U.S. patent application number 13/720963 was filed with the patent office on 2013-08-08 for recovery from a hydrocarbon reservoir.
The applicant listed for this patent is George R. Scott. Invention is credited to George R. Scott.
Application Number | 20130199780 13/720963 |
Document ID | / |
Family ID | 48901889 |
Filed Date | 2013-08-08 |
United States Patent
Application |
20130199780 |
Kind Code |
A1 |
Scott; George R. |
August 8, 2013 |
RECOVERY FROM A HYDROCARBON RESERVOIR
Abstract
A method and systems for using a non-volatile solvent to recover
heavy oils are provided. In a method a solvent that includes a
non-volatile component is injected into the reservoir. A mobilizing
fluid is injected into the reservoir. Fluid is produced from the
reservoir, wherein the fluid comprises the solvent, the mobilizing
fluid, and the hydrocarbons from the reservoir.
Inventors: |
Scott; George R.; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Scott; George R. |
Calgary |
|
CA |
|
|
Family ID: |
48901889 |
Appl. No.: |
13/720963 |
Filed: |
December 19, 2012 |
Current U.S.
Class: |
166/268 ;
166/302; 166/303; 166/305.1; 166/50; 166/52 |
Current CPC
Class: |
E21B 43/24 20130101;
E21B 43/16 20130101; E21B 43/25 20130101 |
Class at
Publication: |
166/268 ;
166/305.1; 166/302; 166/303; 166/52; 166/50 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/24 20060101 E21B043/24 |
Foreign Application Data
Date |
Code |
Application Number |
Feb 6, 2012 |
CA |
2,766,849 |
Claims
1. A method of recovering hydrocarbons from a reservoir, comprising
injecting a solvent comprising a non-volatile component into a well
in the reservoir; injecting a mobilizing fluid into the reservoir;
and producing fluid from the reservoir, wherein the fluid comprises
the solvent, the mobilizing fluid, and the hydrocarbons from the
reservoir.
2. The method of claim 1, where the mobilizing fluid is steam,
heated water, volatile solvent, or any combinations thereof.
3. The method of claim 1, comprising co-injecting the solvent with
the mobilizing fluid.
4. The method of claim 1, comprising injecting the solvent
separately from the mobilizing fluid.
5. The method of claim 1, comprising injecting the solvent on a
continuous basis.
6. The method of claim 1, comprising injecting the solvent prior to
the start of a process shutdown.
7. The method of claim 1, comprising injecting the solvent during a
restart period after a process shutdown.
8. The method of claim 1, comprising heating the solvent before
injection.
9. The method of claim 1, comprising injecting the solvent using a
tubular in either an injection well, a production well, or
both.
10. The method of claim 1, comprising injecting the same solvent
into both an injection well and a production well.
11. The method of claim 1, wherein the volume of solvent injected
into the reservoir is limited to an amount used to make a blend
with the hydrocarbon for shipping.
12. The methods of claim 1, comprising: injecting the solvent into
a production well, an injection well, or both; recovering the
solvent; and reinjecting the solvent into an alternate injection or
production well.
13. A system for recovering heavy oil from a reservoir, comprising:
a reservoir comprising heavy oil; an injection well configured to
inject at least a mobilizing agent into the reservoir; a production
well configured to produce at least the heavy oil and the
mobilizing agent from the reservoir; and a tubular placed within
the injection well, the production well, or both, wherein the
tubular is configured to convey a solvent into a well, and wherein
the solvent comprises a non-volatile component.
14. The system of claim 13, wherein the solvent is the same solvent
used to dilute the heavy oil for shipping.
15. The system of claim 13, wherein a different solvent is injected
in each of the production well and the injection well.
16. The system of claim 13, where at least 50 vol. % of the
injected solvent remains as a liquid at the conditions in the
reservoir.
17. The system of claim 13, wherein the solvent comprises an
inorganic component.
18. The system of claim 13, comprising an artificial lift system
configured to remove production fluids from the production
well.
19. The system of claim 18, where the volume of solvent injected
lowers the viscosity of an oil/solvent blend to stay below a
viscosity constraint associated with an artificial lift system.
20. The system of claim 13, wherein the production well, the
injection well, or both, are horizontal.
21. A method for recovering hydrocarbons from a reservoir after a
no-flow condition, comprising: injecting a solvent comprising a
non-volatile component into the reservoir, wherein the solvent
contacts the reservoir; soaking the solvent in contact with the
reservoir; placing the reservoir back in service; injecting a
mobilizing fluid into the reservoir; and producing fluid from the
reservoir, wherein the fluid comprises the solvent, the mobilizing
fluid, and the hydrocarbons from the reservoir.
22. The method of claim 21, wherein the mobilizing fluid is steam,
heated water, volatile solvent, or any combinations thereof.
23. The method of claim 21, wherein the solvent is injected prior
to starting a process shutdown.
24. The method of claim 21, wherein the solvent is injected during
a restart period after a process shutdown.
25. The method of claim 21, wherein the solvent is continuously
injected during a process shutdown.
26. The method of claim 21, wherein the solvent is intermittently
injected during a process shutdown, and wherein the solvent that is
injected is from another interval of the reservoir.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of Canadian patent
application number 2,766,849 filed on Feb. 6, 2012 entitled
IMPROVING RECOVERY FROM A HYDROCARBON RESERVOIR, the entirety of
which is incorporated herein.
FIELD
[0002] The present techniques relate to harvesting resources using
gravity drainage processes. Specifically, techniques are disclosed
for lowering the viscosity of bitumen without raising the
temperature.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present techniques. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present techniques. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] Modern society is greatly dependent on the use of
hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are
generally found in subsurface rock formations that can be termed
"reservoirs." Removing hydrocarbons from the reservoirs depends on
numerous physical properties of the rock formations, such as the
permeability of the rock containing the hydrocarbons, the ability
of the hydrocarbons to flow through the rock formations, and the
proportion of hydrocarbons present, among others.
[0005] Easily harvested sources of hydrocarbon are dwindling,
leaving less accessible sources to satisfy future energy needs.
However, as the costs of hydrocarbons increase, these less
accessible sources become more economically attractive. For
example, the harvesting of oil sands to remove hydrocarbons has
become more extensive as it has become more economical. The
hydrocarbons harvested from these reservoirs may have relatively
high viscosities, for example, ranging from 8 API, or lower, up to
20 API, or higher. Accordingly, the hydrocarbons may include heavy
oils, bitumen, or other carbonaceous materials, collectively
referred to herein as "heavy oil," which are difficult to recover
using standard techniques.
[0006] Several methods have been developed to remove hydrocarbons
from oil sands. For example, strip or surface mining may be
performed to access the oil sands, which can then be treated with
hot water or steam to extract the oil. However, deeper formations
may not be accessible using a strip mining approach. For these
formations, a well can be drilled to the reservoir and steam, hot
air, solvents, or combinations thereof, can be injected to release
the hydrocarbons. The released hydrocarbons may then be collected
by the injection well or by other wells and brought to the
surface.
[0007] A number of techniques have been developed for harvesting
heavy oil from subsurface formations using well-based recovery
techniques. These operations include a suite of steam based in-situ
thermal recovery techniques, such as cyclic steam stimulation
(CSS), steam flooding and steam assisted gravity drainage (SAGD) as
well as surface mining and their associated thermal based surface
extraction techniques.
