a discussion of the basic principles of hydraulic fracturing and
`
`wellhead protection, I repeat Section (II) of my contemporaneous declaration
`
`submitted in support of OSES’s primary opposition to Greene’s petition for inter
`
`partes review.
`
`7.
`
`A petroleum operating company drills a well for the purpose of
`
`reaching a productive reservoir containing oil or gas at a particular depth and
`
`location in a geologic structure. After drilling, it is sometimes necessary to
`
`stimulate the reservoir to improve productivity. This section describes general
`
`concepts for drilling and completion, fracture stimulation and the use of wellhead
`
`protection devices.
`
`
`
`2
`
`

`
`1.
`
`8.
`
`Drilling
`
`To accomplish the drilling of a well, typically a petroleum operator
`
`contracts with a drilling contractor which provides the drilling rig and crew to
`
`operate it. The drilling rig runs a drill bit on drill pipe, and rotating the bit drills the
`
`well.
`
`9.
`
`After drill bits and drill pipe have drilled an oil or gas well, casing
`
`(steel pipe) is run in the well to hold the borehole open for future operations. When
`
`the casing is in place cement is pumped down the inside of the casing, out the
`
`bottom and around the outside of the casing between the casing and the open hole.
`
`10. Figure 2.1 shows a typical wellbore
`
`at the end of drilling. In this example 20”
`
`Depth, feet
`0
`
`Figure 2.1
`Production Casing
`At End of Drilling
`
`
`diameter conductor pipe was set near the surface,
`
`through which a 12-1/4” hole was drilled to
`
`approximately 1,000’. At
`
`that depth 9-5/8”
`
`surface casing was run and cemented in the hole
`
`to protect shallow drinking water and provide
`
`structural support for deeper drilling.
`
`11. Through the inside of the 9-5/8”
`
`casing a 7-7/8” bit was run and drilled to total
`
`1,000'
`
`1,000'
`
`2,000'
`
`3,000'
`
`4,000'
`
`5,000'
`
`6,000'
`
`20" conductor
`cement
`
`9-5/8"
`surface casing
`
`production
`casing
`
`top of
`cement
`
`5,500'
`
`reservoir
`
`5-1/2"
`produciton casing
`
`
`
`depth of 5,500’. At that depth, the drill pipe and drill bit were pulled out of the
`
`
`
`3
`
`

`
`hole, and well logs were run to determine if the target reservoir appeared to be
`
`capable of commercial production. If well logs and other data indicated the well
`
`was not productive then cement plugs are set and the well is abandoned. For the
`
`example shown in Figure 2.1 it was assumed the logs and other data indicated the
`
`well may be commercially productive, so production casing was run. Cement was
`
`pumped down the inside of the casing and around the outside to a depth of
`
`approximately 3,500’, which is labeled in Figure 2.1. At this point usually the
`
`drilling rig is released.
`
`2.
`
`Completion
`
`12. Sometime after the drilling rig is
`
`released, production equipment is installed at the
`
`well site, which may include flow lines, tanks,
`
`Depth, feet
`0
`
`pumps, separators, treaters, compressors, flow
`
`meters or other equipment. When the well site is
`
`ready for production, a completion rig will rig
`
`up over the well.
`
`13. Typically a wireline unit will run a
`
`1,000'
`
`2,000'
`
`3,000'
`
`4,000'
`
`Figure 2.2
`Completion of Well
`For Production
`
`
`oil & gas
`
`tubing
`
`perforating gun which will perforate
`
`the
`
`production casing at the desired depth in the
`
`reservoir based on logs and other data. Either
`
`perforations
`5,000'
`
`5,500'
`
`6,000'
`
`packer
`
`reservoir
`
`5-1/2"
`production casing
`
`
`
`
`
`4
`
`

