Note: Descriptions are shown in the official language in which they were submitted.
CA 02281083 1999-08-17
METHOD AND APPARATUS FOR DOWN-HOLE OILIWATER SEPARATION
DURING OIL WELL PUMPING OPERATIONS
TECHNICAL FIELD OF THE INVENTION
The present invention relates generally to equipment for the production of
hydrocarbons and, more particularly, to a method and apparatus for down-hole
oil/water separation during oil well pumping operations.
BACKGROUND OF THE INVENTION
The production of underground hydrocarbons often requires substantial
investment in drilling and pumping equipment. When production is underway, up-
front costs can be recouped provided operating costs remain low enough for the
sale
of oil and/or gas to be profitable. One factor which significantly effects the
operating
costs of many wells is the amount of water present within the associated
hydrocarbon producing formation. Many profitable wells become uneconomic
because of excessive water production. Costs involved with pumping,
separating,
collecting, treating and/or disposing of water often have a devastating impact
on the
profit margins, particularly for older wells with declining hydrocarbon
production.
Over the years, many attempts have been made to limit the amount of water
produced by a well. Down-hole video has been utilized to determine which
perforations within the well produce the most oil, and which perforations
produce the
most water. Chemicals and/or cement may then be utilized in an effort to shut
off
CA 02281083 1999-08-17
-2-
water producing perforations. One such down-hole video revealed that oil
droplets
were distinctly separate from the water that was being produced. More
importantly,
it was recognized that oil and water are typically separated by gravity
segregation in
the wellbore until they are mixed together by the downhole pump.
In order to capitalize on this phenomena, the Dual Action Pumping System
("DAPS") was developed wherein a dual ported, dual plunger rod pump produced
oil
and water from the annulus on the upstroke while injecting water on the down
stroke.
In many suitable wells DAPS have substantially increased production while
simultaneously reducing power requirements.
SUMMARY OF THE INVENTION
In accordance with teachings of the present invention an improved method
and apparatus for down-hole oil/water separation during pumping operations is
provided to substantially improve hydrocarbon production as compared to prior
down-hole oil/water separating pumps.
One embodiment of the present invention includes a conventional sucker rod
pump disposed within a tubing string which may be disposed within the casing
of a
wellbore. The sucker rod pump may be releasably attached to a sucker rod at
one
end. The sucker rod pump may have a single ball and seat type traveling valve
with
the bottom check valve or standing valve removed.
In another embodiment, the casing may also contain a plurality of injection
perforations which may be spaced down-hole from a plurality of production
perforations. A packer may be located in a down-hole position between the
production perforations and the injection perforation. The packer may
CA 02281083 1999-08-17
-3-
circumferentially surround the tubing string to form a fluid seal within the
annulus
between the casing string and the tubing string.
In yet another embodiment, a side intake valve may be disposed within the
tubing string at a position down-hole from the sucker rod pump. The side
intake
valve may also be disposed at an elevation above the packer and above the
production perforations.
In still another embodiment, a check valve may be located within the tubing
string at a position down-hole from the sucker rod pump. The check valve is
preferably disposed at an elevation below the side intake valve. In one
embodiment,
the check valve may be of the gravity operated type. In another embodiment,
the
check valve may be of the spring-loaded type.
In yet another embodiment, the sucker rod may be attached to a standard
pumping jack located at the surface of the wellbore. The tubing string may be
attached to production piping at the surface of the wellbore. In one
embodiment, the
production piping may be configured to form a bypass loop. The bypass loop may
further contain a check valve to regulate the direction of flow of the
produced fluid.
An automatic control valve may also be located within the bypass loop to allow
the
produced fluid to bypass the check valve. A back pressure regulator may be
installed within the production piping on the side of the bypass loop opposite
the
wellbore. In one embodiment, an accumulator may also be connected to the
production piping between the bypass loop and the back pressure regulator.
Technical advantages of the present invention include providing a sucker rod
pump for down-hole oil/water segregation during pumping operations. In
particular,
CA 02281083 1999-08-17
-4-
the apparatus of the present invention may separate oil and water in the
tubing string
and/or the annulus between the tubing string and the casing. This allows the
apparatus to produce oil with a limited amount of water to the surface of the
well
while injecting water back into the formation, during pumping operations.
Another technical advantage of the present invention includes the simplicity
and compactness of its design. This permits the apparatus to operate utilizing
standard downhole well equipment with minor modifications. Accordingly,
downhole
equipment incorporating teachings of the present invention can be built and
maintained at a reduced cost and operators require very minimal training.
Furthermore, this apparatus is not limited in application and can be
incorporated into
any standard-sized casing or tubing string.
Yet another technical advantage of the present invention includes the
injection pressure supplied by the accumulator located at the well surface.
