U.S. patent application number 13/928934 was filed with the patent office on 2014-01-02 for uplifted single well steam assisted gravity drainage system and process.
This patent application is currently assigned to NEXEN INC.. The applicant listed for this patent is Richard Kelso Kerr. Invention is credited to Richard Kelso Kerr.
Application Number | 20140000888 13/928934 |
Document ID | / |
Family ID | 49776943 |
Filed Date | 2014-01-02 |
United States Patent
Application |
20140000888 |
Kind Code |
A1 |
Kerr; Richard Kelso |
January 2, 2014 |
UPLIFTED SINGLE WELL STEAM ASSISTED GRAVITY DRAINAGE SYSTEM AND
PROCESS
Abstract
A Single Well Steam Assisted Gravity Drainage (SWSAGD) process
to recover liquid hydrocarbons from an underground hydrocarbon
reservoir, wherein the single well includes a single substantially
horizontal well including a heel area and a toe area, wherein the
toe area of the horizontal well extends upwardly into the
reservoir, the process including 1- injecting steam into the
reservoir via a steam injection area, proximate the toe area of the
horizontal well, 2- allowing the steam to condense causing heated
hydrocarbon liquids and water to drain into a liquid recovery zone
of the horizontal well between the toe area and the heel area of
the horizontal well, and 3- recovering the heated hydrocarbon
liquids to the ground surface from the liquid recovery zone.
Inventors: |
Kerr; Richard Kelso;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Kerr; Richard Kelso |
Calgary |
|
CA |
|
|
Assignee: |
NEXEN INC.
Calgary
CA
|
Family ID: |
49776943 |
Appl. No.: |
13/928934 |
Filed: |
June 27, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61666166 |
Jun 29, 2012 |
|
|
|
Current U.S.
Class: |
166/272.3 ;
166/50 |
Current CPC
Class: |
E21B 33/12 20130101;
E21B 43/305 20130101; E21B 43/2406 20130101; E21B 43/122 20130101;
E21B 43/24 20130101 |
Class at
Publication: |
166/272.3 ;
166/50 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A Single Well Steam Assisted Gravity Drainage (SWSAGD) process
to recover liquid hydrocarbons from an underground hydrocarbon
reservoir, wherein said single well comprises a single
substantially horizontal well comprising a heel area and a toe
area, wherein the toe area of said horizontal well extends upwardly
into the reservoir; said process comprising 1- injecting steam into
the reservoir via a steam injection area, proximate the toe area of
the horizontal well, 2- allowing the steam to condense causing
heated hydrocarbon liquids and water to drain into a liquid
recovery zone of the horizontal well between the toe area and the
heel area of the horizontal well, and 3- recovering said heated
hydrocarbon liquids to the ground surface from the liquid recovery
zone.
2. A SWSAGD substantially horizontal well for hydrocarbon recovery
in a hydrocarbon containing reservoir in the ground, said well
having a predetermined length, comprising a heel section, and a toe
section distant said heel section, wherein said toe section is at a
first predetermined depth in the ground and said heel section is at
a second predetermined depth in the ground, such that said heel
section is deeper in the ground than said toe section.
3. The SWSAGD of claim 2 wherein said SWSAGD further comprises a
steam injection zone and a liquid recovery zone.
4. The SWSAGD of claim 3 wherein said steam injection zone is
proximate said toe section and said liquid recovery zone is
proximate said substantially horizontal well.
5. The SWSAGD of claim 2 wherein said toe section for steam
injection has a length less than 20 percent of the total horizontal
well length.
6. The SWSAGD of claim 2 further comprising at least one thermal
packer isolating the steam injection zone from the liquid recovery
zone.
7. The process of claim 1 wherein the hydrocarbon is heavy oil with
a density of 10<API<20.
8. The process of claim 7 wherein the hydrocarbon is bitumen with
density of API<10.
9. The process of claim 1 wherein the toe area for steam injection
constitutes less than 20 percent of the total horizontal well
length.
10. The process of claim 1 wherein steam injection has an elevation
target of greater than about 2 meters above the bottom of said
reservoir.
11. The process of claim 10 wherein said elevation target is
achieved by drilling up-dip in a dipping reservoir.
