Note: Descriptions are shown in the official language in which they were submitted.
CA 02886212 2016-10-05
INTEGRATED LIQUID-TO-GAS ARTIFICIAL LIFT AND BITUMEN DILUTION
METHODS AND SYSTEMS
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S. Provisional
Patent Application
61/727,493 filed 16 November 2012 entitled INTEGRATED LIQUID-TO-GAS
ARTIFICIAL LIFT AND BITUMEN DILUTION METHODS AND SYSTEMS.
FIELD
[0002] Embodiments of the invention relate to methods and systems for
producing a
dense oil sand slurry. More particularly, embodiments of the invention relate
to methods and
systems for artificially lifting dense oil sand slurries from oil sand
formations located in a
subsurface formation having an overburden.
BACKGROUND
[0003] This section is intended to introduce various aspects of the art,
which may be
associated with exemplary embodiments of the present disclosure. This
discussion is
believed to assist in providing a framework to facilitate a better
understanding of particular
aspects of the present disclosure. Accordingly, it should be understood that
this section
should be read in this light, and not necessarily as admissions of prior art.
[0004] Bitumen is any heavy oil or tar with viscosity more than 10,000 cP
found in
porous subsurface geologic formations. Bitumen is often entrained in sand,
clay, or other
porous solids and is resistant to flow at subsurface temperatures and
pressures. Current
recovery methods inject heat or viscosity reducing solvents to reduce the
viscosity of the
bitumen and allow it to flow through the subsurface formations and to the
surface through
boreholes or wellbores. Other methods breakup the sand matrix in which the
heavy oil is
entrained by water injection to produce the formation sand with the oil;
however, the
recovery of bitumen using water injection techniques is limited to the area
proximal the bore
hole. These methods generally have low recovery ratios and are expensive to
operate and
maintain. However, there are hundreds of billions of barrels of these very
heavy oils in the
reachable subsurface in the province of Alberta alone and additional hundreds
of billions of
- 1 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
barrels in other heavy oil areas around the world. Efficiently and effectively
recovering these
resources for use in the energy market is one of the world's toughest energy
challenges.
100051 Extracting bitumen from oil sand reservoirs generally leads to
production of sand,
limestone, clay, shale, bitumen, asphaltenes, and other in-situ geo-materials
(herein
collectively referred to as sand or particulate solids) in methods such as
Cold Heavy Oil
Production with Sand (CHOPS), Cyclic Steam Stimulation (CSS), Steam Assisted
Gravity
Drainage (SAGD), and Slurrified Heavy Oil Reservoir Extraction process
(SHORE). The
amount of sand and water produced may vary from very small to large and it
depends on the
type of method, stress-state within the reservoir, drawdown and depletion. In
cases of CSS
and SAGD, sand production is not desirable. On the other hand, sand production
is
encouraged in cases of CHOPS and SHORE (International Patent Application
Publication
W02007/050180) processes. The SHORE process relies on artificial lift ("AL")
methods to
lift slurry containing bitumen to the surface. In particular, gas lift ("GL")
is one of the
preferred AL methods.
100061 Various artificial lift ("AL") methods for lifting oil/water/gas
with some small
solids content is known in the oil industry. However, lifting a dense slurry
through a vertical
pipe represents a unique challenge due to large slurry resistance components
such as friction
and hydrostatic pressure. An issue with using existing AL approaches to lift
dense slurries is
the high erosion rate. A dense slurry has very high sand content characterized
by high
erosive power characteristic of sand particles. The erosion problem is
augmented by the
duration of the lift process and cost and necessity to shut down the producer
well associated
with underground pump maintenance. In short, current AL methods are not
capable of lifting
such a dense slurry from any substantial depth over an extended period of
time.
100071 Conventional gas lift uses compressed air, nitrogen, steam or
natural gas to reduce
hydrostatic weight in the well. For slurry lift, the GL has significant
advantages over other
AL methods. However, use of conventional GL for bitumen production may also
have
certain disadvantages. For example, the high production rate envisioned for
SHORE together
with the high density of the slurry makes gas compression expensive. Moreover,
surface
bitumen extraction is fairly sensitive to the chemical composition of the
produced slurry
which could be affected by the gas injection. Therefore, conventional GL may
have a
detrimental influence on bitumen extraction in certain circumstances.
