Note: Descriptions are shown in the official language in which they were submitted.
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System and Method for Controlling the Processing of Oil Sands
Field of the invention
The invention relates to a system and method for controlling the system to
extract oil
from oil sands.
Background to the invention
Oil sands are a mix of sand, water, clay and bitumen (unrefined oil). Under
normal
conditions, the bitumen is too heavy and/or thick to float or be pumped, for
example at
11 C, bitumen is solid. Accordingly, the bitumen needs to be heated and/or
thinned out
so that this valuable resource can be collected.
Figure 1 shows a reservoir 10 of oil sand beneath other layers of rock, soil
etc. A
known method of extracting the bitumen from the reservoir is to drill two well
lines 12,
14 into the reservoir forming a wellpair. The first well line 12 is for
inputting steam, with
or without other fluids, into the reservoir to heat the bitumen. The arrows
along the well
line indicate the direction of steam flow. The second well line 14 is for
extracting the
bitumen, along with water and other injected fluids, from the reservoir. As
shown, the
two well lines are not connected to each other and are spaced apart, perhaps
generally
parallel to one another into the reservoir.
Initially, the steam injected into the reservoir creates a small steam
chamber. The
steam expands in both the longitudinal and axial direction as indicated by
arrows A and
flows to the interface between the steam chamber and the reservoir. The steam
expansion gradually expands the steam chamber 18. The steam heats the bitumen
which flows under gravity to the lower portion of the steam chamber as
indicated by
arrows B. Other fluids may be injected along with steam to reduce the
viscosity of
bitumen to make it more mobile. The bitumen (and any other condensate or
fluid) is
drawn off through the second well line using a pump. The arrows along the well
line
indicate the direction of output fluid flow.
Uniform steam chamber development is critical to ensure a productive well. The
current challenges facing efficient and effective extraction include the
variation in
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response from the reservoir depending on steam chamber size, reservoir
heterogenity,
presence of lean zones. In general, the reservoirs are not well understood.
It is known to use instrumentation to measure the state of the wellpairs. An
operator
observes these measurements on a visualization system and takes action if the
measurements are outside normal behavior or outside pre-defined limits. The
operator
may change the pump rate on the second well line and/or injection rates into
the first
well line. These changes are made based on the operator's training and/or
based on
directions from production engineers responsible for the wellpairs.
Typically, workflow depends very much on the experience of the operator and
the
production engineer working on that specific shift. Operators will normally
have to take
care of many wellpairs. This means that wells have to be operated with a
reasonable
margin of error or "comfort level" which often leads to a production that is
less optimal.
The present applicant has recognised the need for a method and system to
improve
extraction of bitumen from oil sands.
Statements of invention
According to a first aspect of the invention, there is provided a control
system for a well
pair extraction system in an oil sand reservoir, the well pair extraction
system
comprising an injection well for injecting fluid into the reservoir and a
production well for
outputting fluid from the reservoir, the control system comprising:
a central processor configured to:
receive measurements from at least one sensor within the well pair
extraction system, the at least one sensor measuring at least one control
variable of the well pair extraction system;
predict a future value of the at least one control variable by inputting the
measurements into a model of the well pair extraction system, the model being
dependent on the at least one control variables and at least one manipulated
variable which is adjustable to control the at least one control variable;
determine, based on the predicted future value of the at least one
control variable, whether the at least one manipulated variable for the well
pair
extraction system is to be changed, and
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output any change to the at least one manipulated variable
According to a second aspect of the invention, there is provided a method of
controlling
a well pair extraction system in an oil sand reservoir, the well pair
extraction system
comprising an injection well for injecting fluid into the reservoir and a
production well for
outputting fluid from the reservoir, the method comprising:
receiving measurements from at least one sensor within the well pair
extraction system, the at least one sensor measuring at least one control
variable of the well pair extraction system;
predicting a future value of the at least one control variable by inputting
the measurements into a model of the well pair extraction system, the model
being dependent on the at least one control variable and at least one
manipulated variable which is adjustable to control the control variables;
determining, based on the predicted future value of the at least one
control variable, whether the at least one manipulated variable for the well
pair
extraction system is to be changed, and
outputting any change to the at least one manipulated variable.
The following apply to both aspects of the invention.
The invention allows production from the well pair extraction system to be
controlled by
monitoring various parameters of the system and manipulating or changing other
parameters of the system (which are termed manipulated variables) to control
the
monitored parameters. The control variables may thus be defined as the
parameters
(or a subset of the parameters) of the system which are monitored and/or
measured.
There are preferably a plurality of control variables which are measured and
thus there
may be a plurality of sensors. There may also be a plurality of future values
which are
predicted, i.e. one future value for each of the plurality of control
variables. The
manipulated variables may thus be defined as the parameters (or a subset of
the
parameters) of the system which are manipulated and/or changed to control the
control
variables.
Use of the above system and method allows the pair of wells (injection and
production)
to be operated in a consistent way. For example, measurements and models are
used
to predict future well and reservoir behaviour and optimize the changes on the
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manipulated variables to keep the controlled variables at their targets and
within given
constraints.
