U.S. patent application number 10/664784 was filed with the patent office on 2004-04-01 for method and apparatus for increasing fluid recovery from a subterranean formation.
Invention is credited to Kelley, Terry Earl.
Application Number | 20040060705 10/664784 |
Document ID | / |
Family ID | 26708139 |
Filed Date | 2004-04-01 |
United States Patent
Application |
20040060705 |
Kind Code |
A1 |
Kelley, Terry Earl |
April 1, 2004 |
Method and apparatus for increasing fluid recovery from a
subterranean formation
Abstract
A downhole injector (10), (26), (38) and (54) is provided at the
lower end of the production tubing string (TS) for passing liquids
from a downhole hydrocarbon formation (F) into the tubing string
while preventing gases from passing through the injector. The
present invention uses the injector with an optimum wellbore
annulus (A) back pressure using a regulator (64) and a pressure
gauge (62) to enhance total gaseous and liquid hydrocarbon
recovery. In wells requiring artificial lift, a downhole pump (P)
may be used to efficiently pump formation fluids to the surface or
alternatively one or more gas lift valves (LV) for raising slugs of
liquid to the surface. The present invention may also be used with
multi horizontal borehole technology for increasing hydrocarbon
recovery by retaining gases in the formation to act upon liquid
hydrocarbons by maintaining an over head pressure for driving the
liquids from the formation through the injector for maximum
ultimate recovery and hydrocarbon reserve value.
Inventors: |
Kelley, Terry Earl;
(Berkeley, CA) |
Correspondence
Address: |
Mr. Terry Earl Kelley
2738 MLK JR Way
Berkeley
CA
94703
US
|
Family ID: |
26708139 |
Appl. No.: |
10/664784 |
Filed: |
September 17, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10664784 |
Sep 17, 2003 |
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10001383 |
Oct 23, 2001 |
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6622791 |
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10001383 |
Oct 23, 2001 |
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09590152 |
Jun 8, 2000 |
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6237691 |
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09590152 |
Jun 8, 2000 |
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09589854 |
Jun 8, 2000 |
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6325152 |
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09589854 |
Jun 8, 2000 |
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08978702 |
Nov 26, 1997 |
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6089322 |
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60032218 |
Dec 2, 1996 |
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Current U.S.
Class: |
166/372 ;
166/105 |
Current CPC
Class: |
E21B 43/38 20130101;
E21B 43/121 20130101 |
Class at
Publication: |
166/372 ;
166/105 |
International
Class: |
E21B 043/00 |
Claims
What is claimed is:
1. A system for producing and recovering liquids at the surface of
a well in fluid communication with a downhole gaseous and liquid
hydrocarbon formation, the liquids being produced and recovered
through a production tubing string within a wellbore, the system
comprising: the wellbore being perforated for fluid communication
with the downhole hydrocarbon formation both above and bellow a
gas-fluid interface separating hydrocarbon fluids from a gas cap
above the fluids; a surface gas flow pressure regulator and a
surface pressure gauge on the casing well head annulus exit port
for respectively controlling gas flow and pressure and measuring
pressure while maintaining a predetermined flow pressure on the
wellbore annulus; a downhole injector for passing formation fluids
by pressure differential through the injector and into the
production tubing string while preventing gases from passing
through the injector; a downhole pump positioned within the
production tubing string above the injector for pumping liquids to
the surface; the downhole pump for efficiently pumping liquid
inflow through the production tubing string to the surface of the
well; and the wellbore with maintained direct fluid communication
between the well and a formation gas zone and between the well and
a formation hydrocarbon liquid zone beneath the gas zone, such that
such gas pressure acts as a cap on the formation liquids to force
the liquids out of the formation and through the injector toward
the surface.
2. The system as defined in claim 1, further comprising: the
downhole injector being positioned relative to the downhole opened
hydrocarbon formation so that all incoming liquid hydrocarbons are
efficiently and completely removed from the wellbore into the lower
pressure production tubing string on to the surface for increased
gaseous and liquid hydrocarbon recovery.
3. The system as defined in claim 1, further comprising: wherein
the well has a surface gas flow meter for continually and
comparatively measuring and monitoring the formation gas flow
production, pressure and recovery for the most effective optimum
gas flow pressure at the surface and periodically making and
observing fluid level and gas-oil ratio test, while continually and
comparatively measuring and monitoring the production and recovery
of formation liquids through a surface metering facility for a
combined total maximum gaseous and liquid hydrocarbon production
and ultimate recovery, throughout the reservoir's formations total
gaseous and liquid hydrocarbon recovery life for maximum
hydrocarbon reserve value.
4. The system as defined in claim 1, further comprising: the
surface gas flow pressure regulator and the surface pressure gauge
for continually and controllably and comparatively regulating
flowing formation gas production and pressure at a controlled flow
pressure to retain a predetermined optimum formation gas pressure
in an annulus about the production tubing string, and thereby on
and within the downhole opened hydrocarbon formation, such that the
gas pressure prevents solution gas within the liquid hydrocarbon in
its formation and the wellbore from breaking out of solution,
whereby maintaining its expulsive force, high mobility and low
viscosity, and acts as a driving force to pass pressured higher
pressure hydrostatic head liquids out of the formation and through
the injector by pressure differential up into the lower pressure
production tubing string to recover formation liquids at the
surface, wherein total in place liquid hydrocarbons are maintained
highly fluid and recoverable, thereby increasing related liquid
hydrocarbon reserve value.
5. The system as defined in claim 1, further comprising: the
wellbore annulus with a maintained predetermined formation gas
pressure such that gas pressure acts as a driving force on all
liquids to pass them through the injector by pressure differential
up into the lower pressure production tubing string for formation
fluid recovery at the surface, so that a liquid level is maintained
in the wellbore at the injector liquid in take level for maximum
free gas and pressurized fluid flow from all opened hydrocarbon
formations for maximum gaseous and liquid hydrocarbon recovery,
whereby total gaseous and liquid hydrocarbon reserve recoverability
and related value is increased.
6. The system as defined in claim 1, further comprising: the
wellbore with maintained gas pressure in the annulus above the
downhole injector intake liquid level as a driving force to
maintain a predetermined liquid level in the lower pressure
production tubing string for maximum artificial lift efficiency of
incoming liquids on to the surface.
7. The system as defined in claim 1, further comprising: one or
more gas lift valves as an alternative means for lifting liquids
positioned along the production tubing string above the downhole
injector for selectively, at a predetermined pressure, passing
annulus gases through the production tubing string to raise
incoming liquids in cycles as slugs of liquid to the surface
through the production tubing string.
8. The system as defined in claim 1, further comprising: the
wellbore opened with one or more horizontal and alternatively
highly angled boreholes in a gas zone for maximum zone exposure and
increased gas flow and recovery.
9. The system as defined in claim 1, further comprising: the
wellbore opened with one or more horizontal and alternatively
highly angled boreholes in a liquid hydrocarbon zone for maximum
zone exposure and increased liquid hydrocarbon flow and
recovery.
10. The system as defined in claim 1, further comprising: a check
valve in the tubing string above the top of the injector; and the
injector including an injector housing having a nominal outer
diameter, a fluid responsive float open at the top and closed at
the bottom and moveable with respect to the injector housing as a
function of fluid density surrounding the float, and a shut off
valve member moveably responsive to the float for engagement with a
shut off valve seat, the shut off valve member being spaced
vertically below inside the injector housing from the check
valve.
11. The system as defined in claim 1, wherein the injector includes
a sleeveshaped filter screen for restricting at least 90% of solid
particles of 30 microns or greater from passing through the filter
screen.
12. The system as defined in claim 1, further comprising: the well
head surface gas flow pressure regulator for closing off the
release of gas flow and pressure from the opened gas formation of
an opened hydrocarbon reservoir with a considerably high percentage
of liquid hydrocarbons, in an annulus of the vertical wellbore and
connecting horizontal and deviated wellbore annuluses, and the
surface pressure gauge for measuring the surface wellbore annulus
pressure, while simultaneously producing and recovering and
monitoring at the surface production tubing string discharge all
incoming liquid hydrocarbons entering the wellbore, so that
previously incoming formation gas above the incoming liquids in the
wellbore is maintained in the open gas zone, whereby conserving in
place gas volume and pressure by the incoming liquid's greater
hydrostatic head pressure which drives it through the downhole
injector by pressure differential and into the lower pressure
production tubing string on toward the surface for maximum liquid
hydrocarbon production and ultimate recovery from a hydrocarbon
formation.
13. The system as defined in claim 12, further comprising: the
surface gas flow pressure regulator for closing off the wellbore
annulus at the well head exit port such that all gases which are
prevented from flowing and from entering the production tubing
string by the injector are retained downhole within the opened
upper gas zone for storing gases there for future production by the
incoming higher pressure formation liquids in transit through the
wellbore into the injector to be produced and recovered through the
lower pressure production tubing string on to the surface, whereby
maintained formation gas pressure assist by overhead pressure for
the maximum production and ultimate recovery of hydrocarbon
formation fluids from the opened lower liquid hydrocarbon
formation, wherein total in place gaseous and liquid hydrocarbon
reserve recoverability and related value is notably increased.
14. The system as defined in claim 13, further comprising: the
surface gas flow pressure regulator for closing off the wellbore
annulus at the well head exit port throughout the complete
production and total recovery of all in place liquid hydrocarbons
until said production and recovery considerably declines, at such
time converting over to total gas production by releasing the
surface gas flow pressure to a full opened gas flow pressure at the
surface gas flow regulator to efficiently produce and recover
natural gas, whereby total in place liquid hydrocarbons have been
recovered, leaving only the small quantities that stick to the
formation rock pores as a thin film, and that are isolated in any
formation structural traps, wherein in place gas is free to flow to
the surface for total in place natural gas production and ultimate
recovery, thereby recovering total in place liquid and gaseous
hydrocarbons maintained and converted by this recovery process to
be ultimately recoverable.
15. The system as defined in claim 1, further comprising: the
surface gas flow pressure regulator for completely closing a
wellbore annulus at the well head exit port in a well that has no
surface gas sales line such as to prevent surface gas flaring, so
that all gases which are prevented from flowing and from entering
the production tubing string by the injector are retained downhole
within the opened upper gas zone by incoming higher pressure
liquids in transit through the wellbore for storing gases there for
future production, such that the upper gas zone is assisted by
maintained overhead pressure for the production and recovery of all
incoming liquid hydrocarbons which enter the wellbore by their
greater hydrostatic head pressure driving them through the downhole
injector by pressure differential on up into the lower pressure
production tubing string toward the surface for maximum production
and ultimate recovery of hydrocarbon fluids from the opened liquid
hydrocarbon formation, whereby early total in place liquid
hydrocarbon recovery is economically realized at low cost, wherein
total in place gaseous and liquid hydrocarbon reserve value is
significantly increased by becoming recoverable.
16. The system as defined in claim 15, further comprising: the
surface gas flow pressure regulator for controlling the wellbore
annulus gas flow pressure at the wellhead exit port to produce and
recover natural gas in a well that has installed a gas sales line
during the complete production and total recovery of all in place
liquid hydrocarbons, recovering said liquids by a predetermined gas
flow pressure, such that gas is retained in solution within the
recovering liquid hydrocarbons, so that said liquids are always
maintained recoverable, until liquid hydrocarbon production and
recovery considerably decline, at such time converting over to
total gas production by releasing the surface gas flow pressure to
a fully opened gas flow pressure at the surface gas flow regulator
to efficiently produce and recover natural gas, whereby total in
place liquid hydrocarbons have been recovered, leaving only the
small quantities that stick to the formation rock pores as a thin
film, and that are isolated in any formation structural traps,
wherein in place gas is free to flow to the surface for total in
place natural gas production and ultimately recovery, thereby
recovering total in place liquid and gaseous hydrocarbons
maintained and converted by this recovery process to be ultimately
recoverable.
17. The system as defined in claim 1, further comprising: the
surface gas flow pressure regulator for controlling the wellbore
annulus gas flow pressure at the wellhead exit port during the
complete production and total recovery of all in place liquid
hydrocarbons, recovering said liquids by a predetermined gas flow
pressure, such that gas is retained in solution within the
recovering liquid hydrocarbons, so that said liquids are always
maintained recoverable, until liquid hydrocarbon production and
recovery considerably decline, at such time converting over to
total gas production by releasing the surface gas flow pressure to
a fully opened gas flow pressure at the surface gas flow regulator
to efficiently produce and recover natural gas, whereby total in
place liquid hydrocarbons have been recovered, leaving only the
small quantities that stick to the formation rock pores as a thin
film, and that are isolated in any formation structural traps,
wherein in place gas is free to flow to the surface for total in
place natural gas production and ultimate recovery, thereby
recovering total in place liquid and gaseous hydrocarbons
maintained and converted by this recovery process to be ultimately
recoverable.
18. A method of producing and recovering liquids at the surface of
a well in fluid communication with a downhole gaseous and liquid
hydrocarbon formation, the liquids being produced and recovered
through a production tubing string within a wellbore, the method
comprising: providing a surface gas flow pressure regulator and a
surface pressure gauge on the casing well head annulus exit port
for respectively controlling gas flow and pressure and measuring
pressure while maintaining a predetermined flow pressure on the
wellbore annulus; providing perforations in the wellbore for fluid
communication with the downhole hydrocarbon formation both above
and bellow a gas-fluid interface separating fluids from a gas cap
above the fluids; providing a downhole injector for passing
formation fluids by pressure differential through the injector and
into the production tubing string while preventing gases from
passing through the injector; positioning a downhole pump within
the production tubing string above the injector for pumping liquids
to the surface; pumping liquid inflow efficiently through the
production tubing string to the surface of the well; and
maintaining direct fluid communication between the well and a
formation gas zone and between the well and a formation hydrocarbon
liquid zone beneath the gas zone, such that such gas pressure acts
as a cap on the formation liquids to force the liquids out of the
formation and through the injector toward the surface.
19. The method as defined in claim 18, further comprising: wherein
the downhole injector is positioned relative to the downhole opened
hydrocarbon formation in the wellbore so that all incoming liquid
hydrocarbons are efficiently and completely removed from the
wellbore into the lower pressure production tubing string on to the
surface thereby increasing gaseous and liquid hydrocarbon
production and ultimate recovery.
