U.S. patent application number 12/965515 was filed with the patent office on 2011-08-04 for recovery of hydrocarbons using artificial topseals.
Invention is credited to Robert D. Kaminsky, Robert Chick Wattenbarger.
Application Number | 20110186295 12/965515 |
Document ID | / |
Family ID | 44318309 |
Filed Date | 2011-08-04 |
United States Patent
Application |
20110186295 |
Kind Code |
A1 |
Kaminsky; Robert D. ; et
al. |
August 4, 2011 |
Recovery of Hydrocarbons Using Artificial Topseals
Abstract
A method is described for recovering viscous oil such as bitumen
from a subsurface formation. The method involves creating an
artificial barrier in a subterranean zone above or proximate a top
of the subsurface formation. The barrier is largely impermeable to
fluid flow. The method also includes reducing the viscosity of the
viscous oil and mobilizing hydrocarbons into a readily flowable
heavy oil by addition of heat and/or solvent. Heating preferably
uses a plurality of heat injection wells. The method further
includes producing the heavy oil using a production method that
preserves the integrity of the artificial barrier.
Inventors: |
Kaminsky; Robert D.;
(Houston, TX) ; Wattenbarger; Robert Chick;
(Houston, TX) |
Family ID: |
44318309 |
Appl. No.: |
12/965515 |
Filed: |
December 10, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61299696 |
Jan 29, 2010 |
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Current U.S.
Class: |
166/302 ;
166/369 |
Current CPC
Class: |
E21B 43/24 20130101;
E21B 43/00 20130101 |
Class at
Publication: |
166/302 ;
166/369 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 43/00 20060101 E21B043/00 |
Claims
1. A method of recovering a viscous hydrocarbon from a subsurface
formation, comprising: creating an artificial barrier in a
subterranean zone above or proximate a top of the subsurface
formation, the barrier being substantially continuous over an area
that is at least about five acres (20,232 m.sup.2), and is largely
impermeable to fluid flow; reducing the viscosity of the viscous
hydrocarbon in at least a portion of the subsurface formation so as
to mobilize the viscous hydrocarbon into a flowable heavy oil; and
producing the heavy oil using a production method that maintains
the integrity of the artificial barrier.
2. The method of claim 1, wherein reducing the viscosity of the
viscous hydrocarbon comprises heating the subsurface formation.
3. The method of claim 1, wherein reducing the viscosity of the
viscous hydrocarbon comprises injecting a hydrocarbon solvent into
the subsurface formation.
4. The method of claim 3, wherein the hydrocarbon solvent comprises
components in the C.sub.3 to C.sub.10 range.
5. The method of claim 1, wherein the viscous hydrocarbon has a
viscosity greater than about 1,000 cp in its undisturbed in situ
state.
6. The method of claim 5, wherein the viscous hydrocarbon comprises
primarily bitumen.
7. The method of claim 1, wherein the artificial barrier is formed
above and within about five meters of the top of the subsurface
formation.
8. The method of claim 7, wherein: reducing the viscosity of the
viscous hydrocarbon comprises heating the subsurface formation; and
heating the subsurface formation comprises forming a plurality of
heat-supplying wells.
9. The method of claim 8, wherein: each of the heat-supplying wells
carries an electric current; and heating the subsurface formation
comprises applying electrical-resistive heat to the subsurface
formation to reduce the viscosity of the viscous hydrocarbon.
10. The method of claim 8, wherein each of the heat-supplying wells
injects a heated fluid.
11. The method of claim 10, wherein the injected fluid is injected
at a pressure no greater than about 300 psi above an initial
reservoir pressure.
12. The method of claim 10, wherein the injected fluid is injected
at a pressure no greater than about 100 psi above an initial
reservoir pressure.
13. The method of claim 10, where the heated fluid comprises a
vaporized fluid.
14. The method of claim 13, wherein the vaporized fluid comprises
steam.
15. The method of claim 14, wherein the vaporized fluid forms a
steam chamber from which viscous hydrocarbons gravity-drain to a
production well.
16. The method of claim 15, wherein the vaporized fluid further
comprises a hydrocarbon solvent.
17. The method of claim 16, wherein the hydrocarbon solvent
primarily comprises components in the C.sub.3-C.sub.5 range.
18. The method of claim 16, wherein the hydrocarbon solvent
condenses at initial in situ temperature conditions and in situ
pressures.
19. The method of claim 8, wherein: producing the heavy oil
primarily utilizes gravity drainage; and production is
continuous.
20. The method of claim 8, wherein: forming the plurality of heat
injection wells comprises forming first horizontal wells to serve
as the heat injection wells; the method further comprises forming
second horizontal wells to serve as production wells; and wherein:
the first and second wells form respective pairs of wells; and the
first and second wells are completed substantially within a
vertical plane.
21. The method of claim 7, wherein creating an artificial barrier
comprises injecting a gelling fluid into the subterranean zone, the
gelling fluid forming a gel within the subterranean zone after a
period of setting.
22. The method of claim 21, wherein: the gelling fluid is a polymer
solution; and the polymer solution is injected into the
subterranean zone at a pressure below a fracture pressure of the
subterranean zone.
23. The method of claim 22, wherein: the polymer solution is a
cross-linking polymer solution; and the polymer solution forms the
gel as a result of a chemical reaction in situ.
24. The method of claim 21, wherein the gelling fluid has
sufficient density to cause it to flow downward and spread over the
viscous hydrocarbon proximate the top of the subsurface
formation.
25. The method of claim 21, wherein: the gelling fluid is a
temperature-sensitive emulsion containing wax which at least
partially solidifies after injection as a result of cooling in
situ; and the emulsion is injected into the subterranean zone.
26. The method of claim 7, further comprising: injecting a fluid
into the subterranean zone above a fracture pressure so to form
horizontal fractures and to form the artificial barrier.
27. The method of claim 26, wherein the injected fluid is a polymer
solution, a clay slurry, or cement.
28. The method of claim 7, wherein creating an artificial barrier
comprises injecting a fluid into the subterranean zone, the fluid
precipitating solid particles within the subterranean zone and
reducing formation permeability.
29. The method of claim 7, wherein creating an artificial barrier
comprises: completing a plurality of refrigerator wells in the
subterranean zone; circulating a cooling fluid through each of the
plurality of refrigerator wells; and causing water in the
subterranean zone to substantially freeze in situ.
30. The method of claim 29, wherein each refrigerator well
comprises: an elongated tubular member for receiving the cooling
fluid and for transporting the cooling fluid to the subterranean
zone; and a first expansion valve in fluid communication with the
tubular member through which the cooling fluid flows.
31. The method of claim 29, further comprising: chilling the
cooling fluid below ambient air temperature prior to circulating
the cooling fluid through each of the plurality of refrigerator
wells.
32. The method of claim 1, wherein the artificial barrier is
substantially continuous over at least 10 acres (40,464
m.sup.2).
33. A method for recovering viscous hydrocarbons from a subsurface
formation, comprising: locating a permeable subterranean zone
geologically above the subsurface formation; injecting a gelling
fluid into the subterranean zone in a liquid phase; allowing time
for the gelling fluid to gel within the subterranean zone and form
an artificial topseal over the subsurface formation; forming a
plurality of heat injection wells into the subsurface formation;
forming a plurality of producer wells into the subsurface formation
such that each injector well has one or more associated producer
wells, thereby creating sets of wells; injecting steam into each of
the plurality of heat injection wells in order to heat the
subsurface formation, thereby, (i) creating steam chambers within
the subsurface formation, (ii) reducing the viscosity of the
viscous hydrocarbons, and (iii) mobilizing the viscous hydrocarbons
into a flowable heavy oil; and producing the heavy oil through each
of the plurality of producer wells.
34. The method of claim 33, wherein each of the heat injection
wells is completed horizontally within the subsurface
formation.
35. The method of claim 33, wherein each of the producer wells is
completed horizontally within the subsurface formation.
36. The method of claim 34, wherein: each of the heat injection
wells is completed horizontally within the subsurface formation;
each of the producer wells is completed horizontally within the
subsurface formation, such that each of the sets of wells is a pair
of wells; and each of the pairs of wells is completed substantially
within a vertical plane.
37. The method of claim 33, further comprising: injecting a
hydrocarbon solvent into the subsurface formation with the steam as
the steam chambers grow away from the heat injection wells.
38. The method of claim 37, wherein the hydrocarbon solvent
comprises hydrocarbon components in the C.sub.3 to C.sub.5
range.
39. The method of claim 33, wherein (i) the temperature of the
injected steam is reduced before the steam chamber reaches the
artificial topseal, (ii) the composition of the injected steam is
modified to include a hydrocarbon solvent after injection has
begun, (iii) a pressure at which steam is injected through the heat
injection wells is reduced after injection into the subsurface
formation has begun, or (iv) combinations thereof, thereby
preserving the effectiveness of the artificial topseal.
40. The method of claim 33, wherein the gelling fluid is a
cross-linked polymer solution that chemically reacts within the
subterranean zone to form a gel.
41. The method of claim 33, wherein: the gelling fluid is a waxy,
oil-external emulsion comprising oil, added wax, and water; the
waxy emulsion is formulated to be substantially a solid at initial
in situ temperature conditions and in situ pressures in the
subterranean zone; and the method further comprises heating the
waxy, oil-external emulsion into a flowable liquid at a surface
heater before injecting the emulsion into the permeable
subterranean zone.
42. The method of claim 41, wherein the water concentration of the
waxy emulsion is 40 to 60 volume % of water.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] The present application claims priority to and the benefit
of U.S. Provisional Patent Application Ser. No. 61/299,696, which
was filed on 29 Jan. 2010, which was entitled, RECOVERY OF
HYDROCARBONS USING ARTIFICIAL TOPSEALS, and which is incorporated
herein by reference in its entirety for all purposes.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to the field of hydrocarbon
recovery from subsurface formations. More specifically, the present
invention relates to the in situ recovery of hydrocarbon fluids
from viscous oil formations including, for example, oil sands
formations containing bitumen. The present invention also relates
to methods for sealing a formation to prevent the upward migration
of an injected heating vapor and/or solvent.
[0004] 2. Discussion of Technology
[0005] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0006] For many years, oil companies have explored for and produced
hydrocarbons. While the term "hydrocarbons" generally refers to any
organic material with molecular structures containing carbon bonded
to hydrogen, hydrocarbons have primarily been produced from
subsurface formations where the hydrocarbon is in a fluid form. In
a liquid state, such hydrocarbons are commonly referred to as
"oil," while in a gas state such hydrocarbons are known as "natural
gas."
[0007] In the last 25 years, energy companies have investigated the
production of hydrocarbons that reside in a highly viscous or even
solid (non-fluid) form. Such hydrocarbons may generally be referred
to as "heavy hydrocarbons" and "solid hydrocarbons,"
respectively.
[0008] "Solid hydrocarbons" refers to any hydrocarbon material that
is found naturally in substantially solid form at formation
conditions. Examples include kerogen, coal, shungites, asphaltites,
and natural mineral waxes. Heavy hydrocarbons include hydrocarbons
that are highly viscous at ambient conditions
(15.degree.-25.degree. C. and 1 atm pressure). These include
bitumen, asphalt, and so-called heavy oil.
[0009] The viscosity of heavy hydrocarbons is generally greater
than about 100 centipoise at 15.degree. C. Bitumen and heavy oil
are sometimes together referred to as viscous oils. Heavy
hydrocarbons may also be classified by API gravity, and generally
have an API gravity below about 20 degrees. Heavy oil, for example,
generally has an API gravity of about 10 to 20 degrees, whereas tar
generally has an API gravity below about 10 degrees.