`
`before or after perforation production tubing will be run with a packer to a depth
`
`just above the reservoir. The packer seals the annular space between the inside of
`
`the casing and the outside of the tubing to force production fluid to flow through
`
`the tubing.
`
`14. Figure 2.2 illustrates a typical well after completion. Oil and gas is
`
`shown flowing from the reservoir up the tubing to the surface.
`
`3.
`
`Fracture Stimulation
`
`15. For certain
`
`reservoirs,
`
`flow
`
`is
`
`limited by low reservoir permeability, damage
`
`Figure 2.3
`Injection to
`Stimulate Reservoir
`
`
`around the wellbore, or other factors. Also, there
`
`Depth, feet
`0
`
`injection fluid
`
`are reservoirs with natural fracture systems that
`
`can be accessed to improve productivity. For
`
`these well conditions it is possible to stimulate
`
`the reservoir by injecting specific fluids and
`
`solids down the well and into the reservoir.
`
`1,000'
`
`2,000'
`
`3,000'
`
`4,000'
`
`tubing
`
`16. Figure 2.3 illustrates the injection
`
`process used to stimulate the reservoir. Fluids
`
`perforations
`5,000'
`
`5,500'
`
`and solids may be injected at the surface into the
`
`6,000'
`
`packer
`
`reservoir
`
`5-1/2"
`production casing
`
`
`
`tubing as shown in the figure. The fluid travels down the tubing, then passes
`
`through the perforations in the production casing and into the reservoir.
`
`
`
`5
`
`

`
`17. Alternatively, the fluid can be injected through the casing before
`
`tubing is placed in the well. When injecting through the casing, care should be
`
`taken to avoid damage to the casing from the fluids and solids and from the pres-
`
`sure applied.
`
`18. Stimulation may involve injecting fluid at lower pressures (below
`
`formation fracture pressure) to saturate the pore space around the wellbore, or
`
`injection can occur at higher pressures (above formation fracture pressure) to
`
`initiate and propagate a fracture through the formation. When hydraulic fractures
`
`are created by injecting fluid at pressures above formation fracture pressures, then
`
`usually proppant (sand or other particles) is injected with the fluid to prop open the
`
`fractures when the fluid pressure is released.
`
`19.
`
`In the last few decades horizontal drilling has become more popular to
`
`provide additional exposure of the wellbore to the productive formation.
`
`Horizontal drilling can improve productivity and ultimate recovery in conventional
`
`reservoirs, but has been most helpful in making previously uneconomic formations
`
`such as shales economically viable. Horizontal drilling was employed in the 1980’s
`
`for the Austin Chalk formation in Texas to connect natural fractures, and became
`
`especially beneficial in the 1990’s to stimulate the Barnett Shale in Texas.
`
`
`
`6
`
`

`
`Figure 2.4
`Typical Horizontal Shale Well
`
`
`Depth, feet
`0
`
`1,000'
`
`prump frac fluid
`and proppant
`
`13-1/2" hole
`
`2,000'
`
`1,855'
`
`10-3/4" surface casing
`
`20. Figure
`
`2.4
`
`illustrates a typical horizontal
`
`shale well. A 6-3/4” hole was
`
`drilled out the 7-5/8” casing at
`
`10,800’, then turned horizontal
`
`through the reservoir depicted
`
`at 11,500’ and drilled to a
`
`measured depth of 15,978’. 5-
`
`1/2” casing was run to 15,971’
`
`and cemented.
`
`21. A series of 10
`
`perforating guns and
`
`frac
`
`plugs were run to fracture
`
`3,000'
`
`4,000'
`
`5,000'
`
`6,000'
`
`7,000'
`
`8,000'
`
`9,000'
`
`10,000'
`
`10,800'
`11,000'
`6-3/4" hole
`
`reservoir
`
`9-1/4" hole
`
`formation
`fractures
`
`7-5/8" drilling casing
`
`perfs
`
`frac plugs
`
`5-1/2"
`production
`casing
`
`15,978'
`MD TD
`15,971' MD
`
`stimulate the shale reservoir.
`
`
`At each stage the casing is perforated then frac fluid and proppant are pumped
`
`down the casing as depicted in Figure 2.4 for the 10th stage.
`
`22. After hydraulic fracture stimulation the composite frac plugs are
`
`drilled out to allow frac fluid to flow from each stimulated zone to the surface,
`
`hopefully followed by gas or oil production.
`
`
`
`
`
`7
`
`