12. The process of claim 1 wherein the substantially horizontal
section of the well is completed closer than 2 meters from the
bottom of the reservoir.
13. The process of claim 1 wherein the toe section for steam
injection is shorter than 50 meters.
14. The process of claim 1 further comprising isolating the steam
injection from the liquid recovery zone via a packer (thermal
packer).
15. The process of claim 1 with a steam injection point at least 5
meters higher than the highest point of liquid recovery zone.
16. The process of claim 1 wherein at least one blank pipe section
is placed between the steam injection area and liquid recovery
zone.
17. The process of claim 16 wherein at least one packer is placed
in the blank pipe section isolating the steam injection area from
the liquid recovery zone.
18. The process of claim 1 further comprising pumping produced
fluids out of the well via an offset packer.
19. The process of claim 1 further comprising providing an
operating pressure in the reservoir sufficient to lift the produced
liquids to the surface, without using an artificial lift
system.
20. The process of claim 1 further comprising conveying the
produced liquids to the surface via a gas-lift.
21. The process of claim 1 further comprising conveying steam to
the toe area of the well via insulated concentric tubing.
Description
FIELD OF THE INVENTION
[0001] This invention involves completing the horizontal well of a
Single Well Steam Assisted Gravity Drainage (SWSAGD) system by
drilling upwards, for the toe section of the well, where steam is
to be injected, so steam injected proximate the toe section of the
well is higher than the liquids production section of the well.
Production is improved by inhibition of steam breakthrough. The
process is called SWSAGD(U) where the "U" denotes uplift of the toe
section.
BACKGROUND OF THE INVENTION
[0002] The following acronyms will be used herein:
[0003] CNRL--Canadian Natural Resources Ltd.
[0004] EOR--Enhanced Oil Recovery
[0005] SWSAGD--Single Well SAGD
[0006] SWSAGD(U)--SWSAGD with Upturned toe
[0007] HOSC--Heavy Oil Science Center
[0008] SAGD--Steam Assisted Gravity Drainage
[0009] SPE--Society of Petroleum Engineers
[0010] SF--Steam Flood
[0011] ICCT--Insulated Concentric Coiled Tubing
[0012] Single well SAGD (SWSAGD) is a thermal enhanced oil recovery
(EOR) alternative for bitumen and heavy oil recovery (Elliott, K.
et al, "Simulation of Early-Time Response of SWSAGD" SPE, 54618,
1999), (Elan Energy "Announces . . . Results", August and November
1996), (Improved Recovery Week, "Thermal System ups Heavy Oil . . .
" Dec. 4, 1995). The process was targeted toward thin-pay resources
where SAGD was not practical. The idea was to incorporate steam
injection and fluid production (oil & water) into a single
horizontal well using a thermal packer to isolate steam injection
from fluid production (FIG. 1B). Another version of SWSAGD uses no
packers, simply tubing to segregate flows (FIG. 2B).
[0013] Elan Energy was the original proponent of the SWSAGD
process. The original reservoir targets were thin, heavy oil
deposits in Saskatchewan and Alberta (Ashok, K. et al, "A
Mechanistic Study of SWSAGD", SPE, 59333-MS, 2000), (Elan (1996)),
(Luft, H. B. et al, "Thermal Performance of Insulated Concentric
Coiled Tubing", SPE, 37534-MS, 1997). The first SWSAGD well was
drilled at Cactus Lake, Saskatchewan in 1995. Several field tests
were conducted by Elan and others in the 1990's, and the following
issues were observed (Elliott (1999)), (Saltuklaroglu, M. et al,
"Mobil's SAGD Experience at Celtic . . . " SPE, 99-25, June, 1999):
[0014] The centralized concentric steam line is in contact with the
produced fluids (water & oil) (FIGS. 1 & 2). The produced
fluids have a high heat capacity (i.e. SAGD), and normally, the
fluids would be at a lower temperature than saturated-steam (i.e.
