Note: Descriptions are shown in the official language in which they were submitted.
CA 02462466 2004-03-30
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to control systems and methods for fluid
extraction from oil and gas wells. More particularly, the present invention
relates
to methodologies for controlling a downhole pump in an oil or gas well to
optimize
the fluid removal process and/or gas, oil, or water production. In another
aspect,
the present invention relates to systems and devices for optimal control of a
flow
control device. In yet another aspect, the present invention relates to
systems
and methods for monitoring and recording physical changes in a fluid body.
2. Description of the Related Art
Hydrocarbons (e.g., oil and gas) are recovered by drilling a welibore in a
subterranean formation having one or more hydrocarbon reservoirs. Under
formation pressure or by artificial lift, the hydrocarbons flow up the
welibore and
are recovered at the surface, a process commonly referred to as hydrocarbon
production. In many instances, downhole devices such as pumps are used to
assist in hydrocarbon production. For example, pumps are often used to control
the levels of fluids in the welibore (e.g., water, gas, oil), to provide a
pressure
boost to flow the wellbore fluids to the surface or other location, or to
otherwise
adjust the wellbore environment to maintain efficient production. Wellbore
pumps are used in a number of applications, including: conventional oil
production, heavy oil production, gas-dewatering, and coal-bed methane
production.
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Coal-bed methane production is illustrative of some aspects of welibore or
downhole pumps and associated control devices. Coal bed methane is methane
that is found in coal seams. Methane is a significant by-product of
coalification,
the process by which organic matter becomes coal. Often the coal seams are at
or near underground water or aquifers, and coal bed methane production is
reliant on manipulation of underground water tables and levels. The
underground
water often saturates the coal seam where methane is found, and the
underground water is often saturated with methane. The methane may be found
in aquifers in and around coal seams, whether as a free gas or in the water,
adsorbed to the coal or embedded in the coal itself. Methane is a primary
constituent of natural gas. Recovery of coal bed methane can be an economic
method for production of natural gas. Such recovery is now pursued in geologic
basins around the world. However, every coal seam that produces coal bed
methane has a unique set of reservoir characteristics that determine its
economic
and technical viability.
Methods of coal bed methane recovery vary from basin to basin and
operator to operator. However, a typical recovery strategy is when a well is
drilled
into the coal seam, usually a few hundred to several thousand feet below the
surface. Thereafter, a casing is set and cemented in place and a water pump
and gas separation device are installed. The water pump is operated to remove
water from the coal seam at a rate appropriate to reduce the hydrostatic
pressure
exerted on the formation fluids. When the hydrostatic pressure is sufficiently
low,
the methane desorps from the coal. However, because the rate of desorption
varies roughly inversely with the exerted hydrostatic pressure, dropping the
hydrostatic pressure too low may result in a rate of methane production that
can
overwhelm the methane recovery equipment. Thus. control over the water head
or height of a water column in the well is a significant factor in the
production of
methane.
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In conventional coal-seam gas wells, submersible pumps with variable
speed controllers are used as liquid removal systems. Typically, these pumps
are controlled in response to a determination of the water level in the
wellbore. A
conventional arrangement includes a liquid level sensor that uses a pressure
responsive switch. For instance, the system can have an electrical control
circuit
including a switch which operates to turn on the water pump motor when the
water level in the well reaches a certain high level (as measured by the
pressure
responsive switch) and to turn off the pump motor the water level reaches a
certain low level in the well. These sensors are exemplary of mechanical
sensors-i.e., sensors that mechanically co-act with the sensed fluid in order
to
measure a condition in the wellbore (e.g., the presence or absence of
surrounding water). For example, an element of a pressure switch moves or
compresses in response to hydrostatic pressure or a float member of a float
switch moves in response to buoyancy force. The mechanical and electrical
elements of such mechanical devices can be prone to sticking, wear and
corrosion. Thus, a long-standing and persistent drawback of such sensors is
that
their operating life can be much shorter than the life of a production well.
The
cost accompanying the cessation of gas or oil production to repair or replace
an
inoperative sensor can be significant.
