Patent Grant
9856707
Reciprocating pump systems, such as sucker rod pump systems, extract fluids from a well and employ a downhole pump connected to a driving source at the surface. A rod string connects the surface driving force to the downhole pump in the well. When operated, the driving source cyclically raises and lowers the downhole pump, and with each stroke, the downhole pump lifts well fluids toward the surface.
For example,
During the upstroke, the traveling valve 22 is closed, and any fluid above the plunger 20 in the production tubing 18 is lifted towards the surface. Meanwhile, the standing valve 24 opens and allows fluid to enter the pump barrel 16 from the wellbore. At the top of stroke (TOS), the standing valve 24 closes and holds in the fluid that has entered the pump barrel 16. During the downstroke, the traveling valve 22 initially remains closed until the plunger 20 reaches the surface of the fluid in the barrel 16. Sufficient pressure builds up in the fluid below the traveling valve 22 to balance the pressure. After the pressure balances, the traveling valve 22 opens and the plunger 20 continues to move downward to its lowest position to fill the pump 14. The reciprocating process is repeated to lift fluid in the tubing.
In many applications, such as in reciprocating pump systems noted above, operators may want to inject chemicals to assist in the control of corrosion, water, scale, paraffin, salt, and Hydrogen Sulfide (H2S) in the production tubing. One way to inject chemicals uses a capillary injection system, which can deliver the chemicals downhole using a capillary string. In addition to controlling buildup and the like, the capillary injection system can be used to inject a lifting chemical to offset a reduction in bottom hole pressure (BHP) that typically occurs as a hydrocarbon reservoir is produced.
Chemical injections have been developed to mitigate or eliminate these difficulties. For example, surfactants are commonly injected into wells to de-water them. Other chemicals are used to counter the effects of emulsions and precipitates and to provide corrosion protection. If the well is untreated, it is well known that corrosive materials can rapidly degrade wellbore components, such as sucker rods. Of course, if these components must be replaced, the non-productive time for the well will result in lost or slowed production.
Spoolable tubing has been used for delivering the above mentioned chemicals. Examples of spoolable tubing are capillary tubing and coiled tubing.
Below the tubing anchor 40, the assembly has the sucker rod pump P and may have a perforated sub (not shown). The sucker rod pump P is connected to a sucker rod string R extending through the production tubing T to the surface. As already noted, reciprocation of the string R axially reciprocates the pump P to transport fluids from the formation through the production tubing T to the surface.
To deliver chemicals downhole, the capillary string S extends from the wellhead (not shown) at the surface and along the tubing T. The capillary string S is typically banded to the production tubing T with various bands. Eventually, the capillary string S terminates at the production tubing T uphole of the tubing anchor 40, where injected chemicals are delivered.
In
These traditional treatment methods in
To improve the chemical injection, it has been proposed in the prior art to extend the end of the capillary string past the tubing anchor and closer to the inlet of the rod pump. For example,
As disclosed in U.S. Pat. No. 4,605,063, a solution has been proposed in the prior art in which a capillary string is simply passed through a conventional tubing anchor. Referring to
The tubing anchor 40 is incorporated into the production string to prevent vertical movement of the tubing string. The tubing anchor 40 has an axially extending tubular body 41 conventionally attached to the tubing T by upper and lower threaded couplings 43a-b. The tubular body 41 has upper and lower threads 41a, 41c adjacent its upper and lower ends. The upper threads 41a are of an opposite hand from the lower threads 41c. At least one axially extending groove 41b is located along the exterior surface of the tubular body 41 and extends through both the upper and lower threads 41a and 41c. Although not shown, the groove 41b has a dovetail cross-sectional configuration.
An upper conical expander 42 has inner threads 42a engagable with the tubular body's upper threads 41a, and the expander 12 is positioned concentrically around tubular body 41 adjacent threads 41a. The expander 42 has a downwardly facing conical surface 42c. A similar lower expander 52 has an upwardly facing conical surface 52a. This lower expander 52 has internal threads 52c and is located adjacent the lower end of the tubular body 41. The internal threads 52c are nonfunctional after assembly. In a retracted position (not shown), the threads 52c are not in engagement with the body's lower threads 41c.
The anchoring slips 50 are positioned concentrically encircling the tubular body 41 between the upper and lower expanders 42 and 52. When expanded against the casing, the anchoring slips 50 can securely engage to prevent vertical movement in either direction. The anchoring slips 50 are received within openings or windows 44a defined within an exterior tubular housing 44 encircling the expanders 42 and 52 and the tubular body 41. Coil springs 60 extend circumferentially between adjacent anchoring slips 50 and inwardly bias the anchoring slips 50 to retracted positions.
