Well De-Liquefying System and Method

Abstract

De-liquefying a well includes a steady state de-liquefying cycle which includes an initial step of pressurising the gas with a compressor. In an example embodiment, gas is delivered into the well down an outer tube. The gas displaces liquid within the well by pushing the liquid within tubes up another tube, as a liquid slug, to the surface. A sensor operates to sense the arrival of the liquid. A controller interrogates the sensor to determine whether a slug of liquid has arrived. If not, gas is continued to be delivered into the well. When the controller determines via the sensor that a slug of liquid has arrived, the controller operates to shut the delivery of gas to the well. This may be done either immediately upon detection of the slug or at some predetermined delay thereafter. To shut down the delivery of gas to the well, the controller opens a valve (in the event it was shut) to allow the compressor to discharge to a sales line. The controller also closes a valve and opens another valve to relieve pressure within the outer tube to the separator pressure. The controller then idles for a prescribed time delay before recommencing the cycle.

Description

FIELD

The present invention relates to the de-liquefying of vertical and horizontal gas wells.

BACKGROUND

Liquid loading is a phenomenon where liquid accumulates at the bottom of a gas well. This limits and can ultimately prevent the well from producing gas at a commercially viable rate and in any event at a rate that would normally be possible if the liquid were not present.

The liquid accumulating at the bottom of the well may be water or oil, or a combination of both. Often, initially, the bottom hole pressure (BHP) of a well when first commissioned is sufficiently high so that up hole gas velocity would be sufficient to either carry liquid in the well to the surface, or at least will be sufficient to enable the gas to pass through the liquid to the surface at a reduced rate. The required gas velocity for this complete conveyance of liquid to the surface to occur is generally agreed to be in the order of 3 m (10 feet) per second or greater.

As a gas well loses BHP it will also lose up hole gas velocity, which often results in liquid loading of the well. Liquid that is not conveyed to the surface will build up in the well over time.

The liquid loading is also at times exacerbated by the very procedure required to initially construct and develop the gas well. This may particularly be the case for gas wells drilled in tight shale formations. These formations have a minimal porosity but still contain large volumes of gas. In order to release the gas, it is necessary to increase the permeability of the shale. One process for achieving this is hydraulic fracturing. Hydraulic fracturing involves pumping a slurry of water (“frac water”) and sand (“frac sand”) into the formation at sufficient pressure to fracture the rock. The sand assists in holding the fractures or cracks open after fracturing, allowing the gas to more readily migrate to the well bore. A significant percentage of the frac water will be produced back from the well formation in the initial stages of well development. However the remaining frac water will be held in the formation and produced over time, for example several years, as flow to the well bore. Frac water will also often carry frac sand into the well. The presence of the frac sand makes the frac water difficult to handle with conventional pumps.

It is typical to produce the gas directly up the well casing if possible, but generally very early in the life of a gas well a “velocity string” is installed inside the well casing to reduce the diameter the gas is being produced up and therefore increasing the up hole velocity. In this way liquid can be carried up with the produced gas for a longer term before liquid loading is experienced.

Once liquid loading begins, in some wells, an operator may have only recovered a small proportion of the gas in reserve, which could be as little as 10% or less of the total gas reserves present. At this point, some form of action is required to lift the liquid to the surface so the well can continue to produce gas at a commercially viable rate.

If the right set of circumstances exists, and where liquid loading is only marginal, the addition of foaming chemicals to the well will allow the available BHP to carry small amounts of liquid to the surface as they foam. This technique is often used because it is easy to implement. However is rarely effective for the long term and is also reliant on BHP to a reduced degree.

A further option available is to employ a method called “plunger lift”. This is a method which utilizes the available BHP to carry the liquid to the surface without needing an up hole gas velocity as high as 3 m (10 feet) per second. The plunger used in this method is in the form of a loose fitting plug, generally made of metal and about 500 mm long. When the gas well is in production the up hole velocity is typically sufficient to hold the plunger at the top of the production string. When the gas well is shut in, and production gas flow from the well stops, the plunger falls to the bottom of the production tubing. Given adequate time, it will eventually sink through the liquid and sit on a stop located at the bottom of the production tube.

After a predetermined period of time has elapsed, the well is put back into production. The gas pressure above the liquid in the production tubing falls away and the available BHP pushes the plunger to the surface with a slug of liquid riding above it. In the absence of a plunger in the tubing, the up hole velocity would not be sufficient to carry the slug up the tubing in a single body without the slug breaking up and falling back past the up flowing gas.

With a plunger in the tubing, only a very small insignificant volume of liquid is able to flow back past the plunger as the gas pressure is trying to push up past the plunger. Accordingly this system works well if there is adequate BHP and all other requirements are satisfied. Naturally, this Plunger lift method also relies on gravity to get the plunger to the bottom of the well. Thus this method is not viable in wells which extend beyond 30° from the vertical. De-liquefying of horizontal wells is a more pressing and important problem that requires a solution over vertical wells, therefore plunger lift fails to address this horizontal well problem.