`
`4. Wellhead Protection
`
`23. The frac fluid and proppant described above for fracture stimulation
`
`are pumped into the well at high pressures (up to 15,000 psi) and rates. This fluid
`
`and proppant can cause erosion and other damage to wellhead components through
`
`which it is pumped. With the increase in the number of hydraulic fracture
`
`treatments in the 1980’s, there was an increased need to protect wellhead
`
`components while pumping frac fluid and proppant.
`
`Figure 2.5
`Mounted Wellhead Protection
`Tool
`
`
`
`24. Figure 2.5
`
`is a
`
`schematic
`
`drawing of a wellhead protection tool that
`
`inserts a protective
`
`tubing
`
`inside
`
`the
`
`wellhead. This tool is a generic example of a
`
`type of early tool often referred to as a
`
`hydraulic cylinder
`
`hydraulic ram
`
`“casing saver.” A simple wellhead is shown
`
`control valve
`
`mounted on casing at the bottom of Figure
`
`2.5. A frac valve is installed on top the
`
`wellhead, and above
`
`the frac valve
`
`is
`
`mounted the wellhead protection tool and a
`
`setting tool.
`
`protective
`tubing
`
`seal cups
`
`frac valve
`adapter
`
`hydraulic
`hoses
`
`equalizing and
`bleedoff line
`
`25. Also
`
`in Figure
`
`2.5,
`
`the
`
`protective tubing is labeled and shown with
`
`3-1/2"
`
`line pipe
`
`3-1/2" casing
`
`ground level
`
`
`
`
`
`8
`
`

`
`seal cups at the bottom. The seal cups are typically made of rubber and create a
`
`fluid-tight seal within the casing to protect the wellhead from exposure to frac
`
`fluid. Above the tubing is a control valve with an equalizing and bleed-off
`
`hydraulic line. Shown at the top of Figure 2.5 is a setting tool, which is shown as a
`
`cylinder that uses hydraulic pressure on a piston to push the protective tubing into
`
`the wellhead. Hydraulic pressure is applied through the hoses at the upper right of
`
`Figure 2.6
`Inserted Wellhead Protection
`Tubing
`
`
`
`hydraulic
`cylinder
`
`hydraulic ram
`
`Figure 2.5.
`
`26. Figure
`
`2.6
`
`shows
`
`the
`
`protective tubing inserted inside the well-
`
`head and the line for pumping frac fluid
`
`and proppant attached above the control
`
`valve. Frac fluid and proppant are pumped
`
`into the injection line as depicted by the
`
`arrow on the right near the center of
`
`control valve
`
`Figure 2.6. The frac fluid and proppant
`
`travel
`
`through
`
`the protective
`
`tubing
`
`without making contact with the wellhead,
`
`thereby protecting
`
`the wellhead from
`
`erosion, corrosion and other possible
`
`damage.
`
`
`
`9
`
`Injection Line
`
`equalizing and
`bleedoff line
`
`tubing
`spool
`
`hydraulic
`hoses
`
`protective tubing
`frac valve
`seal cups
`
`3-1/2" casing
`
`ground level
`
`
`
`
`
`