- 2 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
SUMMARY
100081 In one embodiment of the present disclosure, a method for
producing a dense
slurry is provided using a proposed gas lift method to lift large production
rates of slurries in
vertical or near vertical well to the surface. An embodiment of the present
invention uses a
lift liquid with controlled boiling pressure and temperature or evaporation
pressure and
temperature range, instead of compressed gas. Unlike gas, liquid has very low
compressibility and, therefore, it is more economical to pump downhole. In
this sense, the
"ideal" lift fluid would be the one which is a liquid when being pumped
downhole and
becomes a gas when it mixes with the production slurry. Evaporation or boiling
is a natural
process which fits this purpose. Therefore, an important concept of an
embodiment of the
present invention is a lift system which utilizes phase transformation from
liquid to gas by
boiling or evaporation or partial evaporation to economically lift the slurry
to the surface.
100091 In one embodiment of the present disclosure, the composition of
the lift fluid can
also be utilized to promote easier surface recovery of final products, such as
bitumen, from
the reservoir fluids, such as oil sands. An embodiment of this invention may
use a
composition of lift fluid that would contain two groups of chemical component.
The first
group of chemical components would generally include lighter hydrocarbons,
such as
methane, ethane, or propane, that would evaporate at an appropriate pressure
and temperature
to lead to gas lift. A second group of chemical components could include non-
evaporating
solvent components which remain in liquid phase and aid in bitumen extraction
or liberation
during the slurry lift, such as pentane, hexane, heptane, naptha, and/or
cyclohexane.
BRIEF DESCRIPTION OF THE DRAWINGS
100101 The foregoing and other advantages of the present invention may
become
apparent upon reviewing the following detailed description and drawings of non-
limiting
examples of embodiments in which:
100111 FIG. 1 is a process flow chart for methods of producing a dense
slurry in
accordance with certain aspects of the disclosure;
100121 FIG. 2 is an illustration of one exemplary embodiment of a
slurrified heavy oil
reservoir extraction lift system using a fluid lift apparatus to provide
slurry lift;
- 3 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
100131 FIG. 3 illustrates a schematic of an exemplary embodiment of a non
aqueous
extraction process of bitumen;
100141 FIG. 4 is an illustration of an exemplary embodiment of a
slurrified heavy oil
reservoir extraction lift system using a fluid lift apparatus to provide
slurry lift according to
the present disclosure;
100151 FIG. 5 illustrates a schematic of an exemplary embodiment of a non
aqueous
extraction process of bitumen in combination with the fluid lift apparatus of
FIG. 4;
100161 FIG. 6 illustrates a schematic of another exemplary embodiment of
a non aqueous
extraction process of bitumen in combination with the fluid lift apparatus of
FIG. 4;
100171 FIG. 7 illustrates a phase diagram for two exemplary embodiments of
a power
fluid used in a fluid lift apparatus to provide slurry lift;
100181 FIGS. 8A-8B illustrate a schematic of an embodiment of a gas lift
and a
corresponding working cycle on a phase diagram for an embodiment of a 100 m
deep well;
100191 FIG. 9 illustrates a phase diagram and working cycle for another
exemplary
embodiment of a power fluid used in a fluid lift apparatus to provide slurry
lift for an
embodiment of a 300 m deep well;
100201 FIGS. 10A-B illustrate gas holdup for the wells of FIGS. 8 and 9.
DETAILED DESCRIPTION
100211 In the following detailed description section, the specific
embodiments of the
present disclosure are described in connection with preferred embodiments.
However, to the
extent that the following description is specific to a particular embodiment
or a particular use
of the present disclosure, this is intended to be for exemplary purposes only
and simply
provides a description of the exemplary embodiments. Accordingly, the
disclosure is not
limited to the specific embodiments described below, but rather, it includes
all alternatives,
modifications, and equivalents falling within the true spirit and scope of the
appended claims.
- 4 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
DEFINITIONS
100221 Various terms as used herein are defined below. To the extent a
term used in a
claim 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.
100231 The terms "a" and "an," as used herein, mean one or more when
applied to any
feature in embodiments of the present inventions described in the
specification and claims.
The use of "a" and "an" does not limit the meaning to a single feature unless
such a limit is
specifically stated.
100241 The term "about" is intended to allow some leeway in mathematical
exactness to
account for tolerances that are acceptable in the trade. Accordingly, any
deviations upward or
downward from the value modified by the term "about" in the range of 1% to 10%
or less
should be considered to be explicitly within the scope of the stated value.