[0010] The terms "bitumen" and "tar" are sometimes used
interchangeably. Both materials are highly viscous, black, and
sticky substances. However, the naturally occurring tar in
subsurface formations is technically bitumen. Bitumen is a
non-crystalline, highly viscous hydrocarbon material that is
substantially soluble in carbon disulfide. Bitumen includes highly
condensed polycyclic aromatic hydrocarbons, and is commonly used
for paving roads.
[0011] Viscous oil deposits are located in various regions of the
world. For example, viscous oils have been found in abundance in
the Milne Point Field on the North Slope of Alaska. Viscous
hydrocarbons also exist in the Jobo region of Venezuela, and have
been found in the Edna and Sisquoc regions in California. In
addition, extensive formations of oil sands exist in northern
Alberta, Canada. These formations are sometimes referred to as "tar
sands," though they technically contain bitumen.
[0012] The Athabasca oil sands deposit in northern Alberta is one
of the largest viscous oil deposits in the world. There are also
sizable oil sands deposits on Melville Island in the Canadian
Arctic, and two smaller deposits in northern Alberta near Cold Lake
and Peace River. The oil sands contain substantial amounts of
bitumen.
[0013] There are two methods currently used to extract bitumen from
the ground. These are an open pit mining process, and an in situ
recovery process. In either instance, once extracted, oil sands
producers typically maintain the hydrocarbon material in a heated
condition and/or add lighter hydrocarbons to the bitumen to allow
it to flow through pipelines. Upgraders then process the bitumen
into synthetic crude.
[0014] Open pit mining resembles conventional mining techniques,
and is effective in extracting oil sands deposits if the deposits
are sufficiently tar-like. Mining of bitumen deposits is a
well-established technology. However, bitumen mining has several
drawbacks. First open pit mining is generally limited to oil sands
deposits that are near the surface. Generally, production is
limited to formations that are less than about 80 meters in depth
due to the cost of overburden removal. In addition, there are high
capital and maintenance costs associated with solids-handling
equipment. Further, open pit mining may require high water usage
for separating the bitumen from the sand. Finally, open pit mining
creates a substantial disruption of the surface for years during
recovery operations and until restoration activities are
performed.
[0015] The bulk of Canada's oil sands deposits are too deep below
the surface to use open pit mining. However, the in situ recovery
method may reach the deeper deposits. In situ extraction often
involves the use of a heated fluid to separate bitumen from the
sands at a selected depth, and permit the heated bitumen to flow
through wells to the surface. The heated fluid may be steam.
Alternatively, the heated fluid may be a solvent vapor or a
steam-solvent mixture. In some processes, unheated solvent is used
in a liquid or vapor state.
[0016] Several steam injection processes have been suggested for
heating bitumen. One general method for recovering viscous
hydrocarbons is by using a "steam stimulation" technique known as
the "huff-and-puff" process. In the huff-and-puff process, steam is
injected into a formation by means of one or more wells. The wells
are then shut-in to permit the steam to heat the bitumen, thereby
reducing its viscosity. Subsequently, all formation fluids,
including mobilized bitumen and at least partially condensed steam,
are produced together from the well using accumulated reservoir
pressure as the driving force for production.
[0017] Initially in the huff-and-puff process, sufficient pressure
may be available in the vicinity of the wellbores to lift fluids to
the surface. As the pressure falls, artificial lifting methods are
normally employed. Production is terminated when artificial lift is
no longer effective. Steam is then injected again. This cycle may
take place many times until oil production is no longer
economical.
[0018] In the huff-and-puff method, the highest pressures and
temperatures exist in the vicinity of the well immediately
following the injection phase. Normally this pressure and
temperature will correspond to the properties of the steam which
was employed. Before oil can be moved from the remote parts of the
reservoir to the well, the pressure in the near well region must
fall so that it is lower than the distant reservoir pressure.
During this initial depressuring phase, the near-wellbore reservoir
material cools down as water flashes into steam. The first
production from the well thus tends to be steam, and this tends to
be followed by hot water. Eventually, the pressure is low enough
that oil can move to the wellbore.
[0019] In the initial production phase, much of the heat which was
put into the reservoir with the steam is simply removed again as
steam and hot water. A major inefficiency of the huff and puff
process is that this heat must be supplied during each cycle. As
the available oil becomes more remote from the well, this cyclic
wasted heat quantity increases, meaning that more hot water but
less mobilized bitumen is produced.
[0020] U.S. Pat. No. 4,344,485, entitled "Method for Continuously
Producing Viscous Hydrocarbons by Gravity Drainage While Injecting
Heated Fluids," presented an improved steam injection technique.
This technique is known as steam-assisted gravity drainage, or
SAGD. This is a low pressure in situ application.
[0021] In SAGD, an injection well is completed for injecting a
heated fluid such as steam. A production well for producing oil and
condensate is also drilled into the formation adjacent to the
injection well. The wells are also completed such that separate oil
and water flowpaths in at least the near-wellbore region of the
production well are ensured with appropriately throttled injection
and production rates. Variants of SAGD exist in which solvent is
added to the steam (see U.S. Pat. No. 6,662,872) or solvent
completely replaces the steam (see U.S. Pat. No. 5,407,009 and U.S.
Pat. No. 6,883,607).
[0022] Initially, the formation may be fractured by injecting the
heated fluid via the injection well at a higher-than-fracture
pressure. Alternatively, a suitable fracturing fluid may be used to
create fractures. Alternatively still, no fracturing is performed
and fluid communication between the wells is established simply by
heating.
[0023] Next, steam is injected via the injection well to heat the
formation. As the steam condenses and gives up its heat to the
formation, the viscous hydrocarbons are mobilized. The hydrocarbons
then drain by gravity toward the production well. Mobilized viscous
hydrocarbons are able to be recovered continuously through the
production well.
[0024] In one embodiment, two nearly horizontal wells are formed,
with one well being located directly above the other. In this
arrangement, the upper well is used to inject steam and then remove
water and condensate, while the lower well is used to continuously
produce the mobilized viscous oil. In another embodiment, two
vertical wells are provided, with one well being the steam
injection/water production well, and the other being a hydrocarbon
production well. In yet a third embodiment, a horizontal well is
drilled and extended below a vertical steam injection well. Steam
is injected into the formation, causing the mobilization of heavy
oil. Oil is then produced through the elongated horizontal
well.
[0025] A requirement of SAGD and other in situ bitumen recovery
methods is the need for a largely impermeable topseal. A topseal is
an impermeable geological barrier provided in a more shallow
formation. The topseal serves to contain injected fluids and/or
gases that are released or created during heating and production.
These released gases may include greenhouse gases such as methane
or carbon dioxide. Moreover, the injected fluids contain heat which
would reduce process efficiency if lost to an overburden
region.
[0026] Many shallow bitumen deposits have tops that are geologic
unconformities such as eroded zones. Such zones are not effective
topseals as they are relatively permeable to fluid flow. Lack of a
topseal typically prevents economic recovery of mobilized heavy
hydrocarbon deposits since any injectant (e.g., steam) readily
channels into the permeable overburden and is lost to
non-productive areas. In some cases, the injectant will leak all
the way to the surface. In either instance, the injectant does not
effectively penetrate the viscous oil material.
[0027] Therefore, there is a need for new methods for recovering
viscous oil from subterranean deposits lacking effective
topseals.
SUMMARY OF THE INVENTION
[0028] The methods described herein have various benefits in the
conducting of oil and gas exploration and production activities in
formations having oil sands or other viscous oil deposits.
[0029] First, a method is provided for recovering a viscous
hydrocarbon from a subsurface formation. In one embodiment, the
method includes creating an artificial barrier in a subterranean
zone. The subterranean zone is above or proximate a top of the
subsurface formation. Preferably, the artificial barrier is formed
within 5 meters of the top of the subsurface formation. The
artificial barrier is largely impermeable to fluid flow.
[0030] The artificial barrier may be formed by injecting a polymer
solution into the subterranean zone. The polymer solution
chemically reacts in situ to form a gel. Preferably, the polymer
solution is injected into the subterranean zone at a pressure below
the fracture pressure. Alternatively, a fluid may be injected into
the subterranean zone above the fracture pressure so to form
horizontal fractures only and fill the fractures with a
barrier-forming substance. The artificial barrier may alternatively
be formed by injecting a waxy emulsion, a clay slurry, or molten
sulfur, or by jetting in a grout material.
[0031] In another arrangement, the step of creating an artificial
barrier may involve completing a plurality of refrigerator wells in
the subterranean zone. In this instance, a cooling fluid is
circulated through each of the plurality of refrigerator wells.
Circulation of the cooling fluid causes water in the subterranean
zone to covert to ice in situ. Thus, a frozen horizontal barrier is
formed.
[0032] The method also includes reducing the viscosity of the
viscous hydrocarbon, and mobilizing the viscous hydrocarbon into a
readily flowable heavy oil. In a preferred embodiment, this is
accomplished by use of heat applied to the subsurface formation.
Heating the formation has the effect of reducing the viscosity of
the viscous hydrocarbon, and mobilizing the viscous hydrocarbon
into a readily flowable heavy oil. In one aspect, heating involves
the creation of a plurality of heat-supplying wells. Each of the
heat-supplying wells may carry an electric current. In this
instance, heating the subsurface formation comprises applying
electrical-resistive heat to the subsurface formation to reduce the
viscosity of the viscous hydrocarbon. In another aspect, each of
the heat-supplying wells is a heat injection well. In this
instance, heating the subsurface formation comprises injecting a
heated, vaporized fluid as an injectant through each of the
injection wells. The injectant may be, for example, steam, a
hydrocarbon solvent, or combinations thereof. In some embodiments,
a hydrocarbon solvent may be injected in an unheated stated.
[0033] The method further includes producing the heavy oil to the
surface. The production process uses a low-pressure production
method. An example is a gravity drainage method that provides for
essentially continuous production. The production method is
compatible with the artificial barrier, meaning that the production
method does not compromise the integrity of the topseal.
[0034] The viscous hydrocarbon may have a viscosity greater than
about 100 centipoise in its undisturbed in situ state. In one
aspect, the viscous hydrocarbon comprises primarily bitumen.
[0035] An alternative method for recovering viscous hydrocarbons
from a subsurface formation is provided herein. This method may
first comprise locating a permeable subterranean zone geologically
above the subsurface formation. A gelling fluid is then injected
into the subterranean zone in a liquid phase. After a time, the
gelling fluid will gel, forming an artificial topseal over the
subsurface formation.
[0036] In one aspect, the gelling fluid is a polymer solution that
undergoes a chemical reaction within the subterranean zone to
slowly form the gel. In another aspect, the gelling fluid is a
temperature-sensitive, waxy, oil-external emulsion comprising oil,
added wax, and water. The waxy emulsion is formulated to be
substantially a solid at initial in situ temperature conditions and
in situ pressures in the subterranean zone. In order to inject the
gelling fluid, the method further comprises heating the waxy,
oil-external emulsion into a flowable liquid at a surface heater
before injecting the emulsion into the permeable subterranean zone.
The emulsion will form the gel as it cools in the subterranean
zone. In another aspect, the injected fluid chemically reacts in
situ to form a solid precipitate which leads to pore plugging and
permeability reduction of the formation rock.
[0037] The method also includes forming a plurality of heat
injection wells into the subsurface formation, and also forming a
plurality of producer wells into the subsurface formation. Each
injector well has one or more associated producer wells, thereby
creating sets of wells for the recovery operation. In one aspect,
each of the heat injection wells is completed horizontally within
the subsurface formation. In another aspect, each of the producer
wells is completed horizontally within the subsurface formation. In
one embodiment, each of the heat injection wells is completed
horizontally within the subsurface formation and each of the
producer wells is completed horizontally within the subsurface
formation, such that each of the sets of wells is a pair of wells,
and each of the pairs of wells is completed substantially within a
vertical plane.
