|Publication number||US8196649 B2|
|Application number||US 12/286,840|
|Publication date||Jun 12, 2012|
|Priority date||Nov 28, 2006|
|Also published as||US20090032241, US20110100646|
|Publication number||12286840, 286840, US 8196649 B2, US 8196649B2, US-B2-8196649, US8196649 B2, US8196649B2|
|Inventors||Robert Steven ALLEN, David Earl Cain, Bashir M. Koleilat|
|Original Assignee||T-3 Property Holdings, Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (135), Non-Patent Citations (37), Referenced by (5), Classifications (7), Legal Events (2)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application is a continuation-in-part of co-pending U.S. application Ser. No. 11/941,179 filed on Nov. 16, 2007, which claims the benefit of U.S. Provisional Application No. 60/867,476 filed on Nov. 28, 2006, both of which applications are hereby incorporated by reference for all purposes in their entirety.
1. Field of the Invention
The present invention relates to oil field downhole tools and wellhead equipment.
2. Description of the Related Art
Oil field wells are typically controlled by a “stack” of equipment for supporting downhole “strings” of tubulars, such as casing and tubing, valves, and other equipment to manage the drilling and production pressurized fluids in a well. A “conductor” pipe or casing is generally the first string of casing placed in the open hole to prevent the soil formations near the surface from caving in. An initial “surface” casing is the first string of casing that is placed in a well after the conductor. A wellhead typically sits on top of a base plate mounted on the conductor and provides controlled access to the wellbore during drilling and production. Various spools, a tubing head, and valves can be assembled thereto. As the wellbore depth increases, additional smaller casings can be placed inside the surface casing to extend to the deeper portions of the well. The additional casings are supported in the stack by supporting surfaces in the wellhead, a casing hanger held in the wellhead, and/or a casing spool mounted to the wellhead.
When the well is completed at a certain depth and cement is placed around the outer surface of the casing, production tubing is installed to the desired production depth in a similar arrangement by supporting the tubing from a tubing hanger in the wellhead. A blowout preventer (“BOP”) is usually installed in the stack to control the well if an overpressure condition occurs. In the past, the stack and particularly the BOP were disassembled for access to the wellbore to place another size casing or tubing. The system needed to be pressure tested after each reassembly, costing significant expense and time. Also, because the wellbore could have significant pressure during the interim access without the blowout preventer, the disassembly and reassembly was hazardous.
Over the last 100 years, the improvements in the drilling and production systems typically have been small, incremental adjustments to satisfy specific needs as deeper wells were drilled and produced sometimes with higher pressures, faster drilling, less disassembly and assembly, and other improvements. One improvement in recent years is a “unitized” wellhead. The unitized wellhead facilitates using different sizes of casing and tubing without having to disassemble major portions of the stack or remove the blowout preventer. One such unitized wellhead is available from T3 Energy Services, Inc. of Houston, Tex., USA. The assembled unitized wellhead includes a lower casing head and an upper casing spool that are coupled together and installed as a single unit. As smaller sizes of casing strings are needed, different casing hangers can be progressively cascaded and installed within the bore of the unitized wellhead for supporting the casing stings without removing the BOP. When a casing is set and cemented in place, a support pack-off bushing can be installed above the casing hanger to both seal the annulus below the casing hanger and the wellhead flanges, and create a landing shoulder for the tubing hanger. A tubing head can be installed above the unitized wellhead casing spool to house the tubing hanger.
Another improvement in recent years is the “thru diverter” type wellhead. Such a wellhead allows for lower cost drilling on smaller or marginal formations. A thru diverter wellhead is particularly useful in “batch drilling,” which makes efficient use of a larger more expensive drilling rig to drill a number of wells. In batch drilling, after the drilling of a well is completed, the well may be capped, and the rig moved to another well location. The wells can be completed later by smaller more economical rigs.
