Liquid or Hydrate Power System Applied To A Single Point Injection Gas Lift System

Abstract

This system stores and uses as needed Compressed Gas, Hydrates, or Liquified Gas to unload and add power in order to produce a well or transfer fluids from one place to another. It can also supply gas to run the system, or generate electricity or various other auxiliary functions. It has been proven successful and could increase production in America and the world by bringing back into production wells that are not economical any other way. One well at a time, or entire fields can be produced with a single compressor. Stripper wells account for 40% of total domestic production. There are 1000s of wells not being produced. Huge production OPEC type wells could be produced with this system better, faster, and less expensive than any other system. This is also environmentally cleaner as very little gas will escape to the atmosphere. I believe that generators and other engines could be operated with this expanding vapor renewable physical reaction which seems close to the level of energy created during the expansion of a diesel chemical reaction.

Description

When producing a well or transferring fluid, the production system or transfer system stops occasionally resulting in a hydrostatic head loading the well or tubing. Conventional gas lift and liquid lifts use several preset valves or pumps to unload a system of its fluids. This system involves compressing or dropping temperatures or a combination of the two in order to cause sufficient pressure to overcome the hydrostatic head even a change from low pressure gas to hydrates, high pressure compressed gas, or Ia liquid. The hydrates form at a much lower pressure and higher temperature than liquids will form (2500+ psi and 10 degrees Kelvin), and hydrates offer a great point to unload shallow wells around 300 to 600 psi 30 to 60 degrees Fahrenheit.

Hydrates provide a very economical storage and expansion energy production point. Much lower phase change curves than LNG or LP. Therefore, this system can match the pressure of the loaded fluid, or can also match the height with liquids. Once the pressure, height or both are reached the system will be unloaded. The injected fluid will seep into the well and begin to move toward the surface as it will be in a denser fluid. It will at some point revert back to its natural state as a gas once pressure is low enough and temperature is high enough, and begin unloading, flushing, producing, hence gas lifting the well. This is the surface system which completes the through tubing gas lift mandrel system already pending.

Once at the surface, the gas is separated from the fluids, cleaned and re-compressed to the designed required composite for the well, and stored in the holding tank. This is for intermittent production where the system runs and then resets. A permanent system can use a second compressor which keeps the gas circulating while the liquification system takes the extra gas and converts it to a liquid for later use or various other uses.

The Gas Phase-Composite production system requires a holding tank for the compressed natural gas, hydrates or liquid natural gas, a separator to handle the gas phase and various produced liquid and gas components, a compressor to reach the designed pressure and content, and possibly a pump to transfer the liquid in the holding tank into the high pressure tubing of the production system. There may be a need for a second low pressure compressor to operate the unloaded system unless the compression and storage system can keep up constant production.

This system could unload problem wells which are unable to unload due to changes in pressure since original design. This system can easily be altered through the tubing or with respect to surface equipment. Nearly all of these components are available to purchase but have not been used in this collaborative manner or at the specific pressures, temperatures, or volumes. Specific fabrication to combine the components with pressure, volume, Temperature (PVT) controllers will need to be accomplished.

BACKGROUND OF THE INVENTION

This patent application deals with changing the way systems are unloaded of their column of static fluid. The original study was conducted when this module considering hydrate expansion was considered to be added to the blowout simulator created in an MWD class in 1986. It was too difficult to understand in a random reservoir of unknowns and so it was ignored with respect to the simulation. However, it was considered as possibly part of the through tubing gas lift system.

The hydrostatic head of the column can require a much higher pressure than the normal production pressure required of a flowing system. The industry uses several methods to unload the column of static fluid, and most involve using a series of preset pressure sensitive valves up the production system which pop off at different pressures to unload the well. This is incredibly expensive and in most cases must be placed in the well at the time of the original completion whether it is needed or not because doing this is so expensive otherwise. The expense can be 1 million to 5 million dollars a well just for the unloading and production system of a typical oil well offshore.

