Note: Descriptions are shown in the official language in which they were submitted.
SYSTEM TO ESTIMATE CHAMBER CONFORMANCE IN A THERMAL GRAVITY
DRAINAGE PROCESS USING PRESSURE TRANSIENT ANALYSIS
Technical Field
[0001] The present disclosure relates generally to systems and methods of
characterizing reservoirs during oil extraction processes, and more
specifically, to
systems and methods of estimating chamber conformance in thermal gravity
drainage
processes using pressure transient analysis.
Background
[0002] In the oil and gas industry, reservoir modeling involves the
construction of
a computer model of a petroleum reservoir for the purposes of improving
estimation of
reserves and making decisions regarding the development of the field,
predicting future
production, placing additional wells, and evaluating alternative reservoir
management
scenarios.
[0003] Reservoir characterization is the process of preparing a
quantitative
representation of a reservoir during oil extraction using data (e.g. reservoir
parameters)
from a variety of sources. These sources may include but are not limited to
flow rates,
pressure measurements and temperature measurements.
[0004] Current methods of estimating chamber volume during oil extraction
processes include 4D seismic monitoring, which is time-lapsed seismic
reservoir
monitoring comparing two or more points in time. However, 4D seismic
monitoring can
be expensive and indirect.
[0005] Pressure fall off tests are typically used for estimating pressure
drop in an
injector wellbore following shut-in. The corollary test for producer wellbores
is termed a
build-up test. Fall off tests and build-up tests offer potential for
estimating the total swept
volume of a steam chamber and, therefore, chamber conformance. However, solid
carbonaceous subterranean formations often exhibit a high degree of
heterogeneity and
anisotropy, which cannot be determined from standard pressure fall-off tests.
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[0006] Accordingly, there is a need for improved systems and methods of
surveilling bitumen recovery operations of thermal gravity drainage processes.
Summary
[0007] The present disclosure provides systems and methods of estimating
chamber conformance of a drainage chamber in a subterranean reservoir during a
thermal gravity drainage process as disclosed herein. The thermal gravity
drainage
process is operated in an injector well and a producer well, the injector well
and the
producer well being positioned within the drainage chamber. The system
includes a
plurality of pressure sensors distributed along the injector well, each sensor
of the plurality
of sensors positioned outside a steel casing of the injector well and
configured to measure
a local pressure of a respective portion of the reservoir adjacent to the
injector well. The
system also includes one or more processors operatively coupled to each
pressure
sensor of the plurality of pressure sensors. The one or more processors is,
collectively,
configured to receive the pressure of the portion of the chamber adjacent to
the injector
well as measured by each pressure sensor of the plurality of pressure sensors;
determine
a time to achieve pseudo steady state for each portion of the chamber adjacent
to the
injector well when both the injector well and the producer well are shut-in;
and, based on
the time to achieve pseudo steady state for each portion of the chamber
adjacent to the
injector well, estimate the chamber conformance along the injector well.
[0008] The one or more processors may be further configured to, during
the step
of estimating the chamber conformance along the injector well, estimate a
total swept
volume of the chamber and, based on the total swept volume of the chamber and
the time
to achieve pseudo steady state for each portion of the chamber adjacent to the
injector
well, estimate the chamber conformance along the injector well.
[0009] The time to achieve pseudo steady state may be proportional to the
volume
of each portion of the chamber adjacent to the injector well.
[0010] The system may also include a flow rate sensor to measure a flow
rate of
injected fluid into the injector well and the one or more processors may be
further
configured to, during the step of estimating the chamber conformance along the
injector
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CA 3038186 2019-03-27
well, estimate the total swept volume of the chamber over time based on the
flow rate of
injected fluid into the injector well.
[0011] The injected fluid may be steam.
[0012] The injected fluid may be a combination of steam and solvent.
[0013] The plurality of pressure sensors may be evenly distributed along
the
injector well.
[0014] The plurality of pressure sensors may be unevenly distributed
along the
injector well.
[0015] The plurality of pressure sensors may include at least 8 pressure
sensors.
[0016] The thermal gravity drainage process may be a vapour extraction
process.
[0017] The thermal gravity drainage process may be a solvent-assisted,
steam-
assisted gravity drainage process.
[0018] In some embodiments, another system to estimate chamber
conformance
of a drainage chamber in a subterranean reservoir during a thermal gravity
drainage
process is described herein. Again, in this system, the thermal gravity
drainage process
is operated in an injector well and a producer well, the injector well and the
producer well
being positioned within the drainage chamber. The system includes a plurality
of pressure
sensors distributed along the producer well, each sensor of the plurality of
sensors
configured to measure a pressure of a portion of the reservoir adjacent to the
producer
well. The system also includes one or more processors operatively coupled to
each
pressure sensor of the plurality of pressure sensors, the one or more
processors,
collectively, configured to: receive the pressure of the portion of the
chamber adjacent to
the producer well as measured by each pressure sensor of the plurality of
pressure
sensors; determine a time to achieve pseudo steady state for each portion of
the chamber
adjacent to the producer well when both the injector well and the producer
well are shut-
in; and based on the time to achieve pseudo steady state for each portion of
the chamber
adjacent to the producer well, estimate the chamber conformance along the
producer
well.