When determining any changes to the manipulated variables, the system and/or
method may take into consideration that there may be an error in the predicted
value.
For example, the system and/or method compares a current measurement with a
previously predicted value for that current time to determine any error.
However, there
is typically no change to the model used to predict the future value even if
the error is
identified. Thus, the predicted values and/or the difference between the
predicted
values and the measured values are not being fed back into the model. The
future
predictions are directly updated by adding a portion or trend of the error.
Thus the
models may be empirical step response coefficient models and linear or
quadratic
programming algorithms may be used to optimize the changes on the manipulated
variables (i.e. to determine whether or not to change a manipulated variable).
The system and/or method can be used, for example, to reduce start up time
after a
circulation phase and/or shut down. The operation may be independent of the
operator
and may thus be a closed-loop control system. In other words, said processor
may be
configured to iteratively repeat said receiving, predicting, determining and
outputting
steps. However, the operators can intervene in the more problematic cases so
that the
system can also operate in open-loop or manual mode under the control of the
operators.
The control variables may include parameters of said injection well which are
to be
controlled by said control system, for example pressure within said injection
well and/or
rate of injection of fluid into said injection well. The injection well may
comprise of a
short string which injects fluid into the heel part of the well (i.e. towards
the beginning of
the horizontal section of the well) and a long injection string which injects
fluid into the
toe part of the well (i.e. at the end of the horizontal section of the well).
The
manipulated variables may preferably include pressure and/or rate of injection
of fluid
within one or both strings.
Steam is preferably the fluid which is injected through the injection well.
However, one
or more fluids may be injected and these may include alternative fluids. For
example,
solvents may be used instead of or along with steam. The solvent may be a
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hydrocarbon solvent which is injected into the reservoir to dilute the bitumen
to enable
the diluted bitumen to flow into the production well. One such process is
known as
solvent co-injection process.
The control variables may include parameters of said production well which are
to be
controlled by said control system. There may be many sensors on the production
well.
For example, there may be pressure and temperature sensors (PI, TI) at both
the toe of
the well and the heel of the well. There may also be temperature and pressure
sensors
(PI, TI) at various points along the length of the well. The pressure and
temperature
sensors may be combined sensors. The production well preferably comprises a
pump
or other similar lifting mechanism for drawing fluid out from said production
well. At the
pump there may be a variety of different sensors including for example,
winding
temperature sensor (TI), current (II), voltage (El), variable frequency drive
VFD speed
(SI), pressure (PI). There may also be temperature and flow rate sensors (TI
and Fl) at
the output from the well or downstream from the output, e.g. at the surface
facilities.
Accordingly, the control variables may be any one or more of (but not limited
to):
a) Pressure at one or more points along the production well
b) Temperature at one or more points along the production well
c) Temperature differential across one or more pairs of points along the
production
well
d) Flow from the production well
e) Parameters of said pump for outputting fluid from said production well,
wherein
said pump parameters may include winding temperature sensor, current,
voltage, variable frequency drive (VFD) speed and/or pressure (PI).
The control variables may be individually measured and controlled by the
system.
Alternatively, the measurements of the control variables may be combined to
allow
control a key overarching control variable, for example said at least one
subcool within
said production well, where said subcool is defined as:
Subcool =Tsai ¨T,
where
Tõt is a saturation temperature of the fluid within the production well at
production
pressure and
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T, is the temperature at or near location i in the producer (production well).
The saturation temperature is the temperature at which a liquid boils into its
vapor
phase for a corresponding saturation pressure. Thus, Tsat is the boiling point
of the
liquid (e.g. bitumen-water emulsion) in the production well at production
pressure.
One of the main objectives is to control the subcool along the wellbore. The
higher the
liquid level above the producer the lower the temperature and higher is the
sub-cool.
Where there is no subcool, live steam may be flow directly into the production
well.
Where the subcool is too high, the well is functioning inefficiently. A
balance needs to
be obtained between these two extremes. The optimum subcool is where the
reservoir
has a steam zone which is large relative to an oil extraction zone but which
has no
overlap at an outlet to the production well.
At least one manipulated variable may comprise a parameter of said production
well
which is adjustable to control said control variables, for example said
extraction system
may comprise a pump for outputting fluid from said production well and said at
least
one manipulated variable may include speed of said pump. Alternatively, or
additionally, at least one manipulated variable may comprise a parameter of
said
injection well which is adjustable to control said control variables. Each of
said
production well and said injection well may comprise at least one valve to
control flow
into or from said well, for example said injection well comprises separate
valves to
control flow into said short and long strings and said production well
comprises a valve
to control output flow. Said at least one manipulated variable may comprise a
position
(i.e. open/closed/partially open) of one or more of these valves.
Said processor may be further configured to input a limit associated with each
control
variable and/or each manipulated variable. Limits may be associated with some
or all
of the manipulated variables. Said limit(s) may be input by an operator, e.g.
as part of
an initialisation phase. In the absence of definitions from an operator,
preprogrammed
default limits will be implemented. The limits may be associated with safety
or may
represent optimised limits.
