Apparatus, System and Method for Lifting Fluids in a Wellbore

Abstract

Disclosed are numerous downhole valves, systems, and a method that increases wellbore production and liquid lift efficiency and provides other benefits. The disclosed valves are designed to replace surface intermitted valves that waste reservoir energy and reduce liquid lift inefficiency in stop cocking and plunger lift systems. Additionally, the disclosure may be used to improve production and lift efficiency for surfactant lift systems and to raise liquids from below to above conventional liquid lift equipment. The disclosed valves open with energy supplied from the reservoir and utilize reservoir gas to lift liquids; therefore, no external gas injection or other energy is required. The design of the disclosed valves reduce or eliminate valve chatter, erosion and plugging issues that affect other downhole valves. Included in the disclosure are numerous valve embodiments comprising a tubular housing, an inlet and an outlet, a closing member, and a seat.

Description

BACKGROUND OF THE INVENTION

1. Field of the Disclosure

The present disclosure generally relates to devices, systems, and methods for lifting fluids in oil and gas wells.

2. Description of the Related Art

Most wells will experience liquid loading at some point due to the reservoir's inability to provide enough energy to carry liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate.

There are numerous types of valves that are used in the oil industry but only gas lift valves are utilized to specifically lift wellbore liquids. There are generally two types of gas lift valves known to persons skilled in the art, conventional gas lift valves and pilot operated gas lift valves and both require gas injection that adds energy to the wellbore liquids for lift. Theses valve generally are designed with a gas filled bellows and a spring and open with either injection pressure or production pressure. The opening pressure or crack pressure of a valve is defined as the pressure necessary to open the valve when the first sign of flow is detected. Correspondingly, the closing pressure or reseal pressure is the pressure necessary to close the valve when no detectable leakage occurs through the valve. The difference between the crack pressure and reseal pressure is called the valve spread pressure which is used herein. Continuous injection gas lift valves typically have relatively high crack pressures that can be customized per application; however, they also have high re-seal pressures which result in low valve spread pressures. Therefore, relatively high rates of gas flow and pressure are required to maintain the valve in an open position. Valve chatter, which is well known to a person skilled in the art, may result in valve damage or failure when there is an insufficient gas injection rate to maintain the valve in an open position. Gas lift valves are generally installed in mandrels where space is somewhat limited; therefore, orifices and ports in the gas lift valve are correspondingly small which may result in erosion due to high fluid velocities or plugging issues. Since reservoir fluids often contain particulates or have scaling tendencies, the flow of reservoir fluids through gas lift valves are discouraged because of the potential for erosion and plugging. Additionally, for intermittent gas injection systems, industry studies have shown that gas lift valves with larger ports have higher liquid lift efficiencies than gas lift valves with smaller ports. Pilot operated valves are designed for increased valve spread pressures and rapidly open when the crack pressure is obtained; however, the valve spread pressures are still relatively low due to high reseal pressures, pilot operated valves have more intricate parts, and have similarly small ports that make them susceptible to erosion, particulate plugging, and valve failures if reservoir fluids are routinely passed through the valve.

Gas injection systems, continuous and intermittent, use gas lift valves to lift liquids requiring relatively clean and liquid-free injection gas. Both systems are also well-known in the art and have many benefits, but also have many deficiencies. Continuous gas injection systems become inefficient as reservoir pressures decline due to the back pressure exerted on the reservoir which reduces inflow into the wellbore. Intermittent gas injection systems do not subject the reservoir to constant back pressure; however, they are often difficult to operate and may require a great deal of manpower for system adjustments to optimize the lift process. One intermittent gas injection system called chamber lift, that is well known in the art, utilizes a downhole chamber that intermittently stores and releases accumulated injection gas. Although chamber lift creates a very efficient lift system especially for low pressured reservoirs, it still suffers from the same deficiencies as all other gas injection systems. The most limiting is that many wells lack a sufficient gas supply. Other disadvantages include the need for a multitude of equipment such as compressors, buy gas meters, bleed valves, packers, numerous gas lift valves and other downhole equipment. Further complications include the execution of a gas purchase contract and the expense of obtaining the lift gas or buy gas.

Therefore, a need exists for an apparatus, system and method that is like chamber lift but is designed for the routine passage of reservoir fluids through a downhole valve, has a high valve spread pressure with a low reseal pressure, and can use existing reservoir energy to lift liquids in the wellbore and does not require gas injection and the associated equipment.

Two additional liquid lift methods, plunger lift and stop cocking, generally do not require gas injection but instead utilize existing reservoir energy to lift liquids. Both are well known in the art and function by intermittently opening and closing the well to flow using an intermitting surface valve. During the shut-in period, the wellbore pressure increases due to the inflow of fluids from the reservoir. When a desired surface pressure is attained, the surface valve opens which causes a rapid pressure reduction in the production tubing, resulting in fluid flow and creating a pressure differential between the surface and the reservoir. Stop cocking is not an efficient liquid lift process and often no wellbore liquids or only a small portion of liquids arrive at the surface after a lift cycle due to a condition called liquid fall back that occurs due to gravity and frictional contact of the liquids with the walls of the production tubing. In general, plunger lift is similar in operation to stop cocking, but has a higher liquid lift efficiency since liquids are lifted to the surface by a free-floating plunger. The plunger acts as an interface between the liquid and the gas column and reduces liquid fall back by restricting the gas from rising through the liquids. However, plunger lift and stop cocking suffer from a condition called pressure wave attenuation that results from opening a valve at the surface to initiate flow. Once the surface valve is opened, gas is removed from the well and a pressure wave travels down the wellbore. As the pressure wave travels, the differential pressure that was achieved at the surface valve lessens considerably. This loss of energy causes lower plunger and liquid column velocities and may even cause plunger stalls. Both stalls and lower velocities cause liquid to leak past the plunger and thus lower lift efficiencies. Additionally, since gas separates from the liquid column during the shut-in period for both stop cocking and plunger lift, none of the gas that exists above the liquid column is utilized to lift liquids, resulting in an inefficient use of reservoir energy. If the origin of the pressure wave were somehow lowered deep into the liquid column in the wellbore, a higher lift efficiency could be achieved since more reservoir energy is used to lift liquids. Therefore, a need exists for an apparatus, system, and method to enhance production and liquid lift efficiency for stop cocking and plunger lift systems by positioning the origin of the pressure wave into the liquid column of the wellbore.

