Note: Descriptions are shown in the official language in which they were submitted.
WO 2022/212875
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PROCESSES FOR INCREASING HYDROCARBON PRODUCTION
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Continuation-in-Part
Application no.
17/220,470 filed on April 1, 2021. This application also related to
continuation-in-part of
pending U.S. Application Number 17/034,849 filed September 28, 2020 which
application is
a continuation of 16/780,089 filed February 3, 2020 which issued as U.S.
Patent No.
10,822,933 which application was a continuation of 16/282,831 filed February
22, 2019 which
issued as U.S. Patent No. 10,584,566 which application claimed priority from
provisional
application number 62/634,423 filed February 23, 2018. All of the
aforementioned
applications are incorporated herein by reference.
FIELD OF THE DISCLOSURE
[0002] 'the present disclosure relates to systems and methods for increasing
hydrocarbon
production by, for example, inducing gas lift.
BACKGROUND AND SUMMARY
[0003] Hydrocarbon production from, for example, an oil and gas well, may
often consume
a large amount of energy and be limited in efficiency due to equipment
limitations and/or other
constraints. The present application is directed to processes and systems to
improve the amount
of energy, e.g., reduce the power required, and/or increase the production of
a given well.
[0004] In one embodiment the application is directed a process for increasing
hydrocarbon
production using an electrical submersible pump. The process comprises
configuring an
electrical submersible pump comprising a gas separator to induce a gas lift
effect in a well.
The well comprises a central tubing within a casing such that an annulus is
formed between the
central tubing and the casing. Hydrocarbons may be produced from the well with
the electrical
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submersible pump such that reservoir fluid is produced up the central tubing
and a mixture
comprising reservoir gas and reservoir fluid is produced up the annulus.
100051 In another embodiment the application is directed to a system for
increasing
hydrocarbon production using an electrical submersible pump. The system
comprises a well
with at least a central tubing within a casing. The central tubing comprises a
fluid exit opening
near a surface of the well and a fluid entrance opening downhole. An
electrical submersible
pump may be suspended from the fluid entrance opening of the central tubing.
The electrical
submersible pump comprises a pump operably connected to the fluid entrance
opening of the
central tubing, a gas separator operably connected to the pump, and a motor
operably connected
to the gas separator. The system is configured to produce reservoir fluid up
the central tubing
and to produce a mixture comprising reservoir fluid and reservoir gas up an
annulus between
the central tubing and the casing. The system is also configured to induce a
gas lift effect in
the absence of injecting gas into the well from the surface.
[0006] These and other objects, features and advantages of the exemplary
embodiments of
the present disclosure will become apparent upon reading the following
detailed description of
the exemplary embodiments of the present disclosure, when taken in conjunction
with the
appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] Various embodiments of the present disclosure, together with further
objects and
advantages, may best be understood by reference to the following description
taken in
conjunction with the accompanying drawings.
[0008] FIG. lA depicts an ESP installation using an annulus between the
central tubing and
casing as a second fluid production flow path.
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[0009] FIG. 1B depicts an ESP installation using a second tubing string as an
additional fluid
production flow path.
100101 FIG. 1C depicts an ESP installation using three tubing strings as
additional fluid
production flow paths.
[0011] FIG. 2 depicts a nodal analysis comparing conventional production
methods vs. the
methods described herein.
100121 FIG. 3 depicts a second nodal analysis comparing conventional
production methods
vs. the methods described herein
100131 FIG. 4 depicts a third nodal analysis comparing conventional production
methods vs.
the methods described herein.
[0014] FIG. 5 depicts a fourth nodal analysis comparing conventional
production methods
vs. the methods described herein.
[0015] FIG. 6 shows critical velocities as related to wellhead pressure and
flow rate.
DETAILED DESCRIPTION
[0016] The following description of embodiments provides a non-limiting
representative
examples referencing numerals to particularly describe features and teachings
of different
aspects of the invention. The embodiments described should be recognized as
capable of
implementation separately, or in combination, with other embodiments from the
description of
the embodiments. A person of ordinary skill in the art reviewing the
description of
embodiments should be able to learn and understand the different described
aspects of the
invention. The description of embodiments should facilitate understanding of
the invention to
such an extent that other implementations, not specifically covered but within
the knowledge
of a person of skill in the art having read the description of embodiments,
would be understood
to be consistent with an application of the invention.
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[0017] The systems and methods disclosed herein generally relate to systems
and methods
for increasing hydrocarbon production from a well by, for example, inducing
gas lift and then
producing hydrocarbons from the well with an electrical submersible. That is,
a process for
increasing hydrocarbon production may be employed that uses an electrical
submersible pump.
