AU2016209370A1

AU2016209370A1 - Flowline and injecton tee for frac system

Info

Publication number: AU2016209370A1
Application number: AU2016209370A
Authority: AU
Inventors: Ana Ayres; Kwong-Onn Chan; Gajanan HEGDE; Jason Williams
Original assignee: GE Oil and Gas Pressure Control LP
Current assignee: Vault Pressure Control LLC
Priority date: 2015-01-20
Filing date: 2016-01-20
Publication date: 2017-08-10
Anticipated expiration: 2036-01-20
Also published as: US20160208570A1; CA2974206A1; AU2016209370B2; EP3247872A2; WO2016118596A2; WO2016118596A3

Abstract

A hydraulic fracturing assembly includes a frac tree (15) that mounts to a wellhead (17). An injection tee (23) mounts to the tree (15), the injection tee (23) having an axial injection tee bore (27) that registers with an axial flow bore of the frac tree (15). A single inlet passage (29) in the injection tee (23) extends from a flowline (33) mounting face on an exterior portion of the injection tee (23) downward and inward into a junction with the axial flow bore (25). A wear resistant inlet passage sleeve extends from the mounting face of the injection tee (23) a selected distance into the inlet passage (29). The inlet passage sleeve is of a harder material than the injection tee.

Description

WO 2016/118596 PCT/U S2016/014082 1 FLOWLINE AND INJECTION TEE FOR FRAC SYSTEM Cross Reference to Related Application

This application claims priority to provisional application 62/105/355, filed January 20, 2015.

Field of the Disclosure

This disclosure relates in general to equipment used in hydraulic fracturing operations of hydrocarbon wells, and in particular, to flowline equipment connecting a high pressure flowline to a wellhead.

Background

Well hydraulic fracturing equipment includes a frac tree that mounts to a wellhead. In some types, an injection tee secures to an upper end of the frac tree. The injection tee has a vertical bore and inlet passages leading to the injection tee bore. Flowlines connect high pressure pumps to the inlet passages of the injection tee for pumping a slurry of frac fluid into the well.

To achieve desired flow rates, some prior art hydraulic fracturing systems require two or four 3 inch flowlines connected to each hydraulic fracturing tree. In such prior art systems, the flowlines are connected to the frac tree in pairs on opposite sides of the frac tree through the injection tee. In this way, hydraulic fluid will be injected from both sides of the frac tree simultaneously in order to balance the forces on the hydraulic fracturing tree and to provide sufficient flow capacity. The flowlines are made up of short tubular members secured together. Each of these flowlines can have 10-20 connections between the tubular members, meaning for each hydraulic fracturing tree there can be up to 80 connections that must be made up. WO 2016/118596 PCT/US2016/014082 2

Often, an inlet passage of the injection tee will intersect the vertical bore of the injection tee at 90 degrees. In some instances, multiple inlet passages in the injection tee extend downward and inward to the injection tee bore. In that instance, a separate flowline connects to each of the inlet passages of the injection tee.

The flowlines leading to the injection tee are typically made up of tubular members connected by swivel unions. The flowlines typically have numerous turns with at least three swivel joints to properly align the pipe in three dimensions. Each turn and swivel joint introduces risks such as, for example, the risk of the connection failing or the pipe being eroded.

Rigid connections between the flowline tubular members for frac operations are known. In that type of connector, the ends of the tubular members have hubs that are drawn toward each other by clamps. Each clamp has two halves that bolt together.

The sand contained in the frac fluids used during the hydraulic fracturing can further exacerbate the erosion issues in injection tees, causing cracks, and lodging within surface imperfections, making them even more pronounced. In order to reduce erosion risks, the pressure and flow rate of fluids flowing through these lines can be limited.

Summary A hydraulic fracturing assembly includes a hydraulic fracturing tree having an axis and adapted to be mounted to a wellhead of a well with the axis vertical. The frac tree has an axial flow bore and valves that open and close the flow bore. An injection tee mounts to the frac tree, the injection tee having an axial injection tee bore that registers with the axial flow bore. A single inlet passage in the injection tee extends from a flowline mounting face on an exterior portion of the injection tee downward and inward into a junction with the axial flow bore. In one WO 2016/118596 PCT/US2016/014082 3 embodiment, a wear resistant inlet passage sleeve extends from the mounting face of the injection tee a selected distance into the inlet passage. The inlet passage sleeve is of a harder material than the injection tee. A flowline connects to the mounting face to deliver fluid into the inlet passage. The flowline has an upward curved section and an inclined section that joins the curved section and extends downward and outward away from the injection tee.

