Patent ID: 12241325

DETAILED DESCRIPTION

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 the downhole injection of fluids into a wellbore and, more particularly, to an injection system operable to inject a chemical directly from a side pocket mandrel into an extension of production tubing. The chemical injection treatments described herein may be targeted and tailored to address the needs and requirements of a wellbore and equipment deployed within the wellbore. More specifically, the present disclosure describes a chemical injection system that may be employed within a hydrocarbon producing wellbore in which production tubing extended into the wellbore includes one or more side pocket mandrels. The chemical injection system includes a removable, pressurized container or vessel that injects chemicals directly into the production tubing from its place of containment within a side pocket mandrel.

The presently disclosed chemical injection systems may prove advantageous for a variety of reasons. For example, implementation of such systems eliminates the need for chemical injection lines or bullheading as a means to inject the chemicals into the well, the well annuli and/or the formation. Moreover, the chemical injection systems described herein do not induce near-wellbore formation damage, nor do they induce potential tubing movement and or shrinkage. Furthermore, the systems described herein may be advantageous in facilitating targeted treatment, which cannot be accomplished via conventional methods and systems.

FIG.1is a schematic diagram of an example well system100that may employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system100may include a rig102positioned on a well surface104, e.g., the Earth's surface, and extending over and around a wellbore106that penetrates a subterranean formation108. The rig102may be a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the rig102may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. Moreover, while the well system100is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any offshore, sea-based, or sub-sea application where the rig102may be a floating platform, a semi-submersible platform, or a sub-surface wellhead installation as generally known in the art.

The wellbore106may be drilled into the subterranean formation108using any suitable drilling technique and may extend in a substantially vertical direction away from the well surface104over a vertical wellbore portion110. At some point in the wellbore106, the wellbore106may deviate from vertical relative to the well surface104and the vertical wellbore portion110may transition into a substantially horizontal wellbore portion112. In at least one embodiment, the wellbore106may be completed by cementing a production casing114extending from the well surface104and along a portion of wellbore106. In some applications, the production casing114terminates before reaching the bottom of the wellbore106, thus creating an open-hole section of the wellbore106below (downhole from) the most distal end of the production casing114. In other embodiments, the production casing114may be omitted from the wellbore106and the principles of the present disclosure may equally apply to an entirely “open-hole” wellbore environment. In yet other embodiments, the production casing114may extend for the entirety of the wellbore106.

The well system100may further include production tubing116extending from the well surface104and concentrically arranged within the interior of the production casing114. In some applications, the production tubing116may extend past the distal end of the production casing114and be positioned within the open-hole section of the wellbore106. In other embodiments, the distal end of the production tubing116may be positioned such that it remains within the interior of the production casing114. The production tubing116may be operable to receive and convey formation fluids flowing into the wellbore106from the formation108. The formation fluids may comprise, for example, hydrocarbons (e.g., oil and gas) and water that migrate from a producible reservoir within the formation108and into the wellbore106.

The well system100may further include one or more side pocket mandrels118(one shown) arranged within and forming part of the production tubing116. The side pocket mandrel118may be arranged within the production tubing116at the discretion of the well operator. In at least one embodiment, the side pocket mandrel118may be arranged within the wellbore106inside the production casing114. Alternatively, the side pocket mandrel118may be arranged to axially align with an open-hole section where production casing114has been omitted. In other embodiments, the well system100may include a plurality of side pocket mandrels118, where at least one side pocket mandrel118aligns within an open-hole section and at least one side pocket mandrel118is arranged within the production casing114. In any of the foregoing embodiments, the side pocket mandrel118may fluidly communicate with the interior of the production tubing116.

In some embodiments, the production tubing116may be conveyed into the wellbore106in combination with a production packer120operatively coupled to the production tubing116at or near its distal end. In at least one embodiment, the production packer120may be positioned downhole from the side pocket mandrel118. In other embodiments, the production packer120may be positioned uphole from the side pocket mandrel118without departing from the scope of this disclosure. The production packer120may include any of a variety of radially expandable elements and may be actuated by any of a variety of methods of actuation. The production packer120may be arranged within an annulus122defined between the production tubing116and the inner walls of the wellbore106, wherein the inner walls of the wellbore106may be either the inner wall of the production casing114or the inner wall of an adjacent open-hole section of the wellbore106. In some applications, the annulus122may be referred to as the tubing-casing annulus or “TCA”. When activated (deployed), the expandable elements of the production packer120may extend radially outward to engage the inner walls of the wellbore106(e.g., the inner wall of the production casing114or the inner wall of the adjacent open-hole section) and thereby secure the lowermost portion of the production tubing116within the wellbore106. Moreover, once deployed, the production packer120provides a fluid seal in the annulus122and may be operable as a mechanical well barrier to fluid flow between a producible reservoir and a portion of the annulus122above (uphole) of the production packer. In other embodiments, the production packer120may be omitted from the well system100entirely, and such an embodiment will not exceed the scope of this disclosure.

