Downhole system and method for selectively producing and unloading from a well

A downhole system and method for producing and unloading from a well unloads a first fluid through a tubular in the well while blocking flow of a second fluid into the tubular. In an alternate mode, the second fluid is produced through the tubular while the first fluid is blocked from entering the tubular. In another alternate mode, a third fluid is unloaded through the tubular at the same the second fluid is produced from the well and through the tubular. In yet another alternate mode, the second fluid is pressurized downhole. In one example, the first fluid includes water, the second fluid includes a hydrocarbon gas, and the third fluid includes a hydrocarbon liquid. Means for unloading include a pump, means for pressurizing the second fluid include a compressor, and means for selectively blocking flow includes a flow circuit with one-way valves.

BACKGROUND OF THE INVENTION

1. Field of Invention

The present disclosure relates to unloading a fluid from a hydrocarbon producing well. More specifically, the present disclosure relates to unloading liquid from a hydrocarbon producing well; and also producing gas hydrocarbon from the well without adding or removing equipment to or from the well.

2. Description of Prior Art

Hydrocarbons trapped in a subterranean formation are typically extracted by excavating a wellbore from surface that intersects the formation; and producing the hydrocarbons by directing them up the wellbore to surface. The wellbore is usually completed prior to hydrocarbon production, which generally involves lining most of the wellbore with casing, inserting production tubing inside the casing, and installing a production tree for controlling pressure in the wellbore and distributing produced fluids from the wellbore. Artificial lift is sometimes employed when pressure in the formation is insufficient to drive the hydrocarbons up the wellbore to surface. Types of artificial lift currently in use include electrical submersible pumps, jet/hydraulic pumps, sucker rods, compressors and gas lift.

Gas wells can sometimes experience an accumulation of liquid, such as hydrocarbon condensate or connate water from the formation. If the accumulation is sufficient, gas flow into the well is sometimes impeded that in turn reduces the amount of gas from the well. In more severe instances, the amount of liquid accumulated in the well prevents gas from flowing into the well thereby ceasing production. A well having an amount of accumulated liquid sufficient to affect gas production is sometimes referred to as a loaded well; similarly, removing the accumulated liquid is referred to as unloading a well. Wells that produce an appreciable amount of liquid are usually equipped with liquid artificial lift systems, which can sometimes unload a well without the need for intervention. Wells that produce primarily gas often do not include means for unloading liquids, and usually require a well intervention procedure to unload accumulated liquid. One technique currently employed for unloading accumulated liquid from a well involves injecting nitrogen into the well through coiled tubing; which is costly and can be a safety risk to operations personnel. Accordingly, a need exists for a cost effective and safe way to unload liquid accumulated in a gas well.

SUMMARY OF THE INVENTION

Disclosed is an example of a downhole system for handling fluids in a well and which includes a submersible pump having a pump inlet in communication with liquid in the well and a pump discharge selectively at a pressure that is greater than a pressure at the pump inlet, and a fluids handling circuit. The fluids handling circuit of this example includes a pump discharge line having an inlet in fluid communication with the pump discharge and an exit in selective communication with a bore that is inside of production tubing installed in the well, a gas feed line having an inlet in communication with gas in the well and an outlet in selective communication with the bore, a barrier to a flow from the gas feed line to the pump, and a barrier to a flow of a fluid from the pump discharge line to the inlet of the gas feed line. In an example, a barrier is included between a flow in the gas feed line to the pump, and which is a one-way valve in the pump discharge line, and wherein the barrier between a flow of a fluid in the pump discharge line to the inlet of the gas feed line is a one-way valve in the gas feed line. In this example, the one-way valve in the pump discharge line is selectively openable when a pressure in the pump discharge line is at least as great as a pressure in the gas feed line so that fluid discharged from the pump flows into the bore to define an unloading mode. In an alternative, the one-way valve in the gas feed line is selectively openable when a pressure in the gas feed line is at least as great as a pressure in the pump discharge line so that fluid in the gas feed line flows into the bore to define a production mode. In this example, the fluid in the pump discharge line includes liquid (condensate and/or connate water) accumulated in the well, and wherein the system is in the production mode when the liquid in the well is below a first designated liquid level, and wherein the system is in the unloading mode when the liquid in the well is above a second designated liquid level. In an embodiment the fluids handling circuit is in a crossover bulkhead. In an embodiment, the system includes a compressor having a compressor inlet in fluid communication with gas in the well through a compressor inlet line disposed in a lower bulkhead, and a compressor discharge that is selectively at a pressure greater than a pressure in the well, and where the fluids handling circuit further includes a compressor discharge line having an end in communication with the compressor discharge and that is in fluid communication with the bore. One example of the system includes a barrier to a flow from the gas feed line to the compressor, and a barrier to a flow of a fluid from the pump discharge line to the compressor. In an embodiment, a fluid flowing in the bore is fluid from two or more of fluid flowing through the gas inlet line, fluid being discharged from the compressor, and fluid being discharged from the pump.

