Office Action 1: Non-Final Rejection (2024-12-04)
Rejection types: 102 - Lack of Novelty, 103 - Obviousness

CLAIMS:
CLAIMS

The invention claimed is:

1\. A well system, comprising: a wellhead arranged at a well surface and having a wellbore extending therefrom, the wellhead including a production tubing head housing; production casing extending from the wellhead and into the wellbore; production tubing extending from the production tubing head housing and into the production casing and thereby defining a tubing-casing annulus between the production tubing and the production casing; one or more side outlets extending outwardly from the production tubing head housing at an acute angle and in fluid communication with the tubing-casing annulus; and a downhole assembly conveyable into the tubing-casing annulus via the one or more side outlets and configured to obtain direct measurements of the tubing-casing annulus.
2\. The well system of claim 1, wherein each side outlet includes an outlet conduit extending from the production tubing head housing, and a gate valve arranged within the outlet conduit and operable to facilitate introduction of the downhole assembly into the production tubing head housing to access the tubing-casing annulus.
3\. The well system of claim 1, wherein the downhole assembly is selected from the group consisting of a logging tool, including but not limited to a corrosion logging tool, a gamma ray tool, a noise logging tool, a directional gyro tool, and similar, as well as a temperature sensor, a pressure sensor, a flow meter, and any combination thereof.
4\. The well system of claim 1, wherein the acute angle ranges between about 10° and about 75°.
5\. The well system of claim 4, wherein the acute angle is 45°.
6\. The well system of claim 1, further comprising a conveyance that introduces the downhole assembly into the tubing casing annulus via the one or more side outlets.
7\. The well system of claim 6, wherein the conveyance is selected from the group consisting of slickline, digital slickline, wireline, coiled tubing, and any combination thereof.
8\. The well system of claim 1, further comprising: a packer deployed within the tubing-casing annulus; and corrosion inhibiting diesel pumped into the tubing-casing annulus, wherein the downhole assembly obtains the direct measurements of the tubing-casing annulus while immersed in the corrosion inhibiting diesel.
9\. The well system of claim 1, wherein the production tubing head housing provides a bowl that defines a tubing hanger, and wherein the production tubing is suspended on the tubing hanger, which provides a sealed interface.
10\. The well system of claim 1, further comprising a casing head housing forming part of the wellhead, wherein the production casing extends from the casing head housing and into the wellbore.
11\. The well system of claim 1, further comprising a production tree operatively coupled to and in fluid communication with the wellhead via a master valve.
12\. A method of obtaining downhole measurements, comprising: opening a valve in a side outlet of a production tubing head housing forming part of a wellhead, wherein a wellbore extends from the wellhead and production casing extends from the wellhead and into the wellbore, and wherein production tubing extends from the production tubing head housing and into the production casing and thereby defines a tubing-casing annulus between the production tubing and the production casing; introducing a downhole assembly into the side outlet, wherein the side outlet extends outwardly from the production tubing head housing at an acute angle and is in fluid communication with the tubing-casing annulus; conveying the downhole assembly into the tubing-casing annulus via the side outlet; and obtaining direct measurements of the tubing-casing annulus with the downhole assembly while present within the tubing-casing annulus.
13\. The method of claim 12, wherein conveying the downhole assembly into the tubing-casing annulus is preceded by: deploying a packer within the tubing-casing annulus and thereby forming a bottom of the tubing-casing annulus; pumping corrosion inhibiting diesel into the tubing-casing annulus; and obtaining the direct measurements of the tubing-casing annulus while the downhole assembly is immersed in the corrosion inhibiting diesel.
14\. The method of claim 12, further comprising removing the downhole assembly from the tubing-casing annulus by retracting the conveyance out of the side outlet.
15\. The method of claim 12, wherein the downhole assembly is selected from the group consisting of a logging tool, a temperature sensor, a pressure sensor, a flow meter, and any combination thereof.
16\. The method of claim 11, wherein the acute angle of the side outlet of the production tubing head housing ranges between about 10° and about 75°.

OFFICE ACTION:
DETAILED ACTION
Notice of Pre-AIA  or AIA  Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Claim Rejections - 35 USC § 102
The following is a quotation of the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale, or otherwise available to the public before the effective filing date of the claimed invention.
Claim(s) 1, 2, 4, 6, 9, 10, 12, 14, and 16 is/are rejected under 35 U.S.C. 102a1 as being anticipated by US 2696261 to Ennis.