20. The method as defined in claim 18, further comprising:
continually and comparatively measuring and monitoring the
formation gas flow production, pressure and related recovery for
the most effective optimum gas flow pressure at the wells surface
gas flow meter, and periodically making and observing fluid level
and gas oil ratio test, while continually and comparatively
measuring and monitoring production and recovery of formation
liquids through a surface metering facility for a combined total
maximum gaseous and liquid hydrocarbon production and ultimate
recovery, throughout the reservoirs formations total gaseous and
liquid hydrocarbon recovery life for maximum hydrocarbon reserve
value.
21. The method as defined in claim 18, further comprising: while
recovering formation liquids at the surface production tubing
string discharge, simultaneously flowing formation gas production
and pressure at a regulated and controlled gas flow pressure at the
surface gas flow pressure regulator with the surface pressure gauge
to retain a predetermined optimum formation gas pressure in an
annulus about the production tubing string, and thereby on and
within the downhole opened hydrocarbon formation, such that the gas
pressure prevents solution gas within the liquid hydrocarbon in its
formation and the wellbore from breaking out of solution,
maintaining its expulsive force, high mobility and low viscosity,
and acts as a driving force to pass pressured higher pressure
hydrostatic head liquids out of the formation and through the
injector by pressure differential on up into the lower pressure
production tubing string to recover formation liquids at the
surface, wherein total in place liquid hydrocarbons are maintained
highly fluid and recoverable, thereby increasing related liquid
hydrocarbon reserve value.
22. The method as defined in claim 18, further comprising:
maintaining a predetermined optimum formation gas flow pressure in
the wellbore annulus such that gas pressure acts as a driving force
on all liquids to pass them though the injector by pressure
differential up into the lower pressure production tubing string
for formation fluid recovery at the surface so that a liquid level
is maintained in the wellbore at the injector liquid in take level
for maximum free gas and pressurized fluid flow from all opened
hydrocarbon formations for maximum gaseous and liquid hydrocarbon
recovery, whereby total gaseous and liquid hydrocarbon reserve
recoverability and related value is increased.
23. The method as defined in claim 18, further comprising:
maintaining a wellbore gas pressure in the annulus above the
downhole injector intake liquid level as a driving force to
maintain a.predetermined liquid level in the lower pressure
production tubing string for maximum artificial lift efficiency of
incoming liquids on to the surface.
24. The method as defined in claim 18, further comprising:
continually measuring and controllably regulating the release of
gas flow and pressure at the surface gas flow pressure regulator
for the most effective optimum flow pressure in an annulus about
the production tubing string throughout the reservoirs formations
total gaseous and liquid hydrocarbon recovery life for maximum
recoverability of all in place hydrocarbons to increase hydrocarbon
reserve value.
25. The method as defined in claim 18, further comprising:
providing one or more gas lift valves as an alternative means for
lifting liquids positioned along the production tubing string above
the downhole injector for selectively, at a predetermined pressure,
passing annulus gases through the production tubing string to raise
incoming liquids in cycles as slugs of liquid to the surface
through the production tubing string.
26. The method as defined in claim 18, further comprising: opening
a wellbore with one or more horizontal and alternatively highly
angled boreholes in a gas zone for maximum zone exposure and
increased gas flow and recovery.
27. The method as defined in claim 18, further comprising: opening
a wellbore with one or more horizontal and alternatively highly
angled boreholes in a liquid hydrocarbon zone for maximum zone
exposure and increased liquid hydrocarbon flow and recovery.
28. The method as defined in claim 18, further comprising:
positioning a check valve within a production tubing string above
the top of the injector for preventing fluids which pass by the
check valve from returning to the injector; and the injector
housing having a nominal outer diameter, a fluid responsive float
open at the top and closed at the bottom and moveable with respect
to the injector housing as a function of fluid density surrounding
the float, and a shut off valve member moveably responsive to the
float for engagement with a shut off valve seat, the shut off valve
member being spaced vertically below inside the injector housing
from the check valve.
29. The method as defined in claim 18, further comprising:
providing a sleeve-shaped filter screen across an inlet flow port
of the injector for restricting at least 90% of solid particles 30
microns or greater from passing through the filter screen.
30. The method as defined in claim 18, further comprising:
providing the well head surface gas flow pressure regulator for
closing off the release of gas flow and pressure from the opened
gas formation of an opened hydrocarbon reservoir with a
considerably high percentage of liquid hydrocarbons in an annulus
of the vertical wellbore and connecting horizontal and deviated
wellbore annuluses, and the surface pressure gauge for measuring
the surface wellbore annulus pressure, while simultaneously
producing and recovering and monitoring at the surface production
tubing string discharge all incoming liquid hydrocarbons entering
the wellbore, so that previously incoming formation gas in the
wellbore above the incoming liquids is maintained in the opened gas
zone, thereby conserving in place gas volume and pressure by the
incoming liquid's greater hydrostatic head pressure which drives it
through the pressure drop in the downhole injector and through the
lower pressure production tubing string on to the surface for
maximum liquid hydrocarbon production and ultimate recovery from a
hydrocarbon formation.
31. The method as defined in claim 30, further comprising:
providing the surface gas flow pressure regulator for closing off
the wellbore annulus at the well head exit port such that all gases
which are prevented form flowing and from entering the production
tubing string by the injector are retained downhole within the
opened upper gas zone for storing gases there for future production
by the incoming higher pressure formation liquids in transit
through the wellbore into the injector to be produced and recovered
through the lower pressure production tubing string at the surface,
whereby maintained formation gas pressure assist by overhead
pressure for the maximum production and ultimate recovery of
hydrocarbon formation fluids from the opened lower liquid
hydrocarbon formation, wherein total in place gaseous and liquid
hydrocarbon reserve recoverability and related value is notably
increased.
32. The method as defined in claim 31, further comprising:
providing the surface gas flow pressure regulator for closing off
the wellbore annulus at the well head exit port throughout the
complete production and total recovery of all in place liquid
hydrocarbons until said production and recovery considerably
decline, at such time converting over to total gas production by
releasing the surface gas flow pressure to a full opened gas flow
pressure at the surface gas flow regulator to efficiently produce
and recover natural gas, whereby total in place liquid hydrocarbons
have been recovered, leaving only the small quantities that stick
to the formation rock pores as a thin film and that are isolated in
any formation structural traps, wherein total in place gas is free
to flow to the surface for total in place natural gas production
and ultimate recovery, thereby recovering total in place liquid and
gaseous hydrocarbons maintained and converted by this recovery
process to be ultimately recoverable.
33. The method as defined in claim 18, further comprising:
providing the surface gas flow pressure regulator for completely
closing a wellbore annulus at the well head exit port in a well
that has no surface gas sales line, such as to prevent surface gas
flaring, so that all gases which are prevented from flowing and
from entering the production tubing string by the injector are
retained downhole within the opened upper gas zone for storing
gases there for future production by incoming higher pressure
liquids in transit through the wellbore, such that the upper gas
zone assist by overhead pressure for the production and recovery of
all incoming liquid hydrocarbons entering the wellbore by their
greater hydrostatic head pressure driving them through the downhole
injector by pressure differential on up into the lower pressure
production tubing string toward the surface for maximum production
and ultimate recovery of hydrocarbon fluids from the opened liquid
hydrocarbon formation, whereby early total in place liquid
hydrocarbon recovery is economically realized at low cost, wherein
total in place gaseous and liquid hydrocarbon reserve value is
significantly increased by becoming recoverable.
34. The method as defined in claim 33, further comprising:
providing the surface gas flow pressure regulator for controlling
the wellbore annulus gas flow pressure at the wellhead exit port to
produce and recover natural gas in a well that has installed a gas
sale line during the complete production and total recovery of all
in place liquid hydrocarbons, recovering said liquids by a
predetermined gas flow pressure, such that gas is retained in
solution within the recovering liquid hydrocarbons, so that said
liquids are always maintained recoverable, until liquid hydrocarbon
production and recovery considerably decline, at such time
converting over to total gas production by releasing the surface
gas flow pressure to a fully opened gas flow pressure at the
surface gas flow regulator to efficiently produce and recover
natural gas, whereby total in place liquid hydrocarbons have been
recovered, leaving only the small quantities that stick to the
formation rock pores as a thin film, and that are isolated in any
formation structural traps, wherein in place gas is free to flow to
the surface for total in place natural gas production and ultimate
recovery, thereby recovering total in place liquid and gaseous
hydrocarbons maintained and converted by this recovery process to
be ultimately recoverable.
35. The method as defined in claim 18, further comprising:
maintaining a predetermined optimum flow pressure to produce both
natural gas and liquid hydrocarbons under a state of equilibrium,
thereby providing a more efficient drainage mechanism such that gas
remains on top of liquid hydrocarbons within the reservoir's
formations, utilizing gas energy and the principles of gravity
separation to eliminate undesirable coning and loss of free gas and
solution gas through the liquid hydrocarbon formation into the
wellbore, whereby liquid and gaseous hydrocarbons are maintained
pressured and as recoverable flowing fluids with a more effective
overhead gas cap pressure drive, wherein total in place gaseous and
liquid hydrocarbon reserve recoverability and related value is
notably increased.
36. The method as defined in claim 18, further comprising:
providing the surface gas flow pressure regulator for controlling
the wellbore annulus gas flow pressure at the wellhead exit port
during the complete production and total recovery of all in place
liquid hydrocarbons, recovering said liquids by a predetermined gas
flow pressure, such that gas is retained in solution within the
recovering liquid hydrocarbons, so that said liquids are always
maintained recoverable, until liquid hydrocarbon production and
recovery considerably decline, at such time converting over to
total gas production by releasing the surface gas flow pressure to
a fully opened gas flow pressure at the surface gas flow regulator
to efficiently produce and recover natural gas, whereby total in
place liquid hydrocarbons have been recovered, leaving only the
small quantities that stick to the formation rock pores as a thin
film, and that are isolated in any formation structural traps,
wherein in place gas is free to flow to the surface for total in
place natural gas production and ultimate recovery, thereby
recovering total in place liquid and gaseous hydrocarbons
maintained and converted by this recovery process to be ultimately
recoverable.
37. A system for increasing production and ultimate recovery of
gaseous and liquid hydrocarbons from one or more downhole natural
gas baring formations and through a production tubing string within
a wellbore by complete removal of liquids from the wellbore and
utilizing gas pressure drive of the natural gas baring formation,
the system comprising: the wellbore being perforated for fluid
communication with one or more downhole gas baring formations both
above and bellow a gas-fluid interface; a surface gas flow pressure
regulator and a surface pressure gauge provided on the casing well
head annulus exit port for regulating gas flow and pressure and to
maintain a predetermined flow pressure on the wellbore annulus; a
downhole injector positioned at the bottom of the production tubing
string relative to the lowest opened formation; the downhole
injector for passing formation liquids by pressure differential
through the production tubing string toward the surface while
preventing formation gases from entering the production tubing
string; a downhole pump positioned within a production tubing
string above the injector for pumping liquids to the surface; the
downhole pump for efficiently pumping liquid inflow through the
production tubing string to the surface of the well; and the
wellbore with maintained direct fluid communication with one or
more opened gas baring formations and liquids entering from the
lower part of the formations, such that such gas pressure acts as a
cap on the formation fluids in the opened formation to force the
fluids out of the formation into the wellbore through the injector
and toward the surface.
38. The system as defined in claim 37, further comprising: the
downhole injector being positioned relative to the lowest downhole
opened gas baring formation so that all incoming liquid
hydrocarbons and invading waters are efficiently and completely
removed from the wellbore into the production tubing string on to
the surface for increased gaseous and liquid hydrocarbon
recovery.
39. The system as defined in claim 37, further comprising: wherein
the well has a surface gas flow meter for continually and
comparatively measuring and monitoring the formation gas flow
production, pressure and recovery for the most effective optimum
gas flow pressure at the surface, and periodically making and
observing fluid level test, while continually and comparatively
measuring and monitoring the production and recovery of formation
liquids through a surface metering facility for a combined total
maximum gaseous and liquid hydrocarbon production and ultimate
recovery, throughout the reservoir's formations total gaseous and
liquid hydrocarbon recovery life for maximum hydrocarbon reserve
value.
40. The system as defined in claim 37, further comprising: the
surface gas flow pressure regulator and the surface pressure gauge
for continually and controllably and comparatively regulating
flowing formation gas production and pressure at a controlled flow
pressure to retain a predetermined optimum formation gas pressure
in an annulus about the production tubing string, and thereby on
and within all opened hydrocarbon formations, such that the gas
pressure prevents solution gas within the liquid hydrocarbon in its
formation and the wellbore from breaking out of solution, whereby
maintaining its expulsive force, high mobility and low viscosity,
and acts as a driving force to pass pressured higher pressure
hydrostatic head liquids out of the formation and through the
injector by pressure differential up into the lower pressure
production tubing string to recover formation liquids at the
surface, wherein total in place liquid hydrocarbons are maintained
highly fluid and recoverable, thereby increasing related liquid
hydrocarbon reserve value.
41. The system as defined in claim 37, further comprising: the
wellbore annulus with a maintained predetermined formation gas
pressure such that gas pressure acts as a driving force on all
liquid hydrocarbons and any invading waters to pass them through
the injector by pressure differential up into the lower pressure
production tubing string for formation fluid recovery at the
surface, so that a liquid level is maintained in the wellbore at
the injector liquid intake level for maximum free gas and
pressurized fluid flow from all opened hydrocarbon formations for
maximum gaseous and liquid hydrocarbon recovery, whereby total
gaseous and liquid hydrocarbon reserve recoverability and related
value is increased.
42. The system as defined in claim 37, further comprising: the
wellbore with maintained gas pressure in the annulus above the
downhole injector intake liquid level as a driving force to
maintain a predetermined liquid level in the lower pressure
production tubing string for maximum artificial lift efficiency of
incoming liquids on to the surface.
43. The system as defined in claim 37, further comprising: one or
more gas lift valves as an alternative means for lifting liquids
positioned along the production tubing string above the downhole
injector for selectively passing annulus gases through the
production tubing string to raise incoming liquids as slugs of
liquid to the surface through the production tubing string.
44. The system as defined in claim 37, further comprising: the
wellbore opened with one or more horizontal and alternatively
highly angled boreholes in a gas zone for maximum zone exposure and
increased gas flow and recovery.
45. The system as described in claim 37, further comprising: the
wellbore opened with one or more horizontal and alternatively
highly angled boreholes in a liquid hydrocarbon zone for maximum
zone exposure and increased liquid hydrocarbon flow and
recovery.