Surfactant injection systems, also called soap injection, is another liquid lift system that is well known in the art and utilizes the injection of surfactants into the wellbore to mix with either water or oil to lower surface tensions to create a foam or emulsion which reduces the density of the liquid column, thus aiding in the lift of liquids from the wellbore. The surfactant may be injected from the surface into the casing annulus or through a capillary tubing string, or surfactant sticks may be dropped into the wellbore where they dissolve. The foam that is generated may also act as a plunger to form a gas-liquid interface that reduces liquid fall back. One limitation of surfactant injection is that some wells may not produce sufficient agitation between the mixture of surfactant, liquid, and gas necessary to create a stable foam to efficiently lift liquids in the well. Additionally, it is difficult to optimize the amount of surfactant needed at any given time due to changing downhole wellbore conditions and many surfactant systems that continuously inject surfactants often use more surfactant beyond the needs of the lift system, causing surfactant waste. Another inefficiency results from the injection of a surfactant designed for water being injected into an oil column, or vice versa, causing deficiencies in foam generation. Therefore, a need exists for an apparatus, system, and method that will allow the oil to separate from the water to enable the surfactant to be placed in a specific type of liquid and will also provide sufficient turbulence to create a more efficient foam.

Downhole pumping systems are also well known in the art and consist of various types of pumps that lift liquids to the surface, each with advantages in certain applications. These pumping systems include rod pumps, electric submersible pumps (ESPs), progressive cavity pumps (PC pumps), jet pumps, and hydraulic piston pumps. The most popular pumping systems currently are rod pumps and ESPs.

One limitation that effects pumping systems, as well as all liquid lift systems, is the placement of the downhole lift equipment high above the reservoir. A person skilled in the art would understand that these lift systems cannot lift liquids unless the liquids are raised above the downhole lift equipment. Additionally, the liquid column below the downhole lift equipment exerts back pressure on the reservoir which reduces the inflow of reservoir fluids into the wellbore. There are numerous reasons operators place downhole lift equipment high above the reservoir; regardless, setting the artificial lift equipment high above the reservoir may cause lower production rates and lower ultimate recoveries of oil and gas. Therefore, a need exists for an apparatus, system and method that will provide more efficient liquid lift from below to above the downhole lift equipment for wells that have the downhole lift equipment set high to the reservoir.

U.S. Pat. No. 7,147,059B2 by Hirsch, et al, granted Dec. 12, 2012 teaches a downhole valve and methods that utilizes reservoir gas to lift liquids with a downhole valve that operates by electricity. Hirsh et al also teaches the very limiting requirement of having two reservoirs in proximity, with one reservoir containing oil and the remainder containing primarily gas of a sufficient pressure to lift oil from the oil reservoir. The teachings of the disclosure herein are novel to Hirsh et al in that the valves of the disclosure do not operate with electricity, but instead open and close based on fluid pressure differentials supplied by pressure from the reservoir. In contrast to Hirsch et al, the disclosure is not limited in scope and can be utilized for wellbores with single or multiple reservoirs, does not require electricity, associated chokes, cables, and other equipment necessary to operate the sub-surface valve, and has no need of a connector, or dip tube, extending from the gas reservoir to the oil reservoir.

In summary, there are no currently available devices, systems or methods that offer solutions to the needs described herein.

BRIEF SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure relates to an apparatus, system, and method to lift liquids in a wellbore utilizing a downhole valve that utilizes reservoir energy to operate the valve and to lift liquids in the wellbore.

One object of the disclosure is to replace the surface valve used to intermit the well for stop cocking and plunger lift operations with a downhole intermitting valve to eliminate pressure wave attenuation and to optimize reservoir energy to lift liquids.

Another object is to provide a downhole valve that has lower risks of erosion and plugging from flowing reservoir fluids through the valve and lower risks of damage from valve chatter.

Yet another object of the disclosure is to provide a valve that has a relatively low reseal pressure for purposes of allowing a desirable amount of fluid to pass from the inlet to the outlet before closing and a relatively high spread pressure for purposes of allowing a desirable amount of reservoir gas and pressure to build on the inlet side of the valve.

Another object of the disclosure is to lift wellbore liquids to the surface or above installed liquid lift equipment.

Another object of the disclosure is to provide a downhole valve that may operate without need of additional gas or other energy from the surface, except for certain applications as described herein.

Another object of the disclosure is to provide a downhole valve that upon closing will create a downhole chamber by utilizing existing wellbore space for the purpose of the intermittent storage and release of pressured reservoir gas in the chamber, without need of additional chamber equipment as is required in conventional chamber lift systems.