There is
no pressure limit for this pump because high pressure wells can be
counteracted by
raising the pressure in the accumulator thereby increasing the injection
pressure.
Further technical advantages of the present invention include providing a
pump which eliminates the problem of gas-lock which occurs in dual-plunger
pumping systems. Furthermore, the present invention provides a pumping system
which minimizes or eliminates the injection of oil into the formation when the
upper
pump has "pumped off."
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present invention, and the
advantages thereof, reference is now made to the following brief descriptions,
taken
CA 02281083 2000-O1-24
-5-
in conjunction with the accompanying drawings and detailed description,
wherein
like reference numerals represent like parts, in which:
FIGURE 1 is a schematic drawing in section and in elevation with
portions broken away which show a hydrocarbon producing well having equipment
incorporating teachings of the present invention;
FIGURES 1A & 1B are schematic diagrams of alternate configurations of
surface pumping equipment for use with the well of FIGURE 1;
FIGURE 2 is a schematic drawing in section of a side intake valve and
injection valve incorporating teachings of the present invention;
FIGURE 3 is a schematic drawing in section showing an alternative
embodiment of the injection valve of FIGURE 2;
FIGURE 4 is a schematic drawing in section with portions broken away
showing an alternative embodiment of the side intake valve and injection valve
of
FIGURE 2;
FIGURE 5 is a schematic drawing in section and in elevation with
portions broken away showing a hydrocarbon producing well having equipment
representing an alternative embodiment of the present invention; and
FIGURE 6 is a schematic drawing in section and in elevation with
portions broken away showing the down-hole portion of a well incorporating an
alternative embodiment of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
The preferred embodiments of the present invention and its advantages
are best understood by referring now in more detail to FIGURES 1-6 of the
drawings, in which like numerals refer to like parts.
CA 02281083 1999-08-17
-6-
Referring to FIGURE 1, a diagrammatic cut away side view of a well 30 is
illustrated. Well 30 may be used for the production of hydrocarbons, but
equipment
incorporating teachings of the present invention is also suitable for use with
other
types of wells.
Well 30 includes a wellbore 32, having a casing 34 cemented therein. Casing
34 preferably contains a plurality of production perforations 36 and plurality
of
injection perforations 38. A tubing hanger 40 is secured to casing 34 at the
surface
of wellbore 32. Tubing hanger 40 is releasably connected to tubing string 42
thereby
securing tubing string 42 in place within casing 34. Casing 34 and tubing
string 42
together form annulus 44. A packer 50 circumferentially surrounds tubing
string 42
thereby partitioning annulus 44 into upper annulus 46 and lower annulus 48.
Packer
50 preferably includes one or more expandable elements to form a fluid barrier
within
annulus 44 between tubing string 42 and casing 34. When packer 50 is run into
a
preselected position, it can be expanded mechanically, hydraulically, or by
another
means against tubing string 42 and casing 34. In one embodiment of the present
invention, an on-off tool 51 may be provided at the transition between packer
50 and
tubing string 42. On-off tool 51 allows tubing string 42 to be repeatedly
removed
from and inserted into packer 50 without dislodging and having to reset packer
50
each time. The G-6 Packer with an XL ON-OFF tool as manufactured by Dresser
Oil
Tools, a division of Dresser Industries, Incorporated, Dallas, Texas, is
suitable for
use within the teachings of the present invention.
A standard surface pumping jack 90 may be installed at the surface of
wellbore 32. A steel cable or bridle 92 extends from horsehead 94 of pumping
jack
CA 02281083 1999-08-17
-7-
90. Bridle 92 is coupled to a polished rod 102 by a standard carrier bar 96.
At a
position further down-hole, polished rod 102 is coupled with sucker rod 98. In
one
embodiment of the present invention, sucker rod 98 includes steel rods that
are
screwed together to form a continuous "string" that connects sucker rod pump
52
inside of tubing string 42 to pumping jack 90 on the surface of well 30.
As illustrated in FIGURE 1, polished rod 102 is approximately thirty-three
feet
in length. Polished rod 102 may also be provided at varying lengths within the
teachings of the present invention. A stuffing box 104 is provided at the top
of tubing
string 42 in order to seal the interior of tubing string 42 and prevent
foreign matter
from entering. Stuffing box 104 is essentially a packing gland or chamber to
hold
packing material (not shown) compressed around a moving pump rod or polished
rod
102 to prevent the escape of gas or liquid. Polished rod 102 provides a smooth
transition at stuffing box 104 and allows for polished rod 102 to operate in
an upward
and downward motion without displacing stuffing box 104 or tubing string 42.
