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BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to apparatus and method for increasing the
efficiency of pumping liquids from wells which are substantially deviated
from the vertical direction. More particularly, the apparatus is attached
to the lower end of a tubing in a well or to the casing, contains a
submersible electrical or other type pump and provides a method for
separating gas and liquid before the liquid reaches the pump.
2. Discussion of Related Art
The production of oil and other liquids from the earth through wells often
requires the use of pumps in the wells to force the liquids to the surface
of the earth. There are many designs of subsurface pumps, all of which are
powered by either mechanical, hydraulic or electrical means.
The efficiency of pumps for pumping liquid from wells is often decreased by
the presence of gas simultaneously produced with the liquid, especially
when large amounts of gas are present. Various designs of apparatus have
been used to attempt to separate the gas from the liquid to be pumped from
a well. Preferably, the gas is produced to the surface through a separate
conduit which bypasses the pump. In rod-pumped wells, for example, it is
common practice to pump the well through the tubing in the well and leave
the annulus between the tubing and casing open so that gas can flow up the
annulus.
In wells pumped by electrical power, it is particularly important to
decrease the amount of gas entering the centrifugal pumps utilized.
Excessive amounts of gas may cause extra wear of the pumps, decrease the
efficiency of pumping and, above a certain ratio of gas to liquid, cause
the pump to "gas lock," or stop pumping. At this point the motor must be
shut down quickly to avoid overheating, since cooling of the motor is
primarily by flow of liquid past the housing of the motor. Automatic
shutdown in the event of gas locking is commonly provided with the
submersible electric pumps used in wells. After a pre-selected time, the
pumps restart automatically. The cycling off and on from automatic
shutdowns decreases the amount of fluid that can be pumped and causes loss
of production from the well.
Several types of apparatus are used with electrical submersible pumps to
decrease the amount of gas entering the pump. The types can be generally
classified as static and rotating. The static devices include: (1) a
shroud over the pump, which is placed below perforations in a well and (2)
a "reverse-flow" gas separator, which causes the flow to reverse direction
above the perforations in the wellbore, separating some of the free gas
from the liquid. These devices are helpful, particularly at lower flow
rates. The rotating devices are called "rotary gas separators,"
"centrifugal liquid-gas separators," or "centrifugal gas separators." The
article "Development and Field Test Results of an Efficient Downhole
Centrifugal Gas Separator," by L. S. Kobylinski et al, J. of Pet. Tech.,
July, 1985, pp. 1295- 1304, provides a review of the operation on these
type devices in vertical wells and wells deviated from vertical up to 56
degrees. Deviated wellbores had no effect on the performance of the
centrifugal gas separators in these wells.
Centrifugal separators for submersible pumps are described in U.S. Pat.
Nos. 3,624,822 and 4,481,020. They operate by causing the liquid-gas
mixture to flow in spiral motion, thereby causing the liquid to separate
from the gas. The liquid is then removed from near the wall of the device
and sent to the inlet of the pump. The gas is removed from the center of
the spiral and discharged through a port to the outside of the separator.
An article K. Way, Kevin Welte and N. Kapsch, presented at the 1990
Electric Submersible Pump Workshop sponsored by Society of Petroleum
Engineers, Gulf Coast Section, April 30-May 2, Houston, Tex, describes
modifications to the electric submersible pump system that have extended
application of the system to wells where very high levels of free gas
exist at pump intake conditions. Use of multiple rotary gas separators
ahead of a pump is one modification that has been successful in some
cases.
In recent years, there has been a great increase in the number of wells
drilled for oil production which are deviated from vertical by more than
75 degrees over a portion of the wellbore, and it is not uncommon for
wells to be drilled in a direction near 90 degrees from vertical for
hundreds of feet. For purposes of the present invention, we define any
well drilled for a substantial distance, say approximately 150 feet, at an
angle from vertical of more than about 75 degrees as a horizontal well.
These wells are drilled to achieve greater rates of oil production, to
decrease the amount of unwanted gas or water production, and for other
purposes well known in industry. The wells are typically drilled in a
vertical direction to a certain depth and then "kicked off" from vertical
in the desired vertical and azimuth directions. The curved portion of the
well is called the dogleg or build angle portion. The radius of the curved
portion typically varies from as small as 30 feet to as much as 3000 feet.