[0038] The method further includes injecting steam into each of the
plurality of heat injection wells. Injecting steam serves to heat
the subsurface formation. The heat (i) creates steam chambers
within the subsurface formation, (ii) reduces the viscosity of the
viscous hydrocarbons, and (iii) mobilizes the viscous hydrocarbons
into a flowable heavy oil. In one aspect, the step of injecting
steam into each of the plurality of heat injection wells is ceased
before the steam chamber reaches the artificial topseal. A
preserved viscous hydrocarbon layer at the top of the subsurface
formation serves to enhance the effectiveness of the artificial
topseal. Alternatively, the composition of steam is modified to
include a hydrocarbon solvent, with the temperature of the
injectant being reduced before the steam chamber compromises the
effectiveness of the topseal.
[0039] The method also comprises producing the heavy oil through
each of the plurality of producer wells.
BRIEF DESCRIPTION OF THE DRAWINGS
[0040] So that the present inventions can be better understood,
certain illustrations and flow charts are appended hereto. It is to
be noted, however, that the drawings illustrate only selected
embodiments of the inventions and are therefore not to be
considered limiting of scope, for the inventions may admit to other
equally effective embodiments and applications.
[0041] FIGS. 1A through 1F present cross-sectional views of
subsurface strata in an oil field. The strata include a subsurface
formation having a viscous oil. A substantially horizontal barrier
has been placed as a topseal over the subsurface formation.
[0042] In FIG. 1A, heat injection wells and production wells have
been completed in the subsurface formation. No heating has yet
taken place in the subsurface formation.
[0043] In FIG. 1B, steam or other heated vapor is being injected
into the subsurface formation through the heat injection wells.
Small but growing steam chambers are seen around the heat injection
wells.
[0044] In FIG. 1C, heated vapor continues to be injected into the
subsurface formation. The steam chambers have enlarged around the
heat injection wells. In addition oil drainage layers have formed
where viscous oil flows under low pressure towards the production
wells.
[0045] In FIG. 1D, heated vapor continues to be injected into the
subsurface formation. The steam chambers have approached the
topseal. The oil drainage layers have reached the top of the
subsurface formation.
[0046] In FIG. 1E, the steam chambers have merged to form a single
steam chamber. The topseal allows viscous oil to be mobilized to
the top of the subsurface formation while substantially preventing
heated vapor from migrating into the subterranean zone. Heated
solvent is optionally injected into the subsurface formation to
avoid the encroachment of high-temperature steam into the topseal.
This provides for the mobilization of additional viscous
hydrocarbons without compromising the topseal.
[0047] In FIG. 1F, the steam chambers have expanded away from the
heat injection wells to substantially fill the subsurface
formation. An oil drainage layer continues to advance ahead of the
heated vapor.
[0048] FIGS. 2A and 2B provide cross-sectional views of cooling
wells as may be used to freeze native waters, in alternate
embodiments.
[0049] FIG. 2A shows a cooling well where a cooling fluid is
injected down the bore of a working string, passed through a single
expander valve, and circulated back to the surface through an
annulus.
[0050] FIG. 2B shows a cooling well where a cooling fluid is
injected down the bore of a working string, passed through two
separate expander valves in the bore, and circulated back to the
surface through the annulus.
[0051] FIG. 3 is a flowchart showing steps that may be taken to set
a waxy emulsion in a subterranean zone to form an artificial
barrier.
[0052] FIG. 4 is a cross-sectional view of a pair of wells,
representing a heat injection well and a production well, in one
embodiment. The heat injection well is used to decrease the
viscosity of bitumen or other viscous hydrocarbon in a hydrocarbon
formation.
[0053] FIG. 5 is a flowchart showing steps for a method of
recovering a viscous hydrocarbon from a subsurface formation. The
method includes creating an artificial barrier in a subterranean
zone above or proximate a top of the subsurface formation, and
heating the subsurface formation in order to reduce the viscosity
of the viscous hydrocarbon.
[0054] FIG. 6 is a flowchart showing steps for a method for
recovering viscous hydrocarbons from a subsurface formation, in an
alternate embodiment. The method includes injecting a polymer
solution into the subterranean zone in a liquid phase, and allowing
time for the polymer solution to gel within the subterranean zone
and form an artificial topseal over the subsurface formation.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0055] As used herein, the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Hydrocarbons may also include other elements,
such as, but not limited to, halogens, metallic elements, nitrogen,
oxygen, and/or sulfur. Hydrocarbons generally fall into two
classes: aliphatic, or straight chain hydrocarbons, and cyclic, or
closed ring hydrocarbons, including cyclic terpenes. Examples of
hydrocarbon-containing materials include any form of natural gas,
oil, coal, and bitumen.
[0056] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions or at ambient conditions
(15.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and
other hydrocarbons that are in a gaseous or liquid state.
[0057] The term "viscous hydrocarbon" refers to a hydrocarbon
material residing in a subsurface formation that is in a generally
non-flowable condition. Viscous hydrocarbons have a viscosity that
is generally greater than about 100 centipoise at 15.degree. C. A
non-limiting example is bitumen.
[0058] As used herein, the term "heavy oil" refers to relatively
high viscosity and high density hydrocarbons, such as bitumen.
Gas-free heavy oil generally has a viscosity of greater than 100
centipoise and a density of less than 20 degrees API gravity
(greater than about 900 kilograms/cubic meter). Heavy oil may
include carbon and hydrogen, as well as smaller concentrations of
sulfur, oxygen, and nitrogen. Heavy oil may also include aromatics
or other complex ring hydrocarbons.
[0059] As used herein, the term "subsurface" refers to geologic
strata occurring below the earth's surface.
[0060] The terms "zone" or "subterranean zone" refer to a selected
portion of a formation. The formation may or may not contain
hydrocarbons or formation water.
[0061] As used herein, the term "subsurface formation" means any
definable subsurface region. The formation may contain one or more
hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation. An "overburden" and/or an "underburden" is
geological material above or below the formation of interest. An
overburden or underburden may include one or more different types
of substantially impermeable materials. For example, overburden
and/or underburden may include rock, shale, mudstone, or wet/tight
carbonate (i.e., an impermeable carbonate without hydrocarbons). In
some cases, the overburden and/or underburden may be permeable.
[0062] As used herein, the terms "produced fluids" and "production
fluids" refer to liquids and/or gases removed from a subsurface
formation, including, for example, an organic-rich rock formation.
Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. Production fluids may include, but are not
limited to, pyrolyzed shale oil, synthesis gas, a pyrolysis product
of coal, carbon dioxide, hydrogen sulfide and water (including
steam).
[0063] As used herein, the term "fluid" refers to gases, liquids,
and combinations of gases and liquids, as well as to combinations
of gases and solids, and combinations of liquids and solids.
[0064] As used herein, the term "gas" refers to a fluid that is in
its vapor phase at 1 atm and 15.degree. C.
[0065] As used herein, the term "oil" refers to a hydrocarbon fluid
containing primarily a mixture of condensable hydrocarbons.
[0066] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shape. As used herein, the term
"well", when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
[0067] The term "tubular member" refers to any pipe, such as a
joint of casing, a portion of a liner, or a pup joint.
[0068] As used herein, the term "oil-external emulsion" refers to
any emulsion where oil is the continuous phase.
[0069] The term "wax" refers to any one of various substances that
is substantially hydrophobic, that is, insoluble in water, and that
has a relatively low viscosity when melted. The wax may be, for
example, a petroleum-derived wax such as a paraffin. The wax may
alternatively be a non-petroleum natural wax such as, for example,
beeswax or vegetable wax. One non-limiting example of a wax is
Imperial Oil Wax 1010. Wax may be present in oil naturally or may
be added, in which case it is referred to as "added wax."
[0070] The term "emulsifying agent" refers to any substance that
assists in the formation and stabilization of emulsions.
Non-limiting examples of emulsifying agents include surfactants
(both ionic and non-ionic), fine mineral solids (such as fumed
silica and bentonite), and any pH modifying agent (including, but
not limited to metal hydroxides).
[0071] The term "solvent" refers to any fluid that is significantly
soluble with a particular liquid, resulting in a homogeneous
mixture at the temperature and pressure of interest. Solubility
amounts of the solvent in the liquid resulting in a homogeneous
mixture may be greater than 10 mass percent. Non-limiting examples
of solvents for hydrocarbon oils include propane, heptane, diesel,
and kerosene.
[0072] The term "gel strength" refers to the shear stress required
to cause a fluid to initiate flow. An indicator of gel strength is
the maximum pressure gradient that may be applied to a fluid before
flow occurs through an area plugged with the gel.
Description of Selected Specific Embodiments
[0073] Methods are provided herein for recovering a viscous
hydrocarbon from a subsurface formation. The methods are intended
to create an extended artificial topseal near or just above the top
of the subsurface formation. The topseal may be greater than one
acre or, more preferably, greater than about five acres (20,232
m.sup.2). Alternatively and more preferably, the topseal is
substantially continuous over an area that is at least about ten
acres (40,464 m.sup.2).
[0074] Once in place, the topseal allows for the recovery of
hydrocarbons from oil sands or so-called "tar sands" without need
of surface mining or open pit mining. In this respect, the
subsurface formation may be effectively heated using an injectant
such as steam or a hydrocarbon vapor with minimal to no loss of the
heated injectant. The methods herein may be employed even for
viscous oil deposits that could otherwise be recovered through open
pit mining. This preserves the surface and reduces capital
costs.
[0075] FIG. 1A presents a cross-sectional view of subsurface strata
in an oil field 100 under development. The oil field 100 targets a
subsurface formation 110 containing viscous hydrocarbons such as
bitumen. The viscous hydrocarbons are in an unheated and immobiled
state. However, it is desired to recover the viscous hydrocarbons
from the subsurface formation 110 without disrupting the surface
102 of the oil field 100.
[0076] In FIG. 1A, it can be seen that the oil field 100 contains
near-surface strata 104 above the subsurface formation 110. Between
the formation 110 of interest and the near-surface strata 104 is a
subterranean zone 106. Below the formation 110 is an underburden
112.
[0077] The underburden 112 is typically largely impermeable to
fluid flow. However, the subterranean zone 106 is comprised of
sand, or a mixture of sand and soil, and is highly permeable. The
subterranean zone 106 may geologically be a part of the same
formation as near-surface strata 104. In any instance, the highly
permeable nature of the subterranean zone 106 prevents the
effective use of an injectant as part of an in situ recovery
process.
[0078] In accordance with the methods herein, an artificial barrier
may be created in the subterranean zone 106. An artificial barrier
is shown at 108 extending across the top of the subsurface
formation 110. The artificial barrier 108 serves as a topseal, and
once created is largely impermeable to fluid flow. The artificial
barrier 108 allows for the use of an injectant for an in situ
recovery process within the subsurface formation 110. The
artificial barrier may be several feet in thickness on average but
may be much thinner, for example less than 1 foot or even less than
about 1 inch (2.54 cm).
[0079] In order to place the artificial barrier 108 in the
subterranean zone 106, various service wells 120 have been formed.
In FIG. 1A, the service wells 120 are shown as completed
vertically. However, in some operations it may be preferred to
complete the service wells 120 horizontally along the subterranean
zone.