Onshore wells will not make enough to even consider this form of enhanced production from the conventional methods. Other methods like pumps will be torn up by the brine water and associated sand, metals, and corrosives. So the well is plugged with lots of oil still producible. The costs for every other method in the industry are just too high when initial system cost, installation, and constant maintenance are factored in. Every other system going deep enough for unloading pressure problems, use several preset pressured valves to unload the static column of fluid in the well. These can fail, and are very expensive to replace.

The present invention generally relates to enhanced oil recovery, in general to any valuable product being transferred from one tank to another, or produced from a well or other body of fluid. The cost to this system can be a lot less expensive then the current conventional methods when maintenance is considered. One example of a pump-jack producing 3 bbls of oil and 20 bbls of brine a day with metals and other corrosives cited the pump needed to be replaced every week or 4 times a month. For this very productive well a small workover rig is left on the well. The cost of this maintenance involves lost production for the duration, the labor cost of pulling the pump, lost rig income, and the cost of replacing or rebuilding the pump.

The compressor system or electric motor to run the pump at the surface can be damaged when the subsurface pump is damaged. Everything must be oversized to overcome the unloading of the static column of fluid in the system. All of these facets make any of these options uneconomical. The current system is extremely economical when compared in any way to any other system including initial cost, production costs, and maintenance costs.

The cost for the entire skid for a small well in FIG. 2 might be 20K, and that is very close to the cost of the pump jack, only it is better for the environment with all gas being collected, and very productive for the lease owner and operator as all energy costs come from the well/s. In FIG. 1 the deep 3 phase flow might cost 30K, but will produce a lot more fluid and be much more productive than the pumps fraught with maintenance issues, and with set production volumes that are much lower due to their positive displacement characteristics.

The current system is for one single well, but can be used for clusters or field-wide production. The wells will need to be unloaded one at a time through a valve header, or by a portable unloading system. The system depends on higher pressure and or a taller static column of Compressed Hydrates or Liquified Gas fluid in the high pressure line to unload the static column of fluid in the well. This cannot be done in the current system that pressures up the annular space and uses pre-pressured valves that pop open at certain pressures. The annular space is too voluminous to liquify or pressure up, will release the hydrates before they make it from the injection side into the production side of the system, and is not adequately rated for the pressures. The high pressure tubing used in this current system is very small volume and adequately designed and rated for the pressures.

BRIEF SUMMARY OF THE INVENTION

The present invention is directed to an apparatus that satisfies the above needs of cost and increases in production only limited by the reservoir not the production system, and is a vast improvement over other previously patented designs. This patent application involves the surface system used to produce the well if an existing compression system is not already in place. The downhole system can work with either surface system.

If no compression system is present, or if this system is to be used in addition to existing systems for wells with extreme loading issues, this is the option for the customer. Also this patent keeps the system pressured or lifts the well with high pressure compressed gas hydrates, or liquified natural gas going through an expansion or phase change in the well to become a gas. The system also removes excess gas by compressing the field gas when the separation or suction pressure is too high. The excess stored gas is used to start and run the system, or can be used for heating, cooking, run vehicles, electricity for use or to be sold to the grid, etc. The key is that it is kept from venting openly to the atmosphere.

Referring in general to FIG. 1. The system is not operating for whatever reason whether there was maintenance or intermittent operation. There is predetermined Stored Gas, be it air, Propane, Methane, Nitrogen, or any mixture of any gas phase which works effectively, at a designed pressure and temperature, in the LG Tank (10), The LG Pump (20) pumps LG into the high pressure inlet (31) of the well (30).

The CNG, Hydrates, or LG becomes higher pressure or height than the static head in the well and starts to flow into the production side of the mandrel. It starts to rise to its density level and the pressure drops allowing the Hydrates or LG to change phases into a gas. From that moment on it is just like every other flowing gas lift system. The well is unloaded, and the system gas along with the produced volume comes out of the well (30) on the low pressure production side (32). The entire produced 2 or 3 phase flow empties into the Separator (40). The oil is emptied to the Oil Tank (100), the brine and metals are overflowed past separator production levels to the Brine Tank (90). These will be handled appropriately from this point as industry and sales points require. The key at this point is how the gas lift system operates.

