U.S. patent application number 11/421798 was filed with the patent office on 2007-12-13 for heavy oil recovery and apparatus.
Invention is credited to Henry B. Crichlow.
Application Number | 20070284107 11/421798 |
Document ID | / |
Family ID | 38792281 |
Filed Date | 2007-12-13 |
United States Patent
Application |
20070284107 |
Kind Code |
A1 |
Crichlow; Henry B. |
December 13, 2007 |
Heavy Oil Recovery and Apparatus
Abstract
A thermal in-situ method and apparatus are provided for
recovering hydrocarbons from subterranean hydrocarbon-containing
formations such as oil sands, oil shale and other heavy oil
systems. Recovery of viscous hydrocarbon by hot fluid injection
into subterranean formations is assisted by using a specially
designed wellbore with an active hydraulic seal, with a axial
communication zone with multiple injection perforations separated
from the production perforations by a moveable packer. In addition,
a novel downhole thermal sensing apparatus is used to monitor and
control oil production. A producing mechanism including pumping
equipment lifts the produced oil from the central cavity to the
surface.
Inventors: |
Crichlow; Henry B.; (Norman,
OK) |
Correspondence
Address: |
HENRY CRICHLOW
330 W. GRAY ST., SUITE 504
NORMAN
OK
73069
US
|
Family ID: |
38792281 |
Appl. No.: |
11/421798 |
Filed: |
June 2, 2006 |
Current U.S.
Class: |
166/302 ;
166/369; 166/387; 166/66; 166/66.6 |
Current CPC
Class: |
E21B 43/2408 20130101;
E21B 43/166 20130101; E21B 43/2406 20130101; E21B 43/305
20130101 |
Class at
Publication: |
166/302 ;
166/369; 166/387; 166/66; 166/66.6 |
International
Class: |
E21B 36/00 20060101
E21B036/00; E21B 43/00 20060101 E21B043/00 |
Claims
1. A method for recovering hydrocarbons from a subterranean
formation containing viscous oil or other heavy hydrocarbons, the
method comprising the steps of: (a) drilling at least one wellbore
down to and penetrating the subterranean formation; (b) providing a
wellhead at the entrance or proximal end of the wellbore; (c)
providing at least one set of upper injection perforations and
lower production perforations in the wellbores at pre-selected
intervals; (d) installing at least one downhole wellbore packer
between upper and lower perforations; (e) forming a discrete
annular zone for increased axial fluid communication near the said
wellbore in the said formation so that heated low viscosity oil and
hot water produced from condensed displacing fluid can flow
downwards to the lower production perforations; (f) implementing an
active hydraulic seal in said annular communication zone; (g)
installing a downhole flow control apparatus; (h) heating the said
formation by injecting a displacing fluid into the formation; (i)
communicating with the downhole flow control apparatus from the
surface; (j) computing the prescribed times for triggering the
downhole flow control apparatus; (k) lifting the produced oil and
displaced fluids to the surface; (l) producing the wellbore fluids
at less than a critical rate so that the effects of the displacing
fluid coning are substantially eliminated; (m) scavenging the
formation residual hot oil by injecting a displacing scavenger
fluid.
2. The method of claim 1, wherein the said formation is heated by
injecting steam through wellbore perforations as a displacing
fluid.
3. The method of claim 2, wherein the injected steam heats the
wellbore and surrounding formation for sufficient time and to a
calculated temperature.
4. The method of claim 1, wherein the step of forming said annular
zone comprises: installing a steel pipe selected from the group
consisting of steel casings, steel liners, self-expanding or fixed
sand screens
5. The method of claim 2, wherein the said injected steam forms a
steam chamber or steam bank.
6. The method of claim 1, wherein the hydraulic seal in the
communication zone forms as a no-flow barrier for vertical steam
flow.
7. The method of claim 1, further comprising the step of:
installing a fluid recovery system to lift the produced oil and
displaced fluids to the surface, wherein the produced oil and
displaced fluids are lifted to the surface by using the said fluid
recovery system.
8. The method of claim 7, wherein the said fluid recovery system
comprises a plurality of devices including: (a) displacement pumps,
(b) gas lift devices, (c) cavity pumps.
9. The method of claim 1, wherein the wellbore has a downward,
lateral and an upward section terminating in a new surface wellhead
forming a uniwell.
10. The method of claim 1, wherein the wellbore has a downward
section, a lateral section and terminating in a central production
cavity.
11. The method of claim 1, wherein the wellbore has a downward
section and an enlarged axial central production cavity.
12. The method of claim 1, further comprising the step of cementing
a steel casing in the wellbore in the said formation.
13. The method of claim 1, wherein a plurality of lateral and
horizontal injection mini-wellbores are implemented in a staggered
manner operatively connected to the central wellbore.
14. The method of claim 9, wherein the wellhead at the proximal end
of the wellbore is an injection wellhead and the distal end of the
wellbore is a production wellhead.
15. The method of claim 1, wherein the perforations in the wellbore
are positioned as paired groups or couplets.
16. The method of claim 15, wherein the proximal perforations in
the pair group form an injector set of perforations.
17. The method of claim 15, wherein the next or distal set of
perforations in the pair group form a producer set of
perforations.
18. The method of claim 1, wherein the downhole packer in the
wellbore is placed between the injector and producer pair of
perforations separating the injection and production zones.
19. The method of claim 1, wherein the downhole packer forces the
injection fluid to be to exit the wellbore and be injected into the
hydrocarbon bearing formation through the upper injection
perforations.
20. The method of claim 1, wherein the downhole packer is
retractable and has either a solid or an inflatable element.
21. The method of claim 1, wherein the injected displacing fluid is
steam.
22. The method of claim 1, wherein the injected displacing fluid
forms a steam bank or chamber in the hydrocarbon reservoir.
23. The method of claim 1, wherein the annular communication zone
is concentric to the wellbore.
24. The method of claim 1 wherein the diameter of the annular
communication zone ranges from at least 8 inches to several
feet.
25. The method of claim 1, wherein after each steam displacing zone
is depleted of hydrocarbons the downhole packers, and the downhole
flow controller apparatus, are unseated and moved axially along the
wellbore and re-seated adjacent to new hydrocarbon-rich zones in
the formation to implement the said recovery method.
26. A downhole flow control apparatus comprising: (a) a fluid flow
sensor; (b) a flow valve or flow control device for restricting
fluid flow; (c) a flow device controller for controlling the flow
control device; (d) means for communicating; (e) a wellbore packer;
(f) means for delivering operational power to the apparatus; and
(g) a surface control device.
27. The apparatus of claim 26, wherein the fluid flow sensor is
upstream of the flow valve.
28. The apparatus of claim 26, wherein the fluid flow sensor is
downstream of the flow valve.
29. The apparatus of claim 26, wherein the fluid flow sensor
measures a plurality of material flow characteristics including
pressure, temperature, mass rate and quality of the flow
stream.
30. The apparatus of claim 26, wherein said fluid flow sensor is
selected from the group consisting of electronic, optical,
mechanical and electrical sensors.
31. The apparatus of claim 26 wherein said fluid flow sensor
communicates with a downhole processor, said downhole processor
being adapted to process the raw flow data sensed by said steam
flow sensor to derive processed data, said processed data being
selectively transmitted to the surface.
32. The apparatus of claim 26 wherein said fluid flow sensor
communicates with a downhole processor, said downhole processor
being adapted to process the raw flow data sensed by said steam
flow sensor to derive processed data, said processed data being
selectively utilized to directly control the flow control device in
the steam apparatus.
33. The apparatus of claim 26 further comprising a control circuit
for controlling the operation of the flow control apparatus.
34. The apparatus of claim 33 wherein the control circuit is placed
at a remote place from the device.
35. The apparatus of claim 33 wherein the control circuit
communicates with the flow control device via a conductor.
36. The apparatus of claim 33 wherein the control circuit
communicates with the flow control device via telemetry.
37. The apparatus of claim 33 wherein the control circuit includes
a memory system capable of storing instructions for operating the
flow control device independently of the surface.
38. The apparatus of claim 26, wherein the fluid flow sensor
activates the flow control device.
39. The apparatus of claim 26, wherein the flow control device
controls the flow of fluid through the wellbore.
40. The apparatus of claim 26, wherein the fluid flow through the
wellbore is greater than zero when the flow device is open.
41. The apparatus of claim 26, wherein the fluid flow through the
wellbore is zero when the flow valve is closed.
42. The apparatus of claim 26, wherein the fluid flow sensor
detects the flow of hot oil.
43. The apparatus of claim 26, wherein the fluid flow sensor
detects the flow of hot water.
44. The apparatus of claim 26, wherein the fluid flow sensor
detects the flow of steam.
45. The apparatus of claim 26, wherein the fluid flow sensor
detects the combined flow of steam, hot oil and condensed
water.
46. The apparatus of claim 26, wherein the fluid flow sensor
detects the mass flow rate of the flow stream.
47. The apparatus of claim 26, wherein the fluid flow sensor
detects the temperature of the flow stream.
48. The apparatus of claim 26, wherein the fluid flow sensor
detects the mass flow rate and temperature of the flow stream
simultaneously.
49. The apparatus of claim 26, wherein the fluid flow sensor
triggers the flow device controller when the flow sensor detects
the flow of steam.
50. The apparatus of claim 26, wherein the flow device controller
closes the fluid flow device when the flow sensor detects the flow
of steam.
51. The apparatus of claim 26, wherein the flow device controller
communicates with the surface control device.