The limits may also include maximum rates of change for each of the
manipulated
variables. These maximum rates are always respected. In other words, said
limit may
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actually be said at least one manipulated variable. For example, said at least
one
manipulated variable may be said limit for rate of said steam (or other fluid)
injection
and may be the set point for the injection rate into one or both of said short
string and
long string.
The processor may be configured to determine whether said at least one
manipulated
variable is to be changed by comparing said predicted values of said control
variables
with said at least one limit. Alternatively, or additionally, the processor
may determine
whether said at least one manipulated variable is to be changed by determining
a state
of each manipulated variable required to optimise the system, comparing said
determined state with a current state of said manipulated variable and
determining that
a change is required if the determined state and current state do not match.
The state
required to optimise the system may be determined by adjusting a manipulated
variable, repeating said predicting step and comparing the predicted values
from said
repeating predicting step with the previous predicted values to see whether or
not there
has been any improvement.
Said control system may further comprise a subsidiary controller for
controlling said at
least one manipulated variable and wherein said central processor is
configured to
output any change to said subsidiary controller to implement said change. Said
subsidiary controller may be a flow controller (e.g. a PID) controlling a
valve on an input
or output to said extraction system or a product controller (e.g. a PID)
controlling an
input or output to said extraction system. Thus, in other words, said
subsidiary
controllers implement the changes recommended by the system.
The model may be further dependent on at least one disturbance variable which
disables said processor when activated or contributes to control variable
prediction
when activated and wherein said processor is configured to:
determine whether said at least one disturbance variable is activated and
either cease outputting any change to said at least one manipulated variable
until said at least one disturbance variable is deactivated or a predetermined
time limit
has passed or
update the control variable prediction based on the effect of the disturbance
variable.
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The disturbance variables may include one or more of surface production
pressure,
casing gas pressure and/or pump speed process value. The disturbance variables
may also include a purge indicator, a critical subcool, active subcool and/or
stable
steam.
The model may comprise a plurality of empirical step response coefficient
models
and/or at least one logic relationship.
According to another aspect of the invention, there is provided a well pair
extraction
system for an oil sand reservoir comprising:
an injection well for injecting fluid into the reservoir;
a production well for outputting fluid from the reservoir, and
a control system as defined above.
One or more fluids may be injected or co-injected as described above.
Each aspect of the invention preferably improves the safety of the well
operation. It
may allow wells to be located more closely together, e.g. at a distance of
approximately
3m apart rather than the standard minimum 5m gap, or may allow thinner
reservoirs to
be exploited, e.g. reservoirs having a height of 10m or less rather than the
standard
minimum of 15m. Thus, the system and/or method may be used to reduce the
distance between the well pairs.
The invention may also improve the efficiency of the well, accelerate start-up
after e.g.
the circulation phase or shut-down and generally reduce the energy
consumption. The
control may optimise production to ensure that maximum extraction is achieved
for
minimum energy input.
Said system may be expanded from the above system to cover multiple well
pairs.
Thus according to another aspect of the invention, there is provided an
extraction
system for an oil sand reservoir comprising a plurality of well pair
extraction systems as
defined above; a sources of one or more fluids connected to each of said
plurality of
well pair extraction systems; and an output connected to each of said
plurality of well
pair extraction systems.
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The source of one or more fluids may be termed a common fluid input. Although
there
is a common fluid input and a common output, each wellpair has its own control
system. Each control system is individually connected to the common output to
manipulate fluid flow from the associated production well and to the common
fluid input
to manipulate fluid flow into the associated injection well. Accordingly, the
separate
wellpairs may be individually optimised whilst drawing on the same resources.
The
optimisation may be done individually at each control system or by a central
control.
The extraction system may thus further comprise a main controller connected to
the
control system for each well pair extraction system, the main controller being
configured to control, e.g. optimise, production and steam utilisation across
the
extraction system.
The main controller may thus act as co-ordination system to ensure that fluid
is given to
the well where additional fluid gives the highest increase in oil production
or where
needed due to given constraints. Such constraints may include a minimum
spacing
between individual well pairs. With better co-ordination of the overall
system, the
spacing between individual well pairs may be reduced. Thus according to
another
aspect of the invention, there is provided use of said system to reduce the
distance
between the well pairs.
The invention further provides processor control code to implement the above-
described systems and methods, for example on a general purpose computer
system
or on a digital signal processor (DSP). The code is provided on a physical
data carrier
such as a disk, CD- or DVD-ROM, programmed memory such as non-volatile memory
(eg Flash) or read-only memory (Firmware). Code (and/or data) to implement
embodiments of the invention may comprise source, object or executable code in
a
conventional programming language (interpreted or compiled) such as C, or
assembly
code. As the skilled person will appreciate such code and/or data may be
distributed
between a plurality of coupled components in communication with one another.