The gas phase is piped to the dryer by pressure regulation to the Dryer/Scrubber (50). This is a standard piece of equipment that cleans the gas of any impurities and dries it for re-compression to protect the compressor.

At this point what happens depends on the system design which depends on the production capacity. If the production is intermittent then the LG Compressor (60) will compress the gas back to the designed pressure and phase and pump it into the LG Storage Tank (10).

If it is continuous operation that is too fast for the single high pressure LG Compressor (60), there may be a need for a lower pressure higher volume compressor (70) to run the system like a normal industry standard closed loop gas lift compression system which compresses the gas to a designed pressure and pumps it back down into the well to keep producing fluid.

It may be possible to run continuously without the compressor (70) by injecting slowly into the well using the LG compressor (60) and LG Tank (10) continuously with just the equipment in FIG. 2. This depends on the reservoir and the required pressure and composure to produce the well. While continuous the pressure in the storage tank does not have to be as high or contain hydrates or be in a liquid phase because the pressure to produce can be much less than the pressure to unload the hydrostatic head. This is more efficient than existing art of the current systems that have one pressure that the valves release at to unload and produce.

If there is an increase in pressure the LG compressor (10) will take some of the excess and convert it to the designed system storage pressure to unload or produce continually. The controller (80) is monitoring all the components of the system to make decisions via control valves, check valves, etc. If the LG Tank is filled to a certain level either a sales point must be used or the system will just shut down until the LG can be used for whatever purpose. All of the dryers, compressors, pumps, and controls can run off field gas. Generation of electricity is also a possibility to ensure the system runs at a continuous pace if the producing reservoir will allow it. If things dry up and only gas is being circulated the controller (80) can shut down the system. The entire system can be mounted on a single skid, and each of the system components are available from multiple sources. The patent worthy design involves controlling and using the components to effectively unload and produce the well in the most efficient cost effectively safe manner using Liquified Gas and Compressed Gas depending on the well and system requirements. By capturing and using the greenhouse gases it is both an environmental success, and production becomes economical for what was otherwise an uneconomical well.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a top view of the entire possible production system for deep wells with continuous 3 phase flow of oil, brine, and water using an LG compressor (60) and a gas compressor (70) which is lower discharge pressure but higher rate and just boosts the pressure and flowrate. It is a smaller compressor than the conventional gas lift because the well is only produced with it and unloaded by the CNG, Hydrates, or LG in the LG Tank (10).

FIG. 2 is a top view of the possible production system for oil wells that produce all oil, and have low production rates requiring an intermittent production cycle. There could have been a pumpjack on the well and tubing in the hole, there is a wellhead and tubing to the tank which is piped to the separator, and this system is inserted in between the well and the tank where the pump jack used to be. There is only a 2 phase separator (40), no brine tank, and no continuous compressor (70). The well is blown clean as the gas is compressed into CNG, Hydrates, or LNG depending on the requirements to unload to wait for the next cycle. This depends on the flow-rate of the reservoir. This system could be used to unload problem wells in an existing field-wide gas lift system.

IDENTIFICATION OF PARTS/COMPONENTS OF INVENTION

10 LG Tank

20 LG Pump

30 Well

31 High Pressure Inlet

32 Low Pressure Outlet

40 2 or 3 Phase Production Separator

50 Dryer

60 LG Compressor

65 VRU (Vapor Recovery Unit)

70 Compressor for Gas (if Necessary)

80 Controller

90 Brine Tank

100 Oil Tank

DETAILED DESCRIPTION AND BEST IMPLEMENTATION

While the invention is susceptible to various modifications and alternative constructions, certain illustrated embodiments thereof have been shown in the drawings and will be described below in detail. It should be understood, however, that there is no intention to limit the invention to the specific form disclosed, but, on the contrary, the invention is to cover all modifications, alternative constructions, and equivalents falling within the spirit and the scope of the invention as defined in the claims. The patent worthy innovation involves making use of the temperature, pressure, and volume characteristics of phase change in order to improve the production potentials of Gas/Hydrate/Liquids to unload and produce a well by Gas/Hydrate/Liquid expansion or phase change.