Another object of the disclosure is to provide a lift system and lift method to utilize the valve in various wellbore applications and conditions.

Yet another object of the disclosure is that the valve spread pressure may be customized for a particular wellbore application.

Yet another object of the disclosure is to provide a unidirectional valve that is simple to operate, may be installed in-line as part of the production tubing or in a gas lift mandrel or may be installed via wireline inside the production tubing, casing or a side-pocket gas lift mandrel, has little or no depth restrictions, may be installed in the vertical, deviated, or horizontal section of a wellbore, contains few moving parts and is reliable, requires little or no manpower to operate the valve, and does not require: a multitude of gas lift valves, buy gas, a buy gas meter, a buy gas purchase contract, a packer or packers, a wellhead compressor, or a lift gas supply system from the surface.

The disclosure provided herein may be utilized to replace the surface flowline valve used in stop cocking and plunger lift operations and may also be used in conjunction with surfactant injection systems and pumping equipment to increase production and liquid lift efficiency. When installed in a wellbore, the disclosure creates a downhole chamber that is utilized for the intermittent storage and release of reservoir gas for the purposes of lifting wellbore liquids with the stored gas and raising the liquids either to the surface or above installed liquid lift equipment. The disclosed apparatus, system, and method allows the embodiments provided herein to function as a type of chamber lift system but with the following advantages: requires little or no manpower to operate, has means of achieving relatively high valve spread pressures and relatively low re-seal pressures, and will allow fluid flow in only one direction. Valve spread pressures and reseal pressures may be customized per valve to accommodate various well conditions and parameters. The disclosed valves may be placed in a deviated, vertical, or a horizontal section with little or no depth restrictions. The disclosed valves are reliable and will allow the routine flow of reservoir fluids through the valve with little or no erosion or plugging or valve chatter concerns. Compared to conventional chamber lift or other intermittent gas lift systems, the disclosure does not require a compressor or surface gas lift supply, multiple downhole valves, packers, downhole chamber lift equipment, buy gas meters, a buy gas contract or buy gas expense. Additionally, the disclosed valves may be installed via wireline in the production tubing, casing, or in a side-pocket gas lift mandrel or may be installed in a conventional gas lift mandrel or in-line as part of the production tubing. Accept as further described herein, in most applications, the disclosure requires no addition of energy into the wellbore.

The production and liquid lift efficiency of stop cocking systems may be improved by replacing the intermittent surface valve and positioning the disclosed valves deep into the liquid column as close to the reservoir as practical to prevent pressure wave attenuation and the inefficient use of reservoir energy by producing gas that exists above the liquid column in the wellbore during the initial stages of a lift cycle in stop cocking. Similarly, plunger lift may be improved by placing the disclosed valves beneath the plunger. It is contemplated that the addition of a packer above the valve may yield further efficiency improvements by optimizing the chamber volume to better match the gas requirements for lift per application. The lift cycles per day may be increased resulting in more production.

The disclosure teaches greater liquid lift efficiency and production of conventional down-hole pump systems and gas injection systems by positioning the disclosed valves below the pump or gas lift valves to as close to the reservoir as practical. For down-hole pumps and gas lift equipment that are installed high to the reservoir, the liquids would only need to be lifted above the down-hole equipment and not the surface. It is contemplated that the addition of a packer may further increase production like the packer application for stop cocking and plunger lift described previously. It is contemplated that a plunger lift system may be combined with the disclosed valves and a down-hole pump or gas injection system to provide more efficient liquid lift from below to above the down-hole equipment as may be necessary for long lift distances. Optionally, for certain low pressure, low gas rate wellbores, a relatively small amount of gas from the surface may be injected into the casing annulus or through an installed capillary tubing string to supplement the reservoir gas and pressure to attain a desired time interval between the opening and closing of the disclosed valves.

Surfactant injection systems may also be similarly improved by the teachings of the disclosure as is described for stop cocking, plunger lift, down-hole pumps, and gas injection. When the disclosed valves open, the turbulence created by the high rate of gas exiting through the reduced internal diameter of the disclosed valves would more efficiently mix the gas with the surfactant and wellbore liquids to generate a higher quality foam or an emulsion that would more efficiently lift liquids to the surface. Additionally, since the disclosure allows for a well shut-in period, any oil in the production tubing would have time to separate and rise to the top of the liquid column so the surfactant could be preferentially placed in that portion of the liquid that will create a higher quality foam or emulsion without contamination from other liquids, thus yielding a higher liquid lift efficiency.

Additionally, it is contemplated the disclosed valves may be installed in the production casing instead of the production tubing string for all applications described herein. The benefits are that the casing has a larger volume capacity per foot than smaller diameter production tubing; therefore, for equivalent liquid volumes, the liquid height column in the casing is much less resulting in less hydrostatic pressure exerted by the liquid column on the disclosed valve. Less hydrostatic pressure results in less pressure and gas requirements to lift liquids and potentially more lift cycles per day yielding more production per day.

In summary, the disclosure teaches many possible valve and system embodiments, but variances to the disclosed valves should not compromise the novelty of the disclosed system or method. Other and further objects of the disclosure will become apparent upon reading the detailed specification hereinafter following, and by referring to the drawings annexed hereto.

Certain features from the described embodiments may be shared between embodiments presented herein, and certain additional features or materials or alterations may be added or deleted without departing from the scope of the disclosure, which should be readily apparent for those skilled in the art.

Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and that the contributions they represent to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter which will form the subject of the claims appended hereto. The previously described embodiments are presented in a vertical wellbore, but the disclosure can be readily adapted for any wellbore requiring artificial lift and is only illustrative of some of the embodiments that may developed for the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:

FIG. 1A is a drawing of an embodiment of the disclosure showing a valve in a closed position with a closing member in the shape of a ball in conjunction with a mechanical arm assembly to temporarily maintain the closing member on seat;

FIG. 1B is a drawing like FIG. 1A except the valve is shown in an open position;

FIG. 2A is a drawing of a preferred embodiment of the disclosure, like FIG. 1A, showing a flat spring assembly instead of a mechanical arm assembly;

FIG. 2B is a drawing like FIG. 2A, except the valve is shown in an open position;

FIG. 3A is another embodiment like FIG. 1A except an elastomer in the shape of a ring is used to seal the valve and there is no mechanical arm assembly;

FIG. 3B is another embodiment like FIG. 3A, except the elastomer is removed and an additional seat is added and a permanent magnetic is installed between the two seats;

FIG. 3C is another embodiment like FIG. 3A, except the valve is shown in an open position and the closing member and the elastomer are in the shape of disks and are secured to each other;

FIG. 3D is another preferred embodiment and is like FIG. 3C except the elastomer is in the shape of a ring placed in a groove in a seat;

FIG. 4 is a top view of FIG. 1A-3D;

FIG. 5A is a drawing of a rod pump assembly in a wellbore with an apparatus of the disclosure;

FIG. 5B is a drawing like FIG. 5A except a capillary tubing is included and the capillary tubing is in fluid communication below a packer;

FIG. 5C is a drawing of a stop cocked system with the valve of the disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

An apparatus, system, and method for lifting liquids in a wellbore are disclosed that increases production and improves the liquid lift efficiency of stop-cocked wells, plunger lifted wells, or wells with other artificial lift systems. There are many possible embodiments of the disclosure as can be seen by numerous drawings provided herein. Only a few have been included for the sake of brevity; therefore, FIGS. 1A-5C and the additional contemplated descriptions included are only examples of the many different configurations that are possible and should not be viewed in a limiting sense. Drawings of FIGS. 1A-4 are examples of downhole valves that have means of achieving a high valve spread pressure and a low reseal pressure. In the following descriptions, like parts are numbered similarly and drawings are not drawn to scale throughout the specifications. FIGS. 5A-5C show system embodiments that are illustrated in a vertical wellbore, but the disclosure is also contemplated for installations in deviated and horizontal sections of a wellbore. It is also contemplated that openings or other items described herein may be of a different form than illustrated such as but not limited to the shape of a slot, rectangular, circle, sphere, ring, oval, and other shapes, and that openings may be singular or multiple in number and aligned vertically, horizontally, askew, or randomly, unless otherwise specified. Herein, direction references to an upward direction, such as “up”, “above”, “upward”, “rise”, “raise”, “ascend”, “ascent”, and variations thereof, refer to a direction along the wellbore toward the surface. Similarly, direction references to a downward direction, such as “down”, “downward”, “below”, “falling”, “lower”, “descend”, “descent” and variations thereof, refer to a direction along the wellbore away from the surface. Tubing joint collars are not shown for all drawings. FIGS. 1A-5C can share features that are shown in other figures, incorporate features that are not shown, or exclude or change the shape of certain items without compromising the novelty of the disclosure. The following is included to aid in clarifying descriptions of the numerous embodiments contained herein. The production tubing is defined to be at least one of the main tubing strings in the wellbore that transports reservoir fluids to the surface. Additionally, the production tubing may contain plugs, perforated subs, and other equipment. All parts are preferably made of metal unless otherwise specified but other suitable materials may be used if applicable for oil and gas operations in a wellbore. FIG. 1A-5C show valves that are installed on the production tubing string but one skilled in the art can understand that the valves could be adapted to be installed in a gas lift valve, a side pocket mandrel, or inside the production tubing string or casing. The disclosed valve can also be installed via wireline or by other means without compromising the novelty of the disclosure.

FIG. 1A shows a cut-away view of the disclosure showing a valve 40 comprising a tubular 2, and inlet 4 on one with internal threads 28 and outlet 26 on the opposite end with internal threads 24. Internal to tubular 2 is the closing member, ball 16, shown in contact with seat 12 with external threads 70 and channel 11, which separates inlet 4 from outlet 26. Pivot arm 27 is placed through slot 71 and is held in place by pin 29 that extends through the side of seat 12. Wheel 32 is connected to cross bar 33 by pin 37 and cross bar 33 is connected to pivot arm 27 by a weld or other means. Pivot arm 27 is secured to spring 30 by a weld or some means and spring 30 is contact with tubular 2. Cross bar 22 contacts tubular 2 and may or may not be secured to tubular 2. Spring 20 contacts cross bar 22 and may or may not be secured to cross bar 22. Numerous alterations are possible but only a few are described herein as follows: seat 12 may be made as an integral part of tubular 2, therefore, threads 70, threads 28, and threads 24 may be removed, and tubular 2 may contain external threads on outlet 24 and inlet 4. Additionally, cross bar 22 could be removed and spring 20 could be prevented from upward movement by different means. Ball 16 and seat 12 are preferably made of metal but may be made of other suitable materials and ball 16 could be replaced with a closing member comprising a different shape such as a cone, disk, conical frustum, cylinder, cube, cuboid, prism, stem, or dart and seat 12 may also be of a different shape accordingly to make a seal with the differing closing member.