In one embodiment, the inlet passage has an upward and outward facing shoulder. The inlet passage sleeve has a lower end that abuts the shoulder. The shoulder defines an outer portion of the inlet passage and an inner portion of the inlet passage. The outer portion has a greater inner diameter than an inner diameter of the inner portion. The inlet passage sleeve has an inner diameter that is the same as the inner diameter of the inner portion. The inlet passage sleeve may have a length less than a length of the inlet passage and more than one-half a length of the inlet passage.

The mounting face for the flowline is flat. The inlet passage sleeve has an outer portion that protrudes outward past the mounting face.

In one embodiment, a wear resistant injection tee bore sleeve is positioned at a junction of the injection tee bore with the flow bore. The injection tee bore sleeve has a greater hardness than the injection tee.

In one embodiment, a support supports the flowline. The support has a plurality of legs, some of which may be extensible. Each leg has a clamp on an upper end that secures to a portion of the flowline and a base on a lower end for placement on ground. An anchor stake may extend downward from the base for imbedding in ground.

In one embodiment, the flowline comprises a plurality of pipe joints having ends secured together. At least one of the pipe joints is extensible in length. A brace may have an upper end connected to the injection tee and a lower end connected WO 2016/118596 PCT/US2016/014082 4 to a lower portion of the frac tree. The brace may be located on an opposite side of the injection tee from the mounting face.

The injection tee may have a flow back passage extending from the injection tee bore outward in a direction opposite from the mounting face.

Brief Description of the Drawings

While the invention will be described in connection with certain embodiments, it will be understood that it is not intended to limit the invention to those embodiments. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims.

Fig. lisa section view of a hydraulic fracturing flowline and tree assembly in accordance with an embodiment of this disclosure.

Fig. 2 is a section view of an injection tee of the assembly of Fig. 1.

Fig. 3 is a section view of an expansion joint of the assembly of Fig. 1, shown in a retracted position.

Fig. 4 is a section view of the expansion joint of Fig. 3, shown in an extended position.

Fig. 5 is a perspective view of a manifold and three of the flowlines of Fig. 1.

Detailed Description of the Disclosure

The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which certain embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to WO 2016/118596 PCT/US2016/014082 5 those skilled in the art. Like numbers refer to like elements throughout.

Fig. 1 shows a well fluid injection assembly 11 for injecting high pressure fluid into well 13 during a hydraulic fracturing or frac operation. Assembly 11 includes a frac tree 15 that secures to a wellhead 17 at the upper end of well 13. Frac tree 15 may be conventional, having two or more control valves 19 mounted on top of each other. Frac tree 15 includes a tubular adapter 21 above valves 19. An injection tee 23 secures to the upper end of adapter 21.

Injection tee 23 is a solid metal block having an axial injection tee bore 25 extending vertically through it coaxial with a vertical axis 28. Injection tee bore 25 coaxially aligns with a frac tree flow bore 27 extending through frac tree 15. Injection tee 23 has a single inlet passage 29 that extends from the exterior of injection tee 23 downward and inward for delivering well fluid to injection tee bore 25. Inlet passage 29 may incline at an angle in the range from 20 to 40 degrees relative to axis 28. Injection tee bore 25 and inlet passage 29 may be four inches in inner diameter. A swab valve 31 may be mounted to the upper end of injection tee 23. A flowline 33 connects to inlet passage 29 for delivering frac fluid. Flowline 33 has an upward curved portion 35 with a downstream end that joins injection tee 23 at inlet passage 29. An inclined portion 37, which may be substantially straight, joins the upstream end of curved portion 35 and extends downward and away from frac tree 15. The upstream end of inclined portion 3 7 j oins a horizontal portion 3 9 of flowline 33, which may be elevated a short distance above ground 40. The angle of inclination of inclined portion 37 may vary and is shown to be about 45 degrees relative to vertical. Flowline 33 may be formed of separate metal tubular members or pipes coupled together, as discussed subsequently. Alternately, flowline 33 could be a high pressure hose having articulating metal components and being of a type used in subsea applications. WO 2016/118596 PCT/US2016/014082 6

