Note: Descriptions are shown in the official language in which they were submitted.
CA 02900178 2015-08-12
RECOVERING HYDROCARBONS FROM AN UNDERGROUND RESERVOIR
BACKGROUND
Field of Disclosure
[0001] The
disclosure relates generally to the recovery of hydrocarbons. More
specifically, the disclosure relates to the recovery of hydrocarbons from an
underground
reservoir.
Description of Related Art
[0002]
This section is intended to introduce various aspects of the art, which may be
associated with 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.
[0003]
Modern society is greatly dependent on the use of hydrocarbon resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
that can be termed "reservoirs." Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
satisfy future energy needs. As the prices of hydrocarbons increase, the less
accessible
sources become more economically attractive.
[0004]
Recently, the harvesting of oil sands to remove heavy oil has become more
economical. Hydrocarbon removal from oil sands may be performed by several
techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot
gas, solvents, or a
combination thereof, can be injected to release the hydrocarbons. The
released
hydrocarbons may be collected by wells and brought to the surface.
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[0005] At the present time, solvent-dominated recovery processes (SDRPs)
are not
commonly used as commercial recovery processes to produce highly viscous oil.
Solvent-dominated means that the injectant comprises greater than 50 percent
(%) by mass
of solvent or that greater than 50% of the produced oil's viscosity reduction
is obtained by
chemical solvation rather than by thermal means. Highly viscous oils are
produced primarily
using thermal methods in which heat, typically in the form of steam, is added
to the reservoir.
Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A
CSDRP
may be a non-thermal recovery method that uses a solvent to mobilize viscous
oil by cycles
of injection and production. One possible laboratory method for roughly
comparing the
relative contribution of heat and dilution to the viscosity reduction obtained
in a proposed oil
recovery process is to compare the viscosity obtained by diluting an oil
sample with a solvent
to the viscosity reduction obtained by heating the sample.
[0006] In a CSDRP, a viscosity-reducing solvent may be injected through a
well into
a subterranean formation, causing pressure to increase. Next, the pressure is
lowered and
reduced-viscosity oil is produced to the surface of the subterranean formation
through the
same well through which the solvent was injected. Multiple cycles of injection
and production
may be used.
[0007] CSDRPs may be particularly attractive for thinner or lower-oil-
saturation
reservoirs. In such reservoirs, thermal methods utilizing heat to reduce
viscous oil viscosity
may be inefficient due to excessive heat loss to the overburden and/or
underburden and/or
reservoir with low oil content.
[0008] References describing specific CSDRPs include: Canadian Patent No.
2,349,234 (Lim et al.); G. B. Lim et al., "Three-dimensional Scaled Physical
Modeling of
Solvent Vapour Extraction of Cold Lake Bitumen", The Journal of Canadian
Petroleum
Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., "Cyclic
Stimulation of Cold Lake
Oil Sand with Supercritical Ethane", SPE Paper 30298, 1995; U.S. Patent No.
3,954,141
(Allen et al.); and M. Feali et al., "Feasibility Study of the Cyclic VAPEX
Process for Low
Permeable Carbonate Systems", International Petroleum Technology Conference
Paper
12833, 2008.
[0009] The family of processes within the Lim et al. references describes
a particular
SDRP that is also a cyclic solvent-dominated recovery process (CSDRP). These
processes
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relate to the recovery of heavy oil and bitumen from subterranean reservoirs
using cyclic
injection of a solvent in the liquid state which vaporizes upon production.
[0010] With reference to Figure 1, which is a simplified diagram based on
Canadian
Patent No. 2,349,234 (Lim et al.), one CSDRP process is described as a single
well method
for cyclic solvent stimulation, the single well preferably having a horizontal
wellbore portion
and a perforated liner section. A vertical wellbore (1) driven through
overburden (2) into
reservoir (3) is connected to a horizontal wellbore portion (4). The
horizontal wellbore portion
(4) comprises a perforated liner section (5) and an inner bore (6). The
horizontal wellbore
portion comprises a downhole pump (7). In operation, solvent or viscosified
solvent is driven
down and diverted through the perforated liner section (5) where it percolates
into reservoir
(3) and penetrates reservoir material to yield a reservoir penetration zone
(8). Oil dissolved in
the solvent or viscosified solvent flows into the well and is pumped by
downhole pump
through an inner bore (6) through a motor at the wellhead (9) to a production
tank (10) where
oil and solvent are separated and the solvent is recycled.
[0011] Solvent dominated recovery processes (SDRPs) may produce a second
liquid
heavy phase. This second liquid phase may form in the reservoir or in surface
facilities,
which may not be advantageous and may, for instance, impair flow assurance.
Thus, there
is a need for a process that mitigates the presence of this second liquid
phase.
SUMMARY
[0012] It is an object of the present disclosure to provide a process
that mitigates the
presence of a second liquid phase.
[0013] Disclosed herein is a composition for mitigating the presence of a
second
liquid phase in an underground hydrocarbon reservoir, in the wellbore, or in
surface facilities
of a solvent dominated recovery process (SDRP). A goal of mitigating the
presence of the
second liquid phase is to improve flow assurance in the reservoir, in the
wellbore, or in
surface facilities. In a SDRP, the viscosity-reducing component may be
combined with a
high-aromatics component, for instance one comprising at least 60 wt. %
aromatics, based
upon total weight of the high-aromatics component.
[0014] The foregoing has broadly outlined the features of the present
disclosure so
that the detailed description that follows may be better understood.
Additional features will
also be described herein.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0015] These and other features, aspects and advantages of the disclosure
will
become apparent from the following description, appending claims and the
accompanying
drawings, which are briefly described below.
[0016] Fig. 1 is a schematic of a cyclic solvent-dominated recovery
process.
[0017] Fig. 2 is a ternary phase diagram for bitumen, propane, and a
third fluid being
xylene, LCGO, or dilutent.
[0018] Fig. 3 is a graph of bitumen to solvent ratio versus time.