FIG. 1B shows a drawing like FIG. 1A except that valve 40 is in an open position.

The operation of FIG. 1A-FIG. 1B is as follows: a sufficient differential pressure between inlet 4 and outlet 26 opens valve 40 as shown in FIG. 1B by compressing spring 20 and spring 30 and forcing wheel 32 to rotate along ball 16 to a position along the side of ball 16 to apply a lateral force and not a downward force to ball 16. Spring 20 applies a downward force to ball 16; however, when the differential pressure from inlet 4 to outlet 26 lessens, the force applied by fluid flow on ball 16 also lessens and spring 20 expands while ball 16 descends to allow wheel 32 to rotate along the side of ball 16 to a position towards the top of ball 16. When the force from fluid flow on ball 16 is less than the total force applied on ball 16 by spring 20 plus the weight of ball 16, the reseal pressure is reached and ball 16 will seat on seat 12, while spring 30 compresses and wheel 32 is positioned to apply a downward force on the top of ball 16 to keep ball 16 in a closed position as shown in FIG. 1A. Seat 12 is sloped to ensure that ball 16 easily returns to seal with seat 12. A preferred reseal pressure is one that is as low as possible yet will maintain a seal between ball 16 and seat 12 while in a closed position even if valve 40 is in a horizontal or deviated position from vertical. Once a sufficient crack pressure in inlet 4 is obtained, ball 16 rises off seat 12 and the downward force exerted on ball 16 from wheel 32 is reduced as spring 20 and spring 30 compress to allow pivot arm 27 to swing away from ball 16 to allow wheel 32 to apply a lateral force on ball 16 as shown in FIG. 1B. The process then repeats. The changing of a downward force to a lateral force on ball 16 by wheel 32 allows for an increased valve spread pressure and thus allows a larger portion of fluid and pressure to vent from inlet 4 to outlet 26 before valve 40 closes.

Now referring to FIG. 2A which is a preferred embodiment of the disclosure showing a cut-away view like FIG. 1A, except pivot arm 27, spring 30, cross bar 33, pin 29, pin 37, and slot 71 are removed. Instead, flat spring 23 is positioned between ball 16 and spring 20. Included are cavities 72 in seat 12 to assist seat 12 in being screwed into internal threads 28; however, cavities 72 are optional. Flat spring 23 is connected to wheel 66 by pin 35 and wheel 34 by pin 36. Wheels 66 and 34 rest against upset 41 when valve 40 is in a closed position. Flat spring 23, and the weight of ball 16, and optionally spring 20, all apply forces to keep ball 16 on seat 12.

Now referring to FIG. 2B which is like FIG. 2A except valve 40 is in an open position with ball 16 not in contact with seat 12 and flat spring 23 positioned above upset 41. Where applicable, the contemplated alterations described for FIG. 1A-1B also apply to FIG. 2A-2B.

The operations of FIG. 2A and FIG. 2B are like operations of FIGS. 1A-1B except ball 16 is kept on seat 12 by the downward force exerted by flat spring 23 when wheels 66 and 34 being are positioned in the larger inner diameter of tubular 2 below upset 41. Valve 40 will open when a sufficient crack pressure is attained that forces flat spring 23 to flex inwards to allow wheel 66 and 34 to ascend above upset 41 into the smaller diameter of tubular 2 and compress spring 20. When the differential pressure across valve 40 lessens sufficiently, spring 20 will expand to reposition flat spring 23 and wheels 66 and 34 below upset 41 and valve 40 will close and the process will repeat. The changing of the downward force by flat spring 23 as it travels above upset 41 allows for an increased valve spread pressure and thus allows a larger portion of fluid and pressure to vent from inlet 4 to outlet 26 before valve 40 closes.

Now referring to FIG. 3A, which is like FIG. 2A, except there is no flat spring 23, wheel 66 and wheel 34, pin 35 and pin 36 or upset 41. Added is an elastomer 31 that surrounds seat 12 from above and below and thus elastomer 31 is prevented from movement. It is contemplated that elastomer 31 may be secured to seat 12 by other means. Where applicable, the contemplated alterations described for FIG. 1A-2C also apply to FIG. 3A.

The operation for FIG. 3A is as follows: Once the reseal pressure is attained, ball 16 descends to contact elastomer 31 and forms a seal. The contact of ball 16 deforms elastomer 31 creating an imbalance in the force vectors acting on the surface area of ball 16 exposed to pressure in outlet 26 versus the surface area of ball 16 exposed to pressure in inlet 4; thereby allowing for a larger valve spread pressure. The reseal pressure is realized by the weight of ball 16 and the force applied by spring 20. Valve 40 will remain in a closed position until a sufficient crack pressure is attained to force ball 16 from elastomer 31 which will compress spring 20 and flow will occur through channel 11 to outlet 26. It should be apparent for a person skilled in the art to understand the drawing FIG. 3A in an open position; therefore, a drawing is not provided. Once a crack pressure is attained, ball 16 ascends and contacts spring 20 as in FIGS. 1B and 2B and fluids below inlet 4 may flow through valve 40 and pass upward through outlet 26. Additionally, it is contemplated that elastomer 31 may be comprise any suitable elastic material and may be a different shape than the one presented in FIG. 3A.

