Note: Descriptions are shown in the official language in which they were submitted.
INTEGRATED SURVEILLANCE SYSTEM FOR CYCLIC SOLVENT DOMINATED
PROCESSES
Technical Field
[0001] The present disclosure relates generally to systems and
surveillance
methods of bitumen recovery operations, and more specifically, to systems and
surveillance methods of bitumen recovery operations of cyclic solvent
dominated
processes.
Background
[0002] In the oil and gas industry, flow assurance refers to a cost-
effective
approach of producing and transporting a hydrocarbon stream from a reservoir
(i.e. an
underground reservoir) to a processing facility.
[0003] To ensure that the hydrocarbon stream is transported to the
processing
facility in a cost-effective manner, techniques such as network modelling and
transient
multiphase simulation may be used to monitor and predict fluid properties that
might
negatively influence flow assurance, such as the formation of solid deposits
within the
pipeline (e.g. gas hydrates, asphaltene, wax, scale, and naphthalenes).
[0004] The application of solvent as a primary injectant in cyclic
solvent dominated
recovery processes introduces challenges for real-time operational
surveillance. For
instance, it can be difficult to monitor the composition and phases of a
hydrocarbon
stream produced from an underground reservoir in real-time at various
locations within a
bitumen recovery facility because the operating conditions throughout the
facility change
and affect phases of the hydrocarbon stream. Accordingly, it is important to
be able to
monitor the composition of the hydrocarbon stream and operating conditions
throughout
the facility to predict the phases of the hydrocarbon stream to mitigate flow
assurance
disruptions.
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Summary
[0005] The present disclosure provides systems and methods of recovering
bitumen from a reservoir.
[0006] The systems includes systems for monitoring a composition of a
produced
fluid recovered during a cyclic recovery process in a bitumen recovery
facility in real-time
to predict a phase profile of the produced fluid in real-time are disclosed
herein. The cyclic
recovery process includes cyclic injection of a solvent through a wellbore
into a reservoir
and recovery of the produced fluid. The produced fluid includes hydrocarbons
and water
and the hydrocarbons include the solvent and bitumen from the reservoir. The
system
includes at least one flow rate sensor positioned at a first position of the
facility between
a bottom hole of the wellbore and an end of a production stream to measure a
total flow
rate of the produced fluid at the first position; at least one density sensor
positioned at the
first position of the facility to measure a density of the produced fluid at
the first position;
at least one temperature sensor positioned at the first position of the
facility to measure
a temperature of the produced fluid at the first position; at least one
pressure sensor
positioned at the first position of the facility to measure a pressure of the
produced fluid
at the first position; and one or more processors operatively coupled to the
at least one
temperature sensor, the at least one pressure sensor, the at least one flow
rate sensor
and the at least one density sensor. The one or more processors, collectively,
are
configured to: determine a water-cut of the produced fluid in real-time at the
first position
based on the density of the produced fluid at the first position and an
estimate of a density
of the hydrocarbons of the produced fluid; determine a solvent content of the
hydrocarbons of the produced fluid in real-time at the first position based on
the water-
cut of the produced fluid at the first position, a correlation relating a true
density of the
hydrocarbons of the produced fluid to an ideal mixing density of the
hydrocarbons of the
produced fluid, and a correlation relating the true density of the
hydrocarbons of the
produced fluid to the bitumen density of the produced fluid; and predict a
phase profile of
the produced fluid in real-time at the first position based on the temperature
of the
produced fluid at the first position, the pressure of the produced fluid at
the first position
and the solvent content of the hydrocarbons in the produced fluid at the first
position.
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[0007] The first position may be at or near the wellhead.
[0008] The system may also include at least one temperature sensor
positioned at
a second position of the facility to measure a second temperature of the
produced fluid,
at least one pressure sensor positioned at the second position of the facility
to measure
a second pressure of the produced fluid and the one or more processors may be
further
configured to predict a phase profile of the produced fluid in real-time at
the second
position based on the second temperature of the produced fluid at the second
position,
the second pressure of the produced fluid at the second position and the
solvent content
of the hydrocarbons in the produced fluid at the first position when the
second position is
downstream from the wellhead.
[0009] The estimate of the density of the hydrocarbons of the
produced fluid may
be determined based on one or more or historical production data, cycle
progress, testing
of produced fluids and sample history.
[0010] The one or more processors may be further configured to,
when the phase
profile of the produced fluid includes a significant fraction of heavy-liquid,
add a flow
assurance solvent to the production stream to adjust the composition of the
produced
fluid to have a phase profile without heavy-liquid.
[0011] The one or more processors may be further configured to,
when the phase
profile of the produced fluid includes a heavy liquid, heat a portion of the
wellbore.
[0012] The one or more processors may be further configured to,
based on the
water-cut, temperature and pressure of the produced fluid at the first
position and a
hydrate prevention tool, indicate that a hydrate inhibitor is to be added to
the injected
solvent.
[0013] The hydrate inhibitor may be methanol.
[0014] The system may also include at least one temperature sensor
positioned at
a bottom hole of the wellbore to measure a bottom hole temperature; at least
one pressure
sensor positioned at the bottom hole of the wellbore to measure the bottom
hole pressure;
and at least one pressure sensor positioned at an observation well of the
facility to
measure a reference pressure; and the one or more processors may be further
configured
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s
to determine a pseudo-effective permeability of the reservoir based on the
bottom hole
temperature, the bottom hole pressure and the reference pressure.
[0015] The one or more processors may be further configured to
track the pseudo-
effective permeability of the reservoir over more than one cycle to detect
plugging.