The process of pumping fluids from horizontal wells presents difficult
problems unless the pressures in the well are great enough to achieve
desired production rates with the pump set in the vertical section of the
well. Even then, pumping is difficult when large volumes of gas are
produced with the liquids. Electrical submersible pumps, which are
particularly suited for pumping at high rates and often are needed since
the wells are capable of producing at high rates, present a particularly
difficult problem because the standard pumps will not pass through a
portion of the well where the radius is less than about 500 to 800 feet
without possible damage to the pump. In larger radius wells, electrical
submersible pumps have been operated in the horizontal portion or other
straight portions of deviated wells when they can be placed at the desired
location without damaging the pump. The article "Electrical Submersible
Pumps in Horizontal Wells," by A. Gallup et al, Oil & Gas J., Jun. 18,
1990, provides a survey of the subject of producing horizontal wells with
electrical submersible pumps. Special steps such as drilling a larger
hole, drilling a straight section between the vertical and horizontal
portions (called the "tangent section") and drilling the horizontal
section with a continuous downhill inclination are recommended for
increasing the effectiveness of electrical pumps in horizontal wells.
It has been found that another particularly troublesome problem in pumping
horizontal wells is that gas is often produced from the horizontal portion
of the well in slugs. The problem can be severe in wells where long
intervals are at near 90 degrees from vertical or where local high
intervals are created during the drilling of the well. A slug of gas can
enter the pump, even when the pump is equipped with a rotary gas
separator, and the gas will often cause the pump to become gas-locked.
This phenomenon can occur when the well is producing at a gas-to-liquid
ratio that, on average, would not cause frequent pump shutdowns in a
vertical well. Gas-locking of the pump will cause loss of production by
causing the pump to cycle off and on. It is not possible to size or
otherwise design the pump and rotary gas separator adequately for slugging
conditions.
Electrical submersible pumps can be operated with a "stinger" or "tailpipe"
attached to the inlet of the pump. The tailpipe allows fluid intake at a
distance below the pump. An example of such well equipment is described in
the article "An Overview of Horizontal Well Completion Technology," by R.
E. Cooper et al, SPE Paper No. 17582, presented in November, 1988. Tail
pipes are often attached below packers in a well. An electrical
submersible pump can be connected to the tail pipe at the packer.
There is a severe limitation to methods which require placement of packers
in deviated wells. Even if the packer is designed to be movable or
retrievable, there is always the risk that the packer will become stuck
and require very expensive retrieval operations or loss of the well. Also,
the depth of the pumping equipment in the well cannot normally be changed
without the extra expense of retrieving the packer.
All systems proposed in the past for pumping horizontal wells which produce
gas along with the liquid add significantly to the cost of the well or the
cost of operating the well. There is a great need for a system for pumping
a horizontal well without the addition of expensive drilling or completion
steps, which allows simple variations of pumping intake location as
conditions in the well change, and which alleviates or eliminates the
slugging flow problem that is detrimental to the pumping process.
SUMMARY OF THE INVENTION
A system is provided that is low risk for pumping a horizontal well with an
electrical submersible or other type of pump that is located remote to the
distal end of the horizontal well. A length of tubing (dip tube),
preferably closed at the distal end and containing fluid entry ports, is
placed in the deviated portion of the well. A shear joint may be placed at
the top of the dip tube. A swage is used to attach the shear joint or dip
tube to a shroud or a length of liner which contains the pump. In one
embodiment of the invention, the shroud is supported in the well by tubing
extending to the surface and the shroud contains an electrical submersible
pump. Gas-liquid separation occurs in the annulus outside the dip tube and
at the entrance to the perforations in the dip tube. In another
embodiment, the shroud contains a vent hole or holes near the top of the
shroud, the shroud being supported in the well by tubing, and a seal is
present between the vent holes and the intake port of a rotary gas
separator attached to the pump. In a third embodiment the shroud is open
at the top and is supported by the casing through use of a liner hanger.
In all embodiments in which the shroud is supported by tubing, a
shroud-hanger having sufficient strength to support the shroud and the dip
tube is attached at the bottom of the tubing to be placed in the well. In
all embodiments, the dip tube is generally run into the horizontal well to
a position as close to the distal end as practical, which allows fluid
entry to the pump from near the end of the well and eliminates or
substantially decreases the slugs of gas which cause problems in pumping
the well. The pump may be placed in the vertical, tangent, or horizontal
section of the well, but preferably is placed in a section of the hole
having a dogleg severity of less than 1 degree per 100 feet to avoid
flexure of the pump shaft during operation.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a longitudinal sectional view illustrating the gas-liquid
separator apparatus in accordance with a first embodiment of the invention
in which a shroud having a vent and containing a gas separator and pump is
supported in the well by tubing.
FIG. 2 is a longitudinal sectional view illustrating the gas-liquid
separator apparatus in accordance with a second embodiment of the
invention in which a shroud containing a pump is supported in the well by
tubing.
FIG. 3 is a longitudinal sectional view illustrating the gas-liquid
separator apparatus in accordance with a third embodiment of the invention
in which the shroud is supported in the well by casing.