An alternate example of a downhole system for handling fluids in a well is disclosed and which includes a submersible pump having a liquid inlet in fluid communication with liquid in the well, a gas feed line having a gas inlet in fluid communication with gas in the well, and a fluids handling circuit. The fluids handling circuit of this example includes an upstream end in communication with a discharge of the submersible pump and an end of the gas feed line distal from the inlet of the gas feed line, a downstream end in communication with the upstream end and also in communication with a bore of a production tubular installed in the well, and barriers that block a flow of fluid from within the fluids handling circuit to the gas inlet and to the submersible pump. In an example, the pump is driven by a pump motor, and wherein pressure in the motor is equalized to pressure in the well with a pump seal, and wherein the pump, pump motor, and pump seal define an electrical submersible pumping assembly, the system further comprising a pod circumscribing a portion of the pumping assembly, and wherein fluid discharged from the pump flows through a pump discharge line that is routed through the pod. In an example, a cross over assembly is included in which the fluids handling circuit is disposed, and wherein the inlet of the gas feed line is flush with an outer surface of the cross over assembly. Embodiments exist having a compressor with a compressor inlet in communication with gas in the well, a compressor exit in communication with the fluids handling circuit, a barrier that blocks flow from the fluids handling circuit to the exit, and wherein the compressor is selectively operated in a standby mode so that pressure at the compressor exit and inlet are substantially the same, selectively operated in a first operational mode so that pressure at the compressor exit exceeds a pressure at the compressor inlet, and selectively operated in a second operational mode so that pressure at the compressor exit exceeds a pressure at the compressor inlet and fluid in the production tubing comprises a mixture of gas discharged from the compressor and liquid discharged from the pump.

Also disclosed is a method of handling fluid in a well that includes operating in an unloading mode by directing a pressurized liquid within a pressurized liquid flow path within a downhole assembly and to a bore of a production tubular that is installed in the well, and flowing the pressurized liquid through the bore to a wellhead assembly set over the well, operating in a production mode when not operating in the unloading mode by directing gas from within the well and through a gas flow path within the downhole assembly and to the bore, blocking a flow of the pressurized liquid from entering the gas flow path when in the unloading mode, and blocking a flow of the gas from entering the pressurized liquid flow path when in the production mode. The method optionally includes monitoring an amount of a liquid in the well, and operating in the unloaded mode when a level of the liquid in the well is above a designated liquid level, and wherein the pressurized liquid comprises liquid in the well that is pressurized by a pump in the well. The method also optionally includes monitoring an amount of a liquid in the well, and operating in the production mode when a level of the liquid in the well is below a designated liquid level. In an alternative, the method includes operating in a gas production mode by directing pressurized gas from within the well through a pressurized gas flow path within the downhole assembly and to the bore, blocking a flow of the pressurized gas from entering the gas flow path, and blocking a flow of the pressurized gas from entering the pressurized liquid flow path, and wherein the step of operating in the gas production mode is performed when not in the unloading mode. This example further optionally includes operating in a mixed production mode by directing a pressurized liquid along the pressurized fluid path to the bore while also operating in the unloading mode. In one embodiment, a pump is used in the well to pressurize the liquid in the well to define the pressurized liquid, using a compressor in the well to pressurize the gas. Examples exist where the pressurized liquid includes hydrocarbons, water, or a combination.