100251 In the claims, as well as in the specification above, all
transitional phrases such as
"comprising," "including," "carrying," "having," "containing," "involving,"
"holding,"
"composed of," and the like are to be understood to be open-ended, i.e., to
mean including but
not limited to. Only the transitional phrases "consisting of' and "consisting
essentially of'
shall be closed or semi-closed transitional phrases, respectively, as set
forth in the United
States Patent Office Manual of Patent Examining Procedures, Section 2111.03.
100261 The term "dense slurry," as used herein, refers to a mixture of
solids and fluids
having a solids concentration range of about 20-65 volume percent (vol%). Such
a dense
slurry may be found naturally in-situ, may be generated by the slurrified
heavy oil reservoir
extraction (SHORE) process, or may be generated by another process.
100271 The term "exemplary" is used exclusively herein to mean "serving
as an example,
instance, or illustration." Any embodiment described herein as "exemplary" is
not necessarily
to be construed as preferred or advantageous over other embodiments.
100281 The term "formation" refers to a body of rock or other subsurface
solids that is
sufficiently distinctive and continuous that it can be mapped. A "formation"
can be a body of
rock of predominantly one type or a combination of types. A formation can
contain one or
more hydrocarbon-bearing zones. Note that the terms "formation," "reservoir,"
and
"interval" may be used interchangeably, but will generally be used to denote
progressively
- 5 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
smaller subsurface regions, zones or volumes. More specifically, a "formation"
will
generally be the largest subsurface region, a "reservoir" will generally be a
region within the
"formation" and will generally be a hydrocarbon-bearing zone (a formation,
reservoir, or
interval having oil, gas, heavy oil, and any combination thereof), and an
"interval" will
generally refer to a sub-region or portion of a "reservoir."
100291 The term "heavy oil" refers to any hydrocarbon or various mixtures
of
hydrocarbons that occur naturally, including bitumen and tar. In one or more
embodiments, a
heavy oil has a viscosity of between 1,000 centipoise (cP) and 10,000 cP. In
one or more
embodiments, a heavy oil has a viscosity of between 10,000 cP and 100,000 cP
or between
100,000 cP and 1,000,000 cP or more than 1,000,000 cP at subsurface conditions
of
temperature and pressure.
100301 The term "hydrocarbon-bearing zone," as used herein, means a
portion of a
formation that contains hydrocarbons. One hydrocarbon zone can be separated
from another
hydrocarbon-bearing zone by zones of lower permeability such as mudstones,
shales, or
shaley (highly compacted) sands. In one or more embodiments, a hydrocarbon-
bearing zone
includes heavy oil in addition to sand, clay, or other porous solids.
100311 The term "jet pump," as used herein refers to any apparatus having
a nozzle or
nozzles configured to flow a fluid (e.g. a power fluid) through the nozzle
such that: 1) the
fluid is introduced into a producer pipe at a velocity higher than a natural
velocity of the
dense slurry flowing into the producer pipe without the jet pump; 2) the fluid
flow creates a
low pressure region in a subsurface formation adjacent to the jet pump that
has a lower
pressure than the formation's natural pressure; and 3) dilutes the dense
slurry in the pipe to a
density lower than the natural density of the formation.
100321 The term "overburden" refers to the sediments or earth materials
overlying the
formation containing one or more hydrocarbon-bearing zones. The term
"overburden stress"
refers to the load per unit area or stress overlying an area or point of
interest in the subsurface
from the weight of the overlying sediments and fluids. In one or more
embodiments, the
"overburden stress" is the load per unit area or stress overlying the
hydrocarbon-bearing zone
that is being conditioned and/or produced according to the embodiments
described.
100331 The terms "preferred" and "preferably" refer to embodiments of the
inventions
that afford certain benefits under certain circumstances. However, other
embodiments may
- 6 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
also be preferred, under the same or other circumstances. Furthermore, the
recitation of one
or more preferred embodiments does not imply that other embodiments are not
useful, and is
not intended to exclude other embodiments from the scope of the inventions.
100341 The terms "substantial" or "substantially," as used herein, mean a
relative amount
of a material or characteristic that is sufficient to provide the intended
effect. The exact
degree of deviation allowable may in some cases depend on the specific
context.
100351 The definite article "the" preceding singular or plural nouns or
noun phrases
denotes a particular specified feature or particular specified features and
may have a singular
or plural connotation depending upon the context in which it is used.