In this embodiment, a stand 41 supports inclined portion 37 and curved portion 35 of flowline 33. Stand 41 may have various configurations, and is shown with multiple legs 43. One of the legs 43 supports curved portion 35, another supports inclined portion 37, and another supports horizontal portions 39. At least some of the legs 43 may be extensible, having telescoping portions 43a, 43b that lock at a desired length for the leg. Each leg 43 has a clamp 45 on its upper end that secures around flowline 33 to provide support. Each leg 43 has a base 47 that rests on ground 40. One or more stakes or anchors 49 can be driven through each base 47 into ground 40 to provide stability to flowline 33. One or more eyelets 51 on flowline 33 facilitate a crane lifting flowline 33 into position. Stand 41 may also have one or more cross members 53 connecting certain ones of the legs 43 to each other to provide lateral stability.

The high pressure fluid from flowline 33 will exert a bending force on frac tree 15 about axis 28. Optionally, a brace 55 may be employed to resist bending movement of frac tree 15. Brace 55 is a metal beam or rod that is parallel with axis 28 and located on an opposite side of injection tee 23 and frac tree 15 from flowline 33. An upper connector 57 joins an upper end of brace 55, extends perpendicular to axis 28, and secures to injection tee 23. A lower connector 59 joins and extends perpendicular to brace 55, connecting to a lower portion of frac tree 15.

Injection tee 23 may have a return flow passage 61 for returning fluid from well 13. Return flow passage 61 joins injection tee bore 25 and extends to an exterior portion of injection tee 23 opposite flowline 33. Return flow passage 61 may be perpendicular to axis 28 and of smaller diameter than inlet passage 29.

Referring to Fig. 2, injection tee 23 has a supply line mounting face 63 formed on its exterior. Supply line mounting face 63 is flat and faces upward and outward relative to axis 28. A WO 2016/118596 PCT/US2016/014082 7 supply line flange type connector 65 bolts flowline 33 to supply line mounting face 63. Connector 65 forms the downstream end of flowline 33.

Inlet passage 29 has an outer portion 67 that extends inward and downward from supply line mounting face 63. Inlet passage has an inner portion 69 of smaller inner diameter than outer portion 67 and which extends to a junction with injection tee bore 25. The intersection of outer portion 67 and inner portion 69 forms an upward and outward facing shoulder 71. The length of outer portion 67 in this example is greater than the length of inner portion 69, measured along an axis of inlet passage 29. Alternately, the lengths of outer and inner portions 67, 69 could be the same, or the length of inner portion 69 could be greater than outer portion 67. In this embodiment, the length of outer portion 67 is about 55 -60% the overall length of inlet passage 29 measured along its axis. A wear resistant inlet passage sleeve 73 fits in outer portion 67. The outer diameter of inlet passage sleeve 73 is substantially the same as the inner diameter of outer portion 67. The inner diameter of inlet passage sleeve 73 is the same as the inner diameter of inner passage inner portion 69. The wall thickness of inlet passage sleeve 73 is approximately the same as the cross-sectional dimension of shoulder 71. The outer end of inlet passage sleeve 73 protrudes a short distance outward past supply line mounting face 63 and is received in a counterbore 74 in flowline connector 65. In this embodiment, inlet passage sleeve 73 is not press fit into or otherwise bonded in outer portion 67. Rather, it is simply dropped into outer portion 67 during assembly and retained against movement along the axis of inner passage 29 by a base of connector counterbore 74 contacting the outer end of inlet passage sleeve 73. A wear resistant axial bore sleeve 75 is located in injection tee bore 25. A lower portion of axial bore sleeve 75 fits within a counterbore 77 formed in a portion of frac tree flow bore 27 at WO 2016/118596 PCT/US2016/014082 8 the upper end of adapter 21. An upper portion of axial bore sleeve 75 fits within a counterbore 79 formed in the lower end of injection tee bore 25. The inner diameter of axial bore sleeve 75 is the same as frac tree flow bore 27 and injection tee bore 25. The outer diameter of axial bore sleeve 75 is approximately the same as the inner diameters of counterbores 77,79. In this example, axial bore sleeve 75 is not press-fit in either counterbore 77,79, rather it simply drops in place during assembly and is retained against axial movement by engagement with the upper end of counterbore 79 and the lower end of counterbore 77.