`
`27. Because a casing saver like that shown in Figs. 2.5 and 2.6 seals
`
`inside the casing, the inner diameter of the tubing through which the frac fluid is
`
`pumped is necessarily smaller than the inner diameter of the casing. As a result,
`
`casing savers generally did not allow operators to use downhole tools, such as
`
`perforating guns, that were sized for the inner diameter of the casing. In order to
`
`use such downhole tools, the operator would first need to remove the casing saver,
`
`which would then have to be reinstalled before another stage could be fracture
`
`stimulated.
`
`III. Overview of U. S. Patent 6,179,053 to Dallas
`
`28. For a discussion of the concepts and original claims of the ’053
`
`Patent, I repeat Section (III) of my contemporaneous declaration submitted in
`
`support of OSES’s primary opposition to Greene’s petition for inter partes review.
`
`29. On 30 January 2001, L. Murray Dallas of Fairview, Texas was
`
`awarded U.S. Patent No. 6,179,053 entitled “Lockdown Mechanism for Well Tools
`
`Requiring Fixed-Point Packoff.” The patent application was filed 12 August 1999.
`
`This section describes the overall patent concept and the claims challenged in this
`
`proceeding. Ex. 1001 (’053 Patent).
`
`1.
`
`Dallas ’053 Patent Concepts
`
`30. The Dallas ’053 Patent abstract describes “an apparatus for securing a
`
`mandrel . . . in which the mandrel is packed off against a fixed-point in the well.”
`
`
`
`10
`
`

`
`The abstract describes “a [first] mechanical lockdown mechanism to secure the
`
`tool to the wellhead.” Ex. 1001 (’053 Patent), Abstract. Further, the abstract
`
`describes “a mechanical or hydraulic mechanism to move the mandrel into the
`
`operative position while the [first] mechanical lockdown mechanism is in a
`
`lockdown position.” Ex. 1001
`
`(’053 Patent), Abstract. After
`
`the
`
`mechanical/hydraulic mechanism has moved the mandrel into the operative
`
`position, a “second mechanical locking mechanism is provided to ensure the
`
`mandrel is maintained in the operative position in the event that hydraulic pressure
`
`is lost.” Ex. 1001 (’053 Patent), Abstract. The abstract further describes that the
`
`invention provides for a “range of adjustment of the lockdown mechanism” to
`
`allow a mandrel to be placed at a fixed-point in the well.
`
`31. The Dallas ’053 Patent describes two examples of its “apparatus for
`
`securing a mandrel . . . in which the mandrel is packed off against a fixed-point in
`
`the well.” The first example is shown in Figures 1-4 and again in Figure 9, and the
`
`second example is shown in Figures 5-8. Ex. 1001 (’053 Patent), Figures 1-9. The
`
`two examples differ in that the first is completely mechanical, while the second
`
`additionally uses a hydraulic cylinder as part of the second lockdown mechanism
`
`to move the mandrel into the operative position within the range of adjustment.
`
`
`
`11
`
`

`
`32. Figure 3.1 is a modified
`
`and annotated version of Figure 1 from
`
`the Dallas ’053 Patent. This drawing
`
`Figure 3.1
`Lockdown Mechanism for Fixed-Point Packoff
`2001 Dallas U.S. Patent No. 6,179,053
`
`
`mandrel
`head
`
`shows
`
`labeled components of
`
`the
`
`mandrel
`
`connector
`
`lockdown mechanisms.
`
`Running
`
`vertically through the center of Figure
`
`3.1 is the mandrel that is threaded into
`
`the mandrel head at the top, and which
`
`eventually mates up to a fixed point at
`
`the bottom. Around the mandrel at the
`
`center of Figure 3.1 is the base plate
`
`lockdown nut
`
`packing
`rings
`
`base plate
`
`wellhead
`
`fixed point
`
`
`
`that houses packing rings that seal around the mandrel’s outer diameter to hold
`
`wellbore pressure from below. A threaded lockdown nut firmly secures the
`
`mandrel head and connector to the base plate and wellhead.
`
`33.
`
`In Figure 3.1 bolts and nuts firmly connect the mandrel head to the
`
`connector, and allow adjustment of the position of the lower end of the mandrel at
`
`the fixed point. The Dallas ’053 Patent describes that different wellheads may be
`
`of different heights, as would be known to a person of ordinary skill in the art.
`
`These differences may be due to variations in the number of components or valves
`
`in a wellhead, differences in the manufacturer or model of wellhead components,
`
`
`
`12
`
`

