In-Hole Vaporization of Liquid Gas for Well Stimulation

Abstract

An illustrative stimulation method includes: displacing a predetermined volume of liquified gas through a wellhead valve into a service tubing string providing access to a stimulation zone of a well; and closing the wellhead valve to confine the liquified gas and pressurize the stimulation zone as the service tubing string vaporizes the liquified gas. An illustrative well configured for stimulation includes: well casing within a borehole; a stainless-steel wellhead with a valve for receiving a liquified gas; and a stainless-steel service tubing string coupled to the valve to receive and vaporize the liquified gas. The service tubing string acts as a heat exchanger, using the downhole temperatures to vaporize the liquified gas.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims benefit of U.S. Provisional Application 63 / 686,215 filed 2024-08-23 by inventor Humberto Leniek, Sr., and titled “Systems and Methods for Liquid Natural Gas (LNG) Stimulation of Wells”, which is hereby incorporated herein by reference in its entirety.TECHNICAL FIELD

[0002] The present disclosure generally pertains to the field of stimulation methods and systems for oil and gas wells, and more particularly to those stimulation methods and systems achieving high pressurization via in-situ vaporization of a cryogenic fluid.BACKGROUND

[0003] Generally speaking, oil and gas wells are boreholes drilled into reservoirs containing hydrocarbon fluids in their pore space. The weight of overlying earth and rock compresses the fluids and encourages their migration from the pore space into the borehole. Initially, the fluid pressure is typically sufficient to force the fluid to flow along the borehole to the surface or at least to within reach of a pump or other artificial lift mechanism that lifts the fluid the remaining distance. The fluid pressure drops as the reservoir is gradually depleted, reducing the rate of migration from the pore space. This issue is exacerbated in tight (i.e., low permeability) formations.

[0004] To address this issue, reservoir engineers have developed a range of stimulation techniques designed to restore well production to previous levels. The best known such technique is hydraulic fracturing, or “fracking”. Hydraulic fracturing is designed to fracture the reservoir rock at least in the vicinity of the borehole. Such fracturing is traditionally achieved by filling the borehole with an incompressible fluid such as water and raising the pressure until cracks form in the rock and propagate outward from the borehole. Very high fluid flow rates (e.g., 150 liters per second) are often required to reach and maintain the very high downhole pressures (e.g., >70 megapascals, or 10,000 PSI) needed to fracture rock, necessitating access to a large volume of liquid for each fracturing job. Other materials (sand, acid, surfactant) are usually added to the fluid to increase the post-fracking permeability of the formation. Fracking operations consequently require extensive surface installations to deliver both high pressure and volume, adding to the operational complexity and cost. These setups typically involve cumbersome equipment that increases the safety risks associated with high-pressure operations. In addition to the logistical challenges, a large environmental footprint is created by the large fluid and chemical volumes that are injected, a large fraction of which flows back and must be suitably treated.

[0005] Other stimulation methods, such as acidizing and mechanical perforation enhancements, attempt to boost well productivity by dissolving obstructive minerals and enlarging perforation tunnels. These techniques are generally limited to the immediate vicinity around the borehole.

[0006] Another stimulation technique that has been used is the so-called Huff n Puff technique, in which a borehole is cyclically pressurized with a gas such as nitrogen or carbon dioxide. The gas migrates from the borehole to the rock pores, increasing pressure of the reservoir fluid. In some cases, the gas mixes with the reservoir fluid and reduces its viscosity. Between pressurization cycles, the well demonstrates increased production. Though the required injection pressures and flow rates are much less than those of a typical fracking operation, they are nevertheless significant and require that the surface equipment be capable of handling of high pressures. Such equipment increases costs and may pose safety risks.SUMMARY

[0007] Accordingly, there are disclosed herein illustrative stimulation systems and methods that at least partly address the issues identified above. As one example, an illustrative stimulation method includes: displacing a predetermined volume of liquified gas through a wellhead valve into a service tubing string providing access to a stimulation zone of a well; and closing the wellhead valve to confine the liquified gas and pressurize the stimulation zone as the service tubing string vaporizes the liquified gas.

[0008] An illustrative well configured for stimulation includes: well casing within a borehole; a stainless-steel wellhead with a valve for receiving a liquified gas; and a stainless-steel service tubing string coupled to the valve to receive and vaporize the liquified gas.

[0009] Each of the foregoing examples can be employed individually or in conjunction and may include one or more of the following features in any suitable combination: 1. the predetermined volume is sufficient to pressurize the stimulation zone to at least 8,000 psi. 2. prior to said displacing, evacuating gas from an annulus around the service tubing string to reduce a vaporization rate of the liquified gas. 3. prior to said displacing, adding fluid to an annulus around the service tubing string to increase hydrostatic pressure on a packer sealing the stimulation zone. 4. prior to said displacing: installing a stainless-steel wellhead; setting a packer configured to tolerate exposure to cryogenic liquid; and running stainless steel tubing as the service tubing string anchored by the packer. 5. prior to said displacing: installing a stainless-steel wellhead; installing a production tubing string anchored by a downhole packer configured to tolerate exposure to cryogenic liquid; running, inside the production tubing string, stainless steel tubing as the service tubing string anchored by a seating nipple configured to tolerate exposure to cryogenic liquid. 6. said closing is for a close-in period of at least 24 hours. 7. returning the well to production after the close-in period. 8. said displacing uses one or more pressure sensors and one or more flow rate monitors to provide control of the displacing. 9. the displacing includes reducing a flow rate if a derivative of the borehole pressure exceeds a predetermined threshold. 10. the liquified gas is liquified natural gas (LNG) or liquified methane. 11. the liquified gas is liquified nitrogen. 12. a packer seated within the casing to anchor a lower end of the service tubing string and provide a pressure seal. 13. a vacuum pump to evacuate an annulus around the service tubing string. 14. a thermal insulation coating on an upper portion of the service tubing string to reduce a vaporization rate. 15. a cryogenic liquid transfer pump to transfer the liquified gas to the service tubing string. 16. a pressure sensor coupled to the service tubing string. 17. a control system coupled to the pressure sensor and configured to responsively regulate a transfer rate of the liquified gas. 18. a flow sensor coupled to the valve. 19. the control system is configured to close the valve or otherwise halt delivery of the liquified gas after a predetermined volume has been transferred to the service tubing string. 20. a stainless steel production tubing string anchored to a downhole packer, the production tubing string providing a seating nipple that anchors a lower end of the service tubing string.BRIEF DESCRIPTION OF THE FIGURES

[0010] FIG. 1 shows a first illustrative liquified gas stimulation arrangement for a horizontal well.

