Method and system for enhancing hydrocarbon production from a hydrocarbon well

Abstract

Production from a hydrocarbon well is facilitated when heat generated by surface equipment used to produce hydrocarbons from the well is continuously injected into the well to heat the well system. The heat may be further concentrated using a vortex tube to separate a hot component from a cold component of compressed gas injected into the well.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This is the first application filed for the present invention.

MICROFICHE APPENDIX

Not applicable.

TECHNICAL FIELD

The invention relates generally to producing hydrocarbons from a hydrocarbon well and, in particular, to enhancing hydrocarbon production from a hydrocarbon well by heating the hydrocarbon well using heat generated by surface equipment used to produce the hydrocarbons from the well.

BACKGROUND OF THE INVENTION

Hydrocarbons production zones, especially subterranean natural gas production zones have a natural pressure when the hydrocarbon well is drilled to communicate with the zone. The production zone also has a natural geothermal temperature. Production zones often contain natural gas and other fluids such as hydrocarbon condensates, water, crude oil, etc. All of those fluids in the production zone are at ambient temperature and pressure when the well bore is drilled. Normally, in a commercial gas well the original pressure and temperature is sufficient to permit the natural gas to expand and move to a lower pressure at the surface of the well. Frequently, the original flow rate has a velocity sufficient to carry all of the fluids out of the production zone to the surface. Consequently, in many natural gas wells other fluids such as water and hydrocarbon condensates are produced along with the natural gas. However, as the well matures the pressure in the production zone is depleted and a velocity of hydrocarbons produced at the wellbore decreases, allowing some of the fluids to fall below a critical velocity for the natural gas to lift the fluids from the well. Furthermore, the expanding natural gas cools as it rises to the surface, permitting liquids to condense in the wellbore at the reduced pressures and temperatures in the upper regions of the well. In off-shore wells, and particularly in deep water wells, the well fluids have to pass through long sub-sea floor lines and risers to the ocean surface. Sea floor temperatures can be low, causing further cooling of natural gas and potential plugging of the flow from the well.

Fluids condensing from the rising natural gas can accumulate in the wellbore and exert hydrostatic pressure against the reservoir, restricting the rate at which natural gas can flow from the well to the surface. Furthermore, the expansion and cooling of the rising natural gas can cause fluids to freeze causing ice plugs and resulting in a complete blockage of fluid production. Those ice plugs are referred to as “clathrates” or “gas hydrates”. Gas hydrates are crystalline solids that look like ice. Gas hydrates occur when water molecules form a cage-like structure around smaller “guest molecules”. The guest molecules are most commonly methane, ethane, propane, butane, nitrogen, carbon dioxide and hydrogen sulfide, of which methane occurs most frequently. The formation of gas hydrates is exacerbated by cold weather conditions.

In many instances, fluid accumulation in a well and the resulting hydrostatic pressure can cause fluid production to drop significantly, or to stop completely. In such instances, well fluids are generally artificially lifted to the surface to enhance production from the well. Fluids may be lifted using pumps deployed in the well, pumping natural gas down the well to lift the fluids, using plunger lift systems. Chemical additives may also be pumped down the well to inhibit hydrate plugging and fluid accumulation. Such chemicals are pumped down the well while it is producing.

It is also been demonstrated that by running electrical heating cables into the well the temperature of the well system can be increased to keep the liquids from condensing. While electrical heating systems are technically achievable, the application of electrical heat requires the installation of an electrical power system to the well, the deployment of electrical cable within the well and a risk of explosion due to electrical sparks in a gaseous environment.

