Note: Descriptions are shown in the official language in which they were submitted.
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Apparatuses, Systems and Methods for Evaluating Imbibition Effects of
Waterflooding in Tight Oil Reservoirs
Technical Field
[0001] The embodiments disclosed herein relate to waterflooding in oil
reservoirs,
and, in particular to apparatuses, systems and methods for evaluating
imbibition effects
of waterflooding in tight oil reservoirs.
Background
[0002] Primary recovery is typically the first stage of oil and gas
production in
which natural reservoir drives, such as the natural pressure of the reservoir,
are used to
recover hydrocarbons. For instance, in one example of primary recovery,
hydrocarbons
are driven towards the well and to the surface due to the pressure difference
between
the crude oil reservoir and the bottom of the well. Only a portion of the
total crude oil
present in a reservoir can be recovered during a primary recovery process.
[0003] Secondary recovery techniques are used to force additional oil
beyond
that recovered during primary recovery out of the reservoir. The simplest
secondary
recovery technique is direct replacement of crude oil in the reservoir with
another
medium in the form of a displacement fluid (also referred to as an injection
fluid), usually
water or gas. "Waterflooding", as it is called, requires water to be injected
under
pressure into reservoir rock formations via injection wells. The injected
water acts to
help maintain reservoir pressure, and sweeps the displaced oil ahead of it
through the
rock towards production wells from which the oil is recovered.
[0004] Tight oil is light crude oil that is contained in petroleum-
bearing formations
of low permeability such as but not limited to shale and sandstone. While
conducting
waterflooding in tight oil reservoirs, the volume of crude oil produced is
impacted by
water drive effects in relative high permeability layers and imbibition
effects in relative
low permeability payzones. Many researchers have therefore found that
imbibition
effects are a key mechanism for the development of tight oil reservoirs where
their
extremely low porosity and permeability have historically presented many
development
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challenges. However, previous experimental studies of imbibition effects in
the
development of tight oil reservoirs have typically been conducted using
regular cores
under ambient pressures. These experimental conditions vary from the
conditions
present in natural reservoirs featuring high and low permeability layers and,
accordingly,
the lab results from these experiments do not accurately evaluate imbibition
effects on
production performances for tight oil reservoirs with properties of high-
temperature,
high-pressure and heterogeneous payzones.
[0005] With researchers in academia and industry increasingly
turning their
attention to oil extraction from tight oil reservoirs, there is a need for
systems and
methods for evaluating imbibition effects of waterflooding in tight oil
reservoirs.
Summary
[0006] According to some embodiments, a method for determining
imbibition
effects of waterflooding on crude oil produced from at least two core samples,
the
method including providing the at least two core samples to a core holder,
each core
sample forming a layer within the core holder, each core sample being absorbed
with
crude oil that is distinguishable from other crude oil absorbed on other core
samples,
and each core sample having a permeability that is different than a
permeability of the
other core samples; conducting the waterflooding on the core samples by
injecting a
first fluid into the core holder to produce a second fluid, the second fluid
comprising at
least a portion of the crude oil of each of the core samples; analyzing the
second fluid to
determine a volume of one portion of the crude oil produced from one of the
core
samples; and determining, based on the volume of the one portion of the crude
oil, a
volume of crude oil produced due to imbibition effects from the one of the
core samples
based on the permeability the one of the core samples.
[0007] According to some embodiments, the first fluid is injected
into the core
sample having the highest permeability relative to the other core samples.
[0008] According to some embodiments, the crude oil of at least
one of the core
samples is saturated with a tracer to be distinguishable from the other crude
oil
absorbed on the other core samples.
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[0009] According to some embodiments, the providing the at least two core
samples is providing three core samples.
[0010] According to some embodiments, a temperature of the core holder is
in a
range of about 0 C to about 177 C.
[0011] According to some embodiments, a pressure of the core holder is in
a
range of about 0 kPa to about 34473 kPa.
[0012] According to some embodiments, the tracer is one of a dye and an
oleic
fluorescein tracer.
[0013] According to some embodiments, an apparatus for evaluating
imbibition
effects of waterflooding on crude oil produced from at least two core samples
is
provided, the apparatus including a body including a first end; a second end
spaced
apart from the first end; a volume defined by an inner wall of the body, the
volume
extending between the first end and the second end and housing the at least
two core
samples, each core sample forming a layer within the body of the core holder,
each
core sample being absorbed with crude oil that is distinguishable from other
crude oil
absorbed on other core samples, and each core sample having a permeability
that is
different than a permeability of the other core samples; an inlet disposed at
the first end
for receiving a first fluid for conducting the waterflooding; and an outlet
disposed at the
second end for removing a second fluid produced by the waterflooding, the
second fluid
comprising at least a portion of the crude oil of each of the core samples.
[0014] According to some embodiments, the inlet is configured to direct
the fluid
into the core sample with the highest permeability relative to the other core
samples.
[0015] According to some embodiments, the outlet is configured to receive
the
fluid from the core sample with the highest permeability relative to the other
core
samples.
[0016] According to some embodiments, the crude oil of at least one of
the core
samples is saturated with a tracer to be distinguishable from the other crude
oil
absorbed on the other core samples.
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[0017] According to some embodiments, a system for conducting a core
flooding
test is provided, the system including an apparatus for determining imbibition
effects of
waterflooding on crude oil produced from at least two core samples, the
apparatus
including a body including a first end spaced apart from a second end to
define a
volume therebetween, the volume housing the at least two core samples, each
core
sample forming a layer within the body of the core holder, each core sample
being
absorbed with crude oil that is distinguishable from other crude oil absorbed
on other
core samples, and each core sample having a permeability that is different
than a
permeability of the other core samples; an inlet disposed at the first end for
receiving a
first fluid for conducting the waterflooding; and an outlet disposed at the
second end for
removing a second fluid produced by the waterflooding, the second fluid
comprising at
least a portion of the crude oil of each of the core samples; and an analyzer
coupled to
the apparatus and configured to: analyze the second fluid to determine a
volume of one
portion of the crude oil produced from one of the core samples; and determine,
based
on the volume of the one portion of the crude oil, a volume of crude oil
produced due to
imbibition effects from the one of the core samples based on the permeability
the one of
the core samples.
