Note: Descriptions are shown in the official language in which they were submitted.
F I ELD OF TEIE I NVENT I ON
The method of the invention relates to a gas lift
method for lifting well fluid from a well.
BACKGROUND OF 'l'~lh INVENTION
Oil from oil bearing earth formations is produced by
the inherent formation pressure. In many cases, however,
the oil bearing formation lacks sufficient inherent
pressure to force the oil from the formation, upwardly
through a string of production tubing and to the surface
lo where it will be transported rom a wellhead structure by
flow lines. When the pressure of the production zone has
been reduced by continued withdrawal, a time arrives when
the well will not flow from its reservoir energy. When
this occurs, one method of continuing production is to
provide mechanical pumping operations. Another popular
method for achieving production from wells that no longer
are capable of natural flow is by the gas lift method
whereby gas is injected into the annulus between the
production tubing and the casing under controlled
conditions.
;; ;l 3
.
.
--
-
.
7~
The concept of using gas as a means of artificial
lift of well fluids evolved in the late 1700's. The
early methods were designed primarily for continuous flow
operations. Continuous 1OW gas lift has been defined as
5 a means of artificial lift where gas is continuously
injected from the surface down the annulus defined
between the tubing and the casing of a well, through a
gas lift valve between the annulus and the tubing and up
the tubing string. The gas mixes with and aerates the
fluids in the tubing string thereby providing a lifting
force for lifting the fluids to the surface. Gas was
traditionally injected either around the bottom or
through a piece of e~uipment common:Ly called a foot
pleCe.
A technolo~y developed which provided ~or selec-tive
injection of gas into the tubing string through gas lift
valves which are well known in the ar . Intermittent gas
lift is a means of artificial lift where a slug or column
of liquid is allowed to accumulate in the tubing string,
whereupon gases are injected through a gas lift valve
underneath the liquid slug to propel it to the surface in
the fonm of a slug. U.S. Patent 4,392,53~ reveals such a
system. A wide variety of gas lift valves have been
designed specifically for intermittent lift.
Spacing and other characteristio~s of the gas lift
valves must be established in acco:rdance with the
criteria of the particular well involved in order to
achieve production at the maximum rate that is producible
from the formation involved. For the reason that no two
wells are exactly alike and may involve differences in
such parameters as the heigh-t of the static liquid column
within the well, the static gradient o the liquid fluid,
i.e., liquid between the valves, and geothermal
temperature, it is virtually required that each gas lift
system for independent wells be separately calculated to
achieve optimum production.
. : -
,
. .
127~ 3
With both continuous and intermittent gas lift it isrequired that substantial volumes of gas at substantial
pressures be produced at the surface of the well to
achieve desired results. In addition, numerous valves
S are required in ~known systems to provide suitable
pressures at the points where the gas is in-troduced into
the tubing string. Because substantial pressures must be
produced at the surface to force the substantial volumes
of gas down the well for gas lift, the equipment in the
form of compressors, tanks, concluits, valves and the like
which is required to handle the gas is substantial and
expensive.
The high pressure components of the equipment
require careful maintenance to avoid expensive or
dangerous failures and consume substantial quantities of
energy.
Gas lift systems are usually applied to wells that
produce from water driven reservoirs, or in reservoirs,
which, although incapable of natural flow will have
sufficient pressure throughout their life to provide the
submergence required for efficien-t lift.
The overall efficiency of a gas lift system
producing from a well with a strong water drive ~an be
guite high. In present day systems, however, desi~ners,
~5 faced with the necessity of unloading to the deeper
depths, say to 4,000 or 5,000 feet, have resorted to use
of minimum gradient curves which provide for inefficient
operation. Observed efficiencies in some of these wells
have ranged from seven to eleven percent.
30 SUMMARY OF THE INVENTION
The method of the present invention relates to a gas
lift operation wherein pressurized injection gas is mixed
with pressurized injection liquid to form a non-foam
gas-liquid mixture which is mixed at the surface just
prior to introduction into the well. The mixing pressure
and the pressure of injection at the wellhead are
: ' ' . : -
,
- ' . ~ :
.. . ., ~ - . ..
. . , , ;' ' ,
~77:;~Z3
therefore substantially equal. The pressurized injection
gas and liquid mixture is introduced into the production
conduit below an initial column of well fluid present in
the conduit. As the mixture of injection gas and liquid
travels towards the bottom of the well bore the gas is
compressed and is subsequently allowed to expand when the
mixture enters the production conduit. The expansion of
the pressurized injection gas as it travels upwardly
towards the surface in the production conduit lifts the
production fluid in the conduit and thereby "unloads" the
production conduit. As a result of the expanding rising
gas in the production conduit and the lifting of the
initial charge of well fluid in the ~roduction conduit,
the pressure at the lower end of the production conduit
adjacent the producing formation drops, thereby inducing
additional well fluid to enter the production conduit
from the formation. Further injection of pressurized
injection gas and liquid lifts any additional fluid
emerging from the formation and entering the production
conduit. Because the gas~ uid mixture is not a foam,
it can be readily separated at the surface and re-used
for continuous recycling of the gas-liquid mixture.
The production conduit may be a l-ubing string or the
~nnulus around the tubing string. The pressurized
mixture may ~e introduced down the annulus, down the
tubing string, or through a separate inlet pipe.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 represents the gas lift method of the present
invention disclosing three alternate well bore
configurations for carrying out the gas lift method;
Fig. 2 is a schematic view of the embodiment Z shown
at the right hand portion of Fig. 1 showing static well
bore conditions before initiation of the gas lit method;
Fig. 3 illustrates schematically the initial
injection of the pressurized gas and liquid mixture into
-
': . ~ . - -
- . ., -. . .
, , .
. ., ,, - -
.
1~7~
an injection conduit thereby displacing well fluid in a
production conduit;
Fig. 4 illustrates the use of injected liquid and
gas to unload the production conduit within a well bore;
Fig. 5 illustrates formation flow into a procluction
conduit as a result of the in~jected gas and lic~uid
mixture;
Fig. 6 is a sectional view of the gas lift method of
the embodiment X of Fig. 1 using annulus injection;
Fig. 7 is a graphical representation of pxessure
changes within the well during the gas lift operation in
the embodiment of the method shown in Fig. 6;
Fig. 8 is a sectional view of ~he embodiment Z of
Fig. 1, showing the use of an injection conduit;
Fig. 9 is a graphical representation of pressure
changes within the well using the method of Fig. 8 during
gas lift operation;
Fig. 10 is a graphical representation of flowing
pressure gradients for fixed conditions in 2-7/8 inch OD
tu~ing at various depths and pressures taken from McMurry
Hughes, Inc. "Flow Gradient Curves" book;
Fig. 11 is a graphical representation of flowing
pressure gradients using fixed conditions such as zero
percent water produced in 2-3/8 inch tubing at vaEious
~5 depths and pressures taken from McMurry Hughes, Inc.
"Flow Gradient Curves" book; and
Fig. 12 is a graphical representation of flowing
pressure gradients using fixed conditions such as
sixty-five percent water produced for 2-3/8 inch tubing
at various depths and pressures taken from McMurry
Hughes, Inc. "Flow Gradient Curves" book.
DESCRIPTION OF THE PREFERRED EMBODIMENT
In using the gas lift system of the present
invention, FicJ. 1 illustrates several types of gas lit
piping arrangements within a borehole B and the
associated surface ec~uipment. Borehole B is drilled i~to
.
. .
' ' : :
'
. ~ ' - ' ' ~'.
~2~72~
producing formation F in a manner well known in the art.
Typically a casing lOa extends from the ground surface to
or through producing forma-tion F. The casing lOa is
perforated at its lower end lOb within producing
formation F. A production conduit lOc is inserted in-~o
casing lOa in order to conduct well fluid lOd from
producing formation F to the su]face processing e~uipment
as will be discussed in more detail herei~below.
Typically, a packer lOe is inserted between casing lOa
and production conduit lOc at the lower end of production
conduit lOc. Similarly, seal lOf is disposed ~etween
casing lOa and production conduit lOc at the upper end of
production conduit lOc. Packer lOe and seal lOf enclose
an annulus lOg around production conduit lOc. For the
purposes of gas lift, a check valve lOh is disposed at
the lower end of production conduit lOc. Check valve lOh
permits well fluid lOd to flow into production conduit
lOc toward the upper end of production conduit lOc and
prevents flow of the injection gas and liquid mixture
into producing formation F as will be more fully
described hereinbelow. Although check valve lOh offers
advantages in using the gas lift method of the present
invention, its use is not required for implementation of
the gas lift method of the present invention.
As illustrated in Fig. 1, when using the gas lift
method of the pres~nt invention, well fluid lOd may be
brought to the surface S through production conduit lOc
(embodiment X) annulus lOg ~embodiment Y) or a separate
injection tube lOm may extend from surface S and connect
to production conduit lOc at its lower end (embodiment
Z). Each embodiment employed with the gas lift method of
the present invention has its own unique advantages as
will be more fully described hereinbelow.
As seen in the lower left portion of Fig. l,
production conduit lOc has an opening lOj into annulus
lOg adjacent packer lOe and between packers or seals lOe
and lOf. Casing lOa also has an opening lOk into annulus
.
.
.
~;~77~
lOg adjacent seal lOf near surface S. Injected gas and
liquid are admitted as a mixture through opening lOk so
that it may displace well fluid lOd initially found in
annulus lOg. Annulus lOg is in flow communication with
production conduit lOc adjacent packer lOe and as a
result allows injected liquid and gas to flow through
production conduit lOc -towards port ]Oj thereby lifting
well fluid toward surface S.
In the alternate system Y shown in the lower middle
portion of Fig. 1, injection gas and liquid represented
by arrow lOn are pumped into conduit lOc which is in flow
communication with annulus lOg through port lOs above
packer lOe. Accordingly, injection gas and liquid
displace well fluid lOd through annulus lOg to the
surface S through opening lOk. The well fluid enters the
annulus lOg through port lOp which communicates with the
formation F below the packer lOe.
Another alternate system Z shown in the right hand
side of Fig. 1 is similar to the gas lift system X in
that well fluids are produced out of production conduit
lOc. ~owever, rather than injecting gas and liquid into
annulus lOg, an injection conduit lOm is used which is in
flow communication with production conduit lOc at its
lower end. Accordingly, a packer is not required at the
lower end of production conduit lOc in system Z and only
the usual seal lOf adjacent surface S is required.
Production fluids are processed at the surface S by
a variety of equipment. When water is the injection
liguid, well fluid lOd is accumulated in separator 20.
Produced gas exits the upper end of separator 20 and
flows through conduit 22 in the direction of arrow 24
whereupon the produced gas can flow through a back
pressure regulator 26 to a gas gathering line represented
by arrow 28. Alternatively, the produced gas can flow to
compressor 30 and be recycled into the well for gas lift
operations. The compressed gas or injection gas exits
compressor 30 via conduit 32. Check valve 31 is
1~7~ 3
installed in conduit 32 to prevent injection water from
being driven back into compressor 30 in the event
compressor 30 is not operating while pump 44 is running.
The liquids in separator 20 flow through conduit 34
to flow treater 36. Oil and water are separated in flow
treater 36. The oil is delivered to stock via conduit 38
and the water is delivered tc disposal tank 40 via
conduit 42.
If oil is the injection lic~id, it is only necessary
to separate the gas from the oil in separator 20, and
therefore the treater 36 is not needed, and instead, the
oil flows to the tank 40 from the separator 20, with a
part of it going to stock or storage.
A high pressure pump 44 then pumps thé injection
liquid, whether it is water or oil from the tank 40 via
conduit 46 to a junction where it is mixed with injection
gas from conduit 32 at a predetermined pressure which is
the same or substantially the same as the pressure at
which the gas-liquid mixture is introduced into the well.
Oil or other liquids such as salt water available at the
well site can be used in the gas lift system of the
present invention but oil may be preferred to reduce -
slippage in the injection ~onduit. By "slippage" is
meant the flow of the li~uid past the gas on the downward
descent. Slippage is reduced when oil is the liquid used
bec~use substantial guantities of the gas will be
absorbed in solution on the pressure side going in, but
will be released on the travel up the production conduit.
Foaming agents such as surfactants are not used so
that the gas-liquid mixture does not create a foam. A
foam is undesirable for a number of reasons, primarily
because they are difficult to break, particularly stable
foams such as disclosed in Hutchison U.S. Patent No.
3,463,231. Therefore, it is difficult to separate and
re-use the gas and liguids in a foam even if it could be
used for lifting purposes, so that recycling is inhibited
or prevented :if a foam were used. Further foams must be
preformed whereas the gas-liquid mixture used in this
-
. ' ~ -
. ~ .
~Z7722~9
invention is mixed right at the well site as it is
injected.
As seen in Fig. 1, the combined injection liquid and
injection gas frQm conduits 32 and 46 may be injected
into one well bore or several well bores B for gas lift
operations therein. As shown in the system X a check
valve 47 may be installed after the junction of conduits
32 and 46 adjacent well bore B to prevent spills in the
event conduits 32 or 46 rupture. Well fluids lOd which
are produced from a well bore B are directed via conduit
50 into separator 20.
The gas lift method is schematically illustrated in
Figs. 2 through 5. Figs. 2-5 depict a complete gas lif-t
cycle for the gas lift method of the present invention.
Although the Figs. 2 through 5 correspond to system Z,
the operation illustrates the princip:Le of this invention
for the other embodiments X and Y as well.
Prior to initiation of the gas l:ift procedure, there
- is a static liquid level 60 within annulus lOg as well as
injection tubing lOm and production conduit lOc. The
merged streams from conduits 32 and 46 of Fig. 1 are
injected into injection tubing lOm as shown in Fig. 3.
The gas and water in injection conduit lOm are shown
schematically with the lighter segments 60b representing
the gas phase and the darker segments 60c representing
the water phase. As the injection gas and liquid travel
down the well bore B in injection conduit lOm the gas is
progressively compressed more and more by the liquid
thereabove as the height of the liquid column thereabove
increases, as shown by the diminishing size of the
lighter segments 60b toward the bottom of well bore B.
The compression of the gas in the injection liguid in
injection tubing lOm reaches a maximum at the point of
entry into production conduit lOc because at that point,
the maximum column of liquid is acting on the gas.
In embodiments Y and Z in order to minimize
separation between the injected gas and liquid as they
.
~27~3
travel toward the bottom of the well bore,
anti-separation devices such as plastic spheres (not
shown) can be injected at intervals with the liquid gas
mixture to provide longitudinally spaced separators to
thereby minimize potential separation of the liquid and
gas due to differences in the densities of the injected
liquid and gas. This techni~le can also be used in
embodiment X in Fig. 1 but may have a lesser beneficial
impact depending on the configuration of the annular
injection area.
The highly compressed gas phase expands as it
travels up the bore of production conduit lOc (Fig. 4)
because of the column of liqu:id thereabove gradually
decreasing as the mixture goes up the boreh~le. This gas
expansion provides the work of lift on the well fluid lOd
in production conduit lOc to lift the fluid to surface S
as shown in Fig. 4. The net effect of the expanding gas
as it rises in production conduit lOc is to lower the
pressure in the production conduit a1: the bottom of well
bore B. ~hen the pressure reduction during the first or
successive cycle of gas-water injection mixture becomes
sufficiently great, flow from the formation F into the
well bore B and subsequently into production conduit lOc
will ensue (see Fig. 5). The addit:ional well fiuid
represented by arrows lOr in Fig. 5 will also be lifted
through production conduit lOc by the expansive energy of
the injected gas.
It should be understood that Figs. 2-5 are schematic
only, because the gas may not separate completely from
the liquid as shown. The gas phase is compressed as the
mixture goes down the well and expands as the mixture
travels up the well, as explained.
A complete cycle as represented by Figs. 2 through 5
involves an injection of a gas-liquid mix~ure and the
subseguent purging of well fluid lOd from production
conduit lOc in well bore B, a process called unloading.
The rate of injection of the water phase can be decreased
.
' ', ' . "
' '
.
772~
when the flow has stabili2ed. This may be possible after
the first cycle of gas-water mixture. Reduction of the
water phase brings about an increase in injection
gas-water ratio, with a resultant increase in produced
fluid. As the production from the well increases the
bottom hole pressure will decrease and the work of lift
will also increase. The result will be a gradual
increase of the pu~p and compressor discharge pressures
to supply the increased lift energy needed. The capacity
of the surface eguipment may limit the amount that the
water rate can be cut back. In such event the water rate
should be reduced, commensurate with the rating of the
surface eguipment. The gas injection rate an then be
regulated to provide for peak lift efficiency at the rate
being produced. In some wells it may be possible to
reduce the water rate to zero and operate on gas alone.
The dual tubing string instal:lation of Figs. 2
through 5 will be particularly useful in production of
low volume, moderate to high pressure wells. In such
applications the size of the injection and production
tubing can be reduced to permit circulation of relatively
low volume rate of gas-water mixture, commensurate with
the production capability of the well. The bottom hole
pressure can be lowered by adjustmellt of the gas-water
ratio to a value where well fluids ent~r the production
tube readily. Continuous circulation will result in
continuous inflow and lift of wPll fluids.
In wells whose reservoirs are not supported by water
drive, water flood or pressure maintenance, the reservoir
pressure will gradually decline with continued
production.
The dual tubing method will permit efficient lift of
such wells until the percentage of submergence declines
to where lift by such means is no longer practical. This
condition will generally occur late in the life of the
well.
.'' . '- , `' ' " '
: :
~772Z~
12
Referring to Fig. 1, system Y wherein well fluid lOd
is displaced from well bore B through annulus lOg is used
where extremely large volumes of oil and/or water are to
be lifted. This is generally made possible by the large
cross-sectional area of annulus lOg. The advantage of
the gas lift method using an injection conduit lOm in
system Z is that it permits more rapid unloading of the
well bore B after startup. Additionally, the slippage of
the gas in the water on the downward part of the cycle in
injection conduit lOm will ~e less but the friction
losses will be greater. The ready response to surface
conditions makes the arrangement shown in the system Z
preferable for low to moderate production rates.
Fig. 6 is identical to the arrangemen~ within well
bore B shown on the left hand side of Fig. 1. Fig. 7
represents graphically the changes in well bore B when
the gas lift method of the present i~vention is utilized.
In approaching any gas lift problem ~or an existing well,
certain data regarding the well is calready known. Such
data includes the static bottom hole pressure, the
productivity index of the well (measured in barrels of
liquid per day per pound per square inch drop in bottom
hole pressure), the percent water cut, as well as other
data. From this data, the producing bottom hole pressure
at the point of injection to production conduit lOc and
the poin$ of lift can be ascertained for any desired
production rate. The flowing bottom hole pressure for a
given production rate from formation F is shown as point
80 on Fig. 7 and the injection pressure of 800 psi at the
surface, shown as point 82 on Fig. 7, define the average
pressure gradient in the injection conduit lOg.
Knowledge of this gradient allows the rate of injection
of water, that will be required to be mixed with a
specified volume of injection gas, to be determined in
order to maintain the surface injection pressure within
the limits of the pump 44 and compressor 30. Normally,
such injection pressure is in the range of 600-1200 psi.
~' ~' ' .
:
~ ~ .
:~Z772~3
13
Where well fluids 10d are produced through a
production conduit 10c as shown in Figs. 6 and 8,
standard two-phase gas lift 1Ow curves are employed to
determine their return gradient. The return gradient is
illustrated as curve 84 on Fig. 7. The return gradients
illustrated in Figs. 7 and 9 are taken from the "McMurry
Hughes, Inc. - Flow Gradient Curves" book.
EXAMPLE FOR INSTALLATION OF FIG. 6
.
Assumed Conditions:
Depth of well 10,550'
Tubing 2-7/8" EUE
Casing 5~2" od
Injection Pressure 800 psi
Wellhead Pressure 60 psi
Separator Pr~ssure 40 psi
Specific Gravity
of Gas 0.60
Bottom hole Temp. 200F
Perforations 10,000' to 10,040'
Depth of Injection 9,980l
Static Liquid Level 3,500'
Productivity Index 0.35 barrels of liquid
per day per psi drop in
bottom hole pressure
Percentage oil 50%;
API gravity 35;
Specific gravity 0.8499
Crude unsaturated; no free gas in reservoir
Specific gravity of produced water 1.08
Injection water = produced salt water
Desired production 140 barrels oil and 140 barrels
of water per day = 280 barrels liquid per day
or 8.163 gpm
, ~ , :
.
~ - :
~Z7722~
1~
PROCEDU E TO DETERMINE:
(a) Required gas volume;
(b) Rate of injection of water required
(1) Select for first trial injection rate of 120
barrels per day of salt water (SG = 1.08) equal to 3.5
gpm.
(2) Specific gravity of produced oil and water
equals
(140 barrels oil per day) x .8499 + (140 b~rrels wat~r per day) x 1.08 = o 965
280 barr~ls liquid per day
(3) Gradient of produced oil and water eguals (.433
psi per foot) x (.965) = 0.4178 psi per foot.
(4) Static bottom hole pressure at 9,980' = (9,980'
- 3,500) x (.4178) = 2707.5 psi (point; 86 on Fig. 7)
(5) Drop in bottom hole pressure due to production
= rate of production divided by productivity index =
280 barrels liquid per day = 800 psi
0.35
(6) Producing bottom hole pressure eguals
2707.5 psi - 800 psi = 1907.5 psi (see point 80 on
Fig. 7).
Accordingly during static conditions the variation
of pressure with depth in production conduit lOc is given
by curve 88 in Fig. 7. Curve 88 indicates ~hat during
static conditions the pressure begins to increase in well
bore B as the depth increases from 3 t 500 feet to the
bottom of the well bore B at 9,980 feet. It is
understood that the slope of curve 88 is .4178 psi per
foot. When the gas-liquid mixture described above is
introduced into the well bore and circulated back towards
the surface S, the density of the fluid in the well bore
is reduced or lightened so that the bottom hole pressuxe
is reduced.
The amount of the reduction is governed by the
productivity index for any particular well. For an
assumed production of 280 bbls li~./day, as in the above
. ,
- -
.. ~
.. ~ ' : , .. .
~ 1 277%2.~lS
example, the reduction of the bottom hole pressure is 800
psi. The drop in bottom hole pressure at 9,980 feet is
reflected by point 80 on Fig. 7.
The lowering of bottom hole pressure results in a
new and lower producing liquid level from the initial
value of 3,500 feet represented by point 90 on Fig. 7.
The new producing liquid level in the annulus lOg (Fig.
6) is:
4178 psi/ft = 5414 . 8 ~t.
(represented by point 92 on Fig. 7).
It therefore becomes evident that the gas lift
method of this invention will lift the well fluid at the
desired rate of production from a depth of 5414.8 feet.
It is equally evident that the energy of the fluids in
their compressed state in the reservoir from which the
well produces will sustain this produ~ing rate in lifting
from a depth of 10,000 feet up to this same elevation at
5414.8 feet. Because the well is flowing from lift
energy supplied by the gas-liquid mi~ture, the producing
liquid level is lowered below the static liquid level,
and with a consequent reduction in bottom hole pressure
as reflected by point 80 in Fig. '7. The well's
productivity index affixes the drop in bottom hole
pressure for a given rate of production.
The percentage submergence is defined by
(depth of injection~ - (producin~ uid level)
depth of injection
(9,980 feet) - (5,414.8 feet)
9,980 feet X 100 = 45.7%.
Referring to Fig. 10, the desired ratio of cubic
feet of gas per barrel of liquid can be determined.
Knowing that 120 harrels of salt water per day are
injected and a total production of 280 barrels of liquid
per day is desired, it is known that the total production
-
:
:
~.Z~7~
16
from production conduit lOc will be 400 barrels per day.
This condition represents water being 65 percent of the
flowing stream in production conduit lOc towards surface
S. Since the bottom hole depth and pressure at the
bottom of the hole during production of the desired 280
barrels per day of well fluid is known (see pt 110 on
Fig. 10), Fig. 10 indicates that a ratio of 470 cubic
feet of gas per barrel of liquid is required to maintain
the desired production of 280 barrels per day from
formation F. The 470 cubic foot of gas per barrel of
liquid figure is obtained from interpolation between the
curves labeled 400 and 600 on Fig. 10. In the above
examples, the specific gravity of the 400 barrels of
fluid per day emerging from production conduit lOc is
equal to one.
Having found the desired ratio of cubic feet of gas
per barrel of li~uid and knowing that 400 barrels of
liquid per day are produced, the amolmt of the required
gas volume is given by 400 barrels per day times 470
cubic feet of gas per barrel of liqu:id or 188,000 cubic
feet per day or 130.56 cubic feet per minute.
The ratio of the water injected to the volume of gas
injected can be increased thereby lowering the injection
pressure at the surface S. As can readily be seen; the
injection of additional water great:Ly increases the
density of the injected combination of liquid and gas in
the annulus lOg thereby decreasing the pressure required
at compressor 30 and pump 44 in lifting well fluids lOd
to surface S in production conduit lOc. The amount of
water added should be regulated in each application so
that the injection pressure at surface S is close to but
does not exceed the rated capacity of compressor 30 or
pump 44.
.
.
:. '' , ' : .
'7~Z~
17
EXAMPLE FOR INSTALLATION OF F'IG. 8
-
Fig. 9 represents schematically and graphically the
well conditions during a gas lift operation with system Z
(Fig. 1). The assumed well conditions are:
W~ll depth 7,600 feet
Perforations 7, 480 feet to 7, 496 feet
Pressure of injection of the gas~ uid mixture -
750 psi
D~pth of injection 7,460 feet
Production string of tubing 2-3/8 inch EUE
Injection string of tubing 2. 063 inches EUE
Specific gravity of oil 0.8499 (35 API)
Static oil level (no water) 3,250 feet
Productivity index 0.5 barrels of oil per day per
psi drop in bottom hole pressure
Bottom hole temperature 210F
Wellhead pressure 60 pounds per r,quare inch
Separator pressure 80 pounds per square inch
Specific gravit~ of injection wa~er 1.06
Desired production 175 barrels of oil per day or
5.10 gpm
Gas gravity 0.65
PROCEDURE TO DETERMINE:
(a3 Gas volume to be injected; and
(b) Injection water rate for injection pressure of
750 psi for the water and gas mixture.
(1) Gradient due to 35 oil = 0.84g9(.433) = 0.368
psi/ft.
(2) Static bottom hole pressure at 7,460' = (7460 ~
3250)(.368) = 1549.28 psi (point 100 on Fig. 9)
(3) Select 25 barrels per day as injection rate for
salt water = 0.729 gallons per minute.
(4) Specific gravity of oil-water mixture e~uals
175( 8499) +o025(1 06) = 0.876
, '
.
., . ~ , ,' '' .
,
~.~7'72%~
18
(5) Producing bottom hole pressure at
7,460' = 1549.28 - 175
0.5
= 1549.28 - 350 = 1199.28 psi
(point 102 on Fig. 9)
(6) Producing liquid level (equals point of lift)
= 3250 + 350 = 4201.08
.368
(point 104 on Fig. 9)
As in the previous example, curve 106 illustrates
the increase in pressure with depth beginning at zero
pressure at the initial liquid level of 3,250 feet given
by point 108 on Fig. 9 and using a gradient of .368
pounds per square inch per foot to arrive at point 100 on
Fig. 9. As shown in Fig. 9, after production of 175
barrels of oil per day is initiated from the formation F
the bottom hole pressure drops at the 7,460 foot level
from 1,549.28 psi to 1,199.28 psi as indicated by point
100 and point 102, respectively. Accordingly, with the
bottom hole pressure reduced to 1,199.28 psi and further
employing the gradient of .368 pounds per sguare inch per
foot it can be seen on point 104 on Fig. 9 that the
producing liquid level will be lowered from 3,250 feet to
4,201.08 feet as represented by point 108 and point 104,
respectively.
Next, knowing that 175 barrels oE oil are desired to
be produced and that 25 barrels per day of injection
water is also used, Figs. 11 and 12 can be used to
determine the ratio of s-tandard cubic feet of injection
gas required per barrel of production. It should be
noted that Fig. 11 is based upon zero percent water
produced and Fig. 12 is based upon sixty-five percent
water being produced. Since 25 barrels per day are
injected, the actual initial ratio of gas per barrel
produced will comprise of an interpolation between Figs.
11 and 12 weighted towards Fig. 11 since in effect the
injection of 25 barrel per day of water will result in
12~ percent water being produced in produc-tion conduit
: -
: ' ' .
.,~ ' , ' , .
~l 277%2~
lg
lOc. Accordingly, referring to Fig. 11 it can be seenthat the intersection of 1,199.28 psi at 7,460 feet
(which is represented by poin-t 102 on Figs. 9, ll and 12)
translates to approximately 372 standard cubic feet a day
per barrel on Fig. 11 and roughly 440 cubic feet a day
per barrel on Fig. 12. The gas--liquid ratio may then be
calculated:
Gas-liquid ratio = (Barrels oil per day x 372) t (Barrels water per day x 440)
Barrels oil per day + B~rrels wat~r per day
= 175(372) + 25(440) = 380 standard cu. ft. per harrel
200
Finally, the ratio is multiplied by the total production
of 200 barrels per day to yield 76,000 cubic feet per day
or 52.78 cubic feet per minute.
As in the previous example, the ratio of water to
gas can be controlled to regulate the injection pressur~
of the water-gas mixture at the surface S to a pressure
below the rated pressures of pump 44 or compressor 30.
The mixing of the gas and water occurs at the surface S
at the point where the flow lines 32 and 46 join as shown
in Fig. 1, so that mixing of the gas and water is at
substantially the same pressure as the injection pressure
of the gas-oil mixture as it is introduced into the well.
Since data of the type shown in Figs. 10 through 12
is not available for the annulus flow system Y, the
analysis in that type of a gas lift operation involves a
presumption of an overall system efficiency which eguals
the gas lift work output divided by the total compressor
and pump horsepower input. Having assumed an efficiency,
e.g. thirty percent (30%), an initial starting level of
injection water is selected and the calculations proceed
as per the examples given above. As before the ratio of
water to gas is varied to control the injection pressure
at the surface to below the rated limits of pump 44 and
3S compressor 30. However, the efficiencies achieved in
production of well fluids through annulus lOg will be
considerably lower than for those attained in systems X
- ' :'
~ ;~77;~
2~
and Z, wherein production is through tubing. Because of
the larger cross-sectional area of annulus 10g as
compared to the injection concluit 10m in system Y,
greater amounts of injection gas should be reguired to
transport the well fluid 10d to opening 10k in casing
10a. However, applying the gas lift technique for
producing well fluid 10d through annulus lOg has the
advantage of allowing production of greater ~uantities of
well fluid 10d from formation F than the gas lift systems
X and Z wherein well fluids are produced from production
conduit 10c.
On start-up or during unloading, the discharge
~ressure of the compressor 30 and pump 4~, otherwise
called the surface injection pressure, wil~ yenerally
rise as the gasified mixture travels down the injection
conduit 10m or annulus 10g. The pressure will reach a
maximum as the mixture reaches the bottom and starts its
upward travel through the production conduit 10c in
systems X and Z, or through the annulus 10g in system Y.
Up until this time, the surface injection pressure rises
because the gasified fluid inside the injection conduit
is lighter than the initial well fluid being displaced
through the production conduit. For those instances
where the surface injection pressure rises above the
pressure rating of the compressor 30 and or pump 44, gas
injection must be stopped until sufficient water has been
pumped to bring the pressure down. When the well is next
unloaded, the rate of gas injection can be decreased
throughout the first cycle. The first cycle can actually
be achieved using half compressor capacity and then
subseguently reinstating full compressor capacity
operation. Although most wells can be unloaded without
exceeding the rating of the surface eguipment, if such a
problem arises, the well can be unloaded for the first
3S cycle by decreasing the gas rate or increasing the pump
rate or both. It is within the purview cf the present
invention to automate the control of gas ~olume an~
1.~772~.~
21
pressure and water volume and pressure automatically to
avoid exceeding the rated capacities of the injection
compressor 30 or pump 44.
Accordingly, the gas lift method of the present
invention offers many advantages over that of known
conventional gas lift systems. Some of these advantages
are: no gas lift valves are required for unloading of a
well; no gas lift valves or other contrivances are
r~quired to compensate for changing well conditions; no
investment or expenditure of funds for valve replacement
and or repair is required; maximum submergence for any
producing rate is assured at any point of lift (this
means maximum lift efficiency will also result with
minimum expenditure for plant horsepower); and corrosion
and/or scale inhibitors can be introduced into the
injection water for easy protection.
Applicant's method of gas lift c~m be applied either
to flowing or to non-flowing wells. The examples which
have been presented for lifting of non-flowing wells
apply equally to flowing wells.
In conventional gas lift systems employing gas alone
as the lifting medium and gas lift valves, spacing
between the gas lift valves must by their nature decrease
with depth. Hence, there is a limit to the number of
valves that can be run ~or a given installation as well
as depth to which they can be run for a given surface
in~ection pressure. With the gas lift system of the
present invention, no such limitations exist. ~inally,
the gas lift system of the present invention has no
valves to pop open at depths where such valves are not
supposed to open. Instead, only one port exists for
entry of injection fluid to the production conduit.
The foregoing disclosure and description of the
invention are illustrative and explanatory thereof, and
various changes in the size, shape and materials, as well
as in the details of the illustrated construction may be
made without departing from the spirit of the invention.
., - .
- . - - , , .-
:: '~, ~: - - ' ,' ' .