Pump control devices utilizing mechanical sensors encounter similar
modes of failure when used in conventional oil pump control, heavy oil pump
control, and gas-dewatering pump control. In these applications as well,
production objectives such as maintaining a fluid level between specific
levels to
optimize the production, avoiding pumping the well off, optimizing energy
consumption, and reducing wear and tear on the pump are in large measure
contingent upon reliable devices and methodologies for controlling downhole
pumps and other such devices. More generally, the need to reliably control
pump operation arises in other applications such as refineries, water
treatment
plants, chemical production facilities, underground gas or liquid, storage
caverns,.
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and other instances wherein the level / quantity / flow rate I velocity of
fluid is
controlled or wherein the mixture or ratio of fluids is controlled.
The present invention addresses these and other drawbacks of the prior
art.
SUMMARY OF THE INVENTION
In one aspect, the present invention provides a device for determining a
location of an interface between a first fluid and second fluid, such as in a
wellbore, a storage tank, a cavern, etc. The device includes a non-mechanical
sensor that measures a selected parameter of interest relating to the fluid
surrounding the sensor ("the surrounding fluid") and a processor for
processing
the sensor measurements. The non-mechanical sensor does not utilize motion
or a physical co-action between the surrounding fluid and the sensor to
produce
a measurement. Rather, the non-mechanical sensor measures parameters such
as thermal properties (e.g., thermal conductivity or capacity), electrical
properties
(e.g., resistance, capacitance, inductance, etc.), fluid properties (e.g.,
viscosity),
and magnetic properties. Because liquids and gases have distinct and
identifiable differences in such properties, the processor can be programmed
to
process the sensor measurements to identify one or more characteristics in the
measurements that can indicate the nature of the fluid being measured. Once
the nature of the fluid is identified (e.g., whether the fluid is water, oil,
methane,
etc.), the location of the interface can be determined. The determined
location
can be used for any number of purposes, including, but not limited to, real-
time
monitoring via a display device, recorded for long-term reservoir
characterization,
or for actuating an alarm if a pre-set condition is met.
In one embodiment directed to wellbore fluids, the system includes a
sensor positioned in the wellbore and a processor in communication with the
sensor. The sensor includes a temperature probe for measuring the temperature
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of a surrounding fluid. In certain embodiments, the sensor heats the
surrounding
fluid while measuring temperature. The heating element can be the probe itself
or
a separate element. The processor processes the temperature measurements to
identify the state or nature of the surrounding fluid, e.g., whether the fluid
is gas
(e.g., methane) or a liquid (e.g., water). For instance, the processor can
develop
a curve based on the temperature measurements and then identify curve
characteristics (e.g., amplitudes, differentials, slopes, etc.) that are
indicative of a
liquid or a gas.
In another aspect, embodiments of the invention can be used to control a
downhole fluid control device such as a pump or valve. In one arrangement, two
non-mechanical fluid level sensors are positioned in spaced-apart relation in
a
wellbore having a water column. The height of the water column is adjusted by
selective operation of a downhole pump. During use, a controller operatively
coupled to the non-mechanical fluid level sensors determines whether one or
both
of the non-mechanical sensors are surrounded by water or a gas. After making
this
determination, the controller alters the operation of the pump (if needed) to
bring the
height of the water column into a selected range or height. The level sensors
can
be positioned physically at the operating switch points for the pump (e.g.,
the upper
and lower limits for the height of the water column). Alternatively, the level
sensors
can be positioned within the upper and lower limits of the water column
height. For
instance, the processor can determine the rate of change of the height of the
water
column and predict by interpolation or extrapolation the height of the water
column.
The processor can, optionally, also use measurements from other sensors that
relate to hydrocarbon production, water production, and wellbore conditions.
In summary, an apparatus for controlling a flow control device in a wellbore
is provided, the apparatus comprising:
(a) a non-mechanical fluid level sensor being positioned at a first depth in
the
wellbore, said non-mechanical fluid level sensor measuring a temperature of
the
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fluid surrounding said non-mechanical fluid level sensor; and
(b) a controller operatively coupled to said non-mechanical fluid level sensor
and to the flow control device, said controller determining whether said fluid
level
sensor is surrounded by a liquid or a gas based on a temperature differential,
said
controller controlling the flow control device in response to the measurements
provided by said non-mechanical fluid level sensor.