Regarding claim 1, Ennis discloses a well system, comprising: a wellhead 14 arranged at a well surface and having a wellbore extending therefrom, the wellhead including a production tubing head housing 15; production casing 10 extending from the wellhead and into the wellbore; production tubing 30 extending from the production tubing head housing and into the production casing and thereby defining a tubing-casing annulus between the production tubing and the production casing; one or more side outlets 50 extending outwardly from the production tubing head housing at an acute angle and in fluid communication with the tubing-casing annulus; and a downhole assembly 41 conveyable into the tubing-casing annulus via the one or more side outlets and configured to obtain direct measurements of the tubing-casing annulus (figs. 1-4; columns 2-3).
Regarding claim 2, the well system of claim 1, wherein each side outlet includes an outlet conduit 54 extending from the production tubing head housing, and a gate valve 55 arranged within the outlet conduit and operable to facilitate introduction of the downhole assembly into the production tubing head housing to access the tubing-casing annulus (figs. 1-2).
Regarding claim 4, the well system of claim 1, wherein the acute angle ranges between about 10° and about 75° (figs. 1-2).
Regarding claim 6, the well system of claim 1, further comprising a conveyance 42 that introduces the downhole assembly into the tubing casing annulus via the one or more side outlets (figs. 1-2).
Regarding claim 9, the well system of claim 1, wherein the production tubing head housing provides a bowl that defines a tubing hanger 35, and wherein the production tubing is suspended on the tubing hanger, which provides a sealed interface (fig. 1, wherein 24, 26, and 36 provide sealing).
Regarding claim 10, the well system of claim 1, further comprising a casing head housing 12 forming part of the wellhead, wherein the production casing extends from the casing head housing and into the wellbore (figs. 1-2).
Regarding claim 12, Ennis discloses a method of obtaining downhole measurements, comprising: opening a valve 55 in a side outlet 50 of a production tubing head housing 15 forming part of a wellhead 14, wherein a wellbore extends from the wellhead and production casing 10 extends from the wellhead and into the wellbore, and wherein production tubing 30 extends from the production tubing head housing and into the production casing and thereby defines a tubing-casing annulus between the production tubing and the production casing; introducing a downhole assembly 41 into the side outlet, wherein the side outlet extends outwardly from the production tubing head housing at an acute angle and is in fluid communication with the tubing-casing annulus; conveying the downhole assembly into the tubing-casing annulus via the side outlet; and obtaining direct measurements of the tubing-casing annulus with the downhole assembly while present within the tubing-casing annulus (figs. 1-4; columns 2-3).
Regarding claim 14, the method of claim 12, further comprising removing the downhole assembly from the tubing-casing annulus by retracting the conveyance out of the side outlet (col. 3, lines 57-83).
Regarding claim 16, the method of claim 11, wherein the acute angle of the side outlet of the production tubing head housing ranges between about 10° and about 75° (figs. 1-2).
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
This application currently names joint inventors. In considering patentability of the claims the examiner presumes that the subject matter of the various claims was commonly owned as of the effective filing date of the claimed invention(s) absent any evidence to the contrary.  Applicant is advised of the obligation under 37 CFR 1.56 to point out the inventor and effective filing dates of each claim that was not commonly owned as of the effective filing date of the later invention in order for the examiner to consider the applicability of 35 U.S.C. 102(b)(2)(C) for any potential 35 U.S.C. 102(a)(2) prior art against the later invention.
Claim(s) 3 and 15 is/are rejected under 35 U.S.C. 103 as being unpatentable over Ennis in view of US 20030010498 to Tolman et al.
Ennis teaches the downhole assembly from the system and method of claims 1 and 12 above, but the specific type of assembly is not explicitly taught.
Tolman teaches a wellhead with side outlets similar to that of Ennis, wherein it is further taught that a downhole assembly, that is again similar to that of Ennis, is conveyable through/into the wellhead and can be a logging tool (paragraphs 0040 and 0047; figs. 1B and 4).  It would have been obvious to one of ordinary skill in the art, having the teachings of Ennis and Tolman before him prior to the effective filing date of the claimed invention, to modify the downhole assembly taught by Ennis to include the logging tool of Tolman, in order to obtain the predictable result of obtaining a log of wellbore parameters in the annulus.
Claim(s) 5 and 7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Ennis in view of US 20170204714 to Roesner.
Regarding claim 5, Ennis teaches the side outlets from claim 1 above that are at an acute angle, but the specific angle(s) is/are not explicitly taught.