Plunger lift and foaming are useful as they are relatively in expensive and do not rely on external energy other than the wells own BHP.

At some point the above methods that do not rely on any source of external energy other than BHP will not be effective due to reduced BHP and the options at that stage are to either re frac the well in the hope of increasing BHP or, use some form of artificial lift system on the well to remove the liquid. Conventional artificial lift systems include sucker rod pumps, progressive cavity pumps, hydraulically operated down hole pumps and electrical submersible pumps.

However the reliability of these pumping methods operating in the difficult environment of a gas well is so poor that a large number of potentially high producing wells are simply shut in awaiting a more effective technology for deliquefying these wells.

A further significant factor in optimizing gas production is the amount of pressure the well head is subjected to. In a typical gas well, the well casing, or velocity string if installed, is connected at the well head via a gathering line to a separator. The separator separates gas from liquid carried in the gas. The gas is then able to flow from the separator through a valve to a sales line. The sales line carries gas away from the well site for further processing and sale. Ideally the gas in the sales line is at a high pressure in order to effectively transport the gas to the further processing site. However if the sales gas line pressure is too high, for example 300 psi or greater, then the BHP of the well is required to push against this pressure as well as the pressure of the liquid in the hole. To provide context, a gas well head pressure of 300 psi will have the same detrimental effect on gas production on a well as a 660 ft column of liquid standing in the well. Therefore well head compression is often implemented to lower the well head pressure by drawing gas from the well with a gas compressor and forcing it down the sales lines. By reducing the gas pressure at the well head the up hole gas velocity is greatly increased and the affects of reduced BHP on the liquid loading problem can be minimised.

A gas well may have liquid in it for a number of reasons. It may be as a result of liquid loading or it may be that liquid was added to the well deliberately to “Kill” the well to work on it. If enough liquid of the necessary SG weight is added to a well it will completely prevent the well from producing gas at all making it safe to work on. After working on the well it is often necessary to “Kick the well off”. One way that this is done and specifically when the well is fitted with a velocity string is to use a large high pressure gas compressor to blow high pressure gas down the well casing or “back side”. The effect of this is to push liquid down the casing and up the velocity string to the separator. As there are no check valves involved in this conventional process much of the liquid is pushed back into the formation were it came from. This type of compressor is often mounted on a truck and driven to site when needed. Additionally frequently the gas used in this process is nitrogen, requiring the need to also hire a Nitrogen generator. Further due to the high pressures involved (e.g. over 5000PSI) additional safe precautions are required during this procedure. Naturally therefore this kick off process can not be used as a de liquefying method on an ongoing basis as gas production can not be maintained throughout the process and the size and pressure rating of the compressor required is much too large and expensive.

The present invention has arisen through a desire to provide an alternate mechanism for deliquefying a gas well.

SUMMARY

The present invention combines the benefits of well head compression and use of this same well head compressor to provide power to operate a deliquefying mechanism. A gas well that is completely emptied of fluid and has the lowest possible well head pressure will be producing at its maximum potential and operate economically for the longest life. The mechanism will combine the existing techniques developed to kick of a well with compressed gas with the use of a second inner string down the well and a check valve assembly so as to isolate this displacement zone from the producing well casing.

An example method of the present invention comprises de-liquefying a gas well provided with a well casing in fluid communication with a separator into which gas from the well flows, the method comprising:

• • delivering pressurised gas from the separator back into the well to displace liquid in the well to a location outside of the well.

The example method may comprise directing the liquid lifted from the well together with the gas used in lifting the liquid from the well to the separator.

The example method may comprise pressurising the gas from the separator which is delivered back into the well to a pressure sufficient to achieve a gas flow rate up the well of at least 3 m (10 feet) per second while carrying a slug of liquid.

The example method may comprise sensing when liquid lifted from the well reaches the location outside of the well; and, ceasing delivery of the gas from the separator back into the well at a selectable time after sensing the liquid reaching the location.

The example method may comprise, upon expiration of the selectable time period, relieving pressure of the gas to the separator pressure.

The example method may comprise performing a de-liquefying cycle comprising delivering gas from the separator into the well; ceasing delivery of gas at the selected time after sensing the liquid reaching the location, and relieving pressure of the gas to separator pressure.

The example method may comprise measuring a time period between delivery of gas back into the well from the separator and the liquid reaching the location; and,

• • using an adaptive algorithm to control a cycle rate of the deliquefying cycle on the basis of historical data relating to the measured time period.

The example method may comprise performing a start up procedure on initial use of the method, the start up procedure comprising:

• • forming a closed gas circuit between the well casing and the separator, and continuously circulating gas from the well to the well separator and back to the well for a selectable minimum time period.

