TWO-STEP ARTIFICIAL LIFT SYSTEM AND METHOD

Abstract

A two-step artificial lift system and method is proposed which provides for lifting of reservoir fluids without fluid injection using a first step system and lifting of reservoir fluids with fluid injection using a second step system. The second step system reuses the components of the first step system. The system and method aids in lifting reservoir fluids from vertical, deviated, and horizontal wellbores.

Description

1. FIELD OF THE DISCLOSURE

The present disclosure relates to artificial lift production systems and methods deployed in oil and gas wells, and more particularly relates to systems and methods in vertical wells with long perforated intervals, deep reservoirs, high gas to liquid ratio reservoirs, and in deviated wellbores such as horizontal and slanted wells.

2. DESCRIPTION OF THE RELATED ART

Many oil and gas wells experience liquid loading at some point during their productive lives due to the reservoir's inability to provide sufficient energy to carry liquids through the wellbore to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or to flow at a reduced rate. To increase or re-establish production, operators may place the well on artificial lift, which is defined as a method of removing wellbore liquids to the surface by artificially applying some form of energy into the wellbore.

Currently, the most common artificial lift systems in the oil and gas industry are down-hole pumping systems and gas lift systems. In general, in order for reservoir liquids to be lifted, the liquid level in the wellbore must be above these artificial lift systems. The most popular form of down-hole pump is the sucker rod pump, which is a positive displacement pump consisting of a dual ball and seat assembly and a plunger inside a pump barrel. Generally, the plunger is connected by a string of rods contained inside a production tubular string. A surface apparatus provides the reciprocating motion to the rods which in turn provides the reciprocal motion to stroke the pump. As the pump strokes, fluids above the pump are gravity fed into the plunger and barrel and are pumped up the production tubular and out of the wellbore to surface facilities. Other popular forms of artificial lift include progressive cavity pumps (PCP), hydraulic pumps (such as piston pumps and jet pumps), and centrifugal pumps such electric submersible pumps (ESPs). A gas lift system operates by injecting pressured gas below the liquid level in the wellbore to commingle and reduce the density of the reservoir liquids and raise them to the surface.

In general, the greater the bottom-hole pressure in a depletion drive reservoir, the greater the remaining hydrocarbon reserves present in that reservoir; therefore, the economical lowering of the bottom-hole pressure by artificial lift is crucial in ensuring an efficient recovery of a well's reserves. If a well is allowed to have a liquid column above the reservoir, the back pressure that the liquid column exerts on the reservoir will reduce the production from the reservoir and may even cause the well to cease flowing since flow into the wellbore is determined by the differential pressure from the reservoir to the surface facilities. If this back pressure prevents the reservoir from lifting liquids to the artificial lift equipment, the well will cease producing liquids, since conventional artificial lift equipment and methods are not designed to lift liquids that exist below the down-hole equipment. Therefore, it is beneficial for operators to lower the artificial lift equipment to the deeper regions of the wellbore to minimize the reserves that will be left behind.

U.S. Pat. No. 8,985,221, herein incorporated by reference, includes a dual stage, dual concentric tubing, artificial lift method utilizing a fluid displacement device in conjunction with gas injection in the same wellbore. This artificial lift system operates by using injection gas to raise the liquids that exist below the pump to above the pump. The wellbore contains a first tubing string that begins at the surface and is connected to a bi-flow connector, a bushing, a perforated sub, and a packer in the wellbore. The first tubing string extends below the packer. A second tubing string is connected to the bottom of the bushing and extends inside the first tubing string below the packer. A third tubing string begins at the surface and extends inside the first tubing string and connects to the bi-flow connector. A fluid displacement device is installed inside the third tubing string.

U.S. Pat. No. 8,985,221 also shows a method that includes injection of gas into the well from the surface so that the injected gas travels down the annulus between the first and third tubing string. The injection gas passes through the body of the bi-flow connector (lengthwise) and enters and exits the second tubing string and commingles with and lifts reservoir fluids up the annulus between the first and second tubing strings. These commingled fluids exit into the casing annulus through the perforated sub. Liquids are prevented from falling back down the wellbore by the packer. Gas separates from the commingled fluids and travels to the surface while the liquids fall and enter through the side body (width) of the bi-flow connector and enter the fluid displacement device where they are pumped upwards through the third tubing string to the surface. Since gas injection is required, the third tubing string is needed to provide an annular pathway for the injection gas in the wellbore. An additional wellhead is also required at the surface to support the third tubing string and the gas injection requires a pressurized gas source, gas flowline, and a gas meter.