Roesner teaches a wellhead with side outlets similar to that of Ennis, wherein the outlets are at an acute angle of 45 degrees (paragraph 0055).  It would have been considered obvious to one of ordinary skill in the art, prior to the effective filing date of the claimed invention, to have the angle of the outlets of Ennis be at 45 degrees, since it has been held that where the general conditions of a claim are disclosed in the prior art, such as the unspecified acute angle of Ennis, that discovering the optimum or workable ranges involves only routine skill in the art.  In re Boesch, 617 F.2d 272, 205 USPQ 215 (CCPA 1980).  In re Aller, 105 USPQ 233.
Regarding claim 7, Ennis teaches the conveyance from claim 6 above, but does not specifically teach what the conveyance is.
Roesner teaches a wellhead with side outlets similar to that of Ennis, wherein it is further taught that wireline or coiled tubing can be used to convey tools through the wellhead (paragraph 0045).  It would have been obvious for a person of ordinary skill in the art before the effective filing date of the claimed invention to use wireline or coiled tubing as taught by Roesner as the conveyance of Ennis. A person of ordinary skill would have been motivated to do so, with a reasonable expectation of success, because wireline or coiled tubing was a well-known means for delivering tools downhole through a wellhead as taught by Roesner.
Claim(s) 11 is/are rejected under 35 U.S.C. 103 as being unpatentable over Ennis in view of US 4972904 to Godare.
Ennis teaches the wellhead from claim 1 above, but does not specifically teach that there is a production tree operatively coupled to and in fluid communication with the wellhead via a master valve.
Godare teaches a wellhead similar to that of Ennis, wherein it is further taught that there is a production tree operatively coupled to and in fluid communication with the wellhead via a master valve 22 (fig. 1).  It would have been obvious to one of ordinary skill in the art, having the teachings of Ennis and Godare before him prior to the effective filing date of the claimed invention, to modify the wellhead taught by Ennis to include the production tree and master valve of Godare, in order to obtain the predictable result of being able to control the flow if production fluid from the wellhead.
Claim(s) 8 and 13 is/are rejected under 35 U.S.C. 103 as being unpatentable over Ennis in view of US 20210054697 to Dokhon et al.
Ennis teaches the system and method of claims 1 and 12 above, but is it not explicitly taught that conveying the downhole assembly into the tubing-casing annulus is preceded by: deploying a packer within the tubing-casing annulus and thereby forming a bottom of the tubing-casing annulus; pumping corrosion inhibiting diesel into the tubing-casing annulus; and obtaining the direct measurements of the tubing-casing annulus while the downhole assembly is immersed in the corrosion inhibiting diesel.
Dokhon teaches a wellhead and wellbore system/method similar to that of Ennis, wherein it is further taught that the method includes deploying a packer 117 within the tubing-casing annulus and thereby forming a bottom of the tubing-casing annulus; pumping corrosion inhibiting diesel into the tubing-casing annulus; and obtaining the direct measurements of the tubing-casing annulus while the downhole assembly is immersed in the corrosion inhibiting diesel (fig. 1; at least paragraphs 0020 and 0027).  It would have been obvious to one of ordinary skill in the art, having the teachings of Ennis and Dokhon before him prior to the effective filing date of the claimed invention, to modify the system/method taught by Ennis to include the deployment of a packer and pumping of the diesel into the annulus of Dokhon, in order to obtain the predictable result of providing corrosion protection to prolong the life of the well (paragraph 0020 of Dokhon).  After this modification, the downhole assembly will be conveyed into the diesel in the annulus of Ennis so that the assembly can take its measurements as intended.
Conclusion
The prior art made of record on form 892 and not relied upon is considered pertinent to applicant's disclosure.

APPLICANT REBUTTAL: REMARKS
/
ARGUMENTS
.   General Remarks and Disposition of the Claims
Please consider the application in view of the following remarks. Applicant thanks the Examiner for careful consideration of this application.
At the time of the Office Action, claims 1-16 were pending in this application and claims 1-16 were rejected in the Office Action.
