Note: Descriptions are shown in the official language in which they were submitted.
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PAT 102791-1
HYDROCARBON RECOVERY PROCESS
Technical Field
[0001] The present invention relates to the production of hydrocarbons
such as
heavy oils and bitumen from an underground reservoir by heating the reservoir
to
mobilize the hydrocarbons.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the Northern Alberta oil sands that are not
susceptible to
standard oil well production technologies. One problem associated with
producing
hydrocarbons from such deposits is that the hydrocarbons are too viscous to
flow at
commercially relevant rates at the temperatures and pressures present in the
reservoir.
For such reservoirs, thermal techniques may be used to heat the reservoir to
mobilize
the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
One
such technique for utilizing a horizontal well for injecting heated fluids and
producing
hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes
some of
the problems associated with the production of mobilized viscous hydrocarbons
from
horizontal wells.
[0003] One thermal method of recovering viscous hydrocarbons using spaced
horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD
utilizes
gravity in a process that relies on density difference of the mobile fluids to
achieve a
desirable vertical segregation within the reservoir. Various embodiments of
the SAGD
process are described in Canadian Patent No. 1,304,287 and corresponding U.S.
Patent No. 4,344,485. In the SAGD process, pressurized steam is delivered
through an
upper, horizontal, injection well into a viscous hydrocarbon reservoir while
hydrocarbons
are produced from a lower, parallel, horizontal, production well that is near
the injection
well and is vertically spaced from the injection well. The injection and
production wells
are typically situated in the lower portion of the reservoir, with the
producer located
close to the base of the hydrocarbon deposit to collect the hydrocarbons that
flow
toward the bottom.
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[0004] The SAGD process is believed to work as follows. The injected
steam
initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir around
and above the horizontal injection well. The term steam chamber is utilized to
refer to
the volume of the reservoir that is saturated with injected steam and from
which
mobilized oil has at least partially drained. As the steam chamber expands,
viscous
hydrocarbons in the reservoir are heated and mobilized and move with aqueous
condensate, under the effect of gravity, toward the bottom of the steam
chamber, where
the viscous hydrocarbons and aqueous condensate accumulate such that the
liquid /
vapour interface is located below the steam injector and above the producer.
The
heated hydrocarbons and aqueous condensate are collected and produced from the
production well.
[0005] The steam chamber generally does not expand uniformly, from the
steam
injection well, over the length of the well pair. Consequently, the steam
chamber grows
irregularly. Steam is generally more mobile than the viscous hydrocarbons and
other
fluids. Steam and water develop flow paths and these flow paths are favored by
the
steam injected and the condensed water, reducing the effectiveness of the
steam in
heating other regions in the reservoir. Low recovery efficiency of
hydrocarbons from oil
reservoirs is common and, in large part, is due to this difference in
viscosity between the
viscous hydrocarbons and the steam and aqueous condensate.
[0006] Pressure loss in the horizontal segment of the injection well,
inefficiencies
in start-up operations and heterogeneities in the reservoir may also
contribute to the
irregular growth of the steam chamber, also known as poor conformance in the
SAGD
process.
[0007] Attempts to improve conformance include the installation of
various types
of tubing strings in the injection well and the production well, and the
installation of
inflow control devices on one or both of the SAGD injection well and the
production well.
Multiple tubing strings may be utilized to control inflow and oufflow at
various locations
along the horizontal length of the SAGD well pair. Further improvements to
increase
uniformity of steam chamber growth and fluid flow are desirable.
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Summary
[0008] According to an aspect of an embodiment, a process is provided for
facilitating hydrocarbon recovery from a hydrocarbon-bearing formation. The
process
includes identifying a cold portion along a generally horizontal segment of a
well utilized
for hydrocarbon production, locating an electric heater in the well, at a
location along the
generally horizontal segment that corresponds to the identified cold portion,
and heating
the cold portion of the generally horizontal segment to improve inflow of
hydrocarbons
into the well from a region of the formation near the cold portion.