A torque pin 62 attached to the lower expander 52 extends through an axially extending slot 44b located in the outer housing 44. The torque pin 62 thus rotationally secures the outer housing 44 to the lower expander 52, and the windows 44a rotationally secure each radially expandable anchoring slip 50 to the outer housing 44. The lower expander 52 is attached to the expander sleeve 66 with shear pins 64. Sleeve 66 has threaded connections 66c on its interior engagable with the lower threads 41c located on the tubular body 41. Rotation of tubular body 41 will therefore cause movement of the expander sleeve 66 and the lower expander 52 relative thereto.
A nut assembly 46 and 48 secures the outer housing 44 to the tubular body 41. A flexible drag spring 56 is secured to the tubular housing 44 by means of conventional screws 58. The drag spring 56 is outwardly biased and engages the casing C to prevent rotation of the outer housing 44 relative to the casing C. Thus, rotation of the upper and lower expanders 42 and 52 and the anchoring slips 50 relative to the casing is resisted by drag spring 56.
To secure the tubing anchor 40 and the tubing T with respect to the casing C, the tubing T can be rotated thus imparting rotation to the tubular body 41. Rotation of tubular body 41 occurs while the upper expander 42 is rotationally restrained by the outer housing 44 and by the drag springs 56. Therefore, the threads 41a and 42a move the upper expander 42 axially relative to the anchoring slips 50. The slips 50 and the tubular housing 44 are initially moved downwardly relative to tubular body 41.
Eventually, the lower expander 52 moves downwardly into engagement with the body's lower threads 41c whereupon continued rotation of tubular body 41 causes the lower expander 52 to move in the opposite direction toward the slip 50 and the upper expander 42. Continued rotation shifts the upper and lower expanders 42, 52 toward each other and ultimately expands the anchoring slips 50 outwardly into engagement with the casing C. Eventually, sufficient rotation is imparted to the tubular body 41 to fully expand the anchoring slips 50 and to prevent further axial movement of the tubing string T in either direction.
The tubing anchor 40 can be released by sufficient upward tension on the tubing string T to shear the shear pins 64 holding the lower expander 52 fixed relative to the tubular body 41. These shear pins 64 are chosen with a sufficient strength to prevent release under normal anticipated tensile loads.
Since the anchoring slips 50 are actuated by rotational movement of the tubular body 41 and the tubing string T, it will be apparent that the capillary string 30 attached to the tubing T will interfere with the normal expansion of the slips 50 since the capillary string 30 must move rotationally with the tubing T. As shown, a separate conduit or section of the capillary string 30 is provided with upper and lower conventional attachments for attachment to upper and lower sections of the capillary string. This intermediate section of the capillary string 30 comprises a separate section of flow line of the same type and diameter as that of the remainder of the string 30. The intermediate section of the capillary string 30 is received within the body's dovetail groove 41b and extends along the exterior of the tubular body 41 through the upper and lower expanders 42 and 52 and through the encircling anchoring slips 50. This groove 41b is sufficiently deep to permit the capillary string 30 be received therein without interfering with the threaded connections 41a-42a or 41c-52c of the expanders 42, 52. In this way, a path is provided for injection of fluids through the tubing anchor 40 to a subsurface location below the tubing anchor 40, such as adjacent perforations in the casing.
The tubing anchor 40 of
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.
A capillary injection system for delivering a chemical to a targeted area in a wellbore has a production string, a control body or tubing anchor, and a capillary string. The capillary string has an injection valve on its distal end. The capillary string is fastened to at least a portion of the production string disposed in the wellbore. The tubing anchor is adapted to permit a portion of the capillary string to pass therethrough so the valve can deliver the flow of chemicals to a targeted area in the wellbore, such as at a rod pump on the production string.
In one implementations, the tubing anchor has a mandrel, a housing, and a slip holder. The mandrel is coupled to the production string and accommodates a portion of the capillary string outside thereof. The mandrel defines a first slot for the housing and defines a second slot for the slip holder. The mandrel also has a cone disposed thereon.
The housing is disposed on the mandrel about the capillary string and is engaged with the first slot. The holder is disposed on the housing and can rotate relative to the housing. The holder engaged with the second slot on the mandrel. Finally, the holder has a slip movable outward from the mandrel.
When the tubing anchor is in an unset condition, the mandrel has a first portion of the first slot engaged with the housing. The cone on the mandrel is positioned away from the slip so that the slip is not moved outward against the casing.