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[0019] The one or more processors may be further configured to determine
a liquid
level in the reservoir between a horizontal segment of the injection wellbore
and a
horizontal segment of the production wellbore and, based on the liquid level,
determine a
pressure in the reservoir.
[0020] The plurality of pressure sensors may be evenly distributed along
the
producer well.
[0021] The plurality of pressure sensors may be unevenly distributed
along the
producer well.
[0022] The plurality of pressure sensors may include at least 8 pressure
sensors.
[0023] In some embodiments, a method of estimating chamber conformance in
a
drainage chamber in a subterranean reservoir during a thermal gravity drainage
process
is described. The thermal gravity drainage process is operated in an injector
well and a
producer well and both of the injector well and the producer well are
positioned within the
drainage chamber. The method includes measuring a pressure of a portion of the
reservoir adjacent to the injector well with each of a plurality of pressure
sensors
distributed along the injector well; receiving the pressure measurements at
one or more
processors operatively coupled to each pressure sensor of the plurality of
pressure
sensors; determining a time to achieve pseudo steady state for each portion of
the
chamber adjacent to the injector well when both the injector well and the
producer well
are shut-in; and based on the time to achieve pseudo steady state for each
portion of the
chamber adjacent to the injector well, estimating the chamber conformance
along the
injector well.
[0024] In some embodiments, a method of estimating chamber conformance in
a
drainage chamber in a subterranean reservoir during a thermal gravity drainage
process
is described. The thermal gravity drainage process is operated in an injector
well and a
producer well, the injector well and the producer well being positioned within
the drainage
chamber. The method includes measuring a pressure of a portion of the
reservoir
adjacent to the producer well with each of a plurality of pressure sensors
distributed along
the injector well; receiving the pressure measurements at one or more
processors
operatively coupled to each pressure sensor of the plurality of pressure
sensors;
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CA 3038186 2019-03-27
determining a time to achieve pseudo steady state for each portion of the
chamber
adjacent to the injector well when both the injector well and the producer
well are shut-in;
and, based on the time to achieve pseudo steady state for each portion of the
chamber
adjacent to the injector well, estimating the chamber conformance along the
injector well.
[0025] The method may also include determining a liquid level in the
reservoir
between a horizontal segment of the injection wellbore and a horizontal
segment of the
production wellbore and, based on the liquid level, determine a pressure in
the reservoir.
[0026] The method may also include, in response to estimating the chamber
conformance, performing at least one of: increasing an injection rate of a
fluid to the
injector wellbore to increase a total flow rate of fluids in the injector
wellbore, decreasing
an injection rate of a fluid to the injector wellbore to decrease the total
flow rate of fluids
in the injector wellbore, working over the injector wellbore to reduce skin
formation,
modifying a future wellbore design to improve conformance, and injecting a
scale inhibitor
into the injector wellbore to reduce a rate of scale formation. For instance,
increasing an
injection rate of a fluid to the injector wellbore to increase a total flow
rate of fluids in the
injector wellbore, decreasing an injection rate of a fluid to the injector
wellbore to decrease
the total flow rate of fluids in the injector wellbore, may include changing
modifying
heel/toe steam/solvent injection rates. An estimate of chamber conformance
along the
well may also influence flow partitioning and fluid injection rates to heel
and toe for a given
injector. Also, changes in chamber conformance with time may provide a sense
of skin
formation along the well and consequently influence skin remediation and its
timing. Skin
remediation may include working over a well to reduce skin. Working over the
well may
include but is not limited to injecting an acid into the injector wellbore, re-
perforating the
injector wellbore, and the like. Modifying future well designs to provide
better
conformance may include but is not limited to adding inflow control devices to
systems
for estimating chamber conformance, adding outflow control devices to systems
for
estimating chamber conformance, adjusting the placement of wells, and the
like. Injecting
a scale inhibitor may include injecting EDTA (ethylenediaminetetraacetic acid)
or the like.
[0027] The method may also include, in response to estimating the chamber
conformance, performing at least one of: a comparison of the chamber
conformance to
CA 3038186 2019-03-27
chamber volumes for several wells in a pad to provide insight into geology of
the reservoir
and fluid allocation (e.g. injection rate) among wells, and constrain a
simulation to provide
improve a recovery forecast.
[0028] 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
[0029] 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.
[0030] FIG. 1 is a schematic diagram of a cross-sectional view of a
system for
extracting bitumen from a subterranean reservoir, according to one embodiment;
[0031] FIG. 2 is a schematic diagram of a top-down view of the system for
extracting bitumen from a subterranean reservoir shown in FIG. 1;
[0032] FIG. 3 is a simplified process flow diagram for a method of
estimating
chamber conformance of a drainage chamber in a formation during thermal
gravity
drainage process, according to one embodiment;
[0033] FIG. 4 is a plot of pressure versus time in the pseudo steady
state (PSS)
part of a pressure transient analysis (PTA);
[0034] FIG. 5 is a log-log plot of PTA response showing derivative
pressure versus
time following producer shut-in;
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[0035] FIG. 6 is a plot showing a comparison between PTA estimated
conformance
using the method of FIG. 3 with a conformance calculated using a reservoir
simulator
along the system 100;
[0036] FIG. 7 is a simplified process flow diagram for a method for
determining a
liquid level in a formation between a horizontal segment of an injection
wellbore and a
horizontal segment of a production wellbore, according to one embodiment;
[0037] FIG. 8 is a schematic illustration of an estimated liquid level
between a pair
of horizontal wellbores;
[0038] FIG. 9 is a plot of simulation results for local liquid level
height as a function
of local subcool during a simulated SAGD operation; and
[0039] FIG. 10 is a plot of simulation results for a local profile value
as a function
of time during a simulated SAGD operation.
