CROSS-REFERENCE TO RELATED APPLICATIONS
This application claims the benefit of the filing of U.S. Provisional Paten Application Ser. No. 60/543,132, entitled “Down well Pneumatic Submersible Pump With Built-In Mechanical Pressure Amplifier And Pumping”, filed on Feb. 9, 2004, which is incorporated herein by reference.
The present invention relates generally to sub-surface fluid recovery pumping systems for natural gas “Stripper” or older production wells. More particularly, this invention is directed to a pneumatic displacement method of low volumes of well fluids from low pressure natural gas production wells. Specifically, this invention is directed to the provision of a method and apparatus for pneumatic displacement pumping, incorporating flexible metal continuous piping conveyance lines (e.g., unspoiled tubing), a low volume timer-less sub-surface pneumatic pump, and a compressed gas source that cooperates to cause the down-well pump to remove all types of well liquids entering an older natural gas production well.
A problem facing today's well operators of natural gas “Stripper” production wells is that the available pumping systems of today are costing more to operate and maintain than the benefit they provide. Recently the United States Department of the Interior gave “Stripper” well operators a royalty rate reduction to encourage operators not to abandon their non-profitable “Stripper” wells. The main reason for this situation is today's pumping systems were not designed for “Stripper” well conditions. That is low fluid volume recovery, low well pressure, and low production volume. The most popular and most available pumping system today is the “Rod Pump” or Pump Jack” type pumping system. This technology was originally design for high volume fluid removal in high volume production wells. Operators today have made many modifications to this equipment over the years to adapt to dwindling fluid recovery and dwindling production volumes. Even with the many modifications, the “Rod Pump” or Pump Jack” type pumping method is neither cost effective in its daily operations, nor its method of retrieval. Other significant problems facing the “Rod Pump” or Pump Jack” type pumping method is above ground air pollution, noise pollution, and visual pollution. All of these problems need to go away if “Stripper” wells are to be kept producing. Specifically, pumping systems which consume high quantities of an energy resource to operate, remove well fluids on an intermittent basis, and use rigid segment pipe as their fluid discharge pipe are no longer cost effective in the “Stripper” well industry. Finally, other “Rod Pump” problems include vapor locking of the pump, sucker rods wearing holes in the production piping, sucker rods getting stuck in the production piping all of which require a very expensive and time consuming work over rig to pull the rod pump out of the well.
When natural gas production wells begin to fill up with formation fluids such as brine water or crude oil distillates, the flow of natural gas diminishes. Some form of fluid removal on a daily basis is usually required on most natural gas production wells. When production well fluid removal volumes drop to a few barrels per day, the present most common “Rod Pump” or “Pump Jack” pumping systems have to revert to intermittent operation due to their high capacity pumping design. Intermittent recovery of production well fluids creates a substantial loss or complete stoppage of produced natural gas. U.S. Pat. Nos. 6,497,561 to Skillman, and 5,104,301 to Brewer each disclose rod pump type devices for recovering well fluids from a natural gas production well.
Another pumping method giving the “Stripper” well operators problems is the “plunger lift” pumping system. U.S. Pat. Nos. 6,467,541 to Wells and 4,211,279 to Isaacks each disclose “plunger lift” type devices for recovering well fluids from a natural gas production well. This pumping system has reduced above ground equipment and does not require an energy source for consumption to operate. However, it still recovers well fluid very intermittently and uses rigid pipe as its fluid recovery conduit. This pumping system also has a regular problem where the metal plunger gets stuck in the production piping requiring the piping to be pulled from the well.
Yet another method in fluid recovery of natural gas production wells utilizes a hydraulically driven down-well pump with an above ground electrical drive motor pumping system. U.S. Pat. Nos. 6,454,010 to Thomas et al is a good example of a pumping system that consumes the most expensive type of energy and requires an excessive amount materials for operations and servicing. High pressure hydraulic fluid flow is created from an above ground electrically driven pumping system that is used to power the sub-surface well fluids pumping system. This pumping system requires Electricity which is the most expensive energy resource available. Furthermore, Thomas et al invention is very high in material consumption due to its multiple down-well motors, pumps, piping conduits, and an above ground pumping system. This invention also exposes the production well to possible foreign hydraulic fluids when the system has a leak or breakage in its piping.