The upper end of axial bore sleeve 75 is spaced a short distance below the junction of inlet passage 29 with injection tee bore 25. In this embodiment, there is no wear resistant coating or sleeve in the portion of tee bore 25 from axial bore sleeve 75 to the junction with inlet passage 29. In this embodiment, there is no wear resistant coating or sleeve in inlet passage inner portion 69. Inner passage sleeve 73 and axial bore sleeve 75 are formed of materials that are harder and more wear resistant than the material of injection tee 23. The materials may vary and could be hardened steel or tungsten carbide.

Fig. 2 shows a return line mounting face 81 on the exterior ofinjection tee 23. Return line mounting face 81 may be on an opposite side ofinjection tee 23 from supply line mounting face 63. Return line mounting face 81 may be normal to the axis of return flow passage 61, which in this example is perpendicular to axis 28. A flange type return line connector 83 on an end of a return line (not shown) bolts to return line mounting face 81. Injection tee 23 has a flat upper end, on which swab valve 31 (Fig. 1) mounts, and a flat lower end, which mounts on adapter 21. There are no other mounting faces on injection tee 23, other then the flat upper and lower ends and mounting faces 63, 81. WO 2016/118596 PCT/US2016/014082 9

Figs. 3 and 4 illustrate a tubular extensible member 85 that forms a part of flowline 33 (Fig. 1). Flowline 33 may have more than one extensible members 85, and they may be placed at different points in flowline 33. Extensible member 85 includes an inner tube 87 that telescopes within an outer tube 89 between a retracted position shown in Fig. 3 and an extended position shown in Fig. 4. Outer tube 89 has an internal annular shoulder 90 with a groove that retains a seal 91. Seal 91 seals against the outer diameter of inner tube 87. Except at seal 91, an annular clearance 92 exists between the outer diameter of inner tube 87 and the inner diameter of outer tube 89. A plurality of stops 94 on the internal end of inner tube 87 protrude radially outward from the outer diameter of inner tube 87 to limit the movement of inner and outer tubes 87, 89 apart from each other. Stops 94 contact shoulder 90 when extensible member 85 fully extends.

Inner tube 87 has an external flange 93 on its external end that may be integral with inner tube 87, as shown, or secured otherwise. Outer tube 89 has an external flange 95 on its external end. In this example, outer tube flange 95 secures to outer tube 89 by threads 97. A number of threaded rods 99, which are secured to inner tube flange 93, extend through apertures 101 in outer tube flange 95. A nut 103 threads onto each rod 99 and bears against a side of outer tube flange 95 to fix a desired length for extensible member 85. The abutment of nuts 103 with outer tube flange 95 fixes the amount of extension of extensible member 85. In this example, there are no devices, such as nuts 103, to prevent contracting movement from the fully extended position of Fig. 4. The internal fluid pressure while pumping frac fluid will prevent extensible member 85 from contraction.

In one embodiment, the connections of the tubular members of flowline 33 are rigid. Once connected, the tubular members cannot swivel or rotate relative to one another. For example, Figs. 3 and 4 show an external hub 105 on the external end of inner tube 87 and also on the external end of outer tube 89. Hub 105 is an external flange with a tapered shoulder 106 on one side and a WO 2016/118596 PCT/US2016/014082 10 flat face 108 on the other side. Mating seal recesses 107 are located in the inner diameters of hubs 105. A seal 109, which may be metal, elastomeric or a combination, fits within mating recesses 107. A clamp 111 (shown only in Fig. 3) formed in two halves fits around mating hubs 105. When bolts (not shown) extending through bolt holes 113 are tightened, the halves of clamp 111 engage tapered shoulders 106 and draw hubs 105 toward each other, causing seal 109 to set. Normally, a slight clearance exists between faces 108 when clamp 111 is fully tightened. The hub 105 and clamp 111 connections illustrated in Fig. 3 may be used with all of the tubular members of flowline 33, whether extensible or not.