There are several limitations with the existing thru diverter type wellheads. Although the wellheads may be placed in some larger diverters, there is minimal clearance since there are numerous housings and other protrusions typically welded to the wellhead's exterior surface. Further, the exterior surfaces of the wellheads are uneven and non-uniform. Thus, the size of the wellhead that will move thru the diverter is limited. The wellheads will not fit at all in some smaller diverter housings. Further, such limited size wellheads only allow for the positioning of a single casing hanger with a single casing string.
There are also challenges to placement and operation of existing thru diverter type wellheads. There may be external threads on the exterior surface of the wellhead for attachment of the wellhead with other components of the stack. Further, there may be a groove on the exterior surface of the wellhead and a seal for sealing with other components of the stack. The seal, thread and/or the groove may be damaged either during placement of the wellhead or during an operation. An undamaged seal, thread and groove are necessary for the wellhead to maintain its maximum rated pressure after assembly of the stack. Damage to the seal, thread and/or groove will likely not be discovered until after the wellhead is permanently cemented in place with the wellbore, making replacement of the wellhead, at best, difficult. Time consuming and expensive field work may be needed to repair the damaged seal, thread and/or groove, with resulting lost time. The maximum pressure that the wellhead system may maintain may be compromised if a complete repair cannot be made. For example, if the groove cannot be completely repaired, then a lower pressure rated annular seal may be need to be used, which may lower the maximum rated pressure for the wellhead. The result may be a compromised plan for the well.
To protect the interior surface of the existing thru diverter wellhead during cementing and drilling operations, a removable protective sleeve has been positioned within the wellhead, which results in the loss of valuable rig time. Otherwise, cement or drilling fluid contaminants such as sand, rock and/or debris may damage the wellhead. Further, in some operations, there is an unmet need to bring tubulars, such as 4½ inch (11.4 cm) diameter casing or liners, completely back to the surface without disassembling the BOP stack. This would help solve some geological based drilling problems, as well as minimize rig time and mitigate a safety issue, as discussed above.
Another recent improvement in drilling involves the method of counteracting downhole pressures. In the past, drilling has been accomplished by providing a drilling fluid “mud” to weigh down and counteract fluids in the wellbore sometimes with large upward pressures. The weighted mud is pumped downhole while drilling occurs, so that the wellbore pressure is controlled. By controlling the well fluids from rising to the surface, difficult and hazardous conditions are mitigated. However, using such mud increases costs and drilling time, and can counterproductively damage the hydrocarbon formation that is to be produced. Improvements have been made in drilling by reducing use of the mud through techniques sometimes referred to as “underbalanced drilling” and “managed pressure drilling.” The drilling can proceed with less heavy mud and the drilling is typically faster with less down time.
A “downhole deployment valve” has been inserted down the wellbore in the past as a type of one-way check valve attached to the casing to block the downhole well fluids under pressure from escaping up through the casing. The downhole deployment valve is typically set at a certain depth and remains at that depth while drilling continues to greater depths. The drill pipe, bit, and other drill assembly devices are sized to be inserted through the downhole deployment valve to drill the wellbore. When the drill string is removed back through the downhole deployment valve, the downhole deployment valve can be closed to seal the downhole fluids. Therefore, when the drill bit is changed or the drill string is otherwise “tripped,” the operation can be done easier and generally safer because the casing above the downhole deployment valve can be vented to atmosphere while the pressurized fluids are controlled by the downhole deployment valve. Hydraulic control lines from the surface wellhead allow the pressurization of hydraulic fluid downhole to open and close the downhole deployment valve. Therefore, the control lines are used to remotely and selectively control the operation of the downhole deployment valve.
While the downhole deployment valve has been deemed an improvement, there have been challenges with protecting the integrity of the flow of the hydraulic fluid in the control lines for controlling the downhole deployment valve. Typically, the hydraulic fluid must move through the wellhead in fluid passageways from ports at the exterior surface of the wellhead to corresponding ports at the wellhead's interior surface. In past installations, the downhole deployment valve is typically coupled or strapped to a section of casing and a casing hanger is installed on the opposite end of the casing. Control lines are run from the downhole deployment valve up to hydraulic ports on the bottom of the casing hanger. Fluid passageways in the casing hanger allow fluid communication between respective ports on the bottom of the hanger and ports on the side of the hanger.