[0018] According to some embodiments, the inlet is configured to direct
the fluid
into the core sample with the highest permeability relative to the other core
samples.
[0019] According to some embodiments, the outlet is configured to receive
the
fluid from the core sample with the highest permeability relative to the other
core
samples.
[0020] According to some embodiments, the crude oil of at least one of the
core
samples is saturated with a tracer to be distinguishable from the other crude
oil
absorbed on the other core samples.
[0021] Other aspects and features will become apparent, to those
ordinarily
skilled in the art, upon review of the following description of some exemplary
embodiments.
Brief Description of the Drawings
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[0022] The drawings included herewith are for illustrating various
examples of
articles, methods, and apparatuses of the present specification. In the
drawings:
[0023] FIG. 1 is a perspective view of a core holder, according to one
embodiment;
[0024] FIG. 2 is a top view of the core holder shown in FIG. 1;
[0025] FIG. 3 is an end view of the core holder shown in FIG. 1;
[0026] FIG. 4 is a partial cross-section view of a schematic of the core
holder of
FIG. 1;
[0027] FIG. 5 is an exploded side view of the core holder of FIG. 1
showing each
of the internal parts;
[0028] FIG. 6 is an end perspective view of an artificial core, according
to one
embodiment;
[0029] FIG. 7 is a top view of the artificial core of FIG. 6 in an
overlapping
configuration;
[0030] FIG. 8 is a top view of the artificial core of FIG. 6 in a spaced
configuration;
[0031] FIG. 9 is a perspective view of a core sleeve, according to one
embodiment;
[0032] FIG. 10 is a top view of the core sleeve of FIG. 9;
[0033] FIG. 11 is a perspective view of a distributor for use with a core
holder,
according to one embodiment;
[0034] FIG. 12 is an end view of the distributor of FIG. 11;
[0035] FIG. 13 is a graph showing an interpretation diagram of hue value
versus
volume percentage of yellow dye in a crude oil sample;
[0036] FIG. 14 is a method of saturating at least one core sample for
core
flooding testing, according to one embodiment;
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[0037] FIG. 15 is a method of saturating at least one core sample for
core
flooding testing, according to another embodiment;
[0038] FIG. 16 is a sample configuration for combining core samples
saturated
with oil treated with tracers, according to one embodiment;
[0039] FIG. 17 is a second sample configuration for combining core
samples
saturated with oil treated with tracers, according to an embodiment;
[0040] FIG. 18 is a third sample configuration for combining core samples
saturated with oil treated with tracers, according to an embodiment;
[0041] FIG. 19 is a fourth sample configuration for combining core
samples
saturated with oil treated with tracers, according to an embodiment;
[0042] FIG. 20 is a schematic diagram showing a simulation model for
studying
the imbibition contribution;
[0043] FIG. 21 is a graph comparing calculated and experimental oil
recoveries;
[0044] FIG. 22 is a graph showing oil rates of scenarios that consider
imbibition;
[0045] FIG. 23 is a graph showing oil rates of scenarios that do not
consider
imbibition; and
[0046] FIG. 24 is a graph showing oil rates for cores having differing
permeabilities.
Detailed Description
[0047] Various systems and methods will be described below to provide an
example of each claimed embodiment. No embodiment described below limits any
claimed embodiment and any claimed embodiment may cover apparatuses, systems
and methods that differ from those described below. The claimed embodiments
are not
limited to apparatuses, systems and methods having all of the features of any
one
apparatus, system and method described below or to features common to multiple
or all
of the apparatuses, systems and methods described below.
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[0048] Terms of degree such as "about" and "approximately" as used herein
mean
a reasonable amount of deviation of the modified term such that the end result
is not
significantly changed. These terms of degree should be construed as including
a
deviation of at least 5% or at least 10% of the modified term if this
deviation would not
negate the meaning of the word it modifies.
[0049] The term "comprising" and its derivatives, as used herein, are
intended to
be open ended terms that specify the presence of the stated features,
elements,
components, groups, integers, and/or steps, but do not exclude the presence of
other
unstated features, elements, components, groups, integers and/or steps. The
foregoing
also applies to words having similar meanings such as the terms, "including",
"having"
and their derivatives.
[0050] The term "consisting" and its derivatives, as used herein, are
intended to
be closed terms that specify the presence of the stated features, elements,
components, groups, integers, and/or steps, but exclude the presence of other
unstated
features, elements, components, groups, integers and/or steps.
[0051] The term "consisting essentially of", as used herein, is intended
to specify
the presence of the stated features, elements, components, groups, integers,
and/or
steps as well as those that do not materially affect the basic and novel
characteristic(s)
of features, elements, components, groups, integers, and/or steps.
[0052] The apparatuses, systems and methods described herein may provide
apparatuses, systems and methods for evaluating the contribution of imbibition
effects
on the oil production in heterogeneous tight oil reservoirs under high
temperature ¨ high
pressure (HTHP) conditions during waterflooding processes and may enhance the
understanding of waterflooding mechanisms in a heterogeneous oil reservoir.