[0008] For example, CSS techniques includes a number of enhanced
recovery methods for harvesting heavy oil from formations that use
steam heat to lower the viscosity of the heavy oil. These steam
assisted hydrocarbon recovery methods are described in U.S. Pat.
No. 3,292,702 to Boberg, and U.S. Pat. No. 3,739,852 to Woods, et
al., among others. CSS and other steam flood techniques have been
utilized worldwide, beginning in about 1956 with the utilization of
CSS in the Mene Grande field in Venezuela and steam flood in the
early 1960s in the Kern River field in California.
[0009] The CSS process may raise the steam injection pressure above
the formation fracturing pressure to create fractures within the
formation and enhance the surface area access of the steam to the
heavy oil, although CSS may also be practiced at pressures that do
not fracture the formation. The steam raises the temperature of the
heavy oil during a heat soak phase, lowering the viscosity of the
heavy oil. The injection well may then be used to produce heavy oil
from the formation. The cycle is often repeated until the cost of
injecting steam becomes uneconomical, for instance if the cost is
higher than the money made from producing the heavy oil. However,
successive steam injection cycles reenter earlier created fractures
and, thus, the process becomes less efficient over time. CSS is
generally practiced in vertical wells, but systems are operational
in horizontal wells.
[0010] Solvents may be used in combination with steam in CSS
processes, such as in mixtures with the steam or in alternate
injections between steam injections. These techniques are described
in U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to
McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.
[0011] Cyclic enhanced recovery techniques have been developed that
are not based on thermal methods. For example, U.S. Pat. No.
6,769,486 to Lim, et al., discloses a cyclic solvent process (CSP)
for heavy oil production. In the process, a viscosity reducing
hydrocarbon solvent is injected into a reservoir at a pressure
sufficient to keep the hydrocarbon solvent in a liquid phase. The
injection pressure may also be sufficient to cause dilation of the
formation. The hydrocarbon solvent is allowed to mix with the heavy
oil at the elevated pressure. The pressure in the reservoir can
then be reduced to allow at least a portion of the hydrocarbon
solvent to flash, providing a solvent gas drive to assist in
removing the heavy oil from the reservoir. The cycles may be
repeated as long as economical production is achieved.
[0012] Another group of techniques is based on a continuous
injection of steam through a first well to lower the viscosity of
heavy oils and a continuous production of the heavy oil from a
lower-lying second well. Such techniques may be termed "steam
assisted gravity drainage" or SAGD. Various embodiments of the SAGD
process are described in Canadian Patent No. 1,304,287 to Edmunds
and U.S. Pat. No. 4,344,485 to Butler.
[0013] In SAGD, two horizontal wells are completed into the
reservoir. The two wells are first drilled vertically to different
depths within the reservoir. Thereafter, using directional drilling
technology, the two wells are extended in the horizontal direction
that result in two horizontal wells, vertically spaced from, but
otherwise vertically aligned with the other. Ideally, the
production well is located above the base of the reservoir but as
close as practical to the bottom of the reservoir, and the
injection well is located vertically 10 to 30 feet (3 to 10 meters)
above the horizontal well used for production.
[0014] The upper horizontal well is utilized as an injection well
and is supplied with steam from the surface. The steam rises from
the injection well, permeating the reservoir to form a vapor
chamber that grows over time towards the top of the reservoir,
thereby increasing the temperature within the reservoir. The steam,
and its condensate, raise the temperature of the reservoir and
consequently reduce the viscosity of the heavy oil in the
reservoir. The heavy oil and condensed steam will then drain
downward through the reservoir under the action of gravity and may
flow into the lower production well, whereby these liquids can be
pumped to the surface. At the surface of the well, the condensed
steam and heavy oil are separated, and the heavy oil may be diluted
with appropriate light hydrocarbons for transport by pipeline.
[0015] A number of variations of the SAGD process have been
developed in an attempt to increase the productivity of the
process. Such processes may include new well placement techniques
and tools used to enhance production of the heavy oil. In other
variations, extensions similar to those used in CSS, such as
including solvents in the process, have been made. For example,
U.S. Pat. No. 6,230,814 to Nasr, et al., teaches how the SAGD
process can be further enhanced through the addition of small
amounts of solvent to the injected steam. Nasr teaches that as the
planned SAGD operating pressure declines, the molecular weight of
the solvent must be reduced in order to ensure that it is
completely vaporized at the planned operating conditions. This
approach results in the progressive exclusion of heavier solvents,
such as naphtha, natural gas condensate and diesel for example, as
lower operating pressures (and temperatures) are considered.
[0016] In some applications, the steam may be completely replaced
with solvent. For example, Butler, et al., "A New Process (Vapex)
for Recovering Heavy Oils," JCPT, Vol. 30, No. 1, 97-106,
January-February 1991, teaches how solvent can be used instead of
steam in a gravity drainage based recovery process to recover heavy
oil from a subterranean reservoir.
[0017] A number of developments have focused on using solvents to
lower the temperature of an extraction process. For example,
Canadian Patent No. 2,243,105 to Mokrys discloses a non-thermal
vapor extraction method for the recovery of hydrocarbons from deep,
high pressure hydrocarbon reservoirs. The reservoirs may have been
previously exploited by cold flow or may be virgin deposits. The
target reservoirs are underlain by active aquifers. A mixture of a
light hydrocarbon vapor solvent, such as ethane, propane, and
butane, with reservoir natural gas is adjusted so that the dewpoint
of the light hydrocarbon solvent matches the temperature and
pressure conditions in the reservoir. The produced gas is analyzed
for the solvent component, and enriched with the required amount of
recycled solvent to match the dewpoint. The gas is then
reintroduced into the reservoir as an injection gas. Both the
recovered solvent and free gas are continuously circulated through
the reservoir. The extraction can be accomplished by employing
pairs of parallel horizontal injection/production wells, in a
similar fashion to SAGD.
[0018] Similarly, Canadian Patent No. 2,494,391 and Canadian Patent
Application Publication No. 2,584,712 by Chung, et al., disclose a
cold solvent-based extraction method for extracting heavy oil from
a reservoir. The method involves forming a solvent fluid chamber by
solvent fluid injection and heavy oil production using combinations
of horizontal and/or vertical injection wells. The combination may
increase the recovery of heavy oil contained in a reservoir.
[0019] Solvents may also be used in concert with steam addition to
increase the efficiency of the steam in removing the heavy oils.
U.S. Pat. No. 6,230,814 to Nasr, et al., discloses a method for
enhancing heavy oil mobility using a steam additive. The method
included injecting steam and an additive into the formation. The
additive includes a non-aqueous fluid, selected so that the
evaporation temperature of the non-aqueous fluid is within about
.+-.150.degree. C. of the steam temperature at the operating
pressure. Suitable additives include C.sub.1 to C.sub.25
hydrocarbons. At least a portion of the additive condenses in the
formation. The mobility of the heavy oil obtained with the steam
and solvent combination is greater than that obtained using steam
alone under substantially similar formation conditions.
[0020] In solvent based recovery processes, a volatile solvent is
injected into the reservoir to mix with the oil and thereby reduce
the viscosity of the oil. In the case of cyclic solvent recovery
process, such as CSP, the solvent may be injected into the
reservoir as a liquid, where the increase in reservoir pressure
that occurs during injection helps mix the solvent and oil. During
production, the pressure in the reservoir declines, allowing a
portion of dissolved solvent to flash. While this flashing does add
an expanding gas drive recovery mechanism, it comes at the expense
of an increase in the oil viscosity as progressively less solvent
remains dissolved in the oil.