Brief description of drawings
The invention is diagrammatically illustrated, by way of example, in the
accompanying
drawings, in which:
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Fig. 1 is a schematic illustration of known extraction of bitumen from an oil
sands
reservoir;
Fig. 2 is a block diagram of the components of one arrangement of the system
comprising an injection well and a production well;
Figs. 3a and 3b are schematic diagrams of an injection well and an production
well
which may be used of the system of Fig 2;
Figs. 4a to 4c illustrate a steam chamber having zero subcool, preferred
subcool and
high subcool, respectively;
Fig. 5a is a flowchart of the steps for controlling a MPC controller within
the system of
Fig. 2;
Fig. 5b is a graph showing example upper and lower limits defined in the
method of
Fig. 5a;
Fig. 5c is a flowchart of the steps for controlling a PID controller within
the system of
Fig. 2;
Fig. 5d is a graph showing an example set point for the PID controller;
Figs. 6a and 6b are graphs showing steam flow over time within the short
injection and
long injection strings respectively for a model assuming a homogeneous
reservoir;
Fig 6c is a graph showing output fluid flow over time for the model of Fig.
6a;
Figs. 6d and 6e are graphs showing variation in pressure over time within the
short
injection and long injection strings respectively for the model of Fig. 6a;
Fig. 6f is a graph showing the level of one subcool over time for the model of
Fig. 6a;
Figs. 6g and 6h are graphs showing the variation of total steam injection flow
and the
percentage steam flow in the short string with time respectively for the model
of Fig. 6a;
Figs. 7a and 7b are graphs showing steam flow over time within the short
injection and
long injection strings respectively for a model assuming a heterogeneous
reservoir;
Fig 7c is a graph showing output fluid flow over time for the model of Fig.
7a;
Figs. 7d and 7e are graphs showing variation in pressure over time within the
short
injection and long injection strings respectively for the model of Fig. 7a;
Fig. 7f is a graph showing the level of one subcool over time for the model of
Fig. 7a;
Figs. 7g and 7h are graphs showing the variation of total steam injection flow
and the
percentage steam flow in the short string with time respectively for the model
of Fig. 7a;
Fig. 8 is a schematic illustration of a system comprising multiple wellpairs,
and
Fig. 9 is a schematic illustration of one system architecture.
Detailed description of drawings
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Fig. 2 shows a system for extracting oil from oil sands. The system comprises
an
extraction system comprising a steam generator 30 for injecting steam into an
injection
well 41 and a production well 40 for extracting output fluid, including oil.
As shown in
Fig. 2, the injection well 41 and production well 40 are joined by dotted
lines to illustrate
that whilst the injection and production wells may be physically close to each
other
there is no direct connection between these two wells. The wells are connected
by the
creation of a steam chamber as described with reference to Fig. 1 above. The
extraction system may thus be termed a closely spaced injector-producer well
pair.
The creation of the steam chamber and the process of extraction is controlled
by a
control system which comprises a central controller or processor 34 whose
operation is
described in more detail below. The processor 34 is connected to a steam
controller
32 which controls the injection of steam into the injection well and a
production
controller 42 which controls the output from the production well. The
processor and
controllers are shown as separate components but it will be appreciated that
they may
incorporated into a single component. The steam and production controllers may
be
connected to valves (not shown) to open and close the valves to control flow
within the
system. The controllers may also be connected to pump(s) within the system to
control
flow within the system.
The production controller 42 controls the flow of output from the production
well to
downstream polishing separators. The separators may include an initial
oil/water
separator 44 to separate the output flow into an oil flow which is
predominantly oil and
a water flow which is predominantly oil. The water flow is fed to a water
treatment
apparatus 46 for further polishing and the final water flow may be fed back
into the
steam generator 30. The oil flow is fed to an oil treatment apparatus 48 for
further
treatment.
The processor 34 receives data from a variety of sensors 36 which are
positioned
throughout the system, e.g. in the production well and the injection well.
The
processor 34 is also connected to an operator terminal 35 for an operator to
input data
into the system and/or for the processor 34 to output data for an operator to
view.
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Use of the above system allows the pair of wells (injection and production) to
be
operated in a consistent way. The operation may be independent of the operator
and
may thus be a closed-loop control system. Operators can let the automated
system
take care of most of the control. However, the operators can intervene in the
more
problematic cases so that the system can also operate in open-loop mode under
the
control of the operators. One of the aims as explained below is that the steam
assisted
gravity draining subcool is reduced, leading to higher production.
Fig. 3a shows the components of one suitable configuration for the injection
well 41.
The injection well 41 comprises an injector 50 coupled to a short injection
string 52 and
a long injection string 54. The short injection string 52 injects steam into
the heel part
of the well and the long injection string 54 injects steam into the toe part
of the well.
For ease of illustration, the strings are not shown as continuous lines in Fig
3a but
clearly the two parts of each string are connected. As an alternative, a
single injection
string with a plurality of valves along the length of the string could be used
whereby the
string can inject into different areas of the production by appropriate
opening and
closing of one or more valves. Also the production well may be equipped with a
similar
type of valves along the wellbore, making it possible to manipulate the steam
chamber
also from the producer side.
Fuel gas 56 may also be input to the injector to purge the well to prevent
sand etc.
clogging the pressure instrument. Each input to the injector has an associated
valve 58
controlling flows into the injector. Each valve is controlled by a flow
controller FC which
may be incorporated in or may be controlled by the steam controller 32 of Fig.
2.