[0016] The one or more processors may be further configured to,
when plugging is
detected near the wellbore, determine if a mitigation action should be
initiated.
[0017] The mitigation action may be adding a flow assurance
solvent to the
wellbore.
[0018] The mitigation action may be heating a portion of the
wellbore.
[0019] The mitigation action may be a stimulation injection of
flow assurance
solvent into the reservoir.
[0020] The system may also include a heater for heating at least a
portion of the
wellbore.
[0021] The one or more processors may be further configured to
measure an
asphaltene content of a plurality of samples of the produced fluid, each
sample taken
from the produced fluid at a different time during a production cycle;
determine a
cumulative asphaltene produced during the production cycle based on the
asphaltenes
content of the samples and a volume of bitumen produced during the production
cycle;
compare the cumulative asphaltene to a native asphaltene content of the
reservoir; and
determine an asphaltene deposition in the reservoir.
[0022] The asphaltene deposition in the reservoir may indicate a
net asphaltene
content deposited in the reservoir, and the one or more processors may be
further
configured to take the mitigating action of adding a flow assurance solvent to
the wellbore.
[0023] The asphaltene deposition in the reservoir may indicate a
net asphaltene
content deposited in the reservoir, and the one or more processors may be
further
configured to take the mitigating action of adding heating a portion of the
wellbore.
[0024] The asphaltene deposition in the reservoir may indicate a
net asphaltene
content deposited in the reservoir, and the one or more processors may be
further
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configured to take the mitigating action of adding a stimulation injection of
flow assurance
solvent into the reservoir.
[0025] The system may also include a display device operatively coupled
to the
one or more processors, and the one or more processors may be further
configured to
cause the display device to display a graphical representation of the phase
profile of the
produced fluid.
[0026] The methods include methods of monitoring a composition of a
produced
fluid recovered during a cyclic recovery process in a bitumen recovery
facility in real-time
to predict a phase profile of the produced fluid in real-time is also
described herein. The
cyclic recovery process includes cyclic injection of a solvent through a
wellbore into a
reservoir and recovery of the produced fluid. The produced fluid includes
hydrocarbons
and water, the hydrocarbons including the solvent and bitumen from the
reservoir. The
methods include measuring using at least one flow rate sensor positioned at a
first
position of the facility between a bottom hole of the wellbore and an end of a
production
stream a total flow rate of the produced fluid at the first position;
measuring using at least
one density sensor positioned at the first position of the facility a density
of the produced
fluid at the first position; measuring using at least one temperature sensor
positioned at
the first position of the facility a local temperature of the produced fluid;
measuring using
at least one pressure sensor positioned at the first position of the facility
a local pressure
of the produced fluid; determining a water content of the produced fluid in
real-time based
on the density of the produced fluid at the first position and an estimate of
a density of the
hydrocarbons of the produced fluid at the first position; determining a
solvent content of
the hydrocarbons of the produced fluid in real-time based on the water content
of the
produced fluid, a correlation relating a true density of the hydrocarbons of
the produced
fluid to an ideal mixing density of the hydrocarbons of the produced fluid,
and a correlation
relating the true density of the hydrocarbons of the produced fluid to the
bitumen density
of the produced fluid; and predicting a phase profile of the produced fluid in
real-time
based on the local temperature of the produced fluid, the local pressure of
the produced
fluid and the solvent content of the hydrocarbons in the produced fluid.
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[0027] These and other features and advantages of the present
application will
become apparent from the following detailed description taken together with
the
accompanying drawings. However, it should be understood that the detailed
description
and the specific examples, while indicating preferred embodiments of the
application, are
given by way of illustration only, since various changes and modifications
within the spirit
and scope of the application will become apparent to those skilled in the art
from this
detailed description.
Brief Description of the Drawings
[0028] For a better understanding of the various embodiments
described herein,
and to show more clearly how these various embodiments may be carried into
effect,
reference will be made, by way of example, to the accompanying drawings which
show
at least one example embodiment, and which are now described. The drawings are
not
intended to limit the scope of the teachings described herein.
[0029] Figure 1 is a schematic diagram exemplary of a solvent
dominated process
facility for recovering bitumen, according to one embodiment;
[0030] Figure 2 is a block diagram of a method of determining a
composition of a
produced fluid of the facility for recovering bitumen of FIG. 1, according to
one
embodiment;
[0031] Figure 3 is a graph showing the density calculated using an
"ideal mixing"
relation as a function of measured hydrocarbon density, according to one
embodiment;
[0032] Figure 4 is a graph showing a bitumen density correlation
as a function of
the measured hydrocarbon density, according to one embodiment;
[0033] Figure 5 is a graph showing a ternary phase diagram that is
utilized to
determine the phases present given the composition, temperature and pressure
at a point
in the recovery system, according to one embodiment;
[0034] Figure 6 is a graph showing a calculated effective
permeability tracked for
a single well cycle over cycle;
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,
,
[0035] Figure 7A is a graph showing the measured asphaltene
content of samples
taken over a single cycle;
[0036] Figure 7B is a graph showing cumulative produced
asphaltene, inferred
from the cumulative produced bitumen and the asphaltene distribution shown in
FIG. 7A;
and
[0037] Figure 8 is a hydrate inhibitor dosage tool used to
determine the hydrate
inhibitor dosage required to mitigate hydrate formation in the production
stream based on
the composition, temperature and pressure, according to one embodiment.
[0038] The skilled person in the art will understand that the
drawings, further
described below, are for illustration purposes only. The drawings are not
intended to limit
the scope of the applicant's teachings in any way. Also, it will be
appreciated that for
simplicity and clarity of illustration, elements shown in the figures have not
necessarily
been drawn to scale. For example, the dimensions of some of the elements may
be
exaggerated relative to other elements for clarity. Further aspects and
features of the
example embodiments described herein will appear from the following
description taken
together with the accompanying drawings.