DETAILED DESCRIPTION OF INVENTION

The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of a cited magnitude. In an embodiment, the term “substantially” includes +/−5% of a cited magnitude, comparison, or description. In an embodiment, usage of the term “generally” includes +/−10% of a cited magnitude.

Shown in partial side sectional views inFIGS. 1A and 1Bis a schematic example of a downhole system9for use in unloading and producing from a wellbore11that is lined with casing12. InFIG. 1A, downhole system9is shown in a loaded mode, and in use for unloading liquid from within wellbore11that has accumulated. In the illustrated example, fluid F enters wellbore11from a formation13surrounding wellbore11and through perforations15shown radially outward from wellbore11, through casing12, and into formation13. In the illustrated examples, fluid F primarily includes gas with amounts of liquid. As shown inFIG. 1A, liquid included with fluid F collects within wellbore11over time; which is referred to herein as accumulated liquid AL. Embodiments exist where an amount of gas or vapor is included within the accumulated liquid AL. An upper surface of the accumulated liquid AL is at a height or location within wellbore11which defines a liquid level LL of the accumulated liquid AL in wellbore11. Further shown is that the liquid level LL is above the perforations15. As illustrated inFIGS. 1A and 1B, liquid level LL is substantially perpendicular with axis AXof wellbore11. Alternate examples exist where liquid level LL is oblique with axis AXof wellbore11, such as when the liquid level LL is in a deviated portion of wellbore11. Further optionally, embodiments exist where perturbations of fluid F flowing into wellbore11disrupt the surface of the liquid level LL. Included with the downhole system9is a downhole assembly17which is illustrated mounted to a lower end of production tubing19that is installed within the wellbore11. Inside tubing19is a bore20and through which liquid L is transported to a wellhead assembly21shown on surface S and mounted over an opening of the wellbore11. In an example, liquid L is obtained from the accumulated liquid AL; and a packer23is illustrated in the annular space between tubing19and sidewalls of wellbore11and uphole from downhole assembly17. A power cable25is shown within wellbore11and along the outer surface of the production tubing19. In an example, electricity and/or signals are communicated along power cable25between surface S and the downhole assembly17.

An example of a lift system27is schematically illustrated, and which is part of the downhole assembly17. A pod29circumscribes a portion of lift system27and in one example is made up of an outer housing that forms a cavity. Also schematically illustrated is one example of a cross over bulkhead31, and which is shown on an end of the downhole assembly17adjacent production tubing19. On a lowermost end of the lift system27a schematic example of a gas separator33is shown. Inlet ports35are illustrated formed along an outer surface of gas separator33; in an example of operation, accumulated liquid AL is drawn into ports35, and inside gas separator33gas G is removed from within accumulated liquid AL. The gas G separated from the accumulated liquid AL is discharged back into wellbore11from the gas separator33through gas discharge ports37shown on an outer surface of the separator33. Liquid L results from removing gas G from accumulated liquid AL; liquid L exits the separator33and is directed to a pump39that is schematically illustrated on a side of separator33proximate production tubing19. Discharge fluid exiting pump39flows through pod29towards upper bulkhead31and is directed into a line40within upper bulkhead31.

Still referring toFIG. 1A, inside the crossover bulkhead31line40is intersected by a gas feed line42at a junction43. In alternate embodiments, each of lines40,42connect directly into tubing19and communicate separately into bore20, line40intersects into line42, or lines40,42terminate at a manifold (not shown) that is in communication with bore20. An inlet44is shown on an end of the gas feed line42distal from junction43. Inlet44in the example ofFIG. 1Aprojects radially outward from an outer surface of the crossover bulkhead31. Alternate embodiments exist where the inlet44is substantially flush with or recessed within the outer surface of the cross over bulkhead31. One-way valves45,46are shown disposed respectively in lines40,42. One-way valve45allows flow in pump discharge line40in a direction from inlet41to junction43, and blocks fluid downstream of one-way valve45(i.e. on a side of one-way valve45opposite inlet41) from flowing towards pump39. Similarly, one-way valve46allows flow in gas feed line42from inlet44to junction43, and blocks fluid that is downstream of one-way valve46(i.e. on a side of one-way valve46opposite from inlet44) from flowing towards inlet44. In the illustrated example, the lines40,42and one-way valves45,46define a fluids handling circuit47. Further illustrated in the example ofFIG. 1Ais where an outlet48of the fluids handling circuit47connects to an end of production tubing19in the wellbore11and opposite wellhead assembly21. In this example, the outlet48is in fluid communication with bore20, as such the pump discharge and inlet44to the gas feed line42are in selective communication with bore20through the fluids handling circuit47and its outlet48.