Alternatively, another controller such as a pressure controller could be used
in the
place of the FC. There is a pressure sensor PI measuring the pressure on the
fuel gas
input.
Fig. 3b shows the components of the production well 40. The production well 40
comprises a producer 60 which is coupled to a pump or other lifting mechanism
to draw
output fluid flow from the reservoir. The fluid is output to a production
header 62 and
gas is output to a casing gas 64. Each output
from the producer 60 has an
associated valve 68 controlling flows from the producer. On the output to the
production header 62 there is an additional valve 70 to allow some of the
fluid output to
be drawn off to be tested at a test header 66. Each valve is controlled by a
product
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controller PC which may be incorporated in or be controlled by the production
controller
42 of Fig. 2. The pump is shown as an electric submersible pump (ESP) 72 is
fitted
within the production well to pump fluid to the producer 60. Alternative pumps
may be
used as appropriate and thus the term pump and ESP may be interchanged in the
following description.
There are many sensors in the production well. There are pressure and
temperature
sensors (PI, TI) at both the toe of the well and the heel of the well. There
are also
pressure and temperature sensors (PI,TI) at various points along the length of
the well.
These sensors may be combined sensors measuring both pressure and temperature.
Temperature differential (TDI) may also be calculated at various points along
the well.
At the ESP 72 there are a variety of different sensors including, for example,
winding
temperature sensor (TI), current (II), voltage (El), variable frequency drive
VFD speed
(SI), pressure (PI). There are also temperature and flow rate sensors (TI and
Fl) on
each output.
One of the main control objectives is to control the subcool along the
wellbore. Figs 4a
to 4c illustrate this objective. In each of Figs 4a to 4c, there is a steam
zone 80 having
a steam input 84 and an outer oil extraction zone 82 having an oil output 86.
As
explained in relation to Fig 1, the oil is extracted by steam forcing through
the steam
input 84 to the interface of the steam chamber. Heated oil drains under
gravity along
the interface to the base of the chamber and is extracted through oil output
86.
The subcool is related to the fluid level and is defined as:
Subcool = ¨T,
where
Tõt is the saturation temperature at production pressure and
T, is the temperature at location i in the producer (production well)
The higher the liquid level above the producer the lower the temperature and
higher is
the sub-cool. Typically, the lowest subcool is used as the constraining or
limiting
subcool.
In Fig. 4a, there is no subcool, in other words the steam zone 80 extends
below the
steam input and covers the oil output 86 so that there is no separation of the
steam
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zone and oil extraction zone in the region of the oil output. Accordingly,
live steam will
be output which is dangerous. By contrast, in Fig. 4c, the steam zone is small
relative
to the oil extraction zone because of a relatively high subcool. Accordingly,
the well is
likely to function inefficiently with loss of potential head and steam
distribution. The
optimum subcool is shown in Fig. 4b where the steam zone is large relative to
the oil
extraction zone but there is no overlap at the outlet.
As explained in more detail below, the objective of creating an ideal subcool
can be
achieved by monitoring various parameters (termed control variables) and
manipulating
other parameters (termed manipulated variables) within the system to control
the
monitored parameters. For example, the ESP speed, the injector bottomhole
pressure
and injection split, the short- and long steam injection rates are examples of
variables
which may be adjusted to achieve the overall aims. As an example, the ESP
speed
can be raised or decreased by a fixed amount, e.g. 5%.
Fig. 5a illustrates the various steps of the method which are implemented
within the
processor of Fig 2. The first initialisation step S100 is to define any limits
(or set points)
for the system. As shown in Fig. 5b, there may be an upper and a lower limit
90,92.
Each limit may be constant with time or may change with time, e.g. have step
changes
in value. A step change is unusual but could be included by an operator,
perhaps
when overriding in open-loop mode. A separate limit (or pair of limits) is
preferably
defined for each control variable and/or for each manipulated variable. In the
absence
of definitions from an operator, preprogrammed default limits will be
implemented. Any
changes to the limits are communicated to the individual controllers, e.g. the
steam
controller or production controller of Fig. 2 and/or the flow controllers of
Fig 3a and the
product controllers of Fig 3b.
The limits are set to avoid the process limitations such as:
= staying above bottom water zone pressure,
= avoid live steam production,
= staying within pump operation envelope etc.
Thus, the limits may be associated with safety, e.g. max pressure or may
represent
optimised limits, e.g. desired output flow. The limits may also include
maximum rates
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of change for each of the manipulated variables. These maximum rates are
always
respected.
After initialisation, the method automatically loops through steps S102 to
S110
repeatedly, perhaps every minute or at other regular intervals. The prediction
may be
for the next 12 to 18 hours. At step S102, sensor data is received from the
system. As
indicated above, there are a plurality of sensors throughout the system,
including
instrumentation measuring the state of the wellpairs, pumps etc. The
measurements
are primarily for the controlled variables (CVs), i.e. the system variables
which the
system is attempting to control. Other variables can also be measured.
The measurements are fed into the processor which operates a so-called Model
Based
Predictive Control System (MPC) so the processor may be termed an MPC
controller.