By this paper, claims 1, 8, 12 and 13 have been amended, claims 17 and 18 are newly presented, and no claims have been canceled. These amendments are supported by the specification as filed. All the amendments are made in a good faith effort to advance the prosecution on the merits of this case. It should not be assumed that the amendments made herein were made for reasons related to patentability. Applicant requests that the above amendments be entered and further requests reconsideration in light of the amendments and remarks contained herein. II.  Remarks Regarding Rejections under 35 U.S.C. §§ 102 and 103
Claims 1, 2, 4, 6, 9, 10, 12, 14 and 16 stand rejected under 35 U.S.C. § 102 as anticipated by U.S. Patent No. 2,696,261 Ennis. Claims 3 and 15 stand rejected under 35 U.S.C. § 103 as unpatentable over Ennis in view of U.S. Patent Pub. 2003/0010498 to Tolman et al., claims 5 and 7 stand rejected as unpatentable over Ennis in view of U.S. Patent Pub. 2017/0204714 to Roesner, claim 11 is rejected as unpatentable over Ennis in view of U.S. Patent No. 4,972,904 to Godare, and claims 8 and 13 are rejected as unpatentable over Ennis in view of U.S. Patent Pub. 2021/0054697 to Dokhon et al.
Applicant respectfully submits that Ennis does not disclose, teach or suggest each and every limitation of independent claims 1 and 12, as amended herein, and moreover, that none of Tolman, Roesner, Godare and/or Dokhon may be properly combined with Ennis to arrive at independent claims 1 and 12. More particularly, Ennis does not describe a "packer set . . . against the production casing and the production tubing" as recited in amended claim 1, or the similar features recited in amended claim 12. Moreover, Applicant submits that any proposed modification of Ennis to arrive at amended claims 1 and 12 would render Ennis unsatisfactory for its intended purpose in opposition to MPEP § 2143.01(V).
According to example embodiments of Applicant's disclosure, a well system 100 includes a wellhead 104 with side outlets 136 as illustrated in FIG. 1, reproduced below. The side outlets 136 extend at an acute angle relative to a longitudinal axis of the wellhead 104 to facilitate conveying a downhole assembly 134 through the wellhead 104 into a tubing-casing annulus 128 as described in paragraphs [0028] and [0032] of Applicant's specification.
1 D4
A packer 146 is s
and production tubing 126 to prevent produced formation fluids from contacting and corroding an interior of the production casing 124 (paragraph [0034]). The packer 146 may also maintain a corrosion inhibiting diesel 148 within the tubing- casing annulus 128, which may facilitate detecting leaks with a temperature sensor
or flow sensor of the downhole assembly 134 as described in paragraph [0032] of Applicant's specification.
In contrast, Ennis describes a well system as illustrated in FIG. 1, reproduced below. The well system includes a rotating head member 15 with a guide sleeve 50 for introducing an instrument 41 into an annulus defined between a casing 10 and tubing 30 (see col. 3, lines 42-56). Any twists or wraps around the tubing 30 that develop in a line 42 carrying the instrument 41 may be unwound by rotating the rotary head member 15 while withdrawing the instrument (col. 3, lines 57-68). The tubing 30 rotates along with the rotary head member 15 (col. 3, lines 23-33) to allow for the line 42 to be unwound from the tubing 30 without lifting the flow tubing or disturbing the well equipment (col. 3, lines 75-79).
o
From Ennis
The Office Action acknowledges that Ennis does not describe deploying a packer into an annulus defined between the casing 10 and the tubing 30 and relies on Dokhon for this feature (page 7 of the Office Action). Applicant respectfully submits that even if Dokhon does describe a packer, that the combination of Dokhon with Ennis would be improper.
MPEP § 2143.01(V) states "[i]f a proposed modification would render the prior art invention being modified unsatisfactory for its intended purpose, then there is no suggestion or motivation to make the proposed modification. In re Gordon, 733 F.2d 900, 221 USPQ 1125 (Fed. Cir. 1984)." Additionally, [i]f the proposed modification or combination of the prior art would change the principle of operation of the prior art invention being modified, then the teachings of the references are not sufficient to render the claims prima facie obvious. In re Ratti, 270 F.2d 810, 123 USPQ 349 (CCPA 1959)."
In the present case, setting a packer against the casing 10 and tubing 30 of Ennis to maintain a corrosion inhibiting diesel within a tubing-casing annulus in the manner recited in claims 1 and 12 would not permit the tubing 30 to rotate along with the rotary head member 15. Those skilled in the art recognize that packers are generally expanded radially outward in a wellbore with hydraulic pressure or other means to create a tight seal against the wellbore tubulars. Maintaining a tight seal would frustrate the rotation of the tubing 30 for the stated purpose of unwinding the line 42 from the tubing.