The downhole deployment valve, casing, and casing hanger are lowered into the wellhead, until the casing hanger sits on an internal shoulder of the wellhead. U.S. Pat. No. 6,244,348 proposes a tubing hanger with an internal passageway for conveying fluids with a port on a mating surface for sealing with the internal wellhead seal surface, with a check valve positioned within the hanger port to interface with the internal wellhead seal surface. The hydraulic fluid is transported through the wellhead in a passageway for conveying fluids. U.S. Pat. No. 4,623,020 proposes a tubular body with a passageway for conveying fluids with a port on an exterior sealing surface to form a slidable fluid seal with the interior surface of a wellhead adapter member that also has a fluid passageway, which member is provided with a number of elastomeric seals spaced annularly around its interior surface. In practice, the seals, which are located near where the hanger side port interfaces with the port on the interior surface of the wellhead, leak due to the sand, rock, and other debris and contaminants in the drilling fluid passing through the wellhead and wellbore from the drilling operations. The ports and hydraulic fluid can be contaminated and cause control issues with the downhole deployment valve. The control lines can also be compromised from external forces. In addition, equipment can impact the control lines, operators may unintentionally step on the control lines, and other physical damage can occur to the control lines that can render the system inoperative and potentially hazardous to operators nearby.
Pub. No. U.S. 2004/0079532 proposes a single bowl casing head that has one or more access openings or side bores through its sidewall for placement of a single hydraulic line in each opening. The casing head proposed in the '532 publication only allows for the positioning of one casing hanger.
The above discussed U.S. Pat. Nos. 4,623,020 and 6,244,348; and Pub. No. U.S. 2004/0079532 are hereby incorporated by reference for all purposes in their entirety.
There remains a need for a thru diverter type wellhead that allows for the direct coupling of hydraulic control lines and related system to operate a downhole deployment valve and other downhole tools. It would be desirable to run the wellhead thru the diverter without housings and other protrusions extending from the exterior surface of the wellhead during installation so as to increase the size of the wellhead that may be moved relative to the diverter. It would further be desirable for such a wellhead to accommodate more than one casing hanger and casing string, and allow for tubulars to be brought back to the surface without disassembling the BOP stack. It would also be desirable to eliminate the need for a tubing head in certain circumstances. It would also be desirable to have a system and method that would protect the wellhead during its placement and operation. It would further be desirable to eliminate the need to install a temporary protective sleeve in wellhead during certain cementing and drilling operations.
A method and system are provided for positioning a wellhead in a diverter housing over the wellbore. Protrusions on the exterior surface of the wellhead are not initially installed or are removed before moving the wellhead thru the diverter. An overshot running tool may be used to place the wellhead while protecting the wellhead exterior and interior surfaces, grooves, threads, and seals. The overshot running tool allows for operations, such as drilling and cementing, after the wellhead is positioned with the wellbore, but before the running tool is removed. After the diverter is removed, an alignment pin housing may be attached with the wellhead, and an alignment pin used during the positioning or seating of the hanger to align the hanger side ports with the access openings in the wellhead for coupling of hydraulic control lines to the hanger. Hydraulic control lines may extend from the hanger to outside the wellhead and between the hanger and hydraulically operated tools. Other housings, such as those containing retainer pins, may also be attached with the wellhead after the diverter is removed. In one embodiment, the wellhead may be a single bowl that allows for the positioning of one hanger therein. In another embodiment, the wellhead may be an assembled “unitized” multi-bowl that allows for the positioning of two hangers therein. The hangers and tubulars may be positioned either from above or below the wellhead without removal of the BOP stack. Alternatively, the multi-bowl wellhead may be monolithic. The multi-bowl wellhead eliminates the need for a tubing head in certain circumstances.