Detailed Description
[0039] To promote an understanding of the principles of the
disclosure, reference
will now be made to the features illustrated in the drawings and no limitation
of the scope
of the disclosure is hereby intended. Any alterations and further
modifications, and any
further applications of the principles of the disclosure as described herein
are
contemplated as would normally occur to one skilled in the art to which the
disclosure
relates. For the sake of clarity, some features not relevant to the present
disclosure may
not be shown in the drawings.
[0040] At the outset, for ease of reference, certain terms used
in this application
and their meanings as used in this context are set forth. To the extent a term
used herein
is not defined below, it should be given the broadest definition persons in
the pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below,
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CA 3037410 2019-03-20
,
,
as all equivalents, synonyms, new developments, and terms or techniques that
serve the
same or a similar purpose are considered to be within the scope of the present
claims.
[0041] As one of ordinary skill would appreciate, different
persons may refer to the
same feature or component by different names. This document does not intend to
distinguish between components or features that differ in name only. In the
following
description and in the claims, the terms "including" and "comprising" are used
in an open-
ended fashion, and thus, should be interpreted to mean "including, but not
limited to."
[0042] A "hydrocarbon" is an organic compound that primarily
includes the
elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or
any
number of other elements may be present in small amounts. Hydrocarbons
generally
refer to components found in heavy oil or in oil sands. Hydrocarbon compounds
may be
aliphatic or aromatic, and may be straight chained, branched, or partially or
fully cyclic.
[0043] A "light hydrocarbon" is a hydrocarbon having carbon
numbers in a range
from 1 to 9.
[0044] "Bitumen" is a naturally occurring heavy oil material.
Generally, it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
upon the degree of loss of more volatile components. It can vary from a very
viscous,
tar-like, semi-solid material to solid forms. The hydrocarbon types found in
bitumen can
include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen
might be
composed of:
- 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % to
30 wt. %
or higher);
- 19 wt. % asphaltenes (which can range from 5 wt. % to 30 wt. '3/0 or
higher);
- 30 wt. A aromatics (which can range from 15 wt. % to 50 wt. % or
higher);
- 32 wt. % resins (which can range from 15 wt. % to 50 wt. % or higher);
and
- some amount of sulfur (which can range in excess of 7 wt. %), based on
the total
bitumen weight.
[0045] In addition, bitumen can contain some water and nitrogen
compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of
the
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,
,
hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen
as well as
lighter materials that may be found in a sand or carbonate reservoir.
[0046] "Heavy oil" includes oils which are classified by the
American Petroleum
Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term
"heavy oil" includes
bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or
more, 10,000
cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy
oil has an
API gravity between 22.3 API (density of 920 kilograms per meter cubed
(kg/m3) or 0.920
grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1
g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 API
(density greater
than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil
sand or
bituminous sand, which is a combination of clay, sand, water and bitumen.
[0047] The term "viscous oil" as used herein means a hydrocarbon,
or mixture of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
at initial
reservoir conditions. Viscous oil includes oils generally defined as "heavy
oil" or
"bitumen." Bitumen is classified as an extra heavy oil, with an API gravity of
about 10 or
less, referring to its gravity as measured in degrees on the API Scale. Heavy
oil has an
API gravity in the range of about 22.3 to about 10 . The terms viscous oil,
heavy oil, and
bitumen are used interchangeably herein since they may be extracted using
similar
processes.
[0048] In-situ is a Latin phrase for "in the place" and, in the
context of hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example,
in-situ temperature means the temperature within the reservoir. In another
usage, an in-
situ oil recovery technique is one that recovers oil from a reservoir within
the earth.
[0049] The term "subterranean formation" refers to the material
existing below the
Earth's surface. The subterranean formation may comprise a range of
components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well
as the oil
and/or gas that is extracted. The subterranean formation may be a subterranean
body of
rock that is distinct and continuous. The terms "reservoir" and "formation"
may be used
interchangeably.
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CA 3037410 2019-03-20
. .
[0050] The term "wellbore" as used herein means a hole in the
subsurface made
by drilling or inserting a conduit into the subsurface. A wellbore may have a
substantially
circular cross section or any other cross-sectional shape. The term "well,"
when referring
to an opening in the formation, may be used interchangeably with the term
"wellbore."
[0051] The term "cyclic process" refers to an oil recovery technique
in which the
injection of a viscosity reducing agent into a wellbore to stimulate
displacement of the oil
alternates with oil production from the same wellbore and the injection-
production process
is repeated at least once. Cyclic processes for heavy oil recovery may include
a cyclic
steam stimulation (CSS) process, a liquid addition to steam for enhancing
recovery
(LASER) process, a cyclic solvent process (CSP), or any combination thereof.
[0052] A "fluid" includes a gas or a liquid and may include, for
example, a produced
or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold
water, or a mixture
of these among other materials.
[0053] "Facility" or "surface facility" is one or more tangible pieces
of physical
equipment through which hydrocarbon fluids are either produced from a
subterranean
reservoir or injected into a subterranean reservoir, or equipment that can be
used to
control production or completion operations. In its broadest sense, the term
facility is
applied to any equipment that may be present along the flow path between a
subterranean reservoir and its delivery outlets. Facilities may comprise
production wells,
injection wells, well tubulars, wellbore head equipment, gathering lines,
manifolds,
pumps, compressors, separators, surface flow lines, steam generation plants,
processing
plants, and delivery outlets. In some instances, the term "surface facility"
is used to
distinguish from those facilities other than wells.