[0011] FIG. 2 shows a second illustrative liquified gas stimulation arrangement for a horizontal well.

[0012] FIG. 3 is a flow diagram of an illustrative liquified gas stimulation method.DETAILED DESCRIPTION

[0013] The figures and following description do not limit the disclosure, but on the contrary, they provide the foundation for one of ordinary skill in the art to understand all modifications, equivalents, and alternatives falling within the scope of the claim language.

[0014] FIG. 1 shows a schematic representation of a system for liquified gas stimulation of a well. The well includes a cased borehole 102 that extends downward from the earth's surface 100. At a certain depth, the borehole transitions from vertical to horizontal, extending for a horizontal distance 106 to increase exposure to the reservoir formation 108. The figure is not drawn to scale. The vertical portion of the well may be, e.g., eight to ten thousand feet. The horizontal distance 106 may be, e.g., greater than ten thousand feet. The transition radius 104 may be, e.g., 600 to 1000 feet. Various casing perforations 110 are provided within the reservoir 108 to enable reservoir fluid to flow into the borehole.

[0015] A service tubing string 112 is positioned within the cased borehole 102, suspended from a hanger in the wellhead 114. The service tubing string 112, whether continuous tubing (aka “coiled tubing”) or threaded tubing (aka “jointed tubing”), is composed of stainless steel to ensure that it can accommodate exposure to cryogenic fluids without losing integrity. If threaded tubing is employed, it is preferably provided with premium threads to maintain a pressure seal against high pressure. It is contemplated that the service tubing string may have an inner diameter of about 1.75, 2, or 2.5 inches, though other diameters may also be used. As an example, the inner diameter of the casing may be 5, 5.5, or more inches.

[0016] A packer 111 secures the lower end of the service tubing string 112 and seals the annulus around the tubing string from the stimulation zone in the horizontal portion of the borehole. The packer 111 is set in place before the service tubing string is lowered into the borehole. The string's lower end 113 is equipped with a stinger that mechanically engages with the packer 111 to anchor the lower end of the tubing string. In some contemplated implementations, the service tubing string 112 is insulated and equipped with spaced-apart centralizers 132 to limit the rate of heat flow through the tubing wall. As an alternative, or in addition to the insulation, the annulus may be evacuated to further reduce the rate of heat flow through the tubing wall.

[0017] The illustrated wellhead 114 includes a bore access valve 116, an annulus access valve 118, a production outlet 120, and a stimulation fluid inlet 122. A pump 124 may be coupled via a hose 126 to a fluid source 130, shown here as a cryogenic liquid trailer. The pump 124 operates to transfer a cryogenic fluid from the source 130 through one or more check valves 123 to the service tubing string 112. A control system monitors the borehole pressure (e.g., via bore access valve 116) and responsively controls the pump 124 to regulate the injection rate and borehole pressure.

[0018] The source 130 supplies a cryogenic fluid, which is preferably liquified natural gas (LNG) though other fluids may also be suitable such as liquid nitrogen or liquid methane. As a liquid, the fluid occupies a much smaller volume than it would as a gas. Natural gas is a liquid at temperatures below 111 K (−162 degrees C) and can be maintained as a liquid at pressures below 25 kPa (4 PSI) (gauge pressure). When vaporized at standard temperature and pressure, natural gas occupies 600 times as much volume as the liquid. If this vaporization is done on the surface, the surface equipment consumes energy to perform the phase change and must be able to cope with pressurizing the gas to the desired stimulation pressure.

[0019] Conversely, if the vaporization is performed downhole, the vaporization energy is provided by the formation. The service tubing string acts as a heat exchanger, leveraging the formation heat to facilitate the phase change from liquid to vapor. The surface equipment is configured for handling low pressure cryogenic liquids rather than high pressure gases. The borehole pressure is largely contained within the inlet pipe 122, the wellhead 114, the coil tubing string 112, and the stimulation zone.

[0020] The packer 111 and stinger are configured to handle the cryogenic temperature of the chosen fluid. The service tubing string 112 is stainless steel or some other material capable of handling the cryogenic fluid at the contemplated stimulation pressure. The wellhead 114, including the service tubing hanger, is also configured to handle these temperatures and pressures, as is the inlet 122 and pump 124. The remaining components for storing and transferring the cryogenic fluid can be kept near normal atmospheric pressures.

[0021] The inlet pipe 122 may be equipped with a pressure sensor and flow meter that provide measurement signals to a control system. The control system may regulate operation of the pump 124 to limit the derivative of the pressure to a safe threshold and limit the pressure itself to the desired target, which in one implementation is 8,000 PSI. Other contemplated stimulation pressures include, e.g., 10,000 psi. The service tubing string may be configured to make the phase change more gradual to facilitate control of the stimulation process. Options include insulating at least the upper portion of the service tubing string 112. Alternatively, or in addition, centralizers 132 may be employed to limit the rate of heat transfer from the borehole casing to the service tubing string. (In at least some configurations, the jointed tubing upsets may provide sufficient centralization.) FIG. 2 shows an alternative system for liquified gas stimulation of a well. Unlike the system of FIG. 1, the system of FIG. 2 includes a production tubing string 202 with its lower end 204 anchored downhole by packer 111. A packer or seating nipple 206 is provided at the lower end of the production tubing string 202 to seal the stimulation zone and to secure the lower end of the service string 112. Seating nipple 206 may be integrated with, or separate from, packer 111, and it too is preferably rated for cryogenic operation. The annulus between the service tubing string 112 and production tubing string 202 may be optionally evacuated to reduce the vaporization rate of the liquified gas. If the production tubing string has an inner diameter of, say, 2.875 inches, the service tubing string may have an inner diameter of 1.5 inches. Centralization may be obtained using upsets, fins, or other centering configurations. For 3.5-inch production tubing, the service tubing string may have an inner diameter of 1.5 or 1.75 inches. Other suitable diameters may alternatively be employed. If threaded tubing is used for both the service tubing string and the production tubing string, their inner diameters may be, e.g., 2.875 (or less) and 3.5 inches, respectively.