Brief Description of the Drawings
[0009] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0010] FIG. 1 is a sectional view through a reservoir, illustrating a
SAGD well
pair;
[0011] FIG. 2 is a sectional side view illustrating a SAGD well pair
including an
injection well and a production well;
[0012] FIG. 3 is a flowchart illustrating a process for facilitating
hydrocarbon
recovery from a hydrocarbon-bearing formation;
[0013] FIG. 4 is a sectional side view illustrating a production well
according to an
embodiment;
[0014] FIG. 5 is a sectional side view illustrating a production well
according to
another embodiment;
[0015] FIG. 6 is an illustration of a simulation grid showing porosity
and well
locations;
[0016] FIG. 7 is an illustration, in section view, of the temperature
profile of an
intermediate well as modeled on January 1, 2019 (5 years after the start of an
adjacent
SAGD well pair), where a cool portion is located at about the center of the
simulated
intermediate well and where the cool portion is heated with a heater in the
intermediate
well;
[0017] FIG. 8 is an illustration, in section view, of the temperature
profile of an
intermediate well as modeled on January 1, 2019 (5 years after the start of an
adjacent
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SAGD well pair), where a cool portion is located at about the center of the
simulated
intermediate well and where the cool portion is not heated with a heater in
the
intermediate well;
[0018] FIG. 9 is an illustration, in section view, of the temperature
profile of the
intermediate well of FIG. 7 on April 1, 2020, (6 years and 4 months after the
start of
production through the adjacent SAGD well pair);
[0019] FIG 10 is an illustration, in section view, of the temperature
profile of the
intermediate well of FIG. 8 on April 1, 2020, (6 years and 4 months after the
start of
production through the adjacent SAGD well pair);
[0020] FIG. 11 is a graph illustrating the simulated rate of oil
production through
the intermediate well vs. time for the simulations illustrated in FIGs 6-10;
and
[0021] FIG. 12 is a graph illustrating the simulated cumulative oil
produced
through the intermediate well vs. time for the simulations illustrated in FIGs
6-10.
Detailed Description
[0022] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described
herein. The examples may be practiced without these details. In other
instances, well-
known methods, procedures, and components are not described in detail to avoid
obscuring the examples described. The description is not to be considered as
limited to
the scope of the examples described herein.
[0023] The disclosure generally relates to a process for facilitating
hydrocarbon
recovery from a hydrocarbon-bearing formation. The process includes
identifying a cold
portion along a generally horizontal segment of a well utilized for
hydrocarbon
production, locating an electric heater in the well, at a location along the
generally
horizontal segment that corresponds to the identified cold portion, and
heating the cold
portion of the generally horizontal segment to improve inflow of hydrocarbons
into the
well from a region of the formation near the cold portion.
[0024] Throughout the description, reference is made to an injection well
and a
production well. The injection well and the production well may be physically
separate
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wells. Alternatively, the production well and the injection well may be
housed, at least
partially, in a single physical wellbore, for example, a multilateral well.
The production
well and the injection well may be functionally independent components that
are
hydraulically isolated from each other, and housed within a single physical
wellbore.
[0025] As described above, a steam assisted gravity drainage (SAGD)
process
may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a
well pair,
including a hydrocarbon production well and a steam injection well are
utilized. One
example of a well pair is illustrated in FIG. 1 and an example of a
hydrocarbon
production well 100 is illustrated in FIG. 2. The hydrocarbon production well
100
includes a generally horizontal segment 102 that extends near the base or
bottom 104
of the hydrocarbon reservoir 106. The injection well 108 also includes a
generally
horizontal segment 110 that is disposed generally parallel to and is spaced
vertically
above the horizontal segment 102 of the hydrocarbon production well 100.
[0026] During SAGD, steam is injected into the injection well 108 to
mobilize the
hydrocarbons and create a steam chamber 112 in the reservoir 106, around and
above
the generally horizontal segment 110. In addition to steam injection into the
steam
injection well, light hydrocarbons, such as the C3 through C10 alkanes, either
individually or in combination, may optionally be injected with the steam such
that the
light hydrocarbons function as solvents in aiding the mobilization of the
hydrocarbons.
The volume of light hydrocarbons that are injected is relatively small
compared to the
volume of steam injected. The addition of light hydrocarbons is referred to as
a solvent-
assisted process (SAP). Alternatively, or in addition to the light
hydrocarbons, various
non-condensing gases, such as methane or carbon dioxide, may be injected.
Viscous
hydrocarbons in the reservoir are heated and mobilized and the mobilized
hydrocarbons
drain under the effect of gravity. Fluids, including the mobilized
hydrocarbons along
with aqueous condensate, are collected in the generally horizontal segment
102. The
fluids may also include gases such as steam and production gases from the SAGD
process.