A sucker rod pump 52 is secured at one end to sucker rod 98. Sucker rod
pump 52 may be of the conventional type requiring only that the lower ball and
seat
valve be removed prior to operation of the pump. Part number 25-175-TH-20-4-2
as
specified by the American Petroleum Institute's specification 11AX, with the
standing
valve ball removed, is suitable for use within the teachings of the present
invention.
Sucker rod pump 52 includes a barrel 60 which is secured thereto, thereby
becoming an integral part of, tubing string 42 with threaded collars 62.
Sucker rod
pump 52 also includes a movable piston 64. Barrel 60 remains stationary and
connected to tubing string 42 during operation of sucker rod pump 52. When
CA 02281083 1999-08-17
_$_
pumping jack 90 is activated, movable piston 64 is forced upward and downward
through barrel 60 creating a low pressure within barrel 60 and tubing string
42. A
traveling valve 66 is provided at the down-hole end of movable piston 64.
Within one
embodiment of the present invention, traveling valve 66 may be a check valve
of the
single ball and seat type. Traveling valve 66 is configured to allow flow of
fluid
through traveling valve 66 in an uphole direction only. Fluid is prevented
from
traveling through traveling valve 66 in a down-hole direction.
Sucker rod pump 52 of FIGURE 1 is preferably a standard tubing pump
wherein barrel 60 is integral with tubing string 42. In an alternative
embodiment of
the present invention, sucker rod pump 52 may be provided as a standard
American
Petroleum Institute (API) rod pump wherein the entire pump including the
barrel is
run within tubing string 42 by attached sucker rod 98.
A side intake valve 54 is installed within tubing string 42 at a location down-
hole from sucker rod pump 52. Side intake valve 54 may also be positioned
above
packer 50. Side intake valve 54 includes inlet port 55 and check valve 57.
Inlet port
55 allows fluid within annulus 44 to enter tubing string 42. Check valve 57
permits
the flow of fluid from annulus 44 into tubing string 42 but prevents flow in
the
opposite direction. In the embodiment of the present invention illustrated in
FIGURE
1, side intake valve 54 is positioned approximately two standard tubing string
lengths, or sixty six feet above packer 50. While side intake valve 54 may
also be
positioned at a higher or lower elevation with respect to packer 50, it is
often
preferable to place side intake valve 54 in close proximity to packer 50.
Placing side
intake valve 54 a larger distance away from packer 50 may allow a significant
CA 02281083 1999-08-17
_g_
amount of sand and debris to accumulate between side intake valve 54 and
packer
50. This may cause damage to tubing string 42 during removal from casing 34.
Side
intake valves suitable for use within the teachings of the present invention
will be
described later in more detail.
An injection valve 56 may be attached to tubing string 42 at a point down-hole
from packer 50. Injection valve 56 isolates the interior of tubing string 42
from lower
annulus 48. Injection valve 56 is configured to allow flow from the interior
of tubing
string 42 into lower annulus 48, but will prevent flow from lower annulus 48
into the
interior of tubing string 42.
Injection valve 56 may be provided as a standard check valve with tubing
threads for connection to tubing string 42 which prevents backflow of water
from
injection zone 49 surrounding lower annulus 48 during the lifting cycle. The
location
of injection valve 56 with respect to sucker rod pump 52 is generally not
critical
provided injection valve 56 is situated below sucker rod pump 52. Injection
valve 56
should be installed below inlet port 55. The distance between sucker rod pump
52
and injection valve 56 can range from a few feet to over one thousand feet.
Injection valve 56 may be provided as a standard gravity actuated check
valve. In an alternative embodiment, a spring loaded check valve may be
required
to supply back pressure to tubing string 42 to prevent the hydrostatic
pressure within
tubing string 42 from exceeding the pressure required to inject water through
injection valve 56 and into injection zone 49.
At an elevation above tubing hanger 40, production piping 106 extends from
tubing string 42. Production piping 106 allows communication of fluid from
tubing
CA 02281083 1999-08-17
-10-
string 42 to a surface collection point (not expressly shown). A bypass loop
108
extends from production piping 106. A check valve 110 is provided within
bypass
loop 108 and governs the direction of flow of fluids through bypass loop 108.
One
embodiment of the present invention may incorporate a CV-200 check valve as
manufactured by Hydroseal.
An automatic control valve 112 is installed within production piping 106
allowing fluids within production piping 106 to bypass check valve 110 and
bypass
loop 108 when control valve 112 is in the "open" position. A timer switch (not
expressly shown) may also be incorporated to control the opening and closing
of
automatic control valve 112, at specified time intervals. Electric Valve
#31460-WP
as manufactured by Atkomatic with a timer switch CX100A6 as manufactured by
Eagle Signal may be incorporated within the teachings of the present
invention.