46. The system as defined in claim 37, further comprising: a check
valve in the tubing string above the top of the injector; and the
injector including an injector housing having a nominal outer
diameter, a fluid responsive float open at the top and closed at
the bottom and moveable with respect to the injector housing as a
function of fluid density surrounding the float, and a shut off
valve member moveably responsive to the float for engagement with a
shut off valve seat, the shut off valve member being spaced
vertically below inside the injector housing from the check
valve.
47. The system as defined in claim 37, wherein the injector
includes a sleeve shaped filter screen for restricting at least 90%
of solid particles of 30 microns or greater from passing through
the filter screen.
48. The system as defined in claim 37, further comprising: the well
head surface gas flow pressure regulator for closing off the
release of gas flow and pressure in an opened hydrocarbon reservoir
with a considerable high volume of liquid hydrocarbons in one or
more opened gas baring formations and one or more opened liquid
hydrocarbon formations in an annulus of the vertical wellbore and
connecting horizontal and deviated wellbore annuluses, and the
surface pressure gauge for measuring the surface wellbore annulus
pressure, while simultaneously producing and recovering and
monitoring at the surface production tubing string discharge all
incoming liquid hydrocarbons and invading waters entering the
wellbore, so that previously incoming formation gas above the
liquids in the wellbore is maintained in the open gas zone, whereby
conserving in place gas volume and pressure by the incoming
liquid's greater hydrostatic head pressure which drives it through
the downhole injector by pressure differential and into the lower
pressure production tubing string on toward the surface for maximum
liquid hydrocarbon production and ultimate recovery and ultimately
total gaseous hydrocarbon recovery from a hydrocarbon
formation.
49. The system as defined in claim 48, further comprising: the
surface gas flow pressure regulator for closing off the wellbore
annulus at the well head exit port such that all gases which are
prevented from flowing and from entering the production tubing
string by the injector are retained downhole within the opened
upper gas zone for storing gases there for future production by the
incoming higher pressure formation liquids in transit through the
wellbore into the injector to be produced and recovered through the
lower pressure production tubing string on to the surface, whereby
maintained formation gas pressure assist by overhead pressure for
the maximum production and ultimate recovery of hydrocarbon
formation fluids from the opened lower liquid hydrocarbon
formation, wherein total in place gaseous and liquid hydrocarbon
reserve recoverability and related value are notably increased.
50. The system as defined in claim 49, further comprising: the
surface gas flow pressure regulator for closing off the wellbore
annulus at the well head exit port throughout the complete
production and total recovery of all in place liquid hydrocarbons
until said production and recovery considerably decline, at such
time converting over to total gas production by releasing the
surface gas flow pressure to a lower optimum flow pressure at the
surface gas flow regulator to efficiently produce and recover
natural gas, while efficiently removing any incoming invading
waters in the wellbore, whereby total in place liquid hydrocarbons
have been recovered, leaving only the small quantities that stick
to the formation rock pores as a thin film, and that are isolated
in any formation structural traps, wherein total in place gas is
free to flow to the surface for total in place natural gas
production and ultimate recovery, thereby recovering total in place
liquid and gaseous hydrocarbons maintained and converted by this
recovery process to be ultimately recoverable.
51. The system as defined in claim 37, further comprising: the
surface gas flow pressure regulator for completely closing a
wellbore annulus at the wellhead exit port in one or more opened
gas baring formations and in one or more opened liquid hydrocarbon
formations in a well that has no surface gas sales line, such as to
prevent surface gas flaring, so that all gases which are prevented
from flowing and from entering the production tubing string by the
injector are retained downhole within all opened upper gas zones by
incoming higher pressure liquids in transit through the wellbore
for storing gases there for future production, such that the upper
gas zone is assisted by maintained overhead pressure for the
production and recovery of all incoming liquid hydrocarbons and
invading waters which enter the wellbore by their greater
hydrostatic head pressure driving them through the downhole
injector by pressure differential on up into the lower pressure
production tubing string toward the surface for maximum production
and ultimate recovery of hydrocarbon fluids from all opened liquid
hydrocarbon formations, whereby early total in place liquid
hydrocarbon recovery is economically realized at low cost, wherein
total in place gaseous and liquid hydrocarbon reserve value is
considerably increased by becoming recoverable.
52. The system as defined in claim 51, further comprising: the
surface gas flow pressure regulator for controlling the wellbore
annulus flow pressure at the wellhead exit port to produce and
recover natural gas in a well that has installed a gas sales line
during the complete production and total recovery of all in place
liquid hydrocarbons, recovering said liquids by a predetermined gas
flow pressure, such that gas is retained in solution within the
recovering liquid hydrocarbons, so that said liquids are always
maintained recoverable, until liquid hydrocarbon production and
recovery considerably decline, at such time converting over to
total gas production by releasing the surface gas flow pressure to
a lower optimum gas flow pressure at the surface gas flow regulator
to efficiently produce and recover natural gas while removing any
incoming invading waters, whereby total in place liquid
hydrocarbons have been recovered, leaving only the small quantities
that stick to the formation rock pores as a thin film, and that are
isolated in any formation structural traps, wherein in place gas is
free to flow to the surface for total in place natural gas
production and ultimate recovery, thereby recovering total in place
liquid and gaseous hydrocarbons maintained and converted by this
recovery process to be ultimately recoverable.
53. The system as defined in claim 37, further comprising: the
surface gas flow pressure regulator for controlling the wellbore
annulus flow pressure at the wellhead exit port during the complete
production and total recovery of all in place liquid hydrocarbons,
recovering said liquids by a predetermined gas flow pressure, such
that gas is retained in solution within the recovering liquid
hydrocarbons, so that said liquids are always maintained
recoverable, until liquid hydrocarbon production and recovery
considerably decline, at such time converting over to total gas
production by releasing the surface gas flow pressure to a lower
optimum gas flow pressure at the surface gas flow regulator to
efficiently produce and recover natural gas while removing any
incoming invading waters, whereby total in place liquid
hydrocarbons have been recovered, leaving only the small quantities
that stick to the formation rock pores as a thin film, and that are
isolated in any formation structural traps, wherein in place gas is
free to flow to the surface for total in place natural gas
production and ultimate recovery, thereby recovering total in place
liquid and gaseous hydrocarbons maintained and converted by this
recovery process to be ultimately recoverable.
54. A method of increasing production and ultimate recovery of
gaseous and liquid hydrocarbons from one or more downhole natural
gas baring formations and through a production tubing string within
a wellbore by complete removal of liquids from the wellbore and
utilizing gas pressure drive of a natural gas baring formation, the
method comprising: the wellbore being perforated for fluid
communication with one or more downhole hydrocarbon formations both
above and bellow a gas-fluid interface; providing a surface gas
flow pressure regulator and a surface pressure gauge on the casing
well head annulus exit port for respectively regulating gas flow
production and measuring pressure while maintaining a predetermined
flow pressure on the wellbore annulus; positioning a downhole
injector at the bottom of a production tubing string relative to
the lowest opened formation; passing formation fluids through the
downhole injector by pressure differential and through the
production tubing string toward the surface while preventing
formation gases from entering the production tubing string;
positioning a downhole pump within a production tubing string above
the injector for pumping liquids to the surface; pumping liquid
inflow efficiently through the production tubing string to the
surface of the well; and maintaining direct fluid communication
between the wellbore and one or more opened gas baring formations
and liquids entering from the lower part of the formations, such
that such gas pressure acts as a cap on the formation fluids in the
opened formation to force the fluids out of the formation into the
wellbore through the injector and toward the surface.
55. The method as defined in claim 54, further comprising: wherein
the downhole injector is positioned relative to the lowest downhole
opened gas baring formation in the wellbore so that all incoming
liquid hydrocarbons and invading waters are efficiently and
completely removed from the wellbore into the lower pressure
production tubing string on to the surface thereby increasing
gaseous and liquid hydrocarbon recovery.
56. The method as defined in claim 54, further comprising:
continually and comparatively measuring and monitoring the
formation gas flow production, pressure and related recovery for
the most effective optimum gas flow pressure at the wells surface
gas flow meter and periodically making and observing fluid level
and gas-oil ratio test, while continually and comparatively
measuring and monitoring the production and recovery of formation
liquids through a surface metering facility for a combined total
maximum gaseous and liquid hydrocarbon production and ultimate
recovery throughout the reservoir's formations total gaseous and
liquid hydrocarbon recovery life for maximum hydrocarbon reserve
value.
57. The method as defined in claim 54, further comprising: while
recovering formation liquids at the surface production tubing
string discharge, simultaneously flowing formation gas production
and pressure at a regulated and controlled predetermined gas flow
pressure at the surface gas flow pressure regulator with the
surface gas pressure gauge to retain an optimum formation gas
pressure in an annulus about the production tubing string, and
thereby on and within all opened hydrocarbon formations, such that
the gas pressure prevents solution gas within the liquid
hydrocarbon in its formation and the wellbore from breaking out of
solution, thereby maintaining its expulsive force, high mobility
and low viscosity, and acts as a driving force to pass pressured
higher pressure hydrostatic head liquids out of the formation and
through the injector by pressure differential on up into the lower
pressure production tubing string to recover formation liquids at
the surface, wherein total in place liquid hydrocarbons are
maintained highly fluid and recoverable, thereby increasing related
liquid hydrocarbon reserve value.
58. The method as defined in claim 54, further comprising:
maintaining a predetermined optimum formation gas flow pressure in
the wellbore annulus such that gas pressure acts as a driving force
on all liquid hydrocarbons and invading waters to pass them through
the injector by pressure differential into the lower pressure
production tubing string for formation fluid recovery at the
surface, so that a liquid level is maintained in the wellbore at
the injector liquid in take level for maximum free gas and
pressurized fluid flow from all opened hydrocarbon formations for
maximum gaseous and liquid hydrocarbon recovery, whereby total
gaseous and liquid hydrocarbon reserve recoverability and related
value is increased.
59. The method as defined in claim 54, further comprising:
maintaining a wellbore gas pressure in the annulus above the
downhole injector intake liquid level as a driving force to
maintain a predetermined liquid level in the lower pressure
production tubing string for maximum artificial lift efficiency of
incoming liquids on to the surface.
60. The method as defined in claim 54, further comprising;
providing one or more gas lift valves as an alternative means for
lifting liquids positioned along the production tubing string above
the downhole injector for selectively, at a predetermined pressure,
passing annulus gases through the production tubing string to raise
incoming liquids as slugs of liquid to the surface through the
production tubing string.
61. The method as defined in claim 54, further comprising: opening
the wellbore with one or more horizontal and alternatively highly
angled boreholes in a gas zone for maximum zone exposure and
increased gas flow and recovery.
62. The method as defined in claim 54, further comprising: opening
the wellbore with one or more horizontal and alternatively highly
angled boreholes in a liquid hydrocarbon zone for maximum zone
exposure and increased liquid hydrocarbon flow and recovery.
63. The method as defined in claim 54, further comprising:
positioning a check valve within a production tubing string above
the top of the injector for preventing fluids which pass by the
check valve from returning to the injector; and the injector
housing having a nominal outer diameter, a fluid responsive float
open at the top and closed at the bottom and moveable with respect
to the injector housing as a function of fluid density surrounding
the float, and a shut off valve member moveably responsive to the
float for engagement with a shut off valve seat, the shut off valve
member being spaced vertically below inside the injector housing
from the check valve.
64. The method as defined in claim 54, further comprising:
providing a sleeve-shaped filter screen across an inlet flow port
of the injector for restricting at least 90% of solid particles 30
microns or greater from passing through the filter screen.
65. The method as defined in claim 54, further comprising:
providing the well head surface gas flow pressure regulator for
closing off the release of gas flow and pressure in an opened
hydrocarbon reservoir with a considerable high volume of liquid
hydrocarbons in one or more opened gas baring formations with one
or more opened liquid hydrocarbon formations in an annulus of the
vertical wellbore and all connecting horizontal and deviated
wellbore annuluses, and the surface pressure gauge for measuring
the surface wellbore annulus pressure, while simultaneously
producing and recovering and monitoring at the surface production
tubing string discharge all incoming liquid hydrocarbons and
invading waters entering the wellbore, so that previously incoming
formation gas in the wellbore above the incoming liquids is
maintained in all opened gas zones, whereby conserving in place gas
volume and pressure by the incoming liquid's greater hydrostatic
head pressure which drives it through the pressure drop in the
downhole injector and through the lower pressure production tubing
string on to the surface for maximum liquid hydrocarbon production
and ultimate recovery and ultimately total gaseous hydrocarbon
recovery from a hydrocarbon formation.
66. The method as defined in claim 65, further comprising:
providing the surface gas flow pressure regulator for closing off
the wellbore annulus at the well head exit port such that all gases
which are prevented form flowing and from entering the production
tubing string by the injector are retained downhole within all
opened upper gas zones for storing gases there, for future
production by the incoming higher pressure formation liquids in
transit through the wellbore into the injector to be produced and
recovered through the lower pressure production tubing string at
the surface, whereby maintained formation gas pressure assist by
overhead pressure for the maximum production and ultimate recovery
of hydrocarbon formation fluids from all opened liquid hydrocarbon
formations, wherein total gaseous and liquid hydrocarbon reserve
recoverability and related value is notably increased.
67. The method as defined in claim 66, further comprising:
providing the surface gas flow pressure regulator for closing off
the wellbore annulus at the well head exit port throughout the
complete production and total recovery of all in place liquid
hydrocarbons until said production and recovery considerably
declines, at such time converting over to total gas production by
releasing the surface gas flow pressure to a lower predetermined
optimum flow pressure at the surface gas flow regulator to
efficiently produce and recover natural gas while efficiently
removing any incoming invading waters in the wellbore, whereby
total in place liquid hydrocarbons have been recovered, leaving
only the small quantities that stick to the formation rock pores as
a thin film, and that are isolated in any formation structural
traps, wherein total in place gas is free to flow to the surface
for total in place natural gas production and recovery, thereby
recovering total in place liquid and gaseous hydrocarbons
maintained and converted by this recovery process to be ultimately
recoverable.
68. The method as defined in claim 54, further comprising:
providing the surface gas flow pressure regulator for completely
closing a wellbore annulus at the wellhead exit port in one or more
opened gas baring formations and in one or more opened liquid
hydrocarbon formations in a well that has no surface gas sales
line, such as to prevent surface gas flaring, so that all gases
which are prevented from flowing and from entering the production
tubing string by the injector are retained downhole by incoming
higher pressure liquids in transit through the wellbore within the
opened upper gas zone for storing gases there for future
production, such that all upper gas zones assist by overhead
pressure for the production and recovery of all incoming liquid
hydrocarbons and invading waters entering the wellbore by their
greater hydrostatic head pressure, driving them through the
downhole injector by pressure differential on up into the lower
pressure production tubing string toward the surface for maximum
production and ultimate recovery of hydrocarbon fluids from all
opened liquid hydrocarbon formations, whereby early total in place
liquid hydrocarbon recovery is economically realized at low cost,
wherein total in place gaseous and liquid hydrocarbon reserve value
is considerably increased by becoming recoverable.