The minimum time period may be between 5 minutes to 30 minutes.

The example method may comprise after performing the start up procedure, operating the method in a start up mode wherein during an initial number of deliquefying cycles after the start up procedure pressure of gas being delivered from the separator to the well is not relieved to well head pressure.

The initial number of cycles may be between 5 to 15 cycles.

The example method may comprise providing a return path for the delivered gas into and out of the well, wherein the return path is isolated from a production gas flow path from the well casing to the separator, the return path being arranged to allow one way flow of liquid residing in the well into the return path.

Providing the return path may comprise:

• • installing an outer tube in the well casing;
  • installing an inner tube in the outer tube to create a first leg of the return flow path between the inner tube and the outer tube, wherein an inside of the inner tube forms a second leg of the return path; and,
  • providing a one way valve allowing flow of liquid in a direction from the well casing into the outer tube.

The example method may comprise coupling a well head end of the inner tube to the separator.

The example method may comprise coupling a well head end of the outer tube to the separator.

The example method may comprise coupling a compressor between the separator and the well head end of the outer tube.

The example method may comprise providing a valved pressure relief path between the separator and the outer tube, the valved pressure relief path when opened, enabling pressure relief of the gas being delivered from the compressor to the well to be relieved to separator pressure.

Another example method of the present invention comprises de-liquefying a gas well provided with a well casing in fluid communication with a separator into which gas from the well flows, the method comprising:

• • installing an outer tube in the well casing;
  • installing an inner tube in the outer tube to create a first flow path between the inner tube and the outer tube and wherein fluid in the first flow path can flow into the inner tube;
  • enabling the inner tube to be in fluid communication with a fluid collector at a location outside of the well;
  • providing a one way valve allowing flow of liquid in a direction from the well casing into the outer tube; and,
  • pressurising gas sourced from the well and delivering the pressurised gas back to the well through the outer tube.

Enabling the inner tube to be in fluid communication with a fluid collector at a location outside of the well may comprise: arranging the inner tube to be in fluid communication with the separator wherein liquid and gas flowing through the inner tube is directed to flow into the separator.

The example method may comprise ceasing delivery of the pressurised gas upon in response to detecting presence of the liquid at a know location in the inner tube.

The example method may comprise venting the outer tube and the inner tube to the separator subsequent to detecting the presence of the liquid.

The venting may be performed at selectable time periods subsequent to detecting the presence of the liquid.

The example method may comprise using gas pressurised by a well head compressor of the well as the pressurised gas being delivered back into the well.

The example method may comprise:

• • designating the steps of: delivering gas from the separator into the well; ceasing delivery of gas; and, relieving pressure of the gas to separator pressure, as a de-liquefying cycle;
  • measuring a time period between delivery of gas back into the well from the separator and the liquid reaching the location; and,
  • using an adaptive algorithm to control a cycle rate of the de-liquefying cycle on the basis of historical data relating to the measured time period.

In a further example embodiment of the invention, a de-liquefying system is provided for a gas well having a well casing in fluid communication with a separator, the system comprising:

• • a fluid flow path extending from the separator down the well casing, up the well and to a location outside of the gas well; and,
  • a one way valve in the fluid flow path capable of allowing fluid flow only in a direction from the well casing into the fluid flow path, wherein pressurised gas from the separator is delivered to the well and is capable of displacing liquid in the well up the fluid flow path to the location.

The fluid flow path may comprise an outer tube extending down the well and being in fluid communication with the separator at a well head end and provided with the one way valve at a down hole end, and an inner tube suspended in the outer tube and having a down hole end above the one way valve and an opposite well head end in fluid communication with the separator, wherein pressurised gas from the separator flows down the outer tube and displaces liquid in the outer tube and inner tube up the inner tube to the separator.

The de-liquefying system may comprise a controller capable of cyclically controlling delivery of pressurised gas to the fluid flow path.

The controller may operate an adaptive algorithm to vary a rate of cyclically delivering pressurised gas on a basis of a plurality of measured times between delivery of pressurised gas and liquid displaced by the gas reaching the location.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of standard production equipment for a gas well;

FIG. 2 is a graph representing gas production from a gas well;

FIG. 3 is a schematic representation of a system for de-liquefying a well in accordance with an embodiment of the present invention;

FIG. 4 is a flow chart representing steps in a de-liquefying cycle in an embodiment of a method for de-liquefying a gas well; and,

FIG. 5 illustrates an embodiment of a method for de-liquefying a gas well.