[0040] 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
[0041] 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.
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CA 3038186 2019-03-27
[0042] At the outset, for ease of reference, certain terms used in this
application
and their meanings as used in this context are set forth. To the extent a term
used herein
is not defined below, it should be given the broadest definition persons in
the pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below,
as all equivalents, synonyms, new developments, and terms or techniques that
serve the
same or a similar purpose are considered to be within the scope of the present
claims.
[0043] 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."
[0044] 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.
[0045] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a
range
from 1 to 9.
[0046] "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. % or
higher);
- 30 wt. % 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
8
CA 3038186 2019-03-27
¨ some amount of sulfur (which can range in excess of 7 wt. %), based on the
total
bitumen weight.
[0047]
In addition, bitumen can contain some water and nitrogen compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of
the
hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen
as well as
lighter materials that may be found in a sand or carbonate reservoir.
[0048]
"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 10.00 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.
[0049]
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.
[0050]
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.
[0051]
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
9
CA 3038186 2019-03-27
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.
[0052] 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."
[0053] 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.
[0054] "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.
[0055] "Pressure" is the force exerted per unit area by the fluid 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.
[0056] 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
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
3.0
CA 3038186 2019-03-27
(hundreds of meters). The resource is generally a hydrocarbon, such as a heavy
oil
impregnated into a sand bed.
[0057] The term "drainage chamber" refers to a region of the reservoir
whose pore
space is primarily filled with a mobilizing fluid (e.g. steam) and a region
along the edges
of the steam chamber filled with low viscosity bitumen, other hydrocarbons,
and
condensed water.
[0058] The term "gravity drainage chamber" refers to a drainage chamber
in a
reservoir formed by displacing a mobilizing fluid through a horizontal
wellbore (i.e. an
injector wellbore) in the reservoir. The mobilizing fluid may be steam or
another bitumen
mobilizing fluid (e.g. solvents, surfactants, etc.). As the mobilizing fluid
(e.g. steam)
propagates radially from the injector wellbore into the reservoir, the
viscosity of bitumen
(and/or other hydrocarbons present in the reservoir) surrounding the wellbore
is reduced
providing for it to fall via gravity to a second horizontal wellbore (i.e. a
producer wellbore)
positioned beneath the injector wellbore.
[0059] The term "pressure transient analysis" refers to the analysis of
pressure
changes over time, especially variations in the volume of a produced fluid. In
most well
tests, a measured rate of fluid is allowed to flow from the formation via a
wellbore being
tested and the pressure at the formation is monitored over time. Then, the
wellbore is
closed and the pressure is monitored while the fluid within the formation
equilibrates. The
analysis of these pressure changes can provide information on boundary
distances of the
formation as well as reservoir properties such as kh (i.e. product of
formation permeability,
k, and producing formation thickness, h) and skin (i.e. a dimensionless factor
calculated
to determine the production efficiency of a well by comparing actual
conditions with
theoretical or ideal conditions).
[0060] The term "chamber conformance" refers to a distribution of the
swept
volume of a subterranean reservoir along a length of a horizontal wellbore. As
a mobilizing
fluid is injected into a horizontal wellbore and disperses radially out of the
wellbore into
the reservoir, the mobilizing fluid reduces the viscosity of bitumen and other
hydrocarbons
present in the reservoir. The mobilizing fluid also cleans neighboring rocks
and leaves
behind a low bitumen saturation region that is typically filled with the
mobilizing fluid.
11
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1
[0061] The term "gravity drainage process" refers to an oil
recovery technique in
which gravity acts as the main driving force for the displacement of oil into
the wellbore
and the voidage volume of oil in the reservoir is replaced by a mobilizing
fluid. Gravity
drainage processes for heavy oil recovery may include a steam-assisted gravity
drainage
(SAG D) process, a solvent-assisted-steam-assisted gravity drainage (SA-SAG D)
process, a heated solvent vapor-assisted petroleum extraction (H-VAPEX)
process, or
any combination thereof.
[0062] The term "mobilizing fluid" includes steam as well as
solvents and viscosity
reducing agents such as but not limited to light hydrocarbons that are soluble
in bitumen
at reservoir temperatures and pressures that reduce the bitumen viscosity
sufficient to
enable it to flow under gravity.
[0063] 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.
[0064] 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
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.
[0065] "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
12
1 CA 3038186 2019-03-27
1
,
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.
[0066] 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.
[0067] 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,
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.
[0068] In spite of the technologies that have been developed,
there remains a need
in the field for systems and methods of monitoring oil extraction processes.
[0069] Herein, systems and methods of estimating chamber
conformance in a
thermal gravity drainage process using pressure transient analysis is
provided.
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[0070] Referring now to Figures 1 and 2 a system 100 to estimate chamber
conformance of a drainage chamber 102 in a subterranean formation 104 during a
thermal gravity drainage process is provided. The thermal gravity drainage
process is
operated in an injector well 106 and a producer well 108. As shown in Figure
1, the injector
well 106 and the producer well 108 are each positioned within the drainage
chamber 102.