The specific electrical submersible pump is not particularly critical and may
be any
conventional electrical submersible pump known in the art. Particularly
suitable electrical
submersible pumps are those employing a gas separator such as those described
in, for
example, U.S. Patent No. 10,822,933 which is incorporated by reference. The
electrical
submersible pumps used herein may comprise a pump module, a motor such as a
permanent
magnet motor, and a gas separator between the pump module and motor.
[0018] As is known in the art, typical wells comprise a central tubing within
a casing.
Advantageously, the processes and systems used herein may induce gas lift in
the absence of
injecting gas into the well from the surface simply by configuring the
electrical submersible
pump within the well as described herein. Of course, injecting gas into the
well from the
surface may further induce gas lift.
[0019] Configuring the electrical submersible pump within the well may be
accomplished in
any convenient manner so long as the desired gas lift effect is achieved. In
some cases the
configuring step may comprise suspending the electrical submersible pump from
the central
tubing such that reservoir fluid is produced up the central tubing and a
mixture comprising
reservoir gas and reservoir fluid is produced up the annulus. As used herein
reservoir gas may
comprise a hydrocarbon, carbon dioxide, other gases, and mixtures thereof. The
present
methods and systems are typically employed to induce gas lift without
injecting gas into the
well from the surface. However, if gas has been previously injected, then it
may also form a
portion of reservoir gas.
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[0020] The configuring step may comprise suspending the electrical submersible
pump from
the central tubing such that velocity of a gas separated by the gas separator
is preferably above
a critical velocity for the well. Critical velocity may vary depending upon
such factors as cross-
sectional flow area, wellhead pressure, and the like as shown in Figure 6.
Thus, to achieve a
condition where the velocity of gas separated by the gas separator is above a
critical velocity
the critical velocity may somehow be reduced and/or a velocity of the gas
separated by the gas
separator may be increased. Generally, it has been discovered that this may
accomplished by
configuring the respective geometries (such as shown in Figures 1A-1C) within
the pump to
overcome and/or ensure the gas velocity is at equal to or above the critical
velocity of reservoir
fluid. In this manner the velocity of gas up the annulus (with or without
added tubing strings)
is sufficient to lift reservoir fluid up the annulus with the gas (which
annulus may have one or
more additional tubing strings within it). It has been discovered that
critical velocity is related
to, for example, a cross-sectional area of clearance between a central tubing
(and the sum of
any additional tubing strings), if employed, as well as perhaps wellhead
pressure and to a lesser
extent perhaps density of any reservoir fluid.
[0021] In some embodiments the gas lift effect herein is advantageously
induced in the
absence of injecting gas into the well from the surface. That is, a clearance
between the central
tubing (including any additional tubing strings) and the casing is sufficient
to achieve and/or
induce a desired gas lift effect. This may be accomplished in many different
manners
depending upon the specific electrical submersible pump, casing, tubing, and
other parameters.
In some embodiments it has been found that the pump, casing, central tubing
and, if present,
any additional tubing strings, should be configured such that the casing
clearance wherein the
pump is suspended is less than about 30%, or less than about 25%, or less than
about 20%, or
less than about 18%, or less than about 15%, or less than about 10%, or less
than about 8% of
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the casing diameter. In the cases wherein one or more additional tubing
strings are employed
into the annulus that extend at least from a surface into the well and
terminate uphole from the
electrical submersible pump, then the sum of diameters of the central tubing
and the one or
more additional tubing strings is usually less than about 30% less, or than
about 25%, or less
than about 20%, or less than about 18%, or less than about 15%, or less than
about 10%, or less
than about 8% of the casing diameter uphole from the electrical submersible
pump. In this
manner, at least a portion of the mixture comprising reservoir gas and
reservoir fluid produced
up the annulus may pass through, if present, the one or more, e.g., two,
three, or four or more
additional tubing strings. It is not particularly critical where any
additional tubing strings that
extend into the annulus terminate so long as they terminate uphole of the
electrical submersible
pump as shown in Figure 1B and 1C. In some embodiments, it may be desirable to
have the
additional tubing terminate uphole and close to the electrical submersible
pump, e.g., within
500 feet, or within 400 feet, or within 300 feet, or within 200 feet, or
within 100 feet, or within
50 feet, or even closer depending upon the well configuration and parameters.