A system for controlling a downhole pump used to adjust the height of a
water column in a wellbore is also provided, the system comprising:
(a) a plurality of level sensors positioned along wellbore, said level sensors
being adapted to measure the temperature of a surround wellbore fluid;
(b) a power source adapted to selectively transmit an electrical signal to
said
level sensors; and
(c) a controller operably coupled to said level sensors and said power source,
said control unit determining whether said level sensor is surrounded by a
liquid or
a gas based on a temperature differential, said controller controlling the
pump in
response the temperature measurements provided by at least one of said level
sensors, wherein said controller is programmed with a first and second switch
point
for adjusting operation of the pump, said controller determining whether
either of
said first or second switch points have been reached by processing the
temperature
measurements of at least one of said level sensors.
A method for controlling a flow control device in a wellbore is also provided,
the method comprising:
(a) positioning a non-mechanical fluid level sensor in the wellbore;
(b) measuring a temperature of a fluid surrounding the non-mechanical fluid
level sensor using the non-mechanical fluid level sensor;
(c) determining whether the non-mechanical fluid level sensor is surrounded
by a liquid or a gas based on a temperature differential; and
(d) controlling the flow control device in response to the measurements
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provided by the non-mechanical fluid level sensor.
A method for optimizing hydrocarbon production by adjusting a height of a
water column in a wellbore is also provided, the method comprising:
(a) positioning a pump in fluid communication with the water column;
(b) positioning a plurality of level sensors along the wellbore, the level
sensors being adapted to measure the temperature of a surrounding wellbore
fluid;
(c) determining whether the non-mechanical fluid level sensor is surrounded
by a liquid or a gas based on a temperature differential; and
(d) controlling the pump in response to the temperature measurements
provided by at least one of the level sensors.
It should be understood that examples of the more important features of the
invention have been summarized rather broadly in order that detailed
description
thereof that follows may be better understood, and in order that the
contributions to
the art may be appreciated. There are, of course, additional
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features of the invention that will be described hereinafter and which will
form the
subject of the claims appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
For detailed understanding of the present invention, references should be
made to the following detailed description of the preferred embodiment, taken
in
conjunction with the accompanying drawings, in which like elements have been
given like numerals and wherein:
FIG. I schematically illustrates an elevation view of one embodiment of a
well having a pump control system made according to one embodiment of the
present invention;
FIG. 2 schematically illustrates a sectional view of a sensor made
according to one embodiment of the present invention;
FIG. 3 shows an exemplary temperature versus time graph for a Fig. 2
sensor;
FIG. 4 schematically illustrates a pump control circuit made according to
one embodiment of the present invention;
FIG. 5 schematically illustrates an elevation view of another embodiment
of a well having a pump control system made according to the present
invention;
and
FIG. 6 schematically illustrates an elevation view of yet another
embodiment of a well having a pump control system made according to the
present invention.
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Similar reference characters denote corresponding features consistently
throughout the attached drawings.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
The present invention relates to devices and methods for controlling
equipment, such as pumps, used to recover hydrocarbons (e.g., methane) from
subterranean formations. The control systems and methods can apply to any
artificial or natural lift technique, including but not limited to gas-lift,
PCP pump,
ESP pump, rod pump, downhole control valves for selective zone control. The
present invention also relates to devices and methods for determining the
location of an interface between a first liquid and a second liquid. The
present
invention is susceptible to embodiments of different forms. There are shown in
the drawings, and herein will be described in detail, specific embodiments of
the
present invention with the understanding that the present disclosure is to be
considered an exemplification of the principles of the invention, and is not
intended to limit the invention to that illustrated and described herein.