While the concepts provided herein are susceptible to various modifications and alternative forms, only a few specific embodiments have been shown by way of example in the drawings and are described in detail below. The figures and detailed descriptions of these specific embodiments are not intended to limit the breadth or scope of the concepts or the appended claims in any manner. Rather, the figures and detailed written descriptions are provided to illustrate the concepts to a person of ordinary skill in the art as required by 35 U.S.C. §112. A better understanding of the present invention can be obtained with the following detailed descriptions of the various disclosed embodiments in the drawings:
More specific to the present invention, the wellhead can include at least one access opening 20 and in some embodiments a second access opening 21. A sealing member, such as sealing flange 88 can be coupled to the opening 20 and a corresponding sealing member, such as flange 89, can be coupled to the opening 21. The flanges, preferably bolted to the wellhead 8, can provide a pressure-type seal against internal pressures in the wellhead that may exceed 10,000 PSI. A hydraulic line 22 can pass through the opening 20 and generally through the sealing flange 88 to connect with the hanger. Similarly, a hydraulic line 23 can pass through its respective access opening 21 through the flange 89 to be coupled with the hanger. To facilitate alignment between the openings (20, 21) and the appropriate position of the internal hanger, an alignment pin 27, described in detail below, can be disposed through the side wall of the wellhead to align the internal members, such as the hanger. Various leads, such as threaded pins, known as “leads” can support internal members as is customary in the industry. For example, support pack-off bushing leads (24, 25) can support a support pack-off bushing internal to the assembly that assists in isolating pressure from downhole fluids. Similarly, tubing hanger leads 26 can support the tubing hanger internal to the tubing head 16.
The wellhead system 2 can further include one or more test ports 28. The operator may wish to know prior to unsealing the openings (20, 21) whether the system is presently under pressure, or whether there is leakage in the system that would unintentionally place generally unpressurized portions of the system in pressurized conditions. For further safety, one or more protector steps 30 can be disposed at least partially over or around the openings (20, 21) and the associated hydraulic lines to provide a support surface for personnel.
One or more hydraulic valves (32, 33) can be mounted to the respective hydraulic lines (22, 23). The hydraulic valves can control the flow of the hydraulic fluid between the subsurface downhole hydraulic tool and surface control equipment. A surface control unit 34 is generally coupled to the hydraulic control lines to either manually or automatically control a downhole hydraulic tool 38. The downhole hydraulic tool is hydraulically coupled with the hydraulic lines (22, 23) in the wellhead using hydraulic lines (36, 37) disposed downhole to the downhole hydraulic tool 38. An exemplary downhole hydraulic tool 38 can be a downhole deployment valve. The downhole deployment valve provides a check valve to uphole flow of wellbore fluids and enhances the safety of the downhole operations. As described herein, the hydraulic lines (36, 37) can be coupled to a hanger in the wellhead 8 and then coupled to the hydraulic lines (22, 23) without requiring the hydraulic annular seals to maintain hydraulic pressure, referenced above.
Once the drilling is accomplished, a string of production tubing 40 can be placed inside the wellbore through the wellhead system. It is generally supported by a tubing hanger, described below. The tubing hanger is generally disposed in a tubing head, but can be disposed in the casing head 10, the casing spool 12, and similar members coupled thereto.
Similarly, a hydraulic side port 54 is formed at the exit of passageway 53 in the side 49. Generally, the hydraulic tool port 52 will be located on the bottom surface of the hanger and the hydraulic side port 54 will be located on the side 49 of the hanger. Thus, generally, the ports will be disposed at an angle to each other. The one or more access openings to the hydraulic side ports are formed to the side of the wellhead and aligned with the hydraulic side ports on the hanger when the hanger is seated in the wellhead. The port 54 as described herein can be coupled directly to a hydraulic line, such as the hydraulic line 22. By “direct,” it is intended to include a fluid connection or coupling between a hydraulic line and a port that does not require the annular seals that are used to seal annular zones between the hanger and the internal surfaces of a wellhead.