69. The method as defined in claim 68, further comprising:
providing the surface gas flow pressure regulator for controlling
the wellbore annulus gas flow pressure at the wellhead exit port to
produce and recover natural gas in a well that has installed a gas
sales line during the complete production and total recovery of all
in place liquid hydrocarbons, recovering said liquids by a
predetermined gas flow pressure, such that gas is retained in
solution within the recovering liquid hydrocarbons, so that said
liquids are always maintained recoverable, until liquid hydrocarbon
production and recovery considerably decline, at such time
converting over to total gas production by releasing the surface
gas flow pressure to a lower optimum gas flow pressure at the
surface gas flow regulator to efficiently produce and recover
natural gas while removing any and all incoming invading waters,
whereby total in place liquid hydrocarbons have been recovered,
leaving only the small quantities that stick to the formation rock
pores as a thin film, and that are isolated in any formation
structural traps, wherein in place gas is free to flow to the
surface for total in place natural gas production and ultimate
recovery, thereby recovering total in place liquid and gaseous
hydrocarbons maintained and converted by this recovery process to
be ultimately recoverable.
70. The method as defined in claim 54, further comprising:
maintaining a predetermined optimum flow pressure to produce both
natural gas and liquid hydrocarbons under a state of equilibrium
thereby providing a more efficient drainage mechanism such that gas
remains on top of liquid hydrocarbons within all opened hydrocarbon
reservoirs' formations utilizing gas energy and the principles of
gravity separation to eliminate undesirable coning and loss of free
gas and solution gas through all opened liquid hydrocarbon
formations into the wellbore, whereby gaseous and liquid
hydrocarbons are maintained pressured and as recoverable flowing
fluids with a more effective overhead gas cap pressure drive,
wherein total in place gaseous and liquid hydrocarbon reserve
recoverability and related value is substantially increased.
71. The method as defined in claim 54, further comprising:
providing the surface gas flow pressure regulator for controlling
the wellbore annulus gas flow pressure at the wellhead exit port
during the complete production and total recovery of all in place
liquid hydrocarbons, recovering said liquids by a predetermined gas
flow pressure, such that gas is retained in solution within the
recovering liquid hydrocarbons, so that said liquids are always
maintained recoverable, until liquid hydrocarbon production and
recovery considerably decline, at such time converting over to
total gas production by releasing the surface gas flow pressure to
a lower optimum gas flow pressure at the surface gas flow regulator
to efficiently produce and recover natural gas while removing any
incoming invading waters, whereby total in place liquid
hydrocarbons have been recovered, leaving only the small quantities
that stick to the formation rock pores as a thin film, and that are
isolated in any formation structural traps, wherein in place gas is
free to flow to the surface for total in place natural gas
production and ultimate recovery, thereby recovering total in place
liquid and gaseous hydrocarbons maintained and converted by this
recovery process to be ultimately recoverable.
Description
FIELD OF THE INVENTION
[0001] The present invention relates to a liquid/gas separator for
positioning in the lower part of a well intended for the production
of fluids, such as hydrocarbons. The separator prevents the entry
of gas into the production tubing string, but allows the entry of
fluid in liquid form. The invention also relates to a method for
improving the primary, secondary or tertiary recovery of reservoir
hydrocarbons and to improved systems involving downhole liquid/gas
separators for various hydrocarbon recovery applications.
BACKGROUND OF THE INVENTION
[0002] Hydrocarbon recovery operations commonly allow reservoir gas
within the formation to flow into the wellbore and to the surface
with the liquid hydrocarbons. This practice initially drives high
volumes of hydrocarbons into the well and up through the production
tubing. Conventional hydrocarbon producing methods thus allow, and
in many cases rely upon, the pressurized reservoir gases to
directly assist in lifting the production fluids to the surface.
This practice thus utilizes the pressure and liquid-driving
capabilities of the reservoir gas to improve early well production
recovery. While prevalent, this practice significantly reduces the
ultimate recovery of liquid hydrocarbon reserves from the
formation.
[0003] Liquid/gas separators have been used downhole in producing
oil and gas wells to allow the entry of reservoir fluids which are
in the liquid state into the tubular string that conveys the liquid
fluids to the surface, and to prevent the entry of fluids in the
gaseous state into the producing tubular string. One type of
separation device, which remains immersed in the surrounding
downhole fluid, includes a float and a valve arrangement. When this
separation device is full of liquid, an open conduit is provided
from the reservoir to the producing tubular. When the liquid is
displaced by gas in the separation device, the float rises due to
its increased buoyancy and a valve closes to prevent the entry of
fluids into the producing tubular,
[0004] This separator thus includes a float activated valving
system which opens when the separator is full of liquid and closes
when that liquid is displaced by gas. The flotation system within
this separator is configured to operate in the vertical or
substantially vertical orientation. When the liquid/gas separator
is open, the separator allows liquid to be transmitted by pressure
energy within the producing formation upward through the tubular
string which is positioned above a standing or check valve, and
then to be lifted to the surface by a conventional pump powered by
a reciprocating or rotating (progressive cavity) rod string. Other
types of available downhole pumps, such as electrical submersible
pumps or hydraulic (jet-type) pumps, may also be used to lift the
liquid to the surface once it is entrapped above the liquid gas
separator and within the production tubing string.
[0005] In practice, the downhole separator does little to cause or
accelerate the separation of liquid and gas. Rather, the device
senses the presence of a gas or a liquid within the device by the
float, and allows only liquid entry into the production tubing
string. The separator thus operates within a downhole well in a
manner similar to a float operated valve controller which detects
the liquid/gas. interface within a surface vessel. One type of
separation device marketed as the Korkele downhole separator has
proven effective in many installations.
[0006] The separator may be placed and operated within a cased
wellbore with a conventional diameter casing therein or may also be
operated in an open hole. In either case, the separator may be
suspended in the well from production tubing. The basic advantage
of the Korkele downhole separator is that it improves performance
of the well and the well-reservoir production system by allowing
for the production of liquids only, i.e., it prevents the entry of
gas from the reservoir into the production tubular string. The
downhole separator as discussed above is more fully described in a
July 1972 article in World Oil, pages 37-42.
[0007] Further details with respect to this separator are disclosed
in U.S. Pat. No. 3,643,740 granted to Kork E. Kelley and hereby
incorporated by reference.
[0008] Other prior art includes U.S. Pat. Nos. 1,507,454 and
1,757,267. The '454 patent discloses an automatic pump control
system with an upright stem connected to a diaphragm to operate a
standing valve. The '267 patent discloses a gas/oil separator
having a separating chamber located within the tubing and a
mechanism for diverting the path of oil over an enlarged contact
surface to separate free oil from gas.
[0009] U.S. Patents naming Kork Kelly as an inventor or co-inventor
include U.S. Pat. Nos. 2,291,902; 3,410,217; 3,324,803; 3,363,581;
and 3,451,477. The '902 patent discloses a gas anchor having a
float connected to a valve stem which operates a valve head. The
'217 patent discloses a separator for liquid control in gas wells.
The '803 patent discloses a device having a floating bucket
connected by a rod for liquid/gas wells. A valve member is
disclosed below and in close proximity to a check ball. The '581
patent discloses a pressure balanced and full-opening gas lift
valve. The '477 patent relates to an improved method for effecting
gas control in oil wells. The device includes a flotation bucket
with an open top and a valve string including a valve member
connected to the top of a rod, with the bottom of the rod connected
to the bottom bucket. The '740 patent discloses both methods and
apparatus for effecting gas control in oil wells utilizing a
flotation bucket with an open top and a valve string including a
valve member connected to the top of a rod. U.S. Pat. No. 3,971,213
discloses an improved pneumatic beam pumping unit.
[0010] U.S. Pat. No. 3,408,949 discloses a bottom hole gas/liquid
separator having a float tube encircling the lower end of a
production tubing and adapted to move vertically within a housing.
A production valve is disposed on the upper end of a spacer bar
such that the float ad spacer bar form a sand trap. U.S. Pat. No.
3,483,827 discloses a well producing which utilizes a gas separator
in a tubing string to separate liquid from gas prior to nto a
downhole pump. U.S. Pat. No. 3,724,486 discloses a liquid and gas
separation for a downhole well wherein a valve member is moveable
and resiliently mounted on table liquid container designed so that
liquid will accumulate within the bore hole above ition where gas
enters to decrease or prohibit the entry of gas into the bore hole.
U.S. Pat. No. 3,993,129 discloses a fluid injection valve for use
in well tubing for controlling the low of fluid between the outside
of the production tubing and the inside of the tubing.
[0011] More recently issued patents include U.S. Pat. Nos.
4,474,234 and 4,570,718. The '234 patent discloses a hydrocarbon
production well having a safety valve removably mounted in the
production tubing beneath a pump. The '718 patent relates to an oil
level sensor system and method for operating an oil well whereby
upper and lower oil well sensors control pumping of the well. U.S.
Pat. No. 5,456,318 discloses a fluid pumping device having a fluid
inlet valve disposed at its lower end for fluid flow into the body
of the device, a plunger assembly disposed in the interior of the
body for reciprocating movement, a seal which cooperates with the
plunger assembly to divide the body into isolated upper and lower
chambers and to divide the body from the production tube, and fluid
flow control valves.
[0012] U.S. Pat. No. 5,653,286 discloses a downhole gas separator
connected to the lower end of a tubing string designed such that
primary liquid fluid flows into a chamber within the separator.
U.S. Pat. No. 5,655,604 discloses a downhole production pump and
circulating system which utilizes valves wherein the valve balls
are attached to projector stems. U.S. Pat. No. 5,664,628 discloses
an improved filter medium for use in subterranean wells.
[0013] None of the prior art discussed above fully benefits from
the capability of an effective downhole liquid/gas separator.
Further improvements are required to obtain the significant
advantages realized by retaining within the downhole producing
formation the inherent energy, i.e. the compressed gas, which
drives the desired hydrocarbon products from the reservoir rock and
into the wellbore so that they may be more efficiently produced. By
preventing the formation gas at bottom of the well from entering
the production tubing string and permitting only the entry of
liquids into the tubing string, the retained potential energy and
expansive properties of the gas may be effectively utilized to
produce a higher percentage of liquid reserves than would otherwise
be recovered by conventional technology. Alternatively, improved
procedures for pumping liquid accumulations off gas wells are
necessary to improve the performance of gas wells. Moreover,
further improvements in a separation device, in methods of using a
separation device, and in the configuration and operation of the
overall hydrocarbon recovery system in which a separation device is
employed are required to benefit from the numerous applications in
which such a device may be effectively used to enhance recovery of
hydrocarbons.
[0014] The disadvantages of the prior art are overcome by the
present invention. An improved separation device, a method of
operating a separation device, an improved overall hydrocarbon
recovery system, and improved techniques for recovering
hydrocarbons are hereinafter disclosed.
SUMMARY OF THE INVENTION
[0015] The present invention discloses an improved downhole liquid
injector and improved techniques utilizing an injector for
recovering hydrocarbons from producing reservoirs. Several basic
concepts influence the benefits of utilizing the liquid injector of
the present invention in various existing and planned well and/or
reservoir producing systems. First, positive prevention of gas into
the producing tubular improves the efficiency of an artificial lift
pumping system by allowing the lift system to handle primarily
liquids rather than a combination of liquids and gases. By
providing for the positive prevention of gas into the production
tubing, the artificial lift pumping system is efficiently pumping
only primarily liquids. Conventional artificial lift systems, which
utilize a rod string to power a downhole pump thus operate more
efficiently with liquid only flowing through the production tubing
string. Preventing gas lock in downhole positive displacement and
electrical submersible pumps is a major problem for the oil well
operator with existing technology. Since the injector of the
present invention substantially reduces or eliminates unwanted gas
to the production tubing string, gas lock is avoided and the life
and efficiency of positive displacement aid submersible pumps is
increased.
[0016] By preventing gas entry downhole into the production tubing
string, the present invention also reduces the possibility of gas
blowout through the surface production system. The present
invention also reduces sucker rod stuffing box drying and wear to
reduce leakage of fluids from the wellhead and minimize
environmental problems associated with producing hydrocarbons.
[0017] The system of the present invention may significantly
benefit from the concept of preventing gas production from the
reservoir and thereby retaining the gas within the reservoir where
it will continue to supply energy in the form of pressure to drive
well fluids into the producing wellbore. By permitting only the
inflow of reservoir liquids into the production tubing string and
maintaining gases on the top of a liquid column in the well, a high
percentage of natural gas remains in the reservoir where it
provides the pressure to drive liquids toward the wellbore and
creates a more efficient drainage mechanism to best utilize the
principles of gravity separation.
[0018] By keeping gas within the reservoir, the present invention
also creates a more effective liquid drainage pattern within the
reservoir by reducing gas coning around the well and improving the
maintenance of an effective gas cap drive to develop an enhanced
liquid gravity drainage system. The system of the present invention
thus acts to oppose the release of gas from the formation into the
wellbore and minimize undesirable coning of a gas cap, while also
promoting the generation and maintenance of a more effective gas
cap drive.
[0019] By retaining the gas in the reservoir, the flow of desired
liquid hydrocarbons into the wellbore is also assisted by retaining
gas in solution within the crude oil to maintain a lower fluid
viscosity, thereby lowering the resistance to flow of the crude oil
through the reservoir. Since reservoir rock has a lower relative
permeability to liquids than to gas, particularly when the crude
loses its lighter components and becomes heavy, minimizing gas
inflow and maintaining reservoir pressure keeps the crude more gas
saturated and less viscous so that it is mobile and may more freely
flow toward the wellbore area.
[0020] The injector of the present invention may also be used to
significantly improve the efficiency of a downhole system designed
to remove liquids, typically water, from the wellbore which impede
the production of natural gas from a gas reservoir. By providing
for the efficient removal of problem liquids which impede the
production of gases from primarily gas reserve reservoirs, the
efficiency of a gas recovery system may be significantly enhanced.
Systems with a positive downhole gas shutoff for removing liquid
accumulations will also be safer to operate since gas flow to the
surface through the tubing string may be automatically and
positively controlled if surface control is lost.