DESCRIPTION OF PREFERRED EMBODIMENTS
Liquid-gas separator apparatus and methods described herein are
particularly suited for use with submersible electrical pumps in
oil-producing wells. They will be described in that application, but it
will become apparent that the principles of the invention are also
applicable to other means of pumping liquid from a horizontal well, such
as hydraulic pumps or rod-driven pumps.
FIG. 1 illustrates a preferred form of the liquid-gas separator apparatus
10 in accordance with a first embodiment of the invention. The apparatus
is supported in the well by the tubing string 12, and is attached to form
a hydraulic seal to the bottom joint of the tubing string 12 on the
surface before placing the tubing in the well. The upper end of tubing
string 12 extends to the surface of the well where it is supported by the
wellhead using well known techniques. The apparatus 10 includes a pump 14,
this being normally an electrical submersible pump being powered through
an electrical cable 15, the pump 14 being attached to a shroud 16 at the
top of the shroud. The shroud 16 comprises a length of tubular material
having an inside diameter large enough to accommodate a pump and an
outside diameter small enough to pass through the casing 31. A conduit for
gas 24 connects the internal volume of the shroud 16 to the annulus
outside the tubing 12 or to the surface. Connected to the pump 14 and
powered by the same motor 17 is a centrifugal liquid-gas separator 28,
having an inlet port 29. Liquid discharge from the gas-liquid separator 28
passes internally to the pump 14 while gas is preferentially discharged
through the port 30 into the shroud and then through the conduit 24 to the
annulus or to the surface.
The shroud 16 is attached to a shroud hanger 18, preferably by a flange 19,
but threads or other means of attachment to obtain a hydraulic seal and
mechanical strength are suitable. The shroud hanger 18 is preferably
threaded directly on to the tubing 12, but may be welded or otherwise
attached to the tubing. The shroud hanger must be designed to support the
weight of the shroud 16, the pump 14, the motor 17, the dip tube 22 and
other parts of the apparatus. The pump is preferably connected to the
shroud hanger by a threaded connection, but other means of connection may
be used. A swage 20 at the bottom of the shroud allows joining the shroud
to the dip tube 22, the joining means between the shroud and swage 20
preferably being by threads or welding. A shear sub 13 is preferably
placed between the swage 20 and the dip tube 22. The shear sub is a
coupling hydraulically sealed by elastomer and containing a pin which can
be sheared for recovery of the apparatus above if the dip tube 22 becomes
stuck in the well. The dip tube 22 is preferably closed on the distal end
not attached to the swage and preferably contains holes 25 disposed from a
position near the closed end and extending a selected distance along the
tube, the holes being for the entry of fluid into the dip tube. The dip
tube may be formed from tubular materials identical to those used for the
tubing 12 or different diameters and wall thicknesses may be selected for
particular applications. The couplings of the material in the dip tube are
preferably flush with the outside diameter of the tube. The diameter and
wall thickness of the dip tube are selected such that the tube will bend
to allow lowering the tube through existing bends in the casing and to the
desired horizontal distance along the wellbore.
The optimum diameter of the dip tube is large enough to obtain an
acceptable pressure drop and resulting release of gas from solution inside
the dip tube 22 at the rates based on the pumping capacity of the pump 14
and not so large as to inhibit liquid-gas separation and flow of gas along
the annulus outside the dip tube 22. The sizing will be selected for each
well based on operating characteristics of the well, the rotary gas
separator and the pump. Pressure sensors 60a and 60b may be placed inside
the shroud or in the annulus outside the shroud to aid in sizing the dip
tube 22, the conduit 24 and the characteristics of the rotary gas
separator and pump employed. Pressure gages adapted for downhole use are
well known in industry. They may be electrically operated, either
self-contained and battery driven or driven through a conductor cable
extending to the surface of the earth, or they may consist of a small
gas-filled tube extending to surface and connected to a conventional
pressure gage on the surface of the earth. Since there is no packer in the
well, the tubing and gas-liquid separator apparatus can be lowered and
raised in the well to optimize pumping conditions as the conditions in the
well change.
The casing 31 has a lower end 32. Below the casing 31 the section 80 may be
open hole or a liner may be used. A liner may be slotted, drilled or
perforated to allow fluid entry to the well, in accord with well known
techniques in industry. The end of the well 81 is referred to herein as
the distal end.
In the annulus outside the dip tube 22 and as fluid enters the fluid entry
ports 25 in the dip tube 22, gas tends to break out of the liquid and flow
up the annulus outside the dip tube, past the shroud and through the
vertical section of the wellbore to the surface. Liquid and gas flow
through the dip tube and into the inlet port 29 of the rotary gas
separator 28 attached to the pump. Primarily liquid flows through the pump
14 and through the tubing 12 to surface. Any gas separated from the liquid
in the liquid-gas separator 28 is discharged through the outlet port of
the rotary gas separator 30 and thence to the tubing-casing annulus or to
the surface through the conduit 24. The conduit 24 may be perforations
through the wall of the shroud or may be a length of smaller diameter
tubing which extends from partially to surface to entirely to the surface
of the earth. The optimum length will be selected based on characteristics
of the rotary gas separator and calculated or measured pressures inside
and outside the shroud.