[0021] In a gravity drainage solvent recovery process, such as
VAPEX, the pressure declines in the reservoir are concentrated near
the production well. These pressure reductions can allow some of
the dissolved solvent to flash, resulting in an increase in the oil
viscosity. When the solvent recovery process relies on horizontal
production wells, the additional pressure losses occur as the
fluids flow inside the liner, allowing more dissolved solvent to be
flashed and a further increase in the oil viscosity results. Due to
the presence of two phase flow within the liner, i.e., gas and
liquid, the pressure losses and oil viscosity increases are
accentuated by the presence of vertical variations in the well
trajectory. Typically, these pressure losses and associated
increases on oil viscosity will be more pronounced where the fluid
rate in the liner is highest, i.e., closest to the production
suction point, and, thus, their occurrence can compromise inflow
along the entire length of the well.
[0022] In processes utilizing steam or a heated solvent or both,
transient operating conditions, such as when the injection,
production or both wells are shut-in, will also have a detrimental
impact on the oil viscosity as during these transient conditions
the accumulated fluids can continue to cool and the chamber
pressure can decline, potentially reducing the solubility of the
solvent in the oil. An increase in oil viscosity can also
compromise the performance of artificial lift systems, such
positive displacement pumps and electric submersible pumps, on the
production well.
[0023] The factors that can cause an increase in oil viscosity
discussed above may leave a substantial remainder of hydrocarbons
in the reservoir. For example, if a lower pressure steam is used
during the production, the resulting lower temperatures will result
in a higher viscosity fluid, which may lower productivity.
[0024] Various approaches are currently used to manage cooler
production temperatures during the operation of thermal recovery
projects. For example, the production well may be restimulated by
injecting steam and allowing the steam to reheat both the fluids
within the well and the near wellbore area. However, there are
limitations with this approach, such as temperature limitations on
artificial lift systems, which preclude direct steam stimulation.
Further, unless the production well is completed with inflow
control devices (ICDs) there is no certainty as to how much of the
well and near wellbore region is being reheated by steam injection.
A significant investment in steam is required to reheat fluids that
were previously mobilized.
[0025] Hot water may be injected in the production well and used to
reheat both the fluids within the well and the near well bore area.
However, unless the production well is completed with inflow
control devices (ICDs) there is no certainty as to how much of the
well and near well bore region is being reheated by hot water
injection. Also, due to the limited heat capacity of water, a much
larger volume of water must be injected to provide the same heat as
a volume of steam. This hot water must also be subsequently
produced.
[0026] Assuming the production well can continue to be operated,
produced fluids can be reheated and reinjected into neighboring
production wells, injection wells, or both, and the produced fluids
will be reheated by falling through the steam chamber. This process
will keep the production wells that are being produced hot, and
will limit the potential cool fluid production issues on the
limited number of wells were the fluids are being reinjected.
However, the reinjection process may result in plugging of the
injection liner, for example, due to fine sand or the precipitation
of asphaltene.
SUMMARY
[0027] An embodiment described herein provides a method for
recovering hydrocarbons from a reservoir. The method includes
injecting a solvent comprising a non-volatile component into a well
in the reservoir. A mobilizing fluid is injected into the reservoir
and fluid is produced from the reservoir, wherein the fluid
includes the solvent, the mobilizing fluid, and the hydrocarbons
from the reservoir.
[0028] Another embodiment provides a system for recovering heavy
oil from a reservoir. The system includes a reservoir that includes
heavy oil. An injection well is configured to inject at least a
mobilizing agent into a reservoir. A production well is configured
to produce at least the heavy oil and the mobilizing agent from the
reservoir. A tubular is placed within the injection well, the
production well, or both, wherein the tubular is configured to
convey a solvent into a well, and wherein the solvent comprises a
non-volatile component.
[0029] A method for recovering hydrocarbons from a reservoir after
a no-flow condition. The method includes injecting a solvent
comprising a non-volatile component into a reservoir, wherein the
solvent contacts the reservoir. At least a portion of the reservoir
is blocked in, allowing the solvent in contact with the portion of
the reservoir to soak. The reservoir is placed back in service and
a mobilizing fluid is injected into the reservoir. Fluid is
produced from the reservoir, wherein the fluid comprises the
solvent, the mobilizing fluid, and the hydrocarbons from the
reservoir.
DESCRIPTION OF THE DRAWINGS
[0030] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0031] FIG. 1 is a drawing of a steam assisted gravity drainage
(SAGD) process used for accessing hydrocarbon resources in a
reservoir;
[0032] FIG. 2 is a drawing of a SAGD well pair in a reservoir;
[0033] FIG. 3 is a drawing of the SAGD well pair of FIG. 2 during a
period in which production operations have been halted;
[0034] FIG. 4 is a drawing of a SAGD drainage chamber, in which
production fluids from neighboring patterns is injected to slow the
cooling of the fluids in those source chambers;
[0035] FIG. 5 is a drawing of a horizontal portion of one possible
configuration of a SAGD steam injection well;
[0036] FIG. 6 is a drawing of a path that an injected mobilizing
agent, such as steam or a steam and solvent mixture, might travel
through the drainage chamber before it encounters the interface
with the undepleted oil of the reservoir;
[0037] FIG. 7 is a drawing of a path through the chamber that an
injected mobilizing agent that includes a nonvolatile component may
travel through a chamber;
[0038] FIG. 8 is a drawing of the horizontal portion of an
injection well, in which a partially volatile solvent is injected
via a separate tubing string that extends to the toe of the
liner;
[0039] FIG. 9 is another drawing of a horizontal portion of an
injection well, in which a partially volatile solvent is injected
via a separate tubing string that extends to the toe of the
liner;
[0040] FIG. 10 is a drawing of the horizontal portion of a
production well, in which a partially volatile solvent is injected
via a separate tubing string that extends to the toe of the
liner;
[0041] FIG. 11 is a process flow diagram of a method for increasing
hydrocarbon production by the injection of a non-volatile solvent
into a reservoir to decrease a viscosity of the hydrocarbon;
[0042] FIG. 12 is a semi-log plot of viscosity versus temperature
for an Athabasca heavy oil sample; and
[0043] FIG. 13 is a plot of viscosities versus solvent
concentration in blends.
DETAILED DESCRIPTION
[0044] In the following detailed description section, specific
embodiments of the present techniques are described. However, to
the extent that the following description is specific to a
particular embodiment or a particular use of the present
techniques, this is intended to be for exemplary purposes only and
simply provides a description of the exemplary embodiments.
Accordingly, the techniques are not limited to the specific
embodiments described below, but rather, include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
[0045] At the outset, for ease of reference, certain terms used in
this application and their meanings as used in this context are set
forth. To the extent a term used herein is not defined below, it
should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0046] As used herein, the term "base" indicates a lower boundary
of the resources in a reservoir that are practically recoverable,
by a gravity-assisted drainage technique, for example, using an
injected mobilizing fluid, such as steam, solvents, hot water, gas,
and the like. The base may be considered a lower boundary of the
payzone. The lower boundary may be an impermeable rock layer,
including, for example, granite, limestone, sandstone, shale, and
the like. The lower boundary may also include layers that, while
not completely impermeable, impede the formation of fluid
communication between a well on one side and a well on the other
side. Such layers, which may include inclined heterolithic strata
(IHS) of broken shale, mud, silt, and the like. The resources
within the reservoir may extend below the base, but the resources
below the base may not be recoverable with gravity assisted
techniques.