[0022] While not wishing to be bound to any particular theory it is believed
that the -tighter"
configuration, for example, less than about 30% clearance described above,
facilitates gas lift
up the annulus which may include one or more 2nd flow paths which flow paths
may be the
annulus between the central tubing and casing and, of course, may also include
any one or more
tubing strings within the annulus. That is, in some cases the annulus between
the central tubing
and the casing may include a second, and/or third and/or fourth or more tubing
strings.
[0023] Advantageously, a desired tighter clearance may be accomplished in a
number of
ways. For example, as shown in Figure 1A, the desired casing clearance may be
configured
by selecting the pump diameter at an appropriate location, e.g., at or above
the ESP gas
separator in this instance, such that flow path 2 in Figure 1A (the annulus
between the tubing
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and casing) adjacent the pump is within the desired casing clearances
described above.
Alternatively or additionally, desired casing clearances may be accomplished
by employing
additional tubing strings, e.g., one, or two, or three or more additional
tubing strings. Figure
1B shows the casing clearance configured for the desired tighter fit in the
region of a second
tubing which creates at least one flow path 2 for enhancing gas lift.
[0024] Figure 1C shows a casing clearance configured for the desired tighter
fit in the region
of a second, third, and/or fourth or moe tubing which creates additional flow
paths 2 or more
for enhancing gas lift. In the case of adding a second, third, and/or a fourth
or more tubing
string each tubing string may be of the same diameter in cross-section and
length and/or of
different diameters and lengths so long as the desired gas lift effect is
achieved due to the casing
clearance and/or annulus describe above. In some specific embodiments the
second, third,
and/or a fourth tubing string are uphole from the pump and up to all of the
tubing strings may
be smaller in cross-section than the central tubing from which the pump is
suspended. In most
circumstances hydrocarbon fluids are produced up the tubing on which the pump
is suspended
while reservoir fluid, reservoir gas, and mixtures thereof are produced up the
annulus between
the tubing and the casing which annulus may include the one or more added
tubing strings such
as those shown in Figures 1B and 1C.
[0025] Advantageously, using the configurations described herein hydrocarbons
produced
from the well may be at least about 3%, or at least 5%, or at least 10%, or at
least 20%, or more
than a comparable process without the configuring step as shown in the data
below. Similarly,
horsepower or energy consumed for the production process may be diminished by
at least 5%,
or at least 10%, or at least 20% or more than a comparable process without the
configuring step
or other methods and systems described herein. In some embodiments,
hydrocarbons produced
from a well configured as described herein may be about the same or more than
a comparable
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process without the configuring step wherein the comparable process uses more
horsepower
over the time of a given ESP run.
100261 The table below shows representative casing and tubing sizes that may
be employed
in combination to induce gas lift. The casing clearance as a percent of the
casing diameter is
shown in the "clearance" column.
[0027]
Casing Tubing Clearance
Size ID (in) Size OD (in) (in) (% of
Dc)
7.000" 26.00 ppf 6.276 3.500" 9.30 ppf 3.500
1.3880 22.1%
7.000" 26.00 ppf 6.276 2.875" 6.50 ppf 2.875
1.7005 27.1%
5.500" 17.00 ppf 4.892 2.875" 6.50 ppf 2.875
1.0085 20.6%
5.500" 17.00 ppf 4.892 2.375" 4.70 ppf 2.375
1.2585 25.7%
5.000" 15.00 ppf 4.408 2.375" 4.70 ppf 2.375
1.0165 23.1%
[0028] Example 1: The methods described above are employed on a well with the
parameters shown in the table below.
[0029] Well Parameters
Perf Datum: 11,300' TVD
Kick Off Point: 10,850' TVD
Casing: 7.000" 20 ppff
ESP Tubing: 2.875" 6.5 ppf
Dual Lift Tubing: 2.375" 4.7 ppf
Est. Reservoir Pressure: 5400 PSI
528 stages of 3000 Barrels Per Day pump
ESP Description: stage
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[0030] Well Productivity Test
VVH Pressure: 800 PSI
Oil Rate: 875 BPD
Water Rate: 1105 BPD
Gas Rate: 1000 MCF
Test BH Flowing Pressure: 3900 PSI
[0031] Potential horsepower savings using the methods described herein on the
well
described above is shown below.
