Critical velocity reduction in a gas well

Disclosed herein is a system for enhancing the recovery of gas in a perforated interval of a gas well. The system features a tubing string having a dead string attached for reducing the flow area of the annulus in the perforated interval, thereby reducing the critical velocity of the gas, i.e., the velocity required to overcome backpressure due to fluids in the well column. The system includes a ported member for receiving gas from the annulus into the tubing string. The ported member and the dead string are isolated from each other by a retrievable plug. The disclosed system provides access from the surface through the dead string for diagnostic or corrective operations. The system also provides delivery of reagents such as foamers to the perforated region to further reduce the critical velocity.

FIELD OF THE INVENTION

The invention relates to the recovery of natural gas from natural gas wells and more particularly concerns an apparatus for reducing the critical velocity required to unload extended perforated intervals in liquid-loaded gas wells.

BACKGROUND OF THE INVENTION

FIG. 1illustrates a production tubing string13deployed in a cased natural gas wellbore101having an extended perforated interval102. The production rate of a natural gas well is a function of the pressure differential between the underground reservoir and the well head. This differential is decreased by back pressure against the reservoir pressure. As natural gas and associated liquids are extracted during production, a gradual loss of reservoir pressure occurs in some natural gas wells, thus decreasing the pressure differential. Natural gas wells produce liquids such as water and hydrocarbon. Removal of these produced liquids depends on the velocity of the gas stream produced from the formation. As reservoir pressure and flow potential decrease, there is a corresponding drop in the flow velocity of the natural gas through the production tubing to the well head. Eventually, when the flow velocity becomes insufficient to overcome the “fall back” velocity of the liquids, a column of liquids accumulates in the well bore. This phenomenon referred to as liquid loading decreases the production of the well because the weight of the fluid column above the producing formation causes additional back pressure, which the reservoir must overcome. The critical velocity is the flow velocity or flow rate(mcf/d) required to overcome this pressure differential needed to lift produced fluids to surface.

FIG. 2illustrates one of the methods that have been used in the art to overcome the problem of liquid loading. Production tubing13is extended to include a ported tubing section17and a “dead string”14. Ported tubing section17can be a length of production tubing, for example one joint of production tubing or a smaller length of tubing i.e., a pup joint, having holes18drilled therein. The inner diameter (ID) of production tubing section13and the ID of dead string14are isolated from each other by plug15. Alternatively, this design can include a “bull plug” on the bottom of dead string14to force the flow up to the ported section17. Thus, fluids do not flow through the ID of dead string14. Rather, the function of dead string14is to decrease the area of the annular space106between the dead string and the face of the wellbore (or casing). During operation, gas and formation fluids11in perforated interval102flow in the annular region106around dead string14. Dead string14typically has a larger outer diameter (OD) than production tubing section13, though the dead string14can also be the same size as the production tubing13. For example, in a well with 4½″ casing having an ID of 4″, the production string might have an OD of 2⅜″ and the dead string might have an OD of 2⅞″. Dead string14reduces the flow area in the perforated interval, thereby decreasing the required flow rates (critical velocities) to lift produced liquid in the wellbore to surface and reduce the effects of liquid loading. Formation fluids and gas11cross over into the production tubing section13via holes18in ported tubing section17.

Perforated regions of a gas well often produce sand, which can stick to the tubing (i.e., to dead string14inside the casing), fill the tubing, or fill the wellbore below the dead string14. Several actions that well operators would typically perform to diagnose and correct these sand problems are not possible with the apparatus illustrated inFIG. 2. and other dead string installations or designs known in the art. For example, plug15isolating the dead string from the production string (or a permanent “bull plug” on the bottom of dead string14, as mentioned above) prevents an operator from accessing the wellbore below the apparatus. Thus the operator lacks the ability to run a wireline to the bottom of the wellbore to check for sand fill levels below the dead string14. Also, when a tubing string becomes stuck in sand or when the bottom of tubing string becomes filled with sand, i.e., “sanded in,” an operator typically tries to establish fluid flow to the bottom of the tubing string and back up through the annular region to disengage the string from the sand. This operation is not possible with the configuration illustrated inFIG. 2because the holes in17can not be isolated and the bull plug would prevents the ability to get circulation fluids to the bottom of the production tubing.

Another deficiency in the configuration illustrated inFIG. 2is that perforated tubing section17limits an operator's ability run fluid down the annular region between the tubing and the casing to the bottom of the wellbore because such fluids would tend to cross over into the ID of the tubing via holes18. Thus, the configuration illustrated inFIG. 2severely limits an operator's ability to access regions of the wellbore below plug15, for example, to deliver chemical foamer to the end of the dead string.