[0019] Fig. 4 is a graph of propane volume ratio in produced fluid versus
rate ratio of
diluent and total production.
[0020] Fig. 5 is a graph of propane volume ratio in produced fluid versus
rate ratio of
LCGO and total production.
[0021] Fig. 6 is a flow chart of process for recovering hydrocarbons.
[0022] It should be noted that the figures are merely examples and no
limitations on
the scope of the present disclosure are intended thereby. Further, the figures
are generally
not drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating
various aspects of the disclosure.
DETAILED DESCRIPTION
[0023] For the purpose of promoting an understanding of the principles of
the
disclosure, reference will now be made to the features illustrated in the
drawings and specific
language will be used to describe the same. It will nevertheless be understood
that no
limitation of the scope of the disclosure is thereby intended. Any alterations
and further
modifications, and any further applications of the principles of the
disclosure as described
herein are contemplated as would normally occur to one skilled in the art to
which the
disclosure relates. It will be apparent to those skilled in the relevant art
that some features
that are not relevant to the present disclosure may not be shown in the
drawings for the sake
of clarity.
[0024] At the outset, for ease of reference, certain terms used in this
application and
their meaning, as used in this context, are set forth below. To the extent a
term used herein
is not defined below, it should be given the broadest definition persons in
the pertinent art
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CA 02900178 2015-08-12
have given that term as reflected in at least one printed publication or
issued patent. Further,
the present processes are not limited by the usage of the terms shown below,
as all
equivalents, synonyms, new developments and terms or processes that serve the
same or a
similar purpose are considered to be within the scope of the present
disclosure.
[0025] A "hydrocarbon" is an organic compound that primarily includes the
elements
of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any
number of other
elements may be present in small amounts. Hydrocarbons generally refer to
components
found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or
aromatic,
and may be straight chained, branched, or partially or fully cyclic.
[0026] "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:
19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % - 30 wt.
%, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % -50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %), based on the
total bitumen weight.
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 percentage of the hydrocarbon found
in bitumen can
vary. The term "heavy oil" includes bitumen as well as lighter materials that
may be found in
a sand or carbonate reservoir.
[0027] "Heavy oil" includes oils which are classified by the American
Petroleum
Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term
"heavy oil" includes
bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or
more, 10,000 cP
or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil
has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or
0.920 grams
per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1
g/cm3). An extra
heavy oil, in general, has an API gravity of less than 10.0 API (density
greater than 1,000
CA 02900178 2015-08-12
kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or
bituminous sand,
which is a combination of clay, sand, water and bitumen.
[0028]
The term "viscous oil" as used herein means a hydrocarbon, or mixture of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at
initial reservoir conditions. Viscous oil includes oils generally defined as
"heavy oil" or
"bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of
about 100 or
less, referring to its gravity as measured in degrees on the American
Petroleum Institute
(API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about
10 . The terms
viscous oil, heavy oil, and bitumen are used interchangeably herein since they
may be
extracted using similar processes.
[0029] In-
situ is a Latin phrase for "in the place" and, in the context of hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example,
in-situ temperature means the temperature within the reservoir, in another
usage, an in-situ
oil recovery technique is one that recovers oil from a reservoir within the
earth.
[0030]
The term "subterranean formation" refers to the material existing below the
Earth's surface. The subterranean formation may comprise a range of
components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well
as the oil and/or
gas that is extracted. The subterranean formation may be a subterranean body
of rock that
is distinct and continuous.
The terms "reservoir" and "formation" may be used
interchangeably.
[0031]
The terms "approximately," "about," "substantially," and similar terms are
intended to have a broad meaning in harmony with the common and accepted usage
by
those of ordinary skill in the art to which the subject matter of this
disclosure pertains. It
should be understood by those of skill in the art who review this disclosure
that these terms
are intended to allow a description of certain features described and claimed
without
restricting the scope of these features to the precise numeral ranges
provided. Accordingly,
these terms should be interpreted as indicating that insubstantial or
inconsequential
modifications or alterations of the subject matter described and are
considered to be within
the scope of the disclosure.
[0032]
The articles "the", "a" and "an" are not necessarily limited to mean only one,
but rather are inclusive and open ended so as to include, optionally, multiple
such elements.
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[0033] "At least one," in reference to a list of one or more entities
should be
understood to mean at least one entity selected from any one or more of the
entity in the list
of entities, but not necessarily including at least one of each and every
entity specifically
listed within the list of entities and not excluding any combinations of
entities in the list of
entities. This definition also allows that entities may optionally be present
other than the
entities specifically identified within the list of entities to which the
phrase "at least one"
refers, whether related or unrelated to those entities specifically
identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently, "at least
one of A or B," or,
equivalently "at least one of A and/or B") may refer, to at least one,
optionally including more
than one, A, with no B present (and optionally including entities other than
B); to at least one,
optionally including more than one, B, with no A present (and optionally
including entities
other than A); to at least one, optionally including more than one, A, and at
least one,
optionally including more than one, B (and optionally including other
entities). In other words,
the phrases "at least one," "one or more," and "and/or" are open-ended
expressions that are
both conjunctive and disjunctive in operation. For example, each of the
expressions "at least
one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and
C," "one or more of
A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C alone, A and B
together, A
and C together, B and C together, A, B and C together, and optionally any of
the above in
combination with at least one other entity.
[0034] Where two or more ranges are used, such as but not limited to 1 to
5 or 2 to 4,
any number between or inclusive of these ranges is implied.
[0035] As used herein, the phrase, "for example," the phrase, "as an
example,"
and/or simply the term "example," when used with reference to one or more
components,
features, details, structures, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
and/or method is
an illustrative, non-exclusive example of components, features, details,
structures, and/or
methods according to the present disclosure. Thus, the described component,
feature,
detail, structure, and/or method is not intended to be limiting, required, or
exclusive/exhaustive; and other components, features, details, structures,
and/or methods,
including structurally and/or functionally similar and/or equivalent
components, features,
details, structures, and/or methods, are also within the scope of the present
disclosure.