[0071] The thermal gravity drainage process operated in the system 100
includes
injecting a mobilizing fluid (e.g. steam or a mixture of steam and solvent)
through the
injector well 106. The mobilizing fluid is generally pumped down from the
surface through
overburden and into injector wellbore 106 where it passes into the formation
104. In some
instances, the mobilizing fluid can pass through one or more of a plurality of
apertures
provided in the wellbore casing of the injector wellbore 106. In other
instances, injector
wellbore 106 may include a screen on tubing rather than a perforated casing.
In these
instances, a tubing-wrapped screen could have limited entry perforations,
outflow control
devices, slots, or the like.
[0072] Injector wellbore 106 may also be referred to as an injector well
or, simply
an injector. As the mobilizing fluid is injected, thermal energy from the
mobilizing fluid is
transferred to the formation 104. This thermal energy increases the
temperature of
petroleum products present in the formation 104 (e.g. heavy crude oil or
bitumen), which
reduces their viscosity and allows them to flow downwards under the influence
of gravity
towards the producer wellbore 108, where it passes into the producer wellbore
108.
Producer wellbore 108 may include a plurality of apertures provided in a
wellbore casing
thereof to provide for the petroleum products to enter the producer wellbore
108. Producer
wellbore 108 may alternatively include a screen on tubing rather than a
perforated casing.
In these instances, a tubing-wrapped screen could have limited entry
perforations, outflow
control devices, slots, or the like.
[0073] Producer wellbore 108 may also be referred to as a producer well
or, simply
as a producer. One or more artificial lift devices (not shown) (e.g.
electrical submersible
pumps) may be used to pump fluids collected along the producer wellbore 108 up
to the
surface.
14
CA 3038186 2019-03-27
1
,
[0074] In the aforementioned thermal gravity process, solvents
may be used to
enhance the extraction of petroleum products from the formation 104. In some
embodiments, the solvent used in the thermal gravity process may be a light
hydrocarbon,
a mixture of light hydrocarbons or dimethyl ether. In other embodiments, the
solvent may
be a C2-07 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas
plant
condensate comprising alkanes, naphthenes, and aromatics.
[0075] 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.
[0076] 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.
[0077] 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
be, for instance, a ketone or acetone. The non-polar component may be, for
instance, a
02-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),
I CA 3038186 2019-03-27
1
,
,
1971, pp 889-910 and "Hansen Solubility Parameters A User's Handbook" by
Charles
Hansen, CRC Press, 1999.
[0078]
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.
[0079]
The solvent composition may comprise at least 5 mol % of a high-
aromatics
component (based upon total moles of the solvent composition) comprising at
least 60
wt. % aromatics (based upon total mass of the high-aromatics component). 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).
[0080]
As shown in Figure 1, as the mobilizing fluid enters the formation
104,
drainage chamber 102 is formed. During normal operation, producer wellbore 108
acts
as a producer (i.e. fluid is extracted from the formation 104 via the wellbore
108), but it
will be appreciated that producer wellbore 108 may also act as an injector.
For example,
during start-up of a thermal gravity drainage process, fluid may be pumped
into both
wellbores 106 and 108 to initially heat a portion of the formation 104
proximate to the
wellbores 106 and 108, following which wellbore 108 may be transitioned to a
producer
by discontinuing the fluid flow therein.
[0081]
As the thermal gravity drainage process continues and mobilizing
fluid is
injected through the injector wellbore 106, petroleum products present in the
formation
104 tend to flow downwards under the influence of gravity towards the producer
wellbore
108 and a drainage chamber 102 forms and grows. Eventually, at a late phase of
the
thermal gravity drainage process, the drainage chamber 102 is exhausted and
removal
16
1 CA 3038186 2019-03-27
of additional petroleum products present in the formation 104 using the
thermal gravity
process becomes inefficient.
[0082] Referring to Figure 2, the elements as shown in this figure that
are
numbered the same as in Figure 1 have the same meaning as in Figure 1. As
shown in
Figure 2, a plurality of distributed pressure sensors 110 are distributed
along one of the
wellbores 106 and 108 (the producer wellbore 108 not shown in Figure 2, but is
similar in
this configuration with the injector wellbore 106 as shown in Figure 2). In
some
embodiments, the pressure sensors 110 are distributed along the injector
wellbore 106.
In other embodiments, the pressure sensors 110 are distributed along the
producer
wellbore 108. In some embodiments, pressure sensors 110 may be regularly
spaced
along a producing interval (i.e. at least a portion of the producing wellbore
108) or placed
according to a well log to capture the impact of reservoir heterogeneity.
Additionally,
pressure sensors 110 may be placed inside a wellbore casing or outside the
wellbore
casing. In instances where the pressure sensors 110 are positioned inside the
wellbore
casing, models may be required to calculate a pressure change along the well.
[0083] Each pressure sensor may be a discrete unit, such as a quartz-
based
sensor, bubble tube, electromagnetic resonating element (ERE), electrical
resonating
diaphragm, and the like. Alternatively, a distributed pressure sensing system
incorporating one or more distributed Fiber Bragg Grating pressure sensors may
be used
to obtain pressure data for each inflow location (e.g. along producer wellbore
108).