It is also common industry practice to reduce the surface pressure into which the natural gas flows using compressors. Compressors are used because well fluids may have adequate pressure to flow to the surface against atmospheric pressure but natural gas wells produce into natural gas distributions systems, such as pipelines, through which natural gas is transported to market. Delivering natural gas to a pipeline requires the natural gas be pressurized to a pressure slightly higher than the pressure in the pipeline to permit the natural gas to flow into the pipeline system. Consequently, there are many compressors in the around natural gas fields for the purpose of pressurizing the natural gas to a pressure higher than the pressure in the pipeline. Those compressors are often located at a central facility where natural gas from several wells are brought to the facility and compressed before transfer to the natural gas pipeline.

As shown in FIG. 1, further pressure reduction in the well is achieved by placing a compressor 26 at a well site and pulling a vacuum pressure on the well using the compressor 26 to lower the surface pressure and to compress the produced natural gas to a pressure higher than pipeline pressure, to permit the natural gas to be injected into the pipeline. The compression of the natural gas increases the temperature of the natural gas and it is generally required to cool the natural gas prior to injecting it into a pipeline 34. Otherwise, the temperature in the pipeline could increase and the amount of natural gas conducted through the pipeline would be correspondingly reduced. The heat removed from the hot compressed natural gas is normally exhausted to atmosphere using any one of a variety of heat exchangers.

As shown in FIG. 1, natural gas 16 produced from a production zone 12 enters a casing 10 through perforations 17, in a manner well understood in the art. For the sake of simplicity of illustration, the well shown in FIG. 1 is not equipped with production tubing. The natural gas 16 rises through the casing 10 to wellhead 14 and enters a conduit 18 which conducts the natural gas to a separator 20. Fluids are separated from the natural gas by the separator 20 in a manner well known in the art. The fluids flow through conduit 22 to a fluid tank 24. The remaining natural gas is delivered to the compressor with the prime mover 26. In most instances, the prime mover is an internal combustion engine supplied with fuel through a fuel line 28 connected to the conduit 18. The hot compressed natural gas is output by the compressor through a conduit 30. As explained above, the compressed natural gas is generally too hot to be introduced directly into the pipeline 34. Consequently, a cooler 32 cools the hot compressed natural gas before it is delivered to pipeline 34. A check valve 36 ensures that natural gas does not escape from the pipeline in the event that production of natural gas from the well is halted. As also explained above in detail, gas hydrates 17 frequently form within the casing 10 in the upper regions of the well. The hydrates 17 can restrict or completely stop production from the well.

The control and dissolution of gas hydrate plugs is known and many systems for delivering chemical dissolvers or inhibitors have been invented. However, such systems generally require expensive additives and frequent maintenance.

There therefore exits a need for a simple and inexpensive system for facilitating production from a hydrocarbon well that does not require frequent or extensive maintenance.

SUMMARY OF THE INVENTION

It is therefore an object of the invention to provide a system for facilitating production from a hydrocarbon well that is simple to construct, requires little maintenance and uses waste energy to heat the well system.

In accordance with one aspect of the invention there is provided a method of enhancing production from a hydrocarbon well comprising continuously injecting into the well heat generated by surface equipment used to produce the hydrocarbon from the well.

In accordance with another aspect of the invention there is provided a method of enhancing production from a natural gas well, comprising: flowing natural gas from the well to a compressor and compressing the natural gas; diverting a proportion of the compressed natural gas back into the well; and delivering a remainder of the compressed natural gas to a natural gas distribution system.

In accordance with yet another aspect of the invention there is provided a system for enhancing hydrocarbon production from a hydrocarbon well, comprising: a power source for continuously injecting into the well a fluid heated by heat generated by surface equipment used to produce the hydrocarbon from the well.

BRIEF DESCRIPTION OF THE DRAWINGS

Further features and advantages of the present invention will become apparent from the following detailed description, taken in combination with the appended drawings, in which:

FIG. 1 is a schematic diagram of a prior art system for producing natural gas from a hydrocarbon well;

FIG. 2 is an embodiment of a system in accordance with the invention for producing natural gas from a hydrocarbon well;

FIG. 3 is a schematic diagram of another embodiment of the invention for producing the natural gas from the hydrocarbon well; and

FIG. 4 is a schematic diagram of yet another embodiment of the invention for producing crude oil from a hydrocarbon well.