A shortcoming of the prior art is that the requirement of a third tubing string concentric with the first tubing string during all operations limits the liquid production rates for smaller casing sizes and deeper pump setting depths. Generally, higher liquid production rates and deeper pump setting depths require larger diameter third tubing strings to house larger diameter fluid displacement devices and associated equipment, such as sucker rods. Since the third tubing string has a larger diameter, the first tubing string must also have a larger diameter to house the larger third tubing string. A larger diameter first tubing string necessarily reduces the cross-sectional area of the casing annulus, which is the pathway for the commingled reservoir and injection gas to reach the surface. For example, a popular casing size for a wellbore is 5.5-inch diameter that weighs 17 lbs. per foot. A higher capacity down-hole pump would require a first tubing string with a 3.5-inch diameter and an inner third tubing string with a 2.375-inch diameter. A lower capacity down-hole pump would require a first tubing string with a 2.875-inch diameter and a third tubing string with a 1.9-inch diameter. The cross-sectional area of the annulus between the casing and the first tubing string for the higher capacity scenario is 35% less at the tube portion of the first tubing string and 64% less at the connections of the first tubing string versus the lower capacity scenario. This smaller cross-sectional area results in a higher commingled gas velocity that will lift the reservoir liquids up the casing annulus, which is undesirable because the cross-sectional area and length of the pathway is too great and the annular shape is not conducive for efficiently lifting the fluids to the surface. Instead, gas will break out of the liquid causing liquid fall back and will result in liquid slugs being suspended in the annulus. These liquid slugs cannot enter the displacement pump while suspended, will exert back pressure on the reservoir, and will raise the gas injection pressure, thereby reducing the inflow from the reservoir. Additionally, gas pockets will begin to surround the down-hole pump, starving the pump for liquids and causing pump inefficiencies and shut downs. Thus, the production rate is further reduced and the purpose of installing a higher capacity down-hole pump is defeated. Gas injection during these conditions will lower the production rate further since it will worsen the gas and liquid slugging in the casing annulus.

Another shortcoming in the prior art is many wells may not require gas injection, especially when there is sufficient reservoir energy for liquids to flow naturally up the annulus between the first and second tubing strings. Therefore, the gas injection and the associated equipment and the third tubing string and the associated wellhead are an additional expense both for installation and operation and may reduce operational effectiveness.

Another shortcoming of the prior art is the use of the annulus between the first and second tubing strings as a velocity string flow path for lifted reservoir liquids where the annular cross-sectional area is greater than the cross-sectional area inside the second tubing string, resulting in lower velocity and higher density in the lifted fluids.

Another shortcoming of the prior art is that the separation of solids from the reservoir fluids depends solely on gravity. Gravity is not always sufficient for complete separation, and solids entrained in the reservoir fluids may enter the fluid displacement device when prior separation is incomplete. Solids in a fluid displacement device can interfere with operations and cause wear and damage to the displacement device.

Another shortcoming in the prior art is that the dual stage artificial lift system is only shown using gas as the injected fluid to provide lift operations.

There is a need for an artificial lift system and method to provide an optimized artificial lift system and method for wells that have sufficient reservoir energy to flow naturally up to fluid displacement device without a third tubing string, associated wellhead, gas injection and the associated pressured gas source, gas flowline, and gas meter, while also providing the ability to install gas injection for the same well later in life when the well's reservoir energy declines sufficiently to warrant additional gas injection to aid in lifting reservoir liquids. There is also a need to perform the gas injection without having to do a major workover to remove the existing wellbore equipment.

Additionally, there is a need for a dual artificial lift system and method that provides for higher production rates should the well not need gas or fluid injection by allowing a larger fluid displacement device and/or the associated equipment.

There is also a need for an artificial lift system and method that allows a velocity string only installation to be converted to a dual artificial lift system without having to remove the entire tubular assembly from the well which will have less workover risk, save time, and cost less for installation.

Additionally, there is a need for a more efficient solid separation design that utilizes the momentum of the solids to aid in solids separation.

Yet another need exists for a dual stage artificial lift system that can use power fluid for a hydraulic pump instead of gas lift for wells that do not have a sufficient supply of gas for gas lift operations.

