Patent Application
20240309719
The present disclosure relates generally to oil and gas tubing valves and, more particularly, to a modified back pressure valve that incorporates dual flapper check valves.
Throughout the lifetime of an oil and gas well, proper sealing and pressure isolation equipment is required to prevent undesirable fluid flow out of the system, including oil, gas, injection fluid, and formation water. One common mechanical barrier utilized in sealing the wellhead of an oil and gas well is a back pressure valve, which is typically secured within a tubing hanger arranged within a tubing head adapter, which forms part of the wellhead. A production tree (alternately referred to as a “Christmas tree”) is commonly attached to the top of the tubing head adapter to control flow into and out of the wellbore.
The back pressure valve operates as a one-way check valve designed to isolate well pressure from below while enabling the flow of fluids from above; i.e., the Christmas tree. Conventional back pressure valves, however, prevent high flow rates through the valve. Some back pressure valves, for example, include a dynamic poppet-type valve that allows unidirectional fluid flow at very low rates (e.g., around 1-2 bpm). As such, for well operations requiring high fluid injection rates, or the bullheading of kill fluid or suspension fluid, the current practice is to retrieve the back pressure valve from the tubing hanger prior to undertaking the injection operation, and subsequently reinstalling the back pressure valve following injection.
The additional downtime, labor costs, and risk associated with the retrieval and reinstallation of the back pressure valve are undesirable in standard well operations, particularly when performing well services which may require multiple, sequential retrievals and reinstallations. Accordingly, a wellhead back pressure valve which prevents backflow from below while enabling high flow rate injection operations from above is desirable.
Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an exhaustive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.
According to an embodiment consistent with the present disclosure, a method includes installing a dual flapper back pressure valve within a tubing hanger of a wellhead, the dual flapper back pressure valve including an elongate body having opposing upper and lower ends and configured to be received and secured within the tubing hanger, an inner flowpath defined within the body and extending between the opposing upper and lower ends, and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism. The method further includes introducing an injection fluid into the inner flowpath at the upper end, pivoting the flapper from a closed position to an open position with the injection fluid, and circulating the injection fluid through the inner flow path at a flow rate greater than two barrels per minute
In another embodiment, a wellhead includes a tubing head adapter, a tubing hanger arranged within the tubing adapter, and a dual flapper back pressure valve arranged within the tubing hanger. The dual flapper back pressure valve includes an elongate body having opposing upper and lower ends, an inner flowpath defined within the body and extending between the opposing upper and lower ends, and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism, wherein, when the flapper is in a closed position, the flapper forms a sealed interface with the inner wall of the inner flow path that prevents fluids from circulating through the tubing hanger and through the inner flowpath from the lower end to the upper end.
In a further embodiment, a dual flapper back pressure valve includes an elongate body having opposing upper and lower ends and configured to be received and secured within a tubing hanger of a wellhead, an inner flowpath defined within the body and extending between the opposing upper and lower ends, and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism, wherein the pivoting mechanism naturally biases the flapper to a closed position, and wherein, when the flapper is in the closed position, the flapper forms a sealed interface with the inner wall of the inner flow path that prevents fluids from circulating through the inner flowpath from the lower end to the upper end.
Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.
Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.
Embodiments in accordance with the present disclosure generally relate to oil and gas tubing valves and, more particularly, to a tubing head back pressure valve with an incorporated dual flapper check valve, referred to herein as a “dual flapper back pressure valve”. Because it incorporates dual flapper check valves, the dual flapper back pressure valve may enable unidirectional fluid flow from above while preventing upward flow from below, while simultaneously enabling high flow rate injections to pass through the dual flapper back pressure valve without the need for retrieval and subsequent reinstallation of a traditional back pressure valve. As such, the dual flapper back pressure valve disclosed herein may reduce the downtime, labor costs, and risk associated with many downhole operations, particularly with respect to unconventional resources in oil and gas.
The tubing hanger 100 may include or define a landing joint profile 108 within the interior channel 106 at or near the uphole end 104a. The landing joint profile 108 provides a landing shoulder and threaded interface used to attach, or latch to, a running tool in order to run a tubing string during the drilling or completion running phases of the well's operational life. The tubing hanger 100 may also include or define a tubing profile 110 within the interior channel 106 at or near the downhole end 104b. The tubing profile 110 may be configured to mate with or otherwise couple to tubing extending below. In some embodiments, the tubing profile 110 includes tapered threads for mating with the tubing. In alternate embodiments, an adapter pipe may be utilized for connection between the tubing profile 110 and the tubing.
