Plunger assembly with dual dart system

The present application includes and assembly having a dual dart assembly operable between an upper cage and a lower cage. The dual dart assembly is configured to connect an upper dart and a lower dart via a connecting rod. Therefore movement of one dart causes equal movement in the other dart. Movement of the dart is dampened upon impact at the top and bottom of the well by restriction of the working fluid as the dart assembly seats and unseats. A series of expandable seals are independently operated around the outer body and configured to expand and contact the outer wall in response to pressure increases within the outer body.

BACKGROUND

1. Field of the Invention

The present application relates generally to oil field devices and, more particularly, to a plunger assembly with a connected dual dart assembly.

2. Description of Related Art

The oil and gas industry has been drilling holes and removing natural crude oil for decades. Wells contain any number of contaminants, particulates, and water along with the gas/oil being sought. If water is not removed, pressure of the hydrostatic head of water in the surface tubing will become greater than that of the bottom hole pressure, thereby essentially sealing the formation and shutting in the well. Gas cannot on its own pressure typically flow to the surface.

Plungers are downhole tools used by operators to remove contaminants and water from productive natural gas wells. A plunger acts as an artificial lift. In operation the plunger passes down through the well until it reaches a contact point, at which point, potential energy of the plunger falling in the well acts to partially restrict the flow of working fluid through the plunger. Pressure beneath the plunger builds and raises the plunger in the well, thereby pushing out the liquids and contaminants above the plunger.

Typical plunger lift systems rely on the potential energy of the system falling in the well to generate enough force such that upon impact, a dart in the lower portion of the plunger moves to restrict flow of the working fluid through the body of the plunger. In other words, the contact itself sets the dart and generates a seal. Such designs generate a lot of forces on the tool and the equipment (i.e. the stop) at the bottom of the well upon impact. Tools are commonly damaged from the impacts.

An additional disadvantage is the effect of a “drift diameter” restraining the size of the plunger in relation to the well bore. The drift diameter is the minimum inside diameter of the tube in order to pass a ridged tool of some set length through it. Tools are designed to have a maximum diameter no greater than the drift diameter of the tubing. This results in the tools having a gap between them and the ID of the tubing. The large annulus or gap between the tool and the tubing that the tools passes through are one reason why tools tend to be inefficient because plunger lift tools work on a pressure gradient between fluid beneath the tool and fluid above the tool. Leaks between the tool and tubing impact the pressure gradient.

Another disadvantage of conventional plunger lift systems are the particulates (i.e. sand) in the working fluid. The working fluid passes within the gap between the plunger lift system and the casing at increased speeds resulting in tools abrading quickly. Additionally, the leak leads to turbulence created around the down hole edge of the tool when it expands after passing through the leak.

Furthermore a disadvantage remains in that typical plunger lifts require the use of a striker rod in a lubricator located at the top of the well. This extra member of the plunger lift system is used as an impact point for the plunger and to unseat the dart which had been sealed and seated at the bottom of the well. By unseating the dart, the working fluid is once again able to pass through the plunger and the plunger may fall. Plungers can often have limitations on the type of lubricator and striker rod they are compatible with. As flow rates vary within the well, different plungers may be used, thereby requiring the extra time and money necessary to change out the lubricator or striker rod.

Although great strides have been made, considerable shortcomings remain. A new plunger lift assembly tool is required that is usable without a lubricator and striker rod, dampens impact forces, minimizes abrading, and corrects for the constraints associated with the drift diameter.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The assembly in accordance with the present application overcomes one or more of the above-discussed problems commonly associated with conventional plunger lift systems as described above. The assembly of the present application is configured to translate within the tubing of a well bore between a raised top position and a lowered bottom position. The raised top position is located at the surface of the well bore while the lowered bottom position is located at the base of the well bore deep within the ground. Specifically, the assembly is configured to include a dual dart assembly wherein a dart is located at either end of the plunger assembly and is connected together via a connecting rod. The movement of one dart moves the other dart. Additionally, the assembly is configured to provide an internal dampening effect on both darts through a single bleed port. The bleed port dampens the impact of the plunger assembly at both the top and bottom of the well. Furthermore, the plunger assembly is configured to decrease wear on the body of the assembly by using individually operated expandable seals spaced along the body. Wear pads are also used to protect the outer body and provide many benefits described herein. These and other unique features of the assembly are discussed below and illustrated in the accompanying drawings.