52. The apparatus of claim 26, wherein the flow device controller
receives a signal from the surface control device after a
prescribed time.
53. The apparatus of claim 26, wherein the signal from the surface
to the flow device controller triggers the controller to open the
flow control device.
54. The apparatus of claim 26, wherein said flow device controller
is selected from the group consisting of electrical, electronic,
optical, mechanical, hydraulic, pneumatic and electrical
controllers.
55. The apparatus of claim 26 wherein the communication with the
surface is by a wired connection.
56. The apparatus of claim 26 wherein the communication with the
surface is a wireless communication.
57. The apparatus of claim 26 wherein the communication with the
surface is through the steel wellbore using a plurality of
electromagnetic transmissions.
58. The apparatus of claim 57 wherein the communication with the
surface is analyzed using Digital Signal Processing
technologies.
59. The apparatus of claim 26 wherein the device operates in a
"null" sensor mode comprising; (a) receiving a control signal at
pre-selected timed intervals; (b) opening the production valve for
oil flow; (c) keeping the production valve open for a fixed time
period; (d) shutting the downhole valve after a timed interval.
60. The apparatus of claim 59 wherein the control signal can be
sent remotely from the surface or can be generated by an embedded
downhole timing mechanism.
61. The method of claim 1 wherein the injected displacing scavenger
fluid is water.
62. The method of claim 1 wherein the injected displacing scavenger
fluid is non-condensible gas such as flue gas.
63. The method of claim 61, wherein the injected displacing
scavenger water is injected in a plurality of wellbores comprising:
(a) newly drilled horizontal and vertical injector wellbores; (b)
existing wellbores formerly used for steam injection.
64. The method of claim 61, wherein the injected displacing
scavenger non-condensible gas is injected in a plurality of
wellbores comprising: (a) newly drilled horizontal and vertical
injector wellbores; (b) existing wellbores formerly used for steam
injection.
65. The method of claim 63, wherein the injected displacing
scavenger water is injected at the bottom of the steam bank in the
oil formation.
66. The method of claim 64, wherein the injected displacing
scavenger non-condensible gas is injected at the top of the steam
bank in the oil formation.
67. The method of claim 1, wherein the injected displacing
scavenger fluids are injected simultaneously.
68. The method of claim 1, wherein the injected displacing
scavenger fluids are injected separately.
69. The method of claim 1, wherein the critical production rate is
less than 5,000 barrels of fluid per day.
70. The method of claim 1 wherein the prescribed time for
triggering the downhole flow controller is determined by the use of
a computer model.
71. The method of claim 1, wherein the step of forming said annular
zone comprises implementing an open hole completion without a steel
casing.
Description
CROSS REFERENCES
[0001] Reference is made to DD 596,606 filed Mar. 16, 2006 by the
inventor.
INTRODUCTION
[0002] This invention relates generally to a new technology
application used in recovery of heavy and viscous hydrocarbons from
subterranean oil bearing formations during hot fluid injection. The
technology described is the Single Well Acceleration Production
process, herein abbreviated as SWAP which allows a single wellbore
to perform simultaneously, injection and production operations in
heavy oil recovery systems.
[0003] This invention is related to prior filings by the same
applicant, pertaining to the overall recovery of hydrocarbons from
subterranean oil formations. The technology involves the novel use
and application of equipment and techniques in which steam or other
hot fluids are injected into substantially horizontal wellbores in
which injection and production is obtained from the same
wellbore.
[0004] One of the new types of horizontal well is called a
Uniwell.TM. because it can have at least two surface wellheads one
at each end of the axis of the horizontal system. Either wellhead
can be used for either injection or production as needed by the
operator.
[0005] The technology has been the subject of several prior
applications by the same inventor. This particular invention
relates to use of a specialized annular fluid communication zone
between the steam zone and the production zone and the additional
use of a downhole apparatus to selectively monitor flowing fluid
characteristics and subsequently control hot oil production in
order to facilitate the injection of steam into the steam bank
zone. This control mechanism effects oil displacement by
maintaining a viable hydraulic seal in the communication zone
between the steam displacement zone and the production zone of the
wellbore.
[0006] This novel completion technique uses injection and
production perforations separated by a moveable wellbore packer and
this new apparatus is implemented between the injection and
production perforations in the wellbore to sense and monitor the
flow of steam and control the production of hot oil.
FIELD OF INVENTION
[0007] THIS INVENTION is a unique new approach to heavy oil
recovery combining horizontal and lateral wells, steam injection
and specialized downhole devices to facilitate operations and to
significantly accelerate oil production.
[0008] The invention is particularly suited to making heavy oil
formations, oil shales and tar sands producible by a single
wellbore drilled using a specialized form of horizontal directional
drilling. The invention however is not limited to recovery of heavy
oils only; it can be used for many oil recovery processes such as
tar sands and oil shales.
BACKGROUND OF THE INVENTION
[0009] 1. Introduction
[0010] Heavy hydrocarbons in the form of petroleum deposits are
distributed worldwide and the heavy oil reserves are measured in
the hundreds of billions of recoverable barrels. Because of the
relatively high viscosity, up to a million cp, these crude deposits
are essentially immobile and cannot be easily recovered by
conventional primary and secondary means. The only economically
viable means of oil recovery is by the addition of heat to the oil
deposit, which significantly decreases the viscosity of the oil and
allows the oil to flow from the formation into the producing
wellbore. Today, the steam injection can be done in a continuous
fashion or intermittently as in the so-called "huff and puff" or
cyclic steam process. Oil recovery by steam injection involves a
combination of physical processes including, steam distillation,
gravity drainage, steam drive and steam drag to move the heated oil
from the oil zone into the producing wellbore.
[0011] Horizontal wells and lateral wells have played a prominent
part in recovery of oil. These wells can be as much as 4 times as
expensive to drill as conventional vertical wells but the increased
expenses are offset by the increases in rates of oil production and
faster economic returns. Several patents have described various
approaches to using horizontal wellbores. The need for horizontal
wells requires a more efficient economical and easily deployable
system for developing, drilling and utilizing these horizontal
wells. The need to accelerate oil production without waiting for
steam to traverse several hundred feet of reservoir rock between
injection and production wells has created this new technology. In
this technology an approach is used wherein oil production occurs
almost simultaneously with steam injection initiation.
[0012] 2. Prior Art
[0013] Various methods and processes have been disclosed for
recovery of oil and gas by using horizontal wells. There have been
various approaches utilized with vertical wellbores, to heat the
reservoirs by injection of fluids and also to create a combustion
front in the reservoir to displace the insitu oil from the
injection wellbore to the production wellbore.
[0014] U.S. Pat. No. 3,986,557 claims a method using a horizontal
well with two wellheads that can inject steam into a tar sand
formation mobilizing the tar in the sands. In this patent, during
the injection of the steam it is hoped that the steam will enter
the formation and not continue directly down the open wellbore and
back to the surface of the opposite wellhead. It is technically
difficult to visualize the steam entering a cold formation with
extremely highly viscous oil, while a completely open wellbore is
readily available for fluid flow away from the formation.
Furthermore, U.S. Pat. No. 3,986,557 teaches that the steam is
simultaneously injected through perforations into the cold bitumen
formation while hot oil is flowing in the opposite direction
against the invading high pressure steam through the same
perforations through the rock pore structure. This situation is not
only physically impossible but it thermodynamically impossible for
the steam fluid to flow out of, and hot oil flow back into the same
perforations simultaneously.
[0015] U.S. Pat. No. 3,994,341 teaches a vertical closed loop
system inside the wellbore tubulars in which a vertical wellbore is
used to generate a vertical circulation of hot fluids which heat
the wellbore and nearby formation. Hot fluids and drive fluids are
injected into upper perforations which allow the driven oil to be
produced from the bottom of the formation after being driven
towards the bottom by the drive fluid.
[0016] U.S. Pat. No. 4,034,812 describes a cyclic injection process
where a single wellbore is drilled into an unconsolidated mineral
formation and steam is injected into the formation for a period of
time to heat the viscous petroleum near the well. This causes the
unconsolidated mineral sand grains to settle to the bottom of the
heated zone in a cavity and the oil to move to the top of the
zone.
[0017] U.S. Pat. No. 4,037,658 teaches the use of two vertical
wells connected by a cased horizontal shaft or "hole" with a flange
in the vertical well. This type of downhole flange connection is
extremely difficult if not impossible to implement in current
oilfield practice. Two types of fluids are used in this patent, one
inside the horizontal shaft as a heater fluid and one in the
formation as a drive fluid. Both fluids are injected either
intermittently or simultaneously from the surface wellheads.
[0018] Butler et al in U.S. Pat. No. 4,116,275 use a single
horizontal wellbore with multiple tubular strings internal to the
largest wellbore for steam recovery of oil. Steam was injected via
the annulus and after a soak period, the oil is produced from the
inner tubing strings. This approach is basically a modified "Huff
& Puff" displacement in which the injection "huff" is done
through a complex pre-heated horizontal well bore and the well put
on production, the "puff" cycle after a soak period of several
days. In other patents, U.S. Pat. Nos. 4,085,803, 4,344,485,
5,407,009, 5,607,016, Butler describes further uses of horizontal
wells, solvent type and steam displacement mechanisms to produce
viscous oils from tar sands using his SAGD technology.
[0019] U.S. Pat. No. 4,445,574 teaches the drilling of a single
well with two wellheads. This well is perforated in the horizontal
section and a working fluid is injected into the wellbore to
produce a mixture of reservoir oil and injected working fluid.