Advantageously, the system described herein allows the integrity of the hydraulic system to be protected during installation of the hanger 50 into the wellhead 8. For example, as best shown in
In some embodiments, the side port 54 can be disposed in a skirt 64 of the hanger 50. As best shown in
The hanger 50 can further include one or more recesses (60, 62) as would be known to those with ordinary skill in the art. The recesses can be used for supporting the hanger in the head with different leads, such as leads (24, 25, 26) as shown together in
One feature of the present invention is the alignment of a hydraulic side port, such as the side port 54 in the hanger 50 shown in
To facilitate such alignment, an alignment pin 27 can be provided in the drilling wellhead 70 to correspondingly mate with an alignment recess 76 (shown in
As described herein, during the initial phase where the hanger 50 is installed over the support pack-off bushing 80 in the drilling wellhead 70, the ports (54, 55) can be protected with respective plugs (56, 57) inserted therein to keep contaminants from entering the hydraulic passageways. When aligned with the openings (20, 21), the protective plugs (56, 57) can be manually removed from the side ports (54, 55) to open the hydraulic passageways and prepare for inserting and coupling the hydraulic lines thereto. One or more isolation seals (66, 68), shown in
A further safety feature can include a test port 28 that can be disposed on the downstream portion of the support pack-off bushing from the wellbore. Thus, if there is a leak above the support pack-off bushing, an operator can be warned prior to opening the access openings (20, 21).
Thus, the integrity of the hydraulic system is maintained during the installation of the hanger 50 in the drilling wellhead 70. The hydraulic side ports are only exposed to ambient conditions when the hanger is seated in position and a direct coupling to the hydraulic port can be made.
Further assembly of the hydraulic system can be performed. For example, one or more control valves (32, 33) can be coupled to the respective hydraulic lines (22, 23). The control valves can then be coupled to additional hydraulic lines that can couple to various control mechanisms, such as the surface control unit 34 described in reference to
Advantageously, an additional safety feature can be an indicator on the head indicating an open and close control of the downhole hydraulic tool. For example, a green colored flange 88 could indicate that the hydraulic line 22 is used to open the downhole hydraulic tool. A red colored flange 89 could indicate that the hydraulic line 23 is used to close the downhole hydraulic tool.
Packing nuts 128 with retainer pins 132 are attached to casing spool 126 using V-type threads. Such V-type threads are not fabricated for sealing against high internal pressures. Retainer pins 132 are inserted into casing spool 126 to prevent upward movement of upper mandrel hanger 130. As can now be understood, casing head 112 and casing spool 126 assembled together form a “unitized” wellhead. Valves, gauges and tubulars, shown generally as 134, are attached to the top of the wellhead. Valves, gauges and conduits, shown generally as 135, are attached to the side of the wellhead. As used herein throughout, the terms “wellhead” or “drilling wellhead” may be used interchangeably with “casing head,” “casing spool,” “tubing head,” or any assembled combination thereof, or any other structure used to support hangers. Further, the term “tubular” may be used interchangeably with “tubular string.”
One end of tool hydraulic line 154 is coupled with hanger tool port 168. The other end of tool hydraulic line 154 may be coupled with a downhole deployment valve or other downhole tool (not shown). Support pack-off bushing 158 is positioned on mandrel casing hanger 142, and supports slip hanger 160 in casing spool 156 with slips 161 gripping slip hanger tubular 143. Reducer bushing 166 in tubing head 162 is positioned on one end of slip hanger tubular 143. Upper mandrel hanger or mandrel tubing hanger 164 in tubing head 162 supports tubing hanger tubular 145. Tubular 145 may be production tubing. Hydraulic line 172 with one end extending above tubing head 162 to valve 151 may be coupled at the other end with a downhole safety valve (not shown), such as proposed in U.S. Pat. No. 5,465,794, which is hereby incorporated by reference for all purposes in its entirety. As can now be understood, casing head 140 and casing spool 156 assembled together form a “unitized” wellhead.