The plunger assembly of the present application is illustrated in the associated drawings. The assembly includes a three part body including a center body, an upper cage, and a lower cage. Each cage includes a dart wherein both darts are coupled together. Movement of one dart therefore moves the other dart in a corresponding manner. Referring now to the drawings wherein like reference characters identify corresponding or similar elements in form and function throughout the several views.FIG. 1illustrates plunger assembly101within tubing90of a well bore92. Assembly101is configured to operate without the use of a striker rod inside tubing90. The operation of assembly101is similar on both ends of the plunger body. At the bottom of the well bore is a bumper96(i.e. some type of equipment) used to move the dart from a first position to a second position. Likewise, at the top of well bore92is a similar piece of equipment where the dart is moved from a second position to a first position. The forces generated by assembly101during the fall and rise through tubing90are transferred to assembly101. After contact with bumper96at the lower end of well bore92a pressure gradient begins to form from the formation pressure and causes assembly101to rise within tubing90toward the surface. Movement of the dart assembly has restricted flow of the working fluid through the assembly body. After contact at the top of well bore92, the dart is moved which opens or unrestricts the flow of working fluid through the assembly body and therefore permits the plunger assembly101to fall within well bore92. The plunger assembly101of the present application is configured to translate and operate within tubing90between the top end and the lower end of the well bore. As the plunger assembly101rises within tubing90, contaminants, particulates, and water above the assembly are brought to the surface.

As seen inFIG. 1, assembly101includes a body having a central channel105and a dual dart assembly103. Dart assembly103is configured to translate within central channel105between the first and second positions in order to selectively restrict and unrestrict the flow of working fluid within well bore92. Assembly101is shown inFIG. 1in a falling configuration just prior to impact with bumper96.

Referring now also toFIGS. 2-8in the drawings, plunger assembly101is shown in greater detail. An enlarged view of plunger assembly101is illustrated inFIG. 2. Plunger assembly101includes an outer body consisting of three members: an upper cage107, a lower cage109, and a center body111. Upper cage107and lower cage109are coupled to opposing ends of body111. Central channel105passes through a portion of upper cage107, lower cage109, and through body111to allow for the passage of working fluid to pass through the outer body.

As seen in greater detail inFIG. 3, dual dart assembly103is illustrated. Dart assembly103is in communication with upper cage107and lower cage109. Dual dart assembly103operates between the first position and the second position by translating through central channel105. Dual dart assembly103has an upper dart103alocated in upper cage107and a lower dart103blocated in lower cage109. Upper dart103aand lower dart103bare coupled together via a connecting rod103c, such that movement of one dart moves the opposing dart. Rod103cmay be coupled to darts103a/103bin various manners. A rigid connection is possibly, however a connection that permits at least one degree of freedom is preferred in order to prevent potential issued from misalignment. As seen inFIG. 3, darts103a/103bare coupled to rod103cvia a ball and socket type of connection. This hinged connection allows some independent rotation of each dart relative to rod103c. Independent axial movement is restricted however.

Dual dart assembly103further includes one or more seals113. A pressure seal113ais located at the base of upper dart103aand is configured to contact a seat115as dart assembly103is moved into and out of the second position. Seal113acreates a seal between dart103aand upper cage107around the circumference of dart103a. Seals113bare also seen to create a seal with seat115. The use of seals113aand113bhelp to provide a dampening effect upon dart assembly103at impact with the upper and lower portions of well bore92.