It will be appreciated by those skilled in the art that even thoughFIG.1depicts the side pocket mandrel118and the production packer120being arranged and operating in the vertical portion110of the wellbore106, the embodiments described herein are equally applicable for use in portions of the wellbore106that are horizontal, deviated, or otherwise slanted. Moreover, use of directional terms such as above, below, upper, lower, upward, downward, uphole, downhole, and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward or uphole 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. As used herein, the term “proximal” refers to that portion of the component being referred to that is closest to the well surface104, and the term “distal” refers to the portion of the component that is furthest from the surface104.

To prevent or treat scale deposition within the wellbore106, conventional methods of treatments can be utilized that may include performing scale inhibitor squeezes. Squeezes generally entail pumping (bullheading) a chemical, such as a scale inhibitor, into the annulus122. The scale inhibitor may be adsorbed by the exposed formation (e.g., the open-hole section; not shown). When pumping ceases and the well is put back on to production, formation fluids flow back into the wellbore106with the scale inhibitor, preventing the buildup or deposition of scale within the wellbore106and more broadly, the well system100. The rate of flow back is only controllable by increasing or decreasing the amount of water the well produces. Permitting a higher water cut rate flows back the injected chemical at a quicker rate, dissipating the treatment faster and often requiring repeat squeeze operations which may ultimately, with the addition of more chemicals, cause formation damage to the near-bore region of the wellbore106. Such formation damage may reduce the porosity and permeability of the near-bore region and result in an overall reduction of hydrocarbon production.

Side pocket mandrels are a commonly utilized tubular capable of receiving and retaining replaceable downhole devices, such as gas lift valves and circulation valves. Using a side pocket mandrel allows for the retrieval and replacement of valves/components without having to remove the entire production tubing116. As an alternative to bullheading, side pocket mandrels are also used for chemical injection and, more particularly, continuous chemical injection. In such applications, the side pocket mandrel may house a chemical injection valve that is fluidly coupled to a control line that extends from the well surface104to the chemical injection valve. Because the injected chemicals are sourced from the well surface104, they are injected into the control line at ambient temperature and pumped to the chemical injection valve to be discharged into the interior body of the production tubing. In such applications, the chemicals are injected at near surface temperature (i.e., the temperature of the injected chemical is much colder than the downhole temperature) and can result in movement and even shrinkage of the production tubing116, which can cause the production tubing116to unseat from the production packer120, thus resulting in a loss of well barrier integrity.

According to embodiments of the present disclosure, alternative to traditional chemical treatment of the wellbore106, chemical injection may be controlled, targeted, and at (or near) downhole wellbore temperatures. The embodiments herein disclose the use of the side pocket mandrel118capable of housing a removable, pressurized chemical vessel that may discharge specified and known dosages of fluids (e.g., chemicals).

FIG.2is an enlarged, schematic cross-sectional side view of a portion of the wellbore106ofFIG.1, according to one or more embodiments of the present disclosure. More particularly,FIG.2illustrates an enlarged view of the side pocket mandrel118as arranged within the production casing114of the wellbore106. The side pocket mandrel118interposes upper and lower sections of the production tubing116. Accordingly, opposing ends of the side pocket mandrel118may include matable connections (not shown) that may permit operative coupling to the production tubing116. In at least one embodiment, the matable connection comprises threads (e.g., American Petroleum Institute (API) threads) that may threadably engage matable threads defined upon the opposing upper and lower sections of the production tubing116. In other embodiments, the matable members of the side pocket mandrel118may comprise any known connection that will engage the opposing connection of the production tubing116.

As illustrated, the side pocket mandrel118comprises a generally elongate, tubular body202, portions of which align with and have the same outer circumferential dimensions as that of the production tubing116. The body202may define a lateral projection204that extends radially outward from the body202and, therefore, exhibits a larger cross-sectional diameter as compared to the remaining portions of the body202. Accordingly, the lateral projection204extends into the surrounding annulus122.