It will be noted that throughout the appended drawings, like features are identified by like reference numerals.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The present invention provides a method and system for enhancing production from a hydrocarbon well. In accordance with the invention, heat generated by surface equipment used to produce hydrocarbon from the well or to compress natural gas produced by the well is continuously injected into well to heat the well. Heating the well has several benefits, including: a reduction or elimination of the formation of gas hydrates, condensates and other solids or fluids that inhibit production from the well; and, in the case of oil production, paraffins, bitumens and asphaltenes tend to stay in solution until the oil is produced from the well. Heat generated by the surface equipment may be delivered directly from natural gas compressed by a surface compressor; heat recuperated from a prime mover used to produce natural gas or oil, such as a compressor motor, compressor engine or a motor or engine use to drive a surface pump. The heat may be injected into the well by diverting compressed natural gas back into the well or circulating a heated, compressed gas into an oil well. Heat recovery can be enhanced using a vortex tube to increase an efficiency of the system in accordance with the invention.

FIG. 2 is a schematic diagram of an embodiment of a system in accordance with the invention. In this embodiment, natural gas 16 produced from production zone 12 enters the casing 10 through perforations 17 and migrates upwardly through a production tubing 15. The natural gas is isolated from rising in an annulus between the casing 10 and the production tubing 15 by a packer 19 provided with passages 21 closed by check valves 23 which permits heated compressed natural gas 48 to pass from the annulus into the production zone as will be explained below in detail. The natural gas 16 is produced from the well at a natural pressure that is below the pressure of natural gas in a natural gas distribution system, such as the pipeline 34 used to distribute the natural gas to markets. As explained above with reference to FIG. 1, in order to elevate the pressure of the natural gas to above that of the pipeline 34 so that it can be injected into the pipeline 34, a compressor with prime mover 26 is used to compress the natural gas.

Compressing natural gas 16 raises a temperature of the natural gas 16, as well understood in the art. A proportion of the hot, compressed natural gas is diverted through a diverter line 38 to an annulus between the casing 10 and the production tubing 15. The compressor and the prime mover 26 therefore provide a power source for continuously injecting heated natural gas into the well. The amount of heated natural gas diverted to the annulus is controlled by a controller 40, a choke for example, so that a predetermined volume of hot, compressed natural gas 45 is injected into the annulus. Due to a pressure differential, the hot compressed natural gas 48 is forced through the passages 21 in the packer 19 and the check valves 23. The hot compressed natural gas commingles with the natural gas 16 produced from the production zone 12 and rises with the uncompressed natural gas 16 through the production tubing 15 to separator 20, which removes liquids from the natural gas to the fluid tank 24, as explained above. The natural gas is then conducted via the compressor intake conduit 30 to the compressor/prime mover 26. After compression, a proportion of the hot natural gas is diverted back into the well and the heat of compression is used to continuously heat the well.

As is understood by those skilled in the art, it may also be advantageous to add certain additives to the hot compressed natural gas in order to further facilitate production from the well. If so, additives stored in an additive tank 42 are pumped by a pump 44 into the diverter line 38 where they mix with the hot compressed natural gas and are carried down through the annulus and into the production zone 16 by the hot compressed natural gas 48. The additives may include any one or more of: fresh water for dissolving salt deposits; a corrosion inhibitor for protecting downhole metal components of the well system; a scale inhibitor to inhibit the deposit of scale on downhole equipment; a paraffin inhibitor to control paraffin deposition on downhole equipment; an asphaltene inhibitor to control asphaltene deposition; a salt deposit inhibitor to control salt deposit on downhole equipment; a surfactant to reduce surface tension and improve natural gas production; and, a freeze point depressant to further inhibit gas hydrate formation.