[0080] Depending on the nature of the artificial barrier 108, the
wells may serve different purposes. In one aspect, the artificial
barrier 108 is formed using service wells 120 by injection of an
injectable mixture such as a polymer solution, which flows through
the permeable zone and which gels in situ. Alternatively, the
injectable mixture may be molten sulfur (see, for example, U.S.
Pat. No. 7,631,689), or may be grout such as sulfur cement,
Portland cement, or clay which is injected into the formation 110
as a slurry. In this instance, the molten sulfur, cement, or grout
is injected into the subterranean zone 106 under pressure to plug
the pores and vugs in the permeable subterranean zone 106. In some
embodiments, the injectable mixture is dispersed above the
subsurface formation 110 through interconnecting horizontal
fractures.
[0081] The subterranean zone 106 may be shallow, for example less
than 300 feet in depth. Because of a shallow nature of the
subterranean zone 106, the injectable mixture may be injected at a
pressure that exceeds the formation fracture pressure of the strata
104, 106. In this instance, the fractures will primarily be
horizontal in nature. It can be seen from FIG. 1A that the
injectable mixture has spread substantially horizontally over and
across the subsurface formation 110 to create a continuous
topseal.
[0082] In another arrangement, the service wells 120 comprise a
plurality of refrigerator wells. In this instance, a cooling fluid
is circulated through each of the plurality of refrigerator wells
120. The cooling fluid may be a chilled liquid, a vaporizing
refrigerant, or a partially frozen slurry. In one aspect, the
cooling fluid may be a brine, glycol-water solution, or
alcohol-water solution. In another aspect, the cooling fluid is
comprised at least of 50 mol. percent of propane, propylene,
ethane, ethylene, or a mixture thereof In this arrangement, the
service wells 120 will preferably have a substantial horizontal
portion (not shown in FIG. 1A). The horizontal portion of the
various service wells 120 will extend through portions of the
subterranean zone 106.
[0083] Circulation of the cooling fluid through the horizontal
portions of the service wells 120 causes native water in the
subterranean zone to convert to ice. This, in turn, creates a
substantially horizontal frozen barrier. The frozen barrier serves
as the topseal 108. In relatively cold soils such as those found in
the Canadian oil sands of northern Alberta, wells carrying a
cooling fluid may be spaced up to about 5 meters apart to achieve a
frozen layer. According to H.J. Jessberger et al. in Chapter 2.4 of
Geotechnical Engineering Handbook (Ulrich Smoltczyk ed. 2002, Ernst
& Sohn), continuous freezing may occur within about a year.
[0084] In one arrangement of cooling wells, the wellbores,
especially for shallow formations, have so-called "river-crossing
borings." This means that the wellbores go down into the
subterranean zone 106, run largely horizontally, and then bend
upwards to return to the surface 102. This arrangement simplifies
the coolant circulation process. Such an arrangement may be
attractive in northern Alberta, considering the shallow depths of
the oil sands located there.
[0085] The use of the service wells 120 as cooling wells will
require fluid circulating equipment, including fluid pumps and
refrigeration equipment. Such equipment is represented
schematically at 125 in FIG. 1A. Such equipment may be run
continuously until the frozen horizontal barrier is completed, and
then run intermittently to maintain the artificial barrier 108 in a
frozen state. However, where a horizontal frozen barrier is
employed as the topseal, operating temperatures in the subsurface
formation 110 may need to be kept low so as not to rapidly melt the
topseal. This is so even if the circulation of the cooling fluid is
continued after the artificial barrier 108 is constructed. In one
aspect, light non-condensable gases may be injected into the top of
the subsurface formation 110 to create an insulative later at the
top of the formation 110. Such light gases preferably include
hydrocarbon solvents in the C.sub.3-C.sub.5 range of components,
but may also include inert gases such as nitrogen or helium.
[0086] The use of subsurface freezing to provide a barrier to fluid
flow is known in the art. Shell Exploration and Production Company
has discussed the use of freeze walls at the periphery of an oil
shale production area in several patents, including U.S. Pat. No.
6,880,633 and U.S. Pat. No. 7,032,660. Shell's '660 patent uses
subsurface freezing to protect against groundwater flow and
groundwater contamination during in situ shale oil production.
[0087] U.S. Pat. No. 4,860,544 describes a method for creating a
closed, flow-impervious cryogenic barrier by extending an array of
freeze wells at angles into the earth. This forms an array of
inverted, tent-like frozen structures below the earth surface.
Similarly, U.S. Pat. No. 3,267,680 describes the formation of
freeze walls of increased mechanical strength by using a series of
freeze wells that alternate in angle. Specifically, every other
well is vertical while the intermediate wells are 3.degree. to
30.degree. off of vertical. U.S. Pat. No. 3,559,737 describes
forming an underground gas storage chamber by sealing caprock
fractures of a permeable formation using cryogenic cooling. Use of
a downhole throttle is disclosed as a means of cooling.
[0088] Additional patents that disclose the use of so-called freeze
walls include U.S. Pat. Nos. 3,528,252; 3,943,722; 3,729,965;
4,358,222; and 4,607,488. WO Pat. No. 98996480 is also of interest.
Also, K. Stoss and J. Valk, "Uses and Limitations of Ground
Freezing with Liquid Nitrogen", Engineering Geology, 13, pp.
485-494 (1979); and R. Rupprecht, "Application of the
Ground-Freezing Method to Penetrate a Sequence of Water-Bearing and
Dry Formations--Three Construction Cases", Engineering Geology, 13,
pp. 541-546 (1979) discusses subsurface freezing techniques. The
disclosures of the above-listed "freeze wall" patents and technical
articles are hereby incorporated by reference in their
entireties.
[0089] FIG. 2A provides a cross-sectional view of an illustrative
cooling well 220A where refrigeration occurs downhole. The cooling
well 220A is an example of a service well 120 from FIG. 1A as may
be used in the formation of the artificial barrier 108. In FIG. 2A,
the well 220A is seen traversing from the earth surface 102,
through the near-surface strata 104, and into the subterranean zone
106.
[0090] The cooling well 220A defines a bore 225 cut through the
near-surface strata 104 and into the subterranean zone 106 using
any known drilling procedure or technique. The bore 225 of the
cooling well 220A is lined with a string of casing 222. The string
of casing 222, in turn, is sealed into place using a curable
material such as cement 224. The cement 224 not only supports the
casing 222 in the well 220A, but also prevents the migration of
fluids along the wellbore 225 between the near-surface strata 104
and the subterranean zone 106. The casing 222 and cement 224
preferably are not perforated at any point.
[0091] Within the casing 222 is a working string 230. The working
string 230 may be, for example, a string of tubing, a string of
drill pipe, or coiled tubing. Preferably, the working string 230 is
centralized within the casing 222 through centralizers or collars
(not shown). The working string 230 defines a bore 235 that
receives a cooling fluid. The working string 230 extends from the
earth surface 102 to an end 240 of the cooling well 220A.
[0092] The cooling well 220A includes an extended horizontal
portion 206. The horizontal portion 206 runs along the plane of the
subterranean zone 106. Circulation of the cooling fluid causes
water residing in the pore space of the subterranean zone 106 to
freeze. The water may be native water.
[0093] A circulation path for the cooling fluid is seen in FIG. 2A.
The cooling fluid is injected into the bore 235 of the working
string 230, as seen by arrows "I." The cooling fluid travels under
pressure to the end 240 of the cooling well 220A, and then returns
to the earth surface 102 through an annulus 232 formed between the
working string 230 and the surrounding casing 222. Arrows "A"
demonstrate flow of the cooling fluid through the annulus 232.
[0094] The cooling fluid serves as a working fluid for distributing
cold energy to the subterranean zone 106. Upon return to the
surface 102, the cooling fluid is captured at a wellhead (not
shown). From there, the cooling fluid is rechilled in equipment 125
(seen in FIG. 1A) and recirculated.
[0095] Various types of fluids may be used as a cooling fluid, not
all of which require downhole refrigeration. U.S. Pat. No.
3,372,550 discloses the use of a carbon dioxide slurry as a
subsurface cooling fluid. U.S. Pat. No. 3,271,962 describes a
method of freezing the earth around a mine shaft using multiple
freeze wells connected to a common subterranean cavity. The use of
brines or partially frozen brine slurries as cooling fluids is
disclosed. Particularly suitable cooling fluids for circulation
through cooling well 220A include a fluid comprised at least of 50
mol. percent of propane, propylene, ethane, ethylene, or a mixture
thereof
[0096] In one aspect, the cooling fluid may be chilled prior to
injection into the well 220A. For example, a surface refrigeration
system (part of surface equipment 125) may be used to chill the
cooling fluid. However, the working string 230 will most likely
need to be insulated near the surface 102 to prevent a significant
loss of cold energy to the near-surface strata 104.
[0097] As an alternative, the surface refrigeration system is
augmented or even replaced by a gas compression system and a
downhole expansion valve 234. It is known that certain compressed
gases when expanded through a valve undergo significant cooling.
Use of a downhole expansion valve 234 to cause cooling of the
circulating fluid has the benefit of removing or significantly
reducing "cold energy" losses to the overburden (that is, the
near-surface strata 104) while transporting the cooling fluid from
the surface 102 to the subterranean zone 106. In addition, use of a
downhole expansion valve 234 reduces or even removes the need for
wellbore insulation along the near-surface strata 104 as the
cooling fluid need not be completely chilled prior to
injection.
[0098] In operation, gas is compressed in the gas compression
system at the surface 102. The compressed gas is then cooled to
near-ambient temperature via air or water cooling. In some cases,
the gas may be further cooled via refrigeration. None, some, or all
of the fluid may be in a condensed state after the cooling steps.
The cooling fluid is then sent down the bore 235 of the working
string 230, and through the expansion valve 234. This causes the
fluid to cool via the Joule-Thomson effect.
[0099] Preferably, the expansion valve 234 is just above or within
the subterranean zone 106. The cooling fluid is allowed to absorb
heat from the surrounding formation, which in turn leads to ice
formation within the subterranean zone 106. Preferably, the cooling
fluid is at a temperature of about -20.degree. F. to -120.degree.
F. after passing through the expansion valve 234. More preferably,
the cooling fluid is at a temperature of about -20.degree. F. to
-80.degree. F. after passing through the expansion valve 234. More
preferably still, the cooling fluid is at a temperature of about
-30.degree. F. to -60.degree. F. after passing through the
expansion valve 234.
[0100] Preferably, the cooling fluid is at a pressure of about 100
psia to 2,000 psia before passing through the expansion valve 234,
and about 25 psia to about 500 psia after passing through the
expansion valve 234. More preferably, the cooling fluid is at a
pressure of about 200 psia to 800 psia before passing through the
expansion valve 234, and about 40 psia to about 200 psia after
passing through the expansion valve 234.
[0101] As noted, the expansion valve 234 may be placed along the
working string 230 in the cooling well 220A at different locations.
In addition, more than one expansion valve 234 may be used. FIG. 2B
is a cross-sectional view of a cooling well 220B, in an alternate
embodiment. In this cooling well 220B, two expansion valves 234'
and 234'' are placed along the horizontal portion 206 of the bore
225 and within the subterranean zone 106. In this arrangement, both
expansion valves 234', 234'' are within the bore 235 of the working
string 230.
[0102] The use of two expansion valves 234' and 234'' permits a
more uniform cooling temperature along the horizontal length of the
cooling well 220B than would be possible with a single expansion
valve. This, in turn, may lead to a more uniform impermeable
barrier 108 over the subsurface formation 110 targeted for
production.
[0103] In operation, a first temperature drop is accomplished as
the cooling fluid moves through the first expansion valve 234'. The
cooling fluid then imparts cold energy to the subterranean zone 106
on the way down. A second temperature drop is then accomplished as
the working fluid moves through the second expansion valve 234''.