As will become evident in the discussion below, embodiments of the
present invention may be used to enhance the production of methane from
subterranean formations such as coal bed or enhance the production of oil from
conventional or heavy oil formations. Referring initially to Figure 1, there
is
shown a facility for recovering methane from a subterranean formation. In one
embodiment, the methane recovery facility 10 includes a cased well 12 that
intersects a coal bed 14. Suspended or hung within the cased well 12 is a
production tubing 16. The well 12 is partially filled with water that
continually
drains out of the formation, the water line being designated by numeral 18. A
pump 20 connected to an end of the production tubing 16 is used to pump water
out of the cased well 12 to the surface or other locations (e.g.. a subsurface
formation). Operation of the pump 20 controls the height of the water column
21
and therefore the hydrostatic pressure exerted on the coal bed 14. When the
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hydrostatic pressure drops below a particular level or amount, methane 22
flows
out of the formation 14 via an annulus 24 formed by the production tubing 16
and
cased well 12. Methane 22 is collected at the wellhead 26 and piped or
otherwise transported for further refinement.
It will be appreciated that if the water level in the case well 12 is
sufficiently high, the resulting hydrostatic pressure will suppress or
extinguish the
production of methane 22. On the other hand, if the water level 18 drops too
low,
such as below the pump 20, the pump 20 may be damaged. Moreover, the loss
of hydrostatic pressure can lead to an excessive release of methane and an
over
pressure situation in the well 12 and at the wellhead 26. Thus, the wellbore
can
be considered to have two fluids: a gas (e.g., methane) and a liquid (e.g.,
water).
The location of the interface between these two fluids impacts the production
of
the hydrocarbons residing in the formation.
In one embodiment, a pump control system 30 for controlling pump
operation includes a lower level sensor 32, an upper level sensor 34, a
telemetry
cable 36 and a controller 38. The controller 38 periodically communicates with
the level sensors 32 and 34 to determine whether operation of the pump 20
should be adjusted in response to changes in the height of the water column 21
(i.e., shifts in location of the water-gas interface). A number of
arrangements
may be employed to make this determination.
In one arrangement, the controller 38 is programmed to energize and de-
energize the pump 20 upon detecting one or more predetermined conditions.
For instance, a first predetermined condition may be a height of a water
column
21 below a first depth D1. It may be determined that a water column 21 below
the first depth D1 may apply insufficient hydrostatic pressure to the
formation or
raise the risk that the pump 20 may not be fully submerged. Thus, the lower
sensor 32 is positioned at the first depth D1. A second predetermined
condition
may be a water column 21 having a height at or above a second depth D2, a
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height causing a hydrostatic pressure that unacceptably impairs the production
of
methane. Therefore, the upper sensor 34 is set at the second depth D2. During
operation, the controller 38 periodically interrogates each sensor 32, 34.
Based
on the sensor response, the controller 38 determines whether either the first
or
second predetermined condition is present and, if needed, takes appropriate
action. Thus, the first and second depths 1131, D2 are pre-determined set-
points
that are used to adjust the operation of the pump 20.
There are several actions that can be taken by the controller 38 after
interrogating the sensors 32, 34. For instance, the controller 38 can be
programmed to de-energize the pump 20 if the response of the lower sensor 32
indicates that the water level is at or below the lower sensor 32 and energize
the
pump 20 if the response of the upper sensor 34 indicates that water level 18
is at
or above the upper sensor 34. In other embodiments, the controller 38 can
include a timer that energizes or de-energizes the pump 20 after a pre-set
time
delay. In still other embodiments, the controller 38 can be programmed to
adjust
(e.g., increase or decrease) the flow rate of the pump 20 in response to the
detected predetermined condition.
In certain embodiments, the controller 38 can be configured to provide
intelligent control of the pump 20 based on measurements relating to one or
more parameters of interest. In one embodiment, the controller 38 can include
microprocessors having programs for optimizing operation of the pump 20. For
instance, the controller 38 can be programmed to calculate the rate of change
of
the height of the water column 21 by measuring the time required for the water
column 21 to transition between the lower sensor 32 and the upper sensor 34.