[0054] "Pressure" is the force exerted per unit area by the gas on the
walls of the
volume. Pressure may be shown in this disclosure as pounds per square inch
(psi),
kilopascals (kPa) or megapascals (MPa). Atmospheric pressure" refers to the
local
pressure of the air.
[0055] A "subterranean reservoir" is a subsurface rock or sand
reservoir from
which a production fluid, or resource, can be harvested. A subterranean
reservoir may
interchangeably be referred to as a subterranean formation. The subterranean
formation
CA 3037410 2019-03-20
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,
,
may include sand, granite, silica, carbonates, clays, and organic matter, such
as bitumen,
heavy oil (e.g., bitumen), oil, gas, or coal, among others. Subterranean
reservoirs can
vary in thickness from less than one foot (0.3048 meters (m)) to hundreds of
feet
(hundreds of meters). The resource is generally a hydrocarbon, such as a heavy
oil
impregnated into a sand bed.
[0056] The term "asphaltenes" or "asphaltene content" refers to
pentane insolubles
(or the amount of pentane insoluble in a sample) according to ASTM D3279.
Other
examples of standard ASTM asphaltene tests include ASTM test numbers D4055,
D6560,
and D7061.
[0057] As used herein, "phase profile" should be understood to
mean the states of
matter of different components of a fluid (for instance including liquid and
gaseous states,
or mixtures thereof) present at different operating conditions within a field
operation.
[0058] As used herein, the term "light liquid" refers to one of
two liquid phases
formed in a solvent and bitumen system under specific composition, temperature
and
pressure conditions. The first liquid phase is termed a "light liquid" phase
because it is
characterized by lower asphaltene content, lower density and lower viscosity
when
compared to the other liquid phase of the solvent and bitumen system.
[0059] As used herein, the term "heavy liquid" refers to a second
of two liquid
phases formed in a solvent and bitumen system under specific composition,
temperature
and pressure conditions. The second liquid phase is termed a "heavy liquid"
phase
because it is characterized by higher asphaltene content, higher density and
higher
viscosity when compared to the other liquid phase of the solvent and bitumen
system.
[0060] The articles "the," "a" and "an" are not necessarily
limited to mean only one,
but rather are inclusive and open ended to include, optionally, multiple such
elements.
[0061] As used herein, the terms "approximately," "about,"
"substantially," and
similar terms are intended to have a broad meaning in harmony with the common
and
accepted usage by those of ordinary skill in the art to which the subject
matter of this
disclosure pertains. It should be understood by those of skill in the art who
review this
disclosure that these terms are intended to allow a description of certain
features
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CA 3037410 2019-03-20
, .
,
,
described and claimed without restricting the scope of these features to the
precise
numeral ranges provided. Accordingly, these terms should be interpreted as
indicating
that insubstantial or inconsequential modifications or alterations of the
subject matter
described and are considered to be within the scope of the disclosure.
[0062] "At least one," in reference to a list of one or more
entities should be
understood to mean at least one entity selected from any one or more of the
entity in the
list of entities, but not necessarily including at least one of each and every
entity
specifically listed within the list of entities and not excluding any
combinations of entities
in the list of entities. This definition also allows that entities may
optionally be present
other than the entities specifically identified within the list of entities to
which the phrase
"at least one" refers, whether related or unrelated to those entities
specifically identified.
Thus, as a non-limiting example, "at least one of A and B" (or, equivalently,
"at least one
of A or B," or, equivalently "at least one of A and/or B") may refer, to at
least one, optionally
including more than one, A, with no B present (and optionally including
entities other than
B); to at least one, optionally including more than one, B, with no A present
(and optionally
including entities other than A); to at least one, optionally including more
than one, A, and
at least one, optionally including more than one, B (and optionally including
other entities).
In other words, the phrases "at least one," "one or more," and "and/or" are
open-ended
expressions that are both conjunctive and disjunctive in operation. For
example, each of
the expressions "at least one of A, B and C," "at least one of A, B, or C,"
"one or more of
A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A
alone, B alone,
C alone, A and B together, A and C together, B and C together, A, B and C
together, and
optionally any of the above in combination with at least one other entity.
[0063] Where two or more ranges are used, such as but not limited
to 1 to 5 or 2
to 4, any number between or inclusive of these ranges is implied.
[0064] As used herein, the phrases "for example," "as an example,"
and/or simply
the terms "example" or "exemplary," when used with reference to one or more
components, features, details, structures, methods and/or figures according to
the
present disclosure, are intended to convey that the described component,
feature, detail,
structure, method and/or figure is an illustrative, non-exclusive example of
components,
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features, details, structures, methods and/or figures according to the present
disclosure.
Thus, the described component, feature, detail, structure, method and/or
figure is not
intended to be limiting, required, or exclusive/exhaustive; and other
components,
features, details, structures, methods and/or figures, including structurally
and/or
functionally similar and/or equivalent components, features, details,
structures, methods
and/or figures, are also within the scope of the present disclosure. Any
embodiment or
aspect described herein as "exemplary" is not to be construed as preferred or
advantageous over other embodiments.
[0065] In spite of the technologies that have been developed, there
remains a need
in the field for surveillance methods for bitumen recovery of solvent
dominated process
facilities.
[0066] Herein, a surveillance system that couples real-time field
measurements
and technical analysis to provide operational guidance is provided.