The working fluid may then impart additional cold energy to the
subsurface formation 106 on the way back up the annulus 232.
[0104] It is noted that the relative placement of valves 234'' and
234'' is a matter of designer's choice. In addition, the sizing of
the inner diameters of the expansion valves 234', 234'' is a matter
of designer's choice. The placement and the sizing of the expansion
valves 234', 234'' may be adjusted to provide for selective
pressure drops. In one aspect, the cooling fluid is at a pressure
of about 800 psia to 3,000 psia before passing through the first
expansion valve 234', 500 psia to 2,000 psia before passing through
the second expansion valve 234'', and about 25 psia to 300 psia
after passing through the second expansion valve 234''. More
preferably, the cooling fluid is at a pressure of about 800 psia to
2,000 psia before passing through the first expansion valve 234',
about 100 psia to about 500 psia after passing through the first
expansion valve 234', and about 25 psia to 100 psia after passing
through the second expansion valve 234''.
[0105] In the cooling well 220B of FIG. 2B, both expansion valves
234' and 234'' create a Joule-Thompson effect for the cooling fluid
within the bore 235 of the working string 230. However, it is
feasible to provide one or both of the pressure drops outside of
the bore 235. This would involve placement of one or both of the
valves between the bore 235 and the surrounding casing 230, that
is, within the annulus 232 along the horizontal portion 206 of the
cooling well 220B.
[0106] When using downhole expansion valves, a number of cooling
fluids are suitable. Suitable fluids may include C.sub.2-C.sub.4
hydrocarbons (e.g., ethane, ethylene, propane, propylene,
isobutane, and n-butane) or mixtures containing a majority of one
or more of these components. Other suitable components may include
refrigerant halogenated hydrocarbons, carbon dioxide, and ammonia.
The specific compositional choice for a cooling fluid depends on a
number of factors including working pressures, available pressure
drop through the valve, thermodynamic behavior of the fluid,
temperature limits of the metallurgy of the conduits, safety
considerations, and cost/availability considerations. Additional
technical descriptions of working fluids and their uses in forming
freeze walls have been described in U.S. Pat. Nos. 7,516,785 and
7,516,787. These patents also disclose additional cooling well
embodiments. These patents are assigned to ExxonMobil Upstream
Research Company, and are incorporated herein by reference in their
entireties.
[0107] It is optional to provide insulation to the elongated
working string 230 above the subterranean zone 106. In addition,
the operator may employ an elongated U-tube as the working string.
The U-tube provides a closed system through which the cooling fluid
flows.
[0108] Still another option for forming an impermeable barrier 108
involves the use of electrokinetic deposited barriers.
Electrokinetic barriers are thin, impermeable barriers formed by
forced metal dissolution, ion migration, and precipitation. U.S.
Pat. Publ. No. 2006/0163068 entitled "Method for Soil Remediation
and Engineering," describes an electrokinetic method for
groundwater protection. The method comprises applying an electric
field across an area of soil so as to generate a pH and Eh
gradient, and thereby promote the in situ precipitation of a stable
iron-rich band. According to the published application, the method
may be performed for, inter alia, the purpose of forced and
directed migration of contaminated leachates.
[0109] In another example described by Faulkner et al.,
Mineralogical Magazine, pp. 749-757 (October 2005), electrically
stimulated iron rods may be placed in close relation within the
subterranean zone 106. The approach was developed for contamination
confinement. Preferably, the rods are oriented horizontally along
the plane of the subterranean zone 106 to reduce the number of rods
required.
[0110] A preferred embodiment for forming the impermeable barrier
108 involves the injection of a polymer solution. The polymer
solution is injected in a liquid phase, but sets as an extremely
viscous fluid, a stiff gel, or even as a solid. In one aspect, the
polymer solution is a cross-linked polymer solution that slowly
reacts in situ to form a substantially solid material or gel. The
slowly cross-linking polymer solution is injected into injection
wells 120. The polymer solution spreads out over days or weeks
within the subterranean zone 106. The polymer solution then sets
within the subterranean zone 106 as a gel.
[0111] To limit vertical migration and to help ensure coverage, the
injected polymer solution fluids may optionally be flowed to
production wells (not shown) that are completed at similar depths
to the service wells 120. In addition, the cross-linked polymer
solution may include a dense soluble material such as a salt. Use
of a dense fluid helps to limit upward migration of the polymer
solution and to promote its spreading as a relatively thin layer
over the viscous oil deposit. In this way, an effective topseal,
that is, a largely impermeable barrier to low-pressure fluid flow
covering an extended area, is formed.
[0112] In another embodiment, the injected fluid is a
temperature-sensitive solution that cools within the subterranean
zone 106 and hardens in situ. FIG. 3 presents a flow chart
demonstrating a method 300 of plugging a subterranean zone above a
subsurface formation using such a fluid. The method 300 employs a
specially formulated waxy emulsion that is designed to be heated
for injection into the subterranean zone 106. The composition
comprises a water-in-oil emulsion with added wax to adjust the
melting range. The emulsion fills the pores in the permeable
subterranean zone 106, and hardens into a solid as it cools. In
this way, the subterranean zone 106 is plugged to form an extended
topseal.
[0113] In accordance with the method 300 of FIG. 3, the operator of
the reservoir (or a contractor or consultant) first formulates the
waxy emulsion. This is shown generally at Box 310. The emulsion is
a blend of liquids comprising oil, added wax, and water. An
emulsifying agent and solvent may optionally be added to adjust the
viscosity of the emulsion. The composition of the emulsion is
designed so that the mixture will be a liquid above a targeted
temperature, but gels or solidifies into a waxy matrix containing
water droplets once the emulsion cools to below its melting range.
In the present application, the melting range must be above the
temperature experienced by the waxy matrix if heated vapor from the
subsurface formation 110 contacts the subterranean zone 106 during
the in situ recovery of viscous oils.
[0114] In one aspect, the emulsion is formulated to have a
viscosity greater than that of any fluids residing within the zone
106 to be plugged. In this way, the injected emulsion efficiently
displaces the in situ fluids, thus enhancing the ability to achieve
effective plugging.
[0115] To operate in this manner, various reservoir characteristics
and fluid factors are simultaneously considered. One factor is the
temperature of the subterranean zone 106. The emulsion is
formulated to have a melting point above this temperature. Another
factor is the pressure range within the subterranean zone 106. A
minimum gel strength required for the emulsion is deduced from the
pressure prevailing within the zone 106. The operator may also
consider the volume of the high permeability zone 106 to be
plugged. This will determine the desired amount of waxy emulsion to
be injected into the target zone 106. Sufficient emulsion volume is
injected through the service wells 120 to reach a desired radius
for the estimated void volume in the subterranean zone 106. The
operator injects the desired volume, plus a volume sufficient to
fill the injection tubing of the service well 120.
[0116] Next, the viscosity of fluids in the target zone 106 is
preferably determined. The purpose of the viscosity determination
is to determine a desired viscosity for the waxy emulsion. The
viscosity of the emulsion should be similar to or, preferably,
greater than that of any resident fluids in the subterranean zone
106. Also, an oil may be selected for the waxy emulsion. The oil
may be any oil that, when mixed with wax, makes a mixture that
emulsifies with water in the presence of an emulsifying agent. The
oil is preferably crude oil.
[0117] The emulsion will also include a wax. It is noted that in
some produced crude oils, paraffins or other waxes may already be
present in the production stream. However, such wax content may not
be enough to cause a solidification of the emulsion at the
anticipated subterranean zone 106 temperature. Therefore, the wax
may be at least in part a wax additive or added wax. The added wax
may be selected from a wide range of waxes that are soluble in oil.
Examples include petroleum-derived waxes such as paraffins, or
non-petroleum natural waxes, such as beeswax or vegetable wax.
Numerous suppliers offer paraffin and non-paraffin containing
hydrocarbon-based wax stocks that could be utilized in the current
processes. One preferred source for wax is Imperial Oil Limited.
The Imperial Oil Slack Wax product line provides various waxes with
a broad range of melting points and physical characteristics for
use as blending components.
[0118] The composition of the wax-oil mixture is chosen so that the
waxy emulsion is liquid above a targeted temperature, but
solidifies once the emulsion cools to below its melting range. Two
variables generally determine the melting range of the hydrocarbon
phase of the injected emulsion. These are the fraction of wax
included, and the melting range of the individual wax component. A
wax is selected that has a congealing point (the highest
temperature of the melting range) sufficiently high so that
mixtures of approximately one-half wax and one-half oil will have a
melting range lower than the injection temperature, but higher than
the desired stable operating temperature. The wax-oil mixture may
have a congealing point of approximately 20.degree. C. to about
80.degree. C. above the temperature in the subterranean zone
106.
[0119] Additional details for selecting a wax and for formulating a
wax-oil mixture is disclosed in co-owned WO 2008/024147, entitled
"Composition and Method for Using Waxy, Oil-External Emulsions to
Modify Reservoir Permeability Profiles." This published patent
application is incorporated herein by reference in its
entirety.
[0120] In one manner of formulation under Box 310, a series of
mixtures of a selected wax and oil are prepared. The melting range
of each mixture is empirically measured. The preferred method for
measuring the melting range is to measure viscosity versus
temperature in a rheometer, such as the Viscoanalyzer VAR 100.TM.
manufactured by Reologica Instruments, or the HBDV-III viscometer,
manufactured by Brookfield Instruments. The melted sample is placed
in the instrument at a temperature above the melting range, and the
viscosity is measured versus shear rate for a series of decreasing
temperatures. As the temperature drops below the upper temperature
of the melting range, the viscosity of the wax-oil mixture
increases dramatically, indicating the melting range.
[0121] The measured value of the lowest temperature of the melting
range, that is, the temperature at which total solidification
occurs, may vary depending upon the method used. For example, a
scanning differential calorimeter often reveals a lower
solidification temperature than visual or rheometric measurements.
However, for purposes of applying the plugging method 300, precise
measurement of the solidification point is not required. Measuring
the temperature at which wax crystals are first noted is
sufficient, and the fluid composition is designed and the injection
temperature is controlled based on that temperature. While the waxy
emulsion may continue to be injected and flow through porous rock
at temperatures below this upper temperature limit of the melting
range, designing the system so that this limit is not reached by
the fluid prior to entering the subterranean zone 106 ensures that
the process is effective.
[0122] If a viscous, heavy crude oil is chosen as the oil, it may
be desirable to add a solvent to the emulsion. The addition of
diluent solvent reduces the hydrocarbon phase viscosity. This, in
turn, reduces the viscosity of the injected emulsion, as the
viscosity of the emulsion is primarily controlled by the viscosity
of the external hydrocarbon phase. Different solvents may be used
to reduce the viscosity of the emulsion. Examples include kerosene
and Varsol.TM.. Varsol.TM. is a product of Imperial Oil Limited.
Varsol.TM. (a refined middle distillate) is commercially used for
automotive cleaning to remove oil and grease. It is also used for
thinning oil-based paints, varnishes, and polyurethanes.
[0123] Depending on the composition of the wax-oil mixture, changes
in viscosity and melting range due to the addition of solvent may
or may not be significant. Empirical measurements may be made on
mixtures to determine the impact of diluent solvent addition. By
making measurements of viscosity and melting range for various
possible mixtures, the operator may choose a composition that meets
the desired viscosity and melting range. Preferably, the actual
target viscosity of the hydrocarbon blend is chosen so that when a
waxy emulsion is made containing approximately 40 to 60 volume % of
water, the emulsion has a viscosity approximately 1.25 to 3 times
greater than that of the fluids residing within the subterranean
zone 106 to be plugged. This ensures that the emulsion has a
favorable mobility ratio displacement of the fluid existing within
the high permeability zone 106 to be plugged, while still
maintaining a viscosity low enough to be injected easily. Such a
favorable mobility fluid will more effectively displace the
resident fluid and achieve a more uniform plug that better conforms
to the volume distribution of the high permeability zone after
cooling.