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[0036] CSDRP Process Description
[0037] While CSDRP is described in detail, the disclosure is not limited
to any
particular type of SDRP.
[0038] During a CSDRP, a reservoir may accommodate injected viscosity-
reducing
solvent and non-solvent fluid (also referred to as "additional injectants" or
"non-solvent
injectants") by dilating a reservoir pore space by applying an injection
pressure. Dilating the
reservoir pore space may be any effective mechanism for permitting viscosity-
reducing
solvent to enter into reservoirs filled with viscous oils when the reservoir
comprises
unconsolidated sand grains. The viscous oils may interchangeably be referred
to as
hydrocarbons. The solvent fingers into the oil sands and mixes with the
viscous oil to yield a
reduced viscosity mixture with higher mobility than the native viscous oil.
"Fingering" may
occur when two fluids of different viscosities come in contact with one
another and one fluid
penetrates the other in a finger-like pattern, that is, in an uneven manner.
The primary
mixing mechanism of the solvent with the oil may be dispersive mixing, not
diffusion.
Injected fluid in each cycle may replace the volume of previously recovered
fluid. Injected
fluid in each cycle may add additional fluid to contact previously uncontacted
viscous oil.
The injected fluid may comprise greater than 50% by mass of viscosity-reducing
solvent.
The injection well and the production well may utilize a common wellbore.
[0039] While producing hydrocarbon during the CSDRP process, pressure may
be
reduced and the viscosity-reducing solvent(s), non-solvent injectant, and
viscous oil may flow
back to the same well in which the solvent(s) and non-solvent injectant were
injected and are
produced to the surface of the reservoir as produced fluid. The produced fluid
may be a
mixture of the viscosity-reducing solvent and viscous oil. As the pressure in
the reservoir
falls, the produced fluid rate may decline with time. Production of the
produced fluid may be
governed by any of the following mechanisms: gas drive via viscosity-reducing
solvent
vaporization and native gas ex-solution, compaction drive as the reservoir
dilation relaxes,
fluid expansion, and gravity-driven flow. The relative importance of the
mechanisms
depends on static properties such as viscosity-reducing solvent properties,
native GOR (Gas
to Oil Ratio), fluid and rock compressibility characteristics, and/or
reservoir depth. The
relative importance of the mechanism may depend on operational practices such
as
viscosity-reducing solvent injection volume, producing pressure, and/or
viscous oil recovery
to-date, among other factors.
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CA 02900178 2015-08-12
[0040] During an injection/production cycle (i.e. a cycle comprising
injecting an
injected fluid followed by producing hydrocarbons), the volume of produced oil
within the
produced fluid may be above a minimum threshold to economically justify
continuing the
CSDRP process. The produced oil within the produced fluid may be recovered.
[0041] CSDRP Process Description - Solvent composition
[0042] The solvent may comprise a light, but condensable, hydrocarbon or
mixture of
hydrocarbons comprising ethane, propane, butane, or pentane. Additional
injectants may
include CO2, natural gas, C5+ hydrocarbons, ketones, and alcohols. Non-solvent
injectants
may include steam, water, non-condensable gas, or hydrate inhibitors. The
injected fluid
may comprise at least one of diesel, viscous oil, natural gas, bitumen,
diluent, 05+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable
solid particles,
salt, water soluble solid particles, and solvent soluble solid particles.
[0043] To reach a desired injection pressure of the injected fluid, a
viscosifer and/or a
solvent slurry may be used in conjunction with the solvent. The viscosifer may
be useful in
adjusting solvent viscosity to reach desired injection pressures at available
pump rates. The
viscosifer may include diesel, viscous oil, bitumen, and/or diluent. The
viscosifier may be in
the liquid, gas, or solid phase. The viscosifer may be soluble in either one
of the
components of the injected solvent and water. The viscosifer may transition to
the liquid
phase in the reservoir before or during production. In the liquid phase, the
viscosifers are
less likely to increase the viscosity of the produced fluids and/or decrease
the effective
permeability of the formation to the produced fluids.
[0044] The viscosifier may reduce the average distance the solvent
travels from the
well during an injection period. The viscosifer may act like a solvent and
provide flow
assurance near the wellbore and in the surface facilities in the event of
asphaltene
precipitation or solvent vaporization during shut-in periods. Solids suspended
in the solvent
slurry may comprise biodegradable solid particles, salt, water soluble solid
particles, and/or
solvent soluble solid particles.
[0045] The solvent may comprise greater than 50% C2-05 hydrocarbons on a
mass
basis. The solvent may be greater than 50 mass % propane, optionally with
diluent when it
is desirable to adjust the properties of the injectant to improve performance.
Wells may be
subjected to compositions other than these main solvents to improve well
pattern
performance, for example CO2 flooding of a mature operation.
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CA 02900178 2015-08-12
[0046] The solvent may be as described in Canadian Patent No. 2,645,267
(Chakrabarty, issued April 16, 2013). The solvent may comprise (i) a polar
component, the
polar component being a compound comprising a non-terminal carbonyl group; and
(ii) a
non-polar component, the non-polar component being a substantially aliphatic
substantially
non-halogenated alkane. The solvent may have a Hansen hydrogen bonding
parameter of
0.3 to 1.7 (or 0.7 to 1.4). The solvent may have a volume ratio of the polar
component to
non-polar component of 10:90 to 50:50 (or 10:90 to 24:76, 20:80 to 40:60,
25:75 to 35:65, or
29:71 to 31:69). The polar component may be, for instance, a ketone or
acetone. The
non-polar component may be, for instance, a C2-C7 alkane, a C2-C7 n-alkane, an
n-pentane, an n-heptane, or a gas plant condensate comprising alkanes,
naphthenes, and
aromatics.
[0047] The Hansen Solubility Parameter System is now described further.
In
principle, each solvent has a unique set of solvency characteristics described
by their
Hansen parameters: D = dispersive or "non-polar" parameter; P = polar
parameter; and
H = hydrogen bonding parameter. Each of the parameters describes the bonding
characteristic of a solvent in terms of polar, non-polar, and hydrogen bonding
tendencies.
