None.
This invention relates to down hole rod pumps that are typically used to pump liquids from the bottom of a hydrocarbon wells.
As one travels through Texas and Oklahoma and other oil producing regions, it is common to see oil wells with rocking beam pumps in action. The beam is rocked like a seesaw by a motor while one end the beam lifts and lowers a sucker rod string to drive a pump positioned at or neat the bottom of the well. The sucker rod string is typically made up of a number of twenty-five foot to thirty foot steel rod sections connected end to end to form a long string of rods that extend down into the production tubing of a well. The production tubing itself was inserted into the wellbore after the wellbore was drilled and cased. The production tubing is fixed in the wellbore with a down hole rod pump positioned near the bottom. As the sucker rod moves up and down in the production tubing, the pump draws liquids from the wellbore into a chamber of the pump through a first check valve during a first stroke and then pushes the liquids in the chamber through a second check valve during the return stroke. The liquids pass through the second check valve and into the production tubing above the pump so that the liquids are eventually pumped to the surface and are either piped or trucked to market.
Natural gas wells and many low rate oil wells are sometimes provided with pumps to periodically withdraw liquids that enter the wellbore from the formation and tend to accumulate and slowly and eventually stop the production of hydrocarbons the natural gas. The liquid may be water, but may also include hydrocarbon liquids which are sufficiently valuable to collect and transport to market.
One of the problems associated with pump systems for small volumes of liquids in wells is that any solids, particularly fines and small particles, that are produced tend to collect and cause trouble for the pump. If the liquid volume were substantially higher, the particles would likely be carried to the surface and not collect at the bottom of the production tubing. With low liquid production rates and intermittent pumping, the particles tend to collect in the production tubing on top of the pump and have been known to damage the pumps and pumping systems well short of their expected service life. This can be especially challenging in coal seam gas production wells where the particles tend to be very fine and abrasive and are susceptible of stacking out rod strings by caking up and packing between plungers and barrels and blocking the travel of check valves and other vital pumping equipment. Coal seam gas wells typically produce water along with highly abrasive coal fines.
Many other wells produce sand which is a problem on a much larger scale in terms of total numbers of pumps exposed to particles. Some wells have sand delivered into the formation to hold open the fissures, fractures and perforations to enhance production of gas and liquids. This kind of sand is called proppant. Unfortunately such proppant sand causes many rod pump failures every year as some amounts exit the formation and creates hazard for moving equipment such as the pump in the wellbore. Another type of sand that is even more difficult for pumps to handle is formation sand, often referred to as flour sand. Formation sand is quite fine in nature and very difficult to control due to its fine size and mobility. It is highly abrasive and will wear out the polished surfaces of a pump or bury and stack out the pump.
The invention relates to a system for producing gas and liquids from a well where a pump is positioned at or near the bottom of the well and three conduits are arranged to extend into the well from the surface down near the bottom of the well. The first of the three conduits produces gas to the surface and the second of the three conduits is connected to the pump to produce liquids to the surface. The third of the three conduits provides a path for liquid to be delivered to the area of the pump.
In another aspect, the invention more particularly includes a system for producing liquids and solids from the bottom of a hydrocarbon well where the system includes a string of production conduit installed in a wellbore where a lower end thereof is near the bottom of the well and where the production conduit defines a gas production path to the surface on one side and an access conduit on the other. A pump including a barrel and a plunger wherein is positioned at the lower end of the production conduit and a string of hollow rod is disposed within the production conduit such that a tubing annulus is formed around the hollow rod string and where the hollow rod string is connected to the plunger that is positioned within the barrel of the pump for movement up and down within the barrel. The production tubing further includes at least one port for delivering liquid from the tubing annulus to the gas production annulus.
The invention also relates to a process for producing liquids and solids from the bottom of a natural gas well where an open ended string of production conduit is installed into a wellbore with a seating nipple near the open lower end of the production conduit to define a gas annulus outside of the production conduit and within the well. A pump is installed at the end of a string of hollow rod where the pump includes a barrel and a hollow plunger and where the hollow plunger is connected to and in fluid communication with the hollow rod string and further includes a traveling valve to admit liquids into the hollow interior of the plunger and wherein the barrel includes a standing valve to admit liquids from below the seating nipple into the barrel. The barrel is connected to the seating nipple and seals the interior of the production tubing from the open lower end of the production tubing wherein a tubing annulus is defined within the production tubing above the seating nipple and outside the hollow rod string. Substantially particle free liquid is provided into the tubing annulus to be in contact with the barrel and the outside of the plunger and to pass into the gas annulus to slurry solids and the plunger is raised and lowered to draw liquids through the standing valve and through the traveling valve and directing the liquids into the hollow rod string.