[0027] As recovery progresses, the efficiency of recovery may decline in
part due
to the non-uniform displacement of the hydrocarbons by the steam and by the
resulting
aqueous condensate.
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[0028] A flowchart illustrating a process for facilitating hydrocarbon
recovery from
a hydrocarbon-bearing formation is shown in FIG. 3. The process is carried out
in a
hydrocarbon reservoir, such as the reservoir 106. The process may contain
additional
or fewer processes than shown or described, and may be performed in a
different order.
[0029] The reservoir is analyzed at 302. For example, the reservoir may
be
analyzed at 302 by monitoring reservoir characteristics, such as temperature.
For
example, the reservoir may be monitored utilizing a fiber-optic cable that
extends
through the hydrocarbon production well to obtain a real-time temperature
profile across
the generally horizontal segment of the hydrocarbon production well.
Alternatively or
additionally, the inflow of fluids into the generally horizontal segment can
be monitored
to identify portions in which fluid inflow is low. Alternatively or
additionally, seismic
surveys may be utilized to obtain indications of steam chamber growth or
temperature
across the reservoir and across the hydrocarbon production well.
[0030] Alternatively, the reservoir may be analyzed at 302 by modelling
or
simulation of reservoir conditions, for example, over a period of production
such as a
few years of SAGD production.
[0031] Cold spots or cold portions are identified at 304. The cold spots
or cold
portions may be spots or portions along the hydrocarbon production well that
are
identified at 304. The cold portions along the hydrocarbon production well may
be
identified based on the temperature profile or the inflow characteristics, or
a
combination thereof. Cold portions may also be identified by prediction based
on
simulation, seismic survey results, geological and geophysical analysis of the
reservoir,
or any combination thereof.
[0032] A cold portion may be identified by identifying the coldest
temperature
across the hydrocarbon production well or the temperature that is the lowest
measured
temperature, by comparing measured temperatures to an average temperature, by
comparing the measured temperature to a threshold temperature, or in any other
suitable manner. Alternatively, a cold portion may be identified by
identifying portions in
which fluid inflow into the generally horizontal segment of the production
well is low by
comparison to other parts of the generally horizontal segment of the
production well.
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[0033] Alternatively, cold portions in the reservoir may be identified at
304 to
facilitate the identification of a location for an intermediate well that is
located between
two well pairs for the collection of mobilized hydrocarbons in a hydrocarbon
recovery
process. Such a well is also utilized for production and may be referred to as
an infill
well or a well drilled using Wedge WeIITM technology. The cold spot or spots
may be
identified utilizing, for example, the simulation data and the intermediate
well may be
drilled based on the location of the cold portion or cold spots for subsequent
heating.
[0034] An electric heater is located in the production well or the
additional,
intermediate well at 306. The heater is located at a location along the
generally
horizontal segment of the production well or a generally horizontal segment of
the
intermediate well that corresponds to the location of the identified cold
portion.
[0035] The heater is operated to heat the cold portion at 308. Thus, the
heater is
utilized to heat the cold portion to increase uniformity of heating across the
horizontal
segment of the production well or intermediate well. The length of time that
the heater
is utilized to heat the cold portion at 308 is based on several factors and
may be
determined by continuing to monitor the reservoir during heating. Analysis may
be
carried out, for example, by monitoring utilizing fiber optic cable,
thermocouples,
temperature sensors, observation wells, numerical simulation, or any
combination of
these monitoring devices and methods. Thus, the reservoir may be analyzed or
monitored and heating continues until the identified cold portion is heated or
until
heating is predicted to have occurred. Fluid may be circulated in the
production well or
intermediate well during heating. For example, water may be circulated and the
water
flashes into steam in the area of the electric heater to cause steam chamber
growth in
the region of the cold portion.
[0036] A sectional side view illustrating an example of a production well
is shown
in FIG. 4 and described below with continued reference to FIG. 3. As shown in
FIG. 4,
the production well 100 includes the generally horizontal segment 102.
Optionally, an
electric submersible pump (ESP) 402 may be utilized to pump produced fluids,
including
hydrocarbons, to the wellhead. An ESP 402 may be utilized, for example, when
fluids
do not naturally flow to the surface or do not naturally flow at a sufficient
rate.