[0053] In an attempt to mimic waterflooding process in heterogeneous
tight oil
reservoirs, the apparatuses, systems and methods described herein describe
conducting a waterflooding test where crude oil extraction from multiple (e.g.
at least
two) core samples is measured in parallel within a single core holder. This
parallel-core
flooding test can be used to study oil extraction from natural core samples
with varying
permeabilities where the natural core samples have been extracted from a
target tight
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formation oil well (e.g. from adjacent layers of the target tight formation
oil well). The
parallel-core flooding test can be used to study oil extraction from
artificial core samples
having similar physical properties (e.g. porosity, permeability, etc.) as the
target tight
formation oil well (e.g. as adjacent layers of the target tight formation oil
well).
[0054] To study the contributions of imbibition effects on oil extraction
during
waterflooding in core samples with varying permeabilities, the apparatuses,
systems
and methods described herein propose, in some embodiments, to use tracers such
as
dye tracers (e.g. red or green dyes) and/or oleic fluorescein tracers (e.g.
with different
color or different molecular structures) to trace crude oil extracted from
different core
samples (e.g. from different layers) during waterflooding. Core samples having
varying
permeabilities may be positioned within different layers of the core holder
during the
waterflooding test, each core sample saturated with a different tracer. For
instance,
tracers used during the waterflooding tests may vary in color or fluorescence
in order to
trace crude oil from different layers of the core holder. A quantity of crude
oil produced
(e.g. exiting the core holder) may be monitored (e.g. in real-time) during the
waterflooding process. Following this, producing mechanisms of different core
layers
can be evaluated based on crude oil production volume from different layers as
determined based on the presence of the tracers in the produced fluid.
Core Holder
[0055] Referring to Figures 1 to 3, illustrated therein are perspective,
top and
front views, respectively, of a body 102 of a core holder 100 for conducting
core flooding
tests, according to one embodiment. Body 102 has a first end 104 spaced apart
from a
second end 106 to define a volume 108 therebetween. Volume 108 is sized and
shaped
to hold a core sample 132 (see Figure 4) therein for use in core flooding
tests. Core
holder 100 has a first opening 110 at first end 104 and a second opening (not
shown) at
second end 106 to provide for insertion and/or removal of the at least one
core sample
132 into the volume 108, as described below. Core holder 100 optionally has
first and
second attachment mechanisms 116 and 118, respectively. Body 102 of core
holder
100 may be formed, for example, from stainless steel
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[0056] Figure 4 shows a partial cross-sectional view of the core holder
100 in an
assembled configuration, according to one embodiment. Core holder 100
comprises a
sleeve 126 housing one or more core samples 132. Distributors 130 are
positioned on
either side of the one or more core samples 132 to evenly distribute fluid
(e.g. water)
therethrough. Spacers 128 are positioned adjacent to the distributors 130 and
are
flanked by, end caps 124 and end plugs 120, respectively. Figure 5 shows an
exploded
side view of the core holder 100 of FIG. 4, according to one embodiment.
[0057] Core sample 132 is housed in sleeve 126. A distributor 130 is
positioned
on each end of core sample 132 within sleeve 126 to distribute water (or
another water-
based fluid) injected into the core sample 132 via tube 122 to conduct the
waterflooding
tests and to collect the fluid produced by the waterflooding tests. One or
more spacers
128 are also inserted into sleeve 126 to stabilize core sample 132 and
distributors 130
within sleeve 126. End caps 124 insert into each end of sleeve 126. Each end
cap 124
threadingly engages body 102 to support sleeve 126 within body 102. End plugs
120
then insert into and threadingly engage each end cap 124 to seal the core
holder 100.
Confining pressure ports 134 provide a pathway for injecting a fluid into a
space
between an inner surface 136 of body 102 and an outer surface 138 of sleeve
126 to
apply a pressure to the core sample 132 to mimic natural reservoir conditions.
Tube 122
extends from the external environment through the core holder 100 to the
distributor
130 to carry water (or another water-based fluid) to core sample 132. Once the
water or
water-based fluid passes through the core sample 132, a second tube (not
shown)
extends from another distributor 130a to the external environment through the
core
holder 100 to carry produced fluid from the distributor 130 to the external
environment.
[0058] As described further below, core holder 100 can be used with
either
natural core samples (e.g. samples collected from a target oil well) or
artificial core
samples (as described below) for conducting core flooding tests. In some
embodiments,
three core samples of varying permeabilities (i.e. mimicking different layers
of tight oil
reservoirs) can be disposed in distinct layers and inserted into sleeve 126 to
evaluate
imbibition effects of waterflooding on tight oil reservoirs.
Core Sample 132
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[0059] Referring to Figures 6 to 8, illustrated therein is a core
sample 132,
according to one embodiment. In some embodiments, core sample 132 may comprise
one or more core samples taken from one or more hydrocarbon bearing formations
(e.g.
a well bore) of a reservoir that is under investigation, or from an outcrop
rock having
similar physical and chemical characteristics to the formation rock of the
reservoir under
investigation. For example, natural core samples to be compared using the
systems,
methods and apparatuses described herein can be taken from adjacent layers of
a well
bore to assess whether differences in rock characteristics (e.g. permeability)
across the
reservoir have an impact on waterflooding.
[0060] Alternatively or additionally, core sample 132 may
comprise one or more
artificial core samples that mimic natural core samples from a tight oil
reservoir. For
instance, core sample 132 may comprise sandpacks, preferably formed from
produced
sand; packs of ion exchange resin particles (either cationic or anionic
exchange resins)
that are designed to mimic ion exchange between injection fluids (in
particular, injection
waters) and the rock surface at the reservoir scale; packs of hydrophilic or
hydrophobic
resin particles (that are designed to mimic hydrophilic or hydrophobic surface
of the
formation rock); synthetic rock (e.g. silica); zeolites; or ceramic materials.
Clays (for
example a kaolinite, smectite, pyrophyllite, illite, chorite or glauconite
type clay) may be
mixed with a sand prior to forming a sandpack. Clays may also be deposited
onto
sandpacks or onto synthetic rock samples. For example, cemented quartz may be
bound with calcite and clays may then be deposited onto the surface of the
synthetic
rock.