Alternatively, multiple individual Fabry Perot gauges connected to the same
fiber optic
trunkline may be used to obtain pressure data for the injector wellbore 106
and/or the
producer wellbore 108. For example, a sensor system such as a SageWatchTM
Subsurface Surveillance System, available from SageRider, Inc., or the like
may be used.
[0084] In some examples, the system 100 may include a distributed data
acquisition system including one or more multi-function sensors capable of
obtaining both
pressure and temperature data. Accordingly, the same physical sensor apparatus
may
function as both a pressure sensor and as a temperature sensor to obtain
pressure and
temperature data for one or more locations along the wellbores 106 and/or 108.
For
example, sensor systems such as CT-MORE, available from Core Laboratories of
17
CA 3038186 2019-03-27
Houston, Texas, or CanePTIm Optical Pressure and Temperature Sensor, available
from
Weatherford International, or the like may be used.
[0085] As shown, two sensors of the plurality of pressure sensors 110 are
separated by a spacing s. In some embodiments, the pressure sensors 110 are
evenly
distributed along the length of one or more of the wellbores 106 and 108 and
the spacing
s is the same along the length of the one or more of the wellbores 106 and
108. In other
embodiments, the pressure sensors 110 can be unevenly distributed along one or
more
of the wellbores 106 and 108 such that a spacing s between any two pressure
sensors
varies along the one or more of the wellbores 106 and 108. In some
embodiments, the
spacing s of pressure sensors 110 along one or more of the wellbores 106 and
108 can
be based on a heterogeneity of the reservoir. For instance, placement of the
pressure
sensors 110 along the length of the wellbore could be at regular intervals, or
be specified
by an understanding of the geology through logs or seismic.
[0086] In some embodiments, the plurality of pressure sensors 110 may
include
about 8 pressure sensors distributed along one of the wellbores 106,108. In
some
embodiments, the plurality of pressure sensors 110 can be distributed along a
horizontal
wellbore having a length of about 1 kilometer.
[0087] In some embodiments, injector wellbore 106 may also include a flow
rate
sensor to measure the flow rate of injected fluid into the injector well. The
flow rate sensor
may be provided at the surface of system 100. In some embodiments, production
from
multiple wells on a pad can be cycled through a test separator resulting in on
the order of
two tests per month of flow rate.
[0088] By obtaining pressure data for a number of locations or portions
of chamber
102 adjacent to the wellbore 106 or wellbore 108 during shut-in conditions,
chamber
conformance of the chamber 102 can be estimated along the horizontal length of
the
wellbore 106 or the wellbore 108. This may provide for a more accurate and/or
more
detailed baseline model of the chamber 102 to be developed for the reservoir
conditions
along the wellbores. A more accurate model may enable the identification of
conformance
related issues and provide an opportunity to remedy these issues through
control of
production during the thermal gravity drainage process.
18
CA 3038186 2019-03-27
[0089] Figure 3 shows a method 300 of estimating chamber conformance for
a
drainage chamber along a horizontal well, according to one embodiment. Chamber
conformance along the wellbores 106 or 108 is estimated based on a time (t) to
reach
pseudo steady-state (PSS) for each pressure sensor of the plurality of
pressure sensors
110 during a build-up test, where both the injector wellbore 106 and the
producer wellbore
108 are shut-in. Alternatively, in some embodiments, chamber conformance of
the
chamber 102 can be estimated based on a time (t) to reach pseudo steady-state
(PSS)
for each pressure sensor of the plurality of pressure sensors 110 during a
fall-off test,
where only one of the injector 106 and producer 108 are shut-in.
[0090] At a step 302, values of pressure for a plurality of portions of
the chamber
are measured using the plurality of pressure sensors 110 distributed along one
of the
injector wellbore 106 and the producer wellbore 108. As noted above, the
pressure
measurements are obtained during shut-in of one or more of the injector
wellbore 106
and producer wellbore 108. It will be appreciated that the production and
injection
wellbores, 108 and 106, respectively, may be shut-in for a number of reasons,
such as
for periodic scheduled maintenance, or an unscheduled power outage.
[0091] At step 304, a total swept volume of the chamber 102 can be
determined
using the slope of pressure versus time in the PSS part of a pressure
transient analysis.
An example of this type of plot is shown in Figure 4, where different plot
lines therein
represent different fall-off tests. The total swept volume of the chamber 102
can be
determined based on the following Equation (1):
V = (1)
where Qi is a flow rate of mobilizing fluid in the injector wellbore, Mc is a
slope of the
pressure versus time in a PSS flow regime, fl cc Bgs/Ct (and is reasonably
constant with
time), where Bgs is a steam formation volume factor (FVF); and Ct is total
compressibility
(which is dominated by steam condensation and fairly independent of phase
saturations).
[0092] In some embodiments, 11 can be estimated from calibrating at least
one fall-
off test with a method of estimating chamber volume (e.g., 4D seismic,
simulation or
19
CA 3038186 2019-03-27
analogs). Following this, the total swept volume of the well can be estimated
for other fall-
off tests using PTA.