Fig. 5 illustrates a manifold 115 that may be used to direct high pressure frac fluid from several pumps (not shown) to several wells. A supply line 117 of high pressure fluid flows into manifold 115 and out several flowlines 33 (three shown). An upstream end of each flowline 33 connects to a multiple port connector of manifold 115. Each flowline 33 has an injection tee 23 that connects to a frac tree 15 (Fig. 1).

In use, technicians will assemble injection assembly 11 as illustrated in Fig. 1. Extensible members 85 (Fig. 3) may be used and adjusted in length to align injection tee 23 with frac tree 15. High pressure pumps then pump a slurry of frac fluid through flowline 33 and into one or more injection tees 23. The pressures may exceed 10,000 psi and the flow rates are quite high. The frac fluid flows through inlet passage 29 of each injection tee 23 down frac tree flow bore 27 and into well 13. At a certain point, the operator ceases to pump the frac fluid and allows some of the fluid in well 13 to flow back through return flow passage 61.

It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and WO 2016/118596 PCT/US2016/014082 11 specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. Accordingly, the improvements herein described are therefore to be limited only by the scope of the appended claims.

Claims

Claims

1. A hydraulic fracturing assembly, comprising: a hydraulic fracturing tree having an axis and adapted to be mounted to a wellhead of a well with the axis vertical, the tree having an axial flow bore and valves that open and close the flow bore; an injection tee mounted to the tree, the injection tee having an axial injection tee bore that registers with the axial flow bore; a single inlet passage in the injection tee that extends from a flowline mounting face on an exterior portion of the injection tee downward and inward into a junction with the axial flow bore; a wear resistant inlet passage sleeve that extends from the mounting face of the injection tee a selected distance into the inlet passage, the inlet passage sleeve being of a harder material than the injection tee; and a flowline connected to the mounting face to deliver fluid into the inlet passage, the flowline having an upward curved section and an inclined section that joins the curved section and extends downward and outward away from the injection tee.
2. The assembly according to claim 1, wherein: the inlet passage has an upward and outward facing shoulder; and the inlet passage sleeve has a lower end that abuts the shoulder.
3. The assembly according to claim 1, wherein: the inlet passage has an upward and outward facing shoulder spaced from the junction with the injection tee bore, defining an outer portion of the inlet passage and an inner portion of the inlet passage, the outer portion having a greater inner diameter than an inner diameter of the inner portion; and the inlet passage sleeve has a lower end that abuts the shoulder, the inlet passage sleeve having an inner diameter that is the same as the inner diameter of the inner portion.
4. The assembly according to claim 1, wherein: the mounting face is flat; and the inlet passage sleeve has an outer portion that protrudes outward past the mounting face.
5. The assembly according to claim 1, further comprising: a wear resistant injection tee bore sleeve positioned at a junction of the injection tee bore with the flow bore, the injection tee bore sleeve having a greater hardness than the injection tee.
6. The assembly according to claim 1, further comprising: a support having a plurality of extensible legs, each having a clamp on an upper end that secures to a portion of the flowline and a base on a lower end for placement on ground.
7. The assembly according to claim 1, further comprising: a support for the flowline, the support comprising: a plurality of legs that are selectively extensible in length; a clamp on an upper end of each of the legs that secures to a portion of the flowline; a base on a lower end of each of the legs; and an anchor stake extending from the base for imbedding in ground.
8. The assembly according to claim 1, wherein: the flowline comprises a plurality of pipe joints having ends secured together; and at least one of the pipe joints is extensible in length.
9. The assembly according to claim 1, further comprising: a brace having an upper end connected to the injection tee and a lower end connected to a lower portion of the tree, the brace being located on an opposite side of the injection tee from the mounting face.
10. The assembly according to claim 1, further comprising: a flow back passage extending from the injection tee bore outward in a direction opposite from the mounting face.