sub-cool control). Heat losses from the steam injector to the
produced fluids can be considerable for uninsulated, concentric,
carbon steel tubing. The produced fluids are heated rapidly to
saturated steam temperatures and the steam quality is reduced
considerably before injection to the reservoir. The use of steam
trap (sub cool) control for production rates will be difficult, at
best. One solution is to use insulated tubing for the steam
injection tube. Insulated concentric coiled tubing (ICCT) was
developed for this purpose but has not resulted in widespread use
today (Luft (1997)), (Falk (1996)). [0015] Start-up performance was
another issue. Even for heavy oil deposits with some steam
injectivity and some primary production, start-up was difficult and
protracted (Elliott (1999)). Initial production rates were
disappointing (Elliott (1999)). At least partially, this problem
could have been due to two factors: 1) initial steam quality at the
sand face was poor due to heat losses to produced fluids; and 2)
the steam injection site occurs at the same elevation as production
(FIGS. 1 & 2). There is no stand-off like SAGD to allow a
liquid level to isolate the producer and prevent steam
breakthrough. Steam by-passing is an issue (Ashok (2000)). Sand
influx problems were another issue (Elliott (1999)). Because of
these issues, an alternate start-up procedure using cyclic steam
was suggested, but this has not been field tested (Elliott (1999)).
[0016] Even after start up, SWSAGD performance has been
disappointing (Saltuklaroglu (1999), Elliot (1999)). Prior to late
1999, Elan Energy drilled 19 SWSAGD wells with seven separate
pilots. By the end of 1999, five of the seven pilots had been
suspended or converted to other processes due to poor performance
(Elliot (1999)). Best results were for high pressure, low
viscosity, heavy oils with some primary production as foamy oil and
no bottom water. The process was focused on deep thin-pay heavy oil
not bitumen. Post 1999, there have been no indications of further
SWSAGD developments, particularly none associate with bitumen
[0017] Therefore there is need to improve on SWSAGD, and in
particular for application in bitumen reservoirs.
SUMMARY OF THE INVENTION
[0018] Single Well SAGD (SWSAGD) is a process developed to recover
heavy oil or bitumen using a single horizontal well, where steam is
injected near the well toe and hot water and hot oil is produced
from the center to heel portion of the horizontal well. The process
was developed in the 1990's, and several wells were drilled in
thin-pay heavy oil reservoirs in Western Saskatchewan and Eastern
Alberta.
[0019] SWSAGD process horizontal wells are completed in a
horizontal plane, so the steam injection and liquids production
occur at the same elevation. This may cause early steam
breakthrough to the production well-zone as well as inhibition of
steam injection.
[0020] According to one aspect of the invention there is provided a
Single Well Steam Assisted Gravity Drainage (SWSAGD) process to
recover liquid hydrocarbons from an underground hydrocarbon
reservoir, preferably bitumen reservoir. The process utilizes a
single substantially horizontal well comprising a heel area and a
toe area, wherein the toe area of said horizontal well extends
upwardly into the reservoir. Said process comprises: 1) injecting
steam into the reservoir proximate the toe area of the horizontal
well; 2) allowing the steam to condense causing heated hydrocarbon
liquids and water to drain into a liquid recovery zone of the
horizontal well between the toe area and the heel area of the
horizontal well; 3) recovering said heated hydrocarbon liquids to
the ground surface from the liquid recovery zone through the heel
area of the well by means known in the art. Preferably, the lowest
point of the steam injection zone is positioned at least 2 meters
above (in elevation) the highest point of the liquids recovery
zone.
[0021] Preferably, steam injection has an elevation target of at
least 2 meters above the highest point of the liquids recovery
zone, preferably said target is achieved by drilling up-dip in a
dipping reservoir.
[0022] Preferably, the hydrocarbon is heavy oil with a density of
10<API<20. More preferably, the hydrocarbon is bitumen with a
density of API<10.
[0023] According to another aspect of the invention, there is
provided a SWSAGD substantially horizontal well for hydrocarbon
recovery in a hydrocarbon containing reservoir in the ground, said
well having a predetermined length, comprising a heel section, and
a toe section distant said heel section, wherein said toe section
is at a first predetermined depth in the ground and said heel
section is at a second predetermined depth in the ground, such that
said heel section is deeper in the ground than said toe
section.
[0024] Preferably said SWSAGD further comprises a steam injection
zone and a liquid recovery zone. Preferably said steam injection
zone is proximate said uplifted toe section and said liquid
recovery zone is proximate said substantially horizontal well.