[0047] "Bitumen" is a naturally occurring heavy oil material.
Generally, it is the hydrocarbon component found in oil sands.
Bitumen can vary in composition depending upon the degree of loss
of more volatile components. It can vary from a very viscous,
tar-like, semi-solid material to solid forms. The hydrocarbon types
found in bitumen can include aliphatics, aromatics, resins, and
asphaltenes. A typical bitumen might be composed of:
[0048] 19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %,
or higher);
[0049] 19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %,
or higher);
[0050] 30 wt. % aromatics (which can range from 15 wt. %-50 wt. %,
or higher);
[0051] 32 wt. % resins (which can range from 15 wt. %-50 wt. %, or
higher); and
[0052] some amount of sulfur (which can range in excess of 7 wt.
%).
In addition bitumen can contain some water and nitrogen compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The
metals content, while small, must be removed to avoid contamination
of the product synthetic crude oil (SCO). Nickel can vary from less
than 75 ppm (part per million) to more than 200 ppm. Vanadium can
range from less than 200 ppm to more than 500 ppm. The percentage
of the hydrocarbon types found in bitumen can vary. As used herein,
the term "heavy oil" includes bitumen, as well as lighter materials
that may be found in a sand or carbonate reservoir.
[0053] As used herein, a pressure "cycle" represents a sequential
increase to peak operating pressure in a reservoir, followed by a
release of the pressure to a minimum operating pressure. The
elapsed time between two periods of peak operating pressure does
not have to be the same between cycles, nor do the peak operating
pressures and minimum operating pressures.
[0054] As used herein, two locations in a reservoir are in "fluid
communication" when a path for fluid flow exists between the
locations. For example, fluid communication between a production
well and an overlying steam chamber can allow mobilized material to
flow down to the production well for collection and production. As
used herein, a fluid includes a gas or a liquid and may include,
for example, a produced hydrocarbon, an injected mobilizing fluid,
or water, among other materials.
[0055] As used herein, a "cyclic recovery process" uses an
intermittent injection of injected mobilizing fluid selected to
lower the viscosity of heavy oil in a hydrocarbon reservoir. The
injected mobilizing fluid may include steam, solvents, gas, water,
or any combinations thereof. After a soak period, intended to allow
the injected material to interact with the heavy oil in the
reservoir, the material in the reservoir, including the mobilized
heavy oil and some portion of the mobilizing agent may be harvested
from the reservoir. Cyclic recovery processes use multiple recovery
mechanisms, in addition to gravity drainage, early in the life of
the process. The significance of these additional recovery
mechanisms, for example dilation and compaction, solution gas
drive, water flashing, and the like, declines as the recovery
process matures. Practically speaking, gravity drainage is the
dominant recovery mechanism in all mature thermal, thermal-solvent
and solvent based recovery processes used to develop heavy oil and
bitumen deposits, such as steam assisted gravity drainage (SAGD).
For this reason the approaches disclosed here are equally
applicable to all recovery processes in which at the current stage
of depletion gravity drainage is the dominant recovery
mechanism.
[0056] "Facility" as used in this description is a tangible piece
of physical equipment through which hydrocarbon fluids are either
produced from a reservoir or injected into a reservoir, or
equipment which can be used to control production or completion
operations. In its broadest sense, the term facility is applied to
any equipment that may be present along the flow path between a
reservoir and its delivery outlets. Facilities may comprise
production wells, injection wells, well tubulars, wellhead
equipment, gathering lines, manifolds, pumps, compressors,
separators, surface flow lines, steam generation plants, processing
plants, and delivery outlets. In some instances, the term "surface
facility" is used to distinguish those facilities other than
wells.
[0057] "Heavy oil" includes oils which are classified by the
American Petroleum Institute (API), as heavy oils, extra heavy
oils, or bitumens. In general, a heavy oil has an API gravity
between 22.3.degree. (density of 920 kg/m.sup.3 or 0.920
g/cm.sup.3) and 10.0.degree. (density of 1,000 kg/m.sup.3 or 1
g/cm.sup.3). An extra heavy oil, in general, has an API gravity of
less than 10.0.degree. (density greater than 1,000 kg/m.sup.3 or
greater than 1 g/cm.sup.3). For example, a source of heavy oil
includes oil sand or bituminous sand, which is a combination of
clay, sand, water, and bitumen. The thermal recovery of heavy oils
is based on the viscosity decrease of fluids with increasing
temperature or solvent concentration. Once the viscosity is
reduced, the mobilization of fluids by steam, hot water flooding,
or gravity is possible. The reduced viscosity makes the drainage
quicker and therefore directly contributes to the recovery
rate.
[0058] A "hydrocarbon" is an organic compound that primarily
includes the elements hydrogen and carbon, although nitrogen,
sulfur, oxygen, metals, or any number of other elements may be
present in small amounts. As used herein, hydrocarbons generally
refer to components found in heavy oil or in oil sands. However,
the techniques described herein are not limited to heavy oils, but
may also be used with any number of other reservoirs to improve
gravity drainage of liquids.
[0059] "Inclined heterolithic strata" or IHS are layers of rock
containing hydrocarbons that can form above or below sand layers in
an oil sands reservoir. The layers of rock in IHS are often shale
layers formed from clay or other sediments layered over or under
sand beds. The hydrocarbons may be trapped between the layers of
rock. As IHS layers may be poorly drained, it may be problematic to
produce hydrocarbons by gravity drainage from an IHS layer over a
sand layer.
[0060] As used herein, "poorer quality facies" are intervals in a
reservoir that can have poor drainage, often due to a difficulty in
establishing a counter-current flow. In an oil sands reservoir,
poorer quality facies may include IHS layers above the higher
quality sands of a clean pay interval.
[0061] "Permeability" is the capacity of a rock to transmit fluids
through the interconnected pore spaces of the rock. The customary
unit of measurement for permeability is the millidarcy.
[0062] "Pressure" is the force exerted per unit area by the gas on
the walls of the volume. Pressure can be shown as pounds per square
inch (psi). "Atmospheric pressure" refers to the local pressure of
the air. "Absolute pressure" (psia) refers to the sum of the
atmospheric pressure (14.7 psia at standard conditions) plus the
gauge pressure (psig). "Gauge pressure" (psig) refers to the
pressure measured by a gauge, which indicates only the pressure
exceeding the local atmospheric pressure (i.e., a gauge pressure of
0 psig corresponds to an absolute pressure of 14.7 psia). The term
"vapor pressure" has the usual thermodynamic meaning. For a pure
component in an enclosed system at a given pressure, the component
vapor pressure is essentially equal to the total pressure in the
system.
[0063] As used herein, a "reservoir" is a subsurface rock or sand
formation from which a production fluid, or resource, can be
harvested. The rock formation may include sand, granite, silica,
carbonates, clays, and organic matter, such as bitumen, heavy oil,
oil, gas, or coal, among others. Reservoirs can vary in thickness
from less than one foot (0.3048 m) to hundreds of feet (hundreds of
m). The resource is generally a hydrocarbon, such as a heavy oil
impregnated into a sand bed.