The controller 38 can utilize the results of this calculation to determine
whether
the pump 20 should be energized / de-energized, whether a time delay should be
used before adjusting operation of the pump 20, and/or to determine the type
and
magnitude of adjustment to the flow rate of the pump 20.
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Additionally, in certain embodiments, parameters of interest relating to
methane or water production and/or wellbore conditions may be utilized by the
controller 38 to optimize operation of the pump 20. For example, a sensor :39
at
the wellhead 26 (or other location) can provide information on production flow
rate of methane and/or water to the controller 38. Parameters relating to
wellbore conditions include fluid inflow, pressure and temperature.
Optimization
models provided in the controller 38 can utilize this information to maintain
the
height of the water column 21 within a pre-determined or calculated optimal
range. It should be appreciated that what constitutes optimal operation can
vary
with the operator, application and other factors. Exemplary optimal operation
can
include maximizing methane production, minimizing cycling of the pump 20,
minimizing the operating time of the pump 20, and reducing the risk of running
the pump dry (thus damaging the pump), etc.
Referring now to Fig. 2 there is shown one embodiment of a level sensor
50 suitable for use in the control system 30 (Fig. 1). The sensor 50 includes
a
probe 52 that produces a signal indicative of the thermal property of the
wellbore
fluid in which it is immersed. Wellbore fluids can include liquids such as
water
and gases such as methane. During production, the wellbore fluids such as
methane can have relatively high flow rates. In many instances, positioning
the
probe directly within the flowing gas can degrade the capacity of the sensor
50 to
make accurate measurements. Therefore, in some embodiments, one or more
probe shields 54 having vent holes 56 surrounds the probe 52. For illustrative
purposes only one shield 54 is shown. The shield 54 protects the probe 52 by
shielding it from direct splashing and exposure to vigorously turbulent or
bubbling
wellbore fluids and high velocity gas. The vent holes 56 allow the wellbore
fluids
to enter the shield 54 and envelope the probe 52. but keep the probe protected
from liquid splash and out of the direct channel of flowing gas. The cable 36
is
coupled to the probe 52 by a suitable wiring 38. In certain embodiments,
telemetry systems using RF, EMF, pressure waves or acoustics may be used in
lieu of or in addition the wiring 38. A pressure seal 42 may be used to
insulate
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the electrical connection between the cable 36 and the probe 52. In certain
applications, the cable 36 includes a mono-conductor cable. Thus, to operate
two probes over the mono-conductor cable, the sensor 50 includes a diode 40 to
allow selective control over either of the probes. In certain applications
other
sensors may be combined with the system on a separate or same cable to
produce a combination of measurements. One such example of this is the
addition of a down-hole pressure sensor.
One illustrative probe 52 is a resistance temperature detector RTD probe,
the use of which is described below. RTD is defined as any resistance
temperature detector. It consists of a resistive element that changes its
electrical
resistance as the temperature changes. This is commonly referred to as a
platinum resistor, RTD, or thermistor. Other devices also change their
resistance
due to temperature that can be made from copper, nickel or nickel-iron, or any
other electrical conductor that changes its resistance with respect to
temperature.
Referring now to Figs. 1-3, in one mode of operation, the controller 38
initiates
the transmission of a signal, such as an electrical signal, via the cable 36
to the
RTD probe 52. In one arrangement, the controller 38 is programmed to measure
the temperature differentials created by repetitively heating the probe 52 and
letting it cool down to ambient temperature. Fluid has both a higher thermal
capacity and thermal conductivity. Both properties influence the thermal
loading
effect. An RTD probe changes its electrical resistance with respect to
temperature and therefore an indication of temperature can be obtained by
several methods using applied current and voltage to the probe. The resultant
measurement represents a change in resistance of the probe that proportionally
is a measure of the effective temperature of the probe.