According to the Hansen Solubility Parameter System, a mathematical mixing
rule can be
applied in order to derive or calculate the respective Hansen parameters for a
blend of
solvents from knowledge of the respective parameters of each component of the
blend and
the volume fraction of the component in the blend. Thus according to this
mixing rule:
Pblend = Vi Pi and Hblend =Vi Hi, where Vi is the volume fraction of the ith
component in the
blend, Pi is Hansen polar parameter for component i, Hi is the Hansen hydrogen
bonding
parameter for component i, and where summation is over all i components. For
further
details and explanation of the Hansen Solubility Parameter System see, for
example,
Hansen, C. M. and Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology,
(Suppl.
Vol. 2nd Ed), 1971, pp 889-910 and Hansen Solubility Parameters A User's
Handbook by
Charles Hansen, CRC Press, 1999.
[0048] A "substantially aliphatic substantially non-halogenated alkane"
means an
alkane with less than 10% by weight of aromaticity and with no more than 1
mole percent
halogen atoms. In other embodiments, the level of aromaticity is less than 5,
less than 3,
less than 1, or 0 % by weight.
CA 02900178 2015-08-12
[0049] The solvent may be as described in Canadian Patent No. 2,781,273
(Chakrabarty, issued May 20, 2014). The solvent may comprise (i) an ether with
2 to 8
carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms.
Ether may have
2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-
ethyl ether, methyl
iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether,
methyl iso-butyl
ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-
propyl butyl ether, propyl
butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl
ether. The non-polar
hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a C2-05
alkane.
The non-polar hydrocarbon may be propane. The ether may be di-methyl ether and
the
hydrocarbon may be propane. The volume ratio of ether to non-polar hydrocarbon
may be
10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.
[0050] CSDRP Process Description - Phase of Injected Solvent
[0051] The solvent may be injected into the well at a pressure in the
underground
reservoir above a liquid/vapor phase change pressure such that at least 25
mass % of the
solvent enters the reservoir in the liquid phase. At least 50, 70, or even 90
mass % of the
solvent may enter the reservoir in the liquid phase. The percentage of solvent
that may enter
the reservoir in a liquid phase may be within a range that includes or is
bounded by any of
the preceding examples. Injection of the solvent as a liquid may be preferred
for increasing
injected fluid injection pressure. When injecting the solvent as a liquid,
pore dilation at high
pressures is thought to be a particularly effective mechanism for permitting
the solvent to
enter into reservoirs filled with viscous oils when the reservoir comprises
largely
unconsolidated sand grains. When injecting the solvent as a liquid, higher
overall injection
rates than injection as a gas may be allowed.
[0052] A fraction of the solvent may be injected in the solid phase in
order to mitigate
adverse solvent fingering, increase injection pressure, and/or keep the
average distance of
the solvent closer to the wellbore than in the case of pure liquid phase
injection. Less than
20 mass % of the injectant may enter the reservoir in the solid phase. Less
than 10 mass %
or less than 50 mass % of the solvent may enter the reservoir in the solid
phase. The
percentage of solvent that may enter the reservoir in a solid phase may be
within a range
that includes or is bounded by any of the preceding examples. Once in the
reservoir, the
solid phase of the solvent may transition to a liquid phase before or during
production to
prevent or mitigate reservoir permeability reduction during production.
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CA 02900178 2015-08-12
[0053] Injection of the solvent as a vapor may assist uniform solvent
distribution
along a horizontal well, particularly when variable injection rates are
targeted. Vapor injection
in a horizontal well may facilitate an upsize in the port size of installed
inflow control devices
(ICDs) that minimize the risk of plugging the ICDs. Injecting the solvent as a
vapor may
increase the ability to pressurize the reservoir to a desired pressure by
lowering effective
permeability of the injected vapor in a formation comprising liquid viscous
oil.
[0054] The solvent volume may be injected into the well at rates and
pressures such
that immediately after completing injection into the injection well during an
injection period, at
least 25 mass % of the injected solvent is in a liquid state in the reservoir
(e.g.,
underground).
[0055] A non-condensable gas may be injected into the reservoir to
achieve a
desired pressure, followed by injection of the solvent. Alternating periods of
a primarily
non-condensable gas with primarily solvent injection (where primarily means
greater than 50
mass A of the mixture of non-condensable gas and solvent) may provide a way
to maintain
the desired injection pressure target. The primarily gas injection period may
offset the
pressure leak off observed during primarily solvent injection to reestablish
the desired
injection pressure. The alternating strategy of condensable gas to solvent
injection periods
may result in non-condensable gas accumulations in the previous established
solvent
pathways. The accumulation of non-condensable gas may divert the subsequent
primarily
solvent injection to bypassed viscous oil thereby increasing the mixing of
solvent and oil in
the producing well's drainage area.
[0056] A non-solvent injectant in the vapor phase, such as CO2 or natural
gas, may
be injected, followed by injection of a solvent. Depending on the pressure of
the reservoir, it
may be desirable to heat the solvent in order to inject it as a vapor. Heating
of injected vapor
or liquid solvent may enhance production through mechanisms described by
"Boberg, T.C.
and Lantz, R.B., "Calculation of the production of a thermally stimulated
well", JPT,
1613-1623, Dec. 1966. Towards the end of the injection period, a portion of
the injected
solvent, perhaps 25 mass % or more, may become a liquid as pressure rises.