As such, Applicant respectfully submits that a person of ordinary skill in the art would not have a reason to combine these features and that further, the combination thereof would frustrate the principle of operation of Ennis.
Therefore, Applicant respectfully requests withdrawal of the rejections of independent claims 1 and 12 as anticipated by Ennis under 35 U.S.C. § 102, and/or the rejections of claims 2-11 and 13-16, which depend from claims 1 or 12, as either anticipated by Ennis and/or being unpatentable over Ennis in view of Tolman, Roesner, Godare and/or Dokhon under 35 U.S.C. § 103.
III. Remarks Regarding Newly Presented Claims 17 and 18
Claims 17 and 18 are generally directed detecting a leak path in the casing 124 by submerging a temperature sensor or flow sensor into the completion fluid (diesel 148) in direct contact with the leak path as described at least in paragraph [0030] of Applicant's specification.  Applicant submits that the Applicant's specification as originally filed fully supports new claims 17 and 18. Also, Applicant submits that claims 17 and 18 are allowable for at least the reasons independent claim 12, from which claims 17 and 18 depend, is allowable as described above. Accordingly, Applicant requests entry and allowance of newly presented claims 17 and 18.
SUMMARY
In light of the above, Applicant respectfully requests reconsideration and withdrawal of the outstanding rejections. Applicant further submits that the application is now in condition for allowance. Should the Examiner have any questions, comments or suggestions, the Examiner is invited to contact the attorney of record by telephone, facsimile, or electronic mail.
Applicant believes that no fees are due with this response. Should the Commissioner deem that any fees are due, including any fees for extensions of time, Applicant requests that the Commissioner accept this as a Petition Therefore, and direct that any additional fees be charged to Vorys, Sater, Seymour and Pease LLP Account No. 220585, Order Number 074940-000209.
Respectfully submitted,

NEXT OFFICE ACTION: DETAILED ACTION
Notice of Pre-AIA  or AIA  Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Allowable Subject Matter
Claims 1-18 are allowed.
The following is an examiner’s statement of reasons for allowance: The independent claims have been amended to include a packer that is set against the casing and the production tubing, and a corrosion inhibiting fluid is in the annulus above said packer.  US 2696261, which was originally used to reject claims 1 and 12 in the office action mailed on 12/4/2024, does not teach such a packer arrangement. The examiner agrees with the applicant’s remarks that it would not be obvious to modify 2696261 to include a packer because it would defeat the ability of the production tubing to rotate, which is how the line 42 is wound/unwound.  After further search and consideration, the pending claims are deemed to be on condition for allowance.
Any comments considered necessary by applicant must be submitted no later than the payment of the issue fee and, to avoid processing delays, should preferably accompany the issue fee.  Such submissions should be clearly labeled “Comments on Statement of Reasons for Allowance.”
Conclusion

CITED REFERENCE SUMMARIES: Ref US20040206507A1: Claims:
A manifold device for a well having an outer casing, a wellhead for being supported on the outer casing and a production tubing string for being suspended from the wellhead within the outer casing, the device comprising: a tubular body having a hollow interior extending in a longitudinal direction of the body between first and second open ends of the body for receiving the tubing string therethrough; at least one access passage formed in the tubular body, said access passage extending generally in the longitudinal direction of the body between an external end of said access passage which is spaced radially from the hollow interior of the tubular body and an internal end of said access passage converging in communication with the hollow interior; and mounts at the respective first and second open ends of the body for mounting the body in communication between the outer casing and the wellhead of the well.
a tubular body having a hollow interior extending in a longitudinal direction of the body between first and second open ends of the body for receiving the tubing string therethrough;
at least one access passage formed in the tubular body, said access passage extending generally in the longitudinal direction of the body between an external end of said access passage which is spaced radially from the hollow interior of the tubular body and an internal end of said access passage converging in communication with the hollow interior; and
mounts at the respective first and second open ends of the body for mounting the body in communication between the outer casing and the wellhead of the well.
The device according to claim 1 wherein the mounts at the respective first and second ends of the body are configured for mounting in series with the outer casing of the well.
The device according to claim 1 wherein the hollow interior comprises a cylindrical bore having an inner diameter which is approximately equal to an inner diameter of the outer casing.
The device according to claim 1 wherein there is provided a transitional casing for connection between the tubular body and the wellhead.
The device according to claim 1 wherein the hollow interior of the body comprises a cylindrical bore extending through the body and wherein the mounts each comprise a counter bore terminating at an internal shoulder formed in the bore extending through the tubular body.