Fig. 3 illustrates an exemplary temperature versus time curve 60 for such
cyclic heating and cooling of the probe 52. As can be seen the temperature
curve 60 has two distinct portions. One portion 62 represents the response of
the probe 52 when immersed in a gas (e.g., air or methane) and the other
portion
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64 represents the response of the probe 52 when immersed in fluid. In the
exemplary curve 60, the probe 52 is energized at point 66. Because the probe
52 is immersed in gas, the resulting thermal loading is relatively light and
allows
the probe 52 to have a relatively substantial increase in temperature. Heating
is
terminated at point 68 to allow the probe to cool to ambient. Again, the probe
52
displays a relatively large temperature drop due to its immersion in gas. The
heating and cooling can be repeated as needed to gather sufficient information
to
characterize the behavior of the probe 52. At point 70, the probe 52 becomes
immersed in a fluid. Heating at point 72 of the probe 52 results in a
relatively
lower temperature increase due to the relatively high thermal loading caused
by
the water. At point 74, the probe 52 is de-energized and allowed to cool to
ambient temperature. In like fashion, the temperature drop is relatively small
because of the high thermal loading caused by the fluid. It should be
appreciated
that the temperature differential between points 66 and 68 is greater than the
temperature differential between points 72 and 74. Thus, by measuring the
temperature differential, the controller 38 can determine whether the RTD
probe
52 is immersed in water or is above water line 18. It should be appreciated
that
no mechanical co-action is needed between any component of the sensor 50 and
the fluid being sensed; i.e., no element of the sensor 50 is designed to
mechanically move in order to make a measurement. Thus, advantageously, the
risk that the sensor 50 will suffer a premature failure is reduced because a
prevalent mode of failure (mechanical failure) has been largely eliminated.
In another arrangement the sensor may include a first element for heating
the surrounding fluid and a second element for measuring the temperature (or
temperature change) in the surrounding fluid. With this methodology a similar
result of identifying the difference in thermal properties between the gas and
fluid
can be achieved. This arrangement can allow for measurement of thermal
conductivity or heat capacity. Both properties are substantially different and
uniquely identifiable in the two mediums.
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CA 02462466 2004-03-30
It should be understood that other methodologies can be employed to
determine the nature and magnitude of a given thermal loading. For example,
the curves connecting points 66 and 68 and points 72 and 74 may have unique
and distinct characteristics; e.g., different slopes, different rates of
change of
slopes during heating or cooling, etc. Thus, analysis and quantification of
the
characteristics of the curves can lead to additional methods for use in
determining thermal loading (e.g., measuring rate of change of slopes,
frequency
change, curve characteristics). In addition to using the distinctive thermal
properties of liquids and gases such as thermal conductivity, specific heat,
and
head capacity, as a criteria for determining the type of fluid in which a
probe is
immersed, other properties such as resistivity, conductivity, capacitance,
inductive, magnetic, electromagnetic, optical, viscosity, density, surface
tension,
compressibility speed of sound, sonic impendence, fluid or gas properties and
chemical properties may be used as the basis for making such determinations.
Referring now to Fig. 4, there is shown an exemplary control system
utilizing the sensors 32, 34. The system of Fig. 4 includes the upper level
sensor
34, the lower level sensor 32, the processor or controller 38, a power source
such as a current source 80, and a pump control unit 82. The sensors 32, 34,
processor 38 and the current source 80 are operably coupled by a suitable data
conduit or carrier 36. In response to a command signal issued by the processor
38, the current source 80 generates an electrical signal for heating the
sensors
32, 34. The current output by the source 80 is also used for doing a two-point
resistance measurement utilizing the sensors 32 and 34. The processor 38
measures the response of the sensor 32, 34 to determine whether their thermal
loading is indicative of a surrounding gas or liquid. Based on the
determination,
the processor 38 operates a pump control unit 82 having one or more relays 84
that are coupled to the pump (not shown). For example, the processor 38 opens
and closes the relays 84 as necessary to control the operation of the pump
(not
shown). The pump controller may also communicate directly with the processor
38 via a direct digital interface, serial or parallel data bus or analog data
transfer.
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(not shown). Diodes 86, 88 can be used to selectively energize or actuate the
sensors 32, 34 (i.e., the sensors 32, 34 operate at opposite polarities). In
addition to being advantageous where a carrier 36 includes a mono-conductor,
such an arrangement also readily allows the substantially simultaneous heating
of one sensor and the cooling of the other sensor.