As illustrated, the lateral projection204may include upper and lower shoulders206aand206bthat project radially outward from the outer circumference of the body202. In some embodiments, one or both of the shoulders206a,bmay extend from the outer surface of the body202at an obtuse (non-perpendicular) angle. This may prove advantageous in helping to avoid catching the shoulders206a,bon downhole obstructions as the production tubing116is moved downhole or uphole within the wellbore106.

The lateral projection204further provides and otherwise defines a lateral face208, and the shoulders206a,bextend between the body202and the lateral face208. In some embodiments, a well operator may advance the production tubing116into the wellbore106until the lateral face208aligns axially with the desired portion of the wellbore106(e.g., inside the production casing114or within an open-hole section).

The lateral projection204may provide and otherwise define a pocket210that forms the interior of the lateral projection204. As described in more detail below, the pocket210may be sized and otherwise configured to receive and retain a chemical vessel operable to discharge an injection fluid into the wellbore106and, more particularly, into the interior of the production tubing116.

FIG.3is another enlarged, schematic cross-sectional side view of the wellbore106, depicting the installation and/or removal of an example chemical vessel302(alternatively referred to as a “chemical bottle” or “chemical container”) within the side pocket mandrel118, according to one or more embodiments of the present disclosure. As illustrated, the chemical vessel302may include a generally cylindrical and elongate body sized and otherwise configured to be received within the pocket210. The chemical vessel302may be configured to contain an injection fluid to be discharged into the interior of the production tubing116. The injection fluid may comprise, for example, a chemical, a mixture of chemicals, or any combination thereof. The injection fluid may comprise a particular volume and composition dictated by the operator and applicable to the needs of the wellbore106.

In at least one embodiment, the injection fluid contained within the chemical vessel302may comprise a scale inhibitor capable of preventing the buildup of scale in the interior of the production tubing116, as well as on inner walls of the wellbore106and/or the exterior of the production tubing116. In other embodiments, the injection fluid may comprise a chemical treatment including, but not limited to, a corrosion inhibitor, an asphaltenes inhibitor, a wax inhibitor, an anti-foamer, a demulsifier, a surfactant, and any combination thereof. In some embodiments, the injection fluid may be pressurized within the chemical vessel302such that the injection fluid may be discharged (propelled) from the chemical vessel302at a known flow rate.

In some embodiments, the chemical vessel302may provide and otherwise define one or more apertures306through which the injection fluid may be discharged from the chemical vessel302. In at least one embodiment, the one or more apertures306may comprise metered orifices configured to restrict or “meter” fluid communication. In such an embodiment, the metered orifice may comprise a known diameter (flow path), through which the injection fluid is discharged from the chemical vessel302at a known flow rate. In other embodiments, one or more of the apertures306may comprise a one-way check valve operable to permit a known flow rate of the injection fluid through the apertures306, while simultaneously preventing backflow of fluids from the production tubing116and into the chemical vessel302. Other embodiments may include apertures306that comprise nozzles actuatable by differential pressure. In yet other embodiments, the apertures306may comprise selectively actuatable valves configured to be opened or closed based on command signals sent from the well surface104(FIG.1) or another location. In such embodiments, the actuatable valves may be selectively opened to a desired degree and thereby permit a known flow rate of the injection fluid.

In at least one embodiment, the chemical vessel302may be removably coupled to the side pocket mandrel118, and thus configured to be deployed and retrieved while the side pocket mandrel118remains in place within the wellbore106. In such embodiments, the chemical vessel302may be releasably coupled to a running tool304operable to selectively couple and decouple from the chemical vessel302. The running tool304may be operatively coupled to and conveyed into the wellbore106by means of a conveyance310such as, but not limited to, wireline, slickline, digital slickline, coiled tubing, or any combination thereof. Deployment (and similarly, retrieval) by wireline or slickline is advantageous over traditional bullheading operations because of the relative simplicity of surface equipment utilized, as well as the speed with which a slickline operation may be carried out. A faster operation may result in reduced non-productive time and as a result, less cost.

InFIG.3, the running tool304is depicted as a kickover tool, but could alternatively comprise other types of downhole tools capable of coupling to and decoupling from the chemical vessel302and running the chemical vessel302into and out of the wellbore106.