Additionally, there is a need for a more efficient velocity string lift design that uses the inside of the second tubing string to naturally lift liquids from the reservoir to increase the velocity and reduce the density of the lifted fluids.

There is also a need for a more efficient velocity string lift design that, when reservoir pressure requires gas injection based artificial lift, uses the annulus between the first and second tubing strings for gas injection and utilize the inside of the second tubing string as a velocity string pathway for the lifted reservoir liquids to increase velocity and reduce density of the lifted liquids.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure is related to an apparatus and system for providing artificial lift in oil and gas wells. Specifically, the present disclosure is related to providing artificial lift in vertical, directional, and horizontal portions of a wellbore.

One embodiment according to the present disclosure includes an artificial lift system for use in a wellbore extending from a surface to a subterranean reservoir containing reservoir fluids, the system comprising: a casing disposed in the wellbore; a first tubular string disposed in the casing; an upper bi-flow connector disposed in the first tubular string, a lower bi-flow connector disposed in the first tubular string below the upper bi-flow connector; a second tubular string disposed below the lower bi-flow connector and sealingly engaging the lower bi-flow connector, wherein the lower bi-flow connector allows flow between the second tubular string and the annulus between the casing and the first tubular string; a first fluid displacement device disposed in the first tubular above the upper bi-flow connector, wherein the upper bi-flow connector allows flow between an annulus formed by the casing and the first tubular string and the fluid displacement device; and a first seating nipple disposed in the first tubular string above the upper bi-flow connector, wherein the fluid displacement device is releaseably connected to the first seating nipple.

Another embodiment according to the present disclosure includes a method of modifying an artificial lift system described above by: removing the first fluid displacement pump from the releaseably connected first sealing nipple; inserting a third tubular string into the first tubular string with a second seating nipple disposed in the third tubular string; connecting the third tubular string to the upper bi-flow connector; and inserting a second fluid displacement device into the second seating nipple.

Another embodiment according to the present disclosure includes an artificial lift system for use in a wellbore extending from a surface to a subterranean reservoir containing reservoir fluids, the system comprising: a casing disposed in the wellbore; a first tubular string disposed in the casing; an upper bi-flow connector disposed in the first tubular string, a lower bi-flow connector disposed in the first tubular string below the upper bi-flow connector; a second tubular string disposed below the lower bi-flow connector and sealingly engaging the lower bi-flow connector, wherein the lower bi-flow connector allows flow between the second tubular string and the annulus between the casing and the first tubular string; a third tubular string disposed in the first tubular string above the upper bi-flow connector; a first fluid displacement device disposed in the third tubular above the upper bi-flow connector, wherein the upper bi-flow connector allows flow between an annulus formed by the casing and the first tubular string and the fluid displacement device; and a second seating nipple disposed in the third tubular string above the upper bi-flow connector, wherein the fluid displacement device is releasably connected to the second seating nipple.

Another embodiment according to the present disclosure includes a method of producing reservoir fluids using the artificial lift system described above, the method comprising: injecting a fluid from the surface into the annulus between the first and third tubing string and the first and second tubing string.

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 in order 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 and which will form the subject of the claims appended hereto.

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. 1 shows a diagram of an embodiment of the system for the first step of the two-step artificial lift system with a sucker rod pump according to the present disclosure;

FIG. 2A shows a diagram of the system of FIG. 1 with the sucker rod pump being removed as part of the installation of the second step of the two-step artificial lift system;

FIG. 2B shows a diagram of the system of FIG. 2A after removal of the sucker rod pump and during installation of a third tubing string;

FIG. 2C shows a diagram of the system of FIG. 2B after installation of the third tubing string;

FIG. 2D shows a diagram of the system of FIG. 2C after reinstallation of a sucker rod pump in the wellbore as the final part of step two of the disclosure with arrows showing the flow paths of the injection gas and reservoir liquids;

FIG. 3 shows a diagram of FIG. 2D with hydraulic pumping instead of gas lift, illustrating the flow paths of the injected fluids and reservoir fluids;

FIG. 4A shows a 3D view of the upper bi-flow connector for use with the system shown in FIGS. 1-3;

FIG. 4B shows a cut away view of the upper bi-flow connector along section line 4B-4B of FIG. 4A;

FIG. 4C shows a view of the top and bottom of the upper bi-flow connector of FIG. 4A;

FIG. 4D shows a 3D view of the lower bi-flow connector for use with the system shown in FIGS. 1-2D;

FIG. 4E shows a cut away view of the lower bi-flow connector along section line 4D-4D of FIG. 4D;

FIG. 4F is a top view of the lower bi-flow connector of FIG. 4D; and

FIG. 4G is a bottom view of the lower bi-flow connector of FIG. 4D.