FIG. 3 is a schematic diagram of another embodiment of the invention for producing natural gas 16 from a production zone 12. In accordance with this embodiment, heat recovery is improved using at least one of a heat exchanger 60 and a vortex tube 70, as will be explained below in more detail. This embodiment is particularly useful in cold environments such as production facilities located in higher latitudes and/or deep sea wells. As will be further noted, the injection of the hot compressed natural gas in this embodiment is through the production tubing 15 whereas natural gas is produced from the well via the annulus between the casing 10 and the production tubing 15. It should be understood by those skilled in the art that the arrangement shown in FIG. 2 can also be used for delivery of the hot compressed natural gas in accordance with this embodiment of the invention, and vice versa.

The embodiment shown in FIG. 3 is identical to that shown in FIG. 2 with the exception that the heat exchanger 60 collects waste heat from the exhaust 62 and/or the engine block of the prime mover 26 via cooling conduits 64 which circulate engine coolant in a manner well known in the art. In accordance with the invention, the hot compressed natural gas output through conduit 30 by the compressor 26 driven by the prime mover is diverted by diverter line 38 through the heat exchanger 60 where it is further heated. The choke or controller 40 governs the amount of hot compressed natural gas that is returned to the well. Efficiency may be further improved by use of the vortex tube 70, well known in the art. Diverter line 38 provides hot compressed natural gas input to the vortex tube 70. The vortex tube 70 separates the hot natural gas into a hot natural gas component which is injected into the well through an injector line 72 into the production tubing 15. The diverter line 38 and the injector line 72 may be insulated using an externally applied insulation 76 of any type well known in the art.

The cold natural gas component output by the vortex tube 70 is returned via a cold natural gas return line 74 to the natural gas distribution system (pipeline 34). Alternatively, the cold natural gas component may be returned (as shown in dashed lines) to the compressed natural gas conduit 30 and re-introduced into the natural gas stream being delivered to the pipeline 34. If so, the cold natural gas component cools the hot compressed natural gas compressed by the compressor 26. A baffle 31, or the like, prevents the cold natural gas component from entering the diverter line 38. In this embodiment, the cooler 32 may not be required since the cold natural gas from the vortex tube 70 reduces the temperature of the hot compressed natural gas in the conduit 30. A check valve 78 controls the flow of natural gas through the cold natural gas return line 74. Optionally, a separator 20′ separates fluids from the cold natural gas returning through the cold natural gas return line 74. A fluid drain line 22′ conducts the separated fluids to the fluid tank 24. In this embodiment, the packer or centralizer 21 permits free movement of natural gas up the annulus between the production tubing 15 and the casing 10.

FIG. 4 is a schematic diagram of yet a further embodiment of the invention in which production from oil wells is facilitated by continuously injecting heat generated by surface equipment used to produce crude oil from the well. In accordance with this embodiment of the invention, a surface pump such as a jack pumping system 102, well known in the art, is driven by prime mover 104 to produce crude oil 100 from a production zone 12 through a production tubing 15 in a manner well known in the art. A packer 21 isolates the annulus between the casing 10 and the production tubing 15 from the production zone. Pump jack system 102 reciprocates a downhole pump 105 in a manner well known in the art to produce oil up through the production tubing 15. The pump jack 102 is driven by the prime mover 104, which is frequently an electric motor, although internal combustion engines are sometimes used, especially if the well also produces natural gas.

Heat exchanger and recirculator 107 collects heat generated by the prime mover 104 and transfers the heat to a heat transfer medium. In this embodiment, a closed loop circuit is used to continuously circulate hot compressed gas to heat the well system. As is well known in the art, oil wells commonly produce some natural gas along with the oil. This natural gas is commonly referred to as “casing head gas”, and it is frequently produced in enough abundance to power the prime mover 104 as well as to provide gas that can be re-injected into the well to heat the well. If the well does not produce natural gas, it can be supplied in an appropriate quantity from another source, or a gas such as carbon dioxide, nitrogen or air can be supplied for use as the heat transfer medium.