At step S104, the future states of the pair of wells are predicted based on a
pre-defined
model. At step S106, the processor calculates what will happen if actions to
various
system variables known as the manipulated variables (MVs) are taken. In
particular,
the processor determines the state of each manipulated variable required to
optimise
the system (e.g. to provide a constant subcool).
The model used in the MPC may comprise a plurality of different models for the
different sections/elements of the system. The models may be of finite-impulse-
response (FIR). The models are identified through iterative testing to
minimise the
difference between the model and real behaviour. Some of the models, e.g. the
model
from injection steam flow MV to subcool CV are difficult to identify due to a
lack of
repetitive behavior. However, these models are still important. Accordingly,
these
models are implemented as logic relationships, for example inject most steam
(within
injection split constraints) where the subcool are highest (heel, middle, toe)
along the
wellbore. However, other alternative implementations of the models may be
used.
The processor then determines whether any of the manipulated variables require
altering (step S108) as a result of the predictions and outputs any changes to
be
implemented (step S110). The changes are then made to the physical system
itself.
The changes may be implemented by subsidiary controllers, e.g. the steam
controller
or the production controller, the flow controller or the product controller.
The subsidiary
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controllers may themselves be PID controllers. Fig. 5c shows the operation of
such a
controller. As with Fig. 5a, the first step S200 is an initialisation phase
which includes
setting the set point of the process variable in question. The controller
receives sensor
data for the process variable at step S202, compares this measurement to the
set point
at step S204 and outputs any resulting change to the controlled variable at
step S206.
The set point of the process variable may be altered, for example by the MPC
controller as described in more detail below.
A summary of the differences between a PID controller and the overall system
controller are set out below:
PID controller MPC controller
1 degree of freedom More degrees of freedom (i.e. more MVs)
Controls PV to a SP. Controls CVs to their limits (or SPs).
Has no prediction capability Has full prediction capability
A PID controller is a Proportional¨Integral¨Derivative controller which is a
generic
control loop feedback mechanism (controller) widely used in industrial control
systems.
As examples, the manipulated variables (MVs) include some or all of:
1. Pump (ESP) speed.
2. Short steam injection rate set point.
3. Long steam injection rate set point.
As set out above, limits may be associated with some or all of the MVs. In
practice, the
most common limit is selecting which of the subcools determines the ESP speed;
this
subcool is termed the critical subcool and may be the lowest value of subcool.
The
limits on the steam injection rates are decided by the bottomhole injection
pressure and
the injection split. However, after a shut-down of the wells, the total steam
injection
rate is then a common limit while the injection pressure builds up.
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The ESP speed is selected as an MV. As an alternative (or additionally), the
production
flow rate set point from the production well could be an MV. However, the ESP
speed
is a variable that the operators are used to manipulating using the manual
operating
system. Furthermore, the production flow rate is a more noisy measurement so
this
may be controlled with a PID controller. The ESP speed is operated with a dead-
band
of 0.5 Hz to avoid small incremental moves in the pump speed.
As shown in Fig 3a, flow controllers control the valves on the short and long
steam
injection strings and these controllers may be PID controllers controlling the
rates of
injection. If this is the case, the MPC controller is connected (directly or
via the steam
controller) to the flow controllers to vary the set point to the flow
controller as
necessary. Both the pressure conditions of the injection well and the valve
opening on
the long and short strings determine the rate of steam injected. Accordingly,
it is
advantageous to include control of the steam injection rate within the MPC
controller in
closed-loop because the MPC controller can input and output several variables
whereas a PID controller only has one degree of freedom. Furthermore, some
operators, for example those in the PETECH (Pulse Enhancement technology)
group
are used to deciding the steam flow rates rather than whether to open or close
the
steam valves.
As examples, the controlled variables (CVs) include some or all of (but not
limited to):
1. Subcools along the wellbore and at the pump, 9 in total.
2. Injector bottomhole pressure.
3. Pump motor winding temperature
4. Pump motor current
5. Pump inflow temperatures, 2 in total.
6. Pump inlet pressure
7. Production flow from well (maps the upthrust and downthrust constraints for
the
Pump),
8. Total steam rate
9. Injection split between short and long steam injection
10. Steam pressures in short and long string, 2 in total
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11. Steam injection valves, 2 in total
12. Pressure measurements along the producer well
As explained above, subcools are important when optimising performance and it
is
preferred to consider all the subcools along the wellbore. Additionally,
injector
bottomhole pressure, pump constraints and steam constraints are considered.
The
ESP constraints protect the pump from operating outside its defined operating
window
and temperature ratings. The steam constraints ensure that the steam supply is
sufficient and the pressure in the injection string will not go too high.
The production flow is included as a constraint because the pump curve is
mapped
directly as capacity as a function of speed. Thus, the upthrust and downthrust
constraints for the pump speed can be expressed as high and low limit on the
production flow, where the limits on the production flow changes depend on the
pump
speed itself.
In addition, there are some disturbance variables (DVs) that affect the
process which
may also be included within the model used by the MPC controller. Some
examples of
DVs are (but not limited to):
1. Surface production pressure
2. Casing gas pressure
3. ESP speed process value
The surface production pressure affects the ESP deliverance pressure and thus
affects
the required head for the ESP pump. The ESP speed process value may be added
as
a DV because we want to add the model from the ESP speed towards the injector
bottomhole or producer pressure without using the ESP speed as an MV for this
controlled variable.