The above figures are for illustration purposes only and should not be used in a limiting sense. Such as other fluid displacement systems are contemplated as well as other configurations.

DETAILED DESCRIPTION OF THE DISCLOSURE

An artificial lift system and method is proposed for lifting liquids, particularly liquid hydrocarbons, for implementation in two steps. The first step allows reservoir fluids to be lifted without fluid injection and associated fluid injection equipment. The second step allows for reservoir fluids to be lifted with gas injection without a complete reworking of the well to remove the equipment from the first step. Additionally, the two-step approach allows the addition of down-hole equipment to provide gas injection for when the well needs additional energy to aid in lifting liquids from below the fluid displacement device to above the device without having to perform a major workover to remove the existing wellbore equipment. Also, the two-step approach provides more efficient gas separation in the casing annulus while providing a higher capacity fluid displacement device. Additionally, step one of the two-step approach is less complicated and has less installation and operating costs than prior art installations for specific well conditions, such as when reservoir pressure is sufficient for reservoir liquids to flow out of the well without gas injection. Finally, the two-step approach has an improved solids separation system that uses the momentum of the solids and gravity to separate the solids from the fluid stream.

In the following descriptions, like parts are numbered similarly and drawings are not drawn to scale throughout the specifications. FIGS. 1, 2A-2D, 3, and 4A-4B are illustrated in a vertical wellbore but the disclosure is also contemplated for installations in deviated and horizontal wellbores. It is also contemplated that openings described herein may be of a different form than illustrated such as the shape of a slot, rectangular, oval, and other shapes, and that the openings may be single or multiple and aligned vertically, horizontally, askew, or randomly. Additionally, all tubular strings may be tapered with varying outer or inner diameters and there may additional tubular annular sealing devices, shear subs and other on-off devices than what is illustrated herein. It is contemplated that there may be other fluid displacement devices and associated equipment than those that are illustrated herein. Additionally, there may be one or more casing annular sealing devices or no annular casing sealing devices.

FIG. 1 shows an embodiment of a system for lifting reservoir fluids in a wellbore without gas injection, which is the first step of the two-step installation. The first step system includes a sucker rod pump 34 installed in a first tubing string 12 in a casing 10 in a wellbore. An upper bi-flow connector 14 and a lower bi-flow connector 16 are disposed in the first tubing string 12. The first step system may include an optional packer 18. On bottom of the upper bi-flow connector is an optional mud anchor 56. The optional packer 18 may be disposed between the casing 10 and the first tubing string 12 below the lower bi-flow connector 18 as well as an optional one way check sub 19 on bottom. A second tubing string 20 may be disposed inside the first tubing string 12 below the lower bi-flow connector 16. The second tubing string 20 may be attached to the lower bi-flow connector 16 so that reservoir fluids 26 moving up the second tubing string 20 flow into an inner bore 112 of the lower bi-flow connector 16 (see FIG. 4E), through one or more channel(s) 100 and outside the first tubing string 12 into an annulus 28 formed by the first tubing string 12 and the casing 10. An optional lower shroud 30 may be disposed around the lateral openings 100 (see FIG. 4D) of the lower bi-flow connector and configured to direct the reservoir fluids 26 downward in the annulus 28.

An optional upper shroud 32 may be disposed in the annulus 28 around the upper bi-flow connector 14. The upper shroud 32 may be configured to capture liquids 24 that fall out of the reservoir fluids 26 that are moving up the annulus 28. The upper bi-flow connector 14 directs the liquids 24 towards the sucker rod pump 34 disposed in the first tubing string 12 above the upper bi-flow connector 14. Rods are connected to the sucker rod pump 34 which contain seals 44 and may be disposed in seating nipple 36 within the first tubing string 12. On bottom of the sucker rod pump 34 is spacer 78 containing seals 46 which are sealingly engaged in seal bore 70. J latch 54 is above seal bore 70 and is not used in the first step system. It is contemplated that another artificial lift device may be used in place of the sucker rod pump 34 and rods 58.