The heat exchanger and recirculator 107 circulates the hot compressed gas through an injection line 108 which is optionally connected to the input of a vortex tube 110. The heat exchanger and recirculator 107 therefore provides a power source for continuously injecting heated gas into the well. The vortex tube 110 separates the hot compressed gas into a hot gas component output which is circulated through a hot gas conduit 114 to an injection system 116 connected to a hollow sucker rod 120 using a flexible or reciprocating conduit 118 connected to a top of the hollow sucker rod 106. The heated compressed gas 120 is forced down a center of the hallow sucker rod and through a check valve at a top of the down hole pump 105. The hot compressed gas rises through the crude oil in the production tubing string 15 as gaseous bubbles 124 of hot gas which heat the oil to help keep paraffins, bitumens and asphaltenes in suspension until they are produced from the well in order to prevent obstruction of the production tubing 15. After the hot gas has risen through the oil crude oil it returns via a return line 130 to the heat exchanger and recirculator 107. In this embodiment, the return line 130 is buried underground. Any or all of the lines 108, 114 and 130 may be wrapped in insulation 76 as explained above with reference to FIG. 3. If the vortex tube 110 is used, a cold gas stream separated out by the vortex tube 110 is returned via return line 112 to the heat exchanger and recirculator 107. An optional fuel supply line 113 may supply natural gas fuel to a fuel intake of the prime mover 104, which uses a portion of the casing head gas produced from the well.

The invention therefore facilitates production from both natural gas and oil wells by continuously heating the well system. Waste heat is thereby used for a useful purpose and dependence on chemical additives and their associated maintenance is reduced. The systems in accordance with the invention are low maintenance and self regulating and can significantly improve production from wells where hydrate plugs, paraffin deposits, or condensates inhibit or stop production.

The embodiment(s) of the invention described above are intended to be exemplary only. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.

Claims

1. A method of enhancing production of hydrocarbons from a hydrocarbon well comprising continuously injecting into the hydrocarbon well heat generated by surface equipment used to produce the hydrocarbons from the well or heat generated by surface equipment used to compress the hydrocarbons for injection into a pipeline.

2. The method as claimed in claim 1 wherein the hydrocarbon well is a natural gas well and the method further comprises:

compressing the natural gas produced from the well at the wellhead using a compressor; and

continuously diverting a proportion of the compressed natural gas back into the well to heat the well.

3. The method as claimed in claim 1 wherein diverting a proportion of the compressed natural gas back into the well comprises diverting the compressed natural gas into a production tubing of the well.

4. The method as claimed in claim 1 wherein diverting a proportion of the compressed natural gas back into the well comprises diverting the compressed natural gas into an annulus between production tubing and a casing of the well.

5. The method as claimed in claim 2 further comprising using a vortex tube to separate the compressed natural gas into a hot natural gas component and a cold natural gas component and continuously diverting only the hot natural gas component back into the well.

6. The method as claimed in claim 5 further comprising delivering the cold natural gas component to at least one of a natural gas distribution system and a fuel intake of a prime mover used to produce hydrocarbons from the well or to compress natural gas produced by the well.

7. The method as claimed in claim 6 wherein delivering the cold natural gas component to the natural gas distribution system comprises injecting the cold natural gas component directly into the gas distribution system.

8. The method as claimed in claim 1 wherein the hydrocarbon well is an oil well, and the method further comprises:

continuously collecting heat generated by a prime mover used to pump crude oil from the oil well and transferring the heat to a heat transfer medium; and

continuously recirculating the heat transfer medium through the well to inject the heat into the well.

9. The method as claimed in claim 8 wherein the heat transfer medium comprises a compressed gas.

10. The method as claimed in claim 9 wherein the pump comprises a jack pump and the method further comprises:

continuously circulating the compressed gas down a hollow sucker rod string connected to the jack pump;

continuously drawing the compressed gas returned to a wellhead of the well; and

continuously passing the returned compressed gas through a heat exchanger for transferring to the compressed gas the heat generated by the prime mover.