[0022] Though it may have increased material costs, this system configuration offers several potential advantages particularly if implemented with only jointed tubing. The installation can be performed with a workover rig (no coiled tubing unit would be required). The joint upsets can act as centralizers, making heat flow more uniform. The dual annular spaces may offer further control of heat flow, particularly if evacuated or filled with oil. Additional safety may be offered by the containment redundancy of the dual annular spaces and by the thicker tubing walls possessed by jointed tubing relative to continuous tubing.

[0023] FIG. 3 is a flow diagram of an illustrative liquified gas stimulation method for an existing well. The disclosed stimulation method may be employed post-initial production for additional formation stimulation. It's expected to be effective in reservoirs with declining production rates from traditional hydraulic fracturing. The technique is suitable for use in mature fields, and post-stimulation evaluation tools can be used to assess performance to refine future operations. The lower liquified gas stimulation costs improve economic viability over traditional re-fracking. The technique may be used in conjunction with existing artificial lift systems (ALS), with the stainless-steel tubing string potentially remaining as a permanent fixture or replaced depending on operational needs. liquified gas stimulation may also be used in combination or alternation with traditional stimulation techniques like acidizing and hydraulic fracturing for combined productivity benefits.

[0024] The method begins in block 302 with the removal of any existing tubing strings from the underperforming well. Typically, the well will have no meaningful production flow in the absence of artificial lift, but if some flow remains, a dense “kill” fluid may be circulated downhole to halt any outflow. The crew begins by rigging up a workover rig (transporting the unit to the wellsite and configuring it for operation) and using the workover rig to pull the pump rod, pumps, gas lift components, and any tubing strings. Though a typical workover rig can be used to pull a continuous tubing string from the well, this can be more efficiently done using a coiled tubing unit to avoid having to cut the continuous tubing string into pieces.

[0025] The crew may use the workover rig or a wireline truck in block 304 to run a cement bond log to verify that the annulus outside the well casing is plugged with concrete that has bonded to the casing and the borehole wall in a manner that prevents any external fluid flow along the borehole. The bond log is reviewed in block 306 to verify that the concrete can withstand the expected pressures from the stimulation zone. If not, then in block 308 the crew may run a cement squeeze job to create the desired seal. In block 310, the process pauses for sufficient time to allow the concrete to harden in place. Blocks 304-310 may be repeated as needed to ensure that the stimulation process can be performed safely.

[0026] Once a good bond has been achieved, the workover crew may remove the existing wellhead in block 311 and, for the arrangement of FIG. 1, install a packer 111 near the end of the vertical portion of the well. The installed packer is designed to be capable of maintaining its function while being exposed to cryogenic liquids and the expected pressures during the stimulation process. In block 312 the crew installs a wellhead capable of handling the liquified gas temperatures and the expected stimulation pressures, e.g., a 10,000-psi cryogenic wellhead, including hangers, check valves, relief valve, and venting lines. The crew closes all the wellhead valves before rigging down (readying the workover rig for transport and making the well site accessible for future operations). Estimated time on location for the workover rig and crew is about three days.

[0027] For the arrangement of FIG. 2, block 312 may be performed before the packer 111 is installed. As a preliminary to block 314, the crew secures the packer 111 and seating nipple 206 to the lower end of the production tubing string 202 before running the production tubing string into the well. The crew sets the packer 111 at a predetermined depth near the end of the well's vertical portion before suspending the tubing string from a wellhead hanger and making the appropriate wellhead connections. The crew closes all the wellhead valves before rigging down.

[0028] In block 314, the crew installs the service tubing string. It is expected that the crew will rig up a coiled tubing unit (CTU) at the wellsite, with the desired length of stainless-steel coiled tubing for use as the service tubing string. In some implementations, the tubing string features reinforcement layers and corrosion-resistant coatings for durability. Thermal insulation coatings may be provided on the upper sections of the continuous tubing to slow the rate of phase change during the initial stages of the injection process.

[0029] The crew installs a stinger at the bottom end of the coiled tubing to connect with the packer 111 or seating nipple 206 and runs the service tubing string into the hole, setting the stinger in the packer or seating nipple to anchor the string in the hole and seal the stimulation zone. The crew cuts the coiled tubing to the desired length and hangs the service tubing string on the appropriate wellhead hanger. The crew completes the wellhead connections and closes all valves before rigging down the CTU. Estimated time on location for the CTU rig and crew is about four days.

[0030] As an alternative, the crew may install a stainless-steel jointed tubing string as the service string in block 314. The CTU would not be required. The crew installs a packer at the end of the service string and runs the jointed tubing string inside the casing or inside the production tubing string using the regular workover rig. As before, the crew sets the service tubing string on a wellhead hanger, completes the wellhead connections, and closes all valves before rigging down the workover rig.

[0031] In block 316, the crew injects liquified gas to pressurize the stimulation zone to the desired pressure. This may involve rigging up the liquified gas trailer and connecting it to the service tubing string (via the appropriate wellhead valve, inlet, check valve, and pump if needed). The kill fluid, if any, may be circulated out of the service tubing. The kill fluid (if any) or a suitable volume of crude oil may be displaced into the annulus around the service tubing string (and the annulus around the production tubing string, if any), to exert hydrostatic pressure on the packer and seating nipple to aid in maintaining the stimulation zone seal and to contain any potential leaks of high-pressure gas. If not already available at the wellsite, the crude oil may be transported using a tank truck. The tank truck can be connected to the appropriate wellhead valves to fill the annular space. A corrosion inhibitor may be added if desired. Note that this fluid will be heated to the surrounding formation temperature and may provide more efficient vaporization of the liquified gas conveyed along the service tubing string. To provide better control the vaporization process, the annular space above any such fluid or oil may be evacuated (reduced to a vacuum or lower air pressure) to reduce heat flow and slow the vaporization process in the upper regions of the service tubing string. A compressor / vacuum pump may be rigged up and connected to the appropriate wellhead valves for this purpose. Variations include filling the annular space to the top with the crude oil to maximize hydrostatic pressure and, alternatively, evacuating all of the annular space to minimize the vaporization rate.