The tubing hanger 100 may further include or define a back pressure valve profile 112 within the interior channel 106 at a location between the uphole and downhole ends 104a,b. The back pressure valve profile 112 is configured to receive and mate with a valve operable to control fluid flow through the tubing hanger 100. As illustrated, the back pressure valve profile 112 may include or define a landing shoulder 114 and internal threads 116. The landing shoulder 114 may be configured to receive an opposing shoulder provided on a valve, and the internal threads 116 may be configured to threadably mate with external threads provided on the exterior of the valve. The back pressure valve profile 112 may be used to receive and mate with traditional or conventional back pressure valves commonly used in oil and gas wellhead installations, but may also be used to receive and mate with the dual flapper back pressure valves described herein. Accordingly, in at least one embodiment, the tubing hanger 100 may comprise a traditional or conventional tubing hanger 100 forming part of a traditional or conventional wellhead, but is capable of accommodating the embodiments of the dual flapper back pressure valves described herein.
The back pressure valve 118 may also include an actuatable valve element 124 operable to move between closed and open positions and thereby prevent or allow fluid flow through the back pressure valve 118. In some applications, the actuatable valve element 124 may comprise a poppet valve that enables unidirectional flow from above while preventing back flow from below. The actuatable valve element 124 may be spring-loaded such that the back pressure valve 118 is held closed until pressure forces overcome the spring forces of the actuatable valve element 124. More specifically, the back pressure valve 118 is oriented within the tubing hanger 100 such that the actuatable valve element 124 will compress (open) after a large enough force is applied from above the back pressure valve 118, such that flow from above may pass through the back pressure valve 118 and through the interior channel 106. Once the pressure above the back pressure valve 118 is reduced, the actuatable valve element 124 is naturally biased back to the closed position via spring force of the actuatable valve element 124, thus maintaining a closed back pressure valve 118.
The inside diameter of the actuatable valve element 124 is smaller than the diameter of the interior channel 106. Further, the valve face, or “poppet” may include an elastomer seal (not shown) which may ensure proper sealing within the body of the back pressure valve 118. The smaller inside diameter and the presence of a single elastomer seal limits the maximum flow rate through the back pressure valve 118, as high flow rates may generate increased pressures within a smaller flow diameter and may damage or unseat the elastomer seal. In well operations which utilize only a single back pressure valve 118, damaging or unseating the elastomer seal may lead to leakage and damages from backflow through the tubing hanger 100. When a well operator desires to inject fluids at rates higher than two barrels per minute (bpm), such as in applications where it is desired to perform injection operations into the well, or to open a toe initiation valve (TIV), a toe port, or a frac port, the back pressure valve 118 is typically removed.
Accordingly, current practices involve the retrieval of the back pressure valve 118 prior to any high rate injection operation (e.g., more than 2 bpm) and the subsequent reinstallation of the back pressure valve 118 following the termination of injection. In some oil and gas well operations, several successive injection operations may be required and, therefore, may require repetitive retrieval and reinstallation of the back pressure valve 118, which increases downtime and labor costs while introducing further risk of incomplete or improper installation of the back pressure valve 118 with each operation. Moreover, for unconventional resource oil and gas well operations, such as hydrocarbon extraction from shale formations, higher efficiencies and lower costs may determine the success of the operations. As such, the limitations imposed by traditional back pressure valves 118 and current practices may be unviable for use in unconventional resources and undesirable for use in traditional oil and gas wells.