Similar to the U.S. Pat. No. 3,986,557 patent it is difficult from
a hydraulic point of view to visualize and contemplate the working
fluid entering the formation in a vertical direction while an open
wellbore is available for fluid flow horizontally and vertically
out the distal end of this wellbore.
[0020] U.S. Pat. No. 4,532,986 teaches an extremely complex dual
well system including a horizontal wellbore and a connecting
vertical wellbore which is drilled to intersect the horizontal
well. The vertical well contains a massively complex moveable
diverter system with cables and pulleys attached to the two
separate wellheads to allow the injection of steam. This system is
used to inject steam from the vertical wellhead into the horizontal
wellbore cyclically and sequentially while the oil is produced from
the wellhead at the surface end of the horizontal well.
[0021] Huang in U.S. Pat. No. 4,700,779 describes a plurality of
parallel horizontal wells used in steam recovery in which steam is
injected into the odd numbered wells and oil is produced in the
even numbered wells. Fluid displacement in the reservoir occurs in
a planar fashion.
[0022] U.S. Pat. No. 5,167,280 teaches single concentric horizontal
wellbores in the hydrocarbon formation into which a diffusible
solvent is injected from the distal end to effect production of
lowered viscosity oil backwards at the distal end of the concentric
wellbore annulus.
[0023] U.S. Pat. No. 5,215,149 Lu, uses a single wellbore with
concentric injection and production tubular strings in which the
injection is performed through the annulus and production occurs in
the inner tubular string, which is separated by a packer. This
packer limits the movement of the injected fluids laterally along
the axis of the wellbores. In this invention, the perforations are
made only on the top portion of the annular region of the
horizontal well. Similarly, the production zone beyond the packer
is made on the upper surface only of the annular region. These
perforated zones are fixed at the time of well completion and
remain the same throughout the life of the oil recovery
process.
[0024] Balton in U.S. Pat. No. 5,402,851 teaches a method wherein
multiple horizontal wells are drilled to intersect or terminate in
close proximity a vertical well bore. The vertical wellbore is used
to actually produce the reservoir fluids. The horizontal wellbore
provides the conduits, which direct the fluids to the vertical
producing wellbore.
[0025] U.S. Pat. No. 5,626,193 by Nzekwu et al disclose a single
horizontal well with multiple tubing elements inside the major
wellbore. This horizontal well is used to provide gravity drainage
in a steam assisted heavy oil recovery process. This invention
allows a central injector tube to inject steam and then the heated
produced fluids are produced backwards through the annular region
of the same wellbore beginning at the farthest or distal end of the
horizontal wellbore. The oil is then lifted by a pump. This
invention shows a process where the input and output elements are
the same single wellbore at the surface.
[0026] U.S. Pat. No. 5,655,605 attempts to use two wellbores
sequentially drilled from the surface some distance apart and then
to have these horizontal wellbore segments intersect each other to
form a continuous wellbore with two surface wellheads. This
technology while theoretically possible is operationally difficult
to hit such a small underground target, i.e the axial cross-section
of a typical 8-inch wellbore using a horizontal penetrating drill
bit. It further teaches the use of the horizontal section of these
intersecting wellbores to collect oil produced from the formation
through which the horizontal section penetrates. Oil production
from the native formation is driven by an induced pressure drop in
the collection zone by a set of valves or a pumping system which is
designed into the internal concentric tubing of this invention. The
U.S. Pat. No. 5,655,605 patent also describes a heating mechanism
to lower the viscosity of the produced oil inside the collection
horizontal section by circulating steam or other fluid through an
additional central tubing located inside the horizontal section. At
no time does the steam or other hot fluid actually contact the oil
formation where viscosity lowering by sensible and latent heat
transfer is needed to allow oil production to occur.
[0027] U.S. Pat. No. 6,708,764 provides a description of an
undulating well bore. The undulating well bore includes at least
one inclining portion drilled through the subterranean zone at an
inclination sloping toward an upper boundary of the single layer of
subterranean deposits. At least one declining portion is drilled
through the subterranean zone at a declination sloping toward a
lower boundary of the single layer of subterranean deposits. This
embodiment looks like a waveform situated in the rock
formation.
[0028] U.S. Pat. No. 6,725,922 utilizes a plurality of horizontal
wells to drain a formation in which a second set of horizontal
wells are drilled from and connected to the first group of
horizontal wells. These wells from a dendritic pattern arrangements
to drain the oil formation.
[0029] U.S. Pat. No. 6,729,394 proposes a method of producing from
a subterranean formation through a network of separate wellbores
located within the formation in which one or more of these wells is
a horizontal wellbore, however not intersecting the other well but
in fluid contact through the reservoir formation with the other
well or wells.
[0030] U.S. Pat. No. 6,948,563 illustrates that increases in
permeability may result from a reduction of mass of the heated
portion due to vaporization of water, removal of hydrocarbons,
and/or creation of fractures. In this manner, fluids may more
easily flow through the heated portion.
[0031] U.S. Pat. Nos. 6,951,247, 6,929,067, 6,923,257, 6,918,443,
6,932,155, 6,929,067, 6,902,004, 6,880,633, 20050051327,
20040211569 by various inventors and assigned to Shell Oil Company
have provided a very exhaustive analysis of the oil shale recovery
process using a plurality of downhole heaters in various
configurations. These patents utilize a massive heat source to
process and pyrolize the oil shale insitu and then to produce the
oil shale products by a myriad of wellbore configurations. These
patents teach a variety of combustors with different geometric
shapes one of which is a horizontal combustor system which has two
entry points on the surface of the ground, however the hydrocarbon
production mechanism is considerably different from those proposed
herein by this subject invention.
[0032] U.S. Pat. No. 6,953,087 by Shell, shows that heating of the
hydrocarbon formation increases rock permeability and porosity.
This heating also decreases water saturation by vaporizing the
interstitial water. The combination of these changes increases the
fluid transmissibility of the formation rock in the heated
region.
[0033] U.S. Pat. No. 5,896,928 teaches a "dumb" downhole fluid flow
control device that is electrically operated from either the
surface or downhole. This device is a simple on-off device, which
restricts flow, but is unable to determine, process and operate
based on the sensible characteristics of the flowing fluid such as
the current invention discussed herein.
[0034] A further U.S. Pat. No. 5,868,201 illustrates a downhole
system that senses pressure and that actuate a valve system for
control of the fluid flow remotely. Similar to U.S. Pat. No.
5,896,928 this system is unable to operate based on the sensible
characteristics of the flowing fluid as is needed in the case of
steam, flow where pressure is a minor parameter in determining flow
regimes.
[0035] U.S. Pat. No. 6,006,832 discusses a formation sensor system
for monitoring a producing formation in-situ by using permanently
mounted sensors in the wellbore. These sensors monitor formation
properties using gamma ray, neutron and resistivity sensors. These
type sensors are passive and measure rock and interstitial fluid
properties needed to discriminate rock types and properties. On the
other hand, the present invention herein senses flow parameters and
properties needed for flow control.
[0036] Patent application 20050072578 describes a thermally
controlled valve. This thermally controlled valve is a device that
is capable of regulating the flow of material into, through, and
out of a wellbore in response only to a change in temperature near
the valve. All of the subsequent systems related to the valve
operation depend on the temperature behavior and its measurement.
In steam operations where there is a need to regulate steam flow in
porous media such as injection and production in subterranean heavy
oil formations, there is an indispensable requirement to determine
the total characteristics of the flowing material. A simple
temperature record is insufficient to determine whether flow is a
gas, a liquid or a solid. To fully describe what fluid is flowing
one needs the temperature, pressure and quality in the case of
steam. The 20050072578 application does not address this fact and
as such is incapable of discriminating between hot oil, hot water
and steam in the flow stream and will be inadequate as a controller
of steam flow and a reliable steam shut off mechanism as is needed
in heavy oil field steam displacement processes.
[0037] The Society of Petroleum Engineers Reference 1, SPE paper
20017 teaches a computer simulation of a displacement process using
a concentric wellbore system of three wellbore elements and complex
packers in which steam is injected in a vertical wellbore similar
to that in the U.S. Pat. No. 3,994,341 patent. Simulated steam
injection occurs through one tubing string and circulates in the
wellbore from just above the bottom packer to the injection
perforations near the top of the tar sand. This perforations near
the top of the tar sand. This circulating steam turns the wellbore
into a hot pipe which heats an annulus of tar sand and provides
communication between the steam injection perforations near the top
of the tar sand and the fluid production perforations near the
bottom of the tar sand. This process requires an injection period
of 7 years to increase oil production from 20 BOPD to 70 BOPD.
[0038] Paper 37115 describes a single-well technology applied in
the oil industry which uses a dual stream well with tubing and
annulus: steam is injected into the tubing and fluid is produced
from the annulus. The tubing is insulated to reduce heat losses to
the annulus. This technology tries to increase the quality of steam
discharged to the annulus, while avoiding high temperatures and
liquid flashing at the heel of the wellbore.
[0039] SPE paper 50429 presents an experimental horizontal well
where the horizontal well technology was used to replace ten
vertical injection wells with a single horizontal well with limited
entry. The limited-entry perforations enabled steam to be targeted
at the cold regions of the reservoir.
[0040] SPE paper 37089 presents an experimental SAGD study in which
the lower horizontal well functions as an intermittent
steam-injector and a continuous oil-producer, instead of the usual
SAGD production-well while steam is also injected continuously
through the upper well.