Alternatively, other artificial lift apparatus such as a rod pump, progressive
cavity pump
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or gas lift may be utilized to pump produced fluids, including hydrocarbons,
to the
wellhead when fluids do not naturally flow to the surface or do not naturally
flow at a
sufficient rate.
[0037] During production, the reservoir is monitored 302 and cold
portions along
the generally horizontal segment 102 of the production well 100 are identified
304. In
the example illustrated in FIG. 4, a cold portion is identified. The
production is
discontinued and an electric heater 404 is located 306 in the generally
horizontal
segment 102, at a location that corresponds to the location of the cold
portion. The
heater 404 is operated 308 to heat the cold portion to improve inflow of the
hydrocarbons into the production well 100 from the region of the formation
that is near
the cold portion. The electric heater 404 may be disposed in a tubing string
and may be
operated inside the tubing string or a tubing string may be selectively
heated. In this
example, hydrocarbon production is not carried out during locating the heater
404 and
during heating. When heating is completed, the electric heater 404 is removed
by
pulling the heater from the hydrocarbon production well 100 and hydrocarbon
production is resumed.
[0038] Alternatively, hydrocarbon production may continue during
localized
heating. In the example of FIG. 4, two separate tubing strings, including the
production
tubing string 406 that is coupled to the ESP 402, and the electric heater
tubing string
408 in which the electric heater is located, are utilized. Because the
electric heater 404
in the present example is located in an electric heater tubing string 408,
which is
separate from the production tubing string 406, production can continue while
selectively heating at a location or locations along the generally horizontal
segment 102
of the production well 100.
[0039] A cold portion is identified 304. Hydrocarbon production continues
while
an electric heater 404 in the electric heater tubing string 408 is located 306
in the
generally horizontal segment 102, at a location that corresponds to the
location of the
cold portion. The electric heater 404 is operated 308 to heat the cold portion
to thereby
improve inflow of the hydrocarbons into the production well 100 from the
region of the
formation that is near the cold portion.
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[0040] A sectional side view of yet another example of a production well
is shown
in FIG. 5 and is described below with continued reference to FIG. 3. In the
example of
FIG. 5, an electric heater 504 is coupled to production tubing 506, in the
same string.
Optionally, an ESP 502 may be utilized to increase flow of fluids to the
surface.
[0041] A cold portion is identified 304. Hydrocarbon production continues
while
the electric heater 504 is located 306 in the generally horizontal segment
102, at a
location that corresponds to the location of the cold portion. Thus, the
electric heater
504 is selectively located for heating at a cold portion along the horizontal
section 102 of
the production well 100. The electric heater 504 is operated 308 to heat the
cold portion
to thereby improve inflow of the hydrocarbons into the production well 100
from the
region of the formation that is near the cold portion. In the present example,
the electric
heater 504 is located and is used to selectively heat a cold portion while
producing
hydrocarbons. Thus, fluids are continuously produced from the production well
100
during heating.
[0042] In the above-described embodiments, the heater is located in a
production
well. The heater may be located in any well through which hydrocarbons are
produced.
For example, the heater may be located in a production well of a well pair,
such as a
well pair utilized in SAGD or in a solvent aided process. Alternatively, the
heater may
be located in a single well that is located between two well pairs for the
collection of
mobilized hydrocarbons in a hydrocarbon recovery process. Such a single well
is also
referred to as an infill well, an intermediate well, or a well drilled using
Wedge WeIITM
technology.
[0043] Computationally Simulated Oil Production
[0044] An exemplary process according to the present disclosure was
computationally simulated using a mathematical model of a reservoir. This
exemplary
process was compared to a computational simulation of a process that lacks a
heater.
[0045] Details of the simulated reservoir are as follows:
[0046] Simulation Grid
[0047] A half element of symmetry was employed to ensure faster run
times. The
model had 33 m pay, an 800 m long well. There was 31 m of overburden and 31 m
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underburden. Grid dimensions were 25 x 210 x 33. Block dimensions for the main
reservoir were as follows:
[0048] I ¨ direction: lm 24*2 m lm (26 blocks, total length of 50 m)
[0049] J ¨ direction: 16*50m (16 blocks, total length of 800 m)
[0050] K ¨ direction: 16 m8m4m2m 35*1 m2m4m8m 16 m (41 blocks,
total length of 93 m).