In operation, the first step system provides for reservoir fluids 26 to travel up the second tubing string 20, which serves as a velocity string. These fluids 26 exit into the casing annulus 28 through channel(s) 100 of the lower bi-flow connector 16. The optional lower shroud 30 is incorporated around the lower bi-flow connector 16 to force the fluids 26 in a downward direction which utilizes the momentum of the solids in addition to gravity to separate the solids from the reservoir fluids 26. Once in the casing annulus 28, the optional packer 18 may prevent the movement of the first tubing string 12 and prevent reservoir fluids 26 from falling back down the wellbore, therefore the reservoir fluids 26 flow above the upper bi-flow connector 14. Gas 22 separates from the fluids 26 and travels to the surface. Liquids 24 fall and enter through channels 100 of the upper bi-flow connector 14, through center bore 112 (see FIG. 4A), up spacer 78 and then enter the sucker rod pump 34 where they are pumped to the surface up the first tubing string 12. Debris that enters bi-flow connector 14 and spacer 78 falls and collects into mud anchor 56.

In one embodiment, the first tubing string 12 has a 2.441-inch inner diameter and can house a larger fluid displacement device 34 and the associated equipment than prior art designs while also providing a much larger cross-sectional area in the casing annulus 28 for more efficient gas 22 separation, reduced back pressure on the reservoir, and higher production rates.

FIGS. 2A-2D show the transition from the first step system to the second step system. The second step system involves gas 22 injection from the surface to assist in lifting the reservoir fluids 26 from below a second fluid displacement device 40 to the surface. The installation of the two-step process is very cost efficient in that only the fluid displacement device 34 and its associated equipment needs to be removed from the wellbore. Once this is accomplished, a third tubing string 42 is installed inside the first tubing string 12 and is sealingly engaged to the upper bi-flow connector 14. An additional wellhead (not shown) is installed to support the third tubing string 42 and once the second fluid displacement device 40 is installed, gas 38 is injected into the annulus 28 between the first 12 and third tubing string 42. The ability to leave the first step system equipment in the well without disturbing or removing it is very valuable because of the inherent risks in removing equipment from a wellbore and the associated cost savings. All the first step equipment is necessary for a second step installation, except for the second fluid displacement device 42, which may be the same or a similar sized device as the first fluid displacement device 34 or it may be replaced with a smaller sized or a dissimilar fluid displacement device configured to fit in a smaller tubing string.

FIG. 2A shows the removal of the sucker rod pump 34 and its associated equipment (seals 44 & 46, spacer 78, rods 58, etc.). FIG. 2B shows the installation of a third tubing string 42 containing spacer 78, on-off lugs 62, and seals 46 which are all installed in the first tubing string 12. The third tubing string 42 is disposed above the upper bi-flow connector 14 and includes a seating nipple 60 configured to receive a second fluid displacement device 40. FIG. 2C shows the third tubing string 42 in position within the first tubing string 12 with seals 46 engaged in seal bore 70 and on-off lugs 62 engaged in j latch 54 to prevent movement of the second fluid displacement device 40 during pumping operations. FIG. 2D shows the pathway of the various fluids during the operation of the second fluid displacement 40 device. The annulus 48 between the third tubing string 42 and the first tubing string 12 forms a path for injected gas 38 to flow downward into channels 102 of the upper bi-flow connector 14 and further downward through channels 102 of the lower bi-flow connector 16 and into the annulus 76 between the second tubing string 20 and the first tubing string 12.

In operations, the second step system injects gas 38 into the well from the surface and travels down the annulus 38 between the first 12 and third tubing string 42. The injection gas 38 passes through channels 102 of the upper bi-flow connector 14 and through the 102 of the lower bi-flow connector through the annulus 76 between first tubing 12 and second tubing 20. The gas 38 then enters the second tubing string 12 and commingles with reservoir fluids 26 to become commingled fluids 25 which flow up the second tubing string 20 and then exits into the casing annulus 28 through channels 100 of the lower bi-flow connector 16. The optional shroud 30 forces the lifted commingled fluids 25 in a downward direction and the momentum of the solids along with gravity separate the solids from the fluids 25. The fluids 25 are prevented from falling back down the wellbore by the packer 18. Gas 22 separates from the fluids 25 and travels to the surface while the liquids 24 fall and enter through the channels 100 of the upper bi-flow connector 14 and enter the second fluid displacement device 40 where the liquids 24 are pumped to the surface up the third tubing string 42.