The tubing anchor can be set from the unset condition to a set condition by rotating the production tubing (and the mandrel by connection) less than a full turn (e.g., ¼ turn) and pulling tension on the production tubing (i.e., moving the mandrel axially uphole). When the tubing anchor is in the set condition, the mandrel is moved axially and less than the full turn from the first portion of the first slot relative to the housing. The holder is rotated relative to the housing, and the cone moves the slip outward against the casing.
The tubing anchor can be used in a lift system, such as a reciprocating rod pump, progressive cavity pump, plunger lift, or other system in which the production string is held in tension. The lift system can use an injection valve disposed on a distal end of the capillary string downhole of the tubing anchor.
The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.
As shown in
The well has a casing C with perforations at a production zone. The production string T has threadably interconnected joints and extends from the wellhead 13 at the surface to the tubing anchor 100 and extends from there to the reciprocating rod pump P. Centralizers (not shown) as known to those of ordinary skill in the art can be used to keep the production tubing T centralized in the wellbore. For its part, the tubing anchor 100 anchors the production tubing T in the casing C and allows the production tubing T to be held in tension in the wellbore.
Below the tubing anchor 100, the sucker rod pump P is connected to a sucker rod string R extending through the production tubing T from the pump jack 10 at the surface. Reciprocation of the string R axially reciprocates the pump P to transport fluids from the formation through the production tubing T to the surface. Further downhole, the sucker rod pump P may have a perforated sub 70 and a bull plug. Desander injection ports can be used in this bottom sub 70 to control sand.
During production, hydrocarbons produced from the formation are lifted up to wellhead 13 through the interior of the production tubing T. As discussed above, it may be desirable to deal with detrimental materials, such as water, paraffin, salt and H2S from the wellbore or to deal with other production issues by pumping chemicals into the wellbore. To deliver the chemicals downhole to the pump P, a capillary string S connected to an injection source (not shown) at the surface passes through the wellhead 13 and is disposed on the exterior of production tubing T. An injection valve 80 on the distal end of the capillary string S can then be used to deliver injected chemicals to a targeted location in wellbore downhole of the anchor 100 and preferably adjacent the rod pump P, sub 70, etc.
Passing along the production tubing T, the capillary string S or a section thereof passes through the tubing anchor 100. In other words, the capillary string S extends from the wellhead 13, along the production tubing T, through the tubing anchor 100, and to the bottom end of the last section of production tubing T where the capillary string S connects to the injection valve 80. Along the tubing T, the capillary string S is preferably banded or otherwise fastened to the exterior of the production tubing T. Even below the tubing anchor 100, the capillary string S is preferably banded to the production tubing T.
Preferably, an upper section of the capillary string S connects to a section of capillary tubing 140 that has already been placed through the tubing anchor 100. In this arrangement, this pre-placed section of capillary tubing 140 can be connected to the uphole section as well as to a downhole section of capillary string S using a swage lock (not shown).
The tubing anchor 100 can be located within 40 feet up to several hundred feet above the bottom end of the capillary string S where the injection valve 80 is located. For its part, the injection valve 80 is located proximate the perforated sub 70 so that chemicals delivered from the valve 80 can readily be circulated uphole through the rod pump P and tubing T. The valve 80 may also typically located proximate perforations in the casing C. This valve 80 can be a spring loaded chemical injection valve. To mitigate flow back uphole through capillary string S, it is preferable that the injection valve 80 uses a check valve to prevent flow uphole through capillary string S.
The tubing anchor 100 and capillary string S allow operators to treat paraffin, corrosion, and scale buildups. For example, the tubing anchor 100 lets operators inject foamers, inhibitors, and other chemicals with precision below the anchor 100. The anchor 100 is set above the pump P and works in conjunction with the capillary string S to provide a chemical delivery system. The anchor 100 can be used in various casing sizes (e.g., 4½-, 5½- and 7-in. casing).
As shown, the capillary injection system 60 illustrated in
As noted above, the tubing anchor 100 allows a section of capillary tubing 140 to pass through the anchor 100 so all of the communicated chemicals can be delivered where needed. As shown in
An outer housing 150 is positioned on the mandrel 110 and holds a number of drag blocks or springs 152 and holds a number of slips 153. The one or more drag blocks or springs 152 assist in holding the tubing anchor 100 in the production tubing T, and they may help to centralize the anchor 100. The slips 153 are used to engage the casing. Finally, the mandrel 110 has a cone 130 affixed thereon a distance from the slips 153. Various shear screws 132 can be used to hold the cone 130 in place and can be designed to shear free under a predetermined load.