The device according to claim 5 wherein at least one of the counter bores is internally threaded.
The device according to claim 1 wherein said at least one access passage extends at an inclination of less than fifteen degrees from the longitudinal direction of the body.
The device according to claim 1 wherein the internal end of said at least one access passage lies flush with an interior surface of the hollow interior of the tubular body.
The device according to claim 1 wherein there is provided four access passages evenly spaced circumferentially about the tubular body.
The device according to claim 1 wherein the hollow interior comprises a cylindrical bore extending through the tubular body which has a constant interior diameter.
A method of accessing a casing annulus of a well having an outer casing, a wellhead for being supported on the outer casing and a production tubing string for being suspended from the wellhead within the outer casing to define the casing annulus between the outer casing and the tubing string, the method comprising: providing a manifold device including a tubular body having a hollow interior extending in a longitudinal direction of the body between first and second open ends of the body; providing at least one access passage formed in the tubular body to extend generally in the longitudinal direction of the body between an external end of said access passage which is spaced radially from the hollow interior of the tubular body and an internal end of said access passage converging in communication with the hollow interior; mounting the manifold device in communication between the outer casing and the wellhead of the well with the tubing string being received through the hollow interior of the body of the device; and inserting tools into the casing annulus through said at least one access passage formed in the tubular body of the manifold device.
providing a manifold device including a tubular body having a hollow interior extending in a longitudinal direction of the body between first and second open ends of the body;
providing at least one access passage formed in the tubular body to extend generally in the longitudinal direction of the body between an external end of said access passage which is spaced radially from the hollow interior of the tubular body and an internal end of said access passage converging in communication with the hollow interior;
mounting the manifold device in communication between the outer casing and the wellhead of the well with the tubing string being received through the hollow interior of the body of the device; and
inserting tools into the casing annulus through said at least one access passage formed in the tubular body of the manifold device.
The method according to claim 11 including orienting said at least one access passage to extend radially inwardly and downwardly from the external end to the internal end thereof.
The method according to claim 11 including forming the hollow interior of the tubular body with a cylindrical bore having an internal diameter which is approximately equal to the internal diameter of the outer casing.
The method according to claim 11 including providing a transitional casing between the manifold device and the wellhead so as to mount the manifold device in series with the outer casing and the transitional casing.
The method according to claim 11 wherein the hollow interior of the tubular body is formed by a bore extending through the tubular body including a counter bore formed in at least one end of the bore which terminates at an internal shoulder, the method including receiving the outer casing in the counter bore at a bottom end of the tubular body.
The method according to claim 11 including threadably securing the manifold device to at least one of the outer casing and the wellhead.
The method according to claim 11 including orienting said at least one access passage to extend at an inclination of less than fifteen degrees from the longitudinal direction of the tubular body.
The method according to claim 11 wherein the internal end of said at least one access passage lies flush with interior cylindrical walls of the hollow interior of the tubular body.
The method according to claim 11 wherein there is provided four access passages formed in the tubular body at evenly circumferentially spaced positions.
The method according to claim 11 including forming the hollow interior of the tubular body by a cylindrical bore extending through the tubular body having an interior diameter which is approximately equal to an interior diameter of the wellhead.
Ref US8820400B2: Claims:
An erosion resistant frac head, comprising: a frac head body having a top end with an axial port and a central passage that extends though the axial port and the frac head body, an annular shoulder that surrounds the axial port and is downwardly inclined with respect to the axial port; at least two top entry ports in respective circular sockets machined in the annular shoulder, the circular sockets communicating with circular bores that communicate with the central passage; the central passage including a convergence chamber where the central passage and the circular bores converge, a bottom of the convergence chamber being wider than a top of the convergence chamber; an expansion chamber with a downwardly and outwardly inclined sidewall directly below the convergence chamber; and, a mixing chamber directly below the expansion chamber; and a replaceable bottom leg having a bottom end that comprises a flange, the bottom leg being threadedly secured in a bottom leg socket in the frac head body.
a frac head body having a top end with an axial port and a central passage that extends though the axial port and the frac head body, an annular shoulder that surrounds the axial port and is downwardly inclined with respect to the axial port;
at least two top entry ports in respective circular sockets machined in the annular shoulder, the circular sockets communicating with circular bores that communicate with the central passage;
the central passage including a convergence chamber where the central passage and the circular bores converge, a bottom of the convergence chamber being wider than a top of the convergence chamber; an expansion chamber with a downwardly and outwardly inclined sidewall directly below the convergence chamber; and, a mixing chamber directly below the expansion chamber; and
a replaceable bottom leg having a bottom end that comprises a flange, the bottom leg being threadedly secured in a bottom leg socket in the frac head body.