In addition there are logic DVs which override the MPC controller in whole or
in part.
These logic DVs are added to avoid unwanted moves in special cases. As
examples
these may include some or all of:
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4. Purge indicator. MPC controller disabled if purging of the downhole bubble
tubes is detected.
5. Critical subcool. MPC controller disabled if a critical subcool turns bad.
6. Subcool active. Ensures that at least one subcool CV is active before the
ESP
speed can be used as an MV in the MPC controller.
7. Stable steam. Ensures that the steam supply is stable before the steam
injection rates can be used as an MV in the MPC controller.
Purging of the bubble tubes is done to prevent sand etc. clogging the pressure
instrument. The purging occurs regularly, e.g. every three hours, and fuel gas
is purged
down to the instrument at a significantly higher pressure. Hence, the pressure
readings
go high for a short while, less than 2 minutes. However, the temperature
readings are
affected for longer, and for some subcool values the disturbances last for
about 30
minutes. Typically, the disturbances are only short-term and the process
returns to
approximately the same levels as before the purge. Accordingly, the MPC
controller is
disabled, i.e. turned off or at least prevented from outputting any changes to
the system
for approximately 20-30 minutes following a purge, depending on which subcool
CVs
are actively being used in the modelling.
As set out above, subcools are considered along the length of the production
well. The
critical subcool is the subcool having the lowest value. This is because this
is the
subcool that determines the ESP speed. If this critcial subcool fails or goes
bad, the
MPC controller is disabled. If this logic DV is not used, the controller may
continue to
control the second lowest subcool, and may increase the ESP speed. Before
reinstating the MPC controller, the limits for the CVs may need to be revised
and an
investigation carried out as to why this measurement did turn bad.
The subcool active and/or stable steam DVs avoid unwanted operation of the
SAGD
wellpair. Subcool active ensures that at least one subcool CV is active in the
controller
before the ESP speed can be controlled by the MPC. This is because ESP speed
is
the manipulated variable having the greatest effect on the subcool controlled
variable.
Stable steam ensures that the steam supply is working well and the MPC has the
ability to decide the steam rates.
CA 02812394 2013-03-14
Figs 6a to 7h illustrate the results of a simulation using MPG control of the
above
system. The process was simulated in the thermal reservoir modelling tool
STARS. In
Figs 6a to 6h, a homogeneous model assuming that the reservoir had a uniform
permeability was used. In Figs 7a to 7h, a heterogeneous model with different
permeability in the reservoir was used, leading to different steam
distribution compared
to the homogenous reservoir. In summary, the simulation results showed that
the short
and long string bottomhole pressures were controlled with the steam
injections. The
producer flow controlled the lowest subcool in the wellbore.
Figs. 6a to 6c and Figs. 7a to 7c are the variation in time for each of the
manipulated
variables of the simulated system, namely:
= Short injection string steam flow;
= Long injection string steam flow, and
= Produced fluid flow
These are the variables which are automatically adjusted by the system under
the
control of the MPG controller to ensure the desired or optimal operation of
the system.
For each variable, the upper and lower limits are set by the operator, e.g.
during an
initialisation phase as described in Fig 5.
Figs. 6d to 6h and Figs. 7d to 7h are the variation in time for each of the
controlled
variables of the simulated system, namely:
= Bottomhole pressure for the short string;
= Bottomhole pressure for the long string;
= Subcool level (400mts from the heel for the homogeneous model and at the
toe
for the hetergeneous model)
= Total steam injection flow, and
= Percentage steam flow for the short string
These are the variables which are measured by the system and which the MPC
controller is automatically controlling by manipulation of the manipulated
variables
above. For each variable, the upper and lower limits or set points are set by
the
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operator or production engineer. Figs 6a to 7h illustrate the impact on all
variables of
changes to the limits/set points by the operator. The results are shown over a
period of
several days with the numbers 1 to 5 illustrating the points at which
limits/set points are
changed.
For Figs 6a to 6h, these changes were:
1) The upper limit for the short string bottomhole pressure was increased by
50Kpa and held at the increased limit for three days
2) The upper limit for the long string bottomhole pressure was increased by
50Kpa
and held at the increased limit for three days
3) The lower limit for the subcool was increased by 3 and held at the
increased
limit for three days
4) The upper limit for the short string bottomhole pressure was decreased by
50Kpa and held at the decreased limit for three days
5) The set point for the total steam injection flow was decreased by 25m3/hr
and
held at the decreased limit for three days.
Each of these changes had an immediate impact on the corresponding controlled
variable, e.g. Fig 6d shows that the pressure measured in the short string
spiked when
the upper limit was increased. Some of the changes also effected related
controlled
variables, e.g. Figs 6d and 6e show that the decrease in the total steam flow
at (5) also
results in a drop off in pressure for both strings. Figs 6d to 6h also show
that most of
the controlled variables were stabilised by the system shortly after the
change albeit
that the stabilisation may be a different level.