[0064] As discussed herein, "Steam Assisted Gravity Drainage"
(SAGD), is a thermal recovery process in which steam, or
combinations of steam and solvents, is injected into a first well
to lower a viscosity of a heavy oil, and fluids are recovered from
a second well. Both wells are generally horizontal in the formation
and the first well lies above the second well. Accordingly, the
reduced viscosity heavy oil flows down to the second well under the
force of gravity, although pressure differential may provide some
driving force in various applications. Although SAGD is used as an
exemplary process herein, it can be understood that the techniques
described can include any gravity driven process, such as those
based on steam, solvents, or any combinations thereof.
[0065] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
[0066] As used herein, "thermal recovery processes" include any
type of hydrocarbon recovery process that uses a heat source to
enhance the recovery, for example, by lowering the viscosity of a
hydrocarbon. These processes may use injected mobilizing fluids,
such as hot water, wet steam, dry steam, or solvents alone, or in
any combinations, to lower the viscosity of the hydrocarbon. Such
processes may include subsurface processes, such as cyclic steam
stimulation (CSS), cyclic solvent stimulation, steam flooding,
solvent injection, and SAGD, among others, and processes that use
surface processing for the recovery, such as sub-surface mining and
surface mining. Any of the processes referred to herein, such as
SAGD, may be used in concert with solvents.
[0067] A "tubular" refers to a fluid conduit having an axial bore,
and includes, but is not limited to, a riser, a casing, a
production tubing, a liner, and any other type of wellbore tubular
known to a person of ordinary skill in the art.
[0068] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit into the subsurface. A wellbore may have a
substantially circular cross section or any other cross-sectional
shape, such as an oval, a square, a rectangle, a triangle, or other
regular or irregular shapes. As used herein, the term "well," when
referring to an opening in the formation, may be used
interchangeably with the term "wellbore." Further, multiple pipes
may be inserted into a single wellbore, for example, as a liner
configured to allow flow from an outer chamber to an inner
chamber.
Overview
[0069] Simulations have shown that reductions in SAGD operation
pressure enables a significant improvement in thermal efficiency,
for example, as measured by steam-to-oil ratio (SOR), as the
reservoir is heated to a lower temperature. However as the
operating temperature decreases, the viscosities of the bitumen and
bitumen-water emulsion increase, impairing inflow near and within
the production well. The differences in viscosity for a change in
operating pressure, once an allowance for operating in a sub-cooled
regime is applied, are even larger.
[0070] Further, as a hydrocarbon field matures, the amount of steam
required to completely fill the drainage chambers of the field may
substantially increase, as the drainage chambers increase in size
over time. If insufficient steam supply is available, this may also
lead to a decrease in overall steam chamber pressure and, thus,
lower the temperature of the chamber. The higher oil viscosity that
results from the lower temperature operations can impair the
performance of SAGD by reducing the drainage of the oil. Longer
well pairs or more well pairs for the project may be drilled to
achieve the same oil production rate that could be achieved at
higher pressures and temperatures.
[0071] In embodiments described herein, a heavy solvent is injected
into the well to maintain production rates at lower temperatures.
The heavy solvent, such as diluent, naphtha, or distillate, among
others, does not materially vaporize, and can reduce the viscosity
of the bitumen and emulsion, increasing the flow rates. This can
reduce the pressure drop in the reservoir near and within the
production well.
[0072] In some embodiments, the heavy solvent can be injected using
a separate small diameter tubular within a production or injection
well, for example, extending to the toe of the injection well
liner. The small diameter tubular can be completed with a series of
smaller diameter holes which allow small volumes of the solvent to
be injected uniformly along the liner length. In the case of an
injection well, the solvent would then fall under the influence of
gravity into the accumulation of the bitumen, emulsion and water
present in the vicinity of the production well. Alternatively, all
of the solvent can be injected at the toe location. In the case of
a production well, it will mix with the bitumen as it enters the
liner and flow back along the length of the liner. However, near
production well viscosities may be more substantially reduced from
more even injection.
[0073] The reduced bitumen and emulsion viscosities in the
near-production well reservoir area and within the production liner
may enable the utilization of longer or smaller diameter liners in
these environments. This may be useful in lower pressure SAGD
and/or solvent assisted recovery process applications, such as
Vapex and CSP, or when the oil is very viscous. In these cases, a
reduction in pressure near and within the production wells may
cause a light solvent to be flashed, thereby increasing the
viscosity of the bitumen and impairing productivity.
[0074] The injection of either a partially volatile or a
nonvolatile solvent to improve the performance of a thermal,
thermal-solvent or solvent based recovery process can provide
viscosity reduction from the blending of a volatile portion of the
solvent with oil located within the reservoir and the non-volatile
portion of the solvent blending with oil located in or near the
production well. The benefits can be achieved during both normal
operations or during periods in which production, injection or both
operations are temporarily shut-in. For example, a small diameter
tubing string in the production well may be used to introduce a
small volume of non-volatile or partially volatile solvent into the
production wellbore during production operations.
[0075] Although a portion of the solvent may flash due to the
specific pressure and temperature conditions within the wellbore,
the non-volatile portion of the solvent will mix with the produced
oil, reducing its viscosity within the wellbore. The volatile
portion of the solvent may leave the production liner and rise into
the steam chamber. This portion of the solvent may mix with the oil
located at the edges of the chamber and/or accumulate at the top of
the chamber in the form of an insulating layer that helps reduce
heat losses.
[0076] In the case of a horizontal well (HW), a small diameter
tubing string can extend fully or partially into the production
liner. The tubing can be configured to inject non-volatile or
partially volatile solvent only at the toe of the liner, relying on
continued production from the well to fully mix it with the
incoming production from the reservoir as it moves towards the
production location. In some embodiments, the small tubing string
can contain a series of small openings along its lengths to enable
the injection of a small quantity of non-volatile or partially
volatile solvent along the length of the production well bore.
[0077] In the event of a planned production shut-in event,
non-volatile or partially volatile solvent injection in the
production well can occur, or be increased, over several days prior
to the actual shut-in. In this way production contained in surface
lines between the well and the central processing facility will see
a viscosity benefit due to the solvent addition even as the surface
production lines cool. During the shut-in period, additional
non-volatile or partially volatile solvent can be injected on a
continuous or intermittent basis, into the production well. Due to
its slightly lighter density than the oil, the non-volatile portion
of the solvent will slowly rise, leaving the liner and mix with the
accumulating fluids located outside the production well.
[0078] In a gravity drainage based recovery process which relies on
separate, but closely spacing wells for injection and production,
it is possible to introduce the non-volatile or partially volatile
solvent blended with the steam, steam-solvent blend or light
solvent being injected, or via a separate small diameter tubing
string that extends fully or partially into the injection liner. In
this configuration, the non-volatile portion of the solvent will
exit the injector well liner, under the influence of gravity, and
fall into the accumulation of liquids above the production well.
The volatile portion of the solvent will move through the chamber
before condensing, or dissolving into the oil located, at the edges
of the chamber. An advantage of this configuration is that it
further reduces the oil viscosity in the region of converging flow
near the production well.
[0079] In some embodiments, the pressure drop in the near wellbore
area may be reduced, resulting in a further increase in production.
The solvent can be blended with the production fluids on surface
prior to injecting the fluids into neighboring wells. However, this
procedure may result in plugging of the injection liner, for
example, due to fine sand or asphaltene precipitation.
