UNITED STATES PATENT AND TRADEMARK OFFICE
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`BEFORE THE PATENT TRIAL AND APPEAL BOARD
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`GREENE’S ENERGY GROUP, LLC,
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`Petitioner,
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`v.
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`OIL STATES ENERGY SERVICES, LLC,
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`Patent Owner.
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`Case IPR2014-00216
`Patent No. 6,179,053
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`Case IPR2014-00364
`Patent No. 6,289,993
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`DECLARATION OF L. MURRAY DALLAS
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`Greene’s Energy Group, LLC v. Oil States Energy Services, LLC, IPR2014-00216, Ex. 2013
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`BEFORE THE PATENT TRIAL AND APPEAL BOARD
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`
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`GREENE’S ENERGY GROUP, LLC,
`
`Petitioner,
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`v.
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`OIL STATES ENERGY SERVICES, LLC,
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`Patent Owner.
`
`
`
`
`Case IPR2014-00216
`Patent No. 6,179,053
`
`
`Case IPR2014-00364
`Patent No. 6,289,993
`
`
`DECLARATION OF L. MURRAY DALLAS
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`Greene’s Energy Group, LLC v. Oil States Energy Services, LLC, IPR2014-00216, Ex. 2013
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`I, L. Murray Dallas, hereby declare as follows:
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`1.
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`I am over 18 years of age and personally competent to make this
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`declaration, having personal knowledge of all facts set forth herein.
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`2.
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`I am presently an employee of Oil States Energy Services, LLC
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`(“OSES”). I have been employed by OSES since 2005, when OSES acquired
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`Stinger Wellhead Protection, Inc. (“Stinger”), a company I founded in 1998.
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`Between 1998 and 2005, I was the owner of Stinger and held various executive
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`titles there. I have worked in the oilfield business since 1972, and am the named
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`inventor on dozens of issued U.S. patents.
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`3. When operators of oil & gas wells want to stimulate well production,
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`they will often use a technique known as hydraulic fracturing. The fluid used in
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`hydraulic fracturing can be corrosive and/or abrasive, and is generally pumped into
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`the well at very high pressures. Accordingly, to avoid damage caused by the fluid,
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`the wellhead and other aboveground components generally need to be protected or
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`isolated during hydraulic fracturing operations. That isolation is generally
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`achieved using wellhead isolation tools.
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`4.
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`Prior to the mid-1990s, it was relatively rare for operators to perform
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`“multistage” hydraulic fracturing, in which several different locations within a well
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`are stimulated in succession. During this time, the most common wellhead
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`isolation tools were casing savers and tree savers, both of which must be removed
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`Case IPR2014-00216
`Patent No. 6,179,053
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`from the wellhead between each fracking stage, and then reinstalled for the next
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`stage.
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`5. Multistage fracking began to become more prevalent during the mid-
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`1990s, in large part due to the efforts of George Mitchell and his company,
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`Mitchell Energy. In multistage fracking, a casing saver or tree saver is
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`inconvenient and expensive because it must be installed and removed every time a
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`new stage is stimulated. Accordingly, in or around 1996, I began trying to develop
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`a wellhead isolation tool that would deliver superior performance for multistage
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`fracking jobs without removing the tool between stages.
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`6.
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`In or around early 1997, I conceived of a tool that Stinger came to
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`refer to as the “blowout preventer protector” or “BOP protector.” I filed a patent
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`application for this tool in the U.S. and another one in Canada (Canadian Patent
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`Application No. 2,195,118). The U.S. application eventually issued as U.S. Patent
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`No. 5,819,851. The Canadian application issued as Canadian Patent No.
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`2,195,118.
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`7.
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`During 1997, Stinger worked on building a commercial embodiment
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`of the tool described in what would become the ’851 Patent. We finished
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`construction and began using this BOP protector in or around the fall of 1997.
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`Over the course of the next several months, it quickly became apparent that this
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`Patent No. 6,179,053
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`BOP protector did not function as intended and was not suitable for use in
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`multistage fracking operations.
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`8.
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`The problem with the BOP protector arose from the fact that the seal
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`assembly, which was located at the bottom of the mandrel, was intended to be held
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`in place exclusively by hydraulic fluid pressure pushing down on the mandrel. The
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`hydraulic fluid pressure was simply not capable of reliably holding the seal
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`assembly in position against the upward pressure exerted by the fracking fluid, as
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`well as the natural formation within the wellbore. There were numerous variables
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`that led to this problem. The first such variable was the frequent and rapid changes
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`in fracking pressure, caused by changes in the rate at which fracking fluid was
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`being pumped downhole. These changes in fracking pressures, in turn,
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`necessitated changes in the hydraulic pressure that would have been necessary to
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`hold the mandrel in place. At the time this tool was being used, I had developed a
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`chart that was intended to tell the operator what level of hydraulic fluid pressure
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`applied to the top of the mandrel was necessary to maintain the mandrel in the
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`operative position. However, I realized quickly that it was simply not practical for
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`the operators to make this kind of adjustment in real time, particularly given the
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`complexity of these systems.
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`9.
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`There were numerous other factors that made the operation of the
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`BOP protector extremely unpredictable, even with the charts I had developed.