[0067] Referring now to Figure 1, illustrated therein is a schematic
diagram of a
layout of a facility 100 for a solvent dominated cyclic process for recovering
bitumen from
an underground reservoir 110, according to one embodiment. Herein, the
underground
reservoir 110 includes an injector/producer well 102 and a neighboring
observation well
104. Facility 100 includes a collection of surface units 106 and a production
pipeline 108.
[0068] Injector/producer well 102 is used to perform cyclic solvent
injection and
production operations to recover bitumen from underground reservoir 110. In
the
embodiment shown in Figure 1, during injection cycles, solvent stored in the
surface
facilities 106 (e.g. solvent storage unit 112) is injected through a wellhead
114 and into
the underground reservoir 110 via wellbore 102. Flow assurance solvent stored
in the
surface facilities (e.g. flow assurance solvent storage 116) may also be
injected with the
solvent into the underground reservoir 110.
[0069] In the aforementioned solvent dominated cyclic processes,
solvents may be
used to enhance the extraction of petroleum products from the reservoir 110.
In some
embodiments, the solvent used in the solvent dominated cyclic processes may be
a light
hydrocarbon, a mixture of light hydrocarbons or dimethyl ether. In other
embodiments,
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the solvent may be a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-
heptane, or a
gas plant condensate comprising alkanes, naphthenes, and aromatics.
[0070] In other embodiments, the solvent may be a light, but condensable,
hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or
pentane.
The solvent may comprise at least one of ethane, propane, butane, pentane, and
carbon
dioxide. The solvent may comprise greater than 50% C2-05 hydrocarbons on a
mass
basis. The solvent may be greater than 50 mass% propane, optionally with
diluent when
it is desirable to adjust the properties of the injectant to improve
performance.
[0071] Additional injectants may include CO2, natural gas, C5+
hydrocarbons,
ketones, and alcohols. Non-solvent injectants that are co-injected with the
solvent may
include steam, non-condensable gas, or hydrate inhibitors. The solvent
composition may
comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent,
C5+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable
solid
particles, salt, water soluble solid particles, and solvent soluble solid
particles.
[0072] To reach a desired injection pressure of the solvent composition,
a
viscosifier may be used in conjunction with the solvent. The viscosifier may
be useful in
adjusting solvent viscosity to reach desired injection pressures at available
pump rates.
The viscosifier may include diesel, viscous oil, bitumen, and/or diluent. The
viscosifier
may be in the liquid, gas, or solid phase. The viscosifier may be soluble in
either one of
the components of the injected solvent and water. The viscosifier may
transition to the
liquid phase in the reservoir before or during production. In the liquid
phase, the
viscosifiers are less likely to increase the viscosity of the produced fluids
and/or decrease
the effective permeability of the formation to the produced fluids.
[0073] The solvent composition may comprise (i) a polar component, the
polar
component being a compound comprising a non-terminal carbonyl group; and (ii)
a non-
polar component, the non-polar component being a substantially aliphatic
substantially
non-halogenated alkane. The solvent composition may have a Hansen hydrogen
bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent composition may
have a
volume ratio of the polar component to non-polar component of 10:90 to 50:50
(or 10:90
to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar
component may
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be, for instance, a ketone or acetone. The non-polar component may be, for
instance, a
C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant
condensate
comprising alkanes, naphthenes, and aromatics. For further details and
explanation of
the Hansen Solubility Parameter System see, for example, Hansen, C. M. and
Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl. Vol. 2nd
Ed),
1971, pp 889-910 and "Hansen Solubility Parameters A User's Handbook" by
Charles
Hansen, CRC Press, 1999.
[0074]
The solvent composition may comprise (i) an ether with 2 to 8 carbon
atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may
have 2 to
8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl
ether, methyl
iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether,
methyl iso-butyl
ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-
propyl butyl ether,
propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-
methyl ether. The
non-polar hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a
C2-
05 alkane. The non-polar hydrocarbon may be propane. The ether may be di-
methyl
ether and the hydrocarbon may be propane. The volume ratio of ether to non-
polar
hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.
[0075]
The solvent composition may comprise at least 5 mol '')/0 of a high-aromatics
component (based upon total moles of the solvent composition) comprising at
least 60
wt. % aromatics (based upon total mass of the high-aromatics component). One
suitable
and inexpensive high-aromatics component is gas oil from a catalytic cracker
of a
hydrocarbon refining process, also known as a light catalytic gas oil (LCGO).
[0076]
In the embodiment shown in Figure 1, during production cycles, a produced
fluid is recovered from the underground reservoir 110 via wellbore 102 and
wellhead 114.
The produced fluid generally includes hydrocarbons and water, where the
hydrocarbons
include at least a portion of the injected solvent and bitumen from the
underground
reservoir 110. The one or more units may include but are not limited to
heaters, test
separator(s), and the like.
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. ,
[0077] Injector/producer wellbore 102 may include one or more flow
rate sensor,
density sensor, temperature sensor and pressure sensor positioned slightly
downstream
of the wellhead 114.
[0078] Neighboring observation wellbore 104 is a wellbore that can be
used to
observe changes in temperature, pressure of the reservoir 110 over a period.
Injector/producer well wellbore 104 may include one or more flow rate sensor,
density
sensor, temperature sensor and pressure sensor positioned between the
underground
reservoir 110 and the wellhead 114.
[0079] Surface facilities 106 generally refers to the collection of
one or more units
and associated pipeline on the surface that are used to process one or more of
the
solvent, flow assurance solvent or the like before injection into the
underground reservoir
110 and to process the produced fluid from the underground reservoir. Surface
facilitates
106 are generally positioned on pad and may include one or more flow rate
sensor,
density sensor, temperature sensor and pressure sensor positioned between the
wellhead 114 and the production pipeline 108. For instance, in the embodiment
shown in
Figure 1, surface facilities 106 may further include one or more storage units
119, pumps
122 and/or one or more heaters 124 for processing fluids prior to injection
into the
wellbore 102. Facility 100 may also include an observational wellbore 104 and
associated
observational wellhead 118.