FIG. 3 shows another embodiment of the second step system where a hydraulic pump 50 is used instead of gas injection 38 to lift the reservoir fluids 26. The hydraulic pump 50 is disposed in the second tubing string 20 below the lower bi-flow connector 16. If an optional packer 18 is present, the hydraulic pump 50 is disposed below the optional packer 18. The hydraulic pump 50 may be seated in a seating nipple 75 disposed in the second tubing string 20 that contains seals 23 to seat in a seating nipple 21. A one-way check sub 19 is installed below the seating nipple 21. It is also contemplated to allow the hydraulic pump 50 to be removed and re-installed from the wellbore via a wireline unit for purposes of repair or replacement. This may be accomplished by also removing plug 66 from the seating nipple 72 in mud anchor 56, and removing plug 68 from seal bore 74 with-in the lower bi-flow connector 16. It is also contemplated that the seal bore 74 be connected above and not a part of bi-flow connector 16. In that instance, bi-flow connector 16 would be essentially the same as bi-flow connector 14. The operations of FIG. 3 are the same as FIG. 2D.

A major benefit of the first step system is that a major workover is not required when converting to a second step system, unlike prior art systems. Additionally, the optional shroud 30 incorporated to surround the lower bi-flow connector 16 using the momentum of the solids and gravity provides improved solids separation.

FIG. 4A shows an upper bi-flow connector 14 which includes a body 111 with an upper end 105 and a lower end 107 with one or more lengthwise channels 102 through a thickness of body 111 from the upper end 105 to the lower end 107. The body 111 also has an inner bore 112 running from the upper end 105 to the lower end 107. Inner bore 112 contain internal threads 106 on end 105 and internal threads 110 on end 107 (see FIG. 4B-4C) that allows a tubular to be connected to inner bore 112 on end 105 and 107. As shown the inner bore 112 is circular and in the center of the body 111; however, other embodiments are contemplated where the inner bore 112 is offset from the center and/or is not circular in shape. One or more side channels 100 run through the thickness and into the inner bore 112. Channels 100 and 102 do not intersect. End 105 may contain external threads 104 and end 107 may contain external threads 108 that allow the bi-flow connector 14 to be connected to a tubing string.

FIG. 4B shows a cut away view of bi-flow connector 14 along lines 4B-4B of FIG. 4A with end 105 and 107, center bore 112, external threads 104 and internal threads 106 on end 105 and external threads 108 and internal threads 110 on end 107.

FIG. 4C shows a view of end 105 or 107 of bi-flow connector 14 with a thickness 109, channels 102, center bore 112, and internal threads 106 or 110.

FIG. 4D shows a lower bi-flow connector 16 like the upper bi-flow connector 14 except the inner bore 112 on end 105 is plugged and does not contain internal threads 106.

FIG. 4E shows a cut away view of bi-flow connector 16 along lines 4E-4E of FIG. 4D with end 105 and 107, center bore 112, external threads 104 on end 105 and external threads 108 and internal threads 110 on end 107.

FIG. 4F shows a top view of end 105 of bi-flow connector 16 with channels 102 and body 111.

FIG. 4G shows a bottom view of end 107 of bi-flow connector 16 showing a thickness 109, body 111, channels 102, and internal threads 110.

While the disclosure has been described with reference to exemplary embodiments, it will be understood that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the disclosure. 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 not be limited to the particular embodiment 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.

Claims

1. An artificial lift system for use in a wellbore extending from a surface to a subterranean reservoir containing reservoir fluids, the system comprising:

a casing disposed in the wellbore;

a first tubular string disposed in the casing;

an upper bi-flow connector disposed in the first tubular string,

a lower bi-flow connector disposed in the first tubular string below the upper bi-flow connector;

a second tubular string disposed below the lower bi-flow connector and sealingly engaging the lower bi-flow connector, wherein the lower bi-flow connector allows flow between the second tubular string and the annulus between the casing and the first tubular string;

a first fluid displacement device disposed in the first tubular above the upper bi-flow connector, wherein the upper bi-flow connector allows flow between an annulus formed by the casing and the first tubular string and the fluid displacement device; and

a first seating nipple disposed in the first tubular string above the upper bi-flow connector, wherein the fluid displacement device is releaseably connected to the first seating nipple.