[0032] The crew secures the wellhead valves before opening the service tubing valve and displacing a predetermined volume of liquified gas into the service tubing sufficient to reach the desired stimulation pressure (after vaporization). A typical well may use about 17 m3 of LNG to provide 8,000 psi of gas pressure in the stimulation zone. Initial tests may use differential pressures alone (pressure built inside the sealed cryogenic tank) to inject the liquified gas, but if this doesn't work a cryogenic pump can be used. Downhole temperatures can exceed 200° F., providing the energy to return the injected liquified gas to a gaseous state, producing high pressures desired for formation stimulation. The service string acts as a heat exchanger, leveraging the formation temperature to drive the phase change and pressure buildup. Modeling and testing may be performed to ensure that the cryogenic liquid completes its phase change before reaching the end of the service string, or to verify that if the liquid exits the lower end of the service string it will not damage the well casing.

[0033] The service tubing valve is promptly closed after the injection. The liquified gas trailer may be disconnected and moved away from the wellhead. In block 318 the wellhead pressures are monitored as the formation heat vaporizes the liquified gas and elevates the pressure in the stimulation zone to the desired level. The valves are kept closed to provide sufficient time for the gas pressure to reopen existing fractures and repressurize the formation. In addition, the injected gas can mix with formation fluids to reduce fluid viscosity, further aiding in boosting production flow when the well is returned to production. The trailer may be left on station for future use or may be rigged down. After sufficient time (e.g., 24 or 48 hours), a wellhead valve may be opened in block 320 to recover or vent the residual gas pressure from the stimulation zone. As fluid flow begins in block 322, a wellhead valve may be opened to direct the flow to the production line. A tank battery may store the recovered liquid and gasses for later transport.

[0034] Well production may continue until such time as well stops flowing in block 324. In optional block 326, a crew installs an artificial lift system. This may involve, for example, rigging up a CTU to pull the stainless-steel service tubing string from the well and to install a regular continuous tubing string as production tubing. The production tubing string may include a seating nipple installed at the lower end. The crew may set a submersible pump in the seating nipple, either using the CTU or a regular pulling unit that can run the submersible pump with sucker rods. In block 328 production resumes using the artificial lift system. Production continues until the flow falls off to a noneconomic level in block 330. At that time, in block 332, management may determine whether repeat stimulation is desired, or whether the well is fully depleted. If depleted, a crew may plug and decommission the well in block 334.

[0035] For successive stimulation, blocks 316 to 324 are repeated at an almost negligible cost, assuming the service tubing string has been left in place. (Though the service string is initially used for delivering liquified gas to the stimulation zone, it may be left in place to serve as a production tubing string or a velocity string.) If an artificial lift system was installed, additional cost may be expected for removal of the artificial lift components and, if needed, re-installation of the service tubing string.

[0036] Sensors and controls may be used to inject a predetermined volume of liquified gas for stimulation, aiming for a pressure buildup to around 8,000 PSI or whatever has been determined to be optimal for the given formation. Pressure sensors and flow rate monitors provide real-time data for precise injection control. The control system considers gas flow dynamics, including turbulent flow and back pressure effects, to enhance operational efficiency. The gas from liquified gas expansion attains high pressures, facilitating stimulation through pre-existing perforations. This method offers an alternative to conventional high-pressure operations, reducing surface installations and associated safety risks. The method lowers the environmental footprint by avoiding large quantities of water and chemicals. Surface valves manage pressures, overseeing controlled residual gas discharge and subsequent well flow. A control algorithm adjusts surface valve operations based on pressure data from downhole sensors. Risk assessment protocols mitigate potential wellbore stability issues. Cryogenic valves designed for low temperatures ensure functionality during rapid phase transitions.

[0037] For comparison, a typical refracking operation through a 3.5″ liner may be expected to cost around 2.25 million dollars, whereas the disclosed stimulation method prices out below 0.5 million dollars. Successive liquified gas stimulations after the first are estimated at 50 thousand dollars, or 50 times less than a typical refracking operation. This cost reduction enhances the method's economic viability for operators seeking to maximize productivity with minimal expenditure.

[0038] The surface equipment that is configured for cryogenic liquid exposure may include: the wellhead, flanges, control valves, safety / relief valves, check valves, and bolts. The downhole equipment that is configured for cryogenic liquid exposure may include: casing liners, production tubing, service tubing, packers, seating nipples, and stingers. It is expected that this equipment will be made of stainless steel to render it capable of cryogenic operation.

[0039] Numerous modifications, equivalents, and alternatives will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable.

Examples

Embodiment Construction

[0013]The figures and following description do not limit the disclosure, but on the contrary, they provide the foundation for one of ordinary skill in the art to understand all modifications, equivalents, and alternatives falling within the scope of the claim language.

[0014]FIG. 1 shows a schematic representation of a system for liquified gas stimulation of a well. The well includes a cased borehole 102 that extends downward from the earth's surface 100. At a certain depth, the borehole transitions from vertical to horizontal, extending for a horizontal distance 106 to increase exposure to the reservoir formation 108. The figure is not drawn to scale. The vertical portion of the well may be, e.g., eight to ten thousand feet. The horizontal distance 106 may be, e.g., greater than ten thousand feet. The transition radius 104 may be, e.g., 600 to 1000 feet. Various casing perforations 110 are provided within the reservoir 108 to enable reservoir fluid to flow into the borehole.

[0015]A ...

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims benefit of U.S. Provisional Application 63 / 686,215 filed 2024-08-23 by inventor Humberto Leniek, Sr., and titled “Systems and Methods for Liquid Natural Gas (LNG) Stimulation of Wells”, which is hereby incorporated herein by reference in its entirety.TECHNICAL FIELD

[0002] The present disclosure generally pertains to the field of stimulation methods and systems for oil and gas wells, and more particularly to those stimulation methods and systems achieving high pressurization via in-situ vaporization of a cryogenic fluid.BACKGROUND

[0003] Generally speaking, oil and gas wells are boreholes drilled into reservoirs containing hydrocarbon fluids in their pore space. The weight of overlying earth and rock compresses the fluids and encourages their migration from the pore space into the borehole. Initially, the fluid pressure is typically sufficient to force the fluid to flow along the borehole to the surface or at least to within reach of a pump or other artificial lift mechanism that lifts the fluid the remaining distance. The fluid pressure drops as the reservoir is gradually depleted, reducing the rate of migration from the pore space. This issue is exacerbated in tight (i.e., low permeability) formations.