Steam Assisted Gravity Drainage
[0080] FIG. 1 is a drawing of a steam assisted gravity drainage
(SAGD) process 100 used for accessing hydrocarbon resources in a
reservoir 102. In the SAGD process 100, steam 104 can be injected
through injection wells 106 to the reservoir 102. As previously
noted, the injection wells 106 may be horizontally drilled through
the reservoir 102. Production wells 108 may be drilled horizontally
through the reservoir 102, with a production well 108 underlying
each injection well 106. Generally, the injection wells 106 and
production wells 108 will be drilled from the same pad 110 at the
surface 112. This may make it easier for the production well 108 to
track the injection well 106. However, in some embodiments the
wells 106 and 108 may be drilled from different pads 110, for
example, if the production well 108 is an infill well.
[0081] The injection of steam 104 into the injection wells 106 may
result in the mobilization of hydrocarbons 114, which may drain to
the production wells 108 and be removed to the surface 112 in a
mixed stream 116 that can contain hydrocarbons, condensate and
other materials, such as water, gases, and the like. Sand filters
may be used in the production wells 108 to decrease sand
entrainment.
[0082] The mixed stream 116 from a number of production wells 108
may be combined and sent to a processing facility 118. At the
processing facility 118, the water and hydrocarbons 120 can be
separated, and the hydrocarbons 120 sent on for further refining.
Water from the separation may be recycled to a steam generation
unit within the facility 118, with or without further treatment,
and used to generate the steam 104 used for the SAGD process
100.
[0083] The production wells 108 may have a segment that is
relatively flat, which, in some developments, may have a slight
upward slope from the heel 122, at which the pipe branches to the
surface, to the toe 124, at which the pipe ends. When present, an
upward slope of this horizontal segment may result in the toe 124
being around one to five meters higher than the heel 122, depending
on the length of the horizontal segment. The slight slope can
assist in draining fluids that enter the horizontal segment to the
heel 122 for removal.
[0084] In some embodiments, a temperature of the steam injected
into the injection well 106 may be lowered, for example, when
production is started in new regions of the reservoir. As this may
lead to lower recovery due to increased viscosity, a solvent with a
non-volatile component may be injected into the reservoir to lower
the viscosity of materials. This may be performed through a tube
reaching to the toe 124 of a well in the reservoir. The injection
may be performed during startup, production, or during a shut-in
period. In some embodiments, the solvent may be injected through a
first well drilled through the reservoir and left to soak in the
reservoir while other wells, and the surface facilities, are
completed. For example, an injection well may be drilled into the
reservoir, and the solvent injected while the production well is
being completed.
[0085] A solvent may be injected into one or more wells after
completion of multiple wells. For example, the drilling may be
completed to the reservoir and a solvent may be injected to soak in
the reservoir while the surface facilities are being completed.
This can lower the time to fluid communication between the wells
once steam injection has been started.
[0086] For the purposes of this description, SAGD is used as the
representative recovery process. However, it can be noted that the
approaches disclosed here are equally applicable to all thermal,
thermal-solvent and solvent based recovery processes.
[0087] FIG. 2 is a drawing 200 of a SAGD well pair 202 in a
reservoir 204. The upper horizontal well is an injection well 206
that is used for the injection of materials, while the lower
horizontal well is a production well 208 that is used for the
production of fluids, including oil, water, and solvent. The
production rates are regulated to minimize the volume of the
liquids 210, such as oil, condensed steam, and solvent that
accumulates above the production well 208 in the base of the steam
chamber 212. Injection rates are regulated to maintain a specified
operating pressure in the steam chamber 212, for example, between
about 150 kPa and 6500 kPa. The pressure selected depends on the
characteristics of the field, including the depth of the reservoir,
the number of wells operating, the steam capacity, the age of
adjacent sections, and the like.
[0088] FIG. 3 is a drawing 300 of the SAGD well pair of FIG. 2
during a period in which production operations have been halted.
Even without additional steam injection occurring, the steam
present in the steam chamber 212 will continue to condense at the
interface 302 between the steam chamber 212 and the undepleted
reservoir 204. Mobilized oil and condensed steam (condensate) will
drain down the interface 302 and accumulate in the liquid sump 304.
Accordingly, the liquid sump 304 will progressively increase in
depth, as indicated by an arrow 306, as the duration of the shut-in
increases. As the liquid sump 304 is the shape of an inverted
triangle, the vertical rise rate will decline with time as the
accommodation space in the liquid sump 304 per unit of height is
increasing. When steam injection has also been shut-in, the decline
in the pressure of the steam chamber 212, along with the
temperature, will also slow the gravity drainage rate along the
interface 302. This inverted triangle shape also influence the rate
at which the accumulating fluids will cool.
[0089] Near the bottom of the liquid sump 304 the quantity of
surface area for heat loss per volume of liquid in the liquid sump
304, and the total time available for the liquids to cool, are
higher than near the top. Thus, the top of the steam chamber 212
cools more slowly. As the cooler temperatures increase the density
of both the oil and water, heat cannot be effectively redistributed
vertically via convection cells. Thus, in one embodiment, the
injection of a non-volatile solvent during the shut-in period may
be used to maintain a lower viscosity of the materials in the
liquid sump 304. This may shorten the period of time it takes to
restart production.
[0090] FIG. 4 is a drawing 400 of a SAGD drainage chamber 402, in
which production fluids from neighboring patterns is injected to
slow the cooling of the fluids in those source chambers. Like
numbered items are as described with respect to the previous
figures. In the SAGD drainage chamber 402 receiving the injected
production fluids, the injection helps mix the fluids 404, and,
thus, prevent the fluids 404 near the base of the liquid sump 304
from cooling too much. The total volume of fluids 404 that
accumulate in this SAGD drainage chamber 402 is much higher than if
production injection did not occur. Thus, in one embodiment, the
injection of a non-volatile solvent during the shut-in period may
be used to maintain a lower viscosity of the materials in the
liquid sump 304.
[0091] FIG. 5 is a drawing 500 of a horizontal portion of one
possible configuration of a SAGD steam injection well. In this
figure, the injection of steam or a steam and solvent mixture
occurs via both the liner annulus 502 and via a tubing string 504
that extends to near the toe 506 of the liner 508. Steam or a steam
and solvent combination enters the reservoir along all portions of
the liner 508, as indicated by arrows 510.
[0092] FIG. 6 is a drawing 600 of a path that an injected
mobilizing agent 602, such as steam or a steam and solvent mixture,
might travel through the drainage chamber 212 before it encounters
the interface 302 with the undepleted oil of the reservoir 204.
Once the mobilizing agent 602 reaches the interface 302, it will
condense and the resulting fluids 604, including water, heated oil,
and any condensing solvent, will drain down the interface 302 of
the chamber 212 to the liquid sump 304. The use of a solvent may
lower the viscosity of the oil in the chamber 212, allowing the
same production rates at lower temperatures.
[0093] FIG. 7 is a drawing of a path through the chamber 212 that
an injected mobilizing agent that includes a nonvolatile component
may travel through a chamber 212. Like numbered items are as
described with respect to previous figures. In this embodiment, the
injected mobilizing agent may include both volatile components,
such as steam or a steam and solvent mixture, and a non-volatile
component, such as a non-volatile solvent. The volatile components
may follow the same paths 602 and 604 discussed with respect to
FIG. 6. Thus, once the steam and volatile portion 702 of the
solvent reach the interface 302, they will condense and the
resulting mixture 704 will drain down the edge of the chamber 212
to the liquid sump 304. The non-volatile portion 706 of the solvent
will drain under the influence of gravity, directly into the liquid
sump 304 located above the production well 202. In the sump 304 the
non-volatile portion of the solvent will mix with the drained oil,
further reducing its viscosity.