11. A hydraulic fracturing assembly, comprising: a hydraulic fracturing tree having an axis and adapted to be mounted to a wellhead of a well with the axis vertical, the tree having an axial flow bore and valves that open and close the flow bore; an injection tee mounted to an upper end of the tree, the injection tee having an axial injection tee bore that registers with the flow bore; a single inlet passage in the injection tee that extends from a supply mounting face on the exterior portion of the injection tee downward and inward into a junction with the axial injection tee bore; a flow back passage in the injection tee for flowing back well fluid from the well, the flow back passage extending from a flow back mounting face on an exterior portion of the injection tee to a junction with the axial injection tee bore, the flow back mounting face being on an opposite side of the injection tee from the supply mounting face; and a supply flowline connected to the supply mounting face to deliver fluid into the inlet passage, the supply flowline having an upward curved section that joins the exterior portion of the tree, and an inclined section that joins the curved section and extends downward and outward away from the tree.
12. The assembly according to claim 11, wherein: the inlet passage has an upward and outward facing shoulder spaced from the junction with the injection tee bore, defining an outer portion of the inlet passage and an inner portion of the inlet passage, the outer portion having a greater inner diameter than an inner diameter of the inner portion; and the assembly further comprises a wear resistant inlet passage sleeve installed in the outer portion of the inlet passage, the inlet passage sleeve having a lower end that abuts the shoulder, the inlet passage sleeve having an inner diameter that is the same as the inner diameter of the inner portion, and the inlet passage sleeve being of a harder material than the injection tee.
13. The assembly according to claim 12, wherein: the inlet passage sleeve has an outer portion that protrudes outward past the mounting face.
14. The assembly according to claim 12, further comprising: a wear resistant injection tee bore sleeve positioned at a junction of the injection tee bore with the flow bore, the injection tee bore sleeve having a greater hardness than the injection tee.
15. The assembly according to claim 11, wherein: the supply flowline comprises a plurality of tubular members having ends secured together; at least one of the tubular members comprises: inner and outer tubes that telescope relative to each other; external inner tube and outer tube flanges that face one another; threaded rods extending from the inner tube flange through apertures in the outer tube flange; and a nut that engages each of the threaded rods to fix a distance between the inner tube and the outer tube flanges.
16. A hydraulic fracturing assembly, comprising: a hydraulic fracturing tree having an axis and adapted to be mounted to a wellhead of a well with the axis vertical, the tree having an axial flow bore and valves that open and close the flow bore; an injection tee mounted to an upper end of the tree, the injection tee having an axial injection tee bore that registers with the flow bore; a single inlet passage in the injection tee that extends from a supply mounting face on the exterior portion of the injection tee downward and inward into a junction with the axial injection tee bore; a supply flowline connected to the supply mounting face to deliver fluid into the inlet passage, the supply flowline having an upward curved section that joins the exterior portion of the tree, and an inclined section that joins the curved section and extends downward and outward away from the tree; a plurality of support legs that are selectively extensible in length; a clamp on an upper end of each of the legs that secures to a portion of the supply flowline; a base on a lower end of each of the legs; and an anchor stake extending from the base for imbedding in ground.
17. The assembly according to claim 16, further comprising: at least one cross member extending between at least two of the legs perpendicular to the legs.
18. The assembly according to claim 16, wherein: the supply flowline comprises a plurality of tubular members having ends secured together; at least one of the tubular members comprises: inner and outer tubes that telescope relative to each other; external inner tube and outer tube flanges that face one another; threaded rods extending from the inner tube flange through apertures in the outer tube flange; a nut that engages each of the threaded rods to fix a distance between the inner tube and the outer tube flanges; and a seal between an inner diameter of the outer tube and an outer diameter of the inner tube.
19. The assembly according to claim 16, wherein: the supply flowline comprises a plurality of tubular members, each of the tubular members having an external flange on and end; each of the tubular members having an internal seal recess at the end, the seal recesses mating with each other when the flanges are brought toward each other; a seal located in the seal recess; and a clamp that bolts around the flanges and draws the flanges toward each other.
20. The assembly according to claim 16, a wear resistant inlet passage sleeve that extends from the mounting face of the injection tee a selected distance into the inlet passage, the inlet passage sleeve being of a harder material than the injection tee; and a wear resistant injection tee bore sleeve positioned at a junction of the injection tee bore with the flow bore, the injection tee bore sleeve having a greater hardness than the injection tee.