[0021] The techniques of the present invention may be used to
improve long-term productivity and increase the recovery of
hydrocarbon reserves from many existing oilfields. In new
oilfields, particularly those in which it is desirable to prevent
or limit the wasteful production or uneconomical recovery of
natural gas which lowers ultimate crude recovery, the present
invention offers a valuable completion option. Such new fields are
continually being discovered and developed in isolated offshore
locations, and in many countries which are just now developing
their petroleum reserves.
[0022] The downhole separation device of the present invention,
which is more properly termed a liquid injector, is a
float-operated device that permits producing reservoir fluids to
flow into a production tubing string but positively shuts off the
entry of gas. In a preferred embodiment, the injector prevents
entry of fine-grain sand into the interior of the injector tool by
utilizing an improved screening device to provide significantly
increased protection from sand entry and minimize filling and
plugging by the fine-grained sand particles. The sand particle
sizes excluded by the screening device do not significantly impede
fluid flow. The screening device also provides advantages relating
to the breakup of foams in the wellbore to enhance the flow of
liquid rather than gas into the interior of the injector. In one
embodiment of the injector, the flow shutoff valve is located at a
high position within or above the intake tube and close to the
standing or check valve. This positioning of the shutoff valve
causes liquids in the intake tube to remain under wellbore pressure
while the shutoff valve is closed, thus preventing the release of
solution gas in response to pressure reduction caused by the
pumping action, thus reducing problems associated with pump gas
lock. Raising the shutoff valve also keeps the shutoff valve out of
the lower area of the float in which sand may settle during the
time the valve is closed, thus further minimizing the possibility
of sand plugging.
[0023] An improved method is provided for creating a liquid
reservoir within a well pumping or producing system. According to
one technique, liquid does not flow directly into the pump intake,
and instead the wellbore formation fluid is first diverted into a
vertical reservoir created in an annulus between the tubing and the
casing by addition of a packer. The downhole pump may then draw
from this reservoir. Should the injector shutoff valve close, the
pump would continue to draw liquid until the working fluid level
drops to the pump intake. An additional benefit from this concept
occurs as a result of further solution gas breakout and separation
within the vertical reservoir. The gas from the producing formation
below the packer may be vented through a vent tube containing a
pressure regulation system to ensure wellbore pressure sufficient
to lift liquid to a working level above a pump. This system may
also benefit from the use of various back pressure controls and
fluid entry and reversal mechanisms.
[0024] The injector of the present invention may also be combined
with an improved beam. pumping unit as described in U.S. Pat. No.
3,971,213. This integrated system uses power derived from the
pressure of natural gas produced in the annulus in the previously
described liquid reservoir. After pressure reduction at the
surface, the produced gas may be routed into a flow line for sale.
No waste or burning of produced gas is required, and instead a
selfcontained operation is achieved.
[0025] The techniques of the present invention minimize the
production of gas which, in many applications, is wasted and
flared. By providing a controlled back pressure relief in a gas
lifted well, a gas lift system in a flowing well may be configured
with double packers to create a chamber above the producing
formation. A tubing regulator device controls the pressure of
entrapped gas from the wellbore which is relieved into the chamber,
which in turn provides a desired pressure differential across the
formation and to the wellbore. Gas in the chamber may further act
as a first lifting stage for slugs of liquid entering the tubing.
Various modifications to this technique are more fully discussed
below. The techniques of the present invention may also be used to
increase productivity in horizontal wells, as discussed further
below. The techniques of the present invention may thus be used to
increase liquid hydrocarbon recovery by conserving and utilizing
natural gas as a reservoir driving mechanism so that a gas cap
pushes the liquid downward to a lower horizontal bore hole or
lateral.
[0026] It is an object of the present invention to provide improved
equipment and methods for recovering hydrocarbons from subterranean
formations. More particularly, the present invention may function
to retain a pressurized gas reservoir downhole and thereby improve
recovery of liquid hydrocarbons, and may also be used to remove
liquids which block the effective recovery of gaseous hydrocarbons.
The improved method of producing hydrocarbons from a well serves to
more efficiently retain and utilize the inherent energy of natural
gas within the reservoir. A properly designed system according to
the present invention may create a reservoir producing mechanism
that minimizes production problems and recovers significantly
greater volumes of liquid hydrocarbon reserves.
[0027] It is a feature of the present invention that the techniques
described herein may be used for maintaining a downhole reservoir
so that the liquid injector may operate independent of an
artificial lift system for the well. The methods of the present
invention may also utilize a liquid injector below an annular seal
or packer between the tubing and casing to provide for and control
the relief of wellbore gas pressure buildup above the liquid in the
wellbore and thereby optimize reservoir inflow performance. The
liquid injector may also be incorporated with a gas lift system to
achieve a design with enhanced wellbore to reservoir pressure
drawdown and inflow patterns. The techniques of the present
invention may be used to enhance hydrocarbon recovery from highly
deviated or horizontal wellbores, and may also be used in
directional well drilling and completion techniques.
[0028] One feature of the present system is that the injector
provides benefits from improved control by preventing formation gas
production with the production of liquids. The injector
incorporates an improved sand filter and may utilize a liquid
reservoir above a packer, and optionally employs a shutoff valve
located closer to the pump. The techniques of the present invention
may be used to minimize and prevent gas locking in pumped wells,
and also minimize the likelihood of gas blowout to surface by
allowing the injector to act as a downhole gas shutoff device. The
techniques of the present invention further result in improved
lubrication for the polished rod to minimize leakage of
hydrocarbons through the stuffing box. The present invention may be
used to effectively de-water gas wells by removing liquids that
prevent optimum gas production. In wells in which liquid
hydrocarbons are produced, gas waste is minimized and conservation
of gas enhances gas drive capabilities.
[0029] A significant feature of the present invention is the
improved long-term productivity and increased recovery of
hydrocarbon reserves of existing oilfields. In new fields, the
systems of the present invention provide an effective completion
option over existing technology. By retaining a high percentage of
natural gas within the reservoir and producing the oil by gravity
drainage, more oil is recovered.
[0030] An advantage of the present invention is that highly
sophisticated equipment and techniques are not required to
significantly improve the production of hydrocarbons. Another
significant advantage of the invention is the relatively low cost
of the equipment and operating techniques as described herein
compared to the significant advantages realized by the well
operator. Moreover, the useful life of other hydrocarbon production
equipment, such as downhole positive displacement pumps and
wellhead stuffing boxes, is improved by the system provided by this
invention.
[0031] These and further objects, features, and advantages of this
invention will become apparent from the following detailed
description, wherein reference is made to the figures in the
accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0032] FIG. 1 is a simplified pictorial view of an injector
according to the present invention suspended from a tubing string
within the interior in a casing of a wellbore. The downhole float
and valve mechanisms are simplistically depicted for easy
understanding of the injector.
[0033] FIG. 2 is a simplified pictorial view of one embodiment of a
liquid injector according to the present invention, including an
improved sand screen.
[0034] FIG. 3 illustrates an injector according to the present
invention incorporating a packer below a liquid reservoir and a gas
vent tube and a spring loaded check valve positioned above the
working liquid level.
[0035] FIG. 4 illustrates schematically the improved hydrocarbon
recovery performance provided by the liquid injector of the present
invention.
[0036] FIG. 5 illustrates the use of an injector in an application
for improving recovery of hydrocarbons from substantially depleted
zones.
[0037] FIG. 6 illustrates schematically improvements in gravity
drainage provided by the liquid injector of the present invention
and a liquid reservoir above a packer.
[0038] FIG. 7 illustrates an application of a liquid injector used
in a flowing well with gas lift.
[0039] FIG. 8 illustrates an application wherein a liquid injector
is used in combination with chamber gas lift with a bleed-off
control.
[0040] FIG. 9 illustrates the use of an injector according to the
present invention in a free flowing well.
[0041] FIG. 10 illustrates an injector used for gas control in a
horizontal well application.
[0042] FIG. 11 illustrates the use of an injector in an alternate
arrangement in a horizontal well application.
[0043] FIG. 12 illustrates another application wherein a liquid
injector is used with horizontal bore hole technology for enhanced
hydrocarbon recovery.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Injector Features and Operation
[0044] FIG. 1 simplistically illustrates the primary components of
a liquid injector 10 according to the present invention suspended
in a tubing string TS within a downhole well passing through a
hydrocarbon-bearing formation F. Injector 10 is thus positioned
within the lower end of a casing C which is perforated to allow
formation fluids to flow into the interior of the casing C and thus
surround the injector 10. Also simplistically shown in FIG. 1 is a
downhole pump P which may be powered by surface equipment such as a
pump jack (not shown), with the power being transmitted from the
surface to the pump via a sucker rod R positioned within the
production tubing string TS. The pump P includes a lower pump
traveling valve TV which allows fluids to pass upward from the
liquid injector 10 and into the pump, and then be transmitted
through the production tubing TS to the surface. As explained
further below, a liquid level LL within the casing C is ideally
maintained by the injector 10 to allow liquid hydrocarbons to be
transmitted to the pump P and then to the surface via the tubing
string TS, while the annulus A between the tubing string TS and the
casing C above the liquid level is occupied by pressurized gas.
[0045] The liquid injector 10 as shown in FIG. 1 includes an outer
housing 12 with a plurality of intake perforations 14 which allow
liquid within the interior of the casing C to flow into the
interior of the housing 12 and then into float 22 to surround
vertical tube 16 which is in fluid communication with the lower end
of the tubing string TS. An injector intake or shutoff valve 19
includes a valve member 18 that cooperates with shutoff seat 20 at
the lower end of the tube 16, and the valve member 18 in turn moves
with the float 22 which surrounds the tubing 16 to control the flow
of liquid into the tube 16. The downhole float 22 thus operates in
response to the liquids which surround it within housing 12. Valve
member 18 thus lowers with respect to the housing 12 when the float
22 is filled with liquid, thereby opening the shutoff valve 19 and
allowing liquids to flow upward into the tubing string past a
standing or check valve 24 and enter the pump P. For most
operations in which a pump P is used, the standing valve is part of
the pump P and is immediately below the traveling valve TV, When
gas in the annulus A displaces the liquid so that the liquid no
longer flows through ports 14 into the float 22, the float 22 rises
to close the valve 19 and prevent gas from entering the interior of
the tubing string TS. The basic operation of the injector 10 is
thus relatively simple, and the injector itself is inexpensive and
reliable. The standing or check valve 24 thus prevents fluids which
pass upward past this valve from returning by gravity back to the
injector. Those skilled in the art will appreciate that the float
22 may have various configurations, and that other arrangements may
be used so that the shutoff valve 19 is automatically responsive to
the operation of the float.
[0046] FIG. 2 illustrates a modified liquid injector 26 according
to the present invention which may similarly be suspended from a
tubing string TS as shown in FIG. 1. The liquid injector 26
includes components previously described and, although the
configuration of the components may be altered, the same reference
numbers are used herein for functionally similar components. The
injector 26 thus includes a float 22 moveable within a housing 12.
At the lower end of the housing 12, a bull plug 28 is removable for
threading a closed lower pipe which serves as a sand reservoir to
the injector. For the embodiment shown in FIG. 2, valve member 19
has been replaced by a combination of an elongate moveable valve
stem 30 and a valve body 32 positioned closely adjacent seat 20.
The valve stem 30 is secured to the float 22 as previously
described, although it is apparent that the intake or shutoff valve
19 for the injector 26 has been substantially raised compared to
the previously described embodiment. Also, fluid flowing up to the
shutoff valve 19 travels upward through a smaller diameter flow
tube 16, where it may continue upward to a pump P as previously
described. Immediately above the shutoff valve 19 is the standing
valve 24 for the pump, as previously described. As with the
operation of the previously described injector, the float lowers
and raises the valve stem 30 to open and close the valve 19 using
valve body 32. The valve body 32 opens to relieve the pressure
differential when the float drops, and the valve closes when gas
displaces the liquid. The valve body 32 has a relief port therein,
as more fully described in U.S. Pat. No. 3,451,477. In a suitable
application, the float 22 may have a three inch outer diameter and
a length of approximately 30 feet, and may be fabricated from 16
gauge metal. The outer housing or jacket 12 of the injector 26 may
have approximately a four inch outer diameter. FIG. 2 also shows an
injector head 34 for structurally interconnecting the tube with the
lower end of the production tubing PT. Also, it should be
understood that the shutoff valve 19 as shown in FIG. 2 may be used
in the lower part of the injector as shown in FIG. 1.
[0047] The housing 12 as shown in FIG. 2 does not include intake
openings 14 and instead a sleeve-shaped sand screen 36 is provided.
Fluids must thus pass through the sleeve-shaped screen 36 and into
the interior of the housing or jacket 12. In prior art liquid/gas
separators, the operation of the separator may be inhibited by
formation sand which may build up in the float and restrict
operation of the separator. The injector 26 as shown in FIG. 2
minimizes this problem by providing a sand filtering screen 36
across the primary fluid intake to the float. Various commercial
screens 36 may be used, such as the Johnson (US Filter) prepacked
screen or the Pall Corporation multilayer wire mesh screen. Screen
36 thus fits across or replaces a portion of the outer housing or
shell of the injector to minimize sand plugging problems, while
also not unduly restricting the flow of liquids into the injector.
Preferred screen 36 may also assist in recovery of hydrocarbons by
reducing foaming and separating liquids from gases. A preferred
screen 36 according to the present invention preferably is adapted
for blocking at least 90% of sand which has a particle size from 10
microns to 30 microns or larger from entering the interior of the
injector, while allowing those few particles smaller than that size
to pass through the screen and thus not unduly restrict fluid flow
or cause screen plugging. The screen 36 may have threaded upper and
lower ends for mating engagement with the housing 12 and with the
head 34 which connects the screen 36 with the tubing string TS. The
selection of the screen and its particle size blocking features
will depend to a large extent upon the formation conditions and the
downhole operations, and the characteristics of the desired screen
may be altered with experience.
[0048] The injector 26 as shown in FIG. 2 has its intake or shutoff
valve 19 for the injector positioned vertically upward relative to
a lowermost end of the float 22. In prior art liquid/gas
separators, there was conventionally a vertical spacing of
approximately 30 feet or more between the intake or shutoff valve
and any standing valve 24. When the lower shutoff valve closed,
pressure in the 30 foot line between these components was lowered
to a vacuum by the action of the pump P, which in some instances
caused the liquid hydrocarbons in this 30 foot line to vaporize.