Referring in general to FIG. 1, a gas lift unloading and compression system can be constructed in accordance with the principles of the invention is seen. It is assumed that the down-hole mandrel can be any system which accepts a high pressure gas/hydrate/liquid and returns said production system gas/hydrate/liquid plus additional reservoir material including gas, liquids and solids.

For example, while certain portions of the system have been described to have specific configurations, it is clear that some variation could be introduced, while still keeping within the teachings of the invention. Therefore, the spirit and scope of the appended claims should not be limited to the description of the preferred versions disclosed. It is paramount to understand that liquified natural gas can be used to create a static column of fluid, while high pressure compressed natural gas and hydrates with provide the pressure that will unload a well and change phases back to a gas when pressure drops in the producing well to lift the fluid and gas out of the well. Hydrates will expand 50 times their volume, and liquid natural gas will expand 500 times.

The Gas/Hydrate/Liquid will match the pressure of the reservoir fluids hydrostatic head. Then flow into the well from the mandrel high pressure side to the low pressure side, and move up through the hydrostatic head of the reservoir fluid toward the surface. This is due primarily to the lighter density of the injection fluid compared to the brine or oil in the reservoir fluid. This will be the primary method of unloading and possibly producing the well. No matter what the depth of the fluid in the well, or pressure, or temperature, the surface system PVT will cause the System Gas/Hydrate/Liquid to expand as it changes to a gas in the well. Consequently the well will be unloaded and produced in this manner. A second gas compressor can take over when the system is flowing continuously.

In FIG. 2, the pressure and volume of the phase change can produce these very shallow low production wells. With a phase change pressure of about 300 psi, and a volumetric expansion estimated to be around 50 times, it may only take 5 gallons of hydrate-natural gas to produce 5 bbls of oil. I say this as tests of my mandrel at 3 cuft per minute produce 3 gallons per minute. The wells are in some cases all oil, and seep slowly into the wellbore. This system could be run once or twice a week to empty the well or whenever the reservoir provides enough fluid. The gas would be recompressed for the next cycle. Gas could run the compressor, and there would be no need for a high pressure pump to inject the CNG, Hydrates, or LG into the well.

The injection fluid would flow in at a rate the LG Compressor (60) could match with flow control. Once inside the lower pressure of the mandrel and low pressure, larger volume of the well the CNG, Hydrates, or LG will expand and initiate the gas lift segment of the system. The oil will be separated from the gas in the 2 phase separator and transferred by system pressure to the tank. In both systems a vapor recovery unit could be used to make sure no gas is lost off the oil in the tanks. This could also produce the shallow wells of 2000′ and less that make oil and brine except with a 3 phase separator and a brine tank added. For examples mentioned it is impossible to describe every possible system.

The components are varied and numerous, but the main emphasis of this system design is to use at the core the LG system using either straight compression, nitrogen assisted compression, or refrigeration to change the gas to a high pressure gas, hydrate, or liquid and stockpile. Then to use the LG to unload and even produce the well in many cases. This will also give the land owner access to natural gas for heating, cooking, running the farm or lease land, or even generating electricity for the grid with a back up generator. When gas is low the system can run and create more. The extra gas will be monitored and limited but it will make life easier for places that loose their electricity in winter. There might be enough gas to even make money by selling to the grid as there will be no sales point in many remote locations.

The downhole mandrel is always flooded during production, and not picking up tiny bits of fluid but displacing fluid with expanding and flowing gas. The rate of flow is either to flush a seeping well of as much fluid as possible, or match a flowing reservoir so that the fluid is continually replaced by the reservoir at the same rate it is produced by the system. If the system does dry out then the system shuts down and recharges.

Hydrates form as low as 300 psi at a temperature as high as 40 degrees F. Compressed natural gas can be stored way in excess of the pressure required to unload the well with or without hydrates. Hydrates require cooling to form, but they have an expansion of 50 to 60 times the compressed volume, which can be very powerful in the low pressure production side of the system.

Compressed Natural Gas stored in the Storage Tank (10) will be flowed into the well at one pressure to unload and flush the well, and a lower pressure to produce continuously if the well flows. This will be decided from unloading tests and production tests.