`
`and/or differences in pressure ratings for wellhead components, among other
`
`things. The Dallas ’053 Patent also describes that mandrels may be of different
`
`lengths. Because of these variations, and because the lower end of the mandrel
`
`must be positioned at a fixed point within the wellhead, the invention allows the
`
`mandrel to be secured within a range of adjustment which is built into the
`
`lockdown mechanism. In Figure 3.1, that “range of adjustment” is shown as a
`
`distance “B” that is allowed from the use of the elongated bolts.
`
`34.
`
`Importantly, in the example shown in Figure 3.1, a setting tool must
`
`still be used to move the mandrel into the operative position at the fixed point
`
`packoff. Once the mandrel is at the fixed point packoff, nuts are screwed down on
`
`the elongated bolts, and the second lockdown mechanism has been locked down.
`
`This is shown in Figure 3 of the Dallas ’053 Patent. With both the first and second
`
`lock-down mechanisms locked down, the mandrel is secured in place, and will not
`
`move away from the operative position due to either pressure in the wellbore or
`
`upward pressure on the mandrel after fracking fluid has been injected into the
`
`system.
`
`
`
`13
`
`

`
`35. Figure 3.2 is a modified
`
`and annotated version of Figure 8 from
`
`the Dallas ’053 Patent. Figure 3.2
`
`shows
`
`the second example of
`
`the
`
`invention from the Dallas ’053 Patent,
`
`with the first and second lockdown
`
`mechanisms labeled near the center of
`
`Figure 3.2. As with the first example,
`
`the embodiment in this example utilizes
`
`a threaded lockdown nut that screws
`
`onto
`
`the base plate, securing
`
`the
`
`connecting flange to the base plate. The
`
`mandrel head is screwed onto the top of
`
`the mandrel.
`
`Figure 3.2
`Application of Lockdown Mechanism to a Wellhead
`2001 Dallas U.S. Patent No. 6,179,053
`
`
`hydraulic cylinder
`
`support plate
`
`support
`rods
`
`HP valve
`
`mandrel
`head
`
`mandrel
`
`connector
`
`lockdown
`nut
`
`baseplate
`
`BOP
`
`BOP
`
`packing
`rings
`
`second
`lockdown
`mechanism
`
`first
`lockdown
`mechanism
`
`seal sub
`fixed point
`casing head
`
`
`36. As also shown with the first example, the second lockdown
`
`mechanism of this example includes nuts that screw onto the threaded bolts that
`
`screw the mandrel head onto the connector top plate, securing the mandrel in the
`
`operative position. As noted above, the difference in this example is that a
`
`hydraulic cylinder that is separate from the setting tool is also included in the
`
`second lockdown mechanism.
`
`
`
`14
`
`

`
`37. The mandrel extends down to a fixed point which in this case is in a
`
`casing head. The hydraulic cylinder of the second lockdown mechanism is used to
`
`move the mandrel within the range of adjustment to the operative position at the
`
`fixed point packoff. The seal sub at the bottom of the mandrel seals wellbore
`
`pressure inside the mandrel when the mandrel is in the operative position.
`
`38. Mounted above the mandrel head is a high pressure valve. Above the
`
`high pressure valve is the mandrel injection mechanism, also known as a setting
`
`tool, which consists of a hydraulic cylinder and piston at the top of Figure 3.2.
`
`Support rods connect the setting tool to the base plate. It should be noted that the
`
`hydraulic piston of the setting tool is distinct from the hydraulic piston of the
`
`second lockdown mechanism, which is shown lower in the figure.
`
`39.
`
`Importantly, because the second lockdown mechanism of the second
`
`example includes a hydraulic cylinder and piston, the setting tool at the top of the
`
`figure may be removed after the first lockdown mechanism has been secured. This
`
`is because the second lockdown mechanism’s hydraulic cylinder may be used to
`
`move the mandrel within the range of adjustment into the operative position after
`
`the first lockdown mechanism has been secured. This is different from the first
`
`example, as shown in Figure 3.1 above, in which the setting tool is needed until the
`
`mandrel is locked in the operative position. After this, similar to the first example,
`
`once the mandrel is in the operative position, the nuts are screwed down onto the
`
`
`
`15
`
`