[0025] According to one aspect of the invention, the toe section
for steam injection has a length less than 20 percent of the total
horizontal well length. According to another aspect of the
invention, the uplifted toe section for steam injection is shorter
than 50 meters.
[0026] According to another aspect of the invention, the
substantially horizontal section of the well is completed closer
than 2 meters from the bottom of the reservoir.
[0027] According to yet another aspect of the invention there is
provided a thermal packer which isolates the steam injection zone
from the liquid recovery zone.
[0028] According to yet another aspect of the invention the lowest
steam injection point is positioned at least 5 meters higher (in
elevation) than the highest point of said liquid recovery zone.
[0029] According to yet another embodiment of the invention at
least one blank pipe section is placed between said steam injection
zone and fluid production zone. Preferably more than one pipe is
placed in this zone. Preferably the thermal packer is placed in the
blank pipe section to isolate the steam injection zone from the
liquid recovery zone.
[0030] In the preferred embodiment an offset packer is used so that
the produced fluids may be pumped out the well.
[0031] According to one embodiment of the invention an operating
pressure in the reservoir is sufficient to lift the produced fluids
to the surface, without using an artificial lift system. According
to another embodiment of the invention gas-lift is used to convey
the produced fluids to the surface.
[0032] According to yet another aspect of the invention a pump is
used to convey the fluids to the surface.
[0033] According to yet another embodiment of the invention, the
steam is conveyed to the toe section of the well using insulated
concentric tubing.
[0034] According to yet another aspect of the invention there is
provided A SWSAGD process, using a single horizontal well, to
recover liquid hydrocarbon from a hydrocarbon reservoir, whereby:
Steam is conveyed to and injected in to the reservoir at the toe
area of the horizontal well, and steam condenses and causes heated
hydrocarbon liquids and water to drain into a separate section of
the horizontal well that is between the toe section of the heel of
the horizontal well, and the toe section of the horizontal well is
drilled upward into the reservoir, and the toe section steam
injector and the liquid producer section are completed (perforated,
slotted . . . ) so the lower point of steam injection is at least 2
meters higher (in elevation) than the highest point of liquids
production.
[0035] Preferably the hydrocarbon is heavy oil with density
10<API<20. More preferably, the hydrocarbon is bitumen with
density API<10.
[0036] Preferably, the toe section for steam injection is less than
20 percent of the total horizontal well length. More preferably,
the toe section for steam injection is less than 50 meters
long.
[0037] According to one aspect of the invention the elevation
target for steam injection (>2 meters) is achieved by drilling
up-dip in a dipping reservoir.
[0038] Preferably, the horizontal section of the well is completed
less than 2 meters above the bottom of the reservoir.
[0039] In a preferred embodiment a packer or thermal packer
isolates the steam injection from the liquid production
section.
[0040] According to another preferred embodiment, the lowest steam
injection point is located at least 5 meters higher (in elevation)
than the highest point of liquids production.
[0041] According to still another aspect of the invention one (or
more) blank pipe (tubing) section is placed between steam injection
and fluid production. Preferably the packer is placed in said blank
section.
[0042] According to another preferred embodiment an offset packer
is used so that the produced fluids may be pumped.
[0043] In the preferred embodiment of the process the operating
pressure in the reservoir is sufficient to lift the produced fluids
to the surface, without using an artificial lift system.
[0044] In yet another embodiment a gas-lift is used to convey the
produced fluids to the surface.
[0045] According to yet another embodiment, steam is conveyed to
the toe of the well using insulated concentric tubing.
BRIEF DESCRIPTION OF THE FIGURES
[0046] FIGS. 1A and 1B depict a typical SWSAGD configuration with
the use of thermal packers.
[0047] FIGS. 2A and 2B depict a typical SWSAGD configuration
without the use of thermal packers.
[0048] FIGS. 3A and 3B depict a typical SWSAGD configuration in
good and poor operation conditions respectively.
[0049] FIGS. 4A and 4B depict a SWSAGD and a SWSAGD(U)
configuration under hydraulic limitation conditions
respectively.
[0050] FIGS. 5A and 5B depict the present invention in several
embodiments.
[0051] FIG. 6 depicts the present invention in an up-dip well
configuration.
[0052] FIG. 7 depicts a pump configuration for SWSAGD.