The composite field gas may contain a variety of hydrocarbon and other gases. The points of hydration or sufficient stored compression can be determined by testing and designed for accordingly. The depth of the mandrel can be changed, and the pressure and volume of the system can be changed at the surface. This is vastly different than the set system parameters of the existing art.

The Controller (80) can keep track of whether the well is flowing, what rate of injection is required to keep the well flowing, whether a secondary compressor (70) is necessary, if there is extra natural gas that needs to be compressed and taken out the system and put in storage, and every other control which makes this one very phenomenal system.

A system such as FIG. 1 or FIG. 2 which stores compressed natural gas and uses temperature, pressure, volume, and/or phase change of a gas, hydrate or liquid, and the expansion, pressure, temperature and volumetric energies that can be expelled to unload the static fluid column, and produce or transfer an oil, gas, liquid, and solids.

The system comprises any or all of the following:

a) a storage tank (10) for compressed gas, hydrates or liquified gas,

b) a compressor (60) to compress and cool the gas to the designed pressure, temperature, and volume,

c) a pump (20) to transfer the liquified gas into the well in the high pressure side to match the hydrostatic head of the well and either go higher or add pressure to the column to unload the well (30) when injection fluid flows into the hydrostatic column of fluid in the low pressure side of the production system,

d) Any mandrel or pump that can use a gas, hydrate, or liquid to operate downhole using a high pressure line or existing production tubing, especially the through tubing gas lift mandrel by this inventor,

e) A typical production system for gas lift which may include a continuous compressor (70), separator (40), dryer (50), and tanks for each type of fluid produced and separated.

f) A controller which monitors the components of the system including pressure, temperature and volume to make decisions about functionality and production cycle specifics. This is typical of computer controllers that are market standard only it can also control two PVT (Pressure, Volume, Temperature) levels one to unload and one to produce.

The system where only a compressor (60), Injection Tank (10), Pump (20), Separator (40), Dryer (50), and Production Tank (100), and a vapor recovery (65) are required to operate the gas lift intermittently or continuously.

The system where gas is pressured and cooled to form hydrates and possibly to the point of a liquid and stored in a holding tank until the targeted production has filled the production side to a certain capacity which must be produced. The liquid height, hydrate volume, and gas pressure are then pumped into the well to create a force which offsets and overcomes the hydrostatic head in the well or low pressure production side of the system hence unloading the well.

The system where after the well is unloaded the injection gas, hydrates, or liquid begins to flow into the low pressure side of the gas lift mandrel and is less dense so it starts to rise to lower pressure. At some point it will cross the phase change boundary and turn to completely to gas with huge expansion displacing and flowing to the lower pressure at the end of the production system.

The system where the combination of all fluids and gases reach the field separator and are handled appropriately as far as is designed. The gas is sent to the scrubber then the LG compressor to be recompressed to a liquid and stored in the holding tank for the next production cycle, or is boosted and sent back down the well to continue production to a time when no more oil or whatever is left. At this time all the gas minus a trace pressure is pulled from the system and compressed into the designed pressure temperature and makeup all stored in the LG tank.

The system where the control unit determines if the system needs to continue producing or stop, and if gas needs to be skimmed off the system and liquified, or if a pressure drop is occurring which may signal a leak, how much gas and at what rate it needs to be pumped into the well. What lower pressure can the system be flowed after the system is initially unloaded and flowing. Basically every decision that needs to be made will be handled by the controller.

The system where the excess gas can be liquified to use as field gas to run the control valves, the compressors, the pumps, and the vapor recovery unit, as well as a generator, and other miscellaneous needs such as heating, etc.

The system where the excess gas can be liquified to use as field gas to run the control valves, the compressors, the pumps, and the vapor recovery unit, as well as a generator, and other miscellaneous needs such as heating, etc.

