Patent Publication Number: US-6209637-B1

Title: Plunger lift with multipart piston and method of using the same

Description:
This invention relates to a plunger lift system for moving liquids upwardly in a petroleum well. 
     BACKGROUND OF THE INVENTION 
     There are many different techniques for artificially lifting formation liquids from hydrocarbon wells. Reciprocating sucker rod pumps are the most commonly used in the oil field because they are the most cost effective, all things considered, over a wide variety of applications. Other types of artificial lift include electrically driven down hole pumps, hydraulic pumps, rotating rod pumps, free pistons or plunger lifts and several varieties of gas lift. These alternate types of artificial lift are more cost effective than sucker rod pumps in the niches or applications where they have become popular. 
     One of the developments that has evolved over the last thirty years are so-called tubingless completions in which a string of tubing, usually 2⅞″ O.D., is cemented in the well bore and then used as the production string. Tubingless completions are never adopted where pumping a well is initially considered likely because sucker rod pumps have proved to be only slightly less than a disaster when used in a 2⅞″ tubingless completions. Artificial lift in a 2⅞″ tubingless completion is almost universally limited to gas lift or free pistons. Thus, tubingless completions are typically used in shallow to moderately deep wells that are believed, at the time a completion decision is made, to produce all or mostly gas, i.e. no more liquid than can be produced along with the gas. 
     Gas wells reach their economic limit for a variety of reasons. A very common reason is the gas production declines to a point where the formation liquids are not readily moved up the production string to the surface. Two phase upward flow in a well is a complicated affair and most engineering equations thought to predict flow are only rough estimates of what is actually occurring. One reason is the changing relation of the liquid and of the gas flowing upwardly in the well. At times of more-or-less constant flow, the liquid acts as an upwardly moving film on the inside of the flow string while the gas flows in a central path on the inside of the liquid film. The gas flows much faster than the liquid film. When the volume of gas flow slows down below some critical value, or stops, the liquid runs down the inside of the flow string and accumulates in the bottom of the well. 
     If sufficient liquid accumulates in the bottom of the well, the well is no longer able to flow because the pressure in the reservoir is not able to start flowing against the pressure of the liquid column. The well is said to have loaded up and died. Years ago, gas wells were plugged much quicker than today because it was not economic to artificially lift small quantities of liquid from a gas well. At relatively high gas prices, it is economic to keep old gas wells on production. It has gradually been realized that gas wells have a life cycle that includes an old age segment where a variety of techniques are used to keep liquids flowing upwardly in the well and thereby prevent the well from loading up and dying. 
     There are many techniques for keeping old gas wells flowing and the appropriate one depends on where the well is in its life cycle. For example, the first technique is to drop soap sticks into the well. The soap sticks and some agitation cause the liquids to foam. The well is then turned to the atmosphere and a great deal of foamed liquid is discharged from the well. Later in its life cycle, when soaping the well has become much less effective, a string of 1″ or 1½″ tubing is run inside the production string. The idea is that the upward velocity in the small tubing string is much higher which keeps the liquid moving upwardly in the well to the surface. A rule of thumb is that wells producing enough gas to have an upward velocity in excess of 10′/second will stay unloaded. Wells where the upward velocity is less than 5′/second will always load up and die. 
     At some stage in the life of a gas well, these techniques no longer work and the only approach left to keep the well on production is to artificially lift the liquid with a pump of some description. The logical and time tested technique is to pump the accumulated liquid up the tubing string with a sucker rod pump and allow produced gas to flow up the annulus between the tubing string and the casing string. This is normally not practical in a 2⅞″ tubingless completion unless one tries to use hollow rods and pump up the rods, which normally doesn&#39;t work very well or very long. Even then, it is not long before the rods cut a hole in the 2⅞″ string and the well is lost. In addition, sucker rod pumps require a large initial capital outlay and either require electrical service or elaborate equipment to restart the engine. 