Casing head 202 is single bowl. Conduits (222, 223) are threadably attached to respective bores (226, 227) in casing head 202. Ball valve 224 is in conduit 223. Other valves are contemplated. Rim 206 is threadably attached with one or more threads on the exterior surface of casing head 202, and bolted with bolts 225 to tubing head 208. As can now be understood, the exterior surface of casing head 202 comprises one or more threads. Annular seal 683 between casing head 202 and tubing head 208 may provide fine finishes for metallic sealing. Reducer bushing 210 is positioned in tubing head 208 on one end of tool tubular 198. Mandrel tubing hanger 212 in tubing head 208 supports tubing hanger tubular 200. Tubing hanger tubular 200 may be a 4½ inch (11.4 cm) diameter casing or tubing, such as a liner. However, other tubulars and sizes are contemplated. Packing nuts 214 with retainer pins 216 are attached to tubing head 208 with V-type threads. Retainer pins 216 extend into tubing head 208 to resist upward movement of tubing mandrel hanger 212. Various valves, gauges and chokes, shown generally as 220, are positioned over the wellhead. It is contemplated that a BOP may also be positioned over the wellhead.
Wellhead or casing head 370 with longitudinal bore interior surface 391 is a monolithic multi-bowl casing head. Conduits (371, 375) are threadably attached to respective threaded bores (376, 378) in casing head 370. Ball valves (380, 382) are in respective conduits (371, 375). Other valves are contemplated. Similarly, conduits (400, 396) are threadably attached to respective threaded bores (402, 398) in casing head 370. It is contemplated that threaded bores (402, 398) may also be used to threadably attach retainer pin housings 640, such as shown in
Annular seal 500 on the interior surface of collar 492 seals with the exterior surface of casing head 202. Collar 492 is attached with body 494 of overshot running tool 490. Collar 492 may be welded to body 494. Other methods of attachment are contemplated. It is contemplated that collar 492 and body 494 may be substantially cylindrical in shape. Collar 492 and body 494 protect and cover groove 683A and thread 498 from cement and debris resulting from operations, as well as contact damage during movement. As shown in
Collar 532 is attached with body 534 of overshot running tool 530. Collar 532 and body 534 protect and cover groove 684A and thread 544 from cement and debris resulting from operations, as well as contact damage during movement. As shown in
The top of extension 554 and the bottom of body 552 of overshot running tool 550 are threadably attached. It is contemplated that extension 554 and body 552 may be substantially cylindrical in shape. The thicknesses of collar 532A and body 552 may not be uniform. It is contemplated that extension 554 may be a tubular, such as a section of casing substantially the same size as tubulars (474A, 476A). However, other sizes are contemplated as well. The longitudinal bore interior surface 556 of extension 554 of overshot running tool 550 may be substantially flush with the interior surfaces of tubulars (474A, 476A). Exterior surface 558 of extension 554 of overshot running tool 550 covers substantially all of the longitudinal bore interior surface 391 of casing head 370, which protects it during cementing and drilling operations. Thread 542A on collar 532A protect thread 544A on casing head 370. Collar 532A and body 552 protect and cover annular groove 685A from cement and debris resulting from operations, as well as contact damage during movement. As shown in
As can now be understood from
Method of Use
As shown in
Support ring (194, 286) is tightened with respective bolts (410, 414) and scrub screws 412 onto wellhead tubular (474, 474A) at the bottom of casing head (202, 240, 370). Eccentric support ring 286 may be necessary if the longitudinal axis of wellhead tubular (474, 474A) is not in alignment the vertical longitudinal axis of the wellbore. The connection between overshot running tool (490, 530, 550) and casing head (202, 240, 370) may be pressure tested using test ports (491, 680, 680A) in overshot running tool (490, 530, 550). The overshot running tool (490, 530, 550) and casing head (202, 240, 370) assembly is inserted thru the longitudinal bore of the diverter housing 470 until support ring (194, 286) rests on landing ring 192.