[0041] SPE paper 50941 presents the "Vapex" process which involves
injection of vaporized hydrocarbon solvents into heavy oil and
bitumen reservoirs; the solvent-diluted oil drains by gravity to a
separate and different horizontal production well or another
vertical well. SPE paper 53687 shows the production results during
the first year of a thermal stimulation using dual and parallel
horizontal wells using the SAGD technology in Venezuela.
[0042] SPE paper 75137 describes a THAI--`Toe-to-Heel Air
Injection` system involving a short-distance displacement process,
that tries to achieve high recovery efficiency by virtue of its
stable operation and ability to produce mobilized oil directly into
an active section of the horizontal producer well, just ahead of
the combustion front. Air is injected via a separate vertical or a
separate horizontal wellbore into the formation at the toe end of
different horizontal producer well and the combustion front moves
along the axis of the producer well.
[0043] SPE 14916 describes the problem of the dual horizontal wells
in a formation with a horizontal shale barrier. This barrier slows
down the recovery under the SAGD system of dual horizontal wells
since the steam bank formation is slowed by the shale. This
analysis also confirms that the gaseous steam overrides the cold
viscous crude zone as it is injected into the reservoir. SPE paper
78131 published an engineering analysis of thermal simulation of
wellbore in oil fields in western Canada and California, U.S.A.
[0044] SPE paper 92685 describes U-tube well technology in which
two separate wellbores are drilled and then connected to form a
single wellbore. The U-tube system was demonstrated as a means of
circumventing hostile surface conditions by drilling under these
physical obstacles.
[0045] SPE 54618 and SPE 37115 describe and illustrate a series of
heavy oil production mechanisms. They describe a "technically
challenging" process whereby in single well gravity drainage
process steam is injected into the "toe" or distal end of a
horizontal well while oil is produced at the "heel" or proximal
end. This system is similar to other approaches in the prior art
and has a serious drawback in that neither investigator describes
how the backwards flow from the "toe" to the "heel" can occur under
reservoir conditions with the extremely viscous in-situ oil. There
is no viable mechanism for the hot oil to travel to the producing
point at the heel. However, in this subject application, this
conceivably insurmountable obstacle is overcome by implementing a
communication zone which forms an active channel between the
growing steam bank and the downstream production zone.
[0046] Reference 2 shows conclusively that the gravity drainage
effect is the most critical factor in oil recovery in heavy oil
systems undergoing displacement by steam.
[0047] Very few of these prior art systems, except the SAGD and
Huff & Puff processes, have been used in the industry with any
success because of their technical complexity, operational
difficulties, and being physically impossible to implement or being
extremely uneconomical systems.
[0048] For example, in U.S. Pat. No. 3,994,341, this patent which
although on the surface it has several similar aspects of the
invention herein, differs significantly since, the U.S. Pat. No.
3,994,341 patent forms a vertical passage way only by circulating a
hot fluid in the wellbore tubulars to heat the nearby formation,
the U.S. Pat. No. 3,994,341 patent claims the drive fluid promotes
the flow of the oil by vertical displacement downwards to the
producing perforations at the bottom, the U.S. Pat. No. 3,994,341
patent teaches the production perforations are set at the bottom of
the vertical formation, a distance which can be several hundred
feet. In this U.S. Pat. No. 3,994,341 embodiment, since no control
mechanism like a back pressure system or pressure control system is
taught, it is obvious that the high pressure drive steam, usually
at several hundred psi, will preferentially flow down the vertical
passageway immediately on injection and bypass the cold formation
with its highly viscous crude and extremely low transmissibility.
Secondly, the large distance between the top of the formation and
the bottom of the formation will cause condensation of the drive
steam allowing essentially hot water to be produced at the bottom
with low quality steam, both fluids being re-circulated back to the
surface. In addition, the mechanism to heat the near wellbore can
only be based on conductive heat transfer through the steel casing.
There is ineffective heat transfer since there is no direct steam
contact with the formation rock in which latent heat transfer to
formation fluids and rock can occur, this latent heat being the
major heat transport system. The U.S. Pat. No. 3,994,341 process is
incapable of delivering sufficient heat in a reasonable time to
heat the formation sufficiently to lower the viscosity of the oil,
raise the porosity and permeability of the formation as taught in
the present patent application.
[0049] Additionally many of the downhole devices patented to
control fluid flow in the downhole wellbores are designed as "dumb"
systems. These so-called dumb systems simply open or close a flow
device depending on an event such as a pressure level or a
temperature level. None of the devices used in the heavy oil
recovery system by steam to date, examine the quality of the
flowing fluid in the novel communication zone to discriminate its
nature and thus restrict flow based on this knowledge to maintain a
hydraulic seal.
[0050] In steam operations where there is a need to regulate steam
flow in porous media such as injection and production in
subterranean heavy oil formations, there is an indispensable
requirement to determine the total characteristics of the flowing
material. A simple temperature record is insufficient to determine
whether flow is a gas, a liquid or a solid. To fully describe what
fluid is flowing one needs the temperature, pressure and quality in
the case of steam. The prior art applications do not adequately
address this fact and as such are incapable of discriminating
between hot oil, hot water and steam in the flow stream and will be
inadequate as controllers of steam flow and thereby reliable steam
shut off mechanisms as are needed in heavy oil field steam recovery
operations.
[0051] The most significant oil recovery problem with heavy oil,
tar sands and similar hydrocarbonaceous material is the extremely
high viscosity of the native hydrocarbons. The viscosity ranges
from 10,000 cp at the low end of the range to 5,000,000 cp at
reservoir conditions. The viscosity of steam at injection
conditions is about 0.020 cp. Assuming similar rock permeability to
both phases steam and oil, then the viscosity ratio provides a good
measure of the flow transmissibility of the formation to each
phase. Under the same pressure, gradient, gaseous steam can
therefore flow from 500,000 to 250,000,000 times easier through the
material than the oil at reservoir conditions. Because of this
viscosity ratio, it is imperative and critical to any recovery
application that the steam be confined or limited to a continuous
3-dimensional volumetric zone in the reservoir by a seal. This seal
can be physical, hydraulic or pneumatic and essentially must
provide a physical situation which guarantees no-flow of any fluid
across an interface. This can be implemented by several means.
Without this "barrier" the steam will bypass, overrun, circumvent,
detour around the cold viscous formation and move to the producer
wellbore. This invention addresses and resolves this major
obstructive element in heavy oil recovery by implementing a
hydraulic seal at the bottom of the steam bank and in the
communication zone.
[0052] There is a long felt need in the industry for a means of
moving the heated low viscosity crude oil that has been contacted
by the steam in the steam zone to a place or location where it can
be produced without having to move it through a cold heavily
viscous oil impregnated formation. This problem has continued to
baffle the contemporary and prior art with possibly the only
exception being the SAGD patent which uses two horizontal wellbores
closely juxtaposed in a vertical plane. Even this SAGD approach has
inherent difficulties in initiating the hot oil flow between the
two wellbores. Trying to push the hot oil through a cold formation
is an intractable proposition.
[0053] In a much-reported SAGD process that has been used
extensively in Canada, there are other shortcomings that limit the
efficacy of the process and which have been overcome in this
subject invention. It is well known that the SAGD production well
must be throttled to maintain the production temperature below the
saturation steam temperature to allow a column of fluid to exist
over 100% of the production well to minimize bypass of steam. In
some situations, in this very operation the newly injected steam
comes into the formation at the lower end of the steam bank. It
then passes vertically through the overlying hot oil and hot water
re-heating this mixture repeatedly which must be kept cool to
prevent bypassing of steam; this is called the "sub-cool" effect.
In essence, this thermodynamically inefficient process is analogous
to running an air conditioner and a heater simultaneously to
maintain a room at a fixed temperature. Further, even though the
SAGD tries to utilize a limited hydraulic seal as is described in
this subject invention, the implementation in this subject patent
application is more precise, more operationally efficient and does
not provide any detrimental effects on the overall steam process.
Having to inject the steam through existing hot oil and water uses
up part of the latent heat of the steam which is critical to good
reservoir heating and effective oil displacement. This heat loss
lowers the overall recovery of the process. In the subject process
there is no operational loss of latent heat since the hot oil-water
leg is at the bottom of the steam bank and the communication zone
and steam is injected directly into the native formation above and
not through the oil-water accumulation zone with no loss of heat
energy.
[0054] There are flow control issues that are inherent in the SAGD
process that are not present in the SWAP process invented herein.
In the SAGD process the operator has to critically control the
steam flow rate along the complete length of the SAGD injection
wellbore. This wellbore can be several thousand feet in length as
it is drilled substantially horizontally, however any deviation
from the horizontal of the producing wellbore provides a potential
zone where the steam can break through from the higher injector and
"short circuit" the recovery process by producing steam in the
lower producer. Maintaining precise horizontal separation as well
as the same azimuth, between two lateral wellbores over several
hundred feet and more than a thousand feet, is not easy and as such
the SAGD process puts higher initial capital costs and difficult
and stringent long term operational demands on the recovery
process. On the other hand the SWAP process presented herein only
needs to control the vertical flow in an axial communication zone
over a distance of a few feet. This control is easily performed by
the hydraulic seal which fills the communication zone and extends
upwards into the bottom zone of the steam bank in much the same way
as a heavy fluid can rest at the bottom of a kitchen sink over a
plugged sink drain while a lighter fluid remains above. Because of
the large volumetric extent of the steam bank encompassing several
thousand barrels, production of the accumulated fluids at the
bottom of the steam bank can occur for a substantial time before
the level of the hydraulic seal is lowered by a few feet. For
example, lowering a one acre steam bank one foot can deliver about
1,200 barrels of hot oil and water into the wellbore. This slow
lowering of fluid levels allows efficient control of the production
process and limits the potential of steam break through into the
production wellbore.