The hydraulic seal 26 is not required in all applications. The rotary gas
separator 28 provides an increase in fluid pressure. Hydraulic conditions
between the inlet port 29 and the discharge port 30 and between the
discharge port 30 and surface may be such that separation of inlet and
discharge streams does not require a seal.
In a second embodiment of this invention, shown in FIG. 2 at 40, the
rotary-gas separator is not used and gas-liquid separation occurs in the
annulus outside the dip tube 22 and at the entrance to the fluid entry
ports 25. The tubing 12 supports the shroud 16 through the shroud hanger
18 and flange 19. The pump 14, having an inlet port 29A, is normally an
electric submersible pump, but may be powered hydraulically or
mechanically by rods. If it is electrical, a cable 15 brings power to an
electric motor 17. A swage 20 is connected to the shroud 16 and to the
shear sub 13. The dip tube 22 is connected to the shear sub 13. Liquid and
a small amount of gas flow through the dip tube 22, the pump 14, and the
tubing 12 to surface. Gas separated in the annulus outside the dip tube 22
flows around the shroud 16 and to surface. The gas flowing up the dip tube
22, either as free gas or gas that comes out of solution in the oil
because of pressure drop in the dip tube, is not so great as to
substantially decrease the efficiency of the pump 14. The gas slugging
into the pump is practically eliminated by the dip tube 22 being located
near the distal end of the wellbore. The dip tube 22 may also be located
in the well such that ports for fluid entry 25 are located in a lower part
of the horizontal wellbore, such that the wellbore efficiency for
gas-liquid separation is increased. Well surveying techniques for
determining the location of such lower parts of the wellbore are well
known in industry. The apparatus can be raised or lowered in the well to
optimize performance by operations not requiring retrieval of a packer or
movement of a packer in the well.
Other numerals used in FIG. 2 have the same meaning as in FIG. 1.
In a third embodiment of this invention, shown in FIG. 3 at 50, the shroud
is supported by the casing 31 having a lower end 32. Below the end of the
casing 32 the segment 80 is an open hole or a liner of conventional
design. The shroud 16 is open at the top and is connected to a liner
hanger 51. The liner hanger 51 is used to transfer the weight of the
shroud -6 and the dip tube 22 to the casing 31. The liner hanger 51 is
preferably retrievable, in that it can be "set" to transfer the weight of
the shroud 16 to the casing 31, and it can later be released, or unset, to
transfer the weight of the shroud back to a pipe string used for
retrieving the shroud from the well. The liner hanger 51 contains a vent
27 which allows gas or liquid to enter the annulus between the tubing 12
and the casing 31 and to flow to surface. Alternatively, or in
combination, the shroud 16 has holes (not shown) near the top which allows
gas to enter the annulus outside the tubing 12. Near the bottom of the
shroud 16 the pump 14 and a centrifugal liquid-gas separator 28 are
placed, supported by tubing 12 and powered through cable 15 to an
electrical motor 17. The centrifugal liquid-gas separator has inlet port
29 and gas discharge port 30. The dip tube 22 has inlet ports 25 which are
placed in the wellbore at a location to optimize gas-liquid separation in
the annulus outside the dip tube. Generally, the inlet ports 25 will be
placed near the distal end of the wellbore 81, but the inlet ports may be
placed in a local low interval in the open hole or liner 80. The shroud 16
and dip tube 22 are sized such that excessive pressure drop does not occur
in the dip tube to cause more solution gas evolution as oil flows through
the tube 22 than can be handled by the centrifugal liquid-gas separator 28
and the pump 14. Pressure gages 60a and 60b adapted for downhole use and
well known in industry may be placed inside the shroud and in the annulus
outside the shroud or tubing to determine optimum design and location of
the shroud 16 and dip tube 22 for the pump to be employed in the well. The
top of the shroud 51 is placed high enough in the well to insure that flow
in the shroud will be from bottom to top and past the electrical motor 17,
such that the motor is adequately cooled.
In all embodiments described, tubing and other equipment is placed in wells
using rigs and rig equipment which are well known in industry.
While preferred embodiments and application of this invention has been
shown and described, it will be apparent to those skilled in the art that
many more modifications and variations are possible without departing from
the inventive concepts herein described. The invention is, therefore, not
to be restricted except as is made necessary by the prior art and the
appended claims.
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