In particular aspects of the invention includes the capability to pump or inject clean liquid, chemically treated liquid, or hot liquid within the tubing annulus on top of the barrel and plunger and allow to exit said annulus anywhere up or down the wellbore.
The ball checks break the volume above the pump into segments to minimize the suspended solids in any one segment that can settle on top of any one ball check. The volume between these ball checks is sized so that expected pump cycle volume before pump off occurs is greater than the volume between the ball checks so that liquid and solids is advanced above the next ball check or more before the pump shuts down.
In a preferred arrangement, a portion of the liquids are produced through the hollow rod string are directed through a filter or settling tank system and then back into the tubing annulus.
The invention, together with further advantages thereof, may best be understood by reference to the following description taken in conjunction with the accompanying drawings in which:
Turning now to the preferred arrangement for the present invention, reference is made to the drawings to enable a more clear understanding of the invention. However, it is to be understood that the inventive features and concept may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
While the explanation of this invention will include the description of conventional components of a pump in a well, a key feature of the invention is the inclusion of an additional conduit that extends from the surface down the well to the vicinity of a pump at the bottom of the well. This additional conduit provides operators and well owners with access to the pump and to other locations down the wellbore to flush the well or provide important chemical treatments to the pump or to the well. Such access to the wellbore and to the pump should enable gas wells to be better maintained and problems to be resolved that are currently quite challenging. The additional conduit is shown in
Now turning to a more complete explanation of the full wellbore installation, in
The completion of a conventional gas well would include the insertion of a production string 150 that includes a seating nipple 152 for a pump 120 to be inserted. However, in the present invention, the pump 120 is inserted to the seating nipple using hollow rod string 125 with a plunger 130 arranged to deliver liquid contents into the interior of the hollow rod string 125. For comparison, please refer to
The pump is in the natural gas well to pump off, liquids that are produced from the formation with the natural gas. Liquids that accumulate in the well and tend to slow or block the production of the natural gas into the wellbore 10 or 110 so it is generally more productive to maintain the level of liquids below the lowest of the perforations 18 or 118. The liquid level is drawn down by the pump 20 or 120 from the bottom end of the production tubing 50 or 150, called a quiet zone 53 or 153 below the pump 20 or 120 and the seating nipple 52 or 152.
The pump 20 or 120 includes a plunger 30 or 130 arranged to move up and down within the barrel 40 or 140. The plunger 30 or 130 is attached to the bottom end of a hollow rod string 22 and is able to move up and down within the barrel 40 or 140 that is firmly connected or locked into the seating nipple 52 or 152, but it should be understood that the periphery of the plunger 30 or 130 and the interior of the barrel 40 or 140 are each machined and sized so that any liquid flow around the plunger 30 or 130 is substantially restricted. The preferred path for liquids to travel through the barrel 40 or 140 is also through the interior of the plunger 30 or 130. Below the barrel 40 or 140 is a strainer nipple 42 or 142 having a number of holes to allow liquids or gas that is in the quiet zone 53 or 153 to pass into the barrel through stranding valve 44 or 144. Standing valve 44 or 144 is shown to be a ball and seat, but may be any suitable one-way valve technology. As the plunger 30 or 130 is lifted relative to the barrel 40 or 140, liquids are drawn up through the strainer nipple 42 or 142 and through standing valve 44 or 144 to fill the space in the barrel 40 or 140 below the plunger 30 or 130. The plunger 30130 includes a travelling valve 34 or 134, that like the standing valve 44 or 144, is shown as a ball and seat, but may be any suitable one-way valve technology. As the plunger 30 or 130 is lowered in the barrel 40 or 140, standing valve 44 or 144 closes to keep liquid in the barrel but unseat the travelling valve 34 or 134 so that the liquids in the barrel below the plunger 30 or 130 would enter and flow into the plunger 30 or 130. Liquids that were already in the plunger 30 or 130 before the plunger began its downward movement in the barrel exit the top of the plunger 30 or 130. In
In