`
`threaded bolts, to lock the mandrel head, and thus the mandrel, in the operative
`
`position.
`
`2.
`
`Dallas ’053 Patent Claim 1
`
`40.
`
`It is my understanding that Claims 1 and 22 of the Dallas ’053 Patent
`
`are the only claims at issue in the inter partes review of the Dallas ’053 Patent.
`
`Figure 3.3
`Claim 1
`2001 Dallas U.S. Patent No. 6,179,053
`
`41. Claim 1 of the
`
`Dallas
`
`’053
`
`Patent,
`
`.
`
`presented in Figure 3.3, is
`
`an independent claim that
`
`describes an apparatus. The
`
`preamble
`
`describes
`
`the
`
`purpose of the apparatus
`
`“for securing a mandrel of a
`
`well tool in an operative
`
`
`
`position
`
`requiring
`
`fixed-
`
`
`
`
`point packoff in the well.” After the preamble, Claim 1 describes the apparatus as
`
`comprising two lockdown mechanisms.
`
`42. When evaluating patent claims, each element of a claim must be
`
`examined. Following is a list of the elements of the apparatus described in Claim 1
`
`of the Dallas ’053 Patent:
`
`
`
`16
`
`

`
`• An apparatus for securing a mandrel of a well tool in an
`operative position requiring fixed-point packoff in the well;
`comprising:
`
`• A first and a second lockdown mechanism arranged so that the
`mandrel is locked in the operative position only when both the
`first and second lockdown mechanisms are in respective
`lockdown positions;
`
`• The first lockdown mechanism adapted to detachably maintain
`the mandrel in proximity to the fixed point packoff when in the
`lockdown position,
`
`• The first lockdown mechanism including a base member for
`connection to a wellhead of the well and
`
`• The first lockdown mechanism including a locking member for
`detachably engaging the base member; and
`
`• The second lockdown mechanism having a range of adjustment
`adequate to ensure that the mandrel can be moved into the
`operative position and locked down in the operative position
`while the first lockdown mechanism is in the lockdown
`position.
`
`
`
`17
`
`

`
`
`
`
`
`3.
`
`Dallas ’053 Patent Claim 22
`
`43. Claim 22
`
`is an
`
`independent claim that describes
`
`.
`
`Figure 3.4
`Claim 22
`2001 Dallas U.S. Patent No. 6,179,053
`
`a method. Similar to Claim 1, the
`
`preamble of Claim 22 describes
`
`the purpose of the method “for
`
`lock-down of a mandrel of a well
`
`tool in an operative position in
`
`which the mandrel is packed off
`
`against a fixed-point
`
`in
`
`the
`
`well.” Claim 22 is presented in
`
`Figure 3.4.
`
`44. Following is a list
`
`of the elements of the method
`
`
`
`described in Claim 22 of the Dallas ’053 Patent:
`
`• A method for lockdown of a mandrel of a well tool in an
`operative position in which the mandrel is packed off against a
`fixed-point in the well, comprising steps of:
`
`• Mounting above a wellhead of the well an apparatus for
`securing the mandrel of the well tool in the operative position,
`comprising:
`
`
`
`18
`
`

`
`• A first and a second lockdown mechanism arranged so that the
`mandrel is locked in the operative position only when both the
`first and the second lockdown mechanisms are in respective
`lockdown positions.
`
`• The first lockdown mechanism being adapted to detachably
`maintain the mandrel in proximity to the fixed-point for
`packoff, and including:
`
`• a base member for connection to a top of a wellhead of the well
`and
`
`• a locking member for detachably engaging the base member;
`and
`
`• The second lockdown mechanism having a range of adjustment
`to ensure that the mandrel can be moved into the operative
`position and locked down in the operative position while the
`first lockdown mechanism is in the locked down position;
`
`• After inserting the mandrel through the wellhead into proximity
`to the fixed-point in the well, engaging the locking member of
`the first lockdown mechanism with the base member so that the
`mandrel is only moveable within the range of adjustment;
`
`• Moving the mandrel into the operative position if the mandrel is
`not yet packed off against the fixed-point; and
`
`• Locking the second lockdown mechanism in the lockdown
`position.
`
`
`
`19
`
`