As seen in particular inFIG. 5, upper cage107includes a bleed port117. Port117is located within seat115ideally between the range of motion of dart103abetween the first and second positions. For example, dual dart assembly103is located in its first position inFIG. 2. Seal113ais outside of seat115in central channel105, however seal113bis positioned just above port117. Port117is configured to remain between seals113aand113bas dual dart assembly103translates between the first and second positions. Bleed port117is configured to dampen the movement of the dual dart assembly103as the dual dart assembly103moves between the first position and a second position. As assembly101is falling and impacts bumper96, assembly103is translated to the second position (pushed upward) wherein seals113acontact seat115and the fluid between seals113aand113bare pushed out through port117. Likewise as assembly101is rising and impacts the upper portion of well bore92, dart assembly103is translated to the first position (pushed downward) wherein working fluid is pulled within seat115through port117. This dampening effect can be regulated by modifying the size of port117.

Referring now back toFIG. 3, dual dart assembly103is shown to include a number of recesses. Assembly103includes an upper recess119and a lower recess121. Recesses119and121are configured to hold dart assembly103in a particular position as assembly101is translating within well bore92. As seen inFIG. 2, assembly101includes a ball detent plunger assembly123configured to position the dual dart assembly between the first position and the second position. Contact of the ball detent plunger123within upper recess119locates assembly103in the first position as seen inFIG. 2. Contact of ball detent plunger123within lower recess121locates assembly103in the second position. Ball detent plunger assembly123is configured to have a ball portion that is spring loaded so as to selectively retract within lower cage109as impact forces move assembly103. Ball detent plunger assembly is adjustable such that the required force to transition the dual dart assembly103between the first position and the second position is selectable. A nut and clutch are used to help provide the adjustment possibilities by selectively locating the ball closer to or further from dart103b.

Assembly101further includes an internal pressure relief port125in upper cage107. Internal pressure relief port125is configured to remain unobstructed by the dual dart assembly103in either the first position, the second position, or travel there between each position. Internal pressure relief port125is configured to moderate the pressure differential between the working fluid adjacent upper cage107and the working fluid adjacent lower cage109. By moderating or regulating the pressure differential, working fluid is permitted to pass through central channel105and exit upper cage107while assembly101is rising in well bore92. By permitting the flow of working fluid through central channel105while assembly101is rising, the speed of assembly101is more controlled and less susceptible to blow out or experience harsh impacts at the upper end of tubing90. It is understood that this may limit some applications of assembly101to wells having a higher rate of production (more pressure) but will help assembly101handle such wells which may not be typically used with conventional plungers. It is understood that an operator may selectively plug or restrict the flow through port125to accommodate various wells and their production rates.

Referring now toFIGS. 6 and 8in the drawings. Lower cage109is configured to include an external taper127. As seen with the use of port125above, it can be desirable to regulate the speed at which assembly101moves through well bore92. Taper127is configured to regulate the fall rate of assembly101. By increasing and decreasing the size of taper127, the fall rate of assembly101may be modified. As seen inFIG. 8, an end view of lower cage109is illustrated, tapers127are seen. The depth of taper127and the number of tapers used around the annulus affects the cross sectional area of assembly101. Assembly101is configured to permit various sized tapers127as necessary for desired applications and wells.

Furthermore withFIG. 6, lower cage109includes a fluid port129configured to permit the passage of the working fluid into center channel105. Fluid port129is sloped relative to the axis of center channel105so as to minimize turbulence of the working fluid upon entering center channel105. In other words, the location of the opening of port129along the outer surface of lower cage109is lower than the opening of port129on the inner surface of lower cage109. As fluid arrives at port129, the fluid is able to more easily pass through into channel105. Turbulence commonly seen with ports orthogonally oriented relative to the flow of working fluid is avoided. It is understood that any number of ports129may be used. More than one port129is possible on each flat of taper127.