Now referring to FIG. 3B, which is like FIG. 3A except elastomer 31 is replaced by seat 39 and ring magnet 10 is added between seat 39 and seat 12. Seat 39 is preferably made of metal but may be made from other suitable materials. Ball 16 contacts seat 39 and forms a metal-to-metal seal. It is contemplated that ball 16 may be replaced with a closing member comprising a different shape. It is also contemplated that seat 12 or seat 39 may be an integral part of tubular 2 rather than an insert into tubular 2. Additionally, a means of centralizing ball 16 may be included to ensure that ball 16 sufficiently contacts seat 12 to make a seal. Where applicable, the contemplated alterations described for FIG. 1A-3A also apply to FIG. 3A-3B.

The operation of FIG. 3B is like FIG. 3A except it is magnetic force from magnet 10 that keeps ball 16 on seat 39. The magnetic force applied by magnet 10 is variable in that the force increases as ball 16 approaches magnet 10 and decreases as ball 16 moves away from magnet 10. This variable force allows for a high valve spread pressure and a low reseal pressure of valve 40 and thus allows a larger portion of pressure and fluid to flow from inlet 4 to outlet 26 before valve 40 closes. There are many design variances possible which are contemplated which can result in a sufficient magnetic force to maintain ball 16 on seat 39 until a desired crack pressure is realized. As illustrated, ball 16 and seat 39 comprise metal that are ferro-magnetic and the magnetic flux from ring magnet 10 attracts and maintains ball 16 to seat 39 with a sufficient force to attain the desired crack pressure. As known by one skilled in the art, ball 16 would not need to contact ring magnet 10 since the magnetic flux lines extend beyond magnet 10 and extend through a ferro-magnetic material. Corrosion is a concern with certain magnetic materials so ring magnet 10 could be coated on the edges exposed in channel 11. Ring magnet 10 could also be composed of a high temperature resistant material per the given application. Another option is that ball 16 may comprise a suitable magnetic material and that seat 39 is ferro-magnetic. In this instance, ring magnet 10 may aid in the resulting magnetic force necessary or ring magnet 10 and seat 12 may be removed. Yet another option is that seat 39 comprises a magnet and ball 16 comprises a ferro-magnetic material and seat 12 may be removed but the impact of ball 16 on seat 39 would be a concern since magnets are often made of brittle materials. Where applicable, the contemplated alterations described for FIG. 1A-3A also apply to FIG. 3B.

Now referring to FIG. 3C which is like FIG. 3A except valve 40 is in an open position, and ball 16 is replaced with disk 17 and elastomer 31. Disk 17 is made of metal or other suitable rigid material. It is also contemplated that elastomer 31 is secured to disk 17 with a bonding agent, a fastener or by other means. It is contemplated that disk 17 and elastomer 31 could have other shapes and that spring 20 may be placed below seat 12 and the force exerted by spring 20 be applied to disk 17 or elastomer 31 by a fastener or other means. It is also contemplated that disk 17 may secured to spring 20 in some fashion or that disk 17 is not secured to spring 20. Additionally, disk 17 may include centralization means to ensure that elastomer 31 makes sufficient contact with seat 12 to form a seal. Where applicable, the contemplated alterations described for FIG. 1A-3B also apply to FIG. 3C.

The operation of FIG. 3C is like FIG. 3A except valve spread pressure is attained as follows: while valve 40 is in a closed position, the cross-sectional area of elastomer 31 above seat 12 is larger than the cross-sectional area of elastomer 31 below seat 12; therefore, fluid force vectors exert a greater force on elastomer 31 above seat 12 than from below seat 12, requiring more pressure from below seat 12 than pressure above seat 12 to open valve 40. Additionally, the applied force on disk 17 and elastomer 31 is variable and is greatest when valve 40 is closed and is zero when valve 40 is open. After valve 40 is opened, it is maintained in an open position by the force applied from fluid flow from the inlet 4 to outlet 26. Once the force from fluid flow is less than the force applied by spring 20, valve 40 will close. The application of a variable force allows a higher valve spread pressure and low reseal pressure for valve 40.

Now referring to FIG. 3D which is another preferred embodiment of the disclosure. FIG. 3D is like FIG. 3C except elastomer 31 has been placed inside groove 38 that has been cut into the surface of seat 12 to prevent elastomer 31 from unwanted movement. Where applicable, the contemplated alterations described for FIG. 1A-3C also apply to FIG. 3D. It is contemplated that instead of groove 38, elastomer 31 may be placed around a back-up ring, made of metal or other suitable material, and placed on seat 12. The back-up ring may be secured or unsecured or may be an integral part of seat 12. Elastomer 31 would necessarily extend above seat 12 to enable a seal with disk 17. Optionally, the back-up ring may comprise a tubular of a sufficient length to be placed inside and secured to seat 12 and extend above seat 12. Another option is to secure the back-up ring to disk 17 instead of seat 12, with elastomer 31 surrounding the back-up ring and in contact with disk 17 and create openings on the back-up ring positioned below the elastomer 31. The assembly comprising the back-up ring, disk 17, and elastomer 31 would have freedom of movement in an upward direction to raise the openings out of channel 11 to allow fluid flow once the crack pressure was attained, and once the reseal pressure was attained, allow movement in a downward direction to allow elastomer 31 to seal with seat 12 thereby stopping fluid flow.

The operation of FIG. 3D is like the operation of FIG. 3C.

Now referring to FIG. 4, which is a top view of FIGS. 1A-3D showing tubular 2, cross bar 22 and spring 20. As can be seen, cross bar 22 allows fluid flow through the void spaces internal to spring 20 and between tubular 2 and spring 20.