11. A method of enhancing production from a natural gas well, comprising:

flowing natural gas from the well to a compressor and compressing the natural gas;

diverting a proportion of the compressed natural gas back into the well; and

delivering a remainder of the compressed natural gas to a natural gas distribution system.

12. The method as claimed in claim 11 wherein compressing the natural gas comprises compressing the natural gas using a compressor driven by an internal combustion engine, and at least a proportion of heat output by the internal combustion engine is used to further heat the compressed natural gas before it is diverted back into the well.

13. The method as claimed in claim 12 further comprising recovering exhaust heat from the internal combustion engine using a heat exchanger and further heating the compressed natural gas using the recovered exhaust heat.

14. The method as claimed in claim 12 further comprising recovering heat from an engine block of the internal combustion engine using a heat exchanger and further heating the compressed natural gas using the recovered engine block heat.

15. The method as claimed in claim 11 further comprising using at least one vortex tube to separate a hot natural gas component of the compressed natural gas from a cold natural gas component of the compressed natural gas, and injecting the hot natural gas component back into the well.

16. The method as claimed in claim 15 further comprising delivering the cold natural gas component to the natural gas distribution system.

17. The method as claimed in claim 11 further comprising mixing additives with the compressed natural gas as the compressed natural gas is diverted back into the well.

18. The method as claimed in claim 17 wherein the additives comprise at least one of: fresh water, a corrosion inhibitor; a scale inhibitor; a paraffin inhibitor; an asphaltene inhibitor; a salt inhibitor; a surfactant; and, a freeze point depressant.

19. The method as claimed in claim 11 wherein diverting the compressed natural gas comprises diverting the compressed natural gas down a production tubing string suspended inside a casing of the well and producing natural gas from an annulus between the production tubing string and the casing of the well.

20. The method as claimed in claim 11 wherein diverting the compressed natural gas comprises diverting the compressed natural gas down a casing of the well and producing the natural gas from a production tubing string suspended inside the casing.

21. A system for enhancing hydrocarbon production from a hydrocarbon well, comprising:

a power source for continuously injecting into the well a compressed gas heated by heat generated by surface equipment used to produce the hydrocarbon from the well or to compress the hydrocarbons produced by the well.

22. The system as claimed in claim 21 wherein the hydrocarbon well is a natural gas well, and the power source comprises a compressor for compressing natural gas produced from the well, the system further comprising:

a diverter line for diverting back into the well a proportion of a hot compressed natural gas stream compressed by the compressor; and

a control valve for controlling the proportion of the hot compressed natural gas stream diverted back into the well.

23. The system as claimed in claim 22 wherein the control valve comprises a choke.

24. The system as claimed in claim 22 further comprising an additive system for mixing additives with the hot compressed natural gas diverted back into the well.

25. The system as claimed in claim 22 wherein the additive system comprises an additive reservoir and an additive pump for pumping an additive from the additive reservoir into the diverter line.

26. The system as claimed in claim 21 further comprising a heat exchanger for extracting heat generated by a prime mover used to drive the compressor.

27. The system as claimed in claim 26 wherein the prime mover is an internal combustion engine and the heat exchanger recuperates heat from exhaust gases of the internal combustion engine.

28. The system as claimed in claim 26 wherein the prime mover is an internal combustion engine and the heat exchanger recuperates heat from an engine block of the internal combustion engine.

29. The system as claimed in claim 21 further comprising:

a vortex tube connected to the diverter line, the vortex tube separating the compressed gas into a hot gas component and a cold gas component; and

a hot gas injector line for injecting the hot gas component into the well.

30. The system as claimed in claim 29 further comprising a cold gas injector line for delivering the cold gas component to a natural gas distribution system.