[0061] Core sample 132 may be arranged to have one or more
layers.
Hereinafter, core sample 132 may be referred to as having layers or as
comprising
individual core samples. For instance, as shown in Figures 6 to 8, core sample
132 may
comprise a first layer 602 and a second layer 604 that are sized and shaped to
fit within
sleeve 126 of core holder 100. Alternatively, first layer 602 and second layer
604 may
be referred to as separate core samples.
[0062] Core sample 132 may be sized (e.g. diameter, shape,
length, etc.) based
on the dimensions of core holder 100 and/or sleeve 126. For example, the cross
section
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of core sample 132 could be circular, square or rectangular, or any other
suitable
shape. In the examples shown in Figures 6 to 8, first layer 602 and second
layer 604
complement each other to provide core sample 132 with a cylindrical shape that
conforms to the interior of sleeve 126. Each layer of core sample 132 (e.g.
first layer
602 and second layer 604) may have a different permeability. Further, each
layer of
core sample 132 may have a different thickness. When using more than one
layers to
form core sample 132, the layers (e.g. first layer 602 and second layer 604)
will
generally have varying permeabilities to mimic the conditions of different
layers in a
target oil reservoir.
[0063] Referring now to Figures 7 and 8, illustrated therein is a
top view of the
core sample 132 of Figure 6. Figures 7 and 8 show that the layers 602, 604 of
core
sample 132 may be separable relative to each other when outside of the core
holder
100. It should be noted that those skilled in the art will understand that
core sample 132
may comprise more than two layers. For example, one or more additional layer
may be
sandwiched between the layers 602, 604 shown in Figures 7 and 8.
[0064] In some embodiments, core sample 132 is cylindrical in
shape and has a
length of about 3 inches to about 12 inches, or about 1 inch to about 3
inches, or about
1.5 inches, and a diameter of about 1.5 inches.
Sleeve
[0065] Referring to Figures 9 and 10, illustrated therein are
perspective and end
views, respectively, of a sleeve 126 according to an exemplary embodiment.
Sleeve
126 has a body 902 having a first end 904, a second end 906 and a volume 908
therebetween. First opening 910 and second opening 912 provide for body 902 to
receive at least one core sample 132 therein. When inserted into core holder
100,
sleeve 126 may form a fluid tight seal with the core holder 100. In one
embodiment,
sleeve 126 can be made out of rubber.
[0066] Typically, core sample 132 is inserted into sleeve 126
through one of
openings 910 and 912. Once the core holder 100 has been assembled and sealed,
a
pressurized fluid may be provided to the core holder 100 through the confining
pressure
port 134, as shown in Figure 4, such that the pressurized fluid can be passed
into the
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annulus and thereby exert an overburden pressure on the core sample within the
sleeve
126, for example.
[0067] Sleeve 126 holds the core sample 132, the distributers 130 and the
spacers 128 in place. Sleeve 126 also connects (e.g. slidingly couples to) end
caps 124
at first end 904 and second end 906 to stabilize core sample 132 therein.
Sleeve 132
also provides for applying a confinement pressure to the core sample 132 and,
after
applying the confinement pressure, sleeve 126 seals the core sample 132.
Distributor
[0068] Referring to Figures 11 and 12, illustrated therein are
perspective and end
views, respectively, of a distributor 130 according to an exemplary
embodiment.
[0069] Distributor 130 provides for distribution of the injection fluid
(e.g. water or a
water-based fluid) throughout the core sample 132 when the core sample 132 is
present
in sleeve 126, and for collection of the produced fluid from the core sample
132. One
distributor 130 is positioned within sleeve 126 at one end of core sample 132
to
distribute fluid entering core sample 132 across an area of the core sample
132. One
distributor 130 is positioned within sleeve 126 at the other end of core
sample 132 to
collect fluid produced from core sample 132 across an area of the core sample
132.
Oil Sample Treatment and Preparation of an Interpretation Diagram
[0070] To differentiate between crude oil produced from different layers
of core
sample 132 of the core holder 100, each crude oil saturated in each layer of
the core
sample 132 can be distinguished from each other crude oil saturated in each
other layer
of the core sample 132. In some embodiments, each crude oil saturated in each
layer of
the core sample 132 can be distinguished from each other crude oil saturated
in each
other layer of the core sample 132 by the presence or absence of a tracer. For
example,
each layer of core sample 132 in the core holder 100 can be saturated in a
fluorescein
(e.g. oleic fluoresceins) and/or dye that can be used as a tracer to
distinguish between
the crude oil produced from each of the layers of the core sample 132 and
present in
the product fluid from the core sample 132. Accordingly, the product fluid
from the core
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sample 132 can be referred to as a mixture of the crude oils saturated in the
layers of
the core sample 132 within the core holder 100.
[0071] It should be noted that although the embodiments and examples
herein
typically refer to the core holder 100 as holding a core sample 132 comprising
three
layers, two or more layers may be tested in parallel in core holder 100. It
should also be
noted that before the layers of the core sample 132 are saturated with a crude
oil
sample, each crude oil sample has already been dyed or fluorescein has already
been
added.
[0072] Hereinafter, when referring to the exemplary layers of core sample
132 of
core holder 100, the following references will be used to refer to each layer
of core
sample 132 being absorbed with crude oil saturated with the following tracers
(or a lack
of a tracer): core sample layer 0-1 will refer to a core sample layer
saturated with
unmarked crude oil (e.g. no tracer); core sample layer 0-2 will refer to a
core sample
layer absorbed with crude oil treated with a green oleic dye tracer; core
sample layer 0-
3 will refer to a core sample layer absorbed with crude oil treated with a red
oleic dye
tracer; core sample layer 0-4 will refer to a core sample layer absorbed with
crude oil
treated with a oleic fluorescein type A tracer; core sample layer 0-5 will
refer to a core
sample layer absorbed with crude oil sample treated with a oleic fluorescein
type B
tracer. In the above mentioned oleic fluorescein tracers, nile red
(C20H18N1202) or the like
can be used as the type A (e.g. red) fluorescein, and C201-11205 or the like
can be used
as the type B (e.g. yellow-greenish) fluorescein.