SUMMARY OF THE INVENTION

The presently disclosed apparatus provides a dead string for reducing the critical velocity of gas produced in a perforated interval of a gas well while still providing the well operator with the ability to access the well bore below the dead string. The apparatus features a tubing string extending into the gas well and having a ported member co-axially disposed within the tubing string. Typical ported members include sliding sleeve valves or ported flow subs, which are described in more detail below. The ported member will typically be positioned at the top of or in the top third of the perforated interval. The ported member is configured to selectively permit or prevent fluid communication between the interior of the ported member and the annular region between the tubing string and a wall of the well. When the ported member is open, fluids and gasses can enter the tubing string from the annulus via ports in the ported member. Alternatively, the ports can be closed to allow fluids to be run through the ported member to sections of the tubing string below the ported member.

The apparatus includes a retrievable plug disposed within the tubing string below the ported member. Typically, when the plug is in place, fluid flow will be entering the tubing string from the annulus via the ported member and flowing toward the surface in the tubing string. However, should an operator wish to run fluids or equipment (wireline equipment, etc.) down the string below the plug, the operator simply removes the plug to access lower regions of the string because the dead string is open ended below the plug.

The apparatus also includes a dead string co-axially disposed in the tubing string below the retrievable plug. Flow between the dead string and the upper part of the tubing string is blocked by the retrievable plug. Thus, the dead string operates simply to decrease the flow area of the annulus and thereby decrease the critical velocity of gas produced in the perforated interval. However, an operator can access the dead string by removing the retrievable plug.

Embodiments of the apparatus are also configured to deliver reagents such as foamers and/or surfactants to the extended perforated interval. For example, capillary tubing can be attached to tubing string to provide a conduit for such reagents. A valve or inlet such as a gas lift mandrel or injection sub can provide a crossover of the reagents from the capillary tubing to the inside of tubing string. According to one embodiment, the retrievable plug is configured to be moved either above or below the depth where reagent is delivered into the tubing string. Further aspects and advantages of the presently disclosed apparatus will be apparent in view of the figures and description below.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 3illustrates an embodiment of the presently disclosed apparatus. The apparatus100can be deployed in a cased wellbore101having a perforated interval102. Apparatus100includes a production tubing section103and a dead string104. The inner diameter (ID) of production tubing section103and the ID of dead string104are isolated from each other by retrievable plug105. During operation, gas and formation fluids in perforated interval102flow in the annular region106around dead string104. Dead string104typically has a larger outer diameter (OD) than production tubing section103but could be the same size as the production tubing. For example, in a well with 4½″ casing having an ID of 4″, the production string might have an OD of 2⅜″ and the dead string might have an OD of 2⅞″. Dead string104reduces the flow area in the perforated interval, thereby decreasing the critical velocity needed to lift produced liquids in the wellbore reducing the effects of liquid loading. It is often preferable that the couplings used for dead string104be configured flush with the profile of the OD of the dead string and not have external collars, etc., which cause accumulation sites for sand and particulate in the wellbore. Such “Ultra Flush Joint” pipe is known in the art. A particularly suitable joint is the ULTRA-FJ, available from Weatherford International, Inc. (Houston, Tex.). Additionally, various sizes of coil tubing are known in the art and can be used.

Fluids and gas flows upward in annular region106and cross over into the production tubing section103via ported member107through ports, which provide fluid communication between the inside and outside of the ported member. According to a one embodiment, ported member107is configured such that ports108can be closed, i.e., so that fluid communication between the inside and the outside of ported member107can be selectively permitted or prevented. Ported member107can be, for example, a sliding sleeve valve, as is known in the art. When the sliding sleeve valve is open, formation fluids can enter the ID production tubing via ports in the valve. Likewise, the valve can be closed, thereby isolating the valve.

According to an alternative embodiment, a ported member107can be a ported flow sub instead of a sliding sleeve valve. An example of a ported flow sub is schematically illustrated inFIG. 4. Ported flow sub201is configured to integrate into a production stream via threaded ends202and203and its simplest embodiment is a length of tubing having ports204disposed therein. A ported flow sub201typically provides greater flow area than is available with a sliding sleeve valve. Flow sub201can include an isolation tool205for closing off ports204. Isolation tool205is a tubular member that is configured to fit within the ID of flow sub201as depicted by dashed line206. Isolation tool205can be designed to lockingly engage within flow sub201, for example, via locking mechanism207, which is configured to engage mating receiver208on flow sub201. The isolation tool illustrated inFIG. 3also features a seal ring packing209that is configured to seal within a polished bore210in flow sub201. When isolation tool205is inserted in flow sub201it effectively isolates ports204and provides a flow path through the inner diameter211of the isolation tool. Thus, an operator can deliver fluids down the production tube to regions of the production tube below the ported flow sub bypassing ports204. A particularly suitable ported member is a Heavy Duty Flow Sub (Weatherford International, Inc., Houston, Tex.), which is compatible with a locking isolation tool as described above.

