Note: Descriptions are shown in the official language in which they were submitted.
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WIRELESS DOWNHOLE WELL INTERVAL INFLOW
AND INJECTION CONTROL
BACKGROUND OF THE INVENTION
FIELD OF THE INVENTION
The present invention relates to a petroleum well for producing petroleum
products.
In one aspect, the present invention relates to systems and methods of
electrically controlling
downhole well interval-inflow and/or injection for producing petroleum
products.
DESCRIPTION OF THE RELATED ART
Attainment of high recovery efficiency from thick hydrocarbon reservoirs,
requires
uniform productivity from wells completed over long intervals.
In vertical wells, the open intervals typically include a number of geologic
layers
having a variety of petrophysical properties and initial reservoir conditions.
Variations in
permeability and initial reservoir pressure especially, result in uneven
depletion of layers, if
the layers are produced as a unit with a single draw-down pressure. As the
field is produced,
high permeability layers are depleted faster than tight layers, and high
pressure layers may
even cross-flow into lower pressure layers.
In horizontal wells, the open completion interval is usually contained in a
single
geologic layer. However, uneven inflow can result from a pressure drop along
the well. This
effect is particularly evident in long completion intervals where the
reservoir pressure is
nearly equal to the pressure in the well at the far end (the toe). In such a
case, almost no
inflow occurs at the toe. At the other end of the open interval near the
vertical part of the
well (the heel), the greater difference between the reservoir pressure and the
pressure in the
well results in higher inflow rates there. High inflow rates near the heel can
lead to early gas
breakthrough from gas coning down, or early water breakthrough from water
coning up.
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Productivity profiles of vertical wells are described by the steady state
Darcy flow
equation for radial flow:
_ 27rkk,hAp
RR ,uln(re1r,v) (1)
where
qR = flow rate [13t1]
k = absolute permeability [ 12 ]
k, = relative permeability [ unitless ]
,&p = pressure draw-down = reservoir pressure-well pressure [ m 171 f2 ]
tu = viscosity [ m 171 f I]
re = outer radius of reservoir [ 1]
rw = well radius [ 1]
h = length of open interval [ 1]
Each flowing fluid may be described by this equation. In most wells, we need
to
account for flow of the gas, oil, and water. In the initial phase of
production of a field,
reservoir pressure is usuaily large. If large draw-down pressures are applied,
inflow profiles
will be uniform for layers with similar permeabilities because variations in
initial reservoir
pressure of layers are usually smaller than the draw-down pressure. As the
well is produced
and layers are depleted, the reservoir pressure affects the productivity
profiles to a greater
extent because some layers may have a small draw-down, even if the well is
produced at its
lowest pressure. Variations in permeability among layers may arise from (1)
differences in
grain size, sorting, and packing, or (2) from interference of flowing fluids,
i.e., the relative
permeability. The former-grain mineral framework-is not expected to change the
productivity profile very much during the life of the well because the grain
framework
remains unchanged, except for compaction. But compaction can equalize layer
permeabilities. The effects of fluid saturation on pemneability lead to poor
productivity
profiles because, for example, a high permeability layer is likely to have a
high specific fluid
saturation, which makes that layer even more productive. During the life of a
well these
saturation effects can lead to even poorer profiles because, for example, gas
or water
breakthrough into a well results in increasing breakthrough fluid saturation
and even higher
productivity of that fluid relative to the other layers.
Productivity profiles in horizontal wells may be affected by layering if the
well
intersects dipping beds or if the horizontal well is slightly inclined and
crosses an
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impermeable bed. However, the major effect is expected to be the difference in
draw-down
pressure between the toe and the heel.
The problems associated with poor productivity profiles in wells with long
interval
completions have been addressed in a recent patent application entitled
"Minipumps in a
Drainhole Section of a Well", filed 15 September 1999, inventors M.E. Amory,
R. Daling,
C.A. Glandt, R.N. Worrall, EPC Patent Application no. 99203017.1. This method
proposes the use of several annular pumping devices located along the open
interval of the
well to offset the pressure drop due to flow in the well and thereby increase
the inflow at
the toe of the well.
Wells may also be used for fluid injection. For example, water flooding is
sometimes
used to displace hydrocarbons in the formation towards producing wells. In
water flooding, it
is desirable to have uniform injection. Hence with fluid injection, the same
issues arise with
respect to ensuring uniform injection as those mentioned above for seeking
uniform inflow,
and for the same reasons.
Conventional packers are known such as described in U.S. Patents 6,148,915,
6,123,148, 3,566,963 and 3,602,305.