The valve 200 may be configured to be received within and mate with the tubing hanger 100 (
In some embodiments, as illustrated, inner threads 212 may be defined within the interior channel 106 at or near the upper end 204a. The inner threads 212 may be configured to threadably mate with outer threads defined on a running tool (not shown) configured to advance the valve 200 into the tubing hanger 100 (
The body 202 of the valve 200 may further include an elongate section 214 extending from the external threads 208. One or more flapper assemblies may be provided within the inner flow path 206 defined by the elongate section 214, shown in
As illustrated, each flapper assembly 216a,b may include a flapper 218 pivotably mounted to the inner wall of the inner flow path 206 at a pivoting mechanism 220. The pivoting mechanism 220 may comprise a self-closing hinge, such as a spring-loaded hinge that includes a torsion spring, for example, configured to naturally bias the flapper 218 to a closed or “sealed” position. Each flapper assembly 216a,b may further include a flapper stopper or “seat” 222 arranged to stop movement of the flapper 218 within the inner flow path 206 as the flapper 218 is urged to the closed position. In some embodiments, the flapper seat 222 may be an extrusion or projection defined within the inner flow path 206, but could alternatively comprise a separate component part (e.g., a tab or ring) secured within the inner flow path 206. In some embodiments, the flapper seat 222 may be fully circular within the inner flow path 206 to provide a robust sealing mechanism. In a further embodiment, all or a portion of the flapper seat 222 may be made of an elastomeric material such that a deformational interference fit may be created between the flapper 218 and the flapper seat 222.
When the flapper 218 moves to the closed position and engages the flapper seat 222, the flapper 218 may form a substantially sealed interface with the inner wall of the inner flow path 206. In some embodiments, the flapper 218 may be sized such that the flapper 218 completely blocks the flow of fluids through the inner flow path 206 in the uphole direction when in the closed position. In at least one embodiment, all or a portion of the flapper 218 may be made of an elastomeric material such that a deformational interference fit may be created between the flapper 218 and the inner wall of the inner flow path 206 when the flapper 218 is in the closed position. In some embodiments, the flapper 218 may be made of a metal material, such that a metal to metal seal is generated between the flapper 218 and the inner wall of the inner flow path 206 when the flapper 218 is in the closed position. The spring force of the pivoting mechanism 220 may hold the flapper 218 against the flapper seat 222 and the walls of the inner flow path 206 until a force is applied to overcome the spring force, which urges the flapper 218 to pivot within the inner flow path 206 away from the closed position. In some embodiments, the pivoting mechanism 220 may thus comprise a self-closing hinge that automatically closes. Those skilled in the art will readily appreciate that the pivoting mechanism 220 described herein is non-limiting and non-exhaustive, such that alternative types pivoting mechanisms 220 may be utilized without departing from the scope of this disclosure.
While the back pressure valve 118 of
Example operation of the dual flapper back pressure valve 200 will now be provided with references to
In
In
In a non-limiting example, the injection fluid 302 may be flowing from the upper end 204a towards the flappers 218 while the return fluid 304 simultaneously flows from the lower end 204b towards the flappers 218. In this example, the lower-most flapper 218 may remained closed, while the upper-most flapper 218 may open and allow the injection fluid 302 to travel downward. Upon reaching the lower-most flapper 218, the pressure may build on either side of the flapper 218. In some embodiments, the pressure from above may overcome the pressure from below, and the flapper 218 may open and allow the injection fluid 302 to travel downwards out of the lower end 204b. Alternatively, the pressure from below may overcome the pressure from above, and the flapper 218 may remain closed without allowing the injection fluid 302 from above to flow downwards, while also preventing the return fluid 304 from below from travelling upwards.
The tubing hanger 412 may be the same as or similar to the tubing hanger 100 of
Embodiments disclosed herein include:
A. A method, comprising: installing a dual flapper back pressure valve within a tubing hanger of a wellhead, the dual flapper back pressure valve including: an elongate body having opposing upper and lower ends and configured to be received and secured within the tubing hanger; an inner flowpath defined within the body and extending between the opposing upper and lower ends; and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism; introducing an injection fluid into the inner flowpath at the upper end; pivoting the flapper from a closed position to an open position with the injection fluid; and circulating the injection fluid through the inner flow path at a flow rate greater than two barrels per minute.
B. A wellhead, comprising: a tubing head adapter; a tubing hanger arranged within the tubing adapter; and a dual flapper back pressure valve arranged within the tubing hanger and including: an elongate body having opposing upper and lower ends; an inner flowpath defined within the body and extending between the opposing upper and lower ends; and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism, wherein, when the flapper is in a closed position, the flapper forms a sealed interface with the inner wall of the inner flow path that prevents fluids from circulating through the tubing hanger and through the inner flowpath from the lower end to the upper end.