[0124] In addition to a solvent, the operator may optionally choose
to add an emulsifying agent. Surfactants may be used as emulsifying
agents. The surfactants may be either ionic or non-ionic. If
surfactants are used, the surfactant type and concentration should
be chosen so that the mixture forms an oil-external emulsion with
water droplets having diameters of approximately 1 to 10 microns.
Water droplets with larger diameters tend to be less stable and may
rupture during injection into the reservoir. Therefore, they are
not recommended.
[0125] The operator may also determine a desired water content for
the waxy emulsion. By definition, the emulsion includes not only
oil, but at least some water. The emulsion formed is a water-in-oil
emulsion. Water is desirable in the emulsion for several reasons.
First, including water in the injected fluid significantly reduces
the cost per volume of the fluid, because water is significantly
less expensive than oil or other additives. Second, the water,
included as internal droplets in an oil-external emulsion, produces
a fluid which has significantly higher viscosity than that of
either the individual oil or water phases. The viscosity of the
emulsion may be adjusted by varying the water content. Therefore,
the resulting emulsion may be designed to have favorable mobility
displacement of any water in the subterranean zone 106. Third, the
presence of water increases the heat capacity of the injected
fluid, allowing the injected fluid to retain heat for a longer
period compared to a single-phase wax. Because water has a higher
specific heat capacity than oil, including water as the internal
phase allows the injected fluid to have a greater heat capacity.
This also allows the injected fluid to cool more slowly and
penetrate into the zone 106 farther than if oil were the sole phase
injected.
[0126] The method described in Box 310 of FIG. 3 allows the
injection of a waxy emulsion in liquid form to achieve effective
penetration into the subterranean zone 106 at distances from the
service wells 120. The method of Box 310 also provides for
adjusting the fluid viscosity during injection by changing the
solvent or water content to provide favorable mobility displacement
of fluids residing in the zone 106 during placement. Because of the
presence of added wax in the emulsion, the emulsion will have a
melting range that is above a targeted temperature. Thus, after a
period of curing, a solidified plug is created that may provide an
artificial barrier 108 to escaping vapors.
[0127] Referring again to FIG. 3, the plugging method 300 also
involves blending the waxy emulsion. This is shown at Box 320. The
hydrocarbon phase components (wax, oil, and any added diluent
solvent (if desired)) are mixed in a suitable storage tank.
Alternatively, separate supply tanks of the wax, oil, and solvent
may be used, and the components continuously mixed in-line during
injection, so that the desired final composition is maintained
within specifications. To blend the emulsion, the hydrocarbon
mixture is blended and sheared, together with any emulsifying agent
and the selected volume ratio of water, in a suitable mixing device
such as an in-line blender.
[0128] During storage of liquids and subsequent mixing, the tanks
and surface flow lines may be heated and insulated to maintain the
temperature of the liquids. Preferably, the temperature of the
liquids is maintained at approximately 20.degree. C. to 80.degree.
C. above the melting range of the waxy emulsion. The emulsion may
then be mixed on the surface using pre-heated fluids. The emulsion
may optionally be further heated after mixing. Thus, blending 320
encompasses any heating process for obtaining a temperature of the
final emulsion blend that is above the melting range of the
emulsion.
[0129] It may be desirable to also heat the service well 120 before
injecting the waxy emulsion into the subterranean zone 106. An
optional wellbore heating step is shown at Box 330. Heating may be
accomplished by circulating steam through the injection string and
back up the annulus. Depending upon the injection well completion
design and its temperature profile from surface to the bottom of
the service well 120, steam may also be injected into a portion of
the subterranean zone 106 prior to injecting the emulsion. This
raises both the wellbore and subsurface temperatures to above the
melting range of the emulsion. This helps prevent premature cooling
and solidification of the emulsion.
[0130] After sufficient heating of the waxy emulsion and,
optionally, the wellbore, the emulsion is injected into the service
well 120 and surrounding subterranean zone 106. The plugging agent
is injected as a heated, liquid emulsion wherein the hydrocarbon
phase contains a wax component. The injection step is indicated at
Box 340. Upon injection, the emulsion fills the pore spaces of the
subterranean zone 106.
[0131] During the injection step of Box 340, sufficient waxy
emulsion volume is injected to reach a radius of investigation
desired to fill the high permeability region to be plugged or the
estimated void volume. The preferred injection mode is to inject
the waxy emulsion as fast as possible without exceeding the
formation fracture pressure until the desired volume is injected.
Injecting at slower rates result in less invasion due to decreasing
fluid mobility and increasing flow resistance caused by the
formation of a wax structure in the emulsion as the temperature
cools into and below its melting range. Because the emulsion is a
heated liquid, injection pressure during the injection in Box 340
may not rise significantly above the formation pressure.
[0132] Following injection of the waxy emulsion, a small volume of
fluid may be injected to displace the tubing volume from surface to
the injection depth. This displacement is shown at Box 350 of FIG.
3. The fluid is injected to displace any emulsion within the
injection string that may solidify and plug the string following
shut down. The fluid is preferably steam.
[0133] After the displacement step in Box 350, the subterranean
zone 106 is allowed to cool. The purpose is to cure the waxy
emulsion in situ. This curing step is shown in Box 360. Curing 360
is accomplished by shutting in the service well 120. The well 120
should remain shut in for a period of time estimated from
experimental data and computations to be sufficient to allow the
injected emulsion within the zone 106 to cool to below its melting
range and reach the desired gel strength. The operator should
determine the period for curing based upon the anticipated
temperature profile of the subterranean zone 106 and the expected
rate of cooling of the injected emulsion. Because the subterranean
zone 106 is typically relatively shallow, cooling should take place
fairly quickly, such as within 2 to 5 days.
[0134] Once in place within the target zone 106, the waxy emulsion
cools to a temperature below its melting range. Upon cooling below
the melting range, the external hydrocarbon phase surrounding the
water droplets within the emulsion solidifies, forming a
topseal.
[0135] Following curing in Box 360, the operator may optionally
circulate a heated cleaning fluid. This is represented by Box 370.
The cleaning fluid will be oil or an emulsion of oil, water, and
perhaps, solvent. Alternatively, only a solvent could be used.
Kerosene or other middle distillates, preferably containing some
aromatic components, may be used. The heated fluid serves to melt
and clean out any solidified plugging agent remaining within the
service wells 120.
[0136] During circulation in Box 370, some plugging agent will be
returned to the surface 102. The used waxy emulsion is collected
for either recovery or disposal. The service wells 120 are then
shut in.
[0137] In an alternate embodiment of the invention, one or more
additional injections of the waxy emulsion are made after curing in
Box 360. The injections are referred to as "squeezes." The
injection in Box 340, displacement in Box 350, cooling in Box 360,
and circulating in Box 370 together may be designated as the first
squeeze. Preferably, two or more additional squeezes of the waxy
emulsion are conducted sequentially to effectively plug the high
permeability zone 106.
[0138] Following the cooling period in Box 360 and, optionally, the
circulating in Box 370, another volume of waxy emulsion is injected
as part of a second squeeze. Injection is intended to fill any
voids remaining after the first injection in Box 340, and to fill
additional high permeability pathways not contacted by the first
injection. Injection pressure during the second (and optional
third) injection typically rises significantly above that observed
during the first injection. Injection may be continued until a
sufficiently high pressure is reached or the desired additional
volume is injected. Again, the injection pressure should not exceed
the fracture pressure for the formation.
[0139] The terminal pressure should be held for several hours by
shutting in injection, allowing the pressure to partly decline, and
then refilling the injection string with additional waxy emulsion
to maintain an elevated pressure on the squeeze. After the rate of
pressure decline has slowed, indicating that the emulsion is
beginning to solidify and provide more flow resistance, another
small volume of oil may be injected to just displace the tubing
volume from surface to the injection depth. This is shown at Box
370. The service wells 120 are again shut in to allow the emulsion
to cool and solidify.
[0140] After the final waxy emulsion injection, a cleanup operation
may be conducted. This is in accordance with Box 380. Heated oil or
solvent is circulated through the service wells 120 to remove
solidified plugging agent in and near the wellbore.
[0141] A benefit of the use of the waxy emulsion as the plugging
agent for the artificial barrier 108 is that the solidified waxy
emulsion may be substantially removed from the subterranean zone
106 at a later time. In this regard, after the in situ recovery
process for viscous oils from the subsurface formation 110 is
completed, the heated oil or other hot cleaning fluid may be
circulated within the service wells 120 to bring the temperature in
the subterranean zone 106 up through the melting range of the
emulsion. After the waxy emulsion has been re-liquefied, the
emulsion may then be at least partially swept out from the
subterranean zone 106 through injection of steam. Selected
injection wells will be converted to production wells to produce
the emulsion back to the surface.
[0142] Another option for forming an impermeable barrier 108
relates to the placement of a solidifying fluid into the
subterranean zone 106. The solidifying fluid is injected into the
subterranean zone 106, where it chemically reacts in situ to form a
solid precipitate. This leads to pore plugging and permeability
reduction of the formation rock in the subterranean zone 106. A
number of in situ precipitation methods have been proposed for
modifying local permeability in a subsurface reservoir so to reduce
flow into wells. Examples of such methods are disclosed in U.S.
Pat. No. 3,684,011, U.S. Pat. No. 3,730,272, U.S. Pat. No.
4,002,204, U.S. Pat. No. 5,244,043, and U.S. Pat. No. 6,401,819,
each of which is incorporated herein by reference. Such methods may
form precipitates from salts of metals, sulfates, bicarbonates,
asphalts, or organic substances. In some embodiments, the
precipitation or gelling chemistry may be chosen to be
temperature-sensitive such that permeability reduction occurs or
increases when heat from a recovery mechanism interacts with the
fluids which were injected to form a barrier.
[0143] Referring again to FIG. 1A, the oil field 100 targets the
subsurface formation 110 containing viscous hydrocarbons such as
bitumen. The viscous hydrocarbons are in an unheated and immobile
state. However, it is desired to recover the viscous hydrocarbons
from the subsurface formation 110 by heating the viscous
hydrocarbons in order to convert them to a mobilized and producible
state. Heating of the subsurface formation 110 may reduce viscosity
of in situ hydrocarbons from a value substantially greater than
1,000 cp to substantially less than 100 cp.
[0144] In FIG. 1A, it can be seen that two sets of wells are
completed in the subsurface formation 110. Each set contains at
least one heat injection well 130 and at least one production well
140. The wells 130, 140 are slightly offset in FIG. 1A for
visibility purposes. The heat injection wells 130 are used for
injecting steam or other heated vapor into the subsurface
formation, while the production wells 140 are used for producing
mobilized hydrocarbon and condensed steam.
[0145] Preferably, each set of wells 130, 140 represents a pair of
wells, meaning one heat injection well 130 with one production well
140, as shown in FIG. 1A. In addition, it is preferred that both
the heat injection well 130 and the production well 140 be
completed horizontally to elongate the heating and production
aspects of the wells 130, 140. This is demonstrated in FIG. 1A,
with the wellbores forming the heat injection 130 and production
140 wells illustratively extending out of the page.