In operation, gas wells often produce sand and other particles that can accumulate at the bottom of the wellbore and cause considerable problems with the pump and interfering with the flow of the liquids into the quiet zone 53 or 153. The liquid flow rates into gas wells is a relative trickle, and as such, the pump 20 or 120 is expected to operate intermittently to lift liquids out of the bottom of the wellbore 10 or 110. At the same time, the liquid flow rates are so slow as to allow the solids to settle at the bottom of the well. The excessive collection of solids, especially particles and fines, are a likely cause of pump failure in a well and can plug off the gas annulus 19 or 119 from the quiescent zone 53 or 153. Using the additional access to the pump area via the tubing annulus 160, a rush of particle free liquid may be flushed from the surface and progress rapidly to the bottom of the well to jet through ports 154 and into the gas annulus 119. The jet of such liquids are intended to stir the solids in the bottom of the wellbore to effectively create a slurry of liquids and suspended particles and fines for removing from the well via the pump 120 and liquid production path 155. The liquids may also scrub the surrounding area to dislodge particles and debris from inside the gas annulus. In some cases, fungus and bacteria may grow inside the well and biocides may be includes with the liquids. The jetting action and other liquid scrubbing effects of the rush of liquid may aid the effectiveness of the biocides. Also, some wells produce waxes and paraffins that may also plug up the production of either or both liquids and gas. Heated liquids and solvents may be added to the liquids to help remove and carry away the waxes and paraffins with the slurry being pumped through the liquid production path 155.
In prior art arrangements such as shown in
To alleviate these and other problems identified in the embodiment of
Focusing on the differences between the invention and the embodiment in
Turning now to
In wells that produce problematic volumes of solids, the solids will tend to settle to the bottom of the hole and even begin to fill the gas annulus 119 while the pump 120 is not in operation. To flush these solids, just prior to initiation of the pump cycle, some of the liquid in tank 185b is delivered into the tubing annulus 160 to pass to the bottom thereof and pass through ports 154. Preferably, a significant volume of liquids are directed into the tubing annulus 160 to blow through the ports 154 with force to stir the solids and create a large volume of a slurry comprised of a lot of fluid and fine and small sized particles. What the inventor has noticed is that once enough liquid has entered the tubing annulus 160 that the weight of the liquid has exceeded the gas pressure, the liquid then siphons more and more liquid into the tubing annulus 160. Preferably, only an amount of liquid that can be pumped by the pump 120 in a reasonable period of time, such as one hour, is allowed into the tubing annulus. Gas from the gas annulus is allowed to fill the tubing annulus 160 behind or above the added liquids. With the liquid flushing and treating the wellbore, the slurry is then drawn into the pump 120 through the strainer nipple 142 and through the standing valve 144 as described above. The pump 120 continues to pump as liquid is continually delivered to tubing annulus 160 until the solids content of the liquid has satisfactorily diminished or until the volume of clean liquid in tank 185b is depleted. The advantage of delivering clean fluid down the tubing annulus 160 is that it remains clean all the way to the ports 154 and thereby prevents the high solids slurry from vulnerable locations inside the barrel 140 near the top of the plunger 130.
Thus, the plunger 130 has clean liquid around the outside thereof and to the extent that any filtered liquid might pass along the small gap around the outside of the plunger 130 and within the barrel 140, it would tend to sweep any particles in that gap back into a location where such particles are directed up into production path 155.
At the end of the pump operation cycle, it is preferred that the plunger 130 is in the “up” position so that if gas had entered the space below the bottom of plunger 130 and above standing valve 144 that some amount of filtered liquid in the barrel 140 would pass through the small gap during the idle time and occupy enough space to unseat the traveling valve 134 before the plunger reaches it full bottom stroke. As long as the travelling valve 134 can be unseated, the gas will quickly pass into the plunger and the gas lock condition will be alleviated without having to undertake substantial intervention. In an alternative embodiment, double standing and double travelling valves may be preferred where fluid travels through a first of the double valves and then through the second. A double valve arrangement provides redundancy in the event that solid particles block open one of the valves. It is preferred that once the liquid at the bottom of the wellbore 110 is depleted that the pump be stopped. With minimal liquid volumes to be pumped, the velocity of the liquids in liquid production path 155 tends to diminish below the speed which fully entrains the solids. As emphasized above, it is highly desirable to produce the fines and particles to the surface. It is generally seen that vertical velocities of about one half of one foot per second or greater (≧0.5 fps) is sufficient to entrain most solids.
In the preferred operation of the well, the pump is stopped in the “up” position until a pump cycle is ready to be undertaken (whether due to elapsed time, reduced gas production or by initiation of an operator at the surface, etc.) a volume of clean liquid is delivered to the tubing annulus 160 from the tank 185b. The pump area of the well is flushed with the liquids stirring up fines and particles while accomplishing any other intended treatments at the bottom or at other locations at predetermined locations higher in the well. With the fines and particles having been stirred into the liquid, the pump 120 is started and begins its operation of up and down movements to pump the slurry or liquid with suspended fines and particles to the surface. The slurry progresses up the interior of the hollow rod string 125 along the liquid production path 155 at a velocity that will re-entrain fines and particles that have settled out of the liquid from the previous pump cycle back into the liquid to be carried to the surface. The fines that had settled out should have only settled on the top of the last check valve that the slurry passed before the pump shut down at the end of the previous pump cycle. Once the liquid level has been pump down, conventional pump-off control technology detects that the liquid level has diminished and preferably shuts down the pump and ends the pump cycle. With a substantial volume of liquid delivered to the tubing annulus, all of the liquid and solids in the liquid production path is preferably completely produced to the surface along with a substantial portion of newly added liquid. However, some operational schemes may not include a great amount of new liquid so the spacing of the check valves 145 may be more important ins some wells so that any fines that enter the interior of the hollow rod string 125 progress beyond at least one additional check valve at each pump cycle including the recognition that such fines will need to be re-entrained at the start of each pump cycle and therefore on top of a check valve and must flow all the way beyond the next check valve to eventually make it fully to the surface. Such calculations to making sure that solids progress is to space the check valves at a distance that is less than the minimum volume of liquid expected to be pumped for each pump cycle. A reasonable margin of error may be to space the check valves at one barrel distances (depending on the diameter of the hollow rod, about 1000 feet) or at one half barrel distances if the minimum expected volume will be 1 or 2 barrels.
While abrasion and wear are the primary concern of the inventor, another aspect of the present invention that may help avoid gas locks is to provide a vent 158 to allow any gas that has entered the quiet zone 153 such as gases dissolved from the hydrocarbon liquid to pass back into the annulus 119 and exit the well 10. The vent 158 is above the highest opening in the strainer nipple 142 so that the liquid level inside the quiet zone 153 is not lower than the liquid level outside the quiet zone in the annulus 119. Another strategy to alleviate gas lock is to increase the fluid slippage past the plunger/barrel interface from annulus 160 into barrel 140 to displace traveling valve 134 and push gas into flow path 155.
Chemical treatments such as a scale, corrosion or paraffin inhibitor may be added into production tubing 150 or into the tubing annulus 160. It should be noted that even hot liquid such as hot water or oil may be added to tubing 150 to enhance production by softening paraffins. The tubing annulus 160 provides many new options for addressing a near endless list of challenges in the oil field.
In one further preferred aspect related to
While it should be understood that the invention introduces two tubing strings which enables operators of wells to control the operating environment of the pump 120. The invention provides a way to flush water or other liquid to the pump from above through the tubing annulus 155.
Turning to
One interesting aspect of this arrangement is that with the liquids coming to the surface within a hollow rod string, the liquids exit the well pumping system on the “downstroke” of the rod pump. In conventional rod pumps, the liquid production occurs on the “upstroke.” This point may not seem significant, but it does reveal that the present invention is quite different than prior systems.
Finally, the scope of protection for this invention is not limited by the description set out above, but is only limited by the claims which follow. That scope of the invention is intended to include all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are part of the description and are a further description and are in addition to the preferred embodiments of the present invention. The discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application.
This application is a continuation-in-part patent application which claims benefit under 35 USC §120 to U.S. patent application Ser. No. 12/895,019 filed Sep. 30, 2010, entitled “Double String Pump for Hydrocarbon Wells,” which is incorporated herein in its entirety.
Number | Date | Country | |
---|---|---|---|
Parent | 12895019 | Sep 2010 | US |
Child | 13076064 | US |