Now referring to FIG. 5A, which is a cut-away view of a wellbore comprising any one of the valves disclosed herein, in conjunction with an artificial lift system. Illustrated is a wellbore having a surface 45, a casing 68 containing gas 46 and liquids 47 and gas-liquids interface 50, a production tubing 65 containing liquids 47, rods 53 connected to rod pump 54 that is seated in seating nipple 52 that is part of production tubing 65 that is connected to packer 49 and gas separator assembly 44 comprising dip tube 55, plugged nipple 48 and perforated subs 43 and 51. Valve 40 is shown with channel 11 and connected to the lower end of production tubing 65. Valve 40 may comprise any of the embodiments illustrated in FIGS. 1A-3A, or as taught in the specifications or the claims herein. It is contemplated the rod pump system may be replaced with a different artificial lift system including but not limited to a gas injection system, ESP, progressive cavity pump, jet pump or a hydraulic piston pump. It is also contemplated that a plunger lift system may additionally be installed below the lift systems mentioned herein. Additionally, there are numerous different possible configurations of FIG. 5A, including but not limited to, production tubing 65 may terminate between gas separator assembly 44 with valve 40 being installed under a packer like packer 49 or secured to casing 68 by some other means, packer 49 may not be installed or may be replaced by a tubing anchor in combination with a cup type packer, and separator assembly 44 may be of a different type or form. Where applicable, the contemplated alterations described for FIG. 1A-3D also apply to FIG. 5A.

The operation of FIG. 5A is as follows: when valve 40 is closed, gas 46 from the reservoir continues to flow into the wellbore and the pressure under valve 40 and packer 49 increases due to the added fluid volume. Gas 46 separates from the liquids 47 and the column of gas 46 extends downward lowering the gas-liquid 50 interface until the crack pressure of the valve 40 is attained. When valve 40 opens, gas 46 below the packer 49 and valve 40, flows upwards through channel 11 and through valve 40 and lifts liquids 47 up production tubing 65. Liquids 47 flow through perforated sub 43 and into and up the annulus between casing 68 and production tubing 65, and then into perforate sub 51 and travel downward to enter and travel up dip tube 55 to rod pump 54, where the liquids are pumped to the surface 45 up production tubing 65. Gas 46 used to lift liquids 47, rise in the same path as liquids 47 except gas 46 does not travel up dip tube 55 but instead rise in the annulus of casing 68 and flow to the surface 45. Once gas 46 vacates the region below valve 40, liquids 47 shown below gas 46, flow through valve 40 and by the same path as previously until the reseal of valve 40 is attained. Valve 40 will then close, the process will repeat. It is also contemplated that gas-liquid interface 50 below valve 40 shown may exist above valve 40 immediately prior to the opening of valve 40, which would cause liquids 47 to flow through valve 40 before gas 46. One skilled in the art can understand how the addition of a plunger lift system, installed below rod pump 54 would allow liquids to be lifted from deep wells above the rod pump 54.

Now referring to FIG. 5B which is like FIG. 5A except packer 49 is either a dual packer or a by-pass packer which are well known in the art and added is capillary tubing 64 which extends from the surface 45 into the annulus between casing 68 and production tubing 65 and connects to a coupling 70 that connects capillary tubing 64 to either one of the tubulars of dual packer 49 or through a port on the packer by-pass which allows gas 46 to be injected below packer 49. Gas 46 that is injected through capillary tubing 64 may be provided by a small volume and small rate compressor or other pressured gas source (not shown). Valve 40 may be one of any of the embodiments illustrated in FIGS. 1A-3D, or as taught in the specifications or the claims attached hereto and where applicable, the contemplated alterations described for FIG. 1A-5A also apply to FIG. 5B.

The operation of FIG. 5B is like FIG. 5A except that gas 46 is injected from surface 45 through capillary tubing 64 to below packer 49 which injects gas below packer 49 to supplement the gas volume below valve 40 to aid in opening valve 40 for wells that do not have sufficient gas volumes or bottom hole pressure to open valve 40 in a desired time frame. It is also contemplated that the rod pump system may be replaced with a different artificial lift system as described herein. Since only a small volume of gas may be necessary, the supply of gas for capillary tubing 64 may be obtained from the separator overhead (not shown) or gas 46 that exists in the production tubing 65 above valve 40 prior to a lift cycle or from a gas flowline or a combination of these options. Therefore, some or all the equipment and limitations as stated with gas injection herein may be avoided.

Now referring to FIG. 5C showing a stop cocking system which is like FIG. 5B except excluded are: capillary tubing 64, coupling 70, packer 49, rods 53, rod pump 54, seating nipple 52, dip tube 55, gas separator assembly 44 comprising perforated sub 51 and 43 and plugged nipple 48. Valve 40 may be one of any of the embodiments illustrated in FIGS. 1A-4, or as taught in the specifications or the claims herein. Where applicable, the contemplated alterations described for FIG. 1A-5B also apply to FIG. 5C.

The operation of FIG. 5C is as follows: once the crack pressure is attained and gas 46 under valve 40 flows up channel 11 through valve 40, gas 46 lifts the liquids 47 to the surface 45. Valve 40 will close once a sufficient volume of liquids 47 rise in production tubing 65 to reseal valve 40. It is contemplated that production tubing 65 may not be installed and valve 40 may be secured to casing 68 under a packer or secured to casing 68 by other means, or production tubing 65 may be installed but may terminate above valve 40. Additionally, one skilled in the art can understand how a plunger lift system could easily be added to any of the possible configurations described for FIG. 5C, and how there are many other possible configurations not listed herein.