After the
targeted injection cycle volume of solvent is achieved, no special effort may
be made to
maintain the injection pressure at the saturation conditions of the solvent,
and liquefaction
may occur through pressurization, not condensation. Downhole pressure gauges
and/or
reservoir simulation may be used to estimate the phase of the solvent and non-
solvent
12
CA 02900178 2015-08-12
injectants at downhole conditions and in the reservoir. A reservoir simulation
may be carried
out using a reservoir simulator, a software program for mathematically
modeling the phase
and flow behavior of fluids in an underground reservoir. Those skilled in the
art understand
how to use a reservoir simulator to determine if 25 mass % of the solvent
would be in the
liquid phase immediately after the completion of an injection period. Those
skilled in the art
may rely on measurements recorded using a downhole pressure gauge in order to
increase
the accuracy of a reservoir simulator. Alternatively, the downhole pressure
gauge
measurements may be used to directly make the determination without the use of
reservoir
simulation.
[0057] Although a CSDRP may be predominantly a non-thermal process in
that heat
is not used principally to reduce the viscosity of the viscous oil, the use of
heat is not
excluded. Heating may be beneficial to improve performance, improve process
start-up, or
provide flow assurance during production. For start-up, low-level heating (for
example, less
than 100 C) may be appropriate. Low-level heating of the solvent prior to
injection may also
be performed to prevent hydrate formation in tubulars and in the reservoir.
Heating to higher
temperatures may benefit recovery. Two non-exclusive scenarios of injecting a
heated
solvent are as follows. In one scenario, vapor solvent would be injected and
would condense
before it reaches the bitumen. In another scenario, a vapor solvent would be
injected at up to
200 C and would become a supercritical fluid at downhole operating pressure.
[0058] CSDRP Process Description - Pore Volume
[0059] As described in Canadian Patent No. 2,734,170 (Dawson et al.,
issued
September 24, 2013), one method of managing fluid injection in a CSDRP is for
the
cumulative volume injected over all injection periods in a given cycle (V
INJECTANT) to equal the
net reservoir voidage (V VOIDAGE) resulting from previous injection and
production cycles plus
an additional volume (V ADDITIONAL), for example approximately 2-15%, or
approximately 3-8%
of the pore volume (PV) of the reservoir volume associated with the well
pattern. In
mathematical terms, the volume (V) may be represented by:
V ¨ V + V
[0060] INIECTANT VOIDAGE ADDITIONAL
[0061] One way to approximate the net in-situ volume of fluids produced
is to
determine the total volume of non-solvent liquid hydrocarbon fraction produced
(V PRODUCED
OIL) and aqueous fraction produced (V PRODUCED WATER) minus the net injectant
fractions
produced (V INJECTED SOLVENT -V PRODUCED SOLVENT)= For example, in the case
where 100% of
13
CA 02900178 2015-08-12
the injectant is solvent and the reservoir contains only oil and water, an
equation that
represents the net in-situ volume of fluids produced (V VOIDAGE) is:
VvõiõAõL = 17õ1:1"D
1?"'"" VwPARI(E"i)?("" (VINJECTED
SOLVENT L,7) 1,N"L
IC"
[0062])
[0063] Estimates of the PV are the reservoir volume inside a unit cell of
a repeating
well pattern or the reservoir volume inside a minimum convex perimeter defined
around a set
of wells in a given cycle. Fluid volume may be calculated at in-situ
conditions, which take
into account reservoir temperatures and pressures. If the application is for a
single well, the
"pore volume of the reservoir" is defined by an inferred drainage radius
region around the
well which is approximately equal to the distance that solvent fingers are
expected to travel
during the injection cycle (for example, about 30-200m). Such a distance may
be estimated
by reservoir surveillance activities, reservoir simulation or reference to
prior observed field
performance. In this approach, the pore volume may be estimated by direct
calculation using
the estimated distance, and injection ceased when the associated injection
volume (2-15%
PV) has been reached.
[0064] As described in the aforementioned Canadian Patent No. 2,734,170,
rather
than measuring pore volume directly, indirect measurements can be made of
other
parameters and used as a proxy for pore volume.
[0065] CSDRP Process Description - Diluent
[0066] In the context of this specification, diluent means a liquid
compound that can
be used to dilute the solvent and can be used to manipulate the viscosity of
any resulting
solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-
bitumen (and
diluent) mixture, the invasion, mobility, and distribution of solvent in the
reservoir can be
controlled so as to increase viscous oil production.
[0067] The diluent is typically a viscous hydrocarbon liquid, especially
a C4-C20
hydrocarbon, or mixture thereof, which may be locally produced and may be used
to thin
bitumen to pipeline specifications. Pentane, hexane, and heptane may be
components of
such diluents. Bitumen itself can be used to modify the viscosity of the
injected fluid, often in
conjunction with ethane solvent.
[0068] The diluent may have an average initial boiling point close to the
boiling point
of pentane (36 C) or hexane (69 C) though the average boiling point (defined
further below)
may change with reuse as the mix changes (some of the solvent originating
among the
recovered viscous oil fractions). More than 50% by volume of the diluent has
an average
14
CA 02900178 2015-08-12
boiling point lower than the boiling point of decane (174 C). More than 75% by
volume, such
as more than 80% by volume or more than 90% by weight of the diluent, may have
an
average boiling point between the boiling point of pentane and the boiling
point of decane.
The diluent may have an average boiling point close to the boiling point of
hexane (69 C) or
heptane (98 C), or even water (100 C).
[0069] More than 50% by weight of the diluent (such as more than 75% or
80% by
weight or more than 90% by weight) may have a boiling point between the
boiling points of
pentane and decane. More than 50% by weight of the diluent may have a boiling
point
between the boiling points of hexane (69 C.) and nonane (151 C), particularly
between the
boiling points of heptane (98 C) and octane (126 C).
[0070] By average boiling point of the diluent, we mean the temperature
at which half
(by volume) of a starting amount of diluent has been boiled off as described
in section 15.1
and shown in Table 6 of ASTM D7096-10 (Standard Test Method for Determination
of the
Boiling Range Distribution of Gasoline by Wide-Bore Capillary Gas
Chromatography). The
average boiling point can be determined by gas chromatographic methods or more
tediously
by distillation. Boiling points are defined as the boiling points at
atmospheric pressure.
[0071] Table 1 outlines the operating ranges for certain CSDRPs. The
present
disclosure is not intended to be limited by such operating ranges.