Dual Lift Example - HP Savings Projection
Est. Gas Fluid
Total Power Power
HP
Reservoi Total Gas Takeaway - Takeaway
Fluid PIP Requirements -
Requirements - Reductio
r Prod Dual Lift - Dual Lift
Prod ESP Only Dual
Lift n
Pressure String String
(PSI) (BPD) (MCFD) (PSI) (MCFD) (%)
(Freq) (HP) (Freq) (HP) %
5400 3000 1650 2650 165 0 57 225 57
225 0
4600 3000 1800 1800 774 20 63 311 56
221 29
4000 2500 1750 1350 1050 12 62 300 58
244 19
3000 2000 1400 1000 840 5 60 269 59
254 6
2200 1500 1050 680 840 4 59 249 59
249 0
1700 1000 700 640 560 3 56 211 56
206 2
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[0032] Potential production increase using the methods described herein on the
well
described above is shown below.
Dual Lift Example ¨ Production Uplift
Total Total Gas
Est. Fluid Fluid Total Takeaway
ESP Power Production
Reservoir Prod - Prod - Gas PIP - Dual
Requirements
Uplift
Pressure ESP Dual Prod Lift
Only Lift String
(PSI) (BPD) (BPD) (MCFD) (PSI) (MCFD) (Freq) (HP)
5400 3000 3000 1650 2650 165 57 225 0
5200 3000 3600 2160 1800 929 63 311 20
4100 2500 2800 1960 1350 1176 62 300 12
3100 2000 2100 1470 1000 882 60 269 5
2400 1500 1560 1092 680 874 59 249 4
1700 1000 1030 721 640 577 56 211 3
[0033] Figures 2 and 3 show a nodal analysis comparing conventional production
methods
vs. the methods described herein. As shown in Figure 2 employing the methods
and systems
described herein may result in reduced energy requirements while Figure 3
shows employing
the methods and systems described herein may additionally or alternative
result in increased
production.
100341 Example 2: The methods described above are employed on a well with the
parameters shown in the table below.
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[0035] Well Parameters
Perf Datum: 9,950' TVD
Kick Off Point: 9,250' TVD
Casing: 5.500" 23 ppff
ESP Tubing: 2.875" 6.5 ppf
Dual Lift Takeaway: 5.5"x 2.875" Annulus
Est. Reservoir Pressure: 4000 PSI
ESP Description: 268 stages of 4000 Barrels Per
Day
[0036] Well Productivity Test
WH Pressure: 400 PSI
Oil Rate: 600 BPD
Water Rate: 3400 BPD
Gas Rate: 1500 MCF
Test BH Flowing Pressure: 2800 PSI
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[0037] Potential horsepower savings using the methods described herein on the
well
described above is shown below.
[00381
Gas Takeaway Fluid Takeaway Power Requirements
Power Requirements
PIP
HP Reduction
- Dual Lift String - Dual Lift String - ESP Only - Dual
Lift
(PSI) (MCFD) (%) (Freq) (HP) (Freq)
(HP) %
2170 1350 53 60 258 40 68
1700 1440 44 63 296 50 125
.:]::::::::.ri...:::::::::=:..
1540 1440 41 60 249 53 143
1400 1440 .. 39 60 246 54 143
1100 1260 23 62 249 61 201
.UQPROP
850 1080 13 65 249 65 241
Ai,W
[0039] Potential production increase using the methods described herein on the
well
described above is shown below.
Est. Reservoir Total Fluid Prod Total Fluid Prod Gas Takeaway
Production
Total Gas Prod PIP ESP Power
Requirements
Pressure - ESP Only - Dual Lift -
Dual Lift String Uplift
(PSI) (BPD) (BPD) (MCFD) (PSI) (MCFD) (Freq)
(HP) %
4000 4000 5200 2300 1700 2070 63 296
EggitEiM
.......................
.......................
-.......-........... ================ ¨
3800 3800 4500 2250 1540 2025 61 250
3400 3400 3900 2200 1400 1980 60 250
iiNnnei!
ii.Diii:=ii
2600 2600 2950 1700 1100 1530 61 250
2000 2050 2250 1700 850 1530 63 250
taliMiin.
[0040] Figures 4 and 5 show a nodal analysis comparing conventional production
methods
vs. the methods described herein. As shown in Figure 4 employing the methods
and systems
described herein may result in reduced energy requirements while Figure 5
shows employing
the methods and systems described herein may additionally or alternative
result in increased
production.
[0041] In the preceding specification, various embodiments have been described
with
references to the accompanying drawings. It will, however, be evident that
various
modifications and changes may be made thereto, and additional embodiments may
be
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implemented, without departing from the broader scope of the invention as set
forth in the
claims that follow. The specification and drawings are accordingly to be
regarded as an
illustrative rather than restrictive sense.
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