To install the chemical vessel302in the side pocket mandrel118, the running tool304may convey the chemical vessel302to the side pocket mandrel118within the production tubing116. Upon reaching the side pocket mandrel118, the chemical vessel302may locate and be received within the pocket210. In at least one embodiment, the running tool304may be manipulated and otherwise operable to position the chemical vessel302within the pocket210such that the apertures306align to face the interior of the production tubing116to allow discharge of the injection fluid from the chemical vessel302. Once the chemical vessel302is properly positioned and aligned, the running tool304may be decoupled (disconnected) from the chemical vessel302and retrieved back to the well surface104(FIG.1) on the conveyance310.

In some embodiments, decoupling the running tool304from the chemical vessel302may actuate and otherwise activate the apertures306to an open position, thereby resulting in an automatic and metered release of the injection fluid contained within the chemical vessel302. In at least one embodiment, however, one or more of the apertures306may include a metered orifice308, as described above. In such embodiments, the injection fluid may pass through the metered orifice308at a known flow rate and be discharged into the production tubing116. In embodiments where the metered orifice308comprises a one-way check valve or the like, the pressurized flow of the injection fluid discharged from the chemical vessel302may open the one-way check valves arranged within the apertures306, thereby allowing the injection fluid to be discharged into the wellbore106and, more particularly, into the production tubing116. In such embodiments, when the pressurized flow of the injection fluid from the apertures306ceases, the one-way check valves will automatically close, thereby creating a barrier to fluid flow from the production tubing116into the chemical vessel302.

In other embodiments, the release of the injection fluid from the chemical vessel302may be via any known actuation mechanism including but not limited to differential pressure nozzles, timed release, telecommunication methods that may be wired or in the alternative, wireless, and radio frequency identification (RFID) activation.

Regardless of the actuation mechanism, the injection fluid may be discharged into the well system100(FIG.1) at or near downhole temperatures or otherwise at a temperature that is at or near the temperature within the wellbore106where the side pocket mandrel118is located. In contrast to conventional chemical injection by means of a control line, the chemicals contained within the chemical vessel302may be gradually exposed to and match the downhole temperature such that the injection fluid may be discharged from the chemical vessel302at or near downhole temperatures. Similarly, wherein the actuation method is timed release or some other on-demand communication methodology, the operator may ensure that chemical injection occurs when the contained chemical has (or should have) reached the downhole temperature. In either embodiment, injection of the injection fluid at or near the downhole temperature of the wellbore106reduces the potential of shifting of the production tubing116or unseating from the production packer120(FIG.1).

Once the injection fluid has been discharged from the chemical vessel302and the chemical vessel302is otherwise “depleted,” the chemical vessel302may be extracted from the wellbore106and refilled and re-pressurized for future use. To retrieve the chemical vessel302, the running tool304may be extended into the production tubing116on the conveyance310and advanced downhole to locate the chemical vessel302. Upon locating the chemical vessel302, the running tool304may be operatively coupled to the chemical vessel302.

In some embodiments, coupling the running tool304to the chemical vessel302may disengage the chemical vessel302from the pocket210. In other embodiments, the running tool304may have to be manipulated to disengage the chemical vessel302from the pocket210. In yet other embodiments, the chemical vessel302may be disengaged from the pocket210by coupling the running tool304to the chemical vessel302and pulling in the uphole direction with the running tool304. Once the chemical vessel302is removed from the pocket210, the conveyance310may be retracted uphole to return the chemical vessel302to the well surface104(FIG.1).

FIG.4is a schematic flowchart of an example chemical injection method400, according to one or more embodiments. The method400may include conveying a chemical vessel into a wellbore, as at402. The chemical vessel may be conveyed into the wellbore within production tubing extended into the wellbore, and the chemical vessel may have an injection fluid stored therein. The wellbore may be at least partially lined with production casing extending from the surface as well, and the production tubing may extend within the interior of the production casing. The chemical vessel may be conveyed downhole until locating a side pocket mandrel interposing upper and lower sections of the production tubing, as at404. The side pocket mandrel may include a body that provides a lateral projection extending radially outward from the body and defining a lateral face, a pocket defined by the lateral projection, and operable to receive and contain the chemical vessel.

The method400may further include receiving the chemical vessel in the pocket, as at406, and discharging the injection fluid into the production tubing via the one or more apertures defined within the chemical vessel, as at408. In some embodiments, the injection fluid is discharged at a temperature of the wellbore where the side pocket mandrel is located. In some embodiments, once the injection fluid is discharged from the chemical vessel, the depleted chemical vessel may then be removed from the pocket and returned to the well surface. In at least one embodiment, the chemical vessel may be re-filled with additional injection fluid and conveyed back downhole to be re-deployed within the pocket of the side pocket mandrel.

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 are used herein 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.

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.