[0146] The subsurface formation 110 has an upper portion 114 and a
lower portion 116. Preferably, the horizontal portions of the
heating 130 and production 140 wells are completed in the lower
portion 116 of the subsurface formation 110. As steam or other
heated vapor is injected through the heat injection wells 130 and
into the subsurface formation 110, the vapor will rise through the
subsurface formation 110. Further, as the viscous hydrocarbons in
the subsurface formation 110 are mobilized, they will drain by
operation of gravity towards the bottom of the subsurface formation
110. Therefore, placement of both the heating wells 130 and the
production wells 140 at the lower portion 116 of the subsurface
formation 110 is preferred.
[0147] FIGS. 1A through 1F together show the process of heating the
subsurface formation 110 and then recovering mobilized
hydrocarbons. In FIG. 1A, no heating has yet taken place in the
subsurface formation 110. In FIG. 1B, steam or other heated vapor
has begun to be injected into the subsurface formation 110 through
the heat injection wells 130. Viscous oils are being heated in a
small but growing steam chamber 135.
[0148] The heated fluid being injected into the steam chamber 135
has a temperature considerably higher, e.g. 150.degree. F. to
1,000.degree. F., than the temperature of the subsurface formation
110 into which it is injected. The heated fluid could be a heated
gas or liquid such as steam, and may also contain surfactants,
solvents, oxygen, air, and inert inorganic gases. However, because
of its high heat content per unit mass, steam is ideal for raising
the temperature of a reservoir and is especially preferred for
practicing the inventions disclosed herein. Thus, the amount of
heat that is released when steam condenses is very large. Because
of this latent heat, viscous oil reservoirs may be effectively
heated.
[0149] The operator may pre-determine a volume of steam to be
injected. Several factors will affect the volume of steam. Among
these are the thickness of the hydrocarbon-containing formation
110, the viscosity of the bitumen or other oil-in-place, the
porosity of the formation, the saturation level of the hydrocarbon,
water in the formation, and the fracture pressure. Generally, the
total steam volume injected may vary between about 1 and 5 liquid
equivalent barrels per barrel of oil produced.
[0150] Various ways may be employed for initiating a steam
injection process. In the beginning, steam may optionally be
injected into the subsurface formation 110 through both the
injection wells 130 and the production wells 140. Alternatively,
heated vapor may be injected into the subsurface formation 110 only
through the heat injection wells 130, but also circulated within
the production wells 140. Circulation of heated vapor within the
wellbores of the production wells 140 increases the temperature of
the subsurface formation 110 around the production wells 140
through thermal energy.
[0151] FIG. 4 is a cross-sectional view of a pair of wells,
representing a heat injection well 430 and a production well 440,
in one embodiment. The wells 430, 440 are placed within subsurface
strata of an oil field 400. As with FIGS. 1A and 1B, the subsurface
strata of the oil field 400 of FIG. 4 include near-surface strata
104 and subterranean zone 106. An artificial barrier 108 is again
in place in the subterranean zone 106 in order to provide a
topseal.
[0152] The subsurface strata of the oil field 400 also includes a
subsurface formation 410 having viscous oil. In this illustrative
arrangement, the subsurface formation 410 is a tar sand deposit.
The heat injection well 430 and the production well 440 are
completed in a lower portion 416 of the tar sand deposit
[0153] In the arrangement of FIG. 4, the production well 440 is
completed substantially horizontally. In this respect, the
production well 440 includes a horizontal portion 446 that extends
along the lower portion 416 of the tar sand deposit 410. The
horizontal portion 446 is preferably drilled so that it extends
along the fracture trend of the formation containing the tar sands
deposit 410.
[0154] The production well 440 is completed with a perforated or
slotted casing 442. In addition, the production well 440 has
concentric inner tubing strings 443 and 444 within the slotted
casing 442. The concentric tubing strings 443, 444 terminate inside
of the casing 442 at a level near the lower portion 416 of the tar
sands deposit 410. However, the horizontal portion 446 of the
production well 440 with the slotted casing 442 extends well past
the tubing strings 443, 444 and along the tar sands deposit 410.
This manner of completion together with the appropriate production
rate helps to ensure that a relatively high oil saturation exists
adjacent to the horizontal portion 446 so that the horizontal
portion 416 of the production well 440 remains full of liquid.
[0155] As noted, the oil field 400 also includes a heat injection
well 430. In the arrangement of FIG. 4, the heat injection well 430
is completed substantially vertically, although in other
embodiments the well may be deviated or horizontal. The heat
injection well 430 extends to near the top of the horizontal
portion 446 of the production well 440. Preferably, the bottom of
the heat injection well 430 will extend to within about 5 to 10
feet from the top of the horizontal portion 446 of the production
well 440, but depending on the nature of the tar sand deposit 410
may be as far as 100 feet. Smaller clearances will be used if it is
desired to achieve thermal communication without fracture or if the
direction of fractures is hard to predict.
[0156] The heat injection well 430 is completed with a slotted
liner 432 for steam injection. In operation, steam (or other heated
vapor) is injected into the formation via well 430 below the
fracture pressure of the formation 410 holding the tar sands
deposit. Mobilized heavy oil drains towards the nearly horizontal
portion 416 of well 440. Tubing strings 443 and 444 terminate at a
distance which is calculated to maintain the main horizontal
portion 416 of the production well 440 full of liquid with
throttled production.
[0157] It is noted that the while the illustrative production well
440 is completed with two concentric strings of tubing 443, 444, in
many cases a dual tubing completion will suffice. The use of a
third tubing string allows an insulating gas to be introduced into
the annulus between the inner two tubing strings, but this is an
optional feature.
[0158] The described configuration of wells 430, 440 promotes
separate oil and water flowpaths, thereby maintaining high oil
relative permeability. In addition, any non-condensable gases which
may accumulate in the tar sands deposit 440 may be purged near an
upper portion 414 of the tar sands deposit 440 via an outer annulus
of the production well 440 via the slots in casing 442. These slots
extend up the casing 442 to near the upper portion 414 of the
reservoir.
[0159] It is noted that the producer may elect not to fracture the
formation holding the tar sands deposit 410. This may be desirable
for the drainage of oil from oil sands that are not very deeply
buried and where fracturing may be uncontrollable or where fluid
communication may be established without fracturing. The technique
may also be used where it is desired to drill the horizontal
production well 440 in a direction other than along a fracture
trend. For example, the operator may desire to drill
perpendicularly from the shore of a small lake which contains an
oil sand reservoir beneath it. In such cases, it is particularly
desirable to have the injection well 430 closer than usual to the
horizontal portion 416 of the production well 440 so that initial
thermal communication may be established fairly rapidly by thermal
conduction.
[0160] It is understood that the current inventions are not limited
to the type of recovery process as long as it maintains the
physical integrity of the barrier. In practice, this will generally
mean the recovery process utilizes relatively low pressures, e.g.,
non-fracturing pressures, so as not to rupture the relatively thin
and, possibly, gel-like, artificial topseal barrier. For example, a
low pressure steam flood may be applied as the recovery process
where steam is continuously flowed from an injection well to a
production well. Furthermore, other arrangements for pairs of wells
may be employed. Examples of such arrangements are described in
U.S. Pat. No. 4,344,485 mentioned above in the Background section.
FIG. 2 of the '485 patent displays a production well (10) completed
horizontally below a horizontally completed heat injection well
(11). FIG. 3 of the '485 patent depicts a production well (40) and
a heat injection well (41), wherein each well is completed
vertically. The '485 patent, including these drawings, is
incorporated herein by reference in its entirety.
[0161] In any of these arrangements, steam is injected into the
subsurface formation at pressures and rates sufficient to create a
large steam chamber to cause gravity drainage of the mobilized
heavy oil. Injection pressures are usually within the range of
about 50 to 1,000 psig, and preferably about 100 to 600 psig,
during the oil recovery phase. Of course, lower pressures may be
employed if a pump such as a conventional sucker rod pump or,
preferably, a chamber lift pump, is provided at the bottom of the
production well.
[0162] Referring now to FIG. 1C, FIG. 1C provides another side view
of the oil field 100. Here, steam or other heated vapor continues
to be injected into the subsurface formation 110. It can be seen
that the steam chambers 135 continue to grow away from the heat
injection wells 130. The steam chambers 135 produce condensate,
both from injected gas and from mobilized viscous oils in the
subsurface formation 110.
[0163] In addition to the steam chambers 135, oil drainage layers
145 have also been formed. The oil drainage layers 145 represent
areas of lesser pressure around the steam chambers 135, where
viscous oils have been mobilized into flowable heavy oil. The
flowable heavy oil flows around and through the steam chambers 135
and into the production wells 140, primarily by means of gravity
drainage. Thus, this represents a low-pressure production
method.
[0164] It is noted that once sizeable steam chambers 135 have been
established such as is shown in FIG. 1C, it may be desirable to
reduce the steam injection pressure. For example, it may be
desirable to operate at formation pressures significantly below the
fracture pressure. This represents another aspect of a low-pressure
production method. Injection pressure is limited to the fracture
pressure, which may be as low as between about 50 and 200 psia.
[0165] FIG. 1D presents another cross-sectional view of the
subsurface strata from the oil field 100. Here, heated vapor
continues to be injected into the subsurface formation 110. The
steam chambers 135 continue to expand above and away from the heat
injection wells 130. In the view of FIG. 1D, the steam chambers
have reached the top of the subsurface formation 110. Beneficially,
the artificial barrier 108 is acting as a topseal, preventing the
vertical migration of steam out of the subsurface formation 110.
Small oil drainage layers 145 remain at the tops of the steam
chambers 135.
[0166] FIG. 1E provides yet another side view of the oil field 100.
Here, steam or other heated vapor continues to be injected into the
subsurface formation 110. It is understood that the heated
injectant will rise within the subsurface formation 110, causing
mobilization of viscous hydrocarbons in the upper portion 114 of
the hydrocarbon formation 110 before the lower portion 116.
[0167] It can be seen in FIG. 1E that the steam chambers 135 have
substantially filled the upper portion 114 of the hydrocarbon
formation 110. The oil drainage layer 145 above the steam chamber
135 is almost gone, indicating successful mobilization of viscous
hydrocarbons up to the artificial barrier 108. In addition, the
steam chambers 135 have essentially merged into a single steam
chamber.
[0168] Because the steam chambers have merged into a single chamber
135, a single oil drainage layer 145 is also formed. Heavy oil
flows from the oil drainage layer 145 into the production wells
140.
[0169] It is noted that the temperatures and pressures associated
with the steam injection and corresponding viscosity reduction are
effective in recovering a substantial portion of the viscous oils
in situ. The steam chambers 135 may be created at a temperature
range of about 350.degree. C. down to about 150.degree. C.,
depending on the in situ pressure. However, such temperatures and
accompanying injection pressures may not be compatible with the
material forming the artificial barrier 108 throughout the life of
the operation. For example, if the artificial barrier is a frozen
barrier or a temperature-sensitive polymer, then the operator may
need to discontinue steam injection as the steam chamber 135
approaches the subterranean zone 106.
[0170] The operator may monitor temperatures in the subterranean
zone 106 using sensors placed in the service wells 120. If the
operator receives feedback suggesting that the temperature is
approaching a melting point of the plugging material forming the
artificial barrier 108, then steam injection may be
discontinued.
[0171] In order to recover an additional amount of oil from the
subsurface formation 110, the operator may choose to inject a light
hydrocarbon solvent into the previously formed steam chambers 135.
The solvent is in the C.sub.3 to C.sub.10 range of components, and
more preferably in the C.sub.3 to C.sub.5 range.