[0055] A further aspect of the SAGD process is pointed out by in
SPE 97647 in which the XSAGD process is described. SPE 97647
teaches that since under SAGD it is impossible to move the injector
and producer wells farther apart vertically, to minimize steam
breakthrough, this constraint necessitates a lowering of oil
production rates as the steam bank grows. However in the present
SWAP invention taught herein, the communication zone allows the
distance between the injector locations (perforations) and producer
locations (perforations) to be constantly changed as needed to meet
the expanding steam bank zone dimensions and this implementation
allows the new invention to maintain a more level rate of high oil
production without any steam breakthrough and in many cases to
increase steam injection and consequently oil production as the
operations develop and the steam bank contacts a larger volume of
reservoir rock.
[0056] Another aspect of the SAGD process inefficiency is the need
to inject steam in both injection and production wells for periods
up to 415 days to "pre-heat" the reservoir and create a
communication zone between the two wellbores. In this subject
invention as soon as a viable steam bank zone develops in a matter
of days, hot oil begins to accumulate in the communication zone at
the bottom of the steam bank and can be produced. Economically such
a long delay can severely impact the economics of a capital
project.
[0057] Another negative aspect of this SAGD process is the capital
needs for drilling and equipping two horizontal wells to implement
the SAGD process. Furthermore, the SAGD process requires a vertical
separation between these two horizontal wells and this property
limits the SAGD process the relatively thick pay sections and
cannot be used in thin reservoir sections. A yet further limitation
of SAGD is the effects of water zones at the base of the oil
formation on the SAGD process since the steam preferentially enters
the water zone and bypasses the cold viscous oil zones. This limits
the thermal and economic efficiency of the SAGD process. A yet
further problem associated with the SAGD process is the presence of
horizontal shale barriers in the oil formation. This shale layer
between the horizontal wellbores is in effect a vertical barrier
and the SAGD process as designed and implemented is unable to
operate since the two horizontal wells are unable to
communicate.
[0058] Additionally, to increase displacement efficiency in thermal
recovery operations, there is a need to discriminate the quality of
flowing fluid in the communication zone in a manner that allows the
operator to open or shut off the production stream and allow the
accumulated fluid to behave as an effective hydraulic seal thus
propagating the steam displacement in the steam bank. The subject
invention offers a solution to this need and provides the mechanism
by which the solution can be implemented using conventional
equipment and procedures.
[0059] Shortcomings of prior art can be related a combination of
effects. These include: [0060] (1) the inability of the process to
inject the hot fluid into a cold highly viscous oil in a limited
conductivity formation with hydrocarbon viscosities in excess of
106 cp, with this viscosity the liquid is essentially immobile at
reservoir temperature.; [0061] (2) the inability of the method to
prevent bypass of injected fluid directly from the injector source
towards the producing sink; [0062] (3) the inability of the method
to form and maintain a viable communication zone from the steam
zone or chamber to the producing sink while simultaneously
preventing bypass and early breakthrough of steam; [0063] (4) the
inability of the process to utilize the very effective gravity
drainage flow component created by the low density of the hot steam
compared to the relatively high density condensed water and hot
oil; [0064] (5) the inability of the process to heat the formation
effectively by physical contact between the steam and the rock
formation such that latent heat, the major source of steam heat
energy, can be transferred to the rock and hydrocarbons
efficiently; [0065] (6) the requirement of long lead times of
months to years of hot fluid injection, before there is any
measurable production response of the displaced oil in the
production wells; [0066] (7) the inability of the existing
technology to maintain and sustain oil production rates when
applied to large patterns of several wells; [0067] (8) the
inability of the downhole devices to determine flowing fluid
characteristics other than temperature; [0068] (9) the inability of
the technology to discriminate between flowing hot oil, hot water
and steam in the flowing material; [0069] (10) the inability of the
devices to operate based on the knowledge gained form these fluid
characteristics; [0070] (11) finally the use of overly complex
equipment of questionable operational effectiveness to implement
the process in the field.
[0071] The above discussed and other problems and deficiencies of
the prior art are overcome or improve upon by the heavy oil
recovery system of the present invention by integrating a viable
steam bank, an axial and concentric communication zone, an active
hydraulic seal, a sensible downhole controller and an operative
production system.
[0072] In contrast to the aforementioned prior art which try to
measure fluid temperatures, or pressures in the wellbore the
present invention determines the true nature of the fluid flowing,
be it steam, hot oil, hot water or a combination of each fluid.
This real time measurement is required since to adequately identify
the steam flow a measure of steam quality must be made in real time
to allow the controller to shut off the oil production inflow from
the steam bank
SUMMARY OF THE INVENTION
[0073] THIS NEW INVENTION provides an improvement in heavy oil
recovery whereby the operator injects a hot displacing fluid into a
specially designed well. An additional implementation is the
development of an integral downhole apparatus which behaves as a
flow sensor, flow controller and a flow valve simultaneously.
Operationally this device provides for flow-or-no-flow of produced
fluids depending on the type of fluid detected in the produced flow
stream. If the flow is hot oil or water the flow device is opened,
when steam is detected the valve is closed. In this application the
term flow valve and flow device are used interchangeably for a
physical element used to control fluid flow.
[0074] In this oil recovery method, the operator drills a well
which is drilled from the surface down to the producing formation.
There are several embodiments of the well ranging from single
vertical wellbores, to combined vertical and horizontal wells and
to the uniwell system which has two wellheads.
[0075] An object of this invention is to provide an improved
process for recovery of heavy oils and similar hydrocarbons from
subterranean formations. The invention uses a single well bore with
an external annular communication zone between the perforations. In
this invention, the accumulation of hot oil and condensed water at
the bottom of the steam bank and in the vertical communication zone
forms a secure controllable hydraulic seal which prevents steam
flow bypass away from the steam bank. An isolation packer
vertically separates injection and production perforations.
[0076] In one embodiment, the external annular communication zone
can be implemented by an additional tubular string outside of the
injection and production tubular string. The perforations for flow
into and out of the wellbores are in the walls of the steel
wellbore casings. In this embodiment, the annular region is a void
with infinite permeability. In another embodiment, an open-hole
communication zone can be implemented. Depending on the rock
formation and oil reservoir properties, the communication zone can
range from a few inches to several feet in diameter.
[0077] The displacing fluid is forced into the upper perforations
by a downhole packer and as steam accumulates heats up and
displaces native oil this oil and condensed water gravitate to the
bottom of the steam bank and collects in the communication annulus
waiting to be produced when the downhole controller opens the flow
control valve. In this invention, the flow-no-flow operation
permits oil and water production but shuts down when steam flow is
detected in the flow stream.
[0078] An object of this invention is to provide an improved
process for recovery of heavy oils and other highly viscous
hydrocarbons from subterranean formations by exploiting the
advantages provided by gravity drainage in the displacement process
of heavy oils in porous formations using steam driven displacement
processes. The use of a modified single well bore with coupled
pairs of injector-producer perforations in close proximity under
positive and viable flow control has several engineering benefits
including cost reduction, better fluid displacement and more
engineering control and accelerated economic recovery of the
injection and oil recovery process.
[0079] Another specific objective is to provide a means whereby the
same wellbore perforations along the vertical section of the
wellbore can be used sequentially for either injection or
production as reservoir oil depletion occurs during steam field
operations as required by the operator.
[0080] Another specific objective is to use the movable packer
between the injection and production perforations, which forces the
steam to exit the wellbore and enter the oil zone at a preset
location upstream of the production perforations.
[0081] Another specific objective is after the initial oil region
is depleted, to unseat and move the movable packer between the
injection and production perforations and the accessory downhole
flow controller apparatus a preset distance along the axis of the
wellbore and reseat them to allow the steam displacement process to
continue throughout the reservoir in a new undepleted or virgin oil
zone.
[0082] Another specific objective is to provide a concentric
communication channel in the formation, which allows the heated oil
to move from the upper steam zone to the production perforations in
the lower production zone rapidly and under gravity.
[0083] Another specific objective is to provide a means to
considerably reduce the distance the heated oil has to move through
the producing formations from the steam injection point to be
produced in the wellbore.
[0084] Another specific objective is to provide a means whereby oil
production begins as early as possible during the injection process
compared to existing technologies like Steam Assisted Gravity
Drainage (SAGD) and conventional Thermal Enhanced Oil Recovery
(TEOR), where oil production takes place after a considerable
length of steam injection ranging from several weeks to several
months and even years.
[0085] Another specific objective is to utilize and incorporate the
lateral steam gravity over-ride characteristics of the steam drive
process to enhance the "backwards" flow of hot oil from the leading
edge of the steam displacement front to the hot oil accumulation
zone and the communication zone in the invention.
[0086] Another specific objective is to utilize a set of staggered
lateral mini-wellbores drilled into the oil formation to maximize
the injection efficiency of the steam so that a steam override
effect is implemented such that a lateral physical flow gradient
occurs in the oil zone with a thin leading edge and a thicker
trailing edge. The hot oil flows along this three-dimensional
surface at the steam-oil interface.