The presently disclosed apparatus provides an advantage over previous dead string assemblies because plug105is a retrievable plug and thus can be removed to provide an operator access to the tubing string below the plug. Retrievable plugs are known in the art. A particularly suitable retrievable plug assembly is a WX Nipple with a retrievable equalizing plug (Weatherford International, Inc., Houston, Tex.).

To check for sand fill in the wellbore below the apparatus illustrated inFIG. 2, an operator can remove retrievable plug105and run a wire line down the tubing. The wire line can exit the bottom of the dead string and continue to the bottom of the well. According to one embodiment, the end of the dead string can include a wire line re-entry guide to assist in pulling the wire line tools back up into the dead string. If sand levels are acceptable, retrievable plug105is simply reinstalled and the system is immediately operational.

If dead string104is sanded in, an operator can try. to establish circulation down the tubing and back up the annulus while pulling or jarring on the production tubing string. To do this, the operator would typically shut off ports108, for example by installing an isolation tool as described above if ported member107is a ported flow sub. The operator can then deliver fluid to the bottom of the dead string while attempting to free the dead string.

According to one embodiment, the apparatus can include a safety release mechanism such as a shear-out joint, for example, between the removable plug105and the dead string104. Such a mechanism provides the operator the option to shear off and pull out the tubing, ported member, and plug assembly, should the previously described correction attempts fail. The operator simply applies adequate tension to tubing string to shear the tubing string at the shear-out joint and removes the string components above the joint. The operator can then recover the component(s) below the shear-out joint (namely, dead string104) via fishing operations known in the art.

Another method commonly used in the art for overcoming liquid loading injection of reagents, such as foamers and/or surfactants into the perforated interval to decrease the surface tension and density of the liquid column. Typically, one would run a small diameter tubing line for delivering the chemical down through the production tubing to the desired depth, for example, out the end of the production tube. However, this method is not possible with the dead string assembly illustrated inFIG. 2because plug15or the bull plug on the end of the dead string essentially isolates the string and wellbore below the plug. The embodiment of the presently disclosed apparatus illustrated inFIG. 5overcomes this limitation of the prior art. This embodiment includes capillary tubing301or a side string banded to the OD of the tubing string and connecting to a gas lift mandrel302or injection sub installed in the tubing string below removable plug105. This embodiment provides the ability to deliver reagents, such as foamers, surfactants, etc. to the perforated interval102(shown inFIG. 1). The gas lift mandrel is installed below retrievable plug105so that such reagents can be injected into dead string104via inlet303, rather than being routed back up the production tubing. The reagents will be injected into the top of dead string104and can then fall through the ID of the dead string and into perforated interval102.

An alternative to banding capillary tubing or a side string to the OD of the tubing string is running the capillary tubing inside the production tubing to a modified nipple where the plug would normally be. This would allow the dead string assembly to be “snubbed” into the hole and still allow an operator the ability to get soap to the bottom of the dead string. This would limit the ability to run plunger lift, as discussed below.

The apparatus can include nipples configured to receive retrievable plug105below inlet303, rather than above inlet303as illustrated inFIG. 5because in some situations it might be desirable to remove retrievable plug105and reinstall it below inlet303. For example, if the perforated interval does not generate sufficient gas to generate foam in the annular region around dead string104, the operator can reinstall plug105below inlet303and inject foamer into the production tubing below ported member107. Typically, the apparatus will be installed in the wellbore so that ported member107is at or near the top third of the perforated interval. There will typically be enough turbulence due to gas entering the production tubing via ported member107to generate foam.

According to an additional embodiment, a plunger lift system can be installed in the production tubing above ported member107. Plunger lift systems are known in the art and need not be explained in detail here, other than to mention that they are typically implemented in conventional systems, such as illustrated inFIG. 1, wherein the production tubing terminates at the top of the perforated interval or in roughly the top third of a perforated interval. The effectiveness of plunger lift systems suffers if the tubing terminates too high above or too deep within the perforated interval. In the presently disclosed apparatus, a plunger lift system can be installed in the production tubing above ported member107. In such a configuration, ported member107is analogous to the terminus of the production tubing in a conventional system and is typically disposed at the top of or within the top third of the perforated interval for optimum plunger lift operation.

It should be understood that the inventive concepts disclosed herein are capable of many modifications. To the extent such modifications fall within the scope of the appended claims and their equivalents, they are intended to be covered by this patent.