[0073] To analyze the fluid produced during the waterflooding test and to
determine a volume of crude oil produced from each layer of the core sample
132, the
resulting color of the produced crude oil (in the case of dyes being used as
tracers) or
the amount of fluorescence of the produced crude oil (in the case of
fluoresceins being
used as tracers), or different combinations of tracer-labeled crude oil
mixtures, can be
compared to interpretation diagrams (for example, the interpretation diagram
shown in
Figure 13) created prior to conducting the waterflooding experiments, where
the
interpretation diagrams are created from known quantities of crude oil in
various core
samples. The interpretation diagrams (see for example Figure 13) therefore
provide
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correlations between compositions of uniquely labeled crude oil samples and
the
resulting colors or fluorescence quantity.
[0074] The process for preparing the above mentioned
interpretation diagrams
can be described as follows: first, mix all labeled oil samples to be
saturated into layers
of a core sample for the waterflooding experiments in a series of test
samples, each test
sample in the series of test samples having a different volume composition
ratio of the
labelled oil samples. For example, each concentration of each oil sample may
vary
between 0% by volume and 100% by volume uniformly in the series of test
samples.
Then, an interpretation diagram can be constructed based on observed colors
and/or
fluorescence of each of the series of mixtures of with known concentrations.
An
example interpretation diagram is provided in Figure 13.
[0075] During an experiment, as oil is produced from core holder
100, the oil is
placed on filter paper to read its hue. Based on the hue reading of the mixed
oil
produced from core holder 100 and the interpretation diagrams generated for
each of
the tracers/fluoresceins in the core sample 132, the volume percentage of each
dye in
the produced oil can be determined.
[0076] In one embodiment, the core sample 132 can be three layers
of crude oil
samples, each oil sample labeled with a tracer to quantify the oil extracted
from each
layer. One or more analytical instruments (not shown) may be provided for
analysis of
effluent fluid flowing from core holder 100. Suitable analytical techniques
and
instruments for use with the core holder 100 are discussed in more detail
below. It is
envisaged that a sample of effluent fluid flowing from core holder 100 can be
directed to
the analytical instrument(s). Alternatively, the analytical instrument(s) may
comprise at
least one probe, sensor, or detector that is located on an effluent line
coupled to core
holder 100, thereby providing for direct analysis of the effluent fluid
flowing through the
effluent line. For example, in the case of infrared (IR) analysis, the
effluent flow may be
irradiated with IR radiation produced by an IR source and an IR detector may
be used to
detect infrared radiation that is transmitted through the flow (i.e. is not
absorbed by the
effluent flow). In this case, the analytical instrument may be a Fourier
Transform (FT) IR
analytic instrument that generates a transmittance or absorbance spectrum
showing the
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wavelengths at which the effluent fluid absorbs IR radiation. Other analytical
methods
for identifying oil mixing composition could include but are not limited to
color detection
methods, flu fluorescein detection, High-Performance Liquid Chromatography
(HPLC),
etc.
Methods to Saturate Core Samples
[0077] Referring to Figures 14 and 15, illustrated therein are two
methods 1400
and 1500, respectively, for saturating core samples for performing
waterflooding tests
as described herein.
[0078] In method 1400, at step 1402, a core sample (e.g. either natural
or
artificial core samples such as core sample 132) is inserted into a core
holder (e.g. core
holder 100) and saturated under reservoir conditions (e.g. conditions similar
to those
found in Bakken tight formations). For example, the reservoir temperature can
be in a
range of about 30 C to about 140 C and the initial reservoir pressure can be
in a range
of about 28000 kPa to about 34500 psi.
[0079] In some embodiments, a formation brine comprising one or more of
Na+,
K+, Ca2+, Mg2+, Cl-, HCO3-,SO4-,C032" or the like may be used to saturate the
core
sample 132 prior to saturation with an oil sample to mimic the reservoir
conditions of a
natural core sample. For instance, in some natural samples the total dissolved
solids in
reservoir can be approximately 100,000 mg/L.
[0080] In some examples, during the saturation process, the pressure can
be in a
range of about 300 kPa to about 400 kPa under a fluid injection rate of about
0.05
cc/min.
[0081] For example, the temperature of the core holder during saturation
is in a
range of about 30 C to about 140 C.
[0082] Saturation of the core samples with the formation brine can aid in
mimicking reservoir conditions before oil is extracted using the formation
water.
[0083] Before saturation of the core sample, various physical properties
of the
core sample may be measured. For example, the porosity of the core sample, the
permeability of the core sample, etc. can be measured. In some embodiments,
the
CA 3000261 2018-04-04
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permeability of tight rock can be smaller than 0.5 md and the porosity can be
in a range
of about 6% to about 16%.
[0084] At step 1404, labelled oil samples (e.g. selected based on
different core
sample requirements from oil samples 1, 2, 3, 4, 5) will be displaced (e.g.
injected) into
the core samples until the connate water saturation is reached. Parameters
such as the
initial oil saturation and initial water saturation may be recorded.
[0085] At step 1406, after the saturation process, the core sample is
removed
form the core holder and cut to a size to accommodate a core configuration
within the
core holder. Various configurations of core samples with the core holder are
described
below.
[0086] At step 1408, the saturated core sample is sealed into a sleeve
(e.g.
sleeve 126) for aging. In some embodiments, the saturated core samples are
aged for a
period of about 10 days to about 15 days.