[0087] Another specific objective is to allow the steam to replace
oil and to pressure up the steam bank at the top, which helps to
displace low viscosity, heated oil downwards along the interface of
hot steam and cold reservoir oil via the communication annulus, to
the producing perforations where there exists a localized pressure
sink because oil is being removed during production.
[0088] Another specific objective is to use a downhole steam
controller apparatus to control the flow, no-flow of steam under
specific operational conditions.
[0089] Another specific objective is to use an operatively
connected valve apparatus to shut off the flow of produced fluid in
the wellbore when the steam sensor indicates that steam
break-through has occurred and that steam is flowing down the
annular region from the steam bank to the production
perforations.
[0090] Another specific objective is to monitor operations such
that hot oil is produced until continuous steam breakthrough is
imminent then close the downhole production valve.
[0091] Another specific objective is to control the downhole
apparatus from the surface.
[0092] Another specific objective is to utilize a scavenging
displacing fluid to recuperate part of the residual hot oil in the
heated oil formation by injecting this displacing fluid after the
steam injection phase is complete.
[0093] This novel utilization proposed herein addresses the needs
and teaches a method and apparatus that is easily implemented,
allows a larger portion of the reservoir to be exposed and allows
more heavy oil recovery to occur sooner.
[0094] Improvements have been made in enhancing the contact of the
steam with the native heavy oil by the introduction of horizontal
well technology, which allows greater recovery than with the
customary vertical wells. This current invention provides a further
extension of the horizontal technology in which a novel well
completion methodology is applied to the recovery effort to allow
wells of much larger lateral extent, potentially larger diameters
and thereby more efficient recovery systems.
[0095] By implementing the new method which is taught in this
application by this invention the oilfield operator can see
improved performance, lower costs, better oilfield management, and
allow for efficient and orderly development of petroleum
resources.
[0096] THIS NEW INVENTION provides an improvement in the recovery
methods and operations of other applications wherein the process of
steam injection was controlled by a downhole apparatus forming a
closed seal, which prevents the production of fluids except under
certain field conditions and which on sensing the flow of steam
shut off the production fluid flow completely.
BRIEF DESCRIPTION OF THE DRAWINGS
[0097] The present invention consists of the wellbore and
associated components shown in the figures below:
[0098] FIG. 1a Shows a schematic of the new downhole apparatus
implemented in a uniwell.TM. system. It shows the steam bank, the
injection and production perforations, annular communication zone
and the accumulated hot fluids in the wellbore.
[0099] FIG. 1b Shows a schematic of a lateral wellbore with the new
downhole apparatus implemented in the lateral system. This
implementation can connect the lateral to a central production
cavity.
[0100] FIG. 1c Shows a vertical well embodiment with a central
production cavity below the wellbore. The steam downhole apparatus
is implemented in the inner wellbore as shown.
[0101] FIG. 2 Shows the steam zone, the communication zone and the
accumulated hot fluids in the steam bank. Also shown is the
downhole steam controller installed between the injection and
production perforations and also shown is the direction of flow of
the steam and the hot oil as they move down the communication zone
into the wellbore. This figure depicts a closed system in which the
downhole apparatus is closed so that no production occurs.
[0102] FIG. 3 Shows a schematic of the new downhole steam
controller apparatus illustrating the various component locations.
The steam sensor, the packer seal, the valve controller, the shut
off valve and the flow of steam and hot fluids around and through
the apparatus.
[0103] FIG. 4 Shows a schematic of the new downhole apparatus
implemented in the wellbore. It also shows the fluid level at the
bottom of the steam bank and the flow direction for hot fluid
entering the device.
[0104] FIG. 5 Shows a schematic of the new downhole apparatus
illustrating the device in a closed no-flow condition. FIG. 6 Shows
a schematic of the new downhole apparatus illustrating the device
in an open flow or producing condition.
[0105] FIG. 7a Shows a schematic of system operating with the new
downhole apparatus in the closed position with the hot fluids
accumulating to form a hydraulic seal at the bottom of the steam
zone. Note the elevated level of the steam-hot fluids
interface.
[0106] FIG. 7b Shows a schematic of system operating with the new
downhole apparatus in the open position with the hot fluids
draining, thus lowering the hydraulic seal level at the bottom of
the steam zone and allowing the hot oil and water to enter the
production cavity. Note the lower level of the steam hot fluids
interface.
[0107] FIG. 8 Shows a flow chart of the operations during injection
and production.
[0108] FIG. 9a, 9b, 9c, 9d Show 4 flow charts illustrating the
sequence of the operations of the invention.
[0109] FIG. 10 Shows a graphic of the typical temperature viscosity
behavior of an oil sands oil.
[0110] FIG. 11 Shows a schematic of the development of the steam
bank during injection in a system in which a series of horizontal
shale barriers occur in the oil formation.
[0111] FIG. 12 Shows a schematic of the scavenging phase in which
water is injected at the bottom of the formation as the displacing
fluid in separate wellbores after steam injection has depleted the
oil formation. Also shown is the growth sequence overlay I, II,
III, IV, V, VI of the steam zone.
[0112] FIG. 13 Shows a schematic of the scavenging phase in which a
non-condensing gas is injected at the top of the formation as the
displacing fluid in separate wellbores after steam injection has
depleted the oil formation. Also shown is the growth sequence
overlay I, II, III, IV, V, VI of the steam zone.
[0113] FIG. 14 Shows a schematic of the wellbore system with a set
of staggered horizontal mini-wellbores implemented to allow steam
injection forming a "wedge" shaped profile.
TABLE-US-00001 List of Items No. Item 1 Wellbore 2 Downhole Steam
Control Apparatus 3a Steel casing for wellbore 3b Steel casing or
Liner for annular reamed zone 4 Steam bank in Oil Formation 5 Oil
bearing formation 6a Hot oil flowing 6b Non Flowing Hot Oil 7
Primary Steam Diverter packer 8 Annular Communication Zone 9a
Injection perforations 9b Perforations in Cased Liner 10a
Production perforations in inner wellbore 10b Production
perforation in outer wellbore 11 Communication element 12 Injected
Steam Flow down wellbore 13 Top of Formation 14a High Level - Hot
Fluids - accumulating phase 14b Low Level - Hot Fluids - producing
phase 15 Flow Device (Valve) in Downhole apparatus 16 Slotted Liner
for fluid inflow 17 Steam in Steam Bank and Annular region 18 Flow
sensor 19 Flow Valve Controller 20 Hot oil gravitating down steam
bank 21a Wellbore packer - internal 21b Wellbore packer - external
22 Bottom of Formation 23 Steam and Hot oil interface 24 Steam Flow
direction 25 Surface Steam Generation System 26 WellHead 27
Production Tubing 28 Production Pump 29 Production Cavity 30 Land
surface 31 Surface control devices 32 Wellbore for Scavenger water
fluids 33 Surface water injection facilities 34 Injection lines 35
Wellbore for Scavenger ono-condensing gases 36 Surface apparatus
for non-condensing gases 37 Injected Water 38 Injected
non-condensing gas 39 Shale barriers 40 Mini-wellbores
DESCRIPTION OF THE PREFERRED EMBODIMENT OF THE INVENTION
[0114] Referring now to the drawings, wherein like elements are
numbered alike. Referring to FIG. 1a, specialized wellbore 1 is
drilled from the surface down to and into the hydrocarbon bearing
formation 5. Many drilling rig configurations can be used, regular
vertical type rigs or slant type rigs can be used to implement the
drilling phase. In field applications of this invention it is
beneficial that the wellbores be oriented along the formation dip
angle such that maximum effect of gravity can be obtained in that
the dip component adds to the gravity component and increases the
gravity segregation of the fluids because of density differences.
There are several embodiments of the wellbore system as shown in
FIGS. 1a, 1b, and 1c. One of the many embodiments includes a
uniwell system with two wellheads shown in FIG. 1a, and a second is
a lateral wellbore which can be extended as shown in FIG. 1b to
intersect a central production cavity, and third a vertical
wellbore with a production cavity shown in FIG. 1c. These three
options do not exhaust the available forms and anyone skilled in
the art can implement similar or diverse systems for completing a
similar wellbore. A significant novel improvement to the wellbore
flow system is implementation of an annular fluid communication
zone 8 shown in FIGS. 1a, 1b and 1c. This is a zone of increased
fluid conductivity which is concentric to the wellbore 1 and forms
an effective flow channel from the hot steam zone 4 to the lower
producing zone of the wellbore system. This communication zone
allows early gravity separation of the steam, hot oil and hot
water. This early precipitation of the heavier and denser fluid
components of the reservoir frees up formation pore space allowing
more steam 17 to be injected into the cold formation 5 and thereby
heating the porous medium and increasing the steam zone 4 growth
and attendant oil recovery. It is imperative that the steam has a
free pore space to enter the formation without which, fluid
displacement is impossible at the typical operating fluid flow
pressures. In practice, the annular zone is implemented in one
embodiment by a steel casing 3b installed outside the inner
wellbore 3a. In the industry, this is generally done when the well
is drilled. A steel liner or a steel screen can also be used to
form the annular communication zone in another embodiment.
[0115] Operatively implemented in this wellbore and shown in FIG.
2, is a novel element called a steam controller apparatus 2, which
monitors and controls the flow of fluid into and through the
wellbore 1 below the injection packer system 7. This device is
installed downstream of the injection system adjacent to the
production perforations 10 as illustrated in FIGS. 2 and 7a and
7b.