[0172] FIG. 1F provides a final cross-sectional view of the
subsurface strata from the oil field 100. Here, a light hydrocarbon
solvent is being injected into the subsurface formation 110 through
the heat injection wells 130. The solvent may be mixed with steam
to form the heated vapor. In any instance, the heated vapor has
caused the steam chamber 135 to substantially fill the hydrocarbon
formation 110. The production wells 140 continue to receive heavy
oil from the oil drainage layer 145 through gravity.
[0173] Given the low operating pressures in the subsurface
formation 110, the sole use of steam to reduce the viscosity of the
in situ oil may be impractical, even during earlier phases of oil
recovery. The addition or substitution of solvent may enhance
viscosity reduction. Moreover, as noted, if the integrity of the
topseal (artificial barrier 108) is temperature-sensitive, solvents
may permit the use of temperatures significantly lower than that of
pure steam. In some embodiments, solvents (with no steam) largely
in the C.sub.3 to C.sub.5 range may be injected in a heated vapor
state. The solvents will condense in situ at about 30.degree. C. or
less at shallow in situ pressures. In situ temperatures of shallow
bitumen resources in Canada are typically 10.degree. to 15.degree.
C.
[0174] It is also noted that the use of light hydrocarbon solvents
may provide some degree of in situ upgrading of the heavy oil.
Solvents may precipitate out a portion of low-value asphaltene
components in certain viscous oils.
[0175] In lieu of steam or heated solvents, the operator may choose
to use other heating methods for the subsurface formation 110. For
example, the heat injection wells 130 may be part of an electric
heating arrangement. Several ways of performing electrical heating
of viscous oil deposits have been described, including electrical
wellbore heaters.
[0176] U.S. Pat. No. 3,149,672 is entitled "Method and Apparatus
for Electrical Heating of Oil-Bearing Formations." In the '672
patent, an electrical current is passed between sets of fractures
that are propped with electrically conductive particles. One set of
fractures may be in an upper portion of a formation, while the
other set may be in a lower portion of the formation. Passing the
electrical current through the formation generates electrically
resistive heat. The purpose is to warm "viscous oil."
[0177] The teachings of the '672 patent are referred to and
incorporated herein by reference in their entirety. Also, a method
of resistively heating a formation by passing electricity between
wellbore electrodes in the formation has been discussed in Paper
2008-209, "Electro-Thermal Pilot in the Athabasca Oil Sands: Theory
Versus Performance," Canadian International Petroleum Conference
(2008).
[0178] U.S. Pat. No. 7,331,385 is entitled "Methods of Treating a
Subterranean Formation to Convert Organic Matter into Producible
Hydrocarbons." This co-owned patent involves a process of heating
organic matter in a subsurface formation in-situ to create and
recover producible hydrocarbons. The formation may contain a solid
organic matter such as kerogen, in which case heating causes
pyrolysis of the solid matter. Alternatively, the formation
contains heavy oil or tar sands, in which case heating causes a
substantial reduction in fluid viscosity.
[0179] In the methods of the '385 patent, the formation is
fractured from one or more wells. Subsequently, an electrically
conductive material is injected into the fractures. The conductive
material may be a proppant such as (i) thinly metal-coated sands,
(ii) composite metal/ceramic materials, or (iii) carbon based
materials. Alternatively, the conductive material may be a
non-proppant such as a conductive cement. Sufficient heat is
generated by electrical resistivity through the conductive material
to pyrolyze at least a portion of the solid organic matter into
producible hydrocarbons, or to reduce the viscosity of at least a
portion of the heavy hydrocarbons. The teachings of the '385 patent
are also referred to and incorporated herein by reference in their
entirety.
[0180] Another heating method involves circulating hot fluids
through closed-loop wells. U.S. Pat. No. 3,994,340 is entitled
"Method of Recovering Viscous Petroleum From Tar Sand." This patent
mentions the circulation of a hot fluid through a wellbore as a
means of reducing viscosity of "viscous petroleum."
[0181] In another arrangement, the heat injection wells 130 may
employ resistive heaters placed within boreholes or along cased
portions of the injection wells 130. U.S. Pat. No. 7,011,154 is
entitled "In Situ Recovery From a Kerogen and Liquid Hydrocarbon
Containing Formation," and describes such an arrangement. The '154
patent lists the use of downhole "insulated conductor heaters" such
as cables, rods and pipes. A current is passed through such
conductive objects to generate resistive heat. Alternatively, the
heating may be accomplished by conducting electricity through the
formation to resistively heat a conductive brine.
[0182] Any of the above-described heating methods may be used in
connection with the hydrocarbon recovery methods disclosed herein.
In addition, monitoring wells (not shown) may be placed between
resistive heating wells to determine when sufficient temperatures
have been reached between heating wells to adequately mobilize in
situ hydrocarbons.
[0183] FIG. 5 is a flowchart showing steps for a method 500 of
recovering a viscous hydrocarbon from a subsurface formation. The
method may first include creating an artificial barrier in a
subterranean zone. This is shown in Box 510. The artificial barrier
may be formed using any of the methods described above so as to
create a topseal.
[0184] The subterranean zone is typically made up of sand or other
high-permeability matrix material. The subterranean zone is above
or proximate a top of a subsurface formation. Preferably, the
artificial barrier is formed within 5 meters of the top of the
subsurface formation. The artificial barrier is largely impermeable
to fluid flow.
[0185] The method 500 also includes heating the subsurface
formation. This is provided in Box 520. The heating reduces the
viscosity of the viscous hydrocarbon in the subsurface formation.
Heating the subsurface formation also mobilizes the viscous
hydrocarbon into a flowable heavy oil.
[0186] Heating may be conducted using any of the techniques
described above. However, heating preferably involves injecting
steam or a mixture of steam and a heated hydrocarbon solvent into
the subsurface formation. Use of pure steam or vaporized heavier
hydrocarbons (e.g., C.sub.7+) may be beneficial during the initial
start-up of the gravity drainage process to speed the fluid
connection of pairs of heat injection and fluid production wells.
During later stages of development, a light hydrocarbon solvent may
be preferred.
[0187] The method 500 further includes producing the heavy oil to
the surface. This is indicated at Box 530. The production process
uses a production method that maintains the integrity of the
artificial barrier. An example is a gravity drainage method that
provides for essentially continuous production. Thermal transfer
away from heat injection wells reduces the viscosity of the bitumen
sufficiently that it may gravity drain to a production well at a
commercially viable rate. The production method is compatible with
the artificial barrier as a low pressure process. This means that
the production method does not compromise the integrity of the
topseal, such as by pressure-rupturing or chemically dissolving the
topseal.
[0188] Methods such as high pressure cyclic steam injection are not
appropriate for the present methods due to the risk of breaching
the relatively thin artificial topseal with the injectant. Unlike
in a deep reservoir, in a shallow reservoir the fracture pressure
changes significantly from the bottom to top on a relative basis.
There is a danger of a vertical fracture piercing to or through the
artificial barrier, thereby defeating the utility of the topseal.
Therefore, injection pressure is controlled so that the pressure at
the top of a steam chamber stays below fracture pressure. The
pressure at the top of a vapor-filled chamber will be similar to
the pressure at the injection point due to the small hydrostatic
head of gas.
[0189] The viscous hydrocarbon may have a viscosity greater than
about 1,000 cp in its undisturbed in situ state. In one aspect, the
viscous hydrocarbon comprises primarily bitumen. After substantial
heating, the viscous hydrocarbon will have a viscosity well below
100 cp.
[0190] FIG. 6 is a flowchart showing steps for a method 600 for
recovering viscous hydrocarbons from a subsurface formation, in an
alternate embodiment.
[0191] The method 600 includes locating a permeable subterranean
zone geologically above the subsurface formation. This is shown at
Box 610. In this instance, the subterranean zone is a permeable
matrix such as sand.
[0192] The method 600 also includes injecting a polymer solution
into the subterranean zone. This is provided at Box 620. The
polymer solution is injected in a liquid phase, but sets as a solid
or gel. In one aspect, the polymer solution is a cross-linked
polymer solution that slowly reacts in situ to form a substantially
solid material as the gel. The polymer solution spreads out over
days or weeks within the subterranean zone. The polymer solution
may be formed using a heavy brine to aid in spreading the polymer
solution along the bitumen or viscous hydrocarbon interface. As an
alternative to a polymer solution, the injectant may be a
temperature-sensitive gelling fluid that cools within the
subterranean zone 106 and hardens in situ.
[0193] The method 600 next includes allowing time for the polymer
solution to gel within the subterranean zone. This is provided at
Box 630. As the polymer solution gels, it forms an artificial
topseal over the subsurface formation.
[0194] The method 600 also includes forming a plurality of heat
injection wells into the subsurface formation. This is provided at
Box 640. The heat injection wells are used to inject a heated vapor
by any of the means mentioned above. The heated vapor may be steam,
heated hydrocarbon solvent, or combinations thereof.
[0195] The method 600 further includes forming a plurality of
producer wells into the subsurface formation. Each heat injection
well has one or more associated producer wells, thereby creating
sets of wells. This is seen at Box 650 of FIG. 6. In one aspect,
each of the heat injection wells is completed horizontally within
the subsurface formation. In another aspect, each of the producer
wells is completed horizontally within the subsurface formation. In
one embodiment, each of the heat injection wells is completed
horizontally within the subsurface formation and each of the
producer wells is completed horizontally within the subsurface
formation, such that each of the sets of wells is a pair of wells
and each of the pairs of wells is completed substantially within a
vertical plane.
[0196] The method 600 also includes injecting steam into each of
the plurality of heat injection wells. This is presented in Box
660. The purpose is to heat the subsurface formation, thereby, (i)
creating a steam chamber within the subsurface formation, (ii)
reducing the viscosity of the viscous hydrocarbons, and (iii)
mobilizing the viscous hydrocarbons into a readily-flowable heavy
oil. The steam may include one or more hydrocarbon components, such
as from the C.sub.3 to C.sub.10 range.
[0197] The method 600 additionally includes producing the heavy oil
through each of the plurality of producer wells. This is presented
in Box 670. In one aspect, the heavy oil flows gravitationally to
the producer wells through the steam chamber and along an oil
drainage layer formed naturally around the steam chamber.
[0198] The method 600 further includes adjusting the composition of
the steam by increasing the solvent content before the steam
chamber reaches the artificial topseal. This optional step is shown
at Box 680. This step may be performed by increasing the
hydrocarbon solvent content of the steam so that a light
hydrocarbon solvent makes up at least 50% by volume of the steam.
Alternatively, the light hydrocarbon solvent makes up at least 75%
by volume of the steam. The solvent is preferably in the C.sub.3 to
C.sub.5 range. The steam with solvent may condense at or near the
interface with the artificial barrier.
[0199] As can be seen, methods are offered herein that provide
improved processes for extracting hydrocarbons from a shallow
subsurface formation containing bitumen or tar. The improved
processes utilize in situ recovery that are preferable to mining
since the processes may result in less surface disruption, permit
deeper targets, have lower upfront capital expenses, and provide
some in situ upgrading. In some embodiments, water usage is greatly
reduced by using a hydrocarbon solvent rather than steam to reduce
in situ oil viscosity. The choice of injectant, injection pressures
and operating temperatures are judiciously chosen to be compatible
with the artificial topseal.
[0200] While it will be apparent that the inventions herein
described are well calculated to achieve the benefits and
advantages set forth above, it will be appreciated that the
inventions are susceptible to modification, variation and change
without departing from the spirit thereof For example, the methods
disclosed herein allow for the formation of an effective topseal
over a hydrocarbon-bearing formation over an area that is at least
five acres, and preferably at least about ten acres.
* * * * *