A pump seal49is illustrated on a side of pump39opposite from the gas separator33and which provides a pressure equalizing functionality for a pump motor51which is also schematically illustrated within the lift system27and on a side of the pump seal49opposite from pump39. In an alternative, a monitoring sub53is set between the pump motor51and cross over bulkhead31. Examples of the monitoring sub53exists where the monitoring sub53includes sensors for monitoring conditions downhole, such as temperature and pressure, and also in one alternative include systems for monitoring functions of the pump motor51and pump39.

Referring now toFIG. 1A, as noted above liquid level LL of accumulated liquid AL is above perforations15; and which in the illustrated example impedes flow of fluid F from perforations of gas into wellbore11. For the purposes of illustration, wellbore11ofFIG. 1Ais in a loaded condition. In a non-limiting example of operation, wellbore11is changed from its loaded condition by activating pump39by energizing motor51. Further in this example, activating pump39drives impellers (not shown) within pump39that pressurize liquid L received by pump39to form pressurized liquid LP, and drive the pressurized liquid LPthrough the pump discharge line40, the fluids handling circuit47, and into the bore20where the pressurized fluid LPis delivered to the wellhead assembly21. In the example ofFIG. 1Adownhole system9is in what is referred to as an unloading mode. At wellhead assembly21, the pressurized liquid LPis selectively directed to offsite facilities, or facilities adjacent the well site for further processing. In one example, liquid L includes primarily water, yet other examples include where liquid L is hydrocarbon that has condensed within wellbore11and accumulated over time. In an example, a decision to operate the downhole system9in the unloading mode is based on a height of the liquid level LL or its location within wellbore11. Example heights or locations triggering the decision to operate in the unloading mode described herein include when liquid level LL is above all perforations15, when liquid level LL is between perforations15, or the liquid level LL is below all of perforations15. It is believed it is within the capabilities of those skilled to determine a suitable liquid level LL for prompting a decision to move to an unloading mode within wellbore11. In an example, a pressurized liquid flow path is defined along the route taken by pressurized liquid LPbetween the discharge of the pump39and to the outlet48.

Shown in the example ofFIG. 1Bis the downhole system9in a production mode where gas G within wellbore11flows into the gas feed line42through the inlet44, and within the fluids handling circuit47is directed into the bore20for transport to the wellhead assembly21. In an example, a gas flow path is defined along the route taken by gas G flowing from within the wellbore11and to the outlet48. In the production mode pump39is not being operated and liquid L is not being lifted to surface S. Similar to the unloading mode, in the production mode gas G flowing inside bore20to wellhead assembly21is directed from within wellhead assembly21to lines for transporting the gas away from the wellsite. While in the flow circuit47, one-way valve45in the pump discharge line40prevents the gas G from flowing through the pump discharge line40and back to the pump39. Further shown in the example ofFIG. 1Bis that liquid level LL has dropped to below perforations15and so that production of gas from wellbore11is not impeded by the accumulation of the liquid within wellbore11. In a non-limiting example of operation, the downhole assembly17is part of the initial installation when completing the wellbore11. In an alternative, the downhole assembly17is added into wellbore11after wellbore11has been producing for a period of time, and where the conditions of the gas being produced, such as its pressure and volume, allow for an amount of accumulated liquid L in the wellbore11dictating a step of unloading with sufficient regularity to justify the expense of adding the downhole assembly17. An advantage of the downhole assembly17over that of other known ways of unloading gas wells is that liquid unloading is possible without the need to suspend production of gas G from wellbore11for a lengthy period of time.