     Free pistons or plunger lifts are another common type of artificial pumping system to raise liquid from a well that produces a substantial quantity of gas. Conventional plunger lift systems comprise a piston that is dropped into the well by stopping upward flow in the well, as by closing the wing valve on the well head. The piston is often called a free piston because it is not attached to a sucker rod string or other mechanism to pull the piston to the surface. When the piston reaches the bottom of the well, it falls into the liquid in the bottom of the well and ultimately into contact with a bumper spring, normally seated in a collar or resting on a collar stop. The wing valve is opened and gas flowing into the well pushes the piston upwardly toward the surface, pushing liquid on top of the piston to the surface. Although plunger lifts are commonly used devices, there is more art than science to their operation. 
     A major disadvantage of conventional plunger lifts is the well must be shut in so the piston is able to fall to the bottom of the well. Because wells in need of artificial lifting are susceptible to being easily killed, stopping flow in the well has a number of serious effects. Most importantly, the liquid on the inside of the production string falls to the bottom of the well, or is pushed downwardly by the falling piston. This is manifestly the last thing that is desired because it is the reason that wells die. In response to the desire to keep the well flowing when a plunger lift piston is dropped into the well, attempts have been made to provide valved bypasses through the piston which open and close at appropriate times. Such devices are to date quite intricate and these attempts have so far failed to gain wide acceptance. 
     Disclosures of some interest relative to this invention are U.S. Pat. Nos. 2,074,912 and 3,090,316. 
     SUMMARY OF THE INVENTION 
     In this invention, a multipart piston includes separate pieces that are independently allowed to fall inside the production string toward the productive formation. The cross-sectional area of the separate pieces are such that upward flow of gas is substantially unimpeded and the pieces fall through an upwardly moving stream of gas and liquid. Thus, the piston of this invention is normally dropped into a well while it is flowing. This has a great advantage because the liquid in a film on the inside of the production string does not fall into the bottom of the well. 
     When the lower piece nears the bottom of the well, it falls into any liquid near the bottom of the well and contacts a bumper spring which cushions the impact of the device. When the upper piece reaches the lower piece, they unite into a single component that has a cross-sectional area comparable to existing plunger lift pistons, i.e. any gas entering the production string from the formation is under the piston and pushes it upwardly, thereby pushing any liquid upwardly in the well to the surface. 
     Preferably, one of the pieces is a sleeve having a central passage through which the gas flows as the sleeve falls in the well. The other piece is preferably a mandrel having a pin that fits into the sleeve and substantially blocks flow in the central passage when the pieces are united. The flow passage around the mandrel is basically on the outside as the it falls in the well. The mandrel provides one or more centralizers which hold the pin in the center of the production string to align with the central passage of the sleeve. 
     When the united components reach the well head at the surface, a decoupler separates the sleeve from the mandrel and allows the mandrel to fall toward the bottom of the well. Conveniently, a catcher holds the sleeve and then releases the sleeve after the mandrel is already on the way to the bottom. 
     A bypass for produced formation products is conveniently provided in the well head to insure that the sleeve and mandrel separate. 
     It is an object of this invention to provide an improved plunger lift and method of using the same. 
     A more specific object of this invention is to provide a multipart piston for a plunger lift in which sections of the piston move separately down into the well, unite near the bottom of the well and then move upwardly as a unit to move liquids toward the surface. 
     These and other objects of this invention will become more fully apparent as this description proceeds, reference being made to the accompanying drawings and appended claims. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a schematic view of a well equipped with a plunger lift system of this invention; 
     FIG. 2 is an exploded vertical cross-sectional view of the piston of this invention, showing the sleeve and mandrel; 
     FIG. 3 is a bottom view of the mandrel; 
     FIG. 4 is a top view of the mandrel; 
     FIG. 5 is a broken isometric view of the sleeve; 
     FIG. 6 is an isometric view of the mandrel, the top of the mandrel being broken away from the bottom for purposes of illustration; 
     FIG. 7 is a broken isometric view of the bottom of the mandrel, taken at 45° relative to FIG. 6; 
     FIG. 8 is a horizontal cross-sectional view of FIG. 6, taken substantially along line  8 — 8  thereof, as viewed in the direction indicated by the arrows; and 
     FIG. 9 is a vertical cross-sectional view of the lower end of the mandrel of FIG.  6 . 