[0093] At step 306, a time to achieve pseudo steady state (tpss) for each
portion of
the chamber 102 adjacent to one of the injector wellbore 106 and the producer
wellbore
108 is determined. For instance, in embodiments where the plurality of
pressure sensors
110 are distributed along a length of the injector wellbore 106, a toss for
each portion of
the chamber 102 adjacent to the injector wellbore 106 is determined.
Conversely, in
embodiments where the plurality of pressure sensors 110 are distributed along
a length
of the producer wellbore 108, a tpss for each portion of the chamber 102
adjacent to the
producer wellbore 108 is determined.
[0094] The tpss can be determined based on the following Equation 2:
6 r,2
tPSSõ = ¨ (2)
where n is hydraulic diffusivity, 6 is a shape factor and ri is a radius of
the wellbore.
[0095] A plot showing the slope of a pressure derivative versus time
graph can be
used to estimate tpss. An example of this plot is shown in Figure 5, where
different plot
lines therein represent different volumes and the tpss is proportional to the
chamber
volume near the pressure measurement. It should be noted that the tPSS for
each sensor
of the pressure sensors 110 is proportional to local connected chamber volume.
[0096] At a step 308, once the total swept volume and the tPSS have been
determined for each pressure sensor of the plurality of pressure sensors 110,
the
conformance of the chamber 102 can be estimated. For instance, to estimate the
conformance of the chamber 102, the total swept volume of the chamber 102 can
be
distributed proportional to the tPSS for each pressure sensor 110 and the
spacing s
between them along the length of one of the injector wellbore 106 and the
producer
wellbore 108.
[0097] In some embodiments, the method 300 can detect locations of poor
conformance along the well and corresponding pressure sensors at such
locations show
small tPSS or does not show the typical fall-off pressure derivative behavior.
CA 3038186 2019-03-27
[0098] Referring now to Figure 6, illustrated therein is an example plot
showing a
comparison of PTA estimated conformance using the method 300 described above
with
a conformance calculated from a commercially available reservoir simulator
(e.g. EMP"er
reservoir simulation) along a well pair. As shown therein, the chamber
conformance
estimated using the method 300 is very similar to the chamber conformance
calculated
using the reservoir simulator.
[0099] In embodiments where pressure sensors 110 are distributed along
the
length of the producer wellbore 108, an optional step 310 may be performed to
estimate
the chamber conformance of chamber 102. In these embodiments, the additional
step
310 may be performed to remove the effects of liquid level change over
producer wellbore
108 on the pressure transient response which is calculated from a pressure of
the
producer wellbore 108.
[0100] Step 310 requires information on an increasing liquid level over
the shut-in
period. This can be obtained from a method previously described in Canadian
Patent
Application 3020827. Briefly, referring to Figure 7, there is illustrated a
method 700 for
determining a liquid level in a formation between a horizontal segment of an
injection
wellbore and a horizontal segment of a production wellbore.
[0101] At 705, the producer wellbore and the injector wellbore (e.g.
wellbores 108
and 106, respectively) are shut-in. Optionally, the injector wellbore may
undergo a gas
purge in order to reduce the liquid level in the injector annulus to obtain a
more accurate
bottom hole pressure for the injector wellbore from a wellhead pressure gauge.
For
example, an inert gas such as N2 may be pumped into the injector wellbore to
displace
any condensed vapour present in the injector wellbore into the reservoir.
[0102] At 710, values for local shut-in temperatures (i.e. a temperature
measured
after the wellbore has been shut-in) for a plurality of inflow zones (e.g.
each zone
corresponding to a region or a portion of the producer wellbore 108
surrounding a sensor)
are measured using one or more temperature sensors 220 distributed along the
producer
wellbore 108 (see Figure 8). Inflow locations 205 and outflow locations 210
are shown in
Figure 8.
21
CA 3038186 2019-03-27
1
,
[0103] At 715, values for local shut-in pressures (i.e. a
pressure measured after
the wellbore has been shut-in) for a plurality of inflow zones are measured
using one or
more pressure sensors 230 distributed along the producer wellbore 108 (see
Figure 9).
[0104] Optionally, at 720, values for local shut-in temperatures
for a plurality of
injection zones (e.g. each zone corresponding to a region or a portion of the
injector
wellbore 108 surrounding a sensor) may be measured using one or more
temperature
sensors distributed along the injector wellbore 106. Alternatively, a shut-in
temperature
for the injection zones may be estimated based on, e.g. wellhead measurements
and/or
a saturation curve for the injected fluid(s).
[0105] Optionally, at 725, values for local shut-in pressures
for a plurality of
injection zones are measured using one or more pressure sensors distributed
along the
injector wellbore 106. Alternatively, a shut-in pressure for the injection
zones may be
estimated based on, e.g. wellhead measurements and/or a saturation curve for
the
injected fluid(s), or any other suitable method.
[0106] For example, under saturated conditions, the saturation
curve for the
injection fluid can be used to determine the saturation pressure as a function
of saturation
temperature and injected solvent concentration:
Psat = f (Tsat, Concsowent)
(3)
Accordingly, under saturation conditions, a measurement of temperature
provides a direct
value for the saturation pressure. For example, for SA-SAGD, a temperature
measurement and injected solvent concentration can be used to determine a
pressure
value.