[0051] Simulated Wells
[0052] In the simulated intermediate well having a heater, the
intermediate well
was located 50 m laterally away from a SAGD well pair. The heater in the
intermediate
well was turned on for 1 year, starting 5 years after the SAGD well pair
starts to operate,
with a maximum temperature of 180 C and maximum power input of 300 kW. The
SAGD production well and offset intermediate well were in the plane.
[0053] In the simulated intermediate well lacking a heater, the
intermediate well
was located 50 m laterally away from a SAGD well pair, and the SAGD production
well
and offset intermediate well were in the plane.
[0054] At the start of the simulations for both wells, there is a portion
in the center
of the intermediate well, at about the 400-500m interval, that is cooler than
the adjacent
areas to the left and right. The general location of the cool portion is
identified by a "*" in
FIGs 7 and 8. Production of the intermediate well is started 5 years after the
SAGD well
pair starts to operate.
[0055] Reservoir Properties
[0056] The grid was populated using the following reservoir variables:
= Temperature = 12 C
= cl) =0.33
= Kh = 7.0 D
= Kv = 1.5 D
= Reference pressure of 2,400 kPa at the top of the SAGD pay
= Sw = 0.20
= So = 0.80
= Mass Fraction Oil of Dead Oil = 0.89
= Mass Fraction Oil of CH4 = 0.11.
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[0057] The thermal properties of the reservoir were characterized using
two rock
types. Rock type one represented clean sand and was used to populate a
selected pay,
representing the McMurray formation in Alberta, Canada. A second rock type
representing shale was used to populate the over and underburden grid. The
properties
of the two rock types were defined with the following properties:
[0058] Rocktype 1 (Sand)
= Porosity Reference Pressure = 100 kPa
= Compressibility = le-6 1/kPa
= Volumetric Heat Capacity 2.39e6 J/(m3*C)
= Rock Thermal Conductivity = 196,820 J/(m*day*C)
= Water Thermal Conductivity = 552,960 J/(m*day*C)
= Oil Thermal Conductivity = 0
= Gas Thermal Conductivity = 0
[0059] Rocktype 2 (Shale Overburden & Underburden)
= Porosity Reference Pressure = 100 kPa
= Compressibility = 1e6 1/kPa
= Volumetric Heat Capacity 2.39e6 J/(m3*C)
= Rock Thermal Conductivity = 146,880 J/(m*day*C)
= Water Thermal Conductivity = 0
= Oil Thermal Conductivity = 0
= Gas Thermal Conductivity = 0
[0060] Relative Permeability
[0061] The oil-water relative permeability curves have the following
properties:
= Connate Water Saturation = 0.2
= Critical Water Saturation = 0.2
= Residual Oil Saturation = 0.15
= Irreducible Oil Saturation = 0.15
= Max relative water permeability = 0.559
= Max relative oil-water permeability = 0.95
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[0062] The oil-gas relative permeability curves have the following
properties:
= Critical Gas Saturation = 0.05
= Residual Liquid Saturation = 0.3
= Max relative gas permeability = 0.72
= Max relative oil-gas permeability = 0.95
[0063] Results of the simulated reservoirs are illustrated in FIGs. 11
and 12. At
simulation time = 0 days, operation of the SAGD well pair is started. After 5
years
(simulation time = approximately 1825 days), production through the offset,
intermediate
well is started. The heater in the exemplary simulated intermediate well is
turned on for
1 year then the heater is turned off. The intermediate wells produce oil for a
total of 5
years (simulation time = approximately 3650 days).
[0064] The heated intermediate well starts producing oil in less than 1
year of
heating. As illustrated in FIG. 9, the heated intermediate well, as of April
1, 2020 (which
corresponds to 1 year and 4 months of production), has vertical flow in the
heated area
and is 100% started.
[0065] The unheated intermediate well is not fully started until well
after 1 year of
the start. As illustrated in FIG. 10, there is no vertical flow in the cool
zone and the
unheated zone is not 100% started as of April 1, 2020 (which corresponds to 1
year and
4 months of production).
[0066] The described embodiments are to be considered in all respects
only as
illustrative and not restrictive. The scope of the claims should not be
limited by the
preferred embodiments set forth in the examples, but should be given the
broadest
interpretation consistent with the description as a whole. All changes that
come with
meaning and range of equivalency of the claims are to be embraced within their
scope.
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