The erosion resistant frac head as claimed in claim 1 wherein the replaceable bottom leg comprises an elongated pin thread that cooperates with a box thread of the bottom leg socket to secure the replaceable bottom leg in the bottom leg socket, and a lock nut threadedly secured to the elongated pin thread, the lock nut being adapted to be tightened against a bottom end of the frac head body to lock the replaceable bottom leg in the bottom leg socket.
The erosion resistant frac head as claimed in claim 2 wherein the replaceable bottom leg retains an abrasion resistant liner that forms the mixing chamber of the frac head body.
The erosion resistant frac head as claimed in claim 3 further comprising an O-ring received in an O-ring groove in the frac head body adjacent both a top end and a bottom end of an outer sidewall of the abrasion resistant liner.
The erosion resistant frac head as claimed in claim 1 wherein the axial port terminates in a threaded union.
The erosion resistant frac head as claimed in claim 1 wherein the outwardly and downwardly inclined sidewall of the expansion chamber is downwardly inclined at about 45Â° with respect to a central axis of the frac head body.
The erosion resistant frac head as claimed in claim 1 wherein the convergence chamber is about 25% wider at the bottom of the convergence chamber than at the top of the convergence chamber.
The erosion resistant frac head as claimed in claim 1 further comprising an abrasion resistant liner that lines the mixing chamber and is supported by a top end of the replaceable bottom leg.
The erosion resistant frac head as claimed in claim 8 wherein the abrasion resistant liner has a cylindrical outer sidewall, and an inner sidewall that has a cylindrical upper section, a downwardly and inwardly inclined central section, and a cylindrical lower section.
An erosion resistant frac head, comprising: a frac head body having a top end with an axial port and a central passage that extends though the axial port and the frac head body, an annular shoulder that surrounds the axial port and is downwardly inclined with respect to the axial port; at least two top entry ports received in respective circular sockets machined in the annular shoulder, the at least two top entry ports being in fluid communication with circular bores that communicate with the central passage; the central passage including a convergence chamber where the central passage and the circular bores converge, a bottom of the convergence chamber being wider than a top of the convergence chamber; an expansion chamber with a downwardly and outwardly inclined sidewall directly below the convergence chamber; and, a mixing chamber directly below the expansion chamber; and a bottom leg having a bottom end that comprises a flange, the bottom leg being removably received in a bottom leg socket in the frac head body with an elongated pin thread that cooperates with a box thread of the bottom leg socket to secure the bottom leg in the bottom leg socket, and a lock nut threadedly secured to the elongated pin thread, the lock nut being tightened against a bottom end of the frac head body to lock the bottom leg in the bottom leg socket.
at least two top entry ports received in respective circular sockets machined in the annular shoulder, the at least two top entry ports being in fluid communication with circular bores that communicate with the central passage;
a bottom leg having a bottom end that comprises a flange, the bottom leg being removably received in a bottom leg socket in the frac head body with an elongated pin thread that cooperates with a box thread of the bottom leg socket to secure the bottom leg in the bottom leg socket, and a lock nut threadedly secured to the elongated pin thread, the lock nut being tightened against a bottom end of the frac head body to lock the bottom leg in the bottom leg socket.
The erosion resistant frac head as claimed in claim 10 wherein the outwardly and downwardly inclined sidewall of the expansion chamber is inclined at an angle of at least 45Â° with respect to a central axis of the frac head body.
The erosion resistant frac head as claimed in claim 10 wherein the annular shoulder is downwardly inclined with respect to the axial port at an angle of about 45Â° with respect to a central axis of the frac head body.
The erosion resistant frac head as claimed in claim 10 wherein the convergence chamber is about 25% wider at the bottom of the convergence chamber than at the top of the convergence chamber.
The erosion resistant frac head as claimed in claim 10 further comprising an abrasion resistant liner that lines the mixing chamber and is supported by a top end of the bottom leg.
The erosion resistant frac head as claimed in claim 14 wherein the abrasion resistant liner has a cylindrical outer sidewall, and an inner sidewall that has a cylindrical upper section, a downwardly and inwardly inclined central section, and a cylindrical lower section.