As can now be understood, the lack of protrusions on casing head (202, 240, 370), such as rim (206, 266, 266A), alignment pin housing 300, retainer pin housings 640, and flange (150, 150A), allow casing head (202, 240, 370) to move thru a smaller interior diameter diverter housing 470 than would otherwise be possible. Protrusions are also contemplated to include packing nuts (128, 214), support pack-off bushing leads (24, 25), and bull plug housings, such as disclosed in Pub. No. US 2004/0079532. As can also now be understood, the use of support ring (194, 286) eliminates conductor wellheads and extra casing heads, thereby saving time. Cementing of tubular (474, 474A) and further drilling operations may continue with overshot running tool (490, 530, 550) in place, thereby saving time. It is contemplated that a “diesel pill” may immediately precede the cement down through the longitudinal bore of the overshot running tool (490, 530, 550) and tubular (474, 474A). The diesel pill will assist in keeping the water in the cement, and will also precede the cement when it exits up the well between the conductor pipe 190A and tubular (474, 474A), providing a signal for when to shut off the cement. Overshot running tool (490, 530, 550) protects the interior surface (391, 512, 540) of casing heads (202, 240, 370), grooves (683A, 684A, 685A), and exterior threads (496, 544, 544A) from cement, debris and contaminants without the need for a protective sleeve. It is contemplated that seals (683, 684, 685) may also be protected. After tubular (474, 474A) is cemented, overshot running tool (490, 530, 550) may be unthreaded from casing head (202, 240, 370) and removed, leaving casing head (202, 240, 370) in the position as shown in
Diverter housing 470 may be removed. As shown in
As shown in
After cementing and/or further drilling, the overshot running tool may be removed. As shown in
As shown in
As shown in
As shown in
Alternatively, rather than coupling second hanger tubular (245, 377) with slip hanger (264, 392) above the wellhead system and moving the assembly down into the wellhead, second hanger tubular (245, 377) may be brought up through the bottom of casing head (240, 370) and coupled with slip hanger (264, 392) and slip hanger (264, 392) seated in casing head (240, 370), such as when a liner may be run to the surface from downhole. Rim (266, 266A) may be coupled with casing head (240, 370) for further assembly of the wellhead system above casing head (240, 370). Retainer pin housings 640 may be removed from casing head (240, 370) and replaced with conduits (260, 262, 396, 400).
As can now be understood, the method of use of a multi-bowl casing head may include positioning a wellbore tubular in the wellbore, cutting the top of the wellbore tubular at the desired elevation for placement of a casing head, and securing a landing ring on top of the wellbore tubular. A diverter housing may then be mounted on the wellbore tubular, and drilling continued in the wellbore. The top of the casing head is threadably coupled with an overshot running tool and the bottom of the casing head may be attached with a wellhead tubular, and a support ring attached onto the wellhead tubular. After pressure testing of the connection between the overshot running tool and the casing head, the wellhead assembly, without protrusions, may be moved down thru the longitudinal bore of the diverter housing until the support ring rests on the landing ring. After cementing and/or drilling in the wellbore, the overshot running tool and the diverter housing are removed. After removing the preferable flush plugs from the casing head, protrusions may be threadably coupled with the wellhead, such as an alignment pin housing, sealing flanges, rims and/or retainer pin housings.
A BOP adapter housing and BOP may be attached with the casing head, and pressure testing of the casing head and BOP accomplished using a combination running tool. The combination running tool may also be used to place and remove a protective sleeve. A first hanger may be coupled with one end of a first hanger tubular, and a downhole deployment valve attached to the other end of the tubular. Tool hydraulic lines may be coupled between the first hanger and the downhole deployment valve. One end of an alignment pin may be inserted through the alignment pin housing to position the first hanger in the casing head. When the first hanger is moved down into the casing head, the first hanger may be rotated as necessary to fit around the end of the alignment pin. Side hydraulic lines may be inserted from outside the casing head and coupled with the first hanger. The downhole deployment valve may be employed in further drilling operations as necessary.