DETAILED DESCRIPTION OF THE INVENTION
[0053] FIGS. 1 and 2 show two versions of traditional SWSAGD. The
SWSAGD well is horizontal with steam 2 injected near the toe of the
well, and liquids (water and oil) 4 produced in the mid and toe
sections of the well. FIGS. 1A and 1B show SWSAGD, using a thermal
packer 6 to isolate the steam injection zone. FIGS. 2A and 2B show
SWSAGD without a packer. The versions of SWSAGD shown produce
fluids using a natural lift, where the production zone has enough
pressure (controlled by steam injection) to lift the produced
fluids to surface 3. A version of SWSAGD using a pump 20 is
possible using an offset packer 18 or a "special" pump design (FIG.
7).
[0054] As best seen in FIG. 1B, SWSAGD, using a packer 6 to isolate
the steam injection section, is the preferred version because it
allows a significant pressure difference between injection and
production, at least during start up. A steam drive mechanism is
active during this phase. The version of SWSAGD shown in FIGS. 2A
and 2B does not allow any significant pressure differences because
the steam injector and liquid producer are in constant
communication.
[0055] After communication is established between steam injection
and fluid production, it is difficult or impossible to sustain
significant pressure differentials, so the main production
mechanism becomes gravity drainage, not steam drive.
[0056] In order to understand issues for SWSAGD, it is instructive
to look at conventional SAGD. Referring now to FIGS. 3A and 3B,
conventional SAGD involves a pair of horizontal wells--a steam
injector 14 and a fluid producer 10--separated by about 5 meters,
with the steam injector as the higher well and the fluid producer
completed near the bottom of the reservoir. At steady-state, mature
operation, a steam/liquid interface 12 is formed between the SAGD
steam injector 14 and the SAGD liquid producer 10. The interface is
controlled to be above the producer using sub-cool (steam-trap)
control. The produced fluids are kept at a temperature less than
saturated steam T by controlling production rates. The interface 12
is titled because of the pressure drop caused by pumping and/or
fluid flow from toe-to-heel of the production well. Ideally, the
interface covers the production well 10 but does not flood the
steam injector 14 (FIG. 4A). If production rate is too high, the
interface 12 can be tilted to partially flood the injector or to
uncover part of the producer (FIG. 4B). This can cause a reduction
in the effective length of the steam injector and/or a steam
breakthrough to the production well. The limitations caused by this
SAGD effect may be ameliorated by 1) increasing separation between
injector/producer, 2) increasing the size (diameter) of the
production well, 3) reducing the length of the production well, or
4) cutting back on steam injection and fluid production.
[0057] SWSAGD may suffer a similar problem. FIG. 4A shows what may
happen, for a mature, steady-state operation. It is still desirous
to maintain a liquid/steam interface 12 above the production well
10 to prevent steam breakthrough. While heat losses from steam
tubing will heat produced fluids to/near saturated steam T,
sub-cool control for production rates is difficult. The interface
12 will again be tilted, with the higher end at/near the toe and
the lower end at/near the heel of the well. The steam injection
zone 11 at the toe will, perforce, be flooded. Steam can bubble up
through the liquid, but steam flow and conformance is impaired.
Steam by-passing can occur in the well bore, if there is no
packer.
[0058] Unlike SAGD, SWSAGD has no stand-off between injector and
producer. The solution, as described in this invention, is to drill
the toe of the SWSAGD horizontal well upwards, so there is a
vertical separation between the lowest steam injection perforation
(or port, or slot) and the highest fluid production perforation (or
port, or slot) as shown in FIGS. 4B and 5. If the separation is
sufficient, the steam/liquid interface 12 will not cover the steam
injector section but will cover the liquid producer. The steam
injection is not inhibited by liquids, and the liquid producer is
protected against steam breakthrough (FIG. 4B).
[0059] If the lower portion of the steam injector section and/or
the final portion of the production section is blank piping (with
no perforations), this separation may be enhanced even further.
[0060] Another version of SWSAGD(U) is achieved by completing the
toe section of the horizontal well in an up-dip direction in a
dipping reservoir, as shown in FIG. 6.
[0061] Other embodiments of the invention will be apparent to a
person of ordinary skill in the art and may be employed by a person
of ordinary skill in the art without departing from the spirit of
the invention.
* * * * *