When the lower shutoff valve then opened, the pumping systems could
become gas locked, The improvement to the injector as shown in FIG.
2 relocates the shutoff valve significantly upward in the injector
housing, and ideally immediately below the standing valve 24. More
particularly, the vertical space between the shutoff valve 19 and
the standing valve 24 is essentially eliminated and is now ideally
less than ten times the outer nominal diameter of the housing 12,
and preferably is less than about three times the outer nominal
diameter of the housing 12. The shutoff valve is thus operated by
long slender rod 30 affixed to the bottom of the float 22, with the
rod extending upward toward the shutoff seat 20. By providing the
shutoff valve closely adjacent the standing valve 24, the volume
between these valves is reduced to allow immediate entry of liquid
under wellbore pressure when the shutoff valve opens.
[0049] The design as shown in FIG. 2 thus solves two problems with
prior art separation devices. First liquids in the long intake tube
16 do not remain under wellbore pressure when the shutoff valve is
closed, which reduces the problem of pump gas lock as described
above. Secondly, by raising the shutoff valve 19, it is kept out of
the lower area of the float in which, sand which passes through the
filter 36 would likely settle during the time the valve is closed,
thus minimizing the possibility of sand plugging. The filter 36 as
described above provides an improved screening device which
significantly increases protection to the entry of very fine grain
sand within the injector and minimizes a likelihood of plugging,
while also serving to break up foams in the wellbore to enhance the
flow of liquids into the injector. The combination of the filter
screen 36 and the repositioning of the injector shutoff valve 19 as
shown in FIG. 2 thus significantly improves the operation of the
injector.
Liquid Reservoir Above Packer
[0050] FIG. 3 depicts another arrangement of a liquid injector 54
according to the present invention. The components of the injector
54 are not being depicted in FIG. 3 since it may be understood that
those components may conform to the previously described
embodiments. The outer housing 12 of the injector 54 includes a
plurality of openings 14 which allow fluids to enter the interior
of the injector from the annulus radially outward of the injector.
The basic operation of the injector 54 is as previously
described.
[0051] For the embodiment as shown in FIG. 3, a downhole packer 44
is provided between the injector 54 and the casing C. A gas vent
tube 46 sealingly passes through the packer 44 and extends upward
to above the working level of the liquid LL within the casing C, as
shown in FIG. 3. It should be understood that the annulus A between
the tubular string TS and the casing C above the liquid level LL is
occupied by gas, while the annulus below the liquid level LL as
shown in FIG. 3 is filled with liquid. A spring loaded check valve
48 is provided at the upper end of the gas vent tube 46 and within
the gaseous portion of the annulus. The spring loaded check valve
48 ensures that the pressure in the wellbore remains adequate to
lift liquid in the annulus A well above tubing inlet ports 40. This
gas vent system thus provides a gas venting and production system
and maintains an adequate lift for the working fluid level to
prevent the pump P from operating against a closed valve as more
fully explained below.
[0052] In an artificial lift system utilizing a downhole pump P and
an injector 54, the intake to the pump P is positively closed when
the float shutoff valve closes. Unless the pump is programmed by
downhole detection or surface energy output measuring devices to
shut off, the pump operation will continue against the closed valve
and thus waste energy. Also when the shutoff valve opens, liquid is
forced into the depressurized flow tube 16 and this jetting action
may induce vaporization. Operating against the closed injector
valve, the pumping system inefficiently raises and lowers the
entire volume of fluid within the tubing on each pump upstroke and
downstroke. Moreover, each upstroke produces a vacuum below the
standing valve which adds an additional pump load. When the
separator shutoff valve opens while the volume below the standing
valve is at a reduced pressure, liquid would be jetted through the
separator shutoff valve and may be depressurized such that gas in
solution with the crude oil may expand to flash and separate. Such
a flashing could cause several undesirable consequences, including
cooling and thus the creation of paraffins or solids participation,
or the creation of a gas volume within the pump chamber which would
prevent 100% liquid fill up and thus reduce the efficiency of the
pump. These same problems would occur with other types of
artificial lift pumping systems, such as electric submersible pumps
or hydraulic positive displacement pumps.
[0053] The system as shown in FIG. 3 prevents pumping against a
closed shutoff valve by providing a packer 44 to seal the annulus
between the tubing string TS and the casing C above the liquid
injector, and providing openings 40 from the annulus between the
tubing and the casing above the packer but below the pump intake.
Liquids from the formation thus flow into the interior of the
injector housing and upward past the packer 44, and then through a
check valve 25. This annular liquid chamber LC thus forms a
vertical reservoir from which the pump P may draw fluid. As shown
in FIG. 3, the injector 54 in the improved embodiment eliminates
the above-described problems for prior art separators by providing
a reservoir of liquid such that the pump intake is not directly
supplied only by fluid passing at that moment through the injector
shutoff valve, but also by liquid in the reservoir which flows
through the annulus openings 40. The injector 54 and the pump P may
thus operate independently in response to the liquid reservoir, and
may operate continuously or intermittently as dictated by the
producing formation and the injector and pump interaction. The pump
P thus preferably will operate as dictated by the level of liquid
in this vertical reservoir. A significant advantage of this concept
is that the pump operation may be monitored and controlled from the
surface such that it need not be operated when it does not have a
sufficient liquid supply to the pump intake. Nevertheless, while
the pump is inactive, the formation may continue to produce from
the reservoir and through the injector. Any formation liquids
produced from the reservoir are thus captured and easily recovered
when the pump is subsequently activated. By adjusting the pump
speed to maintain a working liquid level LL above the pump intake,
optimum gas production is assured while short shut-in periods and
repeated actuation of the injector valves are smoothed out. Longer
term loss of fluid intake may be handled by timed or sensed
pump-off controls while production would continue into the
reservoir while the pump was shut off.
[0054] The vertical liquid reservoir as shown in FIG. 3 is thus
created in the annulus between the tubing and casing and above the
packer or other seal 44. The packer 44 in turn is positioned above
the injector shutoff valve. The openings 40 above the packer 44
establish communication between (a) the interior chamber axially
positioned between the standing valve 24 and the packer 44, and (b)
the surrounding annular vertical reservoir axially between the
packer 44 and the liquid level LL. These openings 40 thus allow
fluid access between the reservoir to both the standing valve and
the pump intake. As long as liquid production from the producing
formation equals or exceeds the volume of the pump output to the
surface, the system as shown in FIG. 3 operates at maximum
efficiency. Should the injector liquid output exceed the pump
output, the liquid level within the annular reservoir would rise.
This fluid level rise would continue until the hydrostatic pressure
of the liquid at the injector valve level equaled the producing
formation pressure available to move the liquid out of the
injector. In effect, the liquid reservoir above the packer thus
lets formation pressure move liquid independently of pump output so
that the pump may be stopped when liquid level drops while the
formation keeps producing.
[0055] It should be understood that the system as shown in FIG. 3
permits two controls from the surface to more efficiently control
the downhole fluid producing system. Because the annular reservoir
above the packer 44 allows continual liquid production from the
formation independent of the pump, the downhole pump may be stopped
when it does not have liquid to supply its intake. A suitable
control mechanism for stopping the pump may be a flow/no-flow
detector in the surface flow line, or other conventional detectors
which monitor pump load electronically. Once the pump is stopped,
it may be programmed to restart automatically after a specified
time period, during which liquid is again building in the annular
reservoir. The system as shown in FIG. 3 assures optimum
hydrocarbon production by adjusting the pump speed to maintain the
working fluid level above the pump intake. A suitable pump-off
control permits longer term pump operation and, most importantly,
production from the reservoir through the wellbore continues when
the pump shuts off. As with conventional artificial lift
operations, it would be a desirable design for the pump capacity to
closely match formation liquid production.
[0056] The second surface control is obtained by monitoring and
controlling the gas pressure in the annulus A. If no gas is bled
from the annulus at the surface, no gas may be produced by the
system described herein. The formation to wellbore pressure
differential necessary to move liquid through the formation may
thus be achieved solely by liquid removal via the wellbore.
Depending on particular formation and fluid properties and the
producing fluid drive mechanism in effect within the producing
formation, however, some gas may be bled off at the surface to
optimize production or to relieve the buildup. This may be achieved
by using available back pressure control devices which may bleed
the desired volume of gas into a well surface flow line or into a
surface located liquid/gas separator unit. The vent tube 46 as
shown in FIG. 3 thus allows gas to move from the formation into an
annulus between the tubing and the casing. The tube 46 functions to
convey gas through the annular liquid reservoir so that it does not
bubble up through the liquid and thus become entrapped or go into
solution in the crude and enter the suction of a pump. A method of
passing gas from the below the packer 44 to the upper portion of
the annulus is desirably obtained without gas contacting the liquid
in the annular reservoir. The length of the tube 46 would thus be
designed so that it extends above the expected height of the liquid
in the annulus at its maximum working level. The check valve 48
prevents liquid from reentering the tube 46 and flowing to the
formation. The back-pressure control mechanism described above may
be simplistically obtained by providing a spring 50 for holding the
valve 48 closed. Valve 48 thus effectively acts as a back-pressure
device to ensure that there will always be a higher level of gas
pressure in the formation to drive liquid to the injector and
upward through the annular reservoir, independent of the pressure
of gas in the annulus. For example, if the chosen spring loading on
the valve 48 required 200 psi differential to open, even if the
annulus pressure were bled to atmosphere at the surface, a 200 psi
formation pressure would be available to lift liquid to the annular
reservoir. Should a surface valve in communication with the annulus
be closed, the valve 48. would still maintain formation pressure at
a higher level and liquid would be transferred upward until the
liquid level build up equaled reservoir pressure in the
wellbore.
[0057] The system as shown in FIG. 3 thus provides a method of
creating a reservoir of liquid to more efficiently supply the pump
P. Liquid may be continuously transferred from the injector to the
liquid reservoir and from the liquid reservoir to the pump by the
appropriate openings 40. This method also assures that a pressure
differential is available to provide formation energy to lift
liquid into the annular reservoir. By providing the back-pressure
feature as discussed above, the optimum pressure differential
around the wellbore may be obtained for maximum formation fluid
movement and hydrocarbon recovery. This system achieves these
objectives while eliminating or minimizing the production of
natural gas and maintaining its valuable contribution as an energy
source to efficiently deplete the oil zone within the downhole
formation. In many isolated locations where liquid hydrocarbons are
produced but wherein a gas pipeline is not accessible, gas would
otherwise have to be flared and thus wasted. The system of the
present invention allows for the production of oil while avoiding
these flaring problems and also maximizes the production of liquid
hydrocarbons from the formation.
[0058] The injector according to the present invention may also be
used with an improved gas pumping power unit, such as that
disclosed in U.S. Pat. No. 3,971,213 hereby incorporated by
reference. The pumping unit as disclosed in the '213 patent
describes a sucker rod pumping unit that may be powered by natural
gas drawn from the annulus between the tubing and the casing of a
well. This gas pressure, which need only be a minimal amount of gas
above a flow-line pressure, may be used to power a piston which in
turn actuates the beam of a pumping unit. The advantages obtained
by this system include operation of the pump with a low incremental
pressure while allowing the return of used gas to a sales line, and
also counterbalancing of the system with pressure energy stored in
the hollow substructure of the unit. The pumping unit as described
in the '213 patent may thus be used in conjunction with the
downhole injector as disclosed herein to create a producing system
that may operate at minimum cost, and without the expense and
maintenance of an electrical gas powered motor drive unit at the
surface.
[0059] Another modification to the system shown in FIG. 3 will be
to provide another check valve 25 above the packer 44, and one or
more tubes 52, open to the tubing TS directly below a disk or plug
in the tubing below ports 40, which provide fluid communication
from above the check valve to the annulus above the packer. Any gas
in solution which does enter the interior of the injector may thus
pass through the check valve 25 and then the discharge tube 52 to
move upward to the working fluid level rather than passing through
the standing valve and to the pump. Gas is then discharged into the
chamber below the liquid level LL but above the ports 40, so that
the gas migrates upward to the liquid level LL and into the gaseous
annulus above that level. Liquid, on the other hand, enters the
pump P from the annulus at a position below the discharge from the
one or more tubes 52, so that little if any gas flows from the
annulus into the pump during its operation.
[0060] In another embodiment of this fluid reversal concept and
which serves the purpose of tubes 52, the check valve 25 may be
located below injector head 34 within a short sub essentially
having the diameter of tubing TS. This sub with check valve 25
would be directly connected to tube 16. Above head 34, another
tubing sub of a length of at least 6 to 10 feet would contain a
vertical divider which creates two flow passages: one closed at the
top to the production tubing string and ported to the annulus at
its topmost location and open at the bottom to the flow from
injector 54, and the other closed at the bottom to the flow from
the injector 54 and having ports open to the annulus at the bottom
and open at the top to standing valve 24.
Efficient Gas Production
[0061] It should also be understood that gas production from the
reservoir may also be allowed according to this invention. Tube 46
through the packer 44 as shown in FIG. 3 extends to above the
expected liquid level LL to allow for gas flow. The check valve 48
at the top of the tube 46 prevents liquid reentry below the packer.
By applying back pressure control on the vent tube 46 via a spring
mechanism 50, a lower annulus pressure above the liquid may be
maintained to create a pressure differential for the desired liquid
level and fluid flow, as well as a controlled relief of reservoir
gas from formation F and below the packer 44 to above the liquid
level LL and to the annulus A between the tubing and the casing.
Various other fluid reentry and reversal mechanisms not shown in
FIG. 3 may also be used in conjunction with the vent tube 46.
[0062] Moreover, the system as shown in FIG. 3 may be used in
dewatering applications for gas wells. As previously noted,
providing a reservoir above packer 44 lets formation pressure move
liquid independently of pump output. The pump P may thus be stopped
when liquid level drops, while the formation keeps producing. This
particular configuration also provides a method of desirably
pumping liquid accumulations off of a gas well and thus increase
gas production. The liquid may be condensate (a liquid gas), or may
be condensate combined with water. In the case of condensate
accumulation, the liquid reservoir provides a superior method of
pumping compared to prior art techniques. As discussed above,
vaporization leads directly to gas locking problems for the pumping
operation (both in oil wells and gas wells with condensate and/or
oil). The technique of this invention desirably avoids vaporization
and reduces pumping inefficiency. As for water accumulation, water
may accumulate in the vertical reservoir above the packers 44 and
be efficiently pumped off rather than build up around the
perforations of the gas producing formation where the water may
cause an undesirable spray-type disturbance in the well annulus.