DESCRIPTION OF EMBODIMENTS
100361 A slurrified heavy oil reservoir extraction process, such as
ExxonMobil's SHORE
process, is a developing oil sand in-situ extraction process that relies on
fluidization of the
reservoir and lifting of the overburden stress to make the oil sand mobile,
often referred to as
the conditioning phase. After a fluidization or conditioning phase a
horizontal pressure
difference is created that is sufficient to overcome friction losses within
the reservoir. As a
result, the whole reservoir slides from an injection well towards a producer
well which is put
on artificial lift.
100371 The oil sand concentration in the oil sand slurry, which may
include sand, clays,
bitumen, water and other materials, immediately around the production well is
approximately
50% volume solids, but can vary significantly within a large range, such as
from 25% to 65%
or larger volume solids. The high density and frictional resistance of the
slurry is too high for
the bottom hole pressure to allow it to flow to the surface. Therefore, some
form of artificial
lift is necessary, in one embodiment, a jet pump is used as a form of
artificial lift. In another
embodiment, an injection line could be used, either in lieu of or instead of
the jet pump or in
addition to the jet pump. The injection line could use a simple orifice or an
expansion valve
to achieve a pressure drop in the power fluid resulting in the evaporation or
partial
evaporation of the power fluid. The jet pump serves as only one embodiment of
how liquid
can be mixed with the slurry. Another example of dilution method could be
liquid
introduction through the well wall opening. As a result of any dilution
method, a diluted
slurry with a sand concentration range of 20-40% volume, or 25-50% volume,
enters the
production well.
- 7 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
100381 However, even a diluted slurry with a sand concentration range of
20-40% volume
is still too heavy for the bottom hole pressure to allow it to flow up the
wellbore so a lift
method in addition to mere dilution is needed. Most of conventional lift
methods will not
work due to the high solid concentration. Therefore, gas lift in conjunction
with the dilution
has been proposed for SHORE production. In general, as gas bubbles move up,
their volume
will increase due to the expected pressure decrease. The larger bubbles will
accelerate and
push sluny slugs faster. Turbulence is expected to increase in such
accelerated slurry slugs.
Beneficially, this is expected to lead to improved conditioning of the slurry
due to increased
shear of particles.
100391 As mentioned above in the Background, the use of conventional gas
lift (GL)
application for SHORE may have certain drawbacks in certain situations. First,
due to the
high production rate and high slurry weight, the cost of gas compression and
injection can be
prohibitively high. Second, gas lift has a potential to be detrimental to the
surface bitumen
extraction, for example, the gas lift could result in foaming in the produced
slurry which
could be difficult for the surface extraction to separate out the gas. Other
types of artificial
lift methods, such as the use of pumps, for example, electric submersible, rod
or progressive
cavity pumps, are not expected to be applicable in a slurrified heavy oil
reservoir extraction
process due to excessive wear from the slurry or flow rate limitations
inherent in those types
of pumps.
[0040j The design of a cost effective GL method aiming at enhanced bitumen
recovery is
an aspect of an embodiment of this invention. An embodiment of the GL method
discussed
herein can also be specifically tailored to a range of bitumen production
methods like
SHORE or CHOPS (Cold Heavy Oil Production with Sand) or SAGD (Steam Assisted
Gravity Drainage). An embodiment of the present invention includes a proposed
GL method
to lift large production rates of slurries in vertical or near vertical well
to the surface. An
embodiment of the present invention uses a lift liquid with controlled boiling
pressure and
temperature or evaporation pressure and temperature range, instead of
compressed gas.
10041j Unlike gas, liquid has very low compressibility and, therefore, it
is cheap to pump
downhole. Hence, if one replaces gas with a liquid as a lift agent the cost of
the lift can be
reduced. However, liquid itself is a poor lift agent because it has density
comparable to a
density of production slurry. In this sense, the "ideal" lift fluid would be
the one which is a
liquid when being pumped downhole and becomes a gas when it mixes with the
production
- 8 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
slurry. Evaporation or boiling is a natural process which fits this purpose.
Therefore, an
important concept of an embodiment of the present invention is a lift system
which utilizes
phase transformation from liquid to gas by boiling or evaporation or partial
evaporation to
economically lift the slurry to the surface.
10042j The existence of a fluid in the liquid or vapor phase is a function
of its chemical
composition and its pressure and temperature. Pure or single component liquids
like water
have a single evaporation pressure at a given temperature. Multicomponent
fluids have a
pressure range over which gradual evaporation of different fluid components
occurs. This
behavior of evaporation as a function of fluid composition can serve as a
means of control of
where and how evaporation and corresponding gas lift happens.