[0080] Production pipeline 108 generally refers to a collection of
one or more units
and associated pipeline that carry produced fluids from the pad to a central
processing
facility where solvent, bitumen and water are separated from the produced
fluid.
Production pipeline 108 generally includes one or more pressure and
temperature
sensors distributed along its length.
[0081] Each of the one or more flow rate sensor, density sensor,
temperature
sensor and pressure sensor of the wellbore 102, observational wellbore 104 and
system
facilities 106, as well as the one or more pressure and temperature sensors
distributed
along the length of the production pipeline 108 is operatively coupled to one
or more
processors such that data (e.g. measurements) collected by the sensors is
transmitted to
the one or more processors for analysis. The one or more processors is
configured to
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. ,
perform calculations that estimate the fluid composition using a density based
approach
yielding estimates of the solvent, bitumen and water volume in the produced
stream. The
one or more processors then use composition, pressure and temperature
measurements
to determine the phases present in the produced stream. If the phases present
in the
produced stream may lead to flow assurance issues, then the one or more
processors
may trigger one or more mitigation actions.
[0082] As noted above, the composition of the hydrocarbons in the
produced fluid
and the operating conditions within the facility 100 can be used to determine
phases (i.e.
a physically distinctive form of a substance, such as the solid, liquid, and
gaseous states
of ordinary matter) present in the produced fluid. For instance, under certain
operating
conditions for a given solvent upon injection into the underground reservoir
110, the
physical properties of the hydrocarbons in the produced fluid can change
and/or
additional hydrocarbon phases in the produced fluid may be present. Such
changes can
lead to flow assurance issues within the reservoir 110, wellbore 102, units
within the
surface facilities 106 and/or the production pipeline 108.
[0083] Turning now to Figure 2, illustrated therein is a block diagram
of a method
200 of determining a composition of the produced fluid including hydrocarbons
and water.
At steps 202, 204, 206 and 208, measurements of the total flow rate of the
produced fluid,
density (p) of the produced fluid, temperature of the produced fluid and
pressure of the
produced fluid are recorded at a first position of the facility 100 in real-
time using one or
more of the flow rate, density, temperature and pressure sensors of wellbore
102, the
wellhead 114, and/or the surface facilities 106, respectively. In some
embodiments, the
first position of the facility 100 is a position at the wellhead 114 of the
facility 100 or
between the wellhead 114 and the production pipeline 108.
[0084] In a cyclic solvent process, the density of the hydrocarbons in
the produced
fluid (and the density of the bitumen) change over a production cycle as the
solvent
concentration in the produced fluid decreases. Therefore, to determine the
composition
of the produced fluid in real-time, initial estimates of the hydrocarbon
density and the
bitumen density of the produced fluid at a first position are necessary as
well as a
correlation relating a true density of the hydrocarbons of the produced fluid
to the
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hydrocarbon density that would be computed using "ideal mixing". Sources for
these
estimates are described below.
[0085] First, at step 210, to determine a composition of the produced
fluid at a first
position of the facility 100, a density-based calculation is applied to
determine the water-
cut of the produced fluid at the first position. The density-based calculation
is shown below
as Equation (1):
PWH = PHC (Pwater PHC)(Pwater (1)
where pWH is the density of the produced fluid at the first position (e.g.
wellhead 114), pHC
is the density of the hydrocarbons of the produced fluid, Pwater is the
density of water and
(pwater is the volume fraction of water.
[0086] In Equation (1), pHc is an estimate of the density of the
hydrocarbons of the
produced fluid and can be determined based on one or more of historical
production data,
cycle progress, testing of produced fluids and sample history.
[0087] At step 212, a subsequent calculation is performed to determine
the solvent
content of the total hydrocarbons in the produced fluid. The second
calculation is shown
below as Equation (2):
PHC ideal mix = PBit (PSolv PBit)(PSolv (2)
where pHC_ideal_mix is the density of the hydrocarbons of the produced fluid
at the first
position under ideal mixing conditions, psoiv is the density of the solvent of
the produced
fluid at the first position, pBit is the density of the bitumen of the
produced fluid at the first
position, and cpsolv is the volume fraction of the of the solvent at the
temperature and
pressure conditions of the first position.
[0088] Turning now to Figure 3, illustrated therein is one example of a
graph
showing a relation of measured (i.e. true) hydrocarbon density to a
hydrocarbon density
calculated using an "ideal mixing" assumption. Ideal mixing implies there is
no total
volume change of the mixed fluid relative to the summation of the individual
component
volumes. The correlation shown in Figure 3 was developed using the results of
sample
analysis program from a solvent dominated process. The composition of each
sample
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. .
was determined experimentally and the true density of the hydrocarbons of the
produced
fluid was measured in a laboratory under pressurized conditions. The true
density of the
hydrocarbons of the produced fluid can then be related the density calculated
using the
"ideal mixing" assumption and the measured composition of the hydrocarbons.
[0089] Figure 4 shows an example of a bitumen density correlation. In
the
embodiment shown therein, the results of a sample analysis program from a
solvent
dominated process were used to determine a relationship between the density of
hydrocarbons of a produced fluid and the density of bitumen of the produced
fluid. In the
embodiment shown in Figure 4, the bitumen density of samples of the produced
fluid were
measured in the laboratory at flashed conditions (e.g. atmospheric pressure).