The injector as shown in FIG. 3 may also be used in conjunction
with horizontal wells as described subsequently to obtain and
enhance recovery and improve reservoir performance. The system of
this invention is also more accommodating to gravel packed wells
since it reduces fluid inflow velocity and wellbore damage.
Improved Reservoir Performance
[0063] By improving the features and operation of the injector as
described above, significant benefits may be obtained by retaining
in situ formation natural gas or injected gas within the reservoir
to effect increased recovery of liquid hydrocarbons. Rather than
use the natural gas energy to immediately produce high quantities
of hydrocarbons and thus deplete the formation, the concept of the
present invention retains the energy of the natural gas as a
driving fluid to achieve desirable initial liquid hydrocarbon flow
rates and significantly higher long-term liquid hydrocarbon flow
rates compared to prior art techniques, without damaging the
reservoir. The basic concept of the method according to the present
invention may be shown with respect to FIG. 4, which depicts an
idealized vertically thick reservoir with the oil bearing formation
F having a good continuous vertical permeability, and with either
initial gas cap GC or highly saturated crude above the formation
that forms a secondary gas cap with pressure reduction. According
to conventional practice, the lower part of the formation would be
open to the reservoir and hydrocarbons would be produced at the
highest rate possible along with the gas. This action would quickly
deplete the near wellbore liquid zone as the gas would tend to cone
towards the pressure depleted zone, driving oil into the well. This
conventional coning would result in a gas to liquid interface as
shown in dashed lines in FIG. 4. This coning is highly undesirable
since it significantly reduces the ultimate oil recovery and
prematurely depletes the gas reserve. Coning is thus avoided or at
least minimized according to the techniques of the present
invention.
[0064] As shown in FIG. 4, a packer 44 is provided in the annulus
between the casing C and the production tubing string TS. The
casing above the formation F, including the gas zone, is also
perforated. Gas in the wellbore below the packer 44 and above the
liquid level LL returns to aid the gas cap, and is kept out of the
tubing string TS by the injector 54. According to the present
invention, gas is refused entry into the wellbore due to the
operation of the injector 54 (which may have the features of the
injectors previously described), and thus gas may stay within the
reservoir. This scenario forces the reservoir to maintain a
substantially horizontal interface between the liquid hydrocarbons
in the formation F and the gas cap GC, which acts on the liquid
from the top down and tends to aid gravity drainage of the liquid
down and then laterally into the wellbore.
[0065] It should be apparent to those skilled in the art that not
all reservoirs will respond to this forced gas drive mechanism as
described above. Liquid producing rates would likely be lower
initially as the gas drive acceleration and natural gas lift is
eliminated. By forcing the return of gas from the top of the
wellbore back into the gas cap within the same well, optimum
resistance-free completions and pressure differentials adequate to
drive the gas back into the formation will be required. This
desired pressure differential may be generated by pressure below
the packer 44 and in the gas zone GC reflecting the higher pressure
at the bottom of a liquid column in and near the injector 54,
wherein said higher pressure results from the hydrostatic head of
liquid in a relatively thick formation. It will be described later
how the return of produced gas in the wellbore may be accomplished
or aided by other mechanical means.
[0066] A pressure differential from the wellbore to the formation
may be created in the upper part of the gas column within the
wellbore by the rising liquid column which builds after the
injector closes to shut in the gas. That pressure differential will
try to displace gas back to the formation, although that pressure
differential is typically quite small and, except for applications
with thick reservoirs of several hundred feet or more, the
formation may not be sufficiently permeable for gas to go back into
the reservoir. A small pressure differential may thus not
effectively prevent continued gas build up in the wellbore. The
liquid/gas interface may thus move relatively quickly downward to
the injector intake, while the interface would likely rise very
slowly to cause only intermittent opening of the injector.
Reservoir studies may be necessary in some applications to define
the requirements and physical characteristics of reservoirs that
will be conducive to the improved performance according to the
present invention, and to analyze the relative economics of the
present invention compared to conventional hydrocarbon exploration
and recovery techniques. Many reservoirs should, however, benefit
from the concepts of the present invention and will result in
significantly improved performance.
[0067] The concepts of the present invention may also be extended
to applicable reservoir situations for secondary and tertiary
recovery by maintaining gas in the reservoir according to the
present invention and then adding gas with a conventional secondary
or tertiary injection operation. Thus the concepts of the present
invention and the maintenance of the formation gases when combined
with injected gases, such as carbon dioxide, nitrogen, natural gas
or steam, may further assist in recovery of hydrocarbons.
Applicable gas driving mechanism may thus be initiated or enhanced
in older reservoirs in which the natural gas has been substantially
depleted. The injector of the present invention will, of course,
also tend to maintain any injected gas in the formation rather than
recovering the ejected gas to the surface and then again
reinjecting the gas. FIG. 5 depicts a secondary or tertiary
recovery operation with an injector 54 in the lower part of a
wellbore. A gas injection string 56 extends from the surface
downhole through the packer 44 to supply pressurized gas to the gas
cap GC. A check valve 57 optionally may be provided at the lower
end of the injection line 56, and possibly within the packer 44, to
prevent fluid from flowing upward past the packer through the
injection line 56. Conventional compressors (if needed) would
typically be provided at the surface for this gas injection
operation. FIG. 5 thus depicts gas supplying the cap GC both from
the lower part of the wellbore where gas is prohibited from
entering the tubing string TS by the injector 54, and from the gas
above the liquid level LL which is input to the wellbore and to the
gas cap GC by injection string 56. It should be understood that
such gas injection could also occur through a separate well as is
the case in many gas reinjection, re-pressuring projects, or gas
storage reservoirs. The pump P as previously described is not shown
in FIGS. 4 and 5, but in many applications a downwhole pump will be
provided above the injector 54 for pumping fluids to the surface
through the production tubing string TS.
[0068] Liquid hydrocarbons may thus be recovered according to the
present invention from an underground formation without producing
natural gas with the liquid hydrocarbons. By positioning the
injector as described above downhole in the wellbore adjacent to
the producing formation, the pressure energy of the gas will be
maintained to flow the liquid hydrocarbons into a producing tubular
string and then to the surface. Such a system may have sufficient
gas pressure to lift or flow a column of liquid to the surface
without the use of an artificial lift system, so that the system
comprises only a production tubing string and a downhole injector.
The injector may be open to the producing formation and operated
within the casing string for retaining gas in the formation. The
entire annular area between the tubing and the casing may thus be
exposed to formation fluids at essentially formation pressure. The
flowing bottom hole pressure of gas and liquid at the intake to the
injector may thus be the energy sufficient to move liquids through
the injector and through the production tubing string to the
surface.
[0069] Flowing oil wells are commonly assisted by the incorporation
of gas in the liquid column, either as slugs from the formation or
as gas breakout through pressure production as the liquid rises
within the tubing. Such gas incorporation reduces the average
density of the flowing fluid and thereby requires less fluid
pressure energy to lift the hydrocarbons to the surface. Separating
gas at the bottom of the wellbore by the injector according to this
invention may thus increase the average density of the flowing
fluid and may thus require a higher pressure to lift the fluid.
[0070] In open annulus wells as described above, the injector may
separate liquid from gas within the wellbore and flow liquids to
the surface while also providing gas formation pressure exceeding
the hydrostatic head of the fluid column, plus the flow line back
pressure. Such configuration is not common because it is generally
not desired to expose the annulus and thus expose the casing itself
to higher formation pressures. Thus wells with formation pressures
high enough to flow, and particularly deeper wells, are generally
equipped with a packer or sealing device located at the bottom of
the tubing string to seal the annulus between the casing and the
tubing and thereby isolate formation pressure from below the packer
and within the tubing string. The annular volume in deep, high
pressure wells may be substantially filled with brine or another
heavier-than-water liquid containing a corrosion inhibitor. Such
fluids and attended monitoring schemes assure that high pressure
does not leak into the annulus. In wells with a packer which seals
with the annulus, the injector according to the present invention
may still be used to separate liquid and gas and thus conserve the
gas and its associated energy within the casing. FIG. 4 thus
illustrates this concept, with the injector located below the
packer. The vent tube 46 as discussed above need not be provided
for the embodiment shown in FIG. 4. The gas energy may still be
used to flow the liquid hydrocarbons to the surface.
[0071] The injector of the present invention may thus be used
adjacent to a producing formation and in a flowing well to avoid
producing natural gas. By providing the injector 54 below a packer
44 in high pressure wells, the annulus between the tubing and the
casing may be sealed from formation pressure. The injector 54 below
the packer may also be used in a well produced by an artificial
lift system, wherein the artificial lift method is a closed loop
gas lift operated with minimum need for supplemental gas from the
formation. The injector of the present invention may thus be used
in numerous applications where gas production is undesired,
wasteful, or prohibited.
[0072] FIG. 6 illustrates another application using the injector 54
of this invention. In this application, a thick reservoir includes
a lower oil bearing formation F and an upper gas cap GC. The
injector 52 is suspended in the well from a production tubing
string TS. A packer 44 is provided to seal the annulus between the
tubing string TS and the casing C at a position above the gas cap
GC. The injector 54 prevents entry of gas into the tubing string so
that gas moves upward in the annulus to rise above the liquid level
LL and reenters the formation. The gas cap moves downward from the
interface shown in dashed lines to the interface shown in solid
lines, and thereby moves the liquid down and toward the well
without coning. Crossover ports 88 in the tubing string TS above
the packer 44 allow communication back to the annulus. Standing
valve 24 is provided above the crossover ports 88, and the pump P
powered by rod string R is then provided above the standing valve.
The annulus above the packer 44 thus obtains a working flow level
for efficient operation of the pump P, as previously described.
[0073] The above-described systems, in conjunction with the
injector 54, allow the formation to produce sufficiently without
gas breakthrough or coning, yet utilizes formation gas to assist in
the flowing and/or artificial lift at the well, This downhole
system may allow for the bleed off of a controlled amount of
formation gas entrapped by the producing system to allow the
efficient production of liquids from the formation, as will be
described. The downhole system may also maintain an optimum
predetermined pressure differential between the wellbore and the
formation. As noted above, a packer may be used in many
applications, but need not always be provided. Formation gas may
thus be effectively utilized to help lift liquids from the well in
a manner which uses the advantages of producing a well with a
downhole injector but permits only liquid production through the
injector.
[0074] A variation of the above described embodiment incorporates
gas lift with a packer 44 in the annulus between the tubing and the
casing, as shown in FIG. 7. This system utilizes gas lift valves LV
positioned along the tubing string TS and above the packer to help
produce liquid from the liquid injector to the surface. The surface
equipment depicted in FIG. 7 includes a surface liquid/gas
separator unit 66 with a liquid hydrocarbon flowline 68 extending
therefrom. Gas from the separator 66 may flow via line 70 to
compressor 72, which in turn is powered by gas engine 74. The
pressurized gas is then circulated in a direct loop, and may be
discharged back into the well to act on the lift valves LV and help
bring the liquid hydrocarbon to the surface. A further explanation
of the lift valves LV is discussed below.
[0075] The system as shown in FIG. 8 uses a lower packer 44 and an
upper packer 78 to create a chamber 80 in the annulus between the
tubing and the casing. This chamber may be fluidly connected to the
wellbore below the lower packer 44, which is open to the formation
F, by a vent line 82. As shown in FIG. 8, the lower packer 44 thus
incorporates a tube 82 with a check valve 84 at its upper end. This
tube 82 allows the release of formation gas to the chamber 80, so
that gas pressure builds up above the lower packer 44. The check
valve 84 prevents communication from the chamber 80 back to the
formation and closes the chamber 80 so that a gas charge may be
built up for the gas lift process. Within the chamber 80, one or
more lift valves LV may sense and maintain pressure in the chamber
80 at a level sufficient to create the desired differential from
the reservoir to the wellbore. Accordingly, when pressure builds
above this level, formation gas is discharged from the chamber 80
to the tubing and thus to the surface. Additional lift valves in
the chamber may sense the level of liquids rising in the tubing and
open to lift the liquid upward to an upper gas lift valve.
[0076] A significant advantage of the system as shown in FIG. 8 is
that gas production may be controlled and utilized for lifting
purposes, but no free gas is allowed to flow into the open tubular
through the injector 54. The gas lift valves LV allow for such
pressure control in the lower chamber 80 and sensing of fluid slugs
S in the tubing string TS. Conventional gas lift technology is thus
combined with the injector 54 of the present invention to permit
only the flow of liquids from the reservoir and retain gas cap
pressure to enhance gravity flow. Moreover, the system as shown in
FIG. 8 provides for the controlled bleed off of gas pressure under
the lower packer 44 within the wellbore and directly utilizes that
bled off gas to help the lift valves 86 to produce the desired
liquid from the tubing string.
[0077] Two gas lift valves are shown within the chamber 80, but
those skilled in the art will realize that additional gas valves
may be desired or necessary for additional volume. The upper valve,
which is commonly known as a casing pressure operated valve, will
typically be set by internal bellows precharging to a known
pressure and will thus act as a regulator. This will ensure that
pressure in the chamber 80 and the corresponding wellbore pressure
will never exceed the desired wellbore pressure limit selected by
the productivity index analysis for optimum reservoir fluid inflow.
This upper regulator valve will thus open and discharge gas into
the tubing when chamber pressure exceeds its predetermined setting.
Gas discharged into the tubing will aid in lifting any liquid
within the tubing to the surface. The lower lift valve, which is
the tubing pressure controlled valve, is designed to open at a
preselected internal tubing pressure reached by the increasing
column of liquid above this valve. When the injector allows
sufficient inflow, the lower gas lift valve opens, then gas buildup
in the chamber 80 suddenly flows under the liquid slug, lifting the
liquid farther up the tubing string. These gas lift valves are also
commonly referred to as intermitting valves.
[0078] The combination of injector and gas lift valves as described
above may also be incorporated into an artificial lift system in
which the primary lift mechanism is the closed system operating
with gas lift valves above the upper packer. In operation, liquid
slugs may be partially lifted by the relief formation gas coming
from the lower chamber to be picked up by the main gas lift system
86 above the upper packer 78, so that the liquid slug is carried to
the surface. Accordingly, the formation F and chamber 80 may be
maintained at a pressure of, e.g., 1,000 psi, or approximately 500
psi below shut-in reservoir pressure. This 1,000 psi will be
available to the lower chamber valve to assist in lifting liquid
slugs when it is activated to do so. The main lift valves 86 may be
responsive to annulus pressure above the upper packer 78, required
to assist in driving the liquid slugs S to the well head W.