Still another method in fluid recovery of natural gas production wells is a down-well electrically driven pump. U.S. Pat. No. 6,550,535 to Traylor is a good example of an another pumping system that consumes the most expensive type of energy available and utilizes rigid piping for its discharge fluids conduit. Down well electrically driven pumps commonly require three phase electric power to lift water from production well depths. This source of power is very unpredictable in it delivery. It is common knowledge that one of the three phases are being dropped or lost on a regular basis. When this happens the electric motor in the down-well pump is damaged enough to require the pump to be removed and motor repaired.
What is needed is a way to remove liquid from a gas well that substantially overcomes the above problems.
In one implementation, an apparatus includes pneumatic means, down a well and driven by gas from the well, for driving hydraulic means, also down the well, for expelling liquid from the well. In this implementation, at least one of the pneumatic or hydraulic means can be in fluid communication with the surface of the gas well through tubing, such room temperature flexible tubing or unspooled tubing, etc.
In another implementation, a pneumatic pump in a gas well is driven by compressed gas from the gas well, and drives a hydraulic pump in the gas well to pump liquid from the gas well.
Compressed gas from the gas well can be used to drive the pneumatic means or pneumatic pump in the foregoing implementations, respectively.
In a still further implementation, gas pumped from the pneumatic means or pneumatic pump in the foregoing implementations, respectively, can be used to drive the hydraulic pump or hydraulic means, respectively, to pump liquid from the gas well.
In yet another implementation, liquid is removed from a gas well with a hydraulic pump by driving a hydraulic pump with the gas that is output by the pneumatic pump.
In any of the foregoing implementations, the pneumatic pump, the pneumatic means, the hydraulic pump, or the hydraulic means can be in fluid communication with a container to contain the conveyed fluid on the surface of the gas well through continuous tubing, such as unspooled tubing.
In a still further implementation, a well casing extends through a drilled bore in the earth to a natural gas bearing earth formation which well casing may be provided with a well head at its upper extremity and with a perforated element, typically referred to as a screen, at its lower extremity. Formation fluids, typically referred to as production fluid, may be forced by formation pressure, either induced naturally or artificially and may enter the well casing through the perforations of the screen and may rise to a level within the casing.
At the surface a natural gas compressor may be provided with an inlet conduit from the well head for flow of low pressure well gas to the compressor and an outlet conduit from the compressor for flow of high pressure well gas to a sales conduit and to the inlet of a surface chemical treatment apparatus. At the surface a flexible small diameter metal conduit may be provided from the outlet of the surface chemical treatment apparatus over to the well head and connected to the down-well gas supply conduit for flow of chemically treated high pressure well gas down to the sub-surface pump. At the surface a fluid discharge holding tank inlet is connected to the well head fluid discharge outlet for flowing sub-surface well fluids to an above ground tank.
In the well a first removably suspended flexible metal gas supply conduit may be provided with a load bearing and well head sealing adapter that is attached to the well head at the surface and a connecting adapter at the bottom below the production zone within the casing to connect to the gas inlet port of the pump. Also in the well a second removably suspended flexible metal fluid discharge conduit may be provided with a non load bearing and well head sealing adapter that is attached to the well head at the surface and a connecting adapter at the bottom below the production zone within the casing to connect to the fluid discharge port of the pump. Also, in the well a third removably suspended flexible metal exhaust gas conduit may be provided just above the fluid level in the well and at the bottom below the production zone within the casing to connect to the exhaust gas port of the pump.
All conduits may be provided a clamping apparatus to prevent conduit damage upon installation into the well casing.
A pneumatic pump provided within the well casing and located below the production zone includes a pneumatic switching valve with an inlet and several outlets for flowing treated high pressure well gas to the pneumatic piston chambers. A pneumatic pump chamber with two two-way flow passages for flowing treated high pressure well gas to the top and bottom sides of the pneumatic portion of the pump piston. A pump piston that transfers the treated high pressure well gas energy into a very high liquid discharge energy. A liquid pump chamber with a filtered inlet for flow of well fluid into the liquid pump chamber from the casing. A solids collection apparatus connected to the liquid pump chamber for preventing the plugging of the pump outlet. A first conduit that connects the gas supply inlet of the pump to the above ground gas compressor outlet. A second conduit that connects the outlet of the solids collection apparatus to the above ground fluid discharge collection tank. A third conduit that connects the gas exhaust outlet of the pump to a check valve positioned a few feet above the well casing fluid level.