[0004] To address this issue, reservoir engineers have developed a range of stimulation techniques designed to restore well production to previous levels. The best known such technique is hydraulic fracturing, or “fracking”. Hydraulic fracturing is designed to fracture the reservoir rock at least in the vicinity of the borehole. Such fracturing is traditionally achieved by filling the borehole with an incompressible fluid such as water and raising the pressure until cracks form in the rock and propagate outward from the borehole. Very high fluid flow rates (e.g., 150 liters per second) are often required to reach and maintain the very high downhole pressures (e.g., >70 megapascals, or 10,000 PSI) needed to fracture rock, necessitating access to a large volume of liquid for each fracturing job. Other materials (sand, acid, surfactant) are usually added to the fluid to increase the post-fracking permeability of the formation. Fracking operations consequently require extensive surface installations to deliver both high pressure and volume, adding to the operational complexity and cost. These setups typically involve cumbersome equipment that increases the safety risks associated with high-pressure operations. In addition to the logistical challenges, a large environmental footprint is created by the large fluid and chemical volumes that are injected, a large fraction of which flows back and must be suitably treated.

[0005] Other stimulation methods, such as acidizing and mechanical perforation enhancements, attempt to boost well productivity by dissolving obstructive minerals and enlarging perforation tunnels. These techniques are generally limited to the immediate vicinity around the borehole.

[0006] Another stimulation technique that has been used is the so-called Huff n Puff technique, in which a borehole is cyclically pressurized with a gas such as nitrogen or carbon dioxide. The gas migrates from the borehole to the rock pores, increasing pressure of the reservoir fluid. In some cases, the gas mixes with the reservoir fluid and reduces its viscosity. Between pressurization cycles, the well demonstrates increased production. Though the required injection pressures and flow rates are much less than those of a typical fracking operation, they are nevertheless significant and require that the surface equipment be capable of handling of high pressures. Such equipment increases costs and may pose safety risks.SUMMARY

[0007] Accordingly, there are disclosed herein illustrative stimulation systems and methods that at least partly address the issues identified above. As one example, an illustrative stimulation method includes: displacing a predetermined volume of liquified gas through a wellhead valve into a service tubing string providing access to a stimulation zone of a well; and closing the wellhead valve to confine the liquified gas and pressurize the stimulation zone as the service tubing string vaporizes the liquified gas.

[0008] An illustrative well configured for stimulation includes: well casing within a borehole; a stainless-steel wellhead with a valve for receiving a liquified gas; and a stainless-steel service tubing string coupled to the valve to receive and vaporize the liquified gas.

[0009] Each of the foregoing examples can be employed individually or in conjunction and may include one or more of the following features in any suitable combination: 1. the predetermined volume is sufficient to pressurize the stimulation zone to at least 8,000 psi. 2. prior to said displacing, evacuating gas from an annulus around the service tubing string to reduce a vaporization rate of the liquified gas. 3. prior to said displacing, adding fluid to an annulus around the service tubing string to increase hydrostatic pressure on a packer sealing the stimulation zone. 4. prior to said displacing: installing a stainless-steel wellhead; setting a packer configured to tolerate exposure to cryogenic liquid; and running stainless steel tubing as the service tubing string anchored by the packer. 5. prior to said displacing: installing a stainless-steel wellhead; installing a production tubing string anchored by a downhole packer configured to tolerate exposure to cryogenic liquid; running, inside the production tubing string, stainless steel tubing as the service tubing string anchored by a seating nipple configured to tolerate exposure to cryogenic liquid. 6. said closing is for a close-in period of at least 24 hours. 7. returning the well to production after the close-in period. 8. said displacing uses one or more pressure sensors and one or more flow rate monitors to provide control of the displacing. 9. the displacing includes reducing a flow rate if a derivative of the borehole pressure exceeds a predetermined threshold. 10. the liquified gas is liquified natural gas (LNG) or liquified methane. 11. the liquified gas is liquified nitrogen. 12. a packer seated within the casing to anchor a lower end of the service tubing string and provide a pressure seal. 13. a vacuum pump to evacuate an annulus around the service tubing string. 14. a thermal insulation coating on an upper portion of the service tubing string to reduce a vaporization rate. 15. a cryogenic liquid transfer pump to transfer the liquified gas to the service tubing string. 16. a pressure sensor coupled to the service tubing string. 17. a control system coupled to the pressure sensor and configured to responsively regulate a transfer rate of the liquified gas. 18. a flow sensor coupled to the valve. 19. the control system is configured to close the valve or otherwise halt delivery of the liquified gas after a predetermined volume has been transferred to the service tubing string. 20. a stainless steel production tubing string anchored to a downhole packer, the production tubing string providing a seating nipple that anchors a lower end of the service tubing string.BRIEF DESCRIPTION OF THE FIGURES

[0010] FIG. 1 shows a first illustrative liquified gas stimulation arrangement for a horizontal well.

[0011] FIG. 2 shows a second illustrative liquified gas stimulation arrangement for a horizontal well.

[0012] FIG. 3 is a flow diagram of an illustrative liquified gas stimulation method.DETAILED DESCRIPTION

[0013] The figures and following description do not limit the disclosure, but on the contrary, they provide the foundation for one of ordinary skill in the art to understand all modifications, equivalents, and alternatives falling within the scope of the claim language.

[0014] FIG. 1 shows a schematic representation of a system for liquified gas stimulation of a well. The well includes a cased borehole 102 that extends downward from the earth's surface 100. At a certain depth, the borehole transitions from vertical to horizontal, extending for a horizontal distance 106 to increase exposure to the reservoir formation 108. The figure is not drawn to scale. The vertical portion of the well may be, e.g., eight to ten thousand feet. The horizontal distance 106 may be, e.g., greater than ten thousand feet. The transition radius 104 may be, e.g., 600 to 1000 feet. Various casing perforations 110 are provided within the reservoir 108 to enable reservoir fluid to flow into the borehole.

[0015] A service tubing string 112 is positioned within the cased borehole 102, suspended from a hanger in the wellhead 114. The service tubing string 112, whether continuous tubing (aka “coiled tubing”) or threaded tubing (aka “jointed tubing”), is composed of stainless steel to ensure that it can accommodate exposure to cryogenic fluids without losing integrity. If threaded tubing is employed, it is preferably provided with premium threads to maintain a pressure seal against high pressure. It is contemplated that the service tubing string may have an inner diameter of about 1.75, 2, or 2.5 inches, though other diameters may also be used. As an example, the inner diameter of the casing may be 5, 5.5, or more inches.