[0090] Figure 5 shows an example of a phase behaviour tool 500. The
tool 500
can be applied to determine the phase(s) of the hydrocarbons present in the
produced
fluid at different operating conditions within a field operation. The diamonds
shown in the
tool 500 represent example operating conditions throughout a facility.
[0091] The phase behaviour tool 500 a solvent-bitumen system shown in
Figure 5
is shown at a single pressure condition and for a single solvent (e.g.
propane), however,
it should be noted that the tool 500 can be used to determine the phase(s) of
the
hydrocarbons present in the produced fluid over a range of operating
conditions expected
within the facility 100 (e.g. within the reservoir 110, wellbore 102, surface
facilities 106
and the production pipeline 108).
[0092] The dashed-lines 502, 504 in Figure 5 represent a boundary
between the
single liquid hydrocarbon (L) and the two-phase hydrocarbon regime at two
different
temperatures, as indicated. For instance, dashed-line 502 represents a
boundary
between the single liquid hydrocarbon (L) and the two-phase hydrocarbon regime
at 30
C and 1800 kPa and dashed-line 504 represents a boundary between the single
liquid
hydrocarbon (L) and the two-phase hydrocarbon regime at 4 C and 1300 kPa. The
first
light liquid (LL) phase and a second heavy liquid (HL) phase co-exist in the
two-phase
regime, as indicated. There is no region between L and LL+HL. The LL+HL region
can
be two different sizes depending on the temperature and pressure condition.
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[0093] The phase regimes and viscosity shown in Figure 5 were determined
from
experimental phase behavior testing in field operating conditions. The plotted
points
represent real-time compositions determined from field measurements at
locations within
the facility 100, such as within the wellbore 102, within the surface
facilities 106 or along
the production pipeline 108. Points that fall within the two-phase region (HL
+ LL) are
within favorable conditions for HL phase formation. The HL physical properties
are
generally significantly different from the L and LL and pose a risk for
facility plugging or
flow restriction.
[0094] In some embodiments such as but not limited to the facility 100
shown in
Figure 1, the HL phase of the produced fluid can be mitigated by increasing a
relative
amount of flow assurance solvent and/or increasing the operating temperature
of the
facility 100. In view of Figure 5, each of these changes can shift the
composition of the
hydrocarbons of the produced fluid to the L region, which is more favourable
for flow
assurance.
[0095] Within the L region, the composition of the hydrocarbons in the
produced
fluid can be further controlled to improve performance (e.g. flow assurance)
of the facility
100. For example, by increasing the solvent and/or flow assurance solvent
content of the
produced fluid, the viscosity of the hydrocarbons in the produced fluid would
be
decreased thereby lowering a required pressure differential require to
transport the fluid.
[0096] In one specific example, the hydrocarbon composition of the
produced fluid
in a near wellbore region of the facility 100 in solvent dominated processes
can be
favourable for HL formation since the solvent concentration is high at certain
times of the
cyclic process. In this example, when the HL phase of the produced fluid
forms, the
asphaltenes can be deposited in pore spaces of the wellbore 102 and
subsequently build-
up over time. Near wellbore stimulation with flow assurance solvent can be one
method
to mitigate the near-wellbore plugging.
[0097] In this case the near well region can be favourable to HL
formation because
injected solvent concentration will be high, and bitumen concentration can be
low in later
cycles. Also, HL formed at regions away from the wellbore will tend to migrate
and
accumulate in time in the near wellbore region.
CA 3037410 2019-03-20
. .
[0098] Furthermore, in low temperature solvent dominated processes
(i.e.
processes where solvent is injected in liquid form rather than vapour form,
generally
around about 80 C or less), heating within the wellbore can passively heat the
near
wellbore region over time. The effect of this near wellbore heating can be to
lower the
viscosity of the HL or transition the phase regime to a LL region.
[0099] In another example, in a cyclic process where the flow rate of
the produced
fluid declines over a production cycle, it may be difficult to identify when
the HL formation
is inhibiting the hydrocarbon production rate. Herein, two methods are
described for
identifying HL build-up in the near wellbore region: (a) real-time tracking of
a pseudo-
effective permeability; and (b) asphaltene deposition within a reservoir.
[0100] With respect to real-time tracking of a pseudo-effective
permeability, a
pseudo-effective permeability (keff) of the reservoir 100 can be calculated
using field
measurements and applying rearranged form of Darcy's Law (Equation 3):
keff = i--LapQ 711" (3)
[0101] The real-time composition of the produced fluid, a measured
bottom-hole
(BH) pressure (e.g. by a pressure sensor positioned at a bottom of the
wellbore 102) and
a measured BH temperature (e.g. by a temperature sensor positioned at a bottom
of the
wellbore 102) are inputs to calculate an in-situ hydrocarbon viscosity (p)
using a viscosity
model calibrated for the facility 100.
[0102] A pressure difference from the production well measured at the
bottom-hole
to a reference pressure measurement, such as a pressure of the observation
well 104,
can be used as a proxy for the in situ pressure drop (AP). The difference
between these
two pressures is caused by pressure losses that occur while fluid is moving
through the
porous reservoir (and the wellbore). With the measured rate of production of
the produced
fluid (e.g. and the hydrocarbons), the pseudo-effective permeability can be
calculated and
tracked cycle-over-cycle, as shown in the graph provided in Figure 6. As
shown, cycle 2
and cycle 3 show similar behavior to each other whereas cycle 4 shows
different behavior
(e.g. lower pseudo effective permeability at the same level of cycle progress,
where cycle
progress is measured as hydrocarbon recovery relative to the hydrocarbons
injected per
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CA 3037410 2019-03-20
. .