[0116] As shown in FIG. 3 the steam controller apparatus 2
comprises three main segments. An inflow section 16 in which the
hot fluids enter the device. An upper steam sensor section 18 which
senses the flow of gaseous steam through the device, a controller
section 19, which monitors the steam flow and which controls the
lower valve section 15 which opens and closes the flow pathway to
allow flow or shut off the flow of hot liquids as needed. Both
elements have a complement of electronic hardware and software as
shown in FIG. 8. It is noted herein, that the device 2 has to
detect steam flow which is more complex than just recording or
monitoring a fluid flow or a flow temperature. The apparatus 2 is
implemented in the wellbore 1 wherein the device is placed between
the upper injection perforations 9a, 9b and the lower production
perforations 10a, 10b. The apparatus 2 is anchored in a manner
typical to the industry and easily accomplished by those skilled in
the industry. In its initial placement in the wellbore, as shown in
FIG. 5 and FIG. 7a, the apparatus is set up in a closed state such
that no flow enters the production perforations 10. The no-flow
situation allows the accumulation of hot fluids to occur in the
communication zone 8 and the bottom of the hot steam bank zone
4.
[0117] Referring to FIG. 2, the steam injection fluid 17, which is
generated on the surface in a steam generation system 25 is
injected into the specialized wellbore 1. The steam fluid 17 is
injected down the wellbore and is directed into the cold viscous
oil bearing formation 5 by the upper packer 7. The steam 17 enters
the formation 5 through the perforations 9a in the inner casing 3a,
strategically placed external packers 21b prevent loss of steam
down the annulus. This steam then enters through the perforations
9b of the outer casing 3b. In the formation 5, it heats up the
formation rock, the interstitial water and the native oil,
significantly lowering the oil viscosity as shown in FIG. 10 from
hundreds of thousands of centipoises to tens of centipoises and
forming a steam bank or steam chamber 4. Because of the significant
fluid density differences, the hot fluids, oil and water
preferentially accumulate at the bottom of this steam chamber 4
under gravity drainage. It should be noted that as the steam
injected volumes 17 move into the farther reaches of the reservoir
5, the steam profile appears as an inverted wedge, i.e. flat at the
top and triangular on the bottom side, because the steam flows more
rapidly at the top of the formation and this override as reported
by many researchers, creates a physical flow gradient at the lower
surface of the steam bank 4. This steam bank 4 is vertically
thinner at the front or leading edge and thicker at the near
wellbore 1 region. This phenomenon allows the hot oil to literally
flow downhill and backwards through the porous formation towards
the bottom of the steam bank 4 where it collects and further into
the communication zone 8. It is also noted that this flow
phenomenon occurs in 3-dimensions since the steam bank 4 in all
respects behaves like an inverted dome with the base being
flattened and the walls of the dome being the flow surface for hot
oil and water. As shown in FIG. 2, a gas cap, literally a steam cap
17 develops at the top of the production interval and an oil and
water leg 14a (high fluid level), 14b (low fluid level) develops at
the bottom of the zone. This is a stable hydrodynamic situation and
the accumulated hot fluids 14a, 14b behave as a plug at the bottom
of the hot zone and prevents steam from moving down the
communication zone 8. The interface 23 is a horizontal plane of
density differences between the gas zone and the hot oil and water
zone. The accumulated hot fluids create a hydraulic plug 14a, 14b,
which prevents the steam from bypassing the cold formation and
traveling downwards to the production perforations. This plug
behaves much like a P-trap in a plumbing system. The invention is
designed such that the hot oil 6, condensed water and free steam
are forced to flow down the annular conductive zone 8 from the
injection zone to the production zone. As shown in FIGS. 4, 7a, 7b,
these hot fluids flow down the communication zone 8 from the
injector zone and steam bank 4 to the production zone and
production perforations 10a, (in inner wellbore), 10b (in outer
wellbore). This hydraulic plug is actively controlled by the levels
of oil production of the well and other operational actions under
the direction and control of the well operator. Hot fluid enters
perforations 10b in the outer wellbore casing and then flows into
the annular cavity 8 whence it enters through perforations 10a into
the innermost wellbore 1 and contacts the input section 16 of the
steam controller device 2. This new steam controller device 2
allows hot water and hot oil to flow but a valve 15 shuts off flow
when steam is detected in the flow stream. Substantial flow of
steam indicates that there is no more oil to be produced from the
formation.
[0118] In the field, the presence of horizontal shale barriers in
the oil zone as shown in FIG. 11 has always been a major obstacle
to developers in the prior art. The barriers 39 lower the
efficiency of the displacement processes in view of the fact that
they provide an almost impenetrable vertical barrier to steam and
oil flow. This invention however, addresses and overcomes this
major problem by the implementation of the vertical annular
communication zone 8 at the near wellbore 1 region. The presence of
this vertical communication zone 8 acts as a vertical relief valve
for oil flow. In the displacement operations as shown herein
earlier, the hot oil 6a, being displaced, will move
counter-current, under gravitational flow, backwards along the
shale barrier towards the wellbore because of the 3-dimensional
characteristics of the steam bank in which the leading edge is
always thinner than the trailing edge. At the near wellbore 1
region the communication zone allows vertical cross flow of the hot
oil and hot condensed water towards the bottom of the wellbore and
the collection and production systems. The hydraulic seal at the
bottom of the steam bank has to be controlled to limit steam
bypassing in both layers.
[0119] This vertical cross-flow resolves the problem created by the
shale barriers. In the field, there may be a plurality of shale
barriers shown in FIG. 11, and the same phenomenon will occur
simultaneously in all the steam displacement layers because the oil
flow occurs along the surface of the steam bank interface with cold
reservoir oil and the hot steam, and is not driven by pressure
gradients but by the density differences of the two fluid
phases.
[0120] Referring to FIG. 14 in which a series of lateral or
horizontal mini-wellbores 40 are drilled radially from the initial
wellbore 1 to increase steam injection efficiency. In this
embodiment, the mini-boreholes 40 they are drilled in a staggered
pattern such that a wedge-like cross-section of the steam bank is
obtained when steam 17 is injected. This cross-section wedge is
thicker at the near wellbore region and thinner at the leading or
front edge of the steam 17. This type of profile provides a
physical flow system in which the hot oil 20 can flow backwards
more readily to the bottom of the steam bank 4 and the axial
concentric communication zone 8. These mini-wellbores 40 can be
predrilled through out the oil formation 5 at specific vertical
depths prior to the steam injection process. In this way when the
injection system is moved axially down the main wellbore 1 these
predrilled mini-wellbores 40 are already in place and available for
steam injection and can also aid in hot oil inflow to the
communication zone 8.
[0121] Referring to FIGS. 5, 6 which show that except under
specific conditions, the steam control apparatus 2 prevents the
flow of hot fluids 6a through the production perforations 10a, 10b.
When the hot fluid flow is allowed, the hot fluid comprising oil
and condensed steam enters the wellbore 1 and flows down the well
to the collection system and the pumping mechanism 28 of the
producing system. As the fluid flows into the steam controller
apparatus 2, sensing components in the device shown in FIG. 8,
detect the presence of steam. When steam is detected, the apparatus
shuts off fluid flow as illustrated in FIG. 5 since there is no
more oil to be produced at the current time. However, continuous
steam injection still occurs in the wellbore in the upper injection
zone perforations 9a and the accumulation of hot oil at the bottom
of the steam zone 4 continues. After a predetermined time as
computed by the well operator in which sufficient oil has
accumulated, the apparatus reopens the production phase to allow
the hot oil 6a (flowing), 6b (non-flowing) to be produced.
Production of oil and water occurs when the downhole pump 28 is
activated and the accumulated oil 14a, 14b in the wellbore is
produced in the customary manner used in the industry. If the
downhole pressure is sufficient, it is possible to flow the oil
directly to the surface.
[0122] This steam controller apparatus 2 along with the wellbore
packers 21a, 21b are sequentially moved down the wellbore 1 and
reseated in a new axial location as the steam injection process
continues until the recoverable oil in the formation 5 is depleted.
In one rudimentary embodiment of the invention, a downhole sensor
18 is not utilized but the flow control apparatus 19 is turned on
and off to open the flow valve 15 at selected times for specific
producing time intervals. This "dumb" approach using a "null"
sensor can be used in situations where the sensors are unavailable.
A further option of the "dumb" approach is to flow the wells in the
producing cycle until steam is visible at the surface 30 then to
shut off the downhole valve 15 such that the hydraulic seal created
by fluid 14a, 14b can start re-forming. These embodiments are
wasteful of steam energy and reservoir productivity however, they
can still function under the prevailing reservoir conditions and in
operating conditions where the low cost of steam generation makes
it economically attractive, examples are in some remote foreign
environments where environmental concerns on combustion processes
for steam generation are not as stringently regulated. An
alternative approach to using the "null" sensor uses historical
data analysis to correlate statistically, injection and production
times such that an intelligent estimate of the required production
time before steam breakthrough occurs can be made. In this way, the
"dumb" approach can be more effective and lessen injected steam
waste.
[0123] Power to the downhole apparatus 2 can be implemented by the
power cable 11 and information back and forth from the downhole
apparatus to the surface can be effected by either a wired or
wireless telemetry system. Both systems are typical to the industry
and can be done by anyone competent in the field. Optical fibers
are a well-developed communications medium used in the
telecommunications industry and have been progressively adopted for
uses in sensors in the oil and gas industry. One of the greatest
benefits of these sensors is the high temperature capability and
reliability, which makes them well suited for steam injection and
other thermal recovery processes. These fiber optic systems are
intrinsically safe since they only transmit light and no electrical
flow occurs which completely removes the possibility of a spark to
ignite the volatile hydrocarbons in the wellbore.