[0072] Table 1. Operating Ranges for a CSDRP.
Parameter Broader Option Narrower Option
Cumulative Fill-up estimated pattern pore Inject a cumulative volume
in a
injectant volume volume plus a cumulative 3-8% cycle, beyond a primary
pressure
per cycle of estimated pattern pore threshold, of 3-8% of estimated
volume; or inject, beyond a pore volume.
primary pressure threshold, for
a cumulative period of time
(e.g. days to months); or
inject, beyond a primary
pressure threshold, a
cumulative of 3-8% of
estimated pore volume.
CA 02900178 2015-08-12
Injectant Main solvent (>50 mass%) Main solvent (>50 mass%) is
composition, 02-Cs. Alternatively, wells may propane (03) or ethane (02).
main be subjected to compositions
other than main solvents to
improve well pattern
performance (i.e. CO2 flooding
of a mature operation or
altering in-situ stress of
reservoir). 002
Injectant Additional injectants may Only diluent, and only when
composition, include CO2 (up to about 30 needed to achieve adequate
additive mass%), 03+, viscosifiers (e.g. injection pressure. Or, a
polar
diesel, viscous oil, bitumen, compound having a non-terminal
diluent), ketones,
alcohols, carbonyl group (e.g. a ketone, for
sulphur dioxide, hydrate instance acetone).
inhibitors, steam,
non-condensable gas,
biodegradable solid particles,
salt, water soluble solid
particles, or solvent soluble
solid particles.
Injectant phase & Solvent injected such that at Solvent injected as a liquid,
and
Injection the end of the injection cycle, most solvent injected just
under
pressure greater than 25% by mass of fracture pressure and above
the solvent exists as a liquid dilation pressure,
and less than 50% by mass of Pfracture > Pinjection > Pdilation >
the injectant exists in the solid Pvapor.
phase in the reservoir, with no
constraint as to whether most
solvent is injected above or
below dilation pressure or
fracture pressure.
Injectant Enough heat to prevent Enough heat to prevent hydrates
temperature hydrates and locally enhance with a safety margin,
wellbore inflow consistent with Thydrate 5 C to
Thydrate
Boberg-Lantz mode +50 C.
16
CA 02900178 2015-08-12
Injection rate 0.1 to 10 m3/day per meter of 0.2 to 6 m3/day per meter of
during completed well length (rate completed well length (rate
continuous expressed as volumes of liquid expressed as volumes of liquid
injection solvent at reservoir conditions). solvent at reservoir
conditions).
Rates may also be designed to
allow for limited or controlled
fracture extent, at fracture
pressure or desired solvent
conformance depending on
reservoir properties.
Threshold Any pressure above initial A pressure between 90% and
pressure reservoir pressure. 100% of fracture pressure.
(pressure at
which solvent
continues to be
injected for either
a period of time
or in a volume
amount)
Well length As long of a horizontal well as 500m ¨ 1500m (commercial
well).
can practically be drilled; or the
entire pay thickness for vertical
wells.
Well Horizontal wells parallel to Horizontal wells parallel to each
configuration each other, separated by some other, separated by some
regular
regular spacing of 20 ¨ 1000m. spacing of 50 ¨ 600m.
Also vertical wells, high angle
slant wells & multi-lateral wells.
Also infill injection and/or
production wells (of any type
above) targeting bypassed
hydrocarbon from surveillance
of pattern performance.
17
CA 02900178 2015-08-12
Well orientation Orientated in any direction. Horizontal wells
orientated
perpendicular to (or with less than
30 degrees of variation) the
direction of maximum horizontal
in-situ stress.
Minimum Generally, the range of the A low pressure below the vapor
producing MPP should be, on the low pressure of the main solvent,
pressure (MPP) end, a pressure significantly ensuring vaporization, or, in
the
below the vapor pressure, limited vaporization scheme, a
ensuring vaporization; and, on high pressure above the vapor
the high-end, a high pressure pressure. At 500m depth with pure
near the native reservoir propane, 0.5 MPa (low) ¨1.5 MPa
pressure. For
example, (high), values that bound the 800
perhaps 0.1 MPa kPa vapor pressure of propane.
(megapascals) ¨ 5 MPa,
depending on depth and mode
of operation (all-liquid or limited
vaporization).
Oil rate Switch to injection when rate Switch when the instantaneous
oil
equals 2 to 50% of the max rate declines below the calendar
rate obtained during the cycle; day oil rate (CDOR) (e.g. total
Alternatively, switch when
oil/total cycle length). Likely most
absolute rate equals a pre-set economically optimal when the oil
value. Alternatively, well is rate is at about 0.5 x CDOR.
unable to sustain hydrocarbon Alternatively, switch to injection
flow (continuous or
when rate equals 20-40% of the
intermittent) by
primary max rate obtained during the
production against cycle.
backpressure of gathering
system or well is "pumped off'
unable to sustain flow from
artificial lift. Alternatively, well
is out of sync with adjacent
well cycles.
18
CA 02900178 2015-08-12
Gas rate Switch to injection when gas Switch to injection when gas
rate
rate exceeds the capacity of exceeds the capacity of the
the pumping or gas venting pumping or gas venting system.
system. Well is unable to During production, an optimal
sustain hydrocarbon
flow strategy is one that limits gas
(continuous or intermittent) by production and maximizes liquid
primary production against from a horizontal well.
backpressure of gathering
system with or without
compression facilities.
Oil to Solvent Begin another cycle if the Begin another cycle if the OISR
of
Ratio OISR of the just completed the just completed cycle is
above
cycle is above 0.15 or 0.25.
economic threshold.
Abandonment Atmospheric or a value at For propane and a depth of 500m,
pressure which all of the solvent is about 340 kPa, the likely
lowest
(pressure at vaporized.
Steps e) and f) obtainable bottomhole pressure at
which well is (described below) may start the operating depth and well
produced after from this point at the same or below the value at which all
of the
CSDRP cycles higher pressure.
propane is vaporized. Steps e)
are completed) and
f) (described below) may start
from this point at the same or
higher pressure.