DETAILED DESCRIPTION

FIG. 1 illustrates a typical well head arrangement for a gas well W. The gas well W is lined with a well casing 10 which is typically cemented in place and later perforated through which production gas flows to the surface. At the well head 12, the well casing 10 is coupled by a gathering line 14 to a separator 16. Isolation valve 18 is placed in the gathering line 14 together with one way valves 22 and 24 which prevent a flow of gas from separator 16 to the well casing 10. Separator 16 operates to separate production gas from liquid which may be lifted by the gas to the well head 12. The separator has a liquid outlet 26 through which liquid 28, separated from the gas in the separator 16 by action of gravity, flows to discharge conduit 30 due to the pressure within the separator. A gas outlet 32 of the separator 16 may be coupled by conduit 34a to a gas compressor 36 if the particular well is already fitted with well head compression. Gas compressor 36 in turn is coupled by conduit 34b to a sales line 38 via a valve 40. Gas compressor 36 draws gas from separator 26, which has the effect of reducing well head pressure, pressurises the gas and delivers the pressurised gas to sales line 38. The gas is pressurised in order to provide sufficient gas pressure for the gas flow along the sales line 38 to a remote storage facility or processing plant. In a typical operational scenario, gas pressure within separator 16 may be in the order of 20 PSI with well head compression fitted whereas gas discharged from a high pressure side 58 of compressor 36 for delivery to sales line 38 can be from 50 to 1,500 PSI. Compressor 36 requires a pumping capacity at least equal to the production capability of the well, for example 600 MCF/D. It is also known to have a well head compressor 36 servicing more than one gas well in which event the compressor FAD is scaled up accordingly.

Hypothetically initial BHP for the well W may be in the order of 3000-4000 PSI. This will ordinarily result in a gas up hole velocity well in excess of 3 m (ten feet) per second in which case liquid loading is not an issue. A substantial drop in BHP in a relatively short time period is common. For example, the BHP may drop to say 1000 PSI within three months or a few years. Thereafter, BHP will progressively decrease in time. In this initial phase of the well life it is not unusual to produce 1000 MCF of gas per day. However, as the BHP reduces, the ability of the gas to lift liquid from the well to de-liquefy the well reduces.

The onset of liquid loading can often be seen by tracking gas production from a well.

FIG. 2 illustrates an example of a gas production curve showing the effects of liquid loading. For a period from T0-T1 gas production is relatively high with BHP being sufficient to result in a gas velocity of >3 m (10 feet) per second. At T1 at which time BHP has reduced to a level where liquid loading commences, the gas production curve commences to oscillate. Initially there is a relatively quick drop in production to point a on the curve as liquid fills the well. The BHP may then build sufficiently over time and experience a short term recovery and increase up hole velocity to a level where the liquid can be blown from the hole resulting in a brief increase in gas production to point b on the curve. Subsequently BHP again falls and as liquid again builds in the well there is a relatively quick drop in production to point c on the curve. This cycle continues until the time T2 where the well is now liquid loaded to the extent that a column of liquid in the well W is built to a height such that the pressure exerted by the column is equal to the wells BHP so that the gas can no longer push its way into the well and gas production ceases.

Of all the various techniques described above for attempting to de-liquefy a gas well it is the installation of a velocity string which is generally the first to be used. FIG. 1 illustrates a velocity string 42 extending into the well. A velocity string is a smaller diameter production tube suspended in the well so that the diameter is reduced thereby increasing the up hole gas velocity. The use of the velocity string increases up hole friction and therefore can slightly reduce production although usually this is inconsequential in comparison to liquid loading. Depending on the well, a velocity string may alleviate liquid loading for a few months or even a number of years. However eventually the well will lose BHP to liquid load again.

FIG. 3 illustrates a system 50 which facilitates an embodiment of a method of de-liquefying a well W. In FIG. 3 features having the same or similar construction and/or operation to those depicted in FIG. 1 are denoted by the same reference numbers. The system 50 can be retrofitted or plumbed to an existing well head construction. In particular FIG. 3 illustrates the system 50 coupled to a well casing 10, gathering line 14, separator 16, and gas compressor 36. When the gas compressor 36 is used to service multiple wells it should have a FAD equivalent to the total production from all wells serviced plus an amount calculated to be necessary to operate the proposed method. Typically this additional capacity is expected to be from 5 to 15%. The system 50 includes an outer tube 52 that is suspended in the well casing 10. In the event that a velocity string 42 was already in place, the velocity string 42 with minor modification can be use as the outer tube 52. This modification being the fitting of a seating nipple at the down hole end which will involve the removal and subsequent re installment of the velocity string 42.