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`Patent No. 6,179,053
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`Those factors included the momentary pressure spikes caused by piston strokes in
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`positive displacement pumps, movement of the cup tool caused by swaying of the
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`tool itself, the unknown compressibility of the hydraulic fluid (given the possible
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`presence of entrained air), the possible contraction of the fluid due to temperature
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`differences, and the often uneven surface of the bit guide against which the cup
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`tool was required to seal.
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`10. Several of these factors were made worse by the required height of the
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`tool described in the ’851 Patent. Because a setting tool was integrated into its
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`design, the tool itself had to be long enough to provide the entire distance for the
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`mandrel to stroke into the wellhead. I believe the BOP protector that we built was
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`approximately five feet high, with an available stroke of approximately four feet.
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`This distance was insufficient to use the tool on many wells, especially those with
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`multiple blowout preventers or other components mounted on top of the wellhead.
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`Nevertheless, the tool could not be made any higher without causing severe safety
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`and operational problems, including excessive vibration and sway. Even with the
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`tool as built, I was often not comfortable with its height, particularly when it was
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`mounted more than a few feet above the ground. My concern over the high profile
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`of this tool was one of the primary reasons I eventually designed the tool claimed
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`in the ’053 Patent.
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`11.
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`I personally recall at least one wellsite where I witnessed this failure
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`as it was occurring. After the seal assembly had been moved into position, the seal
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`failed and, at the same time, the pressure increased in the hydraulic cylinder
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`containing the fluid that was supposed to hold the seal in position. The only way
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`for that pressure to increase was that the fluid was compressed when the mandrel
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`moved away from the intended sealing location.
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`12. The BOP protector described in the ’851 Patent was used on perhaps
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`six to twelve different wells. My best estimate is that the tool failed, as described
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`above, approximately 50% of the time. Based on this unacceptable performance in
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`the field, and because of the many variables discussed above and the general
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`unpredictability and unreliability of using hydraulic fluid in a tool like this, I
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`concluded that it was simply not going to be possible to effectively lock the
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`mandrel in the operative position using a tool like that described in the ’851 Patent.
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`If I could have made the concept work, I would have, but my experience with the
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`tool demonstrated that I needed to try something different.
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`13. Because of the problems with the BOP protector, I started over trying
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`to design a different tool that would solve the issues with prior art wellhead
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`isolation tools. The new tool that I designed is the one described and claimed in
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`the ’053 Patent, which affirmatively mechanically “locks” the mandrel and seal
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`assembly in the operative position, rather than relying on hydraulic pressure to
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`Patent No. 6,179,053
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`(hopefully) hold the seal in place. Thus, the entire reason the ’053 Patent exists is
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`because it is fundamentally different from the BOP protector in the ’851 Patent,
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`which is because that latter design did not function for the intended purpose.
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`14. Unlike the BOP protector of the ’851 Patent, the stage frac tool
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`claimed in the ’053 Patent met with swift customer approval and demand, in large
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`part because of its superior reliability. Large customers such as Anadarko and
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`Mitchell Energy (later Devon Energy) adopted the new tool almost immediately.
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`Anadarko even machined its existing wellheads in order to retrofit them so they
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`would work properly with Stinger’s new stage frac tool.
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`15. One obstacle that Stinger encountered with its new tool involved the
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`location of seals on the side of the mandrel that would seal against the inner
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`surface of the tubing head spool. Historically, this had never been an option
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`because the tubing spool was cast and its inner surface was too irregular and
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`unpredictable to form a reliable seal. Moreover, when I approached the
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`manufacturers of tubing head spools about the possibility of changing the design so
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`that a seal could be formed, they refused to even consider the idea. Ultimately,
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`Stinger was required to work with an independent third party to manufacture its
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`own tubing head spools that would work with its new wellhead isolation tool.
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`When the other manufacturers saw that large customers like Anadarko and
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`Mitchell were so enthusiastic about the new isolation tool that they would also buy
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`Patent No. 6,179,053
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`these new tubing head spools from Stinger, they quickly changed course and began
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`building similar products. Such tubing head spools are now the industry standard.
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`16.
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`I have reviewed U.S. Patent No. 4,076,079. I am aware that this
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`patent refers in column 2 to a prior art tool in which a tubing hanger would seal
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`inside a tubing spool. I do not believe Shell, the owner of this patent, ever made or
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`commercially used the tool described in this patent. I believe one of the reasons
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`for Shell’s failure was likely that, as discussed above, prior to my efforts beginning
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`in 1999, tubing head spools were not manufactured with a surface that would allow
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`an effective seal to be formed. Had Shell tried in 1978 – or at any time prior to
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`2000 – to make the tool shown in this patent, I am quite confident that it would not
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`have worked to adequately protect the blowout protectors or other components of
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`the wellhead assembly during hydraulic fracturing procedures.
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`17. Due to the level of customer demand for its new stage frac tool,
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`Stinger built new tools as fast as it could, including the construction of a new
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`machine shop, as well as employees working overtime and night shifts. By the
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`time of the sale to OSES in 2005, the stage frac tool was responsible for
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`approximately one-third of Stinger’s total revenue. Stinger was sold to OSES for
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`approximately $103,000,000. I believe the stage frac tool has continued to have
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`similar success over the past nine years, but I have not been personally aware of
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`those details.
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`Further, these statements are 1nade with the knowledge that willful false statements
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`are punishable by fine or imprisonment, or both, under Seetion 1001 of Title 18 of
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`the 246 United States Code.
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