FIG. 7illustrates a top view of an exterior portion of the outer body. Working fluid needs to pass by or through the outer body as assembly101falls in the well bore. Various factors limit this from happening. A drift diameter for assembly101and the well bore often lead to close tolerances between assembly101and tubing90. Particulates may also clog or obstruct selected passage ways within tubing90. The plunger tool itself may become clogged in any one of the ports. Limitations to the free flow of working fluid around or through assembly101can result in failed operation. In order to increase the flow of working fluid around assembly101while maintaining the close drift diameter tolerances, portions of the outer body include a series of external channels141. Channels141are designed to provide routes for the passage of working fluid as assembly101falls within the well bore. Channels141are axially aligned with length of the outer body. It is understood that some embodiments may elect to provide non axial alignment if rotation of assembly101is desired.

Working fluid within the tubing of the well bore contains a number of contaminants, debris, particulates, oils, and so forth that can be abrasive and damaging to objects and tools. These provide a constant abrasive and corrosive effect upon the body of assembly101. Assembly101is configured to include one or more wear pads131. Pads131are located in any portion of the outer body. As seen inFIG. 2, pads131are located within grooves133(FIG. 4) and are configured to extend beyond the outer diameter of the outer body. Pads131are designed to be located at locations where abrasion are highest. Pads131are releasably coupled to the outer body and may be replaced when worn. In this way, pads131act as a sacrificial member of assembly101by protecting the outer body from exposure to contaminants and particulates in the working fluid. The design, shape, and contour of pads131are variable and may be selected based upon design constraints and application.

Referring now toFIGS. 2 and 4in the drawings, assembly101is configured to include one or more expandable seals135releasably coupled to the outer body. The Figures illustrate seals135being in communication with center body111but it is understood that either cage107and109may be modified to include seals135in other embodiments. Seals135are configured to selectively increase in diameter as pressure builds within channel105such that seals135expand the effective outer diameter of assembly101and contact tubing90.

Seals135are configured to stretch but there is a balance between the hardness and flexibility of seal135. Seal135is hard enough to provide sufficient abrasion to the walls of well bore92but yet is flexible enough to expand at a pressure level lower than is necessary to lift assembly101. Seal135is configured to have sufficient flexibility to accommodate variations in well bore diameter, meaning that the diameter of seal135may increase or decrease as assembly101rises within the well bore. Seals135may be formed from a hardened and flexible plastic or polyurethane material. Seals135are individually located within separate groove137located on center body111.

As seen inFIG. 4, center body111includes an expandable seal port139configured to allow pressure within channel105to pass through to seals135. Each seal is independently operable from the other expandable seals135because each seal is in direct fluid communication with channel105. In other words, each groove137includes a separate seal port139. It is understood that some ports139may be used to operate one or more seals135in other embodiments and are herein contemplated. As pressure builds within channel105, the working fluid passes through ports139and press outward against seals135thereby causing seals135to expand in diameter.

There are many advantages of having seal135contact the walls of the tubing in the well bore, some of them are as follows: (1) Seal135rubs and scrapes the walls clean when rising. This serves to prolong the life of the tubing/casing and maintain the integrity of the well bore. (2) Scale buildup decreases the relative internal diameter of the tubing leading to potential clogging of tools. Seal135therefore maintains the drift diameter. (3) Seal135creates a seal against the walls that prevents the passage of working fluid (leakage). Therefore, creating the seal reduces abrading. (4) Contact between expandable seal135and the walls increases stabilization of assembly101.

The current application has many advantages over the prior art including at least the following: (1) dual dart assembly; (2) ability to operate within a well bore without the use of a lubricator or striker rod; (3) use of optional wear pads; (4) a bleed port to dampen impact forces at the top and bottom of the well bore; (5) an internal pressure relief port to control the speed of ascent within the well bore; (6) independently operated expandable seals to prevent leakage of working fluid between the assembly and the walls of the well bore; and (7) a tapered lower cage.