100431 In addition, the composition of the lift fluid can also be
utilized to promote easier
surface recovery of final products, such as bitumen, from the reservoir
fluids, such as oil
sands. For example, extraction of bitumen from Alberta, Canada, mined oil
sands relies on
the Clark Hot Water extraction process. This process is both energy and water
intensive as it
requires large volumes of hot water. Conventional oil sand mining has two
drawbacks ¨ only
a few percent of oil sands in Alberta are minable and bitumen extraction
consumes large
volumes of heated fresh water, requiring both water and a fossil fuel for
heat. This is
contrary to the overall trend towards more stringent legislation limiting
fresh water
consumption. Development of new technologies like SHORE has a large potential
to expand
mining on a larger portion of Alberta's oil reserves. The slurrified
technology may use gas lift
together with novel bitumen extraction techniques like non aqueous extraction
(NAE) which
relies on mixing of certain solvents and bitumen bearing sand. An embodiment
of this
invention may use a composition of lift fluid that would contain two groups of
chemical
component. The first group of chemical components would generally include
lighter
hydrocarbons, such as methane, ethane, or propane, that would evaporate at an
appropriate
pressure and temperature to lead to gas lift. A second group of chemical
components could
include non-evaporating solvent components which remain in liquid phase and
aid in bitumen
extraction or liberation during the slurry lift, such as pentane, hexane,
heptane, naptha, and/or
cyclohexane.
[00441 An embodiment of the present invention addresses the problem of
water use
during sluny lift and the potential detrimental effect of adding significant
volumes of water to
the slurry when using certain solvent based extraction technologies at the
surface for bitumen
- 9 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
separation from the sand. Another aspect of an embodiment of the invention is
the control of
the chemical composition of the lift fluid to benefit or supplement the
surface extraction of
bitumen from the produced slurry.
100451 Referring now to the Figures, FIG. 1 is process flow chart for
methods of
producing a dense slurry in accordance with certain aspects of the disclosure.
The process
100 includes injecting 102 a liquid phase fluid into a producer pipe inlet to
mix with the
dense slurry and form a diluted slurry, evaporating 104 at least a portion of
the liquid phase
fluid in the producer pipe, and lifting 106 the diluted sluny up the producer
pipe utilizing the
gas lift of the evaporation of at least a portion of the fluid. The process
100 may also
optionally include selecting 108 the fluid to begin evaporating at the
pressure and
temperature of the producer pipe inlet. The process 100 may also optionally
include
dissolving 110 at least a portion of the bitumen in the diluted slurry with a
liquid phase of the
fluid in the producer pipe.
100461 The dense slurry may enter the producer pipe inlet by positioning
a jet pump
below the producer pipe and injecting a power fluid through the jet pump into
the producer
pipe. Again, a jet pump is just one possible embodiment of slurry dilution. In
another
embodiment, an injection line could be used, either in lieu of or instead of
the jet pump or in
addition to the jet pump. The injection line could use a simple orifice or an
expansion valve
to achieve a pressure drop in the power fluid resulting in the evaporation or
partial
evaporation of the power fluid. Another example of dilution method could be
liquid
introduction through the well wall opening. The diluted slurry is further
lifted up the
producer pipe utilizing the gas lift of the evaporation of at least a portion
of the fluid.
100471 The SHORE process may rely on gas lift and NAE to lift oil sand
and extract
bitumen. An embodiment of a slurrified heavy oil production slurry lift system
200 is
illustrated in Fig. 2. The lift system 200 includes two major components. The
first
component is a jet pump 202. Power fluid 204 is delivered through a nozzle 206
of the jet
pump 202 towards the production well intake 208. High speed fluid jet 210
creates intensive
mixing and drives reservoir fluid oil sand 212 into the production well 214.
Therefore, slurry
216 entering the production well 214 will consist of reservoir fluid and oil
sand 212 diluted
by power fluid 204. The second component is a gas lift 218 in which the gas
220 is injected
downstream of the jet pump 202 and reduces the hydrostatic head in the
production well 214
to such degree so the well can flow to the surface.
- 10 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
100481 Due to a high flow velocity of the slurry as it travels up the
production well,
approximately one meter per second, an intensive mixing of oil sand, reservoir
fluid and
power fluid happens in the well. After gas injection, the flow speed increases
even further
leading to more intense mixing.