BRIEF DESCRIPTION OF THE DRAWINGS
Advantageously, any of the foregoing implementation can be operated so as to avoid substantially consuming or destroying the well gas such that substantially only compressed energy within compressed well gas is consumed.
A more complete understanding of the implementations may be had by reference to the following detailed description when taken in conjunction with the accompanying drawings wherein:
FIG. 1 is a sectional view of a well casing extending through a well bore in the earth's surface to an natural gas bearing earth formation and also illustrating in simple mechanical terms the provision of a pneumatic displacement type pump mechanism constructed in accordance with an exemplary implementation within the casing structure in position for pumping production fluid from the well;
FIGS. 2-5 are respective elevation cross-sectional views of an exemplary implementation, where FIGS. 2 and 5 show a snap shot in a cycle in which liquid is being drawn from the well, and where FIGS. 3 and 4 show a snap shot in a cycle in which liquid is being expelled from the well.
Specific embodiments and variations of the invention will now be described. These embodiments are exemplary in nature, and not intended to limit the invention or its applications. For instance, while an application is discussed for fluid removal from a natural gas production well, implementations may also be utilized for displacement of other fluids that may or may not be located within the earth formation. Moreover, while an application is discussed for the removal of well fluids in a natural gas well with low fluid removal, it is in no way intended that such discussion will limit the invention solely to use in connection with fluid removal from an older or “Stripper” natural gas production well.
In various embodiments, a system and pumping technology provide pumping of very deep well fluids from the bottom of a natural gas production well. This system can include: a low pressure well gas coming out of well into an above ground gas compressor; high pressure well gas flowing from gas compressor to a first flexible continuous metal conduit; high pressure well gas flowing through a conduit down to inlet port of a pneumatic pump; high pressure well gas entering an internal logic switching valve which sends high pressure well gas into an internal mechanical amplifier piston chamber of the pneumatic pump; and a logic switching valve that exhausts low pressure compressed gas out through an exhaust port of the pneumatic pump back into well. A pneumatic mechanical amplifier piston movement creates high pressure internal liquid pumping action in a lower liquid pumping chamber of a hydraulic pneumatic pump and the well fluids enter the bottom inlet of the hydraulic pump. Well liquids are ejected out of the top of the hydraulic pump through the liquid discharge port of hydraulic pump. Discharged liquid from the hydraulic pump flow upward to the surface in a second flexible continuous metal conduit. The low pressure well gas coming out of the production well is compressed by an above ground gas compressor. A substantially small amount of the compressed gas is sent back down to the sub-surface pneumatic pump, and is recycled back into the production well.
Referring now to FIG. 1, there is depicted in partial section a typical earth formation having a well bore drilled and casing 1 inserted with a perforated section 1A at the intersection relation with a natural gas bearing stratum of the formation, an above ground well head 3 connected to the well casing 1A, an above ground well liquids holding tank 14, an above ground natural gas compressor 5, an above ground gas pressure regulator apparatus 7, an above ground gas oil treatment apparatus treatment 8 and 8 a. The natural gas compressor 5 draws high volume, low pressure natural gas from the well head 3 thru a pipe conduit 4 and ejects high volume high pressure natural gas out thru pipe conduit 6 to “Sales” or pipeline meter and low volume high pressure gas out to the gas regulator 7. Gas pressure regulator 7 is adjusted to deliver adequate pressure to cause sub surface pump 24 to lift well fluids to the surface at a desired flow rate. Pressure regulated gas flows into the top of the gas oil treatment apparatus 8 and thru the bottom gas oil treatment apparatus 8 a causing the pressure regulated gas to transport oil to the sub surface pump 24 for internal lubrication of moving parts. A small diameter flexible metal conduit 9 is connected between the outlet of the gas oil treatment apparatus 8 a and to the first down well small diameter flexible metal conduit 17 coming out of the well head “Y” port 10. Another small diameter flexible metal conduit 13 is connected between the outlet of the well fluids holding tank 14 and to the second down well small diameter flexible metal conduit 16 coming out of the well head second conduit support clamp (slips) 12 at the top of the well head 3. The support clamp (slips) is the primary support for down well conduits 16, 17 and pump 24. Just below the support clamp (slips) 12 is a sealing apparatus (packoff) 11 to prevent well gas from escaping the well head 3. Just below the sealing apparatus (packoff) 11 and below the well head flange plate is a control shutoff valve 15 for isolating the well.