The outer tube 52 has an outer diameter substantially smaller than the inner diameter of well casing 10. For example outer tube 52 may comprise a standard 2⅜″ API EUE tubing provided with a standard 2⅜″ seating nipple at the bottom, while the well casing may have a diameter of 4.5″. The outer tube 52 is tied off at the well head 12 as it would have been when used as a velocity string. A check valve (i.e. one way valve) 54 is provided at a down hole end of outer tube 52. The valve 54 enables a flow of liquid in a direction from the well into the outer tube 52 but prevents a reverse flow of liquid. The down hole end of tube 52, is disposed: for a vertical well, below the level of a lower most perforation in well casing 10; or, for a horizontal well, to the point of lowest true depth. A well head end of a tube 52 is plumbed via conduit 56 to a high pressure side 58 of gas compressor 36. Conduit 56 is plumbed to conduit 34b between the high pressure end 58 of gas compressor 36 and valve 40 in the sales line 38. A further conduit 60 extends between conduit 56 and a point on gather line 14 between valves 18 and 22. Valve 62 is placed in conduit 60 to selectively open and close fluid communication between conduits 56 and gather line 14 through the conduit 60. A further valve 64 is placed in conduit 56 upstream of conduit 60. Conduit 56 also has installed in it a pressure transducer 66 upstream of valve 64, and may have a gas meter 68 upstream of the pressure transducer 66.

Pressure transducer 66 operates to provide an indication of gas pressure within conduit 56 to a controller such as a computer or a PLC. The controller is programmed to not commence a de-liquefying cycle in the event that pressure of the gas within conduit 56 is below a threshold level.

Gas meter 68 if provided operates to measure the volume of gas delivered back to the well. Gas meter 68 may typically be used where the system 50 is operating on a number of wells and provides a mechanism for metering the volume of gas delivered back to each well for production record keeping purposes only, as gas produced from one well may be used to de liquefy a different well. As the gas used to de liquefy the well will ultimately look like gas production from that well it is important from an accounting point of view to know how much gas is really produced from each well.

The system 50 also incorporates an inner tube 70 which passes through the outer tube 52 and is suspended so that a down hole end 72 is located slightly above a down hole end of outer tube 52. Inner tube 70 may have an outer diameter of about 1.5″. As a consequence a generally annular flow path is created between the outer tube 52 and inner tube 70. A well head end 74 of inner tube 70 is connected to gathering line 14 between one way valve 22 and valve 24. Liquid sensor 76 is coupled with a horizontal portion 78 of inner tube 70 and operates to sense the presence of liquid in the inner tube 70. Valve 80 is also placed in the horizontal portion 78 of inner tube 70 upstream of liquid sensor 76.

The valves 18, 65 and 80 form an isolation valve set 82 which during normal operation of system 50 are open to allow fluid flow. The isolation valve set 82 can be manually operated however to isolate the well W from equipment down stream of the well head for maintenance purposes or in emergency situations.

A pressure transducer 84 is also coupled with gathering line 14 downstream of valve 18 and upstream of the location where conduit 60 joins gathering line 14. The pressure transducer 84 measures gas pressure in the gathering line 14 and communicates this to the controller. The controller is programmed to not attempt to operate the system 50 to de-liquefy the well if the measured gathering line pressure is above a certain threshold. This pressure would be typically around 50 PSI

In normal operating conditions of system 50, valve set 82 will always be open. Initially all valves will be found in their “Shut In” positions. Valve 62 will start in the open position, valve 64 would be shut, valve 20 would be shut and valve 40 would be open.

For the purposes of this description of system 50, we are assuming that this particular well no longer has enough BHP to achieve an up hole velocity of 3 m (10 feet) per second, either up the casing or up a velocity string, otherwise the operator would not have a liquid loading problem to contend with. We are also in this example making the assumption that the system has been recently operated and has been “shut in” in accordance with the proper procedure therefore there is not the requirement for a high pressure kick off described previously.

Firstly valve 62 would be closed by the PLC to maintain as much pressure as possible in the riser pipe 52. Valve 20 is opened to allow gas from the well casing 10 to flow through conduit 14 to the separator 16. Initially there should not be any liquid carried in this gas but if there was the liquid 28 is separated from the gas and is discharged via outlet 26 and conduit 30. The gas flows through outlet 32 through conduit 34 to the gas compressor 36. Gas is now compressed and discharged at high pressure side 58 and flows through conduit 34b and open valve 40 to the sales line 38.

Gas within the conduit 56 is also pressurised to the same pressure as the gas and sales line 38. However this gas isn't able to flow to the well by virtue of valve 64 being shut. In addition, the pressure transducer 66 provides a signal to the controller indicative of the gas pressure within conduit 56. The controller is programmed to shut valve 64 (in the event that it was not previously shut) and more importantly not initiate a pumping cycle when gas pressure in line 56 is sensed as being lower than that expected to be delivered back into the well for de-liquefying purposes. For example, for the well at hand, if initial calculations show a gas pressure of between 300-400 PSI would ordinarily be required during a de-liquefying cycle, the controller may be programmed to automatically shut valve 64 or not initiate a cycle if gas pressure sensed by sensor 66 in conduit 56 is say under 500 Psi.