C. A dual flapper back pressure valve, comprising: an elongate body having opposing upper and lower ends and configured to be received and secured within a tubing hanger of a wellhead; an inner flowpath defined within the body and extending between the opposing upper and lower ends; and a flapper assembly arranged within the inner flow path and including a flapper pivotably mounted to an inner wall of the inner flow path at a pivoting mechanism, wherein the pivoting mechanism naturally biases the flapper to a closed position, and wherein, when the flapper is in the closed position, the flapper forms a sealed interface with the inner wall of the inner flow path that prevents fluids from circulating through the inner flowpath from the lower end to the upper end.
Each of embodiments A through C may have one or more of the following additional elements in any combination: Element 1: further comprising: reducing the flow rate of the injection fluid through the inner flow path; pivoting the flapper to the closed position and thereby generating a sealed interface with the inner wall of the inner flow path; and preventing a return fluid from circulating through the inner flowpath from the lower end to the upper end with the flapper. Element 2: wherein the flapper assembly comprises a first flapper assembly and the dual flapper back pressure valve further includes a second flapper assembly arranged within the inner flow path and axially offset from the first flapper assembly, the method further comprising: circulating the injection fluid through the inner flow path and past the first and second flapper assemblies; and preventing the return fluid from circulating through the inner flowpath from the lower end to the upper end with the flappers of the first and second flapper assemblies. Element 3: wherein external threads are defined on an exterior of the elongate body, and internal threads are defined within the tubing hanger, and wherein installing the dual flapper back pressure valve within the tubing hanger comprises threadably engaging the external and internal threads. Element 4: further comprising generating a sealed interface between the elongate body and an interior channel of the tubing hanger with a scaling ring arranged about the exterior of the body and above the external threads. Element 5: wherein inner threads are defined within the inner flowpath at or near the upper end, and wherein installing the dual flapper back pressure valve within the tubing hanger is preceded by: threadably attaching a running tool to the dual flapper back pressure valve at the inner threads; and advancing the dual flapper back pressure valve into the tubing hanger. Element 6: wherein the injection fluid comprises an abrasive fluid, a corrosive fluid, a mud mixture, or any combination thereof. Element 7: further comprising: external threads defined on an exterior of the elongate body to threadably secure the elongate body within the tubing hanger of the wellhead; and a sealing ring arranged about the exterior of the body above the external threads to generate a sealed interface between the elongate body and an interior channel of the tubing hanger. Element 8: further comprising inner threads defined within the inner flowpath at or near the upper end, wherein the inner threads are threadably attachable to a running tool for advancing the dual flapper back pressure valve into the tubing hanger. Element 9: wherein the flapper assembly comprises a first flapper assembly, the dual flapper back pressure valve further comprising a second flapper assembly arranged within the inner flow path and axially offset from the first flapper assembly. Element 10: wherein an injection fluid is circulated through the tubing hanger and through the inner flowpath from the lower end to the upper end at a flow rate greater than two barrels per minute. Element 11: further comprising external threads defined on an exterior of the elongate body to threadably secure the elongate body within the tubing hanger of the wellhead. Element 12: further comprising a scaling ring arranged about the exterior of the body above the external threads to generate a sealed interface between the elongate body and an interior channel of the tubing hanger. Element 13: further comprising inner threads defined within the interior channel at or near an uphole end of the tubing hanger, wherein the inner threads are threadably attachable to a running tool for placing the tubing hanger in a tubing head adapter of the wellhead. Element 14: wherein the flapper assembly comprises a first flapper assembly, the dual flapper back pressure valve further comprising a second flapper assembly arranged within the inner flow path and axially offset from the first flapper assembly. Element 15: wherein each flapper assembly further includes a flapper seat arranged within the inner flow path and engageable against the flapper of each flapper assembly when the flapper is moved to the closed position. Element 16: wherein an injection fluid is circulated through the inner flowpath at a flow rate greater than two barrels per minute. Element 17: wherein the pivoting mechanism comprises a self-closing hinge.
By way of non-limiting example, exemplary combination applicable to A through C include: Element 1 with Element 2; Element 3 with Element 4; Element 7 with Element 8; Element 11 with Element 12; Element 12 with Element 13; and Element 14 with Element 15.
The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,” “an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including,” “comprises”, and/or “comprising,” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.
Terms of orientation used herein are merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.
The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.
While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.