[0124] As shown in FIG. 3 and further illustrated in FIGS. 5, 6, 8,
the device 2 comprises the following elements. An inlet section 16
which is generally a slotted liner or a metal sieve to allow the
hot fluids to enter the device. The fluid sensor 18 comprises a
steam flow sensor for example, a mass flow detector which is
minimally capable of determining in realtime the mass of flowing
fluid as well as the temperature, pressure and quality of the flow
stream. This sensor 18 has its own logic and computer capability to
process the data and make it available to other elements of the
steam controller 2 and the surface devices 31. In addition
operatively connected to the sensor system 18 is a flow device
controller system 19. This flow device controller 19 has a full
complement of hardware circuitry, software and software logic,
memory and storage capabilities to process, store, transmit and
implement the instructions needed to control the operations of the
flow valve 15 directly or on command from the surface devices 31 as
seen in FIG. 8. The flow valve or flow control device 15 is a
system typical of the flow devices in industry and are made in a
variety of forms. These valve systems 15 are well known in the
industry and are actuated in a variety of ways. Implementation of
the combination of steam sensor, controller and flow valve as a
means of limiting steam flow through an axial communication zone
below an operating steam bank provides a new means of accelerating
production from a single well. This single well accelerated
production or abbreviatively called SWAP.TM. technology provides
for accelerated economics in the enhanced oil recovery
industry.
[0125] Operationally the preferred embodiment of the invention is
practiced as shown by the following: Referring to FIG. 9a, step 110
illustrates the drilling phase of the field application. In this
phase, the operator selects the type of well(s) that should be
drilled. These types are shown in FIGS. 1a, 1b, 1c, and FIG. 14 in
the case of staggered horizontal or lateral mini-wellbores being
implemented. After the wellbores 1 are drilled, in one embodiment,
the communication zone 8 is cased and perforations 9a, 9b, 10a, 10b
are made in the tubular goods. As shown in step 111, packers 21a
and 21b are prepared and seated as needed in the wellbores when the
steam control device 2 is installed in the inner wellbore 1. At the
same time, the operator computes the steam injection times and
rates. After these specific times, the operator can monitor and
operations and trigger the downhole steam control device 2 to open
up the flow valve 15 as dictated by the flow times. In step 112,
steam is generated on the surface in steam generators 25, as shown
in FIG. 1 In FIGS. 2 and 7a, the steam is injected down the
wellbore 1, and meets the downhole packer 7 which diverts the steam
flow 12 as seen in FIG. 4 thorough the injection perforations 9a
and 9b of the steel wellbore 3a and the annular casing 3b. Flow
down and out of the annular zone 8 is prevented by packers 21b.
[0126] In the operational case where no packers 21b are used some
steam can be sacrificed to fill up the annular cavity with no great
loss of efficiency. The injected steam 17 begins to heat up the
reservoir formation 5, it forms a steam zone or steam bank 4 in
which hot oil and hot water accumulate with the steam. The high
formation temperature lowers the oil viscosity considerably as
shown in FIG. 10 and this oil flow driven by the combined forces of
gravity, formation dip angle and pressure in the steam bank 4,
gravitates to the bottom of the zone to form a liquid saturated
zone 14. This zone forms a fluid-steam contact 23 in the formation
similar to an oil/water contact in natural reservoirs which is
formed by fluid density differences. In this invention, the steam
cap 4 is analogous to a gas cap and the fluid zone 14 is analogous
to an oil leg in typical hydrocarbon reservoirs. As indicated in
step 112 this layer of hot oil and water 14a, 14b forms a hydraulic
seal at the bottom of the steam bank. This hydraulic seal 14 is an
integral part of the invention and its existence in the steam zone
4 and the communication zone 8 prevents the flow of steam into the
wellbore until this seal height is lowered or the fluid is removed
by production.
[0127] The hot dense fluids, oil and water, enter the annular
communication zone through production perforations 10b in the cased
wellbore 3b. Here they remain until the steam controller device 2
"allows" them to enter the production perforations 10a and finally
the inner wellbore 1. During the injection phase the steam bank
grows and its growth and volumetric extent can be easily calculated
by many publicly available computer simulation models. The operator
as shown in step 113 monitors the injection process and is able to
estimate the volume of oil accumulating at the bottom of the zone 4
in the oil leg 14a, 14b. At the pre-determined time the downhole
steam controller 2 is triggered by the control device 31, the flow
control valve 15 is opened and hot fluids begin to enter the inflow
section 16 of the device 2 and flow past the steam sensor 18. The
steam flow sensor measures the fluid characteristics as shown in
steps 102, 103, 104, 105, 106, 107 of FIG. 8. As the flow
continues, the level of the fluid interface 23 is lowered, the
fluid leg drops from a high volume at 14a to a lesser volume at 14b
as shown in FIG. 7b. This fluid lowering occurs in the steam zone 4
and in the communication zone 8. The produced fluids oil and water
collect in the inner wellbore, are transported under gravity, and
flow pressure to the production zone of the respective well systems
used. These can be either into the production cavity 29 of FIG. 1c
or the lateral wellbore of FIG. 1a, or the central production
cavity described for FIG. 1b. In all cases, the production
mechanism 28 is used to lift the oil to the surface if there is
insufficient pressure from the injected fluids to lift the fluid to
the surface.
[0128] As oil production continues through the steam controller
device 2, the flow characteristics are monitored constantly by
device element 18 and the information is processed locally or
remotely at the surface. When the sensor detects the flow of live
steam 17 entering the wellbore 1, the valve controller device 19
triggers the valve 15 to close and no more fluid flow 6a, 6b is
allowed to enter the wellbore 1. This operation creates a shut-off
situation and hot fluid 14a, 14b begins to re-accumulate in the
communication zone 8 and the bottom of the steam zone 4. This
re-accumulation creates a new hydraulic seal which prevents the
steam from bypassing the cold oil formation and directs it to enter
the formation 5 where it remains at the top of the steam zone 4.
Steam injection continues at all times during the production
phase.
[0129] As indicated in step 114, the operator has to make a
decision when the oil in the steamed zone 4 is depleted. If an
analysis of the cumulative oil volume produced indicates that the
reservoir formations 5 are economically depleted, then the heavy
oil recovery operations are terminated. If however, there is still
economically recoverable oil in the reservoir the injection site
for steam injection through the perforations and the steam
controller device must be moved axially down the length of the
wellbore to a new location to exploit additional oil reserves. This
translocation process is shown in step 115. In this step 115, steam
injection is temporarily halted, the packers 21a, 21b are unseated,
the steam controller 2 is unseated and both systems are moved a
calculated distance down the wellbore 1 to be reseated opposite a
new set of injection 9--production 10 pairs of perforations.
[0130] After this re-location, all systems are re-established and
steam injection continues.
[0131] This process of injection, production, decision analysis and
relocation continues until the reservoir is fully depleted as shown
in step 116. Steam injection and production are then terminated and
the displacement scavenging operations are initiated as shown in
step 117 of FIG. 9d. This process is an "oil salvage" process in
which displacing fluids are injected into the hot formation 5 after
steam displacement is complete. This is recuperative process well
known in the industry in which additional oil can be recovered by
flowing these displaced fluids through a hot reservoir with reduced
viscosity oil. The scavenging displacement process is helped by the
fact that the heated reservoir rock has a higher porosity, higher
permeability and the residual oil has a lowered viscosity, all of
these factors are complimentary in their effects in promoting
additional recovery of in-situ oil. Field tests have shown that as
much as 22% of the total oil recovered can be achieved after the
scavenging process is initiated. In implementing the scavenging
phase, the injected displacing fluids are injected in a plurality
wellbores. These wellbores are either: [0132] (a) newly drilled
horizontal and vertical injector wellbores; or [0133] (b) existing
wellbores formerly used for steam injection.
[0134] Referring to FIG. 12 treated water 37 from a surface supply
source 33 is injected down an injector well 32 and enters the
formation at the bottom of the depleted steam bank 4. In one
embodiment, these injector wells 32 can be vertical wellbores or in
other embodiments, they can be substantially horizontal wellbores.
This water 37 displaces the oil towards the wellbore 1 which has
all its perforations 9a, 9b, 10a, 10b open to allow oil flow into
the wellbore driven by the water pressure and production of
displaced oil and hot water occurs and is pumped to the
surface.
[0135] Referring to FIG. 13 non-condensing gas or flue gas from a
surface supply source 36. The supply source can be the treated
exhaust of the steam generation equipment 25. This flue gas 38 is
injected down an injector well 33 and enters the formation 5 at the
top of the depleted steam bank 4. In one embodiment, these injector
wells 33 can be vertical wellbores or in other embodiments, they
can be substantially horizontal wellbores. This gas 38 displaces
the oil towards the wellbore 1 which has all its perforations 9a,
9b, 10a, 10b open to allow oil flow into the wellbore driven by the
gas pressure and production of displaced oil and gas occurs and the
oil is pumped to the surface. The gas can be produced up the casing
annulus of the wellbore. Being less dense the injected flue gas
remains at the top of the steam bank while the denser water
gravitates to the bottom of the steam bank 4.
[0136] In one embodiment, both water injection and flue gas
injection can occur simultaneously or sequentially. After gas and
water breakthrough has occurred, injection is continued to the
economic limit of the projects and then terminated as shown in item
118 of FIG. 9d.
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* * * * *
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