[0107] As another example, for SAGD, assuming no pressure drop
due to flow,
and assuming that the injector wellbore is filled with steam, the static
bottom hole pressure
may be calculated using a pressure measurement taken at the wellhead and known
steam properties:
Pbottom_hole = 'wellhead + (Psteam)(g)(h)
(4)
where n
, steam is the density for steam and h is the height difference between the
bottom
hole location and the location of the wellhead measurement. Alternatively, if
accumulated
22
1
CA 3038186 2019-03-27
liquid is blown out with a gas (e.g. during a purge operation using N2 gas),
r- steam may be
replaced with pflas. Simulation results indicate that reservoir
temperature/pressure at the
injector is relatively uniform in areas of good steam conformance (i.e. where
steam
actually enters the formation). It will be appreciated that additional
measurements (e.g.
temperatures measured for an observation well associated with the
injector/producer
wellpair) may optionally be used to correct the estimation of the injector
pressure.
[0108] It will be appreciated that the production and injection wellbores
may be
shut-in for a number of reasons, such as for periodic scheduled maintenance,
or an
unscheduled power outage. Preferably, steps 710 to 725 may be performed during
an
otherwise scheduled shut-in, as this may limit non-production time for the
recovery
process.
[0109] At 730, a local shut-in liquid level is determined under static
flow conditions
for each of the plurality of inflow zones. Preferably, the shut-in liquid
level for an inflow
zone is based on the measured shut-in pressure at that inflow zone, and a shut-
in
pressure for an injection zone horizontally aligned with that inflow zone.
[0110] For example, with reference to Figure 8, the local liquid level hi
above an
inflow location or zone may be determined based on the local reservoir
pressure P . res_i as
measured at 715, the local pressure in the injector wellbore Pinu at a point
above the local
reservoir location (e.g. as measured at 725 or as otherwise
determined/estimated), and
the local density of the fluid (which may be an assumed value ¨ for example,
the density
of the fluid in the reservoir above the producer wellbore 108 may be estimated
using
Pres_inflow_i (or Pinflow_i), Tres_inflow_i (Or Tinflow_i), and a known or
expected composition of the
fluid). For example, the local liquid level hi may be determined using:
hi =Pres-inflow_i Pinj_i
(5)
PL
where g is the gravitational constant, and Pi, is the density of the liquid in
the reservoir.
For example, density may be measured at the surface, either with online
instruments or
with collected samples, and these surface values may then be corrected to
bottom hole
conditions (e.g. by assuming that the surface composition is the same as the
composition
in the reservoir).
23
CA 3038186 2019-03-27
[0111]
For some processes (e.g. the injection of pure steam, or a pure solvent such
as pentane, hexane, etc.), the local pressure in the injector wellbore PinD
may be
assumed constant over the entire length of the wellbore (e.g. Pinj_i = Pinj).
In other
processes, such as SA-SAGD or VAPEX, this assumption may be less accurate.
Alternatively, the pressure distribution along the injector may be estimated,
e.g. using the
injection pressure and a frictional flow model along the injection well.
[0112]
At 735, a local shut-in subcool value is determined for each of the plurality
of inflow zones. Preferably, the shut-in subcool value for an inflow zone is
based on a
local saturation temperature of an injection fluid at the measured shut-in
pressure at that
inflow zone, and the measured shut-in temperature at that inflow zone. For
example, for
a SAGD or SA-SAGD process, the local shut-in subcool value for an inflow zone
may be
defined as the difference between the saturation temperature Tsat for steam at
the local
shut-in pressure P res_inflow at that zone (i.e. Tsat(Pres_inflow)) and the
local shut-in temperature
Tres_inflow at that zone:
Subcoolshut_ini
= Tsat(Pres_inflow(shut¨in) i) (6)
Tres_inflow(shut¨in)i
As discussed above, the local shut-in pressure in the reservoir adjacent the
inflow location
Pres_inflow(shut¨in) may be assumed as being equal to a pressure value P .
inflow measured
by a pressure sensor 230, or may be based on a measured pressure value Pinflow
subject
to an adjustment factor (e.g. to compensate for a pressure drop across the
reservoir/wellbore interface).
[0113]
For a heated VAPEX (H-VAPEX) process, the local subcool value for an
inflow zone may be defined as the difference between the saturation
temperature Tsat for
the solvent being used at the local shut-in pressure P res_inflow at that zone
and the local
shut-in temperature Tres_inflow at that zone.
[0114]
At 740, a local profile value is determined for each of the plurality of
inflow
zones. The local profile value ST for each inflow zone is based on the local
shut-in subcool
value for that inflow zone and the local shut-in liquid level for that inflow
zone:
24
CA 3038186 2019-03-27
SUbC001shut_1n1
STi = (7)
hi
Combining equations (6) and (7):
= Tsat(Pres_inflow(shut¨in)i) Tres_inflow(shut¨inh
STi (8)
hi
The local profile value STi can be characterized as the change in subcool
required to move
the liquid level by one meter (presuming the liquid level, h, is measured in
meters,
otherwise unit conversion would be required).
[0115] For example, Figure 10 illustrates an example plot of local
profile values STi,
from a simulated SAGD operation using injector and producer wellbores spaced
5m apart,
where the liquid level was being held at about 2.5m. The different plot lines
represent
values taken for different times during the simulated operational life (i.e.
at 680 days of
simulated operation, and at 1400 days, 2120 days, 2840 days, 3560 days, and
(following
a simulated shut-in) at 3602 days). In this illustrative example, there is a
generally linear
relationship between local liquid level heights (y axis) and local subcool
values (x-axis)
for locations in the reservoir below the local liquid level. For locations in
the reservoir
above the local liquid level, the Tsat-T slope is approximately zero.