[0016] A packer 111 secures the lower end of the service tubing string 112 and seals the annulus around the tubing string from the stimulation zone in the horizontal portion of the borehole. The packer 111 is set in place before the service tubing string is lowered into the borehole. The string's lower end 113 is equipped with a stinger that mechanically engages with the packer 111 to anchor the lower end of the tubing string. In some contemplated implementations, the service tubing string 112 is insulated and equipped with spaced-apart centralizers 132 to limit the rate of heat flow through the tubing wall. As an alternative, or in addition to the insulation, the annulus may be evacuated to further reduce the rate of heat flow through the tubing wall.

[0017] The illustrated wellhead 114 includes a bore access valve 116, an annulus access valve 118, a production outlet 120, and a stimulation fluid inlet 122. A pump 124 may be coupled via a hose 126 to a fluid source 130, shown here as a cryogenic liquid trailer. The pump 124 operates to transfer a cryogenic fluid from the source 130 through one or more check valves 123 to the service tubing string 112. A control system monitors the borehole pressure (e.g., via bore access valve 116) and responsively controls the pump 124 to regulate the injection rate and borehole pressure.

[0018] The source 130 supplies a cryogenic fluid, which is preferably liquified natural gas (LNG) though other fluids may also be suitable such as liquid nitrogen or liquid methane. As a liquid, the fluid occupies a much smaller volume than it would as a gas. Natural gas is a liquid at temperatures below 111 K (−162 degrees C) and can be maintained as a liquid at pressures below 25 kPa (4 PSI) (gauge pressure). When vaporized at standard temperature and pressure, natural gas occupies 600 times as much volume as the liquid. If this vaporization is done on the surface, the surface equipment consumes energy to perform the phase change and must be able to cope with pressurizing the gas to the desired stimulation pressure.

[0019] Conversely, if the vaporization is performed downhole, the vaporization energy is provided by the formation. The service tubing string acts as a heat exchanger, leveraging the formation heat to facilitate the phase change from liquid to vapor. The surface equipment is configured for handling low pressure cryogenic liquids rather than high pressure gases. The borehole pressure is largely contained within the inlet pipe 122, the wellhead 114, the coil tubing string 112, and the stimulation zone.

[0020] The packer 111 and stinger are configured to handle the cryogenic temperature of the chosen fluid. The service tubing string 112 is stainless steel or some other material capable of handling the cryogenic fluid at the contemplated stimulation pressure. The wellhead 114, including the service tubing hanger, is also configured to handle these temperatures and pressures, as is the inlet 122 and pump 124. The remaining components for storing and transferring the cryogenic fluid can be kept near normal atmospheric pressures.

[0021] The inlet pipe 122 may be equipped with a pressure sensor and flow meter that provide measurement signals to a control system. The control system may regulate operation of the pump 124 to limit the derivative of the pressure to a safe threshold and limit the pressure itself to the desired target, which in one implementation is 8,000 PSI. Other contemplated stimulation pressures include, e.g., 10,000 psi. The service tubing string may be configured to make the phase change more gradual to facilitate control of the stimulation process. Options include insulating at least the upper portion of the service tubing string 112. Alternatively, or in addition, centralizers 132 may be employed to limit the rate of heat transfer from the borehole casing to the service tubing string. (In at least some configurations, the jointed tubing upsets may provide sufficient centralization.) FIG. 2 shows an alternative system for liquified gas stimulation of a well. Unlike the system of FIG. 1, the system of FIG. 2 includes a production tubing string 202 with its lower end 204 anchored downhole by packer 111. A packer or seating nipple 206 is provided at the lower end of the production tubing string 202 to seal the stimulation zone and to secure the lower end of the service string 112. Seating nipple 206 may be integrated with, or separate from, packer 111, and it too is preferably rated for cryogenic operation. The annulus between the service tubing string 112 and production tubing string 202 may be optionally evacuated to reduce the vaporization rate of the liquified gas. If the production tubing string has an inner diameter of, say, 2.875 inches, the service tubing string may have an inner diameter of 1.5 inches. Centralization may be obtained using upsets, fins, or other centering configurations. For 3.5-inch production tubing, the service tubing string may have an inner diameter of 1.5 or 1.75 inches. Other suitable diameters may alternatively be employed. If threaded tubing is used for both the service tubing string and the production tubing string, their inner diameters may be, e.g., 2.875 (or less) and 3.5 inches, respectively.

[0022] Though it may have increased material costs, this system configuration offers several potential advantages particularly if implemented with only jointed tubing. The installation can be performed with a workover rig (no coiled tubing unit would be required). The joint upsets can act as centralizers, making heat flow more uniform. The dual annular spaces may offer further control of heat flow, particularly if evacuated or filled with oil. Additional safety may be offered by the containment redundancy of the dual annular spaces and by the thicker tubing walls possessed by jointed tubing relative to continuous tubing.

[0023] FIG. 3 is a flow diagram of an illustrative liquified gas stimulation method for an existing well. The disclosed stimulation method may be employed post-initial production for additional formation stimulation. It's expected to be effective in reservoirs with declining production rates from traditional hydraulic fracturing. The technique is suitable for use in mature fields, and post-stimulation evaluation tools can be used to assess performance to refine future operations. The lower liquified gas stimulation costs improve economic viability over traditional re-fracking. The technique may be used in conjunction with existing artificial lift systems (ALS), with the stainless-steel tubing string potentially remaining as a permanent fixture or replaced depending on operational needs. liquified gas stimulation may also be used in combination or alternation with traditional stimulation techniques like acidizing and hydraulic fracturing for combined productivity benefits.

[0024] The method begins in block 302 with the removal of any existing tubing strings from the underperforming well. Typically, the well will have no meaningful production flow in the absence of artificial lift, but if some flow remains, a dense “kill” fluid may be circulated downhole to halt any outflow. The crew begins by rigging up a workover rig (transporting the unit to the wellsite and configuring it for operation) and using the workover rig to pull the pump rod, pumps, gas lift components, and any tubing strings. Though a typical workover rig can be used to pull a continuous tubing string from the well, this can be more efficiently done using a coiled tubing unit to avoid having to cut the continuous tubing string into pieces.