Conventional liquid/gas separation, processing, and decompression
mechanisms provided at the surface may extract the desired liquids
and recycle the gas through the artificial lift system. The system
components 66, 68, 70, 72 and 74 were previously described. Excess
gas introduced from the formation and input to the tubing string
from the lower relief chamber 80 may be partially utilized as fuel
for the compressor prime mover 74, which reduces the gas produced
by the well system. Reservoir and facility engineering calculations
may be used to determine the estimated amount of formation gas to
be utilized to achieve the desired well productivity. Site specific
conditions will influence the design to properly utilize any excess
produced gas, whether for sales line, minimal flaring or
reinjection into another zone or well. By using known reservoir and
gas lift engineering techniques, the system of the present
invention may be designed to maintain a desired pressure
differential between the interior of the wellbore and the formation
to create the desired reservoir fluid inflow.
Flowing Well Applications
[0079] As previously noted, the liquid injector of the present
invention may be used in artificial lifted wells. By obtaining the
significant advantages of retaining in situ gas within the
reservoir, however, the liquid injector may contribute to liquid
hydrocarbon recovery from a high pressure flowing well which will
have sufficient bottom-hole pressure to lift a column of reasonably
light fluid to the surface. In an isolated recovery location,
systems for handling produced gas would thus not be necessary,
thereby retaining the reservoir in an ideal condition. In one
application, a high pressure well may have the annulus between the
tubing and casing open to the reservoir. In another application,
the downhole packer 44 as shown in FIG. 4 may be placed in the
annulus between the tubing and the casing. If desired, the annulus
above the packer 44 may be filled with a protective fluid, such as
a drilling mud or a completion fluid.
[0080] FIG. 9 depicts high pressure gas acting downward on the
formation liquid through the gas cap GC and forcing the formation
liquid into the injector 54. The system as shown in FIG. 9 has a
high pressure in the formation to result in a free flowing well.
Liquid hydrocarbons thus pass upward in the tubing string to the
wellhead W at the subsurface without artificial lift. The system
may thus be operated without a packer between the tubing and the
casing, as shown in FIG. 9, for assisting in recovery from a
flowing well which does not utilize artificial lift. Liquid
hydrocarbons may thus flow out the line 58 from the wellhead W. Gas
in the annulus A between the tubing string TS and the casing C may
be maintained at a desired pressure by regulator 64 at the surface.
This pressure may be monitored by gauge 62, and is ideally
maintained at a safe yet sufficiently high level to maintain the
well in a free flowing condition. Excess gas may be economically
recovered through regulator 64.
Horizontal Well Applications
[0081] The techniques of the present invention are also applicable
to horizontal wellbore technology, wherein one or more horizontal
bore holes or laterals are drilled from and connected to a
substantially vertical well. Horizontal well technology may provide
a variety of downhole hydrocarbon recovery configurations. This
technology has the significant advantage of creating a longer and
more effective drainage system through the reservoir than
conventional vertical well technology. The injector of the present
invention may be applied in many of these applications to offer
substantial advantages over conventional vertical well hydrocarbon
recovery techniques.
[0082] A horizontal wellbore is generally parallel to the formation
and may thus be drilled and completed so as to be open to a
producing formation over a relatively long distance. The horizontal
wellbore or lateral thus has a much greater opportunity to collect
reservoir fluids for production to the surface, and productivity
for horizontal bore holes accordingly may be substantially
increased over conventional vertical wells. Horizontal wellbore
technology thus may recover a greater percentage of the oil and gas
from reserves compared to conventional vertical wellbore
technology. To accommodate the high volumes of fluid that may be
produced by the horizontal bore holes or laterals, the vertical
well with the injector therein should be large enough to
accommodate sufficiently sized tools of the present invention and
match the anticipated fluid production.
[0083] Various types of artificial lift systems may be used in
conjunction with the injector and the horizontal wellbore
technology. Pressure within the annulus of the well may be
controlled from the surface, as explained above, to control the
producing bottom hole pressure in each of the one or more wellbores
positioned within the producing zone. As previously noted, a packer
may be used above the producing zone to isolate the annulus between
the tubing and the casing for producing fluid, with the injector
then being provided below the packer. A system with an injector may
thus be reliably used for high pressure flow in horizontal well
applications. The injector as described above utilizes a float
concept such that the injector may be installed and operated in a
near-vertical position. This limitation does not limit the use of
this technology in horizontal well applications, however, as shown
in FIGS. 10, 11 and 12. Moreover, a modified float system or a
density sensor could be provided downhole for sensing the presence
of liquids or gas, and the shutoff valve could be electrically,
hydraulically or mechanically actuated in response to this modified
float system or density sensor so that the injector operation need
not be limited to a vertical or near-vertical orientation in the
wellbore.
[0084] The liquid injector according to the present invention thus
may be below or above the horizontal laterals and within the
vertical portion of the well. The horizontal configuration of the
producing wells as described above may be used to improve recovery
by gravity drainage as previously described, and there are distinct
advantages achieved by retaining gas energy within the formation in
horizontal well applications. In FIG. 10, the horizontal well
intersects the vertical well above the injector 54. The gas cap GC
forces the oil downward for collection by the horizontal bore hole.
Packer 44 serves its previously described purpose of preventing the
gas from moving up in the well annulus, and thus assists in
maintaining the desired gas cap GC. Accordingly, the casing C may
be perforated in the zone of the gas cap GC and above the liquid
level LL. Pump P drives the oil to the surface and, for this
application, is preferably a high volume electric submersible pump
P to pump large flow rates of oil through the tubing string TS.
Conventional electric submersible pump configurations would require
the addition of ports 40 and 88 as shown in FIGS. 3 and 6 to allow
fluid flow past the pump motor for cooling.
[0085] As shown in FIG. 10, one or more horizontal laterals may be
drilled from a substantially vertical wellbore within a single
substantially horizontal plane. One or more horizontal laterals may
thus each be initiated from a vertical hole by a pilot hole
utilized to start the horizontal bore hole. A pilot bit may be used
to cut a hole in the casing and start the horizontal lateral. The
pilot bit may then be retrieved and a conventional drilling tool
used to result in the horizontal bore hole. A retrievable whipstock
may be used so that the kick off tools do not interfere with the
subsequent placement of the injector in the bore hole. If a cement
plug is positioned on the vertical portion of the bore hole, the
plug may be drilled out after the horizontal bore holes are
completed.
[0086] FIG. 11 illustrates a horizontal bore hole drilled in
formation F below a gas cap GC as a continuation of the vertical
boreholes. The oil enters through a screened liner SL, typically
operating within a gravel-packed borehole. A variety of horizontal
drilling technologies may be used with the concepts of the present
invention. Both horizontal and highly angled holes extending from
the existing wellbore may be used to increase the area of drainage.
Conduits commonly referred to as drain holes may be configured as a
variety of jet drilled perforations or larger boreholes, or
short-radius drilled holes may also be used in conjunction with the
injector of the present invention.
[0087] After drilling the laterals, the injector 54 may then be
located within or above the producing formation and in the vertical
portion of the wellbore. As shown in FIG. 11, the non-vertical
wellbore lateral is provided below the injector 54 and will thus be
open to the producing fluids. This configuration allows for the
drilling and completion of the horizontal wellbore below the
vertical section of the well. The wellbore may be completely cased
or cemented down to at least the producing formation, thereby
positively containing fluid within the formation. In wells
requiring artificial lift, the injector and the intake to the pump
P may be located at a level sufficiently low relative to the
producing formation such that the available reservoir pressure in
the formation may lift liquids to at least the level of the pump.
The reservoir characteristics would thus determine the relative
height at which the injector and pump would be set, which in turn
would determine the horizontal drilling and completion
characteristics. To locate injector 54 as close to the producing
zone as possible will require use of existing shorter-radius
horizontal drilling and completion techniques. The annulus A above
the pump may be pressure controlled at the surface to monitor the
desired liquid level LL. Liquid hydrocarbons from the pump P are
thus produced to the surface through the production tubing string
TS.
[0088] Another example of horizontal well technology is shown in
FIG. 12, wherein a second layer of horizontal wellbores or laterals
extend from the vertical wellbore which contains the injector 54.
The upper wellbore lateral may be located within a gas zone and
above the relatively thick liquid bearing formation F. The injector
54 acts to circulate separated gas back to the reservoir and return
energy to the reservoir for driving oil from the formation rock. By
retaining the gas in the formation and separating the gas downhole,
expensive equipment and techniques involving the recovery of the
gas energy and the subsequent reinjection of the gas back into the
formation are thus avoided. It is understood that more than one
wellbore may be extended laterally from the vertical-wellbore in
both the gas cap and the producing formation and in different
directions to encompass a larger drainage area. This technique is
commonly referred to as using multi-laterals.
[0089] By using the liquid injector of the present invention in
conjunction with one or more laterals or otherwise substantially
horizontal wellbore fluid conduits which extend a long distance
into producing formation, the productivity from the well may be
substantially enhanced. The injector may be used to freely transmit
liquids into the production tubing string while preventing the
entry of gas to the surface. By providing the injector at or near
the level of the producing formation and within the essentially
vertical bore hole which is open to one or more horizontal
laterals, liquid production from one or more horizontal bore holes
may significantly increase and free gas is provided back through
the producing formation, optionally to one or more separate
horizontal bores or conduits at a level higher within the
formation. FIG. 12 thus discloses another possible advantage of
using the horizontal well completion technology with a second bore
hole positioned in the gas cap to facilitate gravity drainage by
enhanced gas pressure in the gas cap. The enhanced gas cap
maintained by the upper lateral in the upper part of the reservoir
thus contributes to the production of the liquids from the lower
lateral. By providing a packer in the well as shown in FIGS. 10 and
12, the techniques of the present invention may be self-sustaining
by the forced return of gas to upper zones.
[0090] FIG. 12 illustrates how the injector 54 may be used in a
vertical section of the well which has one or more horizontal bores
each drilled from different levels. Combining an injector of the
present invention with high productivity from lateral wells while
also retaining the reservoir gas energy downhole is an effective
approach to maximize hydrocarbon recovery. Various types of pumps
such as an electric submersible pump may be used in combination
with an injector to create an efficient and high-volume producing
well. As shown in FIG. 12, a horizontal bore hole through an upper
section may be used to convey injected gas deep into the reservoir
for a more effective drive mechanism to the horizontal producing
wellbore. This system with upper and lower horizontal wellbores
would circulate and retain gas which is prevented from moving into
the tubing string by the injector and thus is maintained in the
downhole formation. As previously disclosed, the gas pressure below
the packer 44 may maintain a desired liquid level LL in the annulus
above the packer, with the crossover ports 88 above the packer
serving the purpose previously described.
[0091] A system similar to that shown in FIG. 12 provides for
strongly enhanced recovery using secondary or tertiary recovery
methods through which pressure depleted reservoirs could be made to
produce at higher levels. Using two horizontal bore holes from
different vertical wells,.gas from the surface may also be used to
assist the driving concept. The injection line 56 thus extends from
the surface through the downhole packer 44 to assist in maintaining
an effective gas cap GC. Check valve 57 optionally may be provided
along line 56 to limit gas flow along line 56 to the downward
direction. The concepts of the present invention may also be
applicable to a version of "huff and puff" recovery technology in
which gas is injected for a period of time then suspended while
liquid buildup is produced. The gas zone for pressurizing could be
injected from an offset well, preferably located structurally close
to the recovery well.
[0092] In a dual packer embodiment used with horizontal technology,
the tubing regulator mechanism may be used to control and trap gas
relief from the wellbore into the chamber between the packers and
thus provide the desired pressure differential from formation to
wellbore, while the injector prevents free gas production. Gas in
the chamber between the packers may further act as the first
lifting stage for slugs of liquid entering the tubing. The injector
of the present invention may thus substantially assist the
productivity of horizontal wells by utilizing the free gas
prevented from going into the tubing string by the injector to
enhance liquid production. In an alternate embodiment, a packer is
positioned in the wellbore between the upper gas injector laterals
and the lower fluid recovery laterals.
[0093] Various other embodiments may be possible utilizing the
injector of the present invention. The entire reservoir may be open
to the wellbore, and the formation isolated only below the packer.
Only liquid may be produced through the liquid injector and gas
recirculated back to the gas zone. The gas may also be injected
through the packer to replenish gas energy as previously described.
Gas re-entry into the gas zone is facilitated by the use of
horizontal lateral boreholes connected with the wellbore below the
packer. The liquid injector of the present invention may thus be
incorporated into existing or planned field gas injection programs
to help control gas breakthrough.
[0094] A significant feature of the injector and packer
configuration according to this invention, which is mentioned
briefly above, is the reduced risk of a well blowout. Gas is not
free to escape from a pump assisted well which includes the
injector as disclosed herein. Only the small amount of gas above
the packer, the oil above the pump and solution gas in liquids that
do pass through the injector would be available fuel for any
blowout. Accordingly, a well including the injector and the
technology of this invention may be more easily controlled if a
blowout does occur.
[0095] While the concepts of the present invention may work in
various types of wells, retaining gas within the reservoir and
recovering a high percentage of oils by gravity drainage is most
effective for use in thicker reservoirs in which a cap gas or
solution gas breakout is otherwise used as a mechanism to enhance
early production to the detriment of a longer, but more productive
oil recovery. By using the benefits of the injector and the
downhole gas shutoff as described herein, the proper reservoir
conditions may be identified and the recovery from the reservoir
optimized. Ideally, the reservoir is relatively thick and has good
vertical permeability. This provides a good mechanism for returning
gas to the gas cap and enhancing the gravity drainage system. If
gas were produced to create the optimum drawdown pressure in the
annulus, then the gas may be re-injected back into the reservoir
for conservation, and inefficient coning in the producing well
still controlled. The effectiveness of the system with nitrogen,
carbon dioxide and other injected gases is also practical.
[0096] The foregoing disclosure and description of the invention
are thus explanatory thereof. It will be appreciated by those
skilled in the art that various changes in the size, shape and
materials, as well in the details of the illustrated construction
and systems, combination of features, and methods as discussed
herein may be made without departing from this invention. Although
the invention has thus been described in detail for various
embodiments, it should be understood that this explanation is for
illustration, and the invention is not limited to these
embodiments. Modifications to the system and methods described
herein will be apparent to those skilled in the art in view of this
disclosure. Such modifications will be made without departing from
the invention, which is defined by the claims.
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