An alternative embodiment of a portion of the downhole system9A having the downhole assembly17A is shown in side sectional view inFIGS. 2A through 2C. Also illustrated are examples of additional modes of operation. In the example ofFIG. 2A, a compressor55A is included with the downhole assembly17A and which is set in a compressor section57A and shown adjacent the cross over sub31A and on a side opposite from where cross over sub31A attaches to tubing19A. Also included in this example is a compressor motor59A for driving compressor55A and a compressor seal61A for equalizing pressure in the compressor motor59A. In an alternative, compressor seal61A also absorbs thrust loads from compressor55A. In this example, compressor seal61A is on a side of compressor section57A opposite from crossover assembly31A and compressor motor59A is on a side of compressor seal61A opposite from the compressor section57A. Monitoring sub53A is illustrated set adjacent a side of the compressor motor59A opposite the compressor seal61A. Also included in the example illustrated inFIGS. 2A through 2Cis a lower cross over bulkhead63A which circumscribes a portion of the pod29A. Inlet66A on the compressor inlet line65A is shown projecting radially outward from an outer surface of pod63A and on a side opposite from where compressor inlet line65A next to an inlet of the compressor55A. Alternate examples exist in which inlet line65A terminates at or within housing of lower cross over bulkhead63A, and inlet66A is flush or within the outer surface of bulkhead63A. A passage64A is shown formed axially through bulkhead63A to allow a flow of liquid L from pump39A.

In the illustrated example, a compressor discharge line67A connects to a discharge of compressor55A on one end and to junction43A on its other. In this embodiment, the compressor discharge line67A makes up part of the fluids handling circuit47A ofFIGS. 2A through 2C. It should be pointed out that embodiments of the piping arrangement exist that are different from the lines meeting at junction43A; alternatively, in an alternative lines40A,67A,42A are in communication with bore20A of production tubing19A through a manifold-type arrangement, in another alternative lines40A,67A,42A join one another at different locations on their way to the bore20A. In the illustrated example, a one-way valve69A is disposed in line65A and that allows flow through line65A from inlet66A to compressor55A, and blocks flow of fluid downstream of one-way valve69A (i.e. on a side of one-way valve69A opposite inlet66A) from flowing to inlet66A. Similarly, a one-way valve71A in line67A allows flow in line67A flowing from compressor55A towards junction43A and blocks a flow of fluid downstream of one-way valve71A (i.e. on a side of one-way valve71A opposite compressor55A) towards compressor55A. Examples exist where each of one-way valves45,46(FIG. 1A) and45A,46A,69A,71A (FIG. 1B), are check valves, motor operated valves, hydraulically actuated valves, or combinations thereof. Further optionally, one-way valves45,46,45A,46A,69A,71A are controlled to open and close in sequences that are consistent with the designated operating mode of the downhole system9,9A. Further illustrated inFIGS. 2A through 2Cis a second power line73A that in one example is used for powering the compressor motor59A as well as providing signal communication from the downhole assembly17A into surface.

Referring now toFIG. 2A, liquid level LL of accumulated liquid AL is shown above perforations15A; which in an alternative is at or above a designated liquid level of accumulated liquid within wellbore11A, or set point, which triggers the downhole assembly17A to operate in the unloading mode. In the example ofFIG. 2Aaccumulated liquid AL flows into the gas separator33A to obtain amounts of liquid L and gas G. The liquid L obtained from the accumulated liquid AL is directed to pump39A where it is pressurized, and then into bore20A via the fluids handling circuit47A. As discussed above, one-way valves45A,71A prevent the flow of pressurized liquid L by pump39A from flowing to the inlet44A or to the compressor55A. In an example, a pressurized liquid flow path is defined along the route taken by pressurized liquid LPbetween the discharge of the pump39A and to the outlet48A.

In the example ofFIG. 2Ban amount of the accumulated liquid AL has been removed during the unloading mode ofFIG. 2Aso that liquid level LL is below perforations15A. In a non-limiting example of operation, conditions in the wellbore11A dictate that the unloading mode of the downhole assembly17A is suspended, and that the downhole assembly17A operate in the production mode. In the example of a production mode as shown inFIG. 2B, gas G flows from within the wellbore11A to the bore20A of production tubing19A. In this example of the production mode, pressure of gas G within wellbore11A is sufficient to flow into inlet44A, past one-way valve46A in line42A, to outlet48A, and up the string of production tubing19A to the wellhead assembly21ofFIG. 1. In an example, a gas flow path is defined along the route taken by gas G from the wellbore11A and to the outlet48A. One-way valves45A,71A block flow of the gas G back to the pump39A and compressor55A. For the purposes of discussion herein, the wellbore11A is operating in a passive production mode when pressure of gas G in wellbore11A is at a magnitude to overcome the gravitational and frictional losses encountered while being handled by the downhole system9A and reach wellhead assembly21(FIG. 1A) on surface S at or above a designated pressure. In this example a designated pressure of the gas G at the wellhead assembly21A is such that the gas G is at a pressure adequate to direct the gas G to a desired destination without additional pressurization. It is within the capabilities of one skilled in the art to identify a designated pressure of the gas G at surface S. In an embodiment, compressor55A is not operating and in a standby mode during the passive production mode.

An alternative production mode occurs when pressure of gas G in wellbore11A is insufficient to flow to the wellhead assembly21A and gas G is pressurized by compressor55A; which for the purposes of discussion is referred to as an active production mode. In this example, compressor55A is activated by energizing compressor motor59A which then draws gas G through inlet66A, into line65A across valve69A and into compressor55A where the gas G is pressurized within compressor55A and discharged into the compressor discharge line67A as pressurized gas GP. The pressurized gas GPis then routed to bore20A through the fluids handling circuit47A and follows the same route as the gas G in the passive operating mode. Similar to the other operating modes discussed within, valves46A,45A prevent flow of gas pressurized by compressor55A from entering wellbore11A through the gas feed line42A or back to the pump39A through the pump discharge line40A. In an example, a pressurized gas flow path is defined along the route taken by pressurized gas GPbetween the discharge of the compressor55A and to the outlet48A.

Another alternative production mode is illustrated inFIG. 2Cwhere a combination of liquid L and gas G is being directed within bore20A of production tubing19A and to wellhead assembly21A; and for the purposes of discussion this production mode is referred to as a mixed production mode. In an embodiment of the mixed production mode the pump39A is operating in conjunction with production of gas G through the gas feed line42A. In another embodiment of the mixed production mode, the pump39A operates in conjunction with operation of the compressor55A as discussed above. In this example, the motor39A is operated such that the pressurized liquid LPat the junction43A is substantially that of pressure of pressurized gas GPat junction43A so that the combined flows of pressurized liquid LPand pressurized gas GPmake up a combined flow up the bore20A.

An example controller75is schematically illustrated inFIGS. 1A and 1Bwhich is in communication with the downhole assembly17via communication means77. Similarly, controller75A and communication means77A are in communication with the downhole assembly17A of embodiments shown inFIGS. 2A through 2C. In a non-limiting example of operation, a mode of operation is suspended in response to the liquid level LL within wellbore11,11A. In another non-limiting example of operation, a mode of operation is initiated in response to the liquid level LL in wellbore11,11A. Examples exist where the liquid level LL triggering suspension of or activation of a mode of operation is above the perforations15,15A (i.e. between perforations15,15A and packer23,23A), adjacent the perforations15,15A, or below the perforations15,15A (i.e. on a side of perforations15,15A opposite the packer23,23A). In an example, a liquid level LL established that triggers suspension or activation of a mode of operation is referred to as a designated liquid level. A further example exists where sensors (not shown) are disposed in the wellbore11,11A for monitoring when the liquid level LL reaches a designated level. Signals for communicating between the controller75,75A and downhole assembly17,17A are optionally delivered via power cables25,25A,73A. Examples of communication means77,77A include hardwired, wireless, telemetry, and fiber optics. In an alternative, an information handling system (“IHS”) is included within controller75,75A. In an example, IHS is in communication with the sensors, and determines when and if to generate a command initiating operation of the pump39,39A and/or compressor55A. In an example, IHS includes one or more of a processor, memory accessible by the processor, nonvolatile storage area accessible by the processor, and logics for performing each of the steps above described. Further examples exist where the rate at which accumulated liquid AL increases within wellbore11,11A is monitored and where the operational modes of unloading may then be triggered at a liquid level LL that is different from situations of a lower rate of increase.