An erosion resistant frac head, comprising: a frac head body having a top end with an axial port and a central passage that extends though the axial port and the frac head body, an annular shoulder that surrounds the axial port and is downwardly inclined with respect to the axial port; at least two top entry ports received in respective circular sockets machined in the annular shoulder, the circular sockets communicating with circular bores that communicate with the central passage; a bottom leg having a bottom end comprising a flange, the bottom leg being removably secured in a bottom leg socket in the frac head body; and the central passage including a convergence chamber where the central passage and the circular bores converge, a bottom of the convergence chamber being wider than a top of the convergence chamber; an expansion chamber with a downwardly and outwardly inclined sidewall directly below the convergence chamber; and, a mixing chamber directly below the expansion chamber.
at least two top entry ports received in respective circular sockets machined in the annular shoulder, the circular sockets communicating with circular bores that communicate with the central passage;
a bottom leg having a bottom end comprising a flange, the bottom leg being removably secured in a bottom leg socket in the frac head body; and
the central passage including a convergence chamber where the central passage and the circular bores converge, a bottom of the convergence chamber being wider than a top of the convergence chamber; an expansion chamber with a downwardly and outwardly inclined sidewall directly below the convergence chamber; and, a mixing chamber directly below the expansion chamber.
The erosion resistant frac head as claimed in claim 16 further comprising an abrasion resistant liner in the mixing chamber that is supported by a top end of the bottom leg.
The erosion resistant frac head as claimed in claim 17 further comprising fluid seals to inhibit fluid penetration between the mixing chamber and the abrasion resistant liner.
The erosion resistant frac head as claimed in claim 16 wherein the convergence chamber is about 25% wider at the bottom of the convergence chamber than at the top of the convergence chamber.
Ref US20030010498A1: Claims:
A wellbore fluid injection device for use in introducing fluid into a wellbore, said wellbore fluid injection device comprising: a main housing having a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of said wellbore, said main central bore having diameter at least equal to the inside diameter of said wellbore, thereby allowing wellbore equipment full access to said wellbore; and at least one side fluid inlet bore extending tangentially into said main central bore at a downwardly inclined angle to the longitudinal axis of said wellbore, whereby treatment fluid injected into said wellbore from said side fluid inlet bore will travel in a downward spiral flow pattern thereby reducing impingement of said treatment fluid upon any wellbore equipment positioned in said wellbore.
a main housing having a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of said wellbore, said main central bore having diameter at least equal to the inside diameter of said wellbore, thereby allowing wellbore equipment full access to said wellbore; and
at least one side fluid inlet bore extending tangentially into said main central bore at a downwardly inclined angle to the longitudinal axis of said wellbore, whereby treatment fluid injected into said wellbore from said side fluid inlet bore will travel in a downward spiral flow pattern thereby reducing impingement of said treatment fluid upon any wellbore equipment positioned in said wellbore.
The apparatus of claim 1 wherein the internal diameter, quantity, orientation and downward angles of said side fluid inlet bores are chosen to obtain a favorable downward spiral flow pattern.
The apparatus of claim 1 wherein the internal diameter, quantity, orientation, and downward angles of said side fluid inlet bores are chosen to obtain a favorable horizontal fluid velocity.
The apparatus of claim 1 wherein said housing is manufactured from billet steel.
The apparatus of claim 1 wherein said housing is manufactured from bar stock steel.
The apparatus of claim 1 wherein at least one valve is machined into said housing.
The apparatus of claim 1 wherein said wellhead fluid injection device has at least two fluid inlet housings.
The apparatus of claim 7 wherein at least one side fluid inlet bore is lower than at least one other side fluid inlet bore.
A method of injecting fluid into a wellbore comprising: providing at the wellhead a fluid injection device having a main housing with a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of said wellbore, said main central bore having a diameter at least equal to the inside diameter of said wellbore, thereby allowing wellbore equipment full access to said wellbore; providing at least one fluid inlet bore extending tangentially into said main central bore at an inclined angle to the longitudinal axis of said wellbore, whereby fluid injected into said wellbore from said side fluid inlet bore will travel in a downwardly spiral flow pattern; and directing fluid injected from said side fluid inlet bore to enter said main central bore and travel in a downward spiral flow pattern thereby reducing impingement of said injected fluid upon any device positioned in said wellbore.
providing at the wellhead a fluid injection device having a main housing with a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of said wellbore, said main central bore having a diameter at least equal to the inside diameter of said wellbore, thereby allowing wellbore equipment full access to said we
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