This implementation stems from the hope to understand what exactly happens with the expansion of hydrates and liquid natural gas. I in no way want this published because it is explosive by expansion. By warning folks not to try this at home I will certainly list warnings and careful experiments of very small quantities would ensue. The question is about the pressure and volume of expansion as hydrates go from a crystalline structure to a gas, and liquid field gas goes to a vaporous gas. I am not burning them in fact there is no oxygen in the closed loop. I would probably hold very high pressure gas in the storage tank, and upon usage a two path system would advance the gas through a cooling pump (20) and whatever hydrates that formed would be pumped into the well. Another path or process would bypass the cooling system or simply not engage that system for a time which would allow high pressure higher temperature gas to be injected directly into the well to kick off the hydrate expansion, unload, and produce the fluid in the well. This would produce shallow wells very handily, and would be a very available source of time controlled dependable predictable energy which is renewable through compression and cooling, expansion loop similar to air conditioning in a closed loop where the gas could also run all the pumps and be produced from the well.

Typical of the extreme pressures of very deep wells, the very high pressure gas would be cooled to a liquid and nitrogen removed in one path which would yield a liquid natural gas to be injected into the high pressure side of the well (31) or it could be stored as such in the storage tank. In either case, at one point when the well is to be unloaded and produced the liquid natural gas is injected into the well. With no check valve the fluid head in the mandrel is the same as in the well so the fluid and pressure in the high pressure side need only add and pressure the column in the high pressure side to start flow. Natural gas of high pressure and temperature could be added to the well to help with unloading and the necessary requirements to regasify the liquid such as re-injecting nitrogen, lower pressures, and higher temperatures will be realized in the very safe expansion zone of the tubing in the well. A very small amount of liquid natural gas would produce everything in the well very quickly. There is no chemical change, just physical changes in this system and to my knowledge there is no limit to the number of times this can be done. The winter would be easy to do things one way, while the heat of the summer would merit that the system be utilized in another way. These are design questions during implementation and do not effect the conceptual patents of a renewable source of energy used here in gas lift, but that could be used for so many prime mover applications as per the doctrine of equivalents. The cooling system part of the injection pump (20) could be turned off by the controller (80) during the second part of the two part injection and that would yield only gas to be injected. The expansion would be initiated by two parts differing only in temperature and injected nitrogen for the liquified natural gas phase change.

There are very serious implications to this work which will help a module of my blowout simulator which deals with hydrates in the earth, and even liquified natural gas as well. Are these coming out of solution during a blowout? The effect on the time it takes a gas kick to reach the surface when hydrate and phase expansions are present is greatly reduced. I have been trying my whole life since college to get in a position to complete this work. These systems should give me the ability to conduct these very serious investigations. I know that fires near this kind of system can be very serious, and extra precautions of pop off valves to vent contents under high pressure are of course in consideration. Warnings would be given, and for the sake of patent rights a very serious concept of B.L.E.V.E.'s must be understood. This is when the liquified natural gas boils and causes such a massive pressure build up that the vessel fails. A Boiling Liquid Expanding Vapor Explosion ensues and the effects can be unbelievably catastrophic. Vents and pop off are the way to handle these things, and a controller that even has access to fresh water or even brine that can be used to automatically put out a fires in an emergency. The system would create a wonderful way to unload and then produce a well or for other any other prime mover applications.

While there is shown and described the present preferred embodiment of the invention, it is to be distinctly understood that this invention is not limited thereto but may be variously embodied as per the doctrine of equivalents to practice within the scope of the following claims. From the foregoing description, it will be apparent that various changes may be made without departing from the spirit and scope of the invention as defined by the following claims.

Claims

1. A system which stores compressed natural gas and uses temperature, pressure, volume, and/or phase change of a gas, hydrate or liquid, and the expansion, pressure, temperature and volumetric energies that can be expelled to unload the static fluid column, and produce or transfer an oil, gas, liquid, and solids.