[0116] At 745, flow is resumed in the producer wellbore and the injector
wellbore.
It will be appreciated that flow may be resumed prior to steps 730, 735,
and/or 740, as
these steps may be performed anytime using the measurements taken during shut-
in.
[0117] At 750, a local operating temperature (i.e. a temperature measured
during
operating conditions after flow in the wellbores has resumed) for an inflow
zone is
measured using one or more temperature sensors distributed along the producer
wellbore
108.
[0118] At 755, a local operating pressure (i.e. a pressure measured
during
operating conditions after flow in the wellbores has resumed) for the inflow
zone is
measured using one or more pressure sensors distributed along the producer
wellbore
108.
CA 3038186 2019-03-27
[0119] At 760, a local operating subcool value is determined for the
inflow zone.
Like the shut-in subcool values determined at 735, the operating subcool value
for an
inflow zone is based on the measured operating temperature at that inflow
zone. For
example, for a SAGD or SA-SAGD process, the local operating subcool value for
an inflow
zone may be defined as the difference between the saturation temperature Tsat
for steam
at the local operating pressure P . inflow (Or Pres_inflow) at that zone (i.e.
Tsat(Pinflow)) and the
local operating temperature Tinflow (or Tres_ inflow) at that zone.
inflow,
Subcooloperatingi
= Tsat(Pres_inflow(operating)i) (9)
Tres_inflow(operating)i
[0120] At 765, a local operating liquid level is determined for the
inflow zone. The
local operating liquid level may be determined by taking the difference
between the local
operating subcool value for the inflow zone and the local shut-in subcool
value for the
inflow zone (determined at 735). Next, this change in the local subcool value
and the local
profile value (determined at 740) can be used to determine a change in the
local liquid
level. This change in the local liquid level can be applied to the local shut-
in liquid level
for the inflow zone (determined at 730) to estimate the local operating liquid
level. For
example:
Subcoo/deitai = Subcooloperatingi Subcoolshut_ini (10)
SUbC0Oide1tai
hdeltai = (11)
STi
hoperatingi = hdeltai hshut-ini (12)
[0121] Alternatively, equations (12), (1), and (7) may be combined to
express the
local operating liquid level as a function of the local operating subcool
value and the local
profile value:
26
CA 3038186 2019-03-27
Subcooloperatingi
hoperatingi (13)
ST1
[0122] Optionally, steps 710 to 740 may be performed each time the
wellbores are
shut-in (e.g. during scheduled service interruptions) to determine updated
local liquid
levels based on pressures measured during static flow conditions. An advantage
of
periodically re-determining the local shut-in liquid levels is that this may
improve the
accuracy of the liquid levels estimated during operation, as the re-determined
baseline
local liquid levels may be more accurate than local liquid levels estimated
following a
significant time period following the prior shut-in.
[0123] Additionally, or alternatively, steps 710 to 740 may be performed
each time
the wellbores are shut-in (e.g. during scheduled service interruptions) to
determine
updated local profile values. An advantage of periodically re-determining the
profile
values is that the relationship between a subcool change and a change in the
local liquid
level may 'drift' over time during the recovery process.
[0124] For example, Figure 10 illustrates an example plot of a local
profile value
from a simulated SAGD operation using injector and producer wellbores spaced
5m apart,
where the liquid level was being held at about 2.5m. In this example, the
change in the
local profile value (i.e. the slope of subcool/liquid level) (y-axis) as a
function of operating
time (x-axis) is generally monotonically increasing over the first 2,000 days
or so, after
which it may stabilize around a long-run value.
[0125] Preferably, after an updated local profile value is determined,
the rate of
'drift' of the profile value (i.e. change in the local profile value as a
function of operating
time) may be estimated for the time period between the determination of the
updated
profile value and the prior profile value. This estimation of the 'drift' rate
may be used as
a factor during the liquid level determination at 765.
[0126] For example, the change in the local subcool value (i.e. the
difference
between the local operating subcool value for the inflow zone and the local
shut-in subcool
value for the inflow zone) may be scaled by an adjusted profile value (e.g.
the local profile
value determined at 740 scaled by the expected 'drift' rate for the time
duration since the
last shut-in) to determine a change in the local liquid level. This change in
the local liquid
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level can then be applied to the local shut-in liquid level for the inflow
zone (determined
at 730) to estimate the local operating liquid level.
[0127] Once the changing liquid level has been determined using the
method 700,
the pressure in the producer wellbore 108 can be determined as the sum of the
reservoir
pressure P
= res and the changing liquid level multiplied by a density of the liquid.
[0128] 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.
[0129] 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.
[0130] For example, a computer monitor or other display device may be
configured
to display a graphical representation of time to pseudo-steady state for a
selected
pressure sensor. In some embodiments, a schematic representation of the
injector,
producer, and formation may be displayed, along with a representation (e.g. a
graph or
chart) of chamber volume along the wellbore.
[0131] 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
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1
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.
[0132]
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.
[0133]
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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