BRIEF SITMMA.RY OF THE INVENTION
The problems and needs outlined above are largely solved and met by the
present
invention. In accordance with one aspect of the present invention, a petroleum
well for
producing petroleum products, is provided. 1'he petroleum well comprises a
well casing, a
production tubing, a source of tinie-varying current, and a downhole
controllable well
section. The well casing extends within a wellbore of the well, and the
production tubing
extends within the casing. The source of time-varying current is at the
surface, and
electrically connected to the tubing and/or the casing, such that the tubing
and/or the casing
acts as an electrical conductor for transmitting time-varying electrical
current from the
surface to .a downhole location. The downhole controllable well section
comprises a
communications and control module, a sensor, an electrically controllable
valve, and an
induction choke. The communications and control module is electrically
connected to the
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tubing and/or the casing. The sensor and the electrically
controllable valve are electrically connected to the
communications and control module. The electrically
controllable valve is adapted to regulate flow between an
exterior of the tubing and an interior of the tubing. The
induction choke is located about a portion of the tubing
and/or the casing. The induction choke is adapted to route
part of the current through the communications and control
module by creating a voltage potential within the tubing
and/or the casing between one side of the induction choke
and another side of the induction choke. The communications
and control module is electrically connected across this
voltage potential. The downhole controllable well section
may further comprise a flow inhibitor located within the
casing and about another portion of the tubing such that
fluid flow within the casing from one side of the flow
inhibitor to another side of the flow inhibitor is hindered
by the flow inhibitor. In an embodiment with multiple well
sections, a flow inhibitor may be used to define a boundary
between the well sections. The sensor may be a fluid flow
sensor, a fluid pressure sensor, a fluid density sensor, or
an acoustic waveform transducer.
In accordance with a related aspect of the present
invention, there is provided a petroleum well for producing
petroleum products comprising: a perforated section having a
plurality of perforated sections in at least a portion
thereof extending within a wellbore of said well; a
production tubing extending within said perforated section;
a source of time-varying current at the surface, said
current source being electrically connected to at least one
of said tubing and said perforated section, such that at
least one of said tubing and said perforated section acts as
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an electrical conductor for transmitting time-varying
electrical current from the surface to a downhole location;
a downhole controllable well section comprising a
communications and control module, a sensor, and an
electrically controllable valve, said communications and
control module being electrically connected to at least one
of said tubing and said perforated section, said sensor and
said electrically controllable valve being electrically
connected to said communications and control module, and
said electrically controllable valve being adapted to
regulate flow between an exterior of said tubing and an
interior of said tubing based at least in part on sensor
measurements; and at least one additional downhole
controllable well sections, each of said well sections being
divided from each other by a flow inhibitor, and each well
section comprising a sensor and an electrically controllable
valve, said electrically controllable valves of said
additional well sections being adapted to regulate flow
between said tubing exterior and said tubing interior, said
flow inhibitors being located within said perforated
sections and about other portions of said tubing such that
fluid flow within said perforated sections at each of said
flow inhibitors is hindered by said flow inhibitors.
In accordance with another aspect of the present
invention, there is provided a use of the petroleum well as
described herein for producing petroleum, wherein said flow
inhibitors are capable of hindering fluid flow between said
well sections within said casing; each of said sensors is
capable of measuring a fluid characteristic at each of said
respective well sections; each of said electrically
controllable valve is capable of regulating fluid flow into
said tubing at one or more of said respective well sections
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based on said fluid characteristic measurements; and petroleum
products produced from said well are via said tubing.
In accordance with another aspect of the present
invention, there is provided a use of the petroleum well as
described herein for controllably injecting fluid into a
formation with a well, wherein said flow inhibitors are
capable of hindering fluid flow between said well sections
within said casing; each of said sensors is capable of
measuring fluid characteristic at each of said respective
well sections; fluid is controllably injected into said
tubing; and each of said electrically controllable valve is
capable of regulating fluid flow from said tubing interior
into said formation at one or more of said respective well
sections based on said fluid measurements.
In accordance with another aspect of the present
invention, a method of producing petroleum from a petroleum
well is provided. The method comprises the following steps,
the order of which may vary: (i) providing a plurality of
downhole controllable well sections of the well for at least
one petroleum production zone, each of the well sections
comprising a communications and control module, a flow
sensor, an electrically controllable valve, and a flow
inhibitor, the flow inhibitor being located within a well
casing and about a portion of a production tubing of the
well, the communications and control module being
electrically connected to the tubing and/or the casing, and
the electrically controllable valve and the flow sensor being
electrically connected to the communications and control
module; (ii) hindering fluid flow between the well sections
within the casing with a flow inhibitor; (iii). measuring
fluid flow between the at least one petroleum production zone
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and an interior of the tubing at each of the well sections
with its respective flow sensor; (iv) regulating fluid flow
between the at least one petroleum production zone and the
interior of the tubing at each of the well sections with its
respective electrically controllable valve, based on the
fluid flow measurements; and (v) producing petroleum products
from the well via the tubing.
The method may further comprise the following
steps, the order of which may vary: (vi) inputting a time-
varying current into the tubing and/or the casing from a
current source at the surface; (vii) impeding the current
with an induction choke located about the tubing and/or the
casing; (viii) creating a voltage potential between one side
of the induction choke
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and another side of the induction choke within the tubing and/or the casing;
(ix) routing the
current through at least one of the communications and control modules at the
voltage
potential using the induction choke; and (x) powering at least one of the
communications and
control modules using the voltage potential and the current from the tubing
and/or the casing.
Also, the method may further comprise the following steps, the order of which
may vary:
(xi) transmitting the fluid flow measurements to a computer system at the
surface using the
communications and control module via the tubing a nd/or the casing; (xii)
calculating a
pressure drop along the well sections, with the computer system, and using the
fluid flow
measurements; (xiii) determining if