If another tubular is needed, a support pack-off bushing may be placed over the first hanger in the casing head. Retainer pins may be inserted through retainer pin housings to hold the support pack-off bushing in place. A second hanger may be coupled with a second hanger tubular, and the second hanger moved into the casing head and positioned on the support pack-off bushing. Again, the downhole deployment valve may be used in further drilling operations as necessary. The retainer pin housings may be removed and replaced with conduits, and a rim threadably coupled with the top of the casing head. A seal may be placed in a groove at the top of the casing head for sealing with other wellhead components, such as a tubing head as necessary. If desired, rather than inserting the second tubular down through the casing head from above, the second tubular may be brought up from the wellbore through the bottom of the casing head and attached with the second hanger either above or in the casing head.
The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the details of the illustrated apparatus and system, and the construction and the method of operation may be made without departing from the spirit of the invention.
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|26||Weatherford, Real Results, Successful Trial of Downhole Deployment Valve (DDV(TM)) Proves the Validity of DDV Technology, © 2003-2007 Weatherford (1 page).|
|27||Weatherford, Real Results, Successful Trial of Downhole Deployment Valve (DDV™) Proves the Validity of DDV Technology, © 2003-2007 Weatherford (1 page).|
|28||Weatherford, Underbalanced Drilling Downhole Deployment Valve, Weatherford Underbalanced Systems, Jun. 21, 2002, © Weatherford International, Inc. (28 page).|
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|33||Wood Group Pressure Control website, Time-Saving Wellhead, Multi-Well Completion, MWC System, printed Feb. 26, 2008, Technical Bulletin #05-0177, corresponding website http://portal.woodgroup.com (3 pages).|
|34||Wood Group Pressure Control website, Time-Saving Wellhead, OSH Offshore Speedhead System, printed Feb. 26, 2008, Technical Bulletin #04-0396, corresponding website http://portal.woodgroup.com (4 pages).|
|35||Wood Group Pressure Control website, Time-Saving Wellhead, SH2 Split Speedhead System, printed Feb. 26, 2008, Technical Bulletin #04-0394, corresponding website http://portal.woodgroup.com (4 pages).|
|36||Wood Group Pressure Control website, Time-Saving Wellhead, SH3 Speedhead System, printed Feb. 26, 2008, Technical Bulletin #04-0395, corresponding website http://portal.woodgroup.com (4 pages).|
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|US8573294 *||Jul 23, 2010||Nov 5, 2013||Schlumberger Technology Corporation||Cable bypass and method for controlled entry of a tubing string and a cable adjacent thereto|
|US8668020 *||Nov 19, 2010||Mar 11, 2014||Weatherford/Lamb, Inc.||Emergency bowl for deploying control line from casing head|
|US9269199||Feb 22, 2013||Feb 23, 2016||National Oilwell Varco, L.P.||Method and system for monitoring downhole assets|
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|U.S. Classification||166/72, 166/379, 166/375|
|International Classification||E21B34/10, E21B19/00|
|Oct 2, 2008||AS||Assignment|
Owner name: T-3 PROPERTY HOLDINGS, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ALLEN, ROBERT STEVEN;CAIN, DAVID EARL;KOLEILAT, BASHIR M.;REEL/FRAME:021704/0831;SIGNING DATES FROM 20080930 TO 20081002
Owner name: T-3 PROPERTY HOLDINGS, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ALLEN, ROBERT STEVEN;CAIN, DAVID EARL;KOLEILAT, BASHIR M.;SIGNING DATES FROM 20080930 TO 20081002;REEL/FRAME:021704/0831
|Nov 25, 2015||FPAY||Fee payment|
Year of fee payment: 4