[0073] In Table 1, the options may be formed by combining two or more
parameters
and, for brevity and clarity, each of these combinations will not be
individually listed.
[0074] Composition for Mitigation of Second Phase
[0075] Proposed herein is a composition for mitigating the presence of a
second
liquid phase in the reservoir, in the wellbore, or in surface facilities of a
SDRP. The SDRP
may or may not be cyclic, i.e. which may or may not be a CSDRP.
[0076] A goal of mitigating the presence of the second liquid phase is to
improve flow
assurance in the reservoir, in the wellbore, or in surface facilities.
[0077] In a SDRP, the viscosity-reducing component may be combined with a
high-aromatics component, for instance one comprising at least 60 wt. %
aromatics, based
upon total weight of the high-aromatics component. One
suitable and inexpensive
19
CA 02900178 2015-08-12
high-aromatics component is gas oil from a catalytic cracker of a hydrocarbon
refining
process, also known as a light catalytic gas oil (LCGO).
[0078] The LCGO may comprise primarily poly-cyclic aromatics, to make the
component composition more miscible with bitumen. This can be done by co-
injecting LCGO
with the viscosity-reducing component into the reservoir to reduce phase
splitting in the
reservoir and/or surface facilities, and/or injecting an amount of LCGO in to
the wellbore
and/or surface facilities to mitigate the second liquid phase formation when
the pressure or
temperature conditions change or to re-dissolve the second liquid phase after
it forms to
facilitate transporting the produced fluids. The amount of high aromatics
component used
may be adjusted over time.
[0079] Lab tests have shown that LCGO is capable of fully dissolving a
heavy phase
with a high asphaltene content (66 wt. % asphaltenes) in 6-9 hours, however,
diluent is only
able to dissolve <50% after 4 weeks.
[0080] Fig. 2 is ternary phase diagram for bitumen, propane and a third
component.
The third component is xylene, LCGO, or diluent. Fig. 2 illustrates that LCGO
may be more
effective than diluent in mitigating the second liquid phase in a propane-
dominated process.
While LCGO is slightly less effective than xylene, it is more environmentally
friendly and far
less costly, making it potentially more commercially attractive.
[0081] An optimum ratio of viscosity-reducing component and LCGO during
co-injection may be determined based on lab and/or field tests, reservoir
simulation, and/or
economics evaluation.
[0082] Fig. 3 shows reservoir performance (in terms of produced bitumen
to injected
solvent ratio) predicted by a reservoir simulation model after one short cycle
of co-injection of
propane with diluent (88 vol. % propane and 12 vol. % diluent or LCGO). The
diluent case is
based on a model history-matched to field data. The same model predicts that
LCGO would
generate approximately 20% uplift in oil recovery.
[0083] The ratio of LCGO added in wellbore or surface facilities to
produced fluid may
be determined from the composition of the produced fluid to minimize formation
of second
liquid phase. This ratio may be adjusted at different stages of the production
through
reservoir and facility surveillance. Figs. 4 and 5 provide a comparison of the
effectiveness of
diluent and LCGO in mitigating the second liquid phase formed in a pipeline
condition and
CA 02900178 2015-08-12
also an illustration of how to determine the high aromatics component rate
based on the
produced fluid composition and production rate.
[0084] In particular, Figs. 4 and 5 show the heavy phase volume
percentages for
different propane volume ratios in the produced fluid when utility diluent or
LCGO is injected
at surface (at a certain rate relative to the total production rate) at
pressure and temperature
(PIT) lower than those at the reservoir condition. These figures are provided
as an illustration
for a given PR'. Similar technical analysis can be performed for other PIT
conditions.
[0085] The propane ratio in the produced fluid can be determined from
reservoir
surveillance, for example from produced density measurement or compositional
analysis.
Facility surveillance also provides pressure and temperature (PIT) in surface
facilities and
pipelines, through pressure/temperature transmitters. Based on the propane
ratio in the
produced fluid and the PIT conditions, one can determine how much heavy liquid
phase may
be formed for any given amount of diluent or LCGO added to the produced
liquid.
Depending upon the facility tolerance of second liquid phase, one can
determine the amount
of LCGO needed to achieve that. For example, with reference to Figs. 4 and 5,
to fully
mitigate a second liquid phase, a reasonable amount of diluent alone will not
be sufficient
when the propane volume ratio is between 0.3-0.5, however, it can be achieved
with a
maximum 20 mol % LCGO added to the production.
[0086] A solvent composition, for use in a solvent dominated recovery
process for
recovering hydrocarbons from an underground reservoir to improve reservoir or
wellbore flow
assurance, may comprise at least 50 mol % of a viscosity-reducing component
(based upon
total moles of the solvent composition) and at least 5 mol % of a high-
aromatics component
(based upon total moles of the solvent composition) comprising at least 60 wt.
% aromatics
(based upon total mass of the high-aromatics component). The high-aromatics
component
may comprise LCGO.
[0087] The LCGO may comprise at least 60 wt. % aromatics, wherein at
least half of
the aromatics by weight are two-ring or three-ring aromatics; less than 20 wt.
% paraffins;
and less than 20 wt. % cycloparaffins, all based upon total weight of the
LCGO. The
aromatics may comprise at least 10 wt. % alkybenzenes; at least 5 wt. %
combined indans,
tetralins, and indenes; at least 30 wt. % naphthalenes; and at least 5 wt. %
combined
acenaphthenes, acenaphthalenes, and tricyclicaromatics, all based upon total
weight of the
LCGO.
21
CA 02900178 2015-08-12
[0088] The LCGO may have an API gravity of 15 to 35 degrees. The LCGO may
have a boiling point of greater than 150 C. The LCGO may have a solubility
blending
number greater than 80 when blending with bitumen at a 1:1 volume ratio. The
LCGO may
not precipitate asphaltene when mixed with bitumen at any blending ratio. The
API gravity is
measured by ASTM D1298. The "solubility blending number" is described in I. A.