In describing operation of system 50, assume that well W is liquid loading, but not liquid loaded. Liquid is at a level L in the well W. Liquid is thus at the same level inside of outer tube 52 and on the inside of inner tube 70. The tubes 52 and 70 form a return flow path 90 comprising a first leg 92 (shown with double arrows) formed by a substantially annular space between outer tube 52 and inner tube 70, and a second leg 94 (shown by triple arrows) being a return leg up the inside of inner tube 70. Thus, assuming the appropriate state or position of the valves, fluid is able to flow through conduit 56 down first leg 92 between tube 52 and tube 70, back up tube 70 and into the gathering line 14.

Liquid is at level L in the well W and within the tubes 52 and 70. A de-liquefying cycle of system 50 comprises delivering pressurised gas from the separator 16 back into the well W to lift liquid in the well to a location outside of the well. For the gas compressor 36 to be able to achieve sufficient pressure to overcome the static weight of the vertical column of fluid in the inner tube 94 it may be necessary to close gas valve 40 to the sales line otherwise the maximum pressure attainable will be equivalent to sales line pressure only. Though not often required the compressor will often have a top pressure rating of 1,500 to 2,500 PSI.

Pressurised gas, which was initially sourced from the well W, is being delivered back into the well through conduit 56 down the first leg 92. The gas pressure acts on the surface of liquid L within the outer tube 52 forcing the liquid down outer tube 52 to flow up the inner tube 70 (i.e. up the second leg 94). The liquid cannot re-enter the well W by action of the valve 54. As the gas continues to act it forces substantially all of the liquid within the inner tube 70 creating a liquid slug, and the gas follows the liquid slug up the inner tube 70. The liquid eventually reaches a location outside the well where it is sensed by sensor 76 within horizontal section 78. The liquid, together with the following gas flows into gathering line 14, valve 20 and one way valve 24, into the separator 16. Also, upon sensing the presence of liquid in the horizontal section 78, the controller closes valve 64 to prevent any more compressed gas to be used for that cycle, opens valve 40 (in the event it was closed) to allow gas from the compressor to return to the sales line and opens valve 62 to relieve pressure within conduit 56 to separator pressure at the well head, i.e. pressure within gathering line 14 and separator 16. Thus pressure is equalised between outer tube 52, gathering line 14 and separator 16. This also relieves pressure on valve 54 allowing liquid from well W to flow into tubes 52 and 70. Depending on the circumstances at hand, valves 40, 64 and 62 may be operated to close and open immediately upon detecting of liquid by the sensor 76, or may be closed and opened at a selectable time delay thereafter.

This completes one de-liquefying cycle of system 50.

The cycle can be continuously repeated at set or variable periods. For example this cycle may be repeated once every hour. The volume and pressure of gas delivered per cycle is determined to provide an up hole gas velocity in the order of 3 m (10 feet) per second in order to lift liquid within the well to the surface. During each cycle, the controller by virtue of operation of sensor 76 is also able to determine the length of time that the sensor senses liquid, i.e. the length of time the sensor is wet. As the inner diameter of inner tube 70 is known, and the velocity of the liquid is known (or assumed at 3 m (10 feet) per second) the controller can determine the approximate volume of liquid lifted per cycle. The controller may be provided with a self learning or adaptive algorithm to vary the cycle period on the basis of a running average of liquid volumes over a previous number of cycles. For example if a cycle is initially performed at periods or intervals of one hour, but the controller determines that the sensor 76 is wet for increasing lengths of time per cycle, which is indicative of liquid loading occurring at a greater rate, the cycle period may be reduced to say 59 minutes. Alternately, if it is determined that the sensor 76 is staying wet for successive shorter periods of time per cycle then the cycle period may be extended to say one hour and one minute. However, maintaining a quicker cycle period than may be strictly necessary does not create any substantive burden or difficulty as the gas delivered to the well per cycle is simply returned each cycle. There is a marginal increase in energy use due to the need to operate compressor 36 to deliver the gas into the well. However this is inconsequential to the overall viability of the well.

It is important to note that this system 50 is not a conventional “Gas Lifting” system. Unlike conventional gas lifting, System 50 is not reliant on the presence of gas mixed with liquid, changing the specific gravity of that liquid to make it possible for the wells bottom hole pressure to “gas lift” the fluid to the surface. It would be possible for an embodiment of system 50 to operate with no BHP in the well at all. By devising a system where we have one tube within another tube within the well casing it is possible for system 50 to effectively create its own BHP environment. This system 50 could be best described as “Slug Lift”.

A slug of liquid is formed by forcing gas down tubing 70 until the displacement gas has forced the top of the liquid all the way down to the bottom of tube 70. As the liquid is forced down the annular flow path 92 by gas pressure the liquid is displaced into and raised up inside tube 94. Once all the liquid has been forced up inside tube 70 the pressure required will not continue to rise any further. The pressure that is required to raise this slug further up tube 70 is a result of a calculation of the SG of the liquid multiplied by the total height of the liquid slug inside the inner tube 94 plus any pressure that is operating against the top of the slug caused by well head and separator back pressure. Additional to this static pressure an allowance has to be made for friction loss acting on the liquid slug in tube 70.