[0094] A solvent does not need to be injected into a single inner
tubular to travel to the toe of the well in a mixture with the
steam. In some embodiments, multiple tubulars may be used to carry
the solvent into the well, as discussed with respect to FIGS. 8 and
9.
[0095] FIG. 8 is a drawing of the horizontal portion 800 of an
injection well 202, in which a partially volatile solvent 802 is
injected via a separate tubing string 804 that extends to the toe
506 of the liner 508. Like numbered items are as described with
respect to the previous figures. In this configuration, the solvent
is injected at a single location 806, and flows down through the
drainage chamber 212. The short time that the solvent falls through
the drainage chamber 212 may result in a reduction in the fraction
of the solvent vaporized and, thus, the amount of solvent that is
available for use at the interface 302 of the drainage chamber
212.
[0096] FIG. 9 is another drawing of a horizontal portion 900 of an
injection well 202, in which a partially volatile solvent 902 is
injected via a separate tubing string 904 that extends to the toe
506 of the liner 508. Like numbered items are as described with
respect to the previous figures. In this embodiment, the separate
tubing string 904 is completed with a number of holes along the
length of the separate tubing string 904 and the end 906 of the
separate tubing string 904 has been plugged. This creates a number
of solvent injection points 908 along the length of the liner 508,
which is regulated by the number, size, and distribution of the
holes along the length of the separate tubing string 904. This may
result in an improvement in the distribution of solvent injection,
both along the length of the liner 508, and within the underlying
liquid sump 304 relative to the configuration used in FIG. 8.
[0097] As a result of the addition of the non-volatile portion of
the solvent to the liquids accumulating in the liquid sump 304, the
viscosity of the oil is reduced in proximity to the production well
208. As this is the region with the smallest cross-sectional area
for flow as it converges to the production well 208, the additional
viscosity reduction will result in a reduction in the pressure drop
required to produce the diluted oil and condensate.
[0098] The solvent does not have to be injected into the injection
well 202, but may be injected into the production well 208. This is
discussed further with respect to FIG. 10.
[0099] FIG. 10 is a drawing of the horizontal portion 1000 of a
production well 206, in which a partially volatile solvent 902 is
injected via a separate tubing string 904 that extends to the toe
506 of the liner 508. Like numbered items are as shown and
described with respect to earlier figures. The separate tubing
string 904 is completed with a number of holes along the length of
the separate tubing string 904, resulting in a more uniform
distribution of solvent injection points 908 along the length of
the liner 508. This tubular configuration can be used to introduce
small volumes of solvent into the production liner 508 to mix with
the production fluids 1002, such as oil and water being produced
from the reservoir. The lower viscosity of the resulting mixture
1004 will result in an increased flow capacity and/or lower
pressure drop along the production well 206.
[0100] When there is a volatile component to the solvent, buoyancy
will allow it to leave the liner 508, as indicated by arrows 1006,
and migrate into the overlying liquid sump 304, where some of the
solvent may be dissolved in the oil contained in sump 304. The
remainder will flow into the drainage chamber 212. This solvent may
travel to the interface 302 of the drainage chamber 212 and the
surrounding reservoir 204 and used to reduce the viscosity of the
draining oil. All, or a portion, may accumulate in the upper
reaches of the drainage chamber 212 and act as a gas blanket to
further reduce overburden heat losses.
[0101] To this point in the description, the focus has been on how
the addition of a partially volatile solvent can be used during
ongoing SAGD operations to beneficially improve the viscosity
characteristics of the produced oil. These beneficial
characteristics can be achieved at the interface 302 of the
drainage chamber 212 with the reservoir 204, in the liquid sump 304
located above the production well 206 and within the production
well 206.
[0102] The relative contributions of these sources of viscosity
improvement can be optimized through the selection of the relative
volatility of the solvent being injected. To increase the benefits
observed inside the production well 208 and liquid sump 304, a low
volatility solvent, such as a naphtha, an alkane, and the like, can
be used. The solvent can be introduced via a separate injection
string in the injector and/or producer. To increase the benefits
observed at the interface 302 of the drainage chamber 212 and the
oil of the reservoir 204 a higher volatility solvent may be
selected.
[0103] If a higher volatility solvent is used, the solvent can be
selected so that some of the injected solvent always remains as a
liquid. The higher volatility solvent may be introduced through the
steam injection string in the injection well 206. In some
embodiments, the partially volatile solvent may be injected through
both the injection and production wells on either a continuous or
on a regular, but intermittent, basis to achieve the desired
results.
[0104] FIG. 11 is a process flow diagram of a method 1100 for
increasing hydrocarbon production by the injection of a
non-volatile solvent into a reservoir to decrease a viscosity of
the hydrocarbon. The method 1100 begins at block 1102, with the
injection of a solvent comprising a non-volatile component. As
described above, this may be done in concert with a steam injection
or separately. The solvent may be injected through a separate
tubular into the reservoir. The solvent may be injected during a
shutdown, or before production is started from a field, to decrease
the amount of time needed to start the production.
[0105] At block 1104, a mobilizing fluid is injected into the
reservoir. In some embodiments, the mobilizing fluid may be steam
used to heat the reservoir. The mobilizing fluid can be injected at
the same time as the non-volatile solvent.
[0106] At block 1106, fluid is produced from the reservoir. The
fluid may include oil, water, entrained gas and any injected
solvent. The gas, water, and solvent may be separated from the oil
and the solvent reused for further production. In some embodiments,
the solvent may be left in a mixture with the oil, and used to
lower the viscosity for shipping.
[0107] FIG. 12 is a semi-log plot 1200 of viscosity versus
temperature for an Athabasca heavy oil sample. The y-axis 1202
represents the log of the viscosity in centipoise (cP), while the
x-axis 1204 represents the temperature in .degree. C. The semi-log
plot 1200 shows that reducing the temperature from about
300.degree. C. to about 200.degree. C. causes the viscosity 1206 to
increase from about 3 cP to about 11 cP, a fourfold increase.
Decreasing the temperature from about 200.degree. C. to about
100.degree. C., increases the viscosity 1206 from about 11 cP to
about 370 cP, a thirty fold increase. Similarly, decreasing the
temperature from about 100.degree. C. to about 50.degree. C.
increases the viscosity 1206 from about 370 cP to about 22,000 cP,
which is a sixty fold increase.
[0108] As previously noted, in thermal based recovery processes,
the oil will tend to cool as it travels through the reservoir
towards the production well. In the case of a cyclic steam recovery
process, such as cyclic steam stimulation (CSS), the cooling is
driven by the reduction in operating pressure that occurs during
the production cycle as well as cooling of the oil that occurs as a
result of heat losses as it travels along the under-burden, or
portion of the oil deposit that is still too cool/viscous to be
effectively produced.
[0109] In a gravity drainage steam recovery process, such as SAGD,
the maximum viscosity reduction is dictated by the operating
pressure and temperature of the steam chamber, and the viscosity
characteristics of the oil. For a given oil, the decision to
operate at a lower steam chamber operating pressure will result in
the draining oil having a higher viscosity than if a higher
operating pressure was selected.
[0110] Additional cooling of the mobilized oil is driven by heat
losses as it travels along the boundary with the portion of the oil
deposit that is still too cool or viscous to be produced.