[0087] Method 1400 may be repeated for different core samples having
varying
permeabilities for conducting core flooding tests as described herein.
[0088] Alternatively, in method 1500, at step 1502 a core sample (e.g.
either
natural or artificial core samples such as core samples 132) cut to a size to
accommodate a core configuration within the core holder. Various
configurations of core
samples with the core holder are described below.
[0089] At step 1504, the cut core sample is inserted into a sleeve (e.g.
a sleeve
having a same shape as the core sample to be saturated) and placed into the
core
holder.
[0090] At step 1506, the core samples are saturated with a formation
brine under
reservoir conditions. After saturation of the core sample, various physical
properties of
the core sample may be measured. For example, the porosity of the core sample,
the
permeability of the core sample, etc. can be measured. In some embodiments,
permeability of tight rock can be smaller than 0.5 md and the porosity can
range from
6% to 16%.
CA 3000261 2018-04-04
=
- 17 -
[0091] Again, for example, the pressure of the core holder during
saturation is in
a range from about 300 kPa to about 400 kPa under a fluid injection rate of
about 0.05
cc/min.
[0092] For example, the temperature of the core holder during
saturation is in a
range of about 30 C to about 140 C.
[0093] Saturation of the core samples with the formation brine may
provide for
mimicking an initial reservoir condition, the oil will be flooded the brine
saturated core to
generate the connate water saturation, as injected oil cannot displaced all
the water in
the core. The connate water plus the mobile oil in the core is similar to the
reservoir
condition when we develop the reservoir at the very beginning.
[0094] At step 1508, labeled oil samples (selected based on
different core
sample requirements from oil samples 1, 2, 3, 4, 5) are displaced into the
core samples
until the connate water saturation of the core samples is reached.
[0095] During step 1508, parameters of the core samples including
but not limited
to initial oil saturation and initial water saturation can be measured and
recorded.
[0096] At step 1510, the saturated core sample is sealed into a
sleeve (e.g.
sleeve 126) for aging. In some embodiments, the saturated core samples are
aged for a
period of about 10 days to about 15 days.
Core Design
[0097] Once the core samples have been saturated (as described
above),
waterflooding testing can be conducted on the core samples in parallel in a
single core
holder using the configurations provided below to evaluate imbibition effects.
For
example, as shown in Figures 16 to 19, three core samples having varying
permeabilities can be tested simultaneously in a single core holder 100.
[0098] In one embodiment, core flooding tests using core holder
100 can be
conducted on three sample cores representing three adjacent layers in a target
reservoir. As noted previously, core holder 100 can be used with natural cores
(e.g.
cores removed from an oil well) or artificial cores, as previously described.
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[0099] Referring to Figures 16 to 19, in one embodiment, three core
samples can
be tested based on the varying permeabilities of the core samples. For
example, in tests
measuring the effects of imbibition on three adjacent core samples in an oil
well, the
three core samples can be labeled as core sample #1 having an ultra-low
permeability
core, (e.g. a permeability of about 0.1 d), core sample #2 having a low
permeability core
(e.g. a permeability of about 1 d) and core sample #3 having an ultra-low
permeability
core (e.g. a permeability of about 0.1 d but lower permeability than core
sample #1).
[0100] Hereinafter, when using the references core sample #1, core sample
#2
and core sample #3, it should be understood that the permeabilities of the
core samples
#1, #2 and #3 relative to each other are as follows: permeability of core
sample #2 >
permeability of core sample #1 > permeability of core sample #3.
[0101] For all core configurations, it may be necessary to place particle
filter
paper (not shown) between adjacent core layers in the core holder 100.
Moreover, to
mimic natural reservoir conditions, the multi-layer core holder 100 may be
placed in an
oven to settle to increase the temperature of the core samples prior to
testing. A
confining pressure may also be added to the core samples prior to testing to
mimic
natural reservoir conditions. For examples, the temperature of the core
samples within
the multi-layer core holder 100 may be increased to be in a range between
about 30 C
and 140 C and the pressure of the core samples within the core holder can be
increased to be in a range from about 20000kPA to about 35000 kPa, or about
23500
kPa to about 32000 kPa, or about 23923 kPa to about 30473 kPa.
[0102] The following paragraphs describe various exemplary and non-
limiting
configurations of three core samples within a core holder 100. The differences
of the
exemplary configurations will be hereinafter explained.
[0103] The first exemplary core configuration (see Figure 16): place core
#1 on
top, core #2 in the middle and core #3 in the bottom of core holder 100. Under
this
configuration, there are two ways to select oil samples (the first oil sample
combination
is 0-2 and 0-3; the second oil sample combination is 0-4 and 0-5), and each
oil
sample combination can have two saturation methods. The first oil sample
combination
(0-2 and 0-3): core #1 is saturated with 0-3, core #2 is saturated with 0-1
and core # 3
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is saturated with 0-2; or core # 1 can be saturated with 0-2, core # 2 can be
saturated
with 0-1 and core #3 can be saturated with 0-3. The second oil sample
combination (0-
4 and 0-5): Core #1 is saturated with 0-4, Core #2 is saturated with 0-1 and
Core #3 is
saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2 can be
saturated
with 0-1 and Core #3 can be saturated with 0-47. The arrows shown in Figure 16
indicate the flow direction of injected water during waterflooding processes.
[0104] The second exemplary core configuration (see Figure 17): place
Core #3
on top, Core #2 in the middle and Core #1 in the bottom. Under this
configuration, there
are two ways to select oil samples (the first oil sample combination is 0-2
and 0-3; the
second oil sample combination is 0-4 and 0-5), and each oil sample combination
can
have two saturation methods. The first oil sample combination (0-2 and 0-3):
Core #1
is saturated with 0-3, Core #2 is saturated with 0-1 and Core #3 is saturated
with 0-2;
or Core #1 can be saturated with 0-2, Core #2 can be saturated with 0-1 and
Core #3
can be saturated with 0-3. The second oil sample combination (0-4 and 0-5):
Core #1
is saturated with 0-4, Core #2 is saturated with 0-1 and Core #3 is saturated
with 0-5;
or Core #1 can be saturated with 0-5, Core #2 can be saturated with 0-1 and
Core #3
can be saturated with 0-4. The arrows shown in Figure 17 indicate the flow
direction of
injected water during waterflooding processes.