10049j Figure 3 illustrates a schematic of a non aqueous extraction process
300 of
bitumen that may be applied at the surface to the slurry lifted by SHORE lift
process. In a
NAE process, a mined oil sand 302 with rather low water content, such as 0.08
< water
mass/solid mass <0.12, is mixed with a rather limited amount of organic
solvent 304 in a
mixing tank 306. Organic solvent 304 can be a paraffinic solvent or a cyclic
aliphatic solvent
or a mixture thereof. Limiting the amount of organic solvent 304 enables
bitumen dissolution
without detrimental asphaltene precipitation. Exiting the mixing tank 306,
bitumen extract
308 contains fines 310 which agglomerate when water 312 is added to the
bitumen extract
308 in the second mixing tank 314. From the second mixing tank 314,
agglomerated solids
316 and bitumen extract 318 can be separated in appropriate apparatus like a
cyclone 320.
Optionally, a second solvent 322 is added to the bitumen extract 324 leaving
the cyclone 320
leading to asphaltene precipitation 326 and additional separation of bitumen
from the fines
and water. The result is a high quality bitumen extract 328. NAE requires
substantially less
amount of water than the traditional Clark hot water process. Moreover,
organic solvent 304
and second solvent 322 have low boiling temperatures and so a modest amount of
energy is
needed to separate them from the final bitumen extract 328.
100501 One embodiment of the present invention illustrated in Fig. 4
integrates SHORE
lift, as previously discussed and illustrated in Fig. 2, and a beginning step
of NAE, as
previously discussed and illustrated in Fig. 3. In this embodiment, the power
fluid is a liquid
mixture of light and heavier components. Similar to Fig. 2, the power fluid
402 is injected
into the production well 404 with a jet pump 408, drawing the reservoir fluid
and oil sand 406
into the production well. The light components of the power fluid 402 will
evaporate at the
pressure and temperature in the production well, providing the needed gas lift
410. The
functions of the compressed gas injection and the power fluid injection from
the jet pump of
Fig. 2 are now combined into a single injection step in Fig. 4. Furthermore,
the heavier
solvents in the liquid power fluid 402 composed of light and heavier
components will extract
and/or liberate the bitumen from the oil sand. Thus, the function of mixing
the oil sand with
an organic solvent in a mixing tank from the example illustrated in Fig. 3 is
now
accomplished in one step during the slurry lift in the production well of Fig.
4.
- 11 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
100511 The power fluid of Fig. 4 may be a special mixture of hydrocarbons
that is formed
at the surface and liquefied at an appropriate pressure and temperature. The
mixture may, in
general, include light hydrocarbons and one or more heavier organic solvents.
This liquid
mixture is used as a power fluid for the jet pump, i.e., it is injected
through the power fluid
duct. For typical SHORE production rate, approximately 1000 - 3000 m3/day of
slurry per
well, the pressure drop at the jet pump nozzle is about 100 psi but it can
vary if another
dilution method is used apart from jet pump. The SHORE production rate can
also be as low
as approximately 200 m3/day of slurry. Light hydrocarbons such as methane
and/or ethane
evaporate at significantly lower pressure than the heavier solvent. Therefore,
the composition
of the mixture is formulated in such a way that power mixture fluid is liquid
upstream of the
jet pump nozzle and the resulting pressure drop downstream of the nozzle
evaporates a
significant part of lighter hydrocarbons. Meanwhile, most of the heavier
solvent(s) remains
in the liquid phase and serves as both a slurry diluter and a bitumen solvent.
As a result, the
evaporated part of the power fluid serves as a gas lift while the heavier
solvent portion mixes
vigorously with the oil sand during fast lift leading to bitumen liberation
and extraction.
100521 It is possible that if the concentration of solvent mass in
respect to bitumen mass
is too high in the production wellbore, a detrimental asphaltene precipitation
may occur.
However, the high velocity in the production wellbore during typical SHORE gas
lift leads to
a solvent/bitumen mixing time of no more than few minutes. Asphaltene
precipitation in
general requires a much longer residence time period than a few minutes so the
amount of
solvent injected at the wellbore may not be restricted by asphaltene
precipitation.
100531 Fig. 5 illustrates a modified NAE process 500 integrated with
SHORE lift by an
embodiment of the present invention. As mentioned above, the function of
mixing the oil
sand with an organic solvent 304 in a mixing tank 306 from the example of Fig.
3 may be
accomplished in one step during the slurry lift in the production well of Fig.
4. In Fig. 5,
water 502 as a fines agglomerating agent can be added at the surface after the
slurry lift.