Referring now to Fig. 5, there is shown another embodiment of the
present invention using a single sensor 90 operable coupled to a downhole
control unit 92 for operating a pump 94. Merely for illustrative purposes, the
single sensor 90 is shown having a heating element 91a separate from a
temperature probe 91b. In the Fig. 5 embodiment, the control unit 92, in one
mode of operation operates the pump 94 until a specified condition has been
met, e.g., the response of the sensor 90 indicates that the height of the
water
column 96 has dropped below the sensor 90. Upon occurrence of the condition,
the control unit 92 stops operation of the pump 94. The control unit 92 can be
programmed to re-initiate operation of the pump 94 after a pre-set or
predetermined time delay, or after the water column 96 has reached a specified
height, or the detection of some other specified condition. Additionally, the
control unit 92 can include microprocessors that process measurements of
parameters relating to wellbore conditions or production to optimize control
of the
pump 94. The control unit 94 can be programmed to operate in a closed loop
fashion (i.e., automatically) or with human intervention. The power source
(not
shown) for activating (e.g., heating and resistivity measurements) the sensor
90
can be integrated into the control unit 94 or can be constructed as a separate
unit. Moreover, power can be transmitted from a surface source (not shown) or
provided from a local source such as a battery, or obtained from the power
provided on the cable driving a downhole electrical' submersible pump (not
shown).
Further, it should be appreciated that the teachings of the present
invention extend beyond controlling downhole devices. The control unit 92 can
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transmit data to surface equipment such as a display device 93a, an alarm 93b
or a data recorder 93c via a suitable telemetry link 95, (e.g., hard-wire,
acoustic
signals, RF, EMF, etc.). The display device 93a can be used to provide the
operator with a real-time or near real-time indication of the location of the
fluid
interface. The alarm 93b can be configured to signal that a predetermined
condition has been detected in the well. The data recorder 93c can be used to
recorded liquid interface movement data, as well as other data such as
production rates, weilbore conditions (e.g., pressure, temperature, etc.) that
can
be used for extended monitoring of the reservoir. It should be understood that
the display device 93a, an alarm 93b or a data recorder 93c are merely
illustrative of devices that utilize the information provided by the fluid
level sensor
90 for purposes other than controlling downhole devices. Devices such as these
(separately or in combination) can be used in addition to or in lieu of a
control
unit for operating a downhole device such as a pump.
Referring now to Fig. 6, in certain embodiments, a pump control system
100 operates a pump 102 based on an estimated height for a water column 104.
The control system 100 includes a first sensor 106, a second sensor 108 and a
control unit 110. The control unit 110 is programmed with pre-determined
switch-
points P1 and P2 for controlling the pump 102. The points P1 and P2 are points
that if reached by the water column 104 will trigger an adjustment to pump
operation (e.g., increasing/decreasing flow rate). The sensors 106, 108 are
not
positioned at the points P1 and P2. Rather, the sensors 106, 108 are position
within the points P1 and P2. As will be discussed below, the control unit 110
utilizes the measurements from the sensors 106, 108 to extrapolate the height
of
the water column 104 and, based on this extrapolation, operate the pump 102.
In one method of operation, the control unit 110 measures the time
needed for the fluid level to transition between the two sensors 106, 108.
Based
on this measurement, an effective inflow rate. an effective pump-off rate, or
differential of the inflow and pump-off rate can be determined. Using this
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information, the control unit 110 can calculate a rate of change (e.g.,
increase or
decrease) of the height of the water column 104. Based on this calculated rate
of
change, the control unit 110 can estimate the time required for the height of
the
water column to reach point P1 from sensor 108 or point P2 from sensor 106.
The estimated time, in turn, is used to adjust operation of the pump, e.g.,
setting
the optimal time to energize or de-energize the pump, selecting an opfimal
adjustment to the pump flow rate, etc. In certain applications, the control
unit 110
can use additional data such as known wellbore / production tubing geometry
(e.g., internal volume of the wellbore), a known inflow or pump off
relationship,
and measurements from other sensors (e.g., pressure sensors) in the wellbore
in
the calculations. It should thus be appreciated that the Fig. 6 embodiment
creates a "virtual" sensor position extending well beyond one or both of the
physical sensor positions.