,
cycle). An earlier reduction of the pseudo-effective permeability is an
indicator that a
mitigation action should be initiated.
[0103] Mitigation actions to be initiated may include but are not
limited to: a
stimulation injection of flow assurance solvent to the near wellbore region, a
wellbore
circulation of flow-assurance solvent, co-injection of flow assurance solvent
during the
following injection cycle and a stimulation injection of flow assurance
solvent into the
reservoir.
[0104] With respect to asphaltene deposition within a reservoir,
the asphaltene
deposition in the reservoir can be inferred when the produced asphaltene is
compared to
native in-situ asphaltene (e.g. in reservoir 110). The produced asphaltene can
be
measured using an array of samples taken throughout a production cycle. Figure
7A
shows a trend of asphaltene content (wt%) as a function of the produced
hydrocarbons
recovery for a given cycle. The cumulative amount of asphaltene produced over
each
cycle can be inferred using the asphaltene content trend in Figure 7A and the
produced
bitumen volume. The resulting cumulative asphaltene produced over the cycle is
shown
in Figure 7B. The cumulative amount of asphaltene can then be compared to a
theoretical
case where the asphaltene content is constant and equal to the native bitumen.
As shown
in Figure 7B, the measured cumulative asphaltene is lower than the theoretical
native
bitumen, thereby indicating there is net amount of asphaltene being deposited
within the
reservoir. If net asphaltene is deposited in the reservoir, the asphaltene
deposition
mitigations implemented may include a stimulation injection of flow assurance
solvent to
the near wellbore region, a wellbore circulation of flow-assurance solvent, co-
injection of
flow assurance solvent during the following injection cycle, etc.
[0105] In another example, hydrate formation occurs in systems
with volatile
hydrocarbons in the presence of water under certain temperature and pressure
conditions. Severe plugging can occur within the flow lines leading to
downtime where
de-pressurization of the facility is often required to remove the hydrate
plug. Methanol or
other hydrate inhibitors can be added to the flow for passive mitigation. The
hydrate
envelope is a function of the temperature, pressure, the hydrocarbons
composition and
the hydrate inhibitor concentration.
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[0106] Referring now to Figure 8, a variation of the hydrate envelop is
shown
therein. The iso-lines represent the required methanol-to-water volume
fraction for a given
operating condition within the facility where the operating condition is
characterized by
the temperature, pressure and fluid composition. The specific hydrate envelope
for a
given system can be measured experimentally or generated from known
correlations.
Herein, real-time pressure and temperature measurements taken along production
pipeline 108 can be used in conjunction with the real-time compositional
estimate (see
above) to determine the required hydrate inhibitor. A dosage of hydrate
inhibitor can be
determined on the worst case condition along the flow path. The real time
monitoring may
ensure the correct dosage and reduce the costs associated with the treatment.
[0107] The various embodiments of the methods and systems described
herein
may be implemented using a combination of hardware and software. These
embodiments
may be implemented in part using computer programs executing on one or more
programmable devices, each programmable device including at least one
processor, an
operating system, one or more data stores (including volatile memory or non-
volatile
memory or other data storage elements or a combination thereof), at least one
communication interface and any other associated hardware and software that is
necessary to implement the functionality of at least one of the embodiments
described
herein. For example, and without limitation, suitable computing devices may
include one
or more of a server, a network appliance, an embedded device, a personal
computer, a
laptop, a wireless device, or any other computing device capable of being
configured to
carry out some or all of the methods described herein.
[0108] In at least some of the embodiments described herein, program code
may
be applied to input data to perform at least some of the functions described
herein and to
generate output information. The output information may be applied to one or
more output
devices, for display or for further processing.
[0109] For example, a computer monitor or other display device may be
configured
to display a graphical representation of determined phase profiles for the
produced fluid.
In some embodiments, a schematic representation of the injector, producer, and
23
CA 3037410 2019-03-20
,
formation may be displayed, along with a representation (e.g. a graph or
chart) of phase
behavior in different parts of the facility.
[0110] In another example, the one or more processors may be configured
to
determine phase profiles for the produced fluid and, based on the determined
phase
profiles, direct one or more mitigation actions outlined above. These
mitigation actions
may be directed through the control of one or more units within different
parts of the
facility. For instance, the one or more processor may be operatively coupled
to a valve
that can control the flow of a flow assurance solvent to the wellbore. In
another example,
the one or more processors may be operatively coupled to a heater that is
capable of
heating a portion of the wellbore.
[0111] At least some of the embodiments described herein that use
programs may
be implemented in a high level procedural or object oriented programming
and/or scripting
language or both. Accordingly, the program code may be written in C, Java, SQL
or any other suitable programming language and may comprise modules or
classes, as
is known to those skilled in object oriented programming. However, other
programs may
be implemented in assembly, machine language or firmware as needed. In either
case,
the language may be a compiled or interpreted language.
[0112] The computer programs may be stored on a storage media (e.g.
a computer readable medium such as, but not limited to, ROM, magnetic disk,
optical
disc) or a device that is readable by a general or special purpose computing
device. The
program code, when read by the computing device, configures the computing
device to
operate in a new, specific and predefined manner in order to perform at least
one of the
methods described herein.
[0113] While the applicant's teachings described herein are in
conjunction with
various embodiments for illustrative purposes, it is not intended that the
applicant's
teachings be limited to such embodiments as the embodiments described herein
are
intended to be examples. On the contrary, the applicant's teachings described
and
illustrated herein encompass various alternatives, modifications, and
equivalents, without
departing from the embodiments described herein, the general scope of which is
defined
in the appended claims.
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