Optionally, water 502 as a fines agglomerating agent can be injected as
fraction of the power
mixture fluid 504. If asphaltene precipitation is not an issue due to short
lift residence time,
then enough solvent and water can be injected so that solids agglomeration and
bitumen
extraction may happen during the slurry lift. In this case, the resulting
slurry may directly go
to separation process, greatly simplify, ing the NAE process and reducing its
cost. This
simplified version of a NAE process 600 with only the separation process at
the surface is
illustrated in Fig. 6.
- 12 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
100541 As mentioned above, the chemical composition of a power mixture
fluid can be
tailored in such a way so that evaporation of light hydrocarbons in the power
fluid begins
downstream of the jet pump nozzle or other relevant dilution method. Different
wells may
have different downhole pressures and temperatures. Therefore, the composition
of the
power mixture fluid may vary from well to well so that evaporation of light
hydrocarbons in
the power fluid begins downstream of the jet pump nozzle, orifice, or
expansion valve for
different well depths, i.e., different pressures, and different well
temperatures. Furthermore,
for a given well, it may be necessary to adjust the composition of the power
fluid at the
surface to control the boiling point and solvency power of the power fluid in
response to
changes pressure, temperature, oil sand composition, etc. To illustrate this
point, the
composition of an embodiment of a power fluid will be discussed below that
consists of
methane and cyclohexane. Methane functions as a lift agent and cyclohexane is
a solvent.
Different chemical components can be chosen, the solvent component can be any
mixture of
hydrocarbons such as paraffinic solvent or cyclic aliphatic hydrocarbon.
Different lift agents
may be used as well.
100551 Fig. 7 illustrates a phase diagram 700 of two possible
compositions of methane
and cyclohexane mixtures. Line 702 is the phase diagram line for a 16% (mole)
methane /
84% cyclohexane mixture and line 704 is the phase diagram line for a 6%
methane 94%
cyclohexane mixture. The temperature 706, in Celsius, is on the x-axis and the
y-axis is
pressure 708 in psia. As is known to a person of ordinary skill in the art,
the area within the
phase diagram line corresponds to a boiling or evaporation temperature and
pressure range
for the mixture, the area to the left of the left portion of the line
corresponds to the liquid
phase for the mixture and the area to the right of the right portion of the
line corresponds to
the vapor phase for the mixture. The downhole pressure for a 100 meter deep
well may be
approximately 207 psia, at this pressure, one might choose the 6% methane /
94%
cyclohexane mixture because at a pressure of 207 psia, depending on the
temperature, the
mixture is likely to be either a liquid, although close to boiling, or nearly
a liquid with some
vapor.
100561 Fig. 8A illustrates a working cycle on the phase diagram of a gas lift
of a 100 m deep
well while Fig. 88 depicts a schematic of an embodiment of a corresponding gas
lift for the
100 m well. In this embodiment, the power fluid is a mixture of 6% methane and
94%
cyclohexane. Points 801, 802, 803 and 804 on phase diagram Fig. 8A correspond
to
locations 801, 802, 803 and 804 on the gas lift schematic in Fig. 8B. Point
803 corresponds
- 13 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
to the exit of the jet pump nozzle 805, at which point evaporation of a
portion of the power
fluid should start, i.e., point 803 should be on the phase line separating
liquid and liquid-
vapor states. Second, production wellhead pressure is fixed ¨ about 50 psi
leading to point
804 being at this approximate pressure level.
10057j Starting at the surface, power fluid 808 is injected into power
fluid conduit 810 as
a liquid-vapor at the surface at a temperature and pressure corresponding to
point 801 on the
phase diagram of Fig. 8A. At this point 801, the liquid-vapor power fluid 808
mixture has
temperature slightly above the reservoir temperature. The liquid-vapor power
fluid 808 then
flows down the power conduit 810 to the jet pump 812. As the liquid-vapor
power fluid 808
flows down the power conduit 810, the pressure increases and the temperature
decreases,
resulting in any vapor condensing so that the power fluid 808 becomes a liquid
and
corresponds to the point 802 on the phase diagram. The pressure increase of
about 100 psi
between points 801 and 802 is due to hydrostatic head of power fluid in
conduit assuming
that majority of the power fluid height is occupied by liquid phase of power
fluid. After
ejection from the jet pump 812 the pressure of the power fluid 808 drops to
point 803 on the
phase diagram. A typical jet nozzle pressure drop is about 100 psi. This leads
to evaporation
of mainly methane while the temperature of the power fluid remains
approximately at
reservoir ambient level due to further mixing with reservoir slurry. As the
power fluid 808
flows up the well together with the reservoir slurry its pressure decreases
leading to further
evaporation of mainly methane until it reaches the wellhead pressure, while
remaining at
reservoir temperature, which pressure and temperature correspond to point 804.