The gas then proceeds to follow the slug of liquid up tube 70. The rate of travel of this slug of liquid up the inner tubing 70 is required to be 3 m (10 feet) per second or greater to ensure that the slug continues to maintain upward travel without falling back. The calculation of the volume of gas required to maintain this 3 m (10 feet) per second up hole velocity of the liquid slug is complex but is primarily the operating pressure multiplied by the volume of 3 m (10 feet) of the tube 70.

FIG. 4 depicts in the form of a flow chart a method 100 of de-liquefying a well W using system 50. The method 100 comprises a steady state de-liquefying cycle 101 which has an initial step 102 of pressurising the gas (by use of compressor 36). This gas is then at step 104 delivered into the well W down leg 92 (i.e. tube 52) of the return path 90. The gas displaces liquid within the well W by in effect pushing the liquid within tubes 52 and 70 up tube 70 to the surface. At step 106 in the method, sensor 76 operates to sense the arrival of the liquid. At step 108 the controller interrogates sensor 76 to determine whether or not a slug of liquid has arrived. If not, gas is continued to be delivered into the well and the method returns to step 104. However when the controller determines via sensor 76 that a slug of liquid has arrived, the controller at step 110 operates to shut the delivery of gas to the well W. This may be done either immediately upon detecting of the slug or at some predetermined delay thereafter. To shut down the delivery of gas to the well W the controller opens valve 40 (in the event it was shut) to allow the compressor 36 to discharge to the sales line 38. Simultaneously, at step 112 the controller closes valve 64 and opens valve 62 to relieve pressure within the outer tube 52 to the separator pressure. The controller then idles for a prescribed time delay 114 before recommencing the cycle.

The steps of method 100 depicted in FIG. 4 together represent the steady state de-liquefying cycle of operation of system 50.

With reference to FIG. 5, it is also seen however that method 100 incorporates an initial start up sequence or procedure 120 and subsequently performs a number of start up cycles 122 prior to entering the steady state de-liquefying cycle 101. In start up procedure 120 valve 40 is shut, valve 62 is shut, valve 64 is open, valve 20 is open and the valve set 82 is open. Compressor 36 is operated to deliver gas from separator 16 through outer tube 52 into the well W. The delivery of gas is maintained for an extended period of time for the purposes of essentially blowing out the liquid within the outer tube 52 and inner tube 70. At this time the system is performing a conventional “gas lift” function as the well has been shut in and probably has sufficient liquid within the well for a conventional gas lift to work for a short time. It is thought that this cycle may take between five to thirty minutes. The start up procedure can be terminated when sensor 76, after initially detecting presence of the liquid, subsequently detects the occasional presence of a liquid.

After the start up procedure 120, system 50 enters or commences a number of start up cycles 122. Typically between 5 to 10 start up cycles may endure prior to the method 100 moving to the steady state de-liquefying cycles 101. The start up cycles 122 operate in the same manner as steady state cycle 101 with the exception that step 112 being the pressure relief/equalisation step is bypassed. In practice this means that the valve 62 is maintained closed for the start up cycles. The purpose of this is to maintain pressure within the outer tube 52 resulting in less liquid entering this space from the well through check valve 54 resulting in a shorter slug height and subsequently reduced operating pressure during start up.

During all times of operation of the system 50 and method 100, the well W is able to produce gas via the casing 10 (assuming sufficient BHP) which then flows through gathering line 14 and into separator 16. Further, the gas pressure within outer tube 52 is isolated from the well pressure. Thus the system 50 and method 100 does not provide any substantive impediment or interruption to gas production from the well.

Embodiments of the method enable liquid to be lifted from a well using gas from the well itself as well as much of the existing infrastructure. In terms of hardware, all that is required in order to install the system 50 and operate method 100 is tubing of two different diameters, a number of valves, some sensors and a controller such as a computer or a PLC.

Modifications and variations to the system and method that would be obvious to persons of ordinary skill in the art are deemed to be within the scope of the present invention the nature of which is to be determined from the above description and the appended claims.

Claims

1. A method of deliquefying a gas well provided with a well casing in fluid communication with a separator into which gas from the well flows, the method comprising:

pressurising the gas from the separator;

delivering pressurised gas from the separator back into the well to lift a liquid slug in the well together with the gas used in lifting the liquid from the well to the separator, wherein the gas from the separator which is delivered into the well is pressurised to a pressure sufficient to achieve a gas flow rate up the well of at least 3 m (10 feet) per second while carrying a slug of liquid.

2. The method according to claim 1, further comprising:

sensing when the liquid slug lifted from the well reaches a location outside of the well; and

ceasing delivery of the gas from the separator back into the well at a selectable time after sensing the liquid reaching the location.