The stabilisation of the controlled variables is achieved by changing the
manipulated
variables. For example, following the increase to the upper limit for the
short string
bottomhole pressure, the system determined that the short injection string
steam flow
needed to be increased but that overall produced fluid flow needed to be
decreased.
In this way, the short string bottomhole pressure could be stabilised at the
new higher
level. The long string bottomhole pressure and subcool were unaffected.
As shown in Figs 6a and 6b, the manipulated variables were not always changed
in
response to the changes to the limits to the controlled variables. In Fig 6c,
each
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change of the limit to the controlled variable resulted in a change to the
manipulated
variable, namely the produced fluid flow.
For Figs 7a to 7h, these changes were:
1) The lower limit for the subcool was decreased by 3 and held at the
decreased
limit for three days
2) The upper limit for the long string bottomhole pressure was increased by
40Kpa
and held at the increased limit for three days
3) The upper limit for the short string bottomhole pressure was increased by
40Kpa and held at the increased limit for three days
4) The set point for the total steam injection flow was decreased by 25m3/hr
and
held at the decreased limit for three days.
5) The percentage of the total steam flow from the short string was increased
by
5%.
As with Figs 6a to 6h, Figs 7a to 7h shows that each of these changes had an
immediate impact on the corresponding controlled variable and also effected
related
controlled variable. Stabilisation of the controlled variables was also
achieved by
changing the manipulated variables. As with Figs 6a to 6h, Figs 7a to 7h show
that the
manipulated variables were not always changed in response to the changes to
the
limits to the controlled variables. As before, in Fig 7c, each change of the
limit to the
controlled variable resulted in a change to the manipulated variable, namely
the
produced fluid flow.
Fig 8 shows a schematic implementation expanding the above system to cover
multiple
wellpairs. A plurality of wellpairs are grouped into a pad (L1, , L4).
There a plurality
of pads, each served by a common steam header 102 and a common production
header 100. As with
Fig. 5, the production header is connected to an oil/water
separator 104 which separates the fluid into a predominantly oil flow to the
oil treatment
apparatus 106 and a predominantly water flow to the water treatment apparatus
108.
The steam header 100 is connected to a common steam generator 110 which may
receive polished water from the water treatment apparatus.
CA 02812394 2013-03-14
23 .
Although there is a common steam input and a common output, each wellpair has
its
own MPC which is individually connected to the production header 100 to
control fluid
flow from the associated production well and to the steam header 102 to
control steam
flow into the associated injection well. Accordingly, the separate wellpairs
may be
individually optimised whilst drawing on the same resources.
As an optional extra, a site wide controller 112 could be connected to each
MPC
controller to optimise production and steam utilisation across the whole site.
Fig 9 illustrates the system architecture for the MPC system. There are a
plurality of
servers for different parts of the system, namely a CPF server, a wellpad
server, a
historien server, active directory domain controller server, a terminal server
and a
gateway server. There are also a plurality of controllers, e.g. PID
controllers, for
different parts of the system, namely CPF controllers, CCS controllers and
wellpad
controllers. Each of the servers and controllers, including the gateway server
and the
wellpad controllers are connected to the control system supervisory network to
enable
communication between the various components. There are also a plurality of
workstations connected to the network, for example operator workstations and
engineer workstations.
The MPC controller is an open connectivity (OPC) client that is connected to
the OPC
server running on the Gateway server. In this way, the MPC system is installed
in
separate computer on top of the digital process control system (DCS) and
implemented
by operators via the operator/engineer workstations. It will be appreciated
that the
different servers could be geographically and physically separated.
Alternatively, the
functionality could be combined into one or more combined servers.
In summary, model predictive control (MPC) has been implemented on a steam-
assisted gravity drainage (SAGD) injector-producer well pair. Although MPC
have been
widely used in industry (e.g. (Qin & Badgwell, 2003)), there is no suggestion
of how the
technology can be implemented in a SAGO process. As described above, in the
invention, MPC is implemented for stable closed-loop control of subcool in the
producer
and the injector bottomhole pressure. MPC uses measurements and models to
predict
future well and reservoir behaviour and optimize the changes on the
manipulated
variables (e.g steam injection rates and electrical submersible pump (ESP)
speed) to
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keep the controlled variables (subcools, pressures) at their targets and
within given
constraints. Constraints on the system and ESP are also respected. With MPC
the
control targets can be specified and the MPC will move the SAGD process to the
desired operation point.
No doubt many other effective alternatives will occur to the skilled person.
For
example, SAGD is just one method of producing heavy oil and bitumen. Known
alternative methods include VAPEX (Vapor Extraction) in which steam is
replaced with
a solvent to displace the oil and reduce its viscosity. Another alternative is
solvent co-
injection in which a solvent is injection alongside the steam. The method
described
above could be adapted for these techniques by means of adding and/or
subtracting
available process handles as manipulated variables and available measurements
as
controlled variables along with updating the models accordingly. It will be
understood
that the invention is not limited to the described embodiments and encompasses
modifications apparent to those skilled in the art lying within the spirit and
scope of the
claims appended hereto.