In another mode of operation, the control unit 110 uses the calculated rate
of increase / decrease in the height of the water column 104 to interpolate
between the two sensors 106,108 to determine the height of the water column
104. Thus, at any given time, the control unit 110 can determine the
approximate
height of the water column 104. This information can be used to provide
enhanced control over the pump 104. For example, the flow rate of the pump
104 can be adjusted to maintain a specified height for the water column 104.
It
should also be appreciated that the switch points P1 and P2 can be adjusted
over time to account for changes in the reservoir. Further, both sensors '106,
108 need not be within switch points P1 and P2. For instance, in some
embodiments, one of the sensors 106 or 108 is positioned at the switch point
P2
or P1.
From the above, it should be appreciated that the teachings of the present
invention include, but are not limited to, systems and methods for
investigating
the nature of materials, such as wellbore fluids. in a well adapted to produce
hydrocarbons. While sensors for measuring thermal loading have been
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discussed above, any non-mechanical sensor adapted to produce distinct and
different responses upon encountering a gas or liquid may used to achieve a
similar functional control. By "non-mechanical" it is meant a sensor that does
not
utilize motion or a physical co-action between the sensed fluid and the sensor
to
produce a measurement. As discussed previously, mechanical sensors such as
pressure transducers employ mechanical parts that, due to repeated movement
and/or a harsh, corrosive wellbore environment, tend to prematurely fail.
Additionally, the control systems utilizing such non-mechanical sensors
are not limited to only downhole pumps. For instance, in certain embodiments,
such sensors can be positioned inside production tubing extending through
multiple production zones. One or more flow control devices (e.g., valves) can
be used to control the in-flow of formation fluids at each of the production
zones.
A control unit uses the measurements from the sensors to identify the nature
and
make up of the fluid in the tubing (e.g., determining gas-oil, gas-water, or
oil-
water ratios). Based on the determinations, the control unit issues
appropriate
control signals to a flow control device such as a valve to adjust in-flows.
It should also be appreciated that the teachings of the present invention
are not limited to any particular number of sensors. For example, in certain
applications three or more sensors may be used. Indeed, some applications
requiring a relatively precise determination of a fluid level height may
utilize
dozens or hundreds of sensors. For instance, a ribbon-like member can be
overlaid with resistive elements distributed at spaced-apart intervals. In
such
arrangements, an enabling device can be configured to selectively enable the
resistive elements in a manner that identifies the location of the first
liquid-second
liquid interface. The enabling device can, for example, utilize a specified
voltage
level, frequency and/or polarity to selectively enable the sensors.
Additionally,
the sensors can be addressable in certain applications to facilitate selective
enablement of a plurality of sensors.
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From the above, it should be appreciated that the teachings of the present
invention include one or more non-mechanical fluid level sensors that are
strategically deployed in body of fluid. While the described embodiments are
described in the context of fluids in a wellbore, the sensed fluids can be in
an
underground storage tank, a storage cavern, or an above-ground tank.
Moreover, the fluid can be a natural body of water (such as a lake or stream)
or a
body of water that are created during special circumstances (e.g., flood
waters in
an under-pass for a road). Indeed, the teachings of the present invention can
be
advantageously applied in nearly any situation where it is desirable to
monitor,
record or take responsive action to changes in height of a body of fluid.
Furthermore, while embodiments of the present invention were discussed in
connection with determining the location of gas-water interface, the present
teachings can also be used to determine the location of a liquid-liquid
interface
(e.g., a water-oil interface).
The foregoing description is directed to particular embodiments of the
present invention for the purpose of illustration and explanation. It will be
apparent, however, to one skilled in the art that many modifications and
changes
to the embodiment set forth above are possible without departing from the
scope
and the spirit of the invention. It is intended that the following claims be
interpreted to embrace all such modifications and changes.
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