Wiehe and
R. J. Kennedy, Energy & Fuels, 14, 56 ¨ 63 (2000).
[0089] The viscosity-reducing component may comprise ethane, propane,
butane,
pentane, heptane, hexane, dimethyl ether, or a combination thereof. The
viscosity-reducing
component may comprise ethane, propane, butane, pentane, or a combination
thereof. The
viscosity-reducing component may comprise ethane or propane.
[0090] The viscosity-reducing component may comprise (i) a polar
component, the
polar component being a compound comprising a non-terminal carbonyl group; and
(ii) a
non-polar component, the non-polar component being a substantially aliphatic
substantially
non-halogenated alkane; wherein the viscosity-reducing component has a Hansen
hydrogen
bonding parameter of 0.3 to 1.7; and wherein the viscosity-reducing component
has a
volume ratio (a):(b) of 10:90 to 50:50. The Hansen hydrogen bonding parameter
may be 0.7
to 1.4. The volume ratio may be 10:90 to 24:76, or 20:80 to 40:60, or 25:75 to
35:65, or
29:71 to 31:69. The polar component may be a ketone. The polar component may
be
acetone. The non-polar component may be a 02-07 alkane, a 02-07 n-alkane, n-
pentane,
n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and
aromatics.
[0091] The viscosity-reducing component may comprise (i) an ether with 2
to 8
carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. The
ether may
have 2 to 4 carbon atoms. The ether may be di-methyl ether, methyl ethyl
ether, di-ethyl
ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-
propyl ether, methyl
iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether,
iso-propyl butyl
ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. The ether may
be di-methyl
ether. The non-polar hydrocarbon may a 02-030 alkane, a 02-05 alkane, or
propane. The
ether may be di-methyl ether and the non-polar hydrocarbon may be propane. The
component may have a volume ratio of the ether to the non-polar hydrocarbon of
10:90 to
90:10, or 20:80 to 70:30, or 22.5:77.5 to 50:50.
[0092] The compositions described herein may be used in a solvent
dominated
recovery process for recovering hydrocarbons from an underground reservoir.
22
CA 02900178 2015-08-12
[0093] Light catalytic gas oil (LCGO) may be used for assisting wellbore
flow
assurance of produced fluids in a solvent dominated recovery process.
[0094] A composition comprising at least 10 mol % of a high-aromatics
component,
based upon total weight of the composition, comprising at least 60 wt. %
aromatics, based
upon total weight of the aromatics, together with a viscosity-reducing
component may be
used in a solvent dominated recovery process for blending with produced
hydrocarbons to
improve facility or pipeline flow assurance, wherein the produced hydrocarbons
comprise
injected viscosity-reducing component.
[0095] A high-aromatics component comprising more than 60 wt. %
aromatics, based
upon total weight of the high-aromatics component, may be used for blending
with produced
hydrocarbons from a solvent dominated recovery process for recovering
hydrocarbons from
an underground reservoir, for improving facility or pipeline flow assurance,
wherein the
produced hydrocarbons comprise injected viscosity-reducing component.
[0096] A light catalytic gas oil (LCGO) may be used for assisting flow
assurance in
surface facilities of a solvent dominated recovery process.
[0097] With reference to Fig. 6, a cyclic solvent-dominated recovery
process, for
recovering hydrocarbons from an underground reservoir, may comprise: (a)
injecting injected
fluid into an injection well completed in the underground reservoir (602),
wherein the injected
fluid comprises the composition as described herein; (b) halting injection
into the injection
well and subsequently producing at least a fraction of the injected fluid and
the hydrocarbons
from the underground reservoir through a production well (604); (c) halting
production
through the production well (606); and (d) repeating the cycle of steps (a) to
(c) (608). The
injection well and the production well may utilize a common wellbore. The
hydrocarbons
may be a viscous oil having a viscosity of at least 10 cP at initial reservoir
conditions. The
injected fluid may comprise diesel, viscous oil, natural gas, bitumen,
diluent, C5+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable
solid particles,
salt, water soluble solid particles, solvent soluble solid particles, or a
combination thereof.
The injected fluid may comprise at least 25 mass % liquid at the end of an
injection cycle,
based upon total mass of the injected fluid. The injected fluid may comprise
less than 50
mass A liquid at the end of an injection cycle, based upon total mass of the
injected fluid. At
least 25 mass % of the viscosity-reducing component in an injection cycle may
enter the
reservoir as a liquid, based upon total mass of the viscosity-reducing
component. At least 25
23
CA 02900178 2015-08-12
mass % of the viscosity-reducing component at the end of an injection cycle
may be a liquid,
based upon total mass of the viscosity-reducing component. An in-situ volume
of fluid
injected over a cycle may be equal to a net in-situ volume of fluids produced
from the
production well summed over all preceding cycles plus an additional in-situ
volume of fluid.
The additional in-situ volume of fluid may be, at reservoir conditions, equal
to 2% to 15% of a
pore volume within a reservoir zone around the injection well within which
solvent fingers are
expected to travel during the cycle. An LCGO injection rate into the surface
facilities to mix
with the produced hydrocarbon liquid may be determined by: a produced
hydrocarbon rate, a
produced hydrocarbon composition, and a facility temperature and pressure, in
order to
mitigate formation of second liquid phase in the facilities.
[0098] A
light catalytic gas oil (LCGO) may be used for removing asphaltenes from
surface facilities of a solvent dominated recovery process or upstream of a
pig to assist
pigging of a pipeline.
[0099] It
should be understood that numerous changes, modifications, and
alternatives to the preceding disclosure can be made without departing from
the scope of the
disclosure. The preceding description, therefore, is not meant to limit the
scope of the
disclosure. Rather, the scope of the disclosure is to be determined only by
the appended
claims and their equivalents. It is also contemplated that structures and
features in the
present examples can be altered, rearranged, substituted, deleted, duplicated,
combined, or
added to each other.
24