`
`IV. Proposed Amended Claims of the ’053 Patent
`
`45. Below are the elements of the proposed amended claims of the ’053
`
`Patent, including underlined portions that represent the added language:
`
`Substitute Claim 28 (Proposed Substitute Claim for Claim 1)
`
`An apparatus for securing a mandrel of a well tool in an operative position
`
`requiring fixed-point packoff above the casing of the well and within a
`
`tubing head spool of a [in the] wellhead assembly, the apparatus comprising:
`
`a setting tool that is arranged to insert a bottom end of the mandrel
`
`through the wellhead, and is removable from the other portions of the
`
`apparatus;
`
`a first and a second mechanical lockdown mechanism that are separate
`
`from the setting tool and arranged so that the mandrel is locked in the
`
`operative position only when both the first and the second mechanical
`
`lockdown mechanisms are in respective lockdown positions;
`
`the first mechanical lockdown mechanism adapted to detachably
`
`maintain a bottom end of the mandrel in proximity to the fixed-point packoff
`
`when in the lockdown position;
`
`the first mechanical lockdown mechanism including a base member
`
`for connection to a wellhead of the well and a locking member for
`
`detachably engaging the base member; [and]
`
`
`
`20
`
`

`
`the second mechanical lockdown mechanism having a range of
`
`adjustment adequate to ensure that the mandrel can be moved into the
`
`operative position, and then locked down in the operative position without
`
`the use of hydraulic pressure while the first mechanical lockdown
`
`mechanism is in the lockdown position; and
`
`the mandrel including a packoff assembly that seals against the fixed-
`
`point packoff within the tubing head spool.
`
`Substitute Claim 29 (Proposed Substitute Claim for Claim 22)
`
`A method for lockdown of a mandrel of a well tool in an operative position
`
`in which the mandrel is packed off against a fixed-point above the casing of
`
`the well and within a tubing head spool of a [in the] wellhead assembly, the
`
`method comprising steps of:
`
`a) mounting above a wellhead of the well an apparatus for securing the
`
`mandrel of the well tool in the operative position, comprising:
`
`i)
`
`a setting tool that is arranged to insert a bottom end of the
`
`mandrel through the wellhead, and is removable from the other
`
`portions of the apparatus;
`
`ii.)
`
`a first and a second mechanical lockdown mechanism that are
`
`separate from the setting tool and arranged so that the mandrel
`
`is locked in the operative position only when both the first and
`
`
`
`21
`
`

`
`second mechanical lockdown mechanisms are in respective
`
`lockdown positions;
`
`iii.)
`
`the first mechanical lockdown mechanism being adapted to
`
`detachably maintain a bottom end of the mandrel in proximity
`
`to the fixed-point for packoff, and including a base member for
`
`connection to a top of a wellhead of the well and a locking
`
`member for detachably engaging the base member; [and]
`
`iv.)
`
`the second mechanical lockdown mechanism having a range of
`
`adjustment to ensure that the mandrel can be moved into the
`
`operative position, and then locked down in the operative
`
`position without the use of hydraulic pressure while the first
`
`mechanical lockdown mechanism is in the lockdown position;
`
`and
`
`v)
`
`the mandrel including a packoff assembly that seals against the
`
`fixed-point packoff within the tubing head spool;
`
`b)
`
`after inserting the mandrel through the wellhead into proximity to the
`
`fixed-point in the well, engaging the locking member of the first
`
`lockdown mechanism with the base member so that the mandrel is
`
`only moveable within the range of adjustment;
`
`
`
`22
`
`

`
`c) moving the mandrel into the operative position if the mandrel is not
`
`yet packed off against the fixed-point; [and]
`
`d)
`
`locking the second lockdown mechanism in the lo