[0105] The third exemplary core configuration (see Figure 18): place Core
#2 on
top, Core #1 in the middle and Core #3 in the bottom. Under this combining
method, oil
sample selection will be 0-4 and 0-5. This oil sample combination can have 2
saturation methods: Core #1 is saturated with 0-4, Core #2 is saturated with 0-
1 and
Core #3 is saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2
can be
saturated with 0-1 and Core #3 can be saturated with 0-4, as illustrated in
Figure 18.
The arrows shown in Figure 18 indicate the flow direction of injected water
during
waterflooding processes.
[0106] The fourth exemplary core configuration (see Figure 19): place
Core #3 on
top, Core #1 in the middle and Core #2 in the bottom. Under this combining
method, oil
sample selection will be 0-4 and 0-5. This oil sample combination can have two
saturation methods: Core #1 is saturated with 0-4, Core #2 is saturated with 0-
1 and
CA 3000261 2018-04-04
.,
- 20 -
Core #3 is saturated with 0-5; or Core #1 can be saturated with 0-5, Core #2
can be
saturated with 0-1 and Core #3 can be saturated with 0-4, as illustrated in
Figure 19.
The arrows shown in Figure 19 indicate the flow direction of injected water
during
waterflooding processes.
[0107] It should be noted that in the four exemplary core
configurations provided
above, core #2 (having the highest permeability) is saturated with 0-1 (no
tracer). To
evaluate the oil recovery contribution of imbibition effects, the low
permeability core is
typically impacted by high capillary pressures and stronger imbibition
effects. Therefore,
the oil saturated in relatively low permeability cores are shown as traced
(e.g. by dye of
fluorescein). Tracing the oil samples in the low permeability cores may
provide for more
accurate measurements when determining the contributions of the oil production
in low
permeability cores. However, if the oil samples labelled with tracer are
saturated into the
high permeability core samples, the methods described above will not change.
Evaluation of Production from Different Layers
[0108] By utilizing the first and second core configurations (as
referred to above),
studies may be performed to analyze the effects of distributions of different
permeable
layers on the imbibition effects during watering flooding processes in a tight
reservoir,
and waterflooding effects on production performances. Because different layers
may be
saturated with different treated oil samples, the colors of produced oil (for
0-2 and 0-3)
may change in relation to the volume of oil produced from different layers;
the similar
principle can be applied to analyze the layer's contribution during
waterflooding
processes based on fluorescence quantities in the produced liquid.
The Effect of Gravity
[0109] In the vertical direction, the effect of gravity on the
injected water may be
determined by analyzing the experimental results using the third and fourth
core
configurations (as referred to above). For the third core configuration, the
gravitational
effects provide a positive influence on the imbibition effects; on the other
hand,
gravitational effects would impose a negative influence on imbibition effects
if the fourth
core sample configuration is applied.
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Interactions between Different Layers
[0110] Because vertical heterogeneous differentiation is possible in
tight oil
reservoirs, the presence of interactions between different layers may be
significant
during waterflooding. The third and fourth core configurations may be utilized
to mimic
the normal/inverted rhythmic deposition in an oil reservoir. For reservoirs
formed by
different rhythmic deposition processes, imbibition effects would result in
interactions
between different layers. By measuring colors or fluorescence quantities of
produced
oil, interactions between different layers resulted from imbibition effects
may be
determined.
Core Flooding Experimental Procedures
[0111] After choosing the core configurations provided above, the aged
core
samples may be placed into multi-layer core holders accordingly. Following
this, the
oven temperature and confining pressure may be set based on actual pressure
and
temperature conditions within the target formation. Displacing fluids (e.g.
water or a
water-based fluid) are then injected into the core sample (e.g. core #2) with
higher
permeability.
Analysis on Experimental Data
Residual oil analysis
[0112] After waterflooding is complete, core samples can be removed from
the
multi-layer core holder 100. The distribution of residual oil in the core
samples can then
be analyzed using an analyzer (not shown), as described above (e.g. a CT
scanner).
The influences of water drive and imbibition effects on core samples with
different
permeability can be determined under different core configurations (as
described below)
based on the analysis with the analyzer (not shown).
[0113] By combining the experimental residual oil distribution results
with actual
field productions, predictions may be made on residual oil distributions based
on
different producing schemes, and thus may provide a theoretical background for
the
implementation of future producing measures.
Analysis on oil production contributed by imbibition effects in different
layers
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[0114] As core sample #2 has a higher permeability when compared to core
sample #1 and core sample #3, crude oil saturated in these three core samples
is
produced according to different displacement mechanisms. For example, crude
oil
produced from core sample #2 may be mainly influenced by water drive effects;
whereas crude oil produced from core samples #1 and #3 may be mainly
influenced by
imbibition effects.
[0115] The fluid produced during waterflooding processes collected from
core
holder 100 comprises crude oil from each of the core samples of core holder
100. The
produced fluid may be dewatered for analyzing the crude oil from each of the
core
samples. If the oil samples were treated with dye tracers, the colors of
produced oil
mixtures can be compared against the pre-determined interpretation diagrams to
determine the volumetric composition of each crude oil component (e.g. 0-1, 0-
2 and
0-3), and thus to analyze the relationship between volumes of produced oil
displacement by water drive and imbibition effects from different layers.