[0025] The crew may use the workover rig or a wireline truck in block 304 to run a cement bond log to verify that the annulus outside the well casing is plugged with concrete that has bonded to the casing and the borehole wall in a manner that prevents any external fluid flow along the borehole. The bond log is reviewed in block 306 to verify that the concrete can withstand the expected pressures from the stimulation zone. If not, then in block 308 the crew may run a cement squeeze job to create the desired seal. In block 310, the process pauses for sufficient time to allow the concrete to harden in place. Blocks 304-310 may be repeated as needed to ensure that the stimulation process can be performed safely.

[0026] Once a good bond has been achieved, the workover crew may remove the existing wellhead in block 311 and, for the arrangement of FIG. 1, install a packer 111 near the end of the vertical portion of the well. The installed packer is designed to be capable of maintaining its function while being exposed to cryogenic liquids and the expected pressures during the stimulation process. In block 312 the crew installs a wellhead capable of handling the liquified gas temperatures and the expected stimulation pressures, e.g., a 10,000-psi cryogenic wellhead, including hangers, check valves, relief valve, and venting lines. The crew closes all the wellhead valves before rigging down (readying the workover rig for transport and making the well site accessible for future operations). Estimated time on location for the workover rig and crew is about three days.

[0027] For the arrangement of FIG. 2, block 312 may be performed before the packer 111 is installed. As a preliminary to block 314, the crew secures the packer 111 and seating nipple 206 to the lower end of the production tubing string 202 before running the production tubing string into the well. The crew sets the packer 111 at a predetermined depth near the end of the well's vertical portion before suspending the tubing string from a wellhead hanger and making the appropriate wellhead connections. The crew closes all the wellhead valves before rigging down.

[0028] In block 314, the crew installs the service tubing string. It is expected that the crew will rig up a coiled tubing unit (CTU) at the wellsite, with the desired length of stainless-steel coiled tubing for use as the service tubing string. In some implementations, the tubing string features reinforcement layers and corrosion-resistant coatings for durability. Thermal insulation coatings may be provided on the upper sections of the continuous tubing to slow the rate of phase change during the initial stages of the injection process.

[0029] The crew installs a stinger at the bottom end of the coiled tubing to connect with the packer 111 or seating nipple 206 and runs the service tubing string into the hole, setting the stinger in the packer or seating nipple to anchor the string in the hole and seal the stimulation zone. The crew cuts the coiled tubing to the desired length and hangs the service tubing string on the appropriate wellhead hanger. The crew completes the wellhead connections and closes all valves before rigging down the CTU. Estimated time on location for the CTU rig and crew is about four days.

[0030] As an alternative, the crew may install a stainless-steel jointed tubing string as the service string in block 314. The CTU would not be required. The crew installs a packer at the end of the service string and runs the jointed tubing string inside the casing or inside the production tubing string using the regular workover rig. As before, the crew sets the service tubing string on a wellhead hanger, completes the wellhead connections, and closes all valves before rigging down the workover rig.

[0031] In block 316, the crew injects liquified gas to pressurize the stimulation zone to the desired pressure. This may involve rigging up the liquified gas trailer and connecting it to the service tubing string (via the appropriate wellhead valve, inlet, check valve, and pump if needed). The kill fluid, if any, may be circulated out of the service tubing. The kill fluid (if any) or a suitable volume of crude oil may be displaced into the annulus around the service tubing string (and the annulus around the production tubing string, if any), to exert hydrostatic pressure on the packer and seating nipple to aid in maintaining the stimulation zone seal and to contain any potential leaks of high-pressure gas. If not already available at the wellsite, the crude oil may be transported using a tank truck. The tank truck can be connected to the appropriate wellhead valves to fill the annular space. A corrosion inhibitor may be added if desired. Note that this fluid will be heated to the surrounding formation temperature and may provide more efficient vaporization of the liquified gas conveyed along the service tubing string. To provide better control the vaporization process, the annular space above any such fluid or oil may be evacuated (reduced to a vacuum or lower air pressure) to reduce heat flow and slow the vaporization process in the upper regions of the service tubing string. A compressor / vacuum pump may be rigged up and connected to the appropriate wellhead valves for this purpose. Variations include filling the annular space to the top with the crude oil to maximize hydrostatic pressure and, alternatively, evacuating all of the annular space to minimize the vaporization rate.

[0032] The crew secures the wellhead valves before opening the service tubing valve and displacing a predetermined volume of liquified gas into the service tubing sufficient to reach the desired stimulation pressure (after vaporization). A typical well may use about 17 m3 of LNG to provide 8,000 psi of gas pressure in the stimulation zone. Initial tests may use differential pressures alone (pressure built inside the sealed cryogenic tank) to inject the liquified gas, but if this doesn't work a cryogenic pump can be used. Downhole temperatures can exceed 200° F., providing the energy to return the injected liquified gas to a gaseous state, producing high pressures desired for formation stimulation. The service string acts as a heat exchanger, leveraging the formation temperature to drive the phase change and pressure buildup. Modeling and testing may be performed to ensure that the cryogenic liquid completes its phase change before reaching the end of the service string, or to verify that if the liquid exits the lower end of the service string it will not damage the well casing.

[0033] The service tubing valve is promptly closed after the injection. The liquified gas trailer may be disconnected and moved away from the wellhead. In block 318 the wellhead pressures are monitored as the formation heat vaporizes the liquified gas and elevates the pressure in the stimulation zone to the desired level. The valves are kept closed to provide sufficient time for the gas pressure to reopen existing fractures and repressurize the formation. In addition, the injected gas can mix with formation fluids to reduce fluid viscosity, further aiding in boosting production flow when the well is returned to production. The trailer may be left on station for future use or may be rigged down. After sufficient time (e.g., 24 or 48 hours), a wellhead valve may be opened in block 320 to recover or vent the residual gas pressure from the stimulation zone. As fluid flow begins in block 322, a wellhead valve may be opened to direct the flow to the production line. A tank battery may store the recovered liquid and gasses for later transport.

[0034] Well production may continue until such time as well stops flowing in block 324. In optional block 326, a crew installs an artificial lift system. This may involve, for example, rigging up a CTU to pull the stainless-steel service tubing string from the well and to install a regular continuous tubing string as production tubing. The production tubing string may include a seating nipple installed at the lower end. The crew may set a submersible pump in the seating nipple, either using the CTU or a regular pulling unit that can run the submersible pump with sucker rods. In block 328 production resumes using the artificial lift system. Production continues until the flow falls off to a noneconomic level in block 330. At that time, in block 332, management may determine whether repeat stimulation is desired, or whether the well is fully depleted. If depleted, a crew may plug and decommission the well in block 334.