    
    
     DETAILED DESCRIPTION 
     Referring to FIGS. 1-9, a hydrocarbon well  10  comprises a production string  12  extending into the earth in communication with a subterranean hydrocarbon bearing formation  14 . The production string  12  is typically a conventional tubing string made up of joints of tubing that are threaded together. Although the production string  12  may be inside a casing string (not shown), it is illustrated as cemented in the earth. The formation  14  communicates with the inside of the production string  12  through perforations  16 . As will be more fully apparent hereinafter, the plunger lift  18  may be used to lift oil, condensate or water from the bottom of the well  10  which may be classified as either an oil well or a gas well. 
     In a typical application of this invention, the well  10  is a gas well that produces some formation liquid. In an earlier stage of the productive life of the well  10 , there is sufficient gas being produced to deliver the formation liquids to the surface. The well  10  is equipped with a conventional well head assembly  20  comprising a pair of master valves  22  and a wing valve  24  delivering produced formation products to a surface facility for separating, measuring and treating the produced products. 
     The plunger lift  18  of this invention comprises, as major components, a piston  26 , an upper bumper  28 , a decoupler  30 , a catcher assembly  32 , a lower bumper  34  and a bypass  36  around the piston  26  when it is its uppermost position in the well head assembly  20 . 
     The piston  26  is of unusual design and is made in at least two pieces which, in a preferred embodiment of the invention, comprises an upper sleeve  38  and a lower mandrel  40 . The sleeve  38  comprises a tubular body  42  having a central passage  44 , a fishing neck  46  at the upper end thereof and a sealing surface  48  at the lower end thereof. 
     The exterior of the sleeve  38  provides a seal arrangement  50  to minimize liquid on the outside of the sleeve  38  from bypassing around the exterior of the sleeve  38 . The seal arrangement  50  may be of any suitable type, such as wire wound around the sleeve  38  providing a multiplicity of bristles or the like or may comprise a series of simple grooves or indentations  52 . The grooves  52  work because they create a turbulent zone between the sleeve  38  and the inside of the production string  12  thereby restricting liquid flow on the outside of the sleeve  38 . 
     The mandrel  40  is of more complex configuration and comprises a body  54  having a robust lower end  56  which takes repeated impacts against the lower bumper, a first centralizer section  58  providing a series of outwardly extending arms  60  and a second centralizer section  62  providing a series of outwardly extending arms  64 . The arms  60  are preferably 90° out of phase with the arms  64  so the centralizer sections  58 ,  62  orient the axis  66  of the mandrel  40  substantially coincident with the axis of the sleeve  38  and of the production string  12 . The arms  60 ,  64  preferably have the same outer dimension as the sleeve  38 . 
     Above the centralizer section  62  is a circular plate  68  having a series of peripheral slots  70  providing a flow bypass between the centralizer arms  64 . Above the plate  68  is a pin  72  which extends into the sleeve  38  and provides a frustoconical sealing surface  74 , a snap ring groove  76  and a pair of fishing grooves  78 . The pin  72  is substantially shorter than the sleeve  38  so, in the upwardly moving or nested position of the piston  26 , the pin  72  terminates below the fishing neck  46  of the sleeve  38 . 
     A sealing member  80  slips over the pin  72  and fits onto the sealing surface  74  of the mandrel  40 . A washer  81  may be provided above the sealing member  80  for abutting a snap ring (not shown) which fits in the groove  76  and holds the sealing member  80  in position. When the mandrel  40  nests inside the sleeve  38 , the sealing member  80  seals against the sealing surface  48 . The sealing member  80  may be of any suitable type and is shown as a Harbison-Fisher nylon seal ring, model 80-190H-10, 1¾″ HR pump seal. 
     As will be more fully apparent hereinafter, the mandrel  40  is first dropped into the well  10 , followed by the sleeve  38 . The mandrel  40  and sleeve  38  accordingly fall separately and independently into the well  10 , usually while the well  10  is producing gas and liquid up the production string  12  and through the well head assembly  20 . By separately, it is meant that the mandrel  40  and sleeve  38  are not connected. By independently, it is meant that the mandrel  48  and sleeve  38  are capable of moving independently of one another even if they are tethered together in some fashion. When the mandrel  40  and sleeve  38  reach the bottom of the well, they nest together in preparation for moving upwardly. 