[0116] For experiments involving oil samples treated with fluoresceins,
the
fluorescence quantities for corresponding wavelength A and wavelength B can be
measured and compared against the pre-determined curves. Based on the
volumetric
composition of oil samples (e.g. 0-1, 0-2 and 0-3) within the produced oil
mixture, the
contributions of oil production from water drive and imbibition effects can be
interpreted.
[0117] For each core configuration, if the imbibition effects are
ignored, the
flowing equation exists for the relationship between oil productions from
layers with
different permeability and total oil production:
= x zickiAAi (1)
where: Q7: oil production from layer i (core #j);
Q: total oil production from specific core configuration;
ki: Effective permeability of oil sample saturated in layer i (core #j);
Ai: cross section area for layer i (core #j);
A: total cross section area for core #1 to #3.
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the number order of core layer in the multi-layer core holder, in which
max i equals to max];
j: the number order of core samples, which could be different from i.
[0118] However for actual production processes, due to the presence of
imbibition effects, the contribution from each layer can be expressed by:
Qi = Q x (2)
where: Qi: oil production from layer i;
Q: total oil production from the core configuration;
Ai: fraction of oil volume produced from layer i against total produced oil
volume, interpreted from the above mentioned diagrams/ curves for
different colors and fluorescence quantities for different wavelengths.
[0119] The oil produced by imbibition effects for each layer can be
expressed
below:
QimbQiQi (3)
Examples
1. Procedure
1.1 Core preparation
[0120] 1) Saturate a high permeability core (e.g. ¨10 mD) with red dye.
[0121] 2) Cut the core in three pieces. One piece is used for determining
relative
permeability test. One or two pieces are used for remounting into multi-layer
core
holder.
[0122] 3) Repeat the step from 1) to 2) for a low permeability core (1
mD). It is
worth noting that the low permeability core is saturated with a dye having
different color
(such as a green dye).
[0123] One representative diagram of an exemplary core configuration is
shown
in Figure 20. In this configuration, the middle layer (e.g. having a length of
20 cm, a
CA 3000261 2018-04-04
- 24 -
width of 5 cm and a thickness of 1 cm) is used as the high permeability core.
The over-
and under- burden layers are the same low permeability cores. The location of
the
injector and producer are shown in Figure 20. The constant pressure of the
well is set to
300 kPa and 100 kPa for the injector and producer respectively.
1.2 Determine relative permeability curves
[0124] Using the unsteady state waterflooding procedure to obtain the
production
data for determining the relative permeability curves. One exemplary
calculation method
can be found in Johnson, E. F., Bossler, D. P., & Bossler, V. 0. N. (1959,
January 1).
Calculation of Relative Permeability from Displacement Experiments. Society of
Petroleum Engineers.
1.3 Conduct Core Flooding Tests on Multi-layer Cores
[0125] After remount the cores with different permeability into the multi-
layer core
holder, conduct the waterflooding and record the production data. The
recording data
are production time, produced oil volume, water cut, pressure difference,
sample oil
color.
1.4 Treatment of Core Flooding Results
[0126] 1) For each time step (30 mins), the produced liquid is
centrifuged to
separate the oil and water.
[0127] 2) A brand new pipette was used to sample the produced oil at each
time
step and write the step number on a test paper.
[0128] 3) Take a picture of oil pots in test paper.
[0129] 4) Use a software to identify the mixed color in HSV (Hue,
Saturation,
Value) version.
[0130] 5) The hue of the mixed oil is used to calculate the color
composition (or
oil composition) based on the pre-established color plate.
[0131] 6) Based on the determined oil production from different
permeability
cores, calculate the average oil saturation of different cores by material
balance
equations.
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[0132] 7) Using the Eq. (1) above to calculate the oil production without
considering imbibition contribution.
[0133] 8) Using the Eq. (3) to estimate the imbibition contribution of
different
permeability cores.
Results and discussion
2.1 The role of imbibition in tight formations
[0134] Figure 21 shows the oil recovery over time. Oil recovery of the
experiment
is much higher than that calculation results before 1000 mins. After 1000
mins, the oil
recovery of experiment is slightly lower than that in the calculation. Figure
22 indicates
that the imbibition can significantly improve the oil recovery rate. However,
for the
improvement of final oil recovery, the imbibition does not play an important
role.
2.2 Imbibition contributions in different permeability cores
[0135] Based on the treatment mentioned in Section 1.4, above, the oil
rate from
different permeability cores can be identified as shown in Figure 24.
2.3 Validation of analysis method in the patent
[0136] In Eq. (1), three kinds of unknowns must be known to calculate the
oil rate
from different permeability cores. The three kinds of unknowns includes total
oil rate
(Q), effective permeability of oil-phase in different permeability regions
(Koi), cross
section areas of different permeability regions (Ai). It should be noted that
i in Koi and Ai
stands for a certain permeability core.
[0137] According to Sections 1.2 and 1.3, the average oil saturations and
relative
permeability curves of different permeability cores are obtained. The Q and Ai
can
obtained from production data and core size, respectively. By using Eq. (1),
the oil rate
without considering imbibition can be calculated. Figure 23 shows the
simulation and
calculation results of core flooding tests.
[0138] Based on Eq. (3), the oil rate difference between high and low
permeability core can be calculated. The results are shown in Figure 24. For
high
permeability region, the oil rate considering imbibition effects is always
higher than that
CA 30002612018-04-04
.,
- 26 -
without considering imbibition. It indicates that imbibition has a strong
positive impacts
on high permeability region. For low permeability region, the imbibition
effects become
more complex. The oil rate considering imbibition is initially higher and then
lowers
without considering imbibition.
[0139]
While the above description provides examples of one or more
apparatuses, methods, or systems, it will be appreciated that other apparatus,
methods,
or systems may be within the scope of the claims as interpreted by one of
skill in the art.
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