Additional heat losses occur within the accumulation of fluids
above the production well. When the thermal recovery process relies
on horizontal production wells, the additional heat losses occur to
the under-burden as the fluids flow inside the liner. These heat
losses will be more pronounced where the fluid rate along the liner
is lowest, for example, furthest from the production suction
point.
[0111] Because the viscosity of oil is a double log function of
temperature, as shown in the semi-log plot 1200, each incremental
reduction in temperature has a progressively larger impact on
viscosity. However, a lower chamber pressure, and the resulting
lower temperature, also increases the productivity improvement that
may be obtained for a dilution related viscosity reduction to be
captured by incorporating a volatile portion to the solvent being
injected.
[0112] This is because the volatile solvent component is able to
contribute a more material increment to the viscosity reduction of
the draining oil. The more rapid drainage shrinks the relative
depth of penetration of the conductively heated region that would
otherwise occur at lower operating temperatures. Reducing this
stored heat component allows an improvement in the thermal
efficiency of the injected steam.
[0113] The non-volatile portion of the solvent injected contributes
more decreasing the viscosity as the desired operating pressure
(and temperature) decreases. For this reason, various embodiments
use higher molecular weight solvents, or solvent blends, that are
either partially volatile or non-volatile at the planned operating
conditions.
[0114] While the description has focused on SAGD as the recovery
process, the application of a nonvolatile or partially volatile
solvent can be utilized in any number of recovery processes in
which a viscosity reduction may allow for enhanced oil recovery.
For example, a temperature based oil viscosity reduction may be
replaced with a dilution based oil viscosity reduction during a
period of time where temperatures are expected to cool, such as a
planned or unplanned interruption in production operations.
[0115] Further, a volatile solvent based oil viscosity reduction
may be replaced with a non-volatile or dilution based oil viscosity
reduction during a period of time, or step in the recovery
operation, where pressures are expected to decline. For example,
this may be done during a planned or unplanned interruption in
injection operations or in association with a flow into, or within,
the production well. The addition of the solvent can result in a
substantial decrease in viscosity, as discussed with respect to
FIG. 13.
[0116] FIG. 13 is a plot 1300 of viscosities versus solvent
concentration in blends. In FIG. 13, the x-axis 1302 represents the
temperature in Celsius, while the y-axis 1304 represents a log of
the viscosity in centipoise (cP). The lowest viscosity curve 1306
represents the viscosity of a pure xylene solution, while the
highest viscosity curve 1308 represents Athabasca heavy oil. As can
be seen from the plot 1300, the addition of even small amounts of
xylene to the heavy oil results in a substantial decrease in
viscosity, wherein the effects are higher at lower
temperatures.
EMBODIMENTS
[0117] Embodiments described herein include any combinations of the
elements in the following numbered paragraphs. [0118] 1. A method
of recovering hydrocarbons from a reservoir, including [0119]
injecting a solvent including a non-volatile component into a well
in the reservoir; [0120] injecting a mobilizing fluid into the
reservoir; and [0121] producing fluid from the reservoir, wherein
the fluid includes the solvent, the mobilizing fluid, and the
hydrocarbons from the reservoir. [0122] 2. The method of paragraph
1, where the mobilizing fluid is steam, heated water, volatile
solvent, or any combinations thereof. [0123] 3. The method of
paragraphs 1 or 2, including co-injecting the solvent with the
mobilizing fluid. [0124] 4. The method of paragraphs 1, 2, or 3,
including injecting the solvent separately from the mobilizing
fluid. [0125] 5. The method of any of the preceding paragraphs,
including injecting the solvent on a continuous basis. [0126] 6.
The method of any of the preceding paragraphs, including injecting
the solvent prior to the start of a process shutdown. [0127] 7. The
method of any of the preceding paragraphs, including injecting the
solvent during a restart period after a process shutdown. [0128] 8.
The method of any of the preceding paragraphs, including heating
the solvent before injection. [0129] 9. The method of any of the
preceding paragraphs, including injecting the solvent using a
tubular in either an injection well, a production well, or both.
[0130] 10. The method of any of the preceding paragraphs, including
injecting the same solvent into both an injection well and a
production well. [0131] 11. The method of any of the preceding
paragraphs, wherein the volume of solvent injected into the
reservoir is limited to an amount used to make a blend with the
hydrocarbon for shipping. [0132] 12. The method of any of the
preceding paragraphs, including: [0133] injecting the solvent into
a production well, an injection well, or both; [0134] recovering
the solvent; and [0135] reinjecting the solvent into an alternate
injection or production well. [0136] 13. A system for recovering
heavy oil from a reservoir, including: [0137] a reservoir including
heavy oil; [0138] an injection well configured to inject at least a
mobilizing agent into the reservoir; [0139] a production well
configured to produce at least the heavy oil and the mobilizing
agent from the reservoir; and [0140] a tubular placed within the
injection well, the production well, or both, wherein the tubular
is configured to convey a solvent into a well, and wherein the
solvent includes a non-volatile component. [0141] 14. The system of
paragraph 13, wherein the solvent is the same solvent used to
dilute the heavy oil for shipping. [0142] 15. The system of
paragraphs 13 or 14, wherein a different solvent is injected in
each of the production well and the injection well. [0143] 16. The
system of any of paragraphs 13-15, where at least 50 vol. % of the
injected solvent remains as a liquid at the conditions in the
reservoir. [0144] 17. The system of any of paragraphs 13-16,
wherein the solvent includes an inorganic component. [0145] 18. The
system of any of paragraphs 13-17, including an artificial lift
system configured to remove production fluids from the production
well. [0146] 19. The system of paragraph 18, where the volume of
solvent injected lowers the viscosity of an oil/solvent blend to
stay below a viscosity constraint associated with an artificial
lift system. [0147] 20. The system of any of paragraphs 13-19,
wherein the production well, the injection well, or both, are
horizontal. [0148] 21. A method for recovering hydrocarbons from a
reservoir after a no-flow condition, including: [0149] injecting a
solvent including a non-volatile component into the reservoir,
wherein the solvent contacts the reservoir; [0150] soaking the
solvent in contact with the reservoir; [0151] placing the reservoir
back in service; [0152] injecting a mobilizing fluid into the
reservoir; and [0153] producing fluid from the reservoir, wherein
the fluid includes the solvent, the mobilizing fluid, and the
hydrocarbons from the reservoir. [0154] 22. The method of paragraph
21, wherein the mobilizing fluid is steam, heated water, volatile
solvent, or any combinations thereof. [0155] 23. The method of
paragraphs 21 or 22, wherein the solvent is injected prior to
starting a process shutdown. [0156] 24. The method of any of
paragraphs 21-23, wherein the solvent is injected during a restart
period after a process shutdown. [0157] 25. The method of any of
paragraphs 21-24, wherein the solvent is continuously injected
during a process shutdown. [0158] 26. The method of any of
paragraphs 21-25, wherein the solvent is intermittently injected
during a process shutdown, and wherein the solvent that is injected
is from another interval of the reservoir.
[0159] While the present techniques may be susceptible to various
modifications and alternative forms, the embodiments discussed
above have been shown only by way of example. However, it should
again be understood that the techniques are not intended to be
limited to the particular embodiments disclosed herein. Indeed, the
present techniques include all alternatives, modifications, and
equivalents falling within the true spirit and scope of the
appended claims.
* * * * *