     In one aspect, the sleeve  38  and mandrel  40  each have a flow bypass so they separately fall easily into the well  10  even when there is substantial upward flow in the production string  12 . When they reach the bottom of the well, they unite into a single component which substantially closes the flow bypasses, or at least restricts them, so gas entering through the perforations  16  pushes the piston  26  upwardly in the well and thereby pushes liquid, above the piston  26 , upwardly toward the well head assembly  20 . 
     Looked at in another perspective, the sleeve  38  and mandrel  40  each have a surface area which is selected so that they separately fall easily in the well but, when they are united into the piston  26 , the piston  26  is pushed upwardly in the well thereby pushing any liquid upwardly toward the well head assembly  20 . The selection of the surface areas of the sleeve  38  and mandrel  40  is preferably done so that a given pressure differential will move the mandrel  40  before moving the sleeve  38 . In other words, the mandrel  40  is easier to move than the sleeve  38 . The reason is that is if the mandrel  40  can be constructed so it always pushes from below, there is no tendency for the sleeve  38  to separate from the mandrel  40  during upward movement in the well  10 . 
     This may be illustrated in the following example. A standard size 2⅞″ tubing used as a production string weighs 6.5 #/foot and has a nominal internal diameter of 2.441″ which, of course, is not perfect and which is interrupted in an assembled string by a gap in the coupling of adjacent joints. A conventional one piece plunger lift has an O.D. of about 2.330″ and can successfully lift liquid from the bottom of a well. A piston  26  of this invention may have a sleeve  38  with an O.D. of 2.330″ and an I.D. of 1.750″ so the downwardly facing area of the sleeve  30  is approximately 1.857 square inches. A mandrel  40  for such a sleeve will have a plate  68  of an O.D. of 2.125″ and its surface area is somewhat less than 3.547 square inches because of the slots  70 . When the sleeve  38  is nested onto the mandrel  40 , the O.D. of the sleeve  38  is slightly larger than the plate  68  as suggested by the dashed lines in FIG.  4 . It will be seen that the area of the mandrel  40  is larger than the area of the sleeve  38  so that any pressure drop applies a greater force to the mandrel  40  than to the sleeve  38 . In addition, the ratio of surface area to weight of the mandrel  40  is greater than the ratio of surface area to weight of the sleeve  38 . 
     The upper bumper  28  is of conventional design and comprises a helical spring. Bumpers of this type are well known in the plunger lift art and are commercially available. 
     The lower bumper  34  sits, or is part of, a conventional collar stop  82  that is supported in the gap provided by couplings between adjacent joints of the production string  12 . In a well (not shown) having a tubing string inside a casing string cemented in the earth, the lower bumper  34  typically sits in a seating nipple (not shown) in the tubing string. The lower bumper  34  includes a body  84 , a relatively long spring  86  and an anvil  88  providing a conventional fishing neck  90 . Because the mandrel  40  falls into the bottom of the well  10  when it is flowing, there is little or no liquid accumulated adjacent the formation  14 . Thus, the mandrel  40  tends to strike the lower bumper  34  at higher velocities than conventional plunger pistons. For this reason, a longer, softer bumper spring is desired. 
     The decoupler  30  acts to separate the piston  26  when it reaches the well head assembly  20 . The decoupler  30  comprises a rod  92  sized to pass into the top of the sleeve  38  and is fixed to a piston  94 . The piston  94  is larger than a conduit  96  in which the rod  92  reciprocates and is thus prevented from falling into the well  10 . The top of the well head assembly  20  is closed with a screw cap  98 . A stop  100  on the rod  92  limits upward movement of the sleeve  38 . A series of grooves  101 , similar to the grooves  70 , allow formation products to pass around the stop  100  and into a flow line  102  connected to the wing valve  24 . It will be seen that the piston  26  moves upwardly in the well  10  as one piece. When the sleeve  38  passes onto the end of the rod  92 , the rod  92  ultimately contacts the top of the pin  72 , stopping upward movement of the mandrel  40  and allowing continued upward movement of the sleeve  38 . The end of the rod  92 , below the stop  100 , is longer than the pin  72  so the mandrel  40  is pushed out of the sleeve  38  thereby releasing the mandrel  40  which falls toward the bottom of the well  10 . 