[00581 At the wellhead, in this embodiment, the reservoir slurry and
power fluid mixture
820 enter a separator 822 with negligible pressure change. At the separator
822, the diluted
bitumen 824, consisting of bitumen and cyclohexane is separated from methane
826. The
methane 826 is then mixed with additional cyclohexane 828 and this mixture 830
goes into
the pump 832. The pump 832 can be a multiphase pump such as a twin-screw pump
or
compressor. The pump 832 must then raise the pressure of the mixture 830 from
point 804 to
point 801. Thus the energy required to run gas lift in this embodiment for a
100 m deep well
goes into compression and liquefaction of the power fluid 808 from
approximately 50 to 200
psia. If the cost of compression of the mixture of 6% methane and 94%
cyclohexane from 50
to 200 psia is lower than cost of air compression from approximately 50 to 300
psia, where
300 psia is the downhole pressure, then the mixture lift method is more
economical than gas
lift plus there is the added benefit of initial bitumen dilution and
liberation. Note that the
- 14 -
CA 02886212 2015-03-26
WO 2014/077947 PCT/US2013/059734
pressure of the power fluid does not need to be as high as the bottom hole
pressure due to the
increase in pressure from the hydrostatic head of the liquid column in the
power fluid
conduit. For 100 m well this beneficial hydrostatic head is about 100 psi.
100591 In another embodiment, a 300 m well has a downhole pressure of
approximately
620 psia. In this embodiment, a mixture of 16% methane and 84% cyclohexane may
be
more suitable as the power fluid, as illustrated in Fig. 9. It is very similar
to the 100 m well
except that the power fluid may be a vapor and liquid mixture which is
injected into the
power conduit at point 901. However, the vapor portion of the power fluid
quickly
condenses to a liquid as pressure rises from point 901 to point 902
immediately upstream of
the jet pump or injection point. In this embodiment thr a 300 m well, the
compression cost is
higher as the pump and/or compressor must raise the pressure from
approximately 50 psia at
the wellhead to approximately 650 psia at the surface location of the power
fluid conduit.
Again, the cost of such pressurization/compression should be compared to cost
of air
compression from 50 to 700 psia.
100601 Figs. 10A and 10B illustrate calculated gas holdup along the height
of a 100 m
(Fig. 10a) and 300 m (Fig. 10b) well. Gas holdup 1002, on the y-axis for both
Fig. 10A and
10B, is a volume ratio of the well occupied by gas, which, in the embodiment
using a
methane/cyclohexane mixture, is primarily evaporated methane. The x-axis is
well pressure
1004, in psia. The gas holdup is calculated with a total volume production
rate of slurry of
2,000 m3/day while the power fluid liquid injection rate, point 803 on Fig.
8b, was 1,500
m3/day and 500 m3/day for the 100 and 300 m well, respectively. Well locations
801, 802,
803 and 804 on Fig. 8b correspond to the points in Figs. 10A and B.
Calculations have
shown that after ejection from the jet nozzle, point 802, methane is
evaporated and expanded
while moving up the well leading to desired gas holdup values in excess of
0.5. Such holdup
profiles reflect typical gas content during normal gas lift operation.
100611 Reservoirs intended for the disclosed methods and systems can be
shallow, about
75 m to 150 m, or deep from about 150 m to 460 m, and even as deep as 1,000 m.
Depending on depth and bottom hole pressure, different combinations of power
fluid
compositions may be utilized. Because the density of the slurry downstream of
the jet pump
is about 1.5-1.7 times that of water, the gas undergoes significant pressure
drop while rising
from the reservoir. Consequent gas expansion may lead to a significant
increase in gas and
slurry rising speed which may incur significant friction losses.
- 15 -
CA 02886212 2016-10-05
[0062] While the present disclosure may be susceptible to various
modifications and
alternative forms, the exemplary embodiments discussed above have been shown
only by
way of example. However, it should again be understood that the disclosure is
not intended
to be limited to the particular embodiments disclosed herein. Indeed, the
present disclosure
includes all alternatives, modifications, and equivalents.
- 16-