3. The method according to claim 2, further comprising:

upon expiration of the selectable time period, relieving pressure of the gas to the separator pressure.

4. The method according to claim 3, further comprising:

performing a deliquefying cycle comprising delivering gas from the separator into the well;

ceasing delivery of gas at the selected time after sensing the liquid reaching the location; and

relieving pressure of the gas to separator pressure.

5. The method according to claim 4, further comprising:

measuring a time period between delivery of gas back into the well from the separator and the liquid reaching the location; and

using an adaptive algorithm to control a cycle rate of the deliquefying cycle on the basis of historical data relating to the measured time period.

6. The method according claim 5, further comprising:

performing a start up procedure on initial use of the method, the start up procedure comprising forming a closed gas circuit between the well casing and the separator, and continuously circulating gas from the well to the well separator and back to the well for a selectable minimum time period.

7. The method according to claim 6, wherein the minimum time period is between 5 minutes to 30 minutes.

8. The method according to claim 7, further comprising:

after performing the start up procedure, operating the method in a start up mode wherein during an initial number of deliquefying cycles after the start up procedure pressure of gas being delivered from the compressor to the well is not relieved to seperator pressure.

9. The method according to claim 8, wherein the initial number of cycles is between 5 to 15 cycles.

10. The method according to claim 6, further comprising:

providing a return path for the delivered gas into and out of the well, wherein the return path is isolated from a production gas flow path from the well casing to the separator, the return path being arranged to allow one way flow of liquid residing in the well into the return path, wherein providing the return path comprises:

installing an outer tube in the well casing;

installing an inner tube in the outer tube to create a first leg of the return flow path between the inner tube and the outer tube, wherein an inside of the inner tube forms a second leg of the return path; and

providing a one way valve allowing flow of liquid in a direction from the well casing into the outer tube.

11. The method according to claim 10, further comprising:

providing a valved pressure relief path between the separator and the outer tube, wherein the valved pressure relief path, when opened, enables pressure relief of the gas being delivered from the compressor to the well to be relieved to separator pressure.

12. A method of de-liquefying a gas well provided with a well casing in fluid communication with a separator into which gas from the well flows, the method comprising:

installing an outer tube in the well casing;

installing an inner tube in the outer tube to create a first flow path between the inner tube and the outer tube and wherein fluid in the first flow path can flow into the inner tube;

enabling the inner tube to be in fluid communication with a fluid collector at a location outside of the well;

providing a one way valve allowing flow of liquid in a direction from the well casing into the outer tube; and

pressurising gas sourced from the well and delivering the pressurised gas back to the well through the outer tube.

13. The method according to claim 12, wherein enabling the inner tube to be in fluid communication with a fluid collector at a location outside of the well comprises:

arranging the inner tube to be in fluid communication with the separator wherein liquid and gas flowing through the inner tube is directed to flow into the separator.

14. The method according to claim 13, further comprising:

ceasing delivery of the pressurised gas upon in response to detecting presence of the liquid at a know location in the inner tube.

15. The method according to 14, further comprising:

venting the outer tube and the inner tube to the separator subsequent to detecting the presence of the liquid.

16. The method according to claim 15, further comprising:

designating the steps of delivering gas from the separator into the well, ceasing delivery of gas, and relieving pressure of the gas to separator pressure, as a de-liquefying cycle;

measuring a time period between delivery of gas back into the well from the separator and the liquid reaching the location; and

using an adaptive algorithm to control a cycle rate of the de-liquefying cycle on the basis of historical data relating to the measured time period.

17. A de-liquefying system for a gas well having a well casing in fluid communication with a separator, the system comprising:

a fluid flow path extending from the separator down the well casing, up the well and to a location outside of the gas well; and

a one way valve in the fluid flow path capable of allowing fluid flow only in a direction from the well casing into the fluid flow path, wherein pressurised gas from the separator is delivered to the well and is capable of displacing liquid in the well up the fluid flow path to the location.

18. The de-liquefying system according to claim 17, wherein the fluid flow path comprises:

an outer tube extending down the well and being in fluid communication with the separator at a well head end and provided with the one way valve at a down hole end; and

an inner tube suspended in the outer tube and having a down hole end above the one way valve and an opposite well head end in fluid communication with the separator;

wherein pressurised gas from the separator flows down the outer tube and displaces liquid in the outer tube and inner tube up the inner tube to the separator.

19. The de-liquefying system according to claim 18, further comprising:

a controller configured to cyclically control delivery of pressurised gas to the fluid flow path.

20. The de-liquefying system according to claim 19, wherein the controller operates an adaptive algorithm to vary a rate of cyclically delivering pressurised gas on a basis of a plurality of measured times between delivery of pressurised gas and liquid displaced by the gas reaching the location.