     The bypass  36  helps prevent the piston  26  from sticking in the well head assembly  20  and may include a valve  103 . The bypass  36  opens into the well head assembly  20  below the bottom of the sleeve  38  when it is in its uppermost position in the well head assembly  20 . Thus, there will be a tendency of gas flowing through the well head assembly  20  to move through the bypass  36  rather than pinning the sleeve  38  against the stop  100 . 
     A catcher  32  may be provided to latch onto the sleeve  38  and thereby hold it for a while to provide a delay period between successive cycles of the piston  26  and to make certain that the sleeve  38  and mandrel  40  fall separately toward the bottom of the well  10 . To these ends, the sleeve  38  is provided with an elongated groove  104  to receive a ball detent  106  forced inwardly into the path of the sleeve  38  by an air cylinder  108  connected to a supply of compressed gas (not shown) through a fitting  110 . A piston  112  in the cylinder  108  is biased by a spring  114  to a position releasing the ball detent  106  for movement out of engagement with the slot  104 . Pressure is normally applied to the cylinder  108  thereby forcing the ball detent  106  into the path of travel of the sleeve  38 . The exterior surfaces of the slot  104  are beveled to cam the ball detent  106  against the force of the compressed gas so the ball detent  106  passes into the slot  104  thereby latching onto the sleeve  38  when it is on the decoupler  30  and preventing it from falling immediately into the well  10 . Upon a signal from a controller (not shown), gas pressure is bled from the cylinder  108  allowing the spring  114  to retract the piston  112  and allowing the weight of the sleeve  38  to push the ball detent  106  out of the slot  104  thereby releasing the sleeve  38  for movement downwardly into the well  10 . 
     When it is desired to retrieve the mandrel  40  or the piston  26 , the decoupler  30  is replaced with a similar device having a stop  100  but eliminating the rod  92 . This causes the piston  26  to impact the bumper  28  without dislodging the mandrel  40 . The piston  26  is held in its upward position by the flow of formation products around the piston  26  in conjunction with the catcher  32  which latches onto the sleeve  38 . 
     Operation of the plunger lift  18  of this invention should now be apparent. The mandrel  40  is first dropped into the well  10 . It falls rapidly through a rising stream of produced products onto the bumper  34  which substantially cushions the impact and minimizes damage to the mandrel  40 . When the sleeve  38  is released by the catcher  32 , it falls through the well  10  to the bottom. Because the pin  72  of the mandrel  40  is aligned with the axis  66 , the sleeve  38  passes over the pin  72 , impacts the top of the plate  68  and seals against the sealing member  80 . The combined downwardly surface area of the sleeve  38  and mandrel  40 , in their united configuration, is sufficient to allow gaseous products from the formation  14  to push the piston  26 , and any liquid above it, upwardly to the well head assembly  20 . 
     As the piston  26  approaches the well head assembly  20 , a slug of liquid passes through the wing valve  24  into the flow line  102  toward a surface treatment facility. The sleeve  36  passes over the rod  92  which stops upward movement of the mandrel  40  thereby releasing the mandrel  40  which drops into the well  10  in the start of another cycle. The sleeve  38  is retained by the catcher  32  for a period of time depending on the requirements of the well  10 . If the well  10  needs to be cycled as often as possible, the delay provided by the catcher  30  is only long enough to be sure the mandrel  40  will reach the bottom of the well  10  before the sleeve  38 . In more normal situations, the sleeve  38  will be retained on the catcher  30  so the piston  26  cycles much less often. 
     A prototype of this invention has been tested. In a 6000′ gas well that loads up and dies with produced liquid, it took seven minutes for the mandrel and sleeve to fall separately to the bottom of the well through the upwardly moving column of gas and water, recombine and return to the surface with ¼ barrels of water. 
     Although this invention has been disclosed and described in its preferred forms with a certain degree of particularity, it is understood that the present disclosure of the preferred forms is only by way of example and that numerous changes in the details of construction and operation and in the combination and arrangement of parts may be resorted to without departing from the spirit and scope of the invention as hereinafter claimed.