Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND SYSTEM FOR ENHANCING HYDROCARBON
PRODUCTION FROM A HYDROCARBON WELL
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
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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
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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. l, 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
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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
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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.
SUN~ARY 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.
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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
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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
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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
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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.
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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 conduits64
which circulate engine coolant in a manner well knownin
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 is
it
further heated. The choke or controller 40 governs the
amount of hot compressed natural gas that is returnedto
the well. Efficiency may be further improved by use the
of
vortex tube 70, well known in the art. Diverter line 38
provides hot compressed natural gas input to the vor tex
tube 70. The vortex tube 70 separates the hot naturalgas
into a hot natural gas component which is injected the
into
well through an injector line 72 into the production
tubing
15. The diverter line 38 and the injector line 72 be
may
insulated using an externally applied insulation 76 any
of
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
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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 centralizes 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
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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
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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 embodiments) 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.