As alluded to above, the outer housing 150 can move on the mandrel 110 to engage the slips 153 against the cone 130, which causes the slips 153 to grip against surrounding casing. Rather than moving through multiple rotations of the production tubing and mandrel 110, the outer housing 150 moves on the mandrel 110 using a J-slot arrangement discussed in more detail below. Setting the tubing anchor 100 requires a ¼ turn, and unsetting the anchor 100 requires pick up above a threshold.
Turning now to the particulars of the tubing anchor 100,
As before, the tubing anchor 100 has the mandrel 110, the supports 120a-b, the cone 130, and the outer housing 150. The mandrel 110 is a tubular component that couples to the tubing string with couplings 114 and 116. The supports 120a-b, the cone 130, and the outer housing 150 are all disposed externally on the mandrel 110.
The mandrel 110 defines an inner bore 112 for conducting production fluid and for passage of the sucker rod. Details of the mandrel 110 are shown in a first cross-sectional view, a second cross-sectional view, and an end view of
Externally, the mandrel 110 defines one or more J-slots 115a-b, slip slots 117, and a capillary groove 118 in the outer surface. As its name implies, the capillary groove 118 accommodates passage of the capillary string (140) or at least a segment thereof along an outside length of the mandrel 118. The groove 118, for example, may accommodate ¼″ or ⅜″ capillary injection tubing. In particular, the groove 118 on the mandrel 110 can accommodate two ¼-in. capillary lines together or can accommodate one ⅜-in. capillary line.
The J-slots 115a-b—two of which are shown in
Ride pins 155 (
As best shown in
The cone 130 is also a ring disposed on the mandrel 110 toward a downhole end. The cone 130 affixes to the mandrel 110 with temporary connections, such as shear screws 132 or the like, in holes (113:
The housing 150 is a cylindrical sleeve or the like disposed on the mandrel 110 about the capillary groove 118. Details of the outer housing 150 are shown in the cross-sectional view and the end view of
The downhole end of the housing 150 holds a slip holder 154 having a plurality of slips 153. Details of the slip holder 154 are shown in the cross-sectional view and the end view of
As best shown in
The tubing anchor 100 is a tension set anchor and is set with a ¼ turn to the left. This may equate to about 2 turns of the production tubing T at the surface to make the ¼ turn at the anchor 100. The anchor 100 has a safety release built into the cone 130. The safety release is field adjustable in 5000 lbf increments up to 55000 lbf using shear screws 132. The anchor 100 with its J-slots 115a-b also has an auto “J” when being released.
To install the tubing anchor 100, the capillary string S is banded to the production tubing T and is either feed through the anchor 100 or coupled to a section of tubing 140 on the anchor 100 as the case way be. Once ready, the anchor 100 is run to the setting depth. The stretch on the tubing T may be about +/−1.3 Ft per 1000′. Once at setting depth, operators pick up on the tubing T and hold left hand torque into the tubing T.
Operators then rotate ¼ turn to the left at the packer. While still pulling up, operators release the left hand torque once the ¼ turn has been made. Finally, operators continue picking up until there is at least 15000 lbf of tension in the anchor 100 at which point the tubing T can be landed in tension from the wellhead 13 using slip anchors, tubing hanger, or other wellhead component. In general, the anchor 100 is landed with at least 15000 lbf of tension.
As noted above, the ride pins 155 (
As also noted above, the ride pins 158 (
As can be seen by the installation process and the function of the ride pins 155 in the J-slots 115a-b, setting of the disclosed anchor 100 requires only moving the production tubing T a ¼ turn and axially to activate. The outer housing 150 does not turn with the tubing T and the mandrel 110.
There is a field adjustable safety release built into the anchor 100. For example, the cone 130 can accommodate up to 11 shear screws 132, with a shear value of 5000 lbf per screw 132. To actually unset the tubing anchor 100, operators set down on the anchor 100 with about 18-24″ of tubing T. Operators then pull up on the anchor 100.
As the tubing T is pulled up, it is rotated a ¼ turn back to the right. Operators continue to pull up on the tubing T until the shear screws 132 on the cone 130 yield. This allows the cone 130 to fall away from the slips 153 to unset the anchor 100. As can be seen, the disclosed anchor 100 operates as an anchor only and not as an anchor and a catcher. In this sense, the disclosed anchor 100 can be set and released, but the disclosed anchor 100 is not intended to catch in the casing C.
The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.
In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.
This application claims the benefit of U.S. Prov. Appl. 61/810,583, filed 10 Apr. 2013, which is incorporated herein by reference in its entirety.
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| Entry |
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| Number | Date | Country | |
|---|---|---|---|
| 20140305633 A1 | Oct 2014 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61810583 | Apr 2013 | US |