2. The system according to claim 1, comprising any or all of the following:

a) a storage tank for compressed gas, hydrates or liquified gas,

b) a compressor to compress and cool the gas to the designed pressure, temperature, and volume,

c) a pump to transfer the liquified gas into the well in the high pressure side to match the hydrostatic head of the well and either go higher or add pressure to the column to unload the well when injection fluid flows into the hydrostatic column of fluid in the low pressure side of the production system,

d) Any mandrel or pump that can use a gas, hydrate, or liquid to operate downhole using a high pressure line or existing production tubing, especially the through tubing gas lift mandrel by this inventor,

e) A typical production system for gas lift which may include a continuous compressor, separator, dryer, and tanks for each type of fluid produced and separated.

f) A controller which monitors the components of the system including pressure, temperature and volume to make decisions about functionality and production cycle specifics. This is typical of computer controllers that are market standard only it can also control two PVT (Pressure, Volume, Temperature) levels one to unload and one to produce.

3. The system according to claim 1, only a compressor, Injection Tank, Pump, Separator, Dryer, and Production Tank are required to operate the gas lift intermittently or continuously.

4. The system according to claim 1, where gas is pressured and cooled to form hydrates and possibly to the point of a liquid and stored in a holding tank until the targeted production has filled the production side to a certain capacity which must be produced. The liquid height, hydrate volume, and gas pressure are then pumped into the well to create a force which offsets and overcomes the hydrostatic head in the well or low pressure production side of the system hence unloading the well.

5. The system according to claim 1, where after the well is unloaded the injection gas, hydrates, or liquid begins to flow into the low pressure side of the gas lift mandrel and is less dense so it starts to rise to lower pressure. At some point it will cross the phase change boundary and turn to completely to gas with huge expansion displacing and flowing to the lower pressure at the end of the production system.

6. The system according to claim 1, where the combination of all fluids and gases reach the field separator and are handled appropriately as far as is designed. The gas is sent to the scrubber then the LG compressor to be recompressed to a liquid and stored in the holding tank for the next production cycle, or is boosted and sent back down the well to continue production to a time when no more oil or whatever is left. At this time all the gas minus a trace pressure is pulled from the system and compressed into the designed pressure temperature and makeup all stored in the LG tank.

7. The system according to claim 1, where the control unit determines if the system needs to continue producing or stop, and if gas needs to be skimmed off the system and liquified, or if a pressure drop is occurring which may signal a leak, how much gas and at what rate it needs to be pumped into the well. What lower pressure can the system be flowed after the system is initially unloaded and flowing. Basically every decision that needs to be made will be handled by the controller.

8. The system according to claim 1, where the excess gas can be liquified to use as field gas to run the control valves, the compressors, the pumps, and the vapor recovery unit, as well as a generator, and other miscellaneous needs such as heating, etc.

9. The system according to claim 1, where the excess gas can be liquified to use as field gas to run the control valves, the compressors, the pumps, and the vapor recovery unit, as well as a generator, and other miscellaneous needs such as heating, etc.

10. The system according to claim 1, which can be used to unload wells with broken gas lift components or different loading heights since the gas conventional gas lift was first installed.

11. The system according to claim 1, which in addition can use a two path or two procedure production enhancement which uses the high pressure gas, or partial hydrate from the storage tank to pump/cool then pump/heat an extremely hydrated gas into the well, and use a higher temperature lower pressure gas in a second path or at a controlled point in the process involving the cryo/pump, or to just bypass the cryo/pump at a time when the well has enough hydrates and needs a hot shot of compressed gas from the storage tank to spur the expansion of the hydrate in the high pressure side of the system to unload the fluid and get the production cycle going possibly to be used in a continuous system as this cooling could be very fast and only before the system is actually used to only compressed gas is actually stored.

12. The system according to claim 1, which in addition can use a two path production enhancement which uses the high pressure gas, or partial hydrate from the storage tank to pump/cool and remove nitrogen to result with a liquified natural gas which is then pumped into the well or point of required expansion energy, and use a higher temperature lower pressure gas along with the required nitrogen in a second path past the cryo/pump to spur the expansion and phase change of the liquid in the high pressure side of the system to unload the fluid and get the production cycle going possibly to be used in a continuous system and would require a very small amount of liquified natural gas to unload and flow the well, economically, safely, and most environmentally green.

13. The system according to claims 11 and 12, which use hydrates or liquified gas to power an engine or prime mover of any type without a chemical reaction but with only expansion and phase changes which are very efficient.