2. The artificial lift system of claim 1, wherein said upper bi-flow connector comprises a tubular that contains a center bore in communication with one or more horizontal channel(s) that extend through the width of the device, and one or more vertical channel(s) that extend through the length of the device, and said horizontal channel(s) and said vertical channel(s) do not communicate with-in said bi-flow tool

3. The artificial lift system of claim 2, wherein said center bore extends to the upper end of said upper bi-flow connector but does not extend to the lower end of said upper bi-flow connector

4. The artificial lift system of claim 2, wherein said center bore extends to the upper and lower end of said upper bi-flow connector

5. The artificial lift system of claim 1, wherein said lower bi-flow connector comprises a tubular that contains a center bore in communication with one or more horizontal channel(s) that extend through the width of the device, and one or more vertical channel(s) that extend through the length of the device, and said horizontal channel(s) and said vertical channel(s) do not communicate with-in said bi-flow tool and said center bore extends to the lower end of said tubular but does not extend to the upper end of said tubular

6. The artificial lift system of claim 1, further including one or more casing annular sealing device or devices installed in said first tubing string below said lower bi-flow connector

7. The artificial lift system of claim 6, further including a one-way check sub installed in said first tubing string below said casing annular sealing device(s)

8. The artificial lift system of claim 1, further including an upper shroud surrounding said upper bi-flow connector and a lower shroud surrounding said lower bi-flow connector

9. A method of modifying the artificial lift system of claim 1, the method comprising:

removing the first fluid displacement device from the releaseably connected first sealing nipple;

inserting a third tubular string into the first tubular string with a second sealing nipple disposed in the third tubular string;

connecting the third tubular string to the upper bi-flow connector; and

inserting a second fluid displacement device into the second sealing nipple

10. An artificial lift system for use in a wellbore extending from a surface to a subterranean reservoir containing reservoir fluids, the system comprising:

a casing disposed in the wellbore;

a first tubular string disposed in the casing;

an upper bi-flow connector disposed in the first tubular string,

a lower bi-flow connector disposed in the first tubular string below the upper bi-flow connector;

a second tubular string disposed below the lower bi-flow connector and sealingly engaging the lower bi-flow connector, wherein the lower bi-flow connector allows flow between the second tubular string and the annulus between the casing and the first tubular string;

a third tubular string disposed in the first tubular string above the upper bi-flow connector;

a first fluid displacement device disposed in the third tubular above the upper bi-flow connector, wherein the upper bi-flow connector allows flow between an annulus formed by the casing and the first tubular string and the fluid displacement device; and

a second seating nipple disposed in the third tubular string above the upper bi-flow connector, wherein the fluid displacement device is releaseably connected to the second seating nipple

11. The artificial lift system of claim 10, wherein said upper bi-flow connector comprises a tubular that contains a center bore in communication with one or more horizontal channel(s) that extend through the width of the device, and one or more vertical channel(s) that extend through the length of the device, and said horizontal channel(s) and said vertical channel(s) do not communicate with-in said bi-flow tool

12. The artificial lift system of claim 10, wherein said center bore extends to the upper end of said upper bi-flow connector but does not extend to the lower end of said upper bi-flow connector

13. The artificial lift system of claim 10, wherein said center bore extends to the upper and lower end of said upper bi-flow connector

14. The artificial lift system of claim 10, wherein said lower bi-flow connector comprises a tubular that contains a center bore in communication with one or more horizontal channel(s) that extend through the width of the device, and one or more vertical channel(s) that extend through the length of the device, and said horizontal channel(s) and said vertical channel(s) do not communicate with-in said bi-flow tool and said center bore extends to the lower end of said tubular but does not extend to the upper end of said tubular

15. The artificial lift system of claim 10, further including one or more casing annular sealing device or devices installed in said first tubing string below said lower bi-flow connector

16. The artificial lift system of claim 15, further including a one-way check sub installed in said first tubing below said casing annular sealing device(s)

17. The artificial lift system of claim 10, further including a third fluid displacement device installed in the second tubular string

18. The artificial lift system of claim 17, further including one or more removeable plugs located in or between said upper and lower bi-flow connectors to allow said third fluid displacement device to be retrieved without having to remove wellbore tubulars

19. The artificial lift system of claim 10, further including an upper shroud surrounding said upper bi-flow connector and a lower shroud surrounding said lower bi-flow connector

20. A method of producing reservoir fluids using the artificial lift system of claim 10, the method comprising:

injecting a fluid from the surface into the annulus between the first and third tubing string and the first and second tubing string.