Viewing FIGS. 5A-5C, one skilled in the art can now understand how many different combinations of the disclosure are possible, and the many differences between the disclosure and conventional liquid lift methods, and how the many described advantages of the disclosure contained herein can replace, alter, and enhance existing liquid lift methods. It can also be understood how the disclosure utilizes reservoir energy to operate the disclosed valves and does not require additional forms of energy to lift liquids such as gas or liquid injection, mechanical, electricity or any other forms of energy.

While the disclosure has been described with reference to exemplary embodiments, it should be noted that various changes may be made, certain parts maybe excluded or added, equivalents may be substituted for elements thereof without departing from the scope of the disclosure, and features may be shared between the exemplary embodiments. In addition, many modifications will be appreciated to adapt a particular instrument, situation, or material to the teachings of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the disclosure is not limited to a particular embodiment or the described uses disclosed as the best mode contemplated for carrying out this disclosure, but that the disclosure will include all embodiments falling within the scope of the appended claims and the examples contained herein are not to be taken in a limiting sense.

Claims

1. A valve with high spread pressure means positioned in the subsurface for the intermittent lift of fluids in a subterranean wellbore comprising a reservoir and said reservoir comprising fluids and said valve comprising:

a tubular housing;

a bore with an inlet and an outlet;

a closing member;

a seat; and

said valve has means for unidirectional flow and said reservoir fluids intermittently flow from said inlet to said outlet; and

the valve spread pressure of said valve is attained by a variable force applied to said closing member and said variable force is greater when said closing member is in contact with said seat and said variable force is lower when said closing member is not in contact with said seat; and

said valve opens with wellbore pressure supplied from said reservoir on said inlet side of said valve; and

upon the opening of said valve energy from the pressured gas supplied by said reservoir on the inlet side of said valve lifts said fluids on said outlet side of said valve; and

said valve closes by the reduction of said fluid flow through said valve.

2. The valve of claim 1, wherein said variable force is provided by at least one:

a pivot arm assembly;

a flat spring;

a magnet;

an imbalance between the combined fluid force vectors acting on the surface area of said closing member on said outlet side and the combined fluid force vectors acting on the surface area of said closing member on said inlet side while said closing member is in a closed position.

3. The valve of claim 2, wherein said pivot arm assembly comprises at least one of: a pivot arm, a compression spring, a rotating wheel.

4. The valve of claim 2, wherein said flat spring comprises at least one rotating wheel.

5. The valve of claim 1, wherein the ratio of said imbalance of combined fluid force vectors is at least one and fifteen hundredths (1.15).

6. The valve of claim 1, wherein said closing member has centralization means to enable an effective seal between said closing member and said seat.

7. The valve of claim 1, wherein said closing member comprises the shape of at least one of a: sphere, ball, cone, a disk, conical frustum, cylinder, cube, cuboid, prism, stem, dart, flapper, an amorphous shaped object.

8. The valve of claim 1, further including a spring in said bore.

9. A liquid lift system in a wellbore comprising a reservoir comprising fluids and at least one tubular string comprising at least one downhole valve that intermittently opens and closes to control fluid flow in said wellbore and said valve comprising an inlet and an outlet with means for unidirectional flow; and

when said valve is in a closed position, fluid communication between said outlet side and said reservoir ceases and the liquids in said tubular string above said outlet descend and accumulate on said outlet side of said valve while said inlet side of said valve remains in fluid communication with said reservoir and a downhole chamber is created in said wellbore on said inlet side of said valve and said reservoir increases the gas and liquid pressure in said downhole chamber; and

when said valve is in an open position, said pressured gas in said downhole chamber lifts said accumulated liquids in said tubular string.

10. The liquid lift system of claim 9, wherein said valve further comprises:

a tubular housing;

a bore;

a seat;

a closing member; and

wherein said closing member creates a seal when in contact with said seat.

11. The liquid lift system of claim 9, wherein said wellbore includes additional liquid lift equipment comprising at least one of: a downhole pump, a gas injection valve, a plunger lift system, a surfactant injection system.

12. The liquid lift system of claim 11, wherein said liquids are lifted to at least one of: the surface, above said additional lift equipment.

13. The liquid lift system of claim 11, wherein supplemental gas is injected into said wellbore to reduce the time interval between the opening and closing of said valve.

14. A method for the intermittent lift of liquids in a wellbore that extends from a surface to a subterranean reservoir containing reservoir fluids comprising gas and liquids and said wellbore comprising at least one tubular string and said tubular string comprising at least one valve with an inlet and an outlet and said method comprising the steps of:

flowing said fluids out of said wellbore;

closing said valve by the reduction of said fluid flow through said valve;

accumulating said liquids in said tubular string above said outlet;

increasing the pressure of said reservoir gas in said wellbore on said inlet side of said valve by the inflow of said fluids from said reservoir into said wellbore;

opening said valve with said increased pressure in said inlet side of said valve;

flowing said pressured reservoir gas from said inlet to said outlet;

lifting at least a portion of the volume of said accumulated liquids in said tubular string with said pressured reservoir gas in the direction of said surface;

repeating said steps.

15. The method of claim 14, further including the step of decreasing the time interval between the opening and closing of said valve by supplemental gas injection into the wellbore after the step of increasing the pressure of said reservoir gas in said wellbore on said inlet side of said valve by the inflow of said reservoir fluids into said wellbore.

16. The method of claim 14, wherein said wellbore further includes additional downhole liquid lift equipment.