[0035] For successive stimulation, blocks 316 to 324 are repeated at an almost negligible cost, assuming the service tubing string has been left in place. (Though the service string is initially used for delivering liquified gas to the stimulation zone, it may be left in place to serve as a production tubing string or a velocity string.) If an artificial lift system was installed, additional cost may be expected for removal of the artificial lift components and, if needed, re-installation of the service tubing string.

[0036] Sensors and controls may be used to inject a predetermined volume of liquified gas for stimulation, aiming for a pressure buildup to around 8,000 PSI or whatever has been determined to be optimal for the given formation. Pressure sensors and flow rate monitors provide real-time data for precise injection control. The control system considers gas flow dynamics, including turbulent flow and back pressure effects, to enhance operational efficiency. The gas from liquified gas expansion attains high pressures, facilitating stimulation through pre-existing perforations. This method offers an alternative to conventional high-pressure operations, reducing surface installations and associated safety risks. The method lowers the environmental footprint by avoiding large quantities of water and chemicals. Surface valves manage pressures, overseeing controlled residual gas discharge and subsequent well flow. A control algorithm adjusts surface valve operations based on pressure data from downhole sensors. Risk assessment protocols mitigate potential wellbore stability issues. Cryogenic valves designed for low temperatures ensure functionality during rapid phase transitions.

[0037] For comparison, a typical refracking operation through a 3.5″ liner may be expected to cost around 2.25 million dollars, whereas the disclosed stimulation method prices out below 0.5 million dollars. Successive liquified gas stimulations after the first are estimated at 50 thousand dollars, or 50 times less than a typical refracking operation. This cost reduction enhances the method's economic viability for operators seeking to maximize productivity with minimal expenditure.

[0038] The surface equipment that is configured for cryogenic liquid exposure may include: the wellhead, flanges, control valves, safety / relief valves, check valves, and bolts. The downhole equipment that is configured for cryogenic liquid exposure may include: casing liners, production tubing, service tubing, packers, seating nipples, and stingers. It is expected that this equipment will be made of stainless steel to render it capable of cryogenic operation.

[0039] Numerous modifications, equivalents, and alternatives will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable.

Examples

Embodiment Construction

[0013]The figures and following description do not limit the disclosure, but on the contrary, they provide the foundation for one of ordinary skill in the art to understand all modifications, equivalents, and alternatives falling within the scope of the claim language.

[0014]FIG. 1 shows a schematic representation of a system for liquified gas stimulation of a well. The well includes a cased borehole 102 that extends downward from the earth's surface 100. At a certain depth, the borehole transitions from vertical to horizontal, extending for a horizontal distance 106 to increase exposure to the reservoir formation 108. The figure is not drawn to scale. The vertical portion of the well may be, e.g., eight to ten thousand feet. The horizontal distance 106 may be, e.g., greater than ten thousand feet. The transition radius 104 may be, e.g., 600 to 1000 feet. Various casing perforations 110 are provided within the reservoir 108 to enable reservoir fluid to flow into the borehole.

[0015]A ...

Claims

1. A stimulation method that comprises:displacing a predetermined volume of liquified gas through a wellhead valve into a service tubing string providing access to a stimulation zone of a well; andclosing the wellhead valve to confine the liquified gas and pressurize the stimulation zone as the service tubing string vaporizes the liquified gas.

2. The stimulation method of claim 1, wherein the predetermined volume is sufficient to pressurize the stimulation zone to at least 8,000 psi.

3. The stimulation method of claim 1, further comprising, prior to said displacing, evacuating gas from an annulus around the service tubing string to reduce a vaporization rate of the liquified gas.

4. The stimulation method of claim 1, further comprising, prior to said displacing, adding fluid to an annulus around the service tubing string to increase hydrostatic pressure on a packer sealing the stimulation zone.

5. The stimulation method of claim 1, further comprising, prior to said displacing:installing a stainless-steel wellhead;setting a packer configured to tolerate exposure to cryogenic liquid; andrunning stainless steel tubing as the service tubing string anchored by the packer.

6. The stimulation method of claim 1, further comprising, prior to said displacing:installing a stainless-steel wellhead;installing a production tubing string anchored by a downhole packer configured to tolerate exposure to cryogenic liquid;running, inside the production tubing string, stainless steel tubing as the service tubing string anchored by a seating nipple configured to tolerate exposure to cryogenic liquid.

7. The stimulation method of claim 1, wherein said closing is for a close-in period of at least 24 hours, and wherein the method further includes returning the well to production after the close-in period.

8. The stimulation method of claim 1, wherein said displacing uses one or more pressure sensors and one or more flow rate monitors to provide control of the displacing, and wherein the displacing includes reducing a flow rate if a derivative of the borehole pressure exceeds a predetermined threshold.

9. The stimulation method of claim 1, wherein the liquified gas is liquified natural gas (LNG) or liquified methane.

10. The stimulation method of claim 1, wherein the liquified gas is liquified nitrogen.

11. A well that comprises:well casing within a borehole;a stainless-steel wellhead with a valve for receiving a liquified gas; anda stainless-steel service tubing string coupled to the valve to receive and vaporize the liquified gas.

12. The well of claim 11, further comprising a packer seated within the casing to anchor a lower end of the service tubing string and provide a pressure seal.

13. The well of claim 12, further comprising a vacuum pump to evacuate an annulus around the service tubing string.

14. The well of claim 12, further comprising a thermal insulation coating on an upper portion of the service tubing string to reduce a vaporization rate.

15. The well of claim 11, further comprising a cryogenic liquid transfer pump to transfer the liquified gas to the service tubing string.

16. The well of claim 15, further comprising:a pressure sensor coupled to the service tubing string; anda control system coupled to the pressure sensor and configured to responsively regulate a transfer rate of the liquified gas.

17. The well of claim 16, further comprising:a flow sensor coupled to the valve,wherein the control system is configured to close the valve or otherwise halt delivery of the liquified gas after a predetermined volume has been transferred to the service tubing string.

18. The well of claim 11, further comprising:a stainless steel production tubing string anchored to a downhole packer, the production tubing string providing a seating nipple that anchors a lower end of the service tubing string.

19. The well of claim 11, wherein the liquified gas is liquified natural gas (LNG) or liquified methane.

20. The well of claim 11, wherein the liquified gas is liquified nitrogen.

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