Suspended from the well head 3 are conduits 16 and 17 which extend down the well casing and connect to the top of pump 24. These conduits are attached together every 100 feet with a metal clamp 18. First conduit 16 connects to the gas inlet port 30 in FIG. 2 and second conduit 17 connects to the top of the outlet of the solids trap 20.
In the well casing the two conduits are joined together with a clamp 18 about every 100 feet over the entire length of these conduits. Soft nylon guides 22 are attached to the solids trap 20 to guide the pump 24 up and down the well casing 1. Small conduit 23 flows well fluids up and into the top of the solids trap 20. The bottom of the solids trap 20 is rigidly connected to the top of the pump 24. The inlet particle filter 25 is rigidly connected to the inlet of the pump 24.
Referring now to the drawing in which there is shown in FIG. 2 a pump 24 in accordance with the present invention. As shown in FIG. 2 of the drawings, I represents the top segment of pump 24 comprising a solid cylindrical body of material not susceptible to corrosion such as 316 stainless steel housing a gas switching valve 32 a and gas switching valve sleeve 32 b, gas exhaust port 31, gas supply port 30 and liquid discharge port 43. II represents the upper piston segment of pump 24 comprising a solid cylindrical body of material not susceptible to corrosion such as 316 stainless steel and housing a gas metering valve 33, a gas switching valve 34 and upper piston 36 support channel. III represents the mechanical amplifier piston housing of pump 24 comprising a solid cylindrical body of material not susceptible to corrosion such as 316 stainless steel and housing the pneumatic mechanical amplifier piston 36. IV represents the bottom segment of pump 24 comprising a solid cylindrical body of material not susceptible to corrosion such as 316 stainless steel and housing the ceramic liquid sleeve 38 and ceramic piston head 39, inlet check valve plug 40, inlet check valve plug housing 41, and a backflow discharge check valve 42. As can be seen, upper piston 36 has a significantly larger surface area than piston head 39, and a rigid member separates pistons 36, 39 are separated by a fixed distance.
Low Pressure well gas entering the well casing 1A from the formation is drawn upwards by the above ground gas compressor 5. This low pressure well gas enters gas compressor 5 thru conduit 4 which is connected to well head 3. This low pressure well gas is then split into two internal flow paths, the first path provides well gas for the compressor engine to operate and the second path is compressed and high pressure well gas is ejected out of the gas compressor 5 thru conduit 6 to “Sales” and to pressure regulator 7. The regulated well gas is split into two flow paths. The first flow path passes into the top of the oiler 8 to provide a balance of pressure inside the oiler 8. The second flow path passes through a tee at the base of the oiler 8 a where oil is dripped into the gas flow. The regulated and oiled gas flows through conduit 9, sub surface conduit 17, and into pump 24 gas inlet GA of FIG. 2.
FIG. 2 shows the pump 24 in the maximum liquid filling state. In FIG. 2, gas flows into pump 24 through GA. Gas flows from GA through switching valve 32 a in segment I, out through channel GB to switching valve 34, and out to channel GE via hidden channel. Gas flows through channel GE into chamber GF of segment III causing the pneumatic mechanical amplifier piston 36 to travel upwards. When piston 36 reaches the top of chamber GF, piston 36 depresses switching valve 34 causing the gas in channel GB to flow through channel GC and into chamber GD. Gas flows into chamber GD forces switching valve 32 a upward. Gas also flows from chamber GF through channel GG into channel GH and out of the pump 24 at GI. Well liquids enter the pump 24 through LA, flow through inlet check valve body 41, around check valve plug 40 and into pumping chamber LB.
FIG. 3 shows the pump 24 in the liquid emptying state. In FIG. 3, gas flows into pump 24 through GA. Gas flows from GA through switching valve 32 a in segment I, out through channel GB to chamber GC in segment III, causing pneumatic mechanical amplifier piston 36 to travel downward. Travel of the pneumatic mechanical amplifier piston 36 causes ceramic piston head 39 to also travel downward discharging well liquids in chamber LA in segment IV, out through channel LB, up through backflow discharge check valve 42, up through channel LD, and out through LE. Gas also flows out of chamber GD, through channel GE, up through channel GF, and out through GG.
FIG. 4 shows the pump 24 in the switching travel direction state. In FIG. 4, gas flowing through needle valve 33, through channel GE and out through GF causes switching valve 32 a to travel downward.
FIG. 5 shows the pump 24 in the liquid filling state. In FIG. 5, gas flows into pump 24 through GA. Gas flows from GA through switching valve 32 a in segment I, out through a hidden channel into channel GB, and into chamber GC causing piston 36 to travel upwards. Gas also flows from chamber GD through channel GE, through channel GF, and out through GG. Well liquids enter pump 24 at LA and flow through inlet check valve body 41, through inlet check valve plug 40, and into chamber LB.
The seals material in the hydraulic and pneumatic pumps can be made from VitonŽ or glass filled TeflonŽ. The pistons in the hydraulic and pneumatic pumps can be ceramic. The in-board gas switching spool valve 32 can be made of a graphite filled nylon.
The sub surface pump 24 can internal metal parts made of non-corrosive materials, for instance 316 stainless steel. The sub surface pump 24 can be made to have dimensions of about 3.50 inches diameter by 13 inches tall, weighing about 40 lbs. The power ratio of the pneumatic to hydraulic pumps can be about 1:11.
In one embodiment, the materials for the tubing 16, 17, and 26 can be continuous metal tubing that is flexible around room temperature. For instance, the tubing can be unwound from a spool prior to insertion in the well during installation. The tubing used in the well for the gas supply and for the liquid discharge can be about ⅜ inch diameter 2205 duplex stainless steel, which is available from WebCo Industries in Sand Springs, Okla.
By way of example, and not by way of limitation, for a natural gas production well of a depth of about 3000 feet, one implementation assumes that the compressed gas supply is about 170 psi, the well casing pressure is about 20 psi, the well diameter is at least 4 inches, and the well fluids viscosity is relatively low. In this case, well liquids at 3000 feet create a back pressure weight at the outlet of the pump of about 1299 psi, which is calculated as: 3000 feet/2.31 feet/psi=1298.70 psi. Such an embodiment of the sub surface pump 24 can lift well liquids from the depth of 3000 feet deep when the gas supply pressure at the inlet of the sub surface pump 24 can is at least 140 psi and the well casing pressure is not more than 20 psi. The working supply pressure, at the inlet gas supply-well casing, is about 120 psi, which is calculated as: 140 psi (e.g., pressure of the compressed gas) −20 psi (e.g., the pressure within the casing). The pump liquid discharge pressure is calculated as: working supply pressure×power ratio, which here is: 120 psi×11=1320 psi.
Disclosed above are implementations of a displacement type pumping mechanism that provides the capability of liquid displacement pumping of a production liquid from an earth formation. These implementations, all or individually, can provide:
- (i) fluid recovery that minimizes energy and material resources consumption;
- (ii) a pneumatic displacement pump that is controllerless, compact, and operates off of low pressure natural gas, and that will not substantially consume or damage the well natural gas but rather can recycle the well gas supplied to the pump back into the production well after use;
- (iii) little or no above-ground negative esthetic visual effects, air pollution, or noise pollution;
- (iv) an apparatus that places gas and/or liquid pumps in fluid communication with the surface of a well through flexible continuous metal piping that can be deployed substantially faster and safer than rigid pipe (for instance, coupled joints), and that can be installed using substantially smaller rigs with substantially no possibility of spilling well fluids on the ground outside the well;
- (v) a pneumatic displacement type pumping apparatus that can be used in production wells of relatively small casing dimensions; and
- (vi) an allowance for liquid chemicals for paraffin control, scale control, and hydrostatic fluid pressure control to pass freely thru the pump and out into the production well fluid.
The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the invention is, therefore, indicated by the appended claims rather than by the foregoing description. All changes which come within the meaning and range of equivalency of the claims are to be embraced within their scope.