An adjustable back pressure regulator 114 regulates the pressure within
production piping 106 and an accumulator 116 is attached to production piping
106
between bypass loop 108 and back pressure regulator 114. Pressure Regulator
#7702 as manufactured by Baird is suitable for use within the teachings of the
present invention. Accumulator 116 maintains sufficient injection pressure to
prevent
traveling valve 66 from opening when automatic control valve 112 is in the
"open"
position. The pressure within accumulator 116 may be maintained by injecting
nitrogen gas 117 into bladder 115. The level of produced fluid within
accumulator
116 is denoted by reference numeral 119. An accumulator suitable for use
within the
teachings of the present invention is PN 831615 as manufactured by Greer
Hydraulics, Inc.
CA 02281083 1999-08-17
-11-
Although the embodiment of the present invention illustrated in FIGURE 1
includes a nitrogen charged accumulator, many other types of accumulators are
also
available for use within the teachings of the present invention. Furthermore,
any
system capable of supplying and maintaining pressure within production piping
106
may be utilized interchangeably with accumulator 116.
During the operation of well 30, a mixture of oil, water and other fluids will
typically enter upper annulus 46 through production perforations 36 to a fluid
level
58 within tubing string 42, as illustrated in FIGURE 1. The fluid level will
depend on
several factors such as formation pressure and formation fluid flow rates.
Side intake
valve 54 is preferably secured into a position below fluid level 58 allowing a
mixture
of oil and water to be drawn through inlet port 55 and into intake valve 54 to
the
interior of tubing string 42. The oil and water mixture within tubing string
42 and
barrel 60 will begin to separate as the tighter oil droplets float toward the
top and the
water settles toward injection valve 56.
Pumping jack 90 forces movable piston 64 up and down within barrel 60.
When piston 64 moves upward toward the surface of wellbore 32, traveling valve
66
prevents fluid located above piston 64 from moving to a down-hole location.
This
creates a low pressure effect down-hole from piston 64 thereby forcing fluid
within
upper annulus 46 to flow through side intake valve 54 and into the interior of
tubing
string 42. When piston 64 is forced downward through barrel 60 traveling valve
66
will open allowing fluid to travel uphole from piston 64 where it will become
trapped
by traveling valve 66. By continuing this operation, all of the fluid within
upper
annulus 46 can be produced to the surface of well 30 and into production
piping 106.
CA 02281083 1999-08-17
-12-
Unfortunately, the oil and water mixture within upper annulus 46 may contain
a large proportion of water. Conventional pumping operations require that all
of the
water contained within this oil water mixture be pumped to the surface,
separated,
collected, treated and/or disposed of which has a negative impact on
production
costs. In order to overcome this, the present invention provides an apparatus
and
a method whereby water is disposed of below the well surface prior to pumping
and
an oil and water mixture containing a much higher proportion of oil to water
is
produced at the well surface. The teachings of the present invention may also
be
used to dewater a gas well. The present invention capitalizes on the rapid
gravity
segregation of oil and water which occurs within tubing string 42 below the
surface
of the well.
The piping and equipment at the surface of well 30 provide a mechanism by
which water within the oil and water mixture can be disposed of prior to
production.
When automatic control valve 112 is in the "closed" position, all fluid
produced from
well 30 through tubing string 42 and into production piping 106 must travel
through
piping loop 108 and check valve 110. Check valve 110 allows fluid to flow from
well
30 toward accumulator 116 and will prevent the flow of fluid in the opposite
direction.
Back pressure regulator 114 is set to maintain a preselected minimum back
pressure within production piping 106 between automatic control valve 112 and
back
pressure regulator 114. This allows accumulator 116 to fill with fluid thereby
maintaining pressure within production piping 106. The back pressure provided
by
nitrogen gas 117 within accumulator 116 can be maintained at a level
sufficient to
CA 02281083 1999-08-17
-13-
seal traveling valve 66 in the "closed" position when automatic control valve
112 is
in the "open" position.
When automatic control valve 112 is in the "closed" position, sucker rod pump
52 will operate as follows. During the upstroke of surface pumping jack 90,
oil and
water enter tubing string 42 through side intake valve 54. The oil tends to
float on
the more dense water inside tubing string 42. As fluid is produced to the
surface, it
bypasses automatic control valve 112 and travels through check valve 110. In
this
manner, accumulator 116 is charged and back pressure regulator 114 releases
excess fluid to a flow line 118. During the downstroke of pumping jack 90,
there is
not enough pressure on injection valve 56 to force fluid from the interior of
tubing
string 42 through injection valve 56. The reason the pressure is too low to
inject
water through injection valve 56 is that automatic control valve 112 isolates
tubing
string 42 from the pressure of accumulator 116. Accordingly, piston 64 moves
down-
hole with traveling valve 66 in the "open" position, thereby collecting fluid
above
piston 64, similar to a conventional rod pump.
When automatic control valve 112 is open, sucker rod pump 52 will operate
as follows. During the upstroke of pumping jack 90, oil and water enter tubing
string
42 through side intake valve 54. Once again, the oil tends to float toward the
surface
as the more dense water settles downward toward packer 50 inside tubing string
42.
At the surface of well 30, produced fluid flows through both automatic control
valve
112 and check valve 110. Accumulator 116 is charged and back pressure
regulator
114 releases excess produced fluid to flow line 118. On the downstroke of
pumping
jack 90, the pressure above piston 64 is greater than the pressure below
piston 64
CA 02281083 1999-08-17
-14-
which causes traveling valve 66 to remain in a "closed" position. Since the
hydrostatic pressure of fluid within tubing string 42 coupled with the
pressure
supplied by accumulator 116 is higher than the pressure required to inject
water
through injection valve 56, water located at the bottom of tubing string 42
will be
forced through injection valve 56 and subsequently travel through injection
perforations 38 to an underground position within injection zone 49. Little or
no oil
is injected into injection valve 56 because the oil and water separate inside
tubing
string 42 between piston 64 and injection valve 56. The lighter oil floats on
water.
On the next upstroke, fluid is not produced to the surface because there is a
one-
stroke vacancy inside the tubing that is replaced by this stroke. The
operation of
automatic control valve 112 determines the ratio of fluid produced to the
surface to
the fluid injected through injection valve 56. For example, if automatic
control valve
112 is preset to open for nine strokes of pumping jack 90 and closed for one,
nine
volumes (90%) of water will be injected through injection valve 56 for every
one
(10%) volume of fluid produced to the surface of well 30.
As discussed previously, a spring loaded injection valve may be required in
low pressure wells in order to create back pressure within tubing string 42.
This back
pressure is required to maintain the level of fluid within tubing string 42
and other
pumping equipment. Back pressure regulator 114 is set to be at least as high
as the
injection pressure of the injection zone minus the hydrostatic pressure of
fluid within
tubing string 42. Accumulator 116 is sized to accommodate a minimum of one
displaced volume of sucker rod pump 52. When automatic control valve 112 is
closed, the pumping action is similar to a conventional sucker rod pump. When
CA 02281083 1999-08-17
-15-
automatic control valve 112 is open, the pump will not produce any fluid to
the
surface but it will inject fluid through injection valve 56 into injection
zone 49. The
ratio of fluid produced to fluid injected is equal the percentage of time that
the control
valve is closed.
FIGURES 1A and 1 B illustrate alternative configurations of surface pumping
equipment available for use with the well of FIGURE 1. For some applications
(i.e.
"low pressure" wells), the accumulator 116 is not required.
When the surface equipment associated with production piping 106 is
configured in accordance with FIGURE 1A, the well can be operated in at least
two
distinct modes. The first mode is available when automatic control valve 112
is
closed. Automatic control valve 112 is not required and the first mode of
operation
may be accomplished when automatic control valve is not installed (See FIGURE
1 B).
During the first mode of operation, on the upstroke water and oil are pulled
in
through side intake valve 54 into tubing string 42. This causes water and oil
within
production piping 106 to be forced through back pressure regulator 114,
bypassing
automatic control valve 112 (see FIGURE 1A). The amount of water and oil
displaced within tubing string 42 is equal to volume of oil and water
displaced by
moveable piston 64. The amount of oil and water forced through production
piping
106 will equal the amount of oil and water displaced by moveable piston 64
reduced
by the amount of water and oil displaced due to the movement of polished rod
102.
On the downstroke polished rod 102 displaces water and oil from tubing string
42
causing the water and oil to be expelled from the tubing string at the
location that
CA 02281083 1999-08-17
-16-
requires the least pressure. In other words, the water and oil will follow the
path of
least resistance, out of tubing string 42. Back pressure regulator 114 may be
adjusted to force this water and oil to be expelled through the lower end of
tubing
string 42 at injection valve 56. The water and oil mixture at the lower end of
tubing
string 42 is predominantly, and in the best case scenario entirely, water.
Therefore,
during this mode of operation, water is expelled through injection valve 56
into
injection zone 49, on the downstroke of moveable piston 64. In this mode of
operation, the ratio of fluid produced to the surface of the well to fluid
disposed of at
injection zone 49 will equal the difference between the amount of fluid
displaced by
moveable piston 64 and the amount of fluid displaced by polished rod 102
divided
by the amount of fluid displaced by polished rod 102.
During the second mode of operation, automatic control valve 112 is open
and all fluid produced to the surface of the well will bypass back pressure
regulator
114 through production piping 106 (see FIGURE 1A). During this operation, back
pressure regulator 114 does not supply pressure within tubing string 42 as it
does
during the operation described in the first mode above. On the upstroke of
moveable
piston 64, water and oil enter tubing string 42 through side intake valve 54.
This
forces fluid through automatic control valve 112 into flow line 118. The
amount of
fluid that enters flow line 118 will equal the amount of fluid displaced by
moveable
piston 64 minus the amount of fluid displaced by polished rod 102. On the
downstroke of moveable piston 64, polished rod 102 displaces fluid from tubing
string
42 which must be expelled from tubing string 42. The expelled fluid will
follow the
path of least resistance and exit tubing string 42 at the point of least
pressure. Since
CA 02281083 1999-08-17
-17-
automatic control valve 112 is open, the expelled fluid will travel through
automatic
control valve 112 into flow line 118. In the second mode of operation, fluid
will be
produced to the surface of the well at flow line 118, and no fluid will be
injected into
injection zone 49. A timing device can be utilized to control the opening of
automatic
control valve 112 at preset intervals in order to achieve various ratios of
fluid
produced to the surface of the well at flow line 118 to fluid injected into
injection zone
49 through injection valve 56. Any device which will control the opening and
closing
of automatic control valve 112 is suitable for use within the teachings of the
present
invention. Check valve 110 of FIGURE 1A is optional and provides a mechanism
to
control the flow of fluid through production piping 106.
FIGURE 1 B illustrates an alternative configuration of surface equipment
suitable for use with the well of FIGURE 1, within the teachings of the
present
invention. This configuration may be utilized by a well operator when the
ambient
conditions at the well render the use of an accumulator and an automatic
control
valve unnecessary.
Although the surface equipment configurations represented in FIGURES 1A
and 1 B have been illustrated and described for use with the well of FIGURE 1,
they
are equally applicable to any other well configuration, including those shown
and
described in FIGURES 5 and 6.
One advantage of the present invention includes its incorporation of a
standard sucker rod pump. Accordingly, the size of the pump does not limit the
application. The present invention may be practiced within any casing size
accessible by conventional sucker rod pumps. Many of the prior attempts to
CA 02281083 1999-08-17
-18-
separate oil and water at a down-hole location have required a larger
specially
designed pump which was not appropriate in smaller casing sizes. Furthermore,
there is no pressure limit inherent within the teachings of the present
invention since
any down-hole pressure can generally be overcome by increasing the pressure of
nitrogen gas 117 of accumulator 116, thereby charging production piping 106
and
tubing string 42 with back pressure sufficient to overcome any pressure
experienced
down-hole.
The configuration of surface equipment illustrated in FIGURE 1 allows for
great versatility in fluid production. The injection to production ratio of
this system
is controlled by the operator from the surface of the well and is determined
by the
timing of automatic control valve 112. Furthermore, the configuration of
equipment
illustrated in FIGURE 1 allows oil and water to be separated within tubing
string 42
rather than annulus 44.
Although oil and water separation have been described and illustrated in
conjunction with FIGURE 1, the teachings of the present invention may also be
utilized to de-water a gas well. The operation of a gas well would include gas
entering well 30 through perforations 36. As water and hydrocarbons
accumulate,
fluid level 58 will rise. The additional pressure within casing 42 caused by
the rising
fluid level 58 makes it difficult to collect gas which accumulates in annulus
44. By
disposing of water into injection zone 49, gas can be more easily collected at
the
surface of the well. Gas which accumulates within annulus 44 would typically
be
collected at tubing hanger 40, by installing gas collection piping (not
expressly
shown).
CA 02281083 1999-08-17
-19-
Referring now to FIGURE 2, a side intake valve 150 and injection valve 160
suitable for use within the teachings of the present invention are shown. As
illustrated by FIGURE 2, side intake valve 150 and injection valve 160 may be
provided within an integral valve assembly 148 suitable for connection to a
tubing
string (not expressly shown) at threaded connections 162 and 164. Side
Intake/Bottom Discharge Valve PN-147372 as manufactured by Dresser Oil Tools,
a division of Dresser Industries, Dallas, Texas, is suitable for use within
the teachings
of the present invention. Injection valve 160, as illustrated in FIGURE 2, is
a bottom
discharge gravity actuated check valve suitable for use in high pressure
injection
zones. An alternative embodiment is illustrated by injection valve 161
illustrated in
FIGURE 3. Injection valve 161 provides a spring loaded bottom discharge
injection
valve suitable for use within low pressure injection zones. Injection valve
161 may
be utilized to prevent unwanted "runaway" injection caused by the low pressure
below injection valve 161.
Valve assembly 148 includes a side intake injection valve 150 and a bottom
discharge injection valve 160. Valve assembly 148 also includes an upper
nipple
173 suitable for threadable connection to a tubing string (not expressly
shown). A
cage bushing 178 is provided within side intake injection valve 150. A
compression
ring 182 is provided around cage insert 184 sealing the gap around the
circumference of cage insert 184. A cage body 186 secures a side intake body
188
in place within valve assembly 148. Side intake body 188 allows the
communication
of fluid outside valve assembly 148 through side intake body 188 into valve
assembly
148. A lower nipple 190 is provided to connect the side intake valve 150
portion of
CA 02281083 1999-08-17
-20-
valve assembly 148 to the bottom discharge injection valve 160 portion of
valve
assembly 148.
Bottom discharge injection valve 160 of valve assembly 148 includes a ring
compression bushing 192 surrounding a caged compression ring 194. Plug seat
196
and plug 198 provide a mechanism by which bottom discharge injection valve 160
may regulate the direction of flow of fluid through injection valve 160 by
preventing
fluid from entering the interior of valve assembly 148 through injection valve
160.
An alternative embodiment of the valve assembly of FIGURE 2 is illustrated
in FIGURE 4.
Referring now to FIGURE 5, an alternative embodiment of the present
invention is illustrated. A diagrammatic cut away side view of a well 230
includes a
wellbore 232, having a casing 234 cemented therein. Casing 234 contains a
plurality
of production perforations 236 and plurality of injection perforations 238. A
tubing
hanger 240 is secured to casing 234 at the surface of wellbore 232. Tubing
hanger
240 is releasably connected to tubing string 242, thereby securing tubing
string 242
in place within casing 234. Casing 234 and tubing string 242 together form
annulus
244. A packer 250 circumferentiallysurrounds tubing string 242 thereby
partitioning
annulus 244 into upper annulus 246 and lower annulus 248. Packer 250 is an
expanding plug used to seal off 244 annulus between tubing string 242 and
casing
234. On-off tool 251 allows tubing string 242 to be repeatedly removed from
and
inserted into packer 250 without having to reset packer 250 each time. A
standard
surface pumping jack 290 is installed at the surface of wellbore 232. A steel
cable
or bridle 292 extends from horsehead 294 of pumping jack 290. Bridle 292 is
CA 02281083 1999-08-17
-21 -
coupled to a polished rod 302 by a standard carrier bar 296. At a position
further
down-hole, polished rod 302 is coupled with sucker rod 298.
A stuffing box 304 is provided at the top of tubing string 242 in order to
seal
the interior of tubing string 242 and prevent foreign matter from entering.
Stuffing
box 304 is essentially a packing gland or chamber to hold packing material
(not
shown) compressed around a moving pump rod or polished rod 302 to prevent the
escape of gas or liquid.
A sucker rod pump 252 is secured at one end to sucker rod 298. Sucker rod
pump 252 may be of the conventional type requiring only that the lower ball
and seat
valve be removed prior to operation of the pump. Sucker rod pump 252 includes
a
barrel 260 which is secured to, thereby becoming an integral part of, tubing
string
242 with threaded collars 262. Sucker rod pump 252 also includes a movable
piston
264. Barrel 260 remains stationary and connected to tubing string 242 during
operation of sucker rod pump 252. When pumping jack 290 is activated, movable
piston 264 is forced upward and downward through barrel 260 creating a partial
vacuum within barrel 260 and tubing string 242. A traveling valve 266 is
provided at
the down-hole end of movable piston 264. Traveling valve 266 is configured to
allow
flow of fluid through traveling valve 266 in an uphole direction only. Fluid
is
prevented from traveling through traveling valve 266 in a down-hole direction.
A first side intake valve 254 is installed within tubing string 242 at a
location
down-hole from sucker rod pump 252. Side intake valve 254 includes inlet port
255
and check valve 257. Inlet port 255 allows fluid within annulus 244 to enter
tubing
CA 02281083 1999-08-17
-22-
string 242. Check valve 257 permits the flow of fluid from annulus 248 into
tubing
string 242 but prevents flow in the opposite direction.
A second side intake valve 354 is installed within tubing string 242 at a
location down-hole form side intake valve 254. Side intake valve 354 includes
inlet
port 355 and check valve 357. Inlet port 355 allows fluid within annulus 244
to enter
tubing string 242. Check valve 357 permits the flow of fluid from annulus 248
into
tubing string 242 but prevents flow in the opposite direction.
An injection valve 256 is attached to tubing string 242 at a point down-hole
from side intake valve 354. Injection valve 256 isolates the interior of
tubing string
242 from lower annulus 248. Check valve 256 is configured to allow flow from
the
interior of tubing string 242 into lower annulus 248, but will prevent flow
from lower
annulus 248 into the interior of tubing string 242. Check valve 256 prevents
backflow
of water from injection zone 249 surrounding lower annulus 248 during the
lifting
cycle.
At an elevation above tubing hanger 240, production piping 306 extends from
tubing string 242. Production piping 306 allows communication of fluid from
tubing
string 242 to the ultimate surface collection point (not expressly shown). A
bypass
loop 308 extends from production piping 306. A check valve 310 is provided
within
bypass loop 308 and governs the direction of flow of fluids through bypass
loop 308.
An automatic control valve 312 is installed within production piping 306
allowing
fluids within production piping 306 to bypass check valve 310 and bypass loop
308
when control valve 312 is in the "open" position.
CA 02281083 1999-08-17
-23-
An adjustable back pressure regulator 314 regulates the pressure within
production piping 306 and an accumulator 316 is attached to production piping
306
between bypass loop 308 and back pressure regulator 314. Accumulator 316
maintains sufficient injection pressure to prevent traveling valve 266 from
opening
when automatic control valve 312 is in the "open" position.
During the operation of well 230, an oil and water fluid mixture will enter
upper
annulus 246 through production perforations 236. The oil and water mixture
will fill
upper annulus 246 to a level indicated by reference numeral 258. Since water
is
heavier than oil, the oil and water mixture will tend to separate within the
annulus,
such that the oil settles near the top and the water is forced down-hole
toward packer
250. The fluid between fluid level 258 and fluid level 259 will comprise
primarily oil.
Further down-hole, an oil water mixture may be present between fluid level 259
and
fluid level 261. The fluid between fluid level 261 and packer 250 will
comprise
primarily water.
Side intake valve 254 is preferably secured into a position between fluid
level
258 and 259. Side intake valve 354 is preferably secured into a position
between
fluid level 261 and packer 250.
Pumping jack 290 forces movable piston 264 up and down within barrel 260.
When piston 264 moves upward toward the surface of wellbore 232 traveling
valve
266 prevents fluid located above piston 264 from moving to a down-hole
location.
This creates a partial vacuum effect down-hole from piston 264, thereby
forcing fluid
within upper annulus 246 through side intake valves 254 and 354 and into the
interior
of tubing string 242. When piston 264 is forced downward through barrel 260,
CA 02281083 1999-08-17
-24-
traveling valve 266 will open allowing fluid within tubing string 242 to
travel uphole
from piston 264 where it will become trapped by traveling valve 266. By
continuing
this operation, all of the fluid within upper annulus 246 can be produced to
the
surface of well 230 and into production piping 306.
The equipment configuration illustrated within FIGURE 5 provides an
apparatus and a method whereby water is disposed of below the surface prior to
pumping and an oil and water mixture containing a much higher proportion of
oil to
water is produced to the surface. Ideally, there will be no water within the
fluid
produced to the surface.
Casing 234 and annulus 244 provide a large conduit for the separation of oil
and water. During rapid pumping operations, or those in which the separation
of oil
and water occurs at a slower rate due to low temperatures or other variables,
a larger
volume will be required to accommodate a more rapid and efficient separation
of oil
and water.
Providing two side intake valves as illustrated in FIGURE 5 accommodates
the separation of oil and water within annulus 244 between casing 234 and
tubing
string 242, and further provides for the separation of oil and water within
tubing string
242. The other components indicated within FIGURE 5 function in a manner
similar
to those of FIGURE 1.
An alternative embodiment of the downhole equipment configuration of
FIGURE 1 is illustrated in FIGURE 6. This configuration allows the production
perforations 436 to be located downhole from the injection perforations 438.
This is
accomplished by installing a bottom packer 450 at a location within casing 434
CA 02281083 1999-08-17
-25-
between production perforations 436 and injection perforations 438. A second
packer 451 is installed within casing 434 at an elevation above injection
perforations
438. Packer 450 is configured to accept an elongate bypass tube 443
therethrough.
Packer 451 is configured to accept bypass tube 443 and tubing string 442
therethrough. A sucker rod pump 452 may be installed within tubing string 442.
A
side intake valve 454 and/or an injection valve 456 may also be installed
within
tubing string 442. Sucker rod pump 452, side intake valve 454, and injection
valve
456 may function similarly to those described within the embodiment
illustrated within
FIGURE 1.
The teachings of the present invention allow an oil well operator to reduce
costs and power requirements involved with water production, handling,
separation
and disposal. By separating oil and water at a down-hole location and
injecting
water into the formation oil production is increased while potential
investment costs
and water handling costs are decreased. As much as 80% or more of water
produced from a well can be injected rather than handled at the surface. With
potential water handling costs of $0.10 to $0.50 per barrel and trucking costs
ranging
from $0.35 bbl to $1.50 bbl, these costs are significant.
Although the present invention has been described by several embodiments,
various changes and modifications may be suggested to one skilled in the art.
It is
intended that the present invention encompasses such changes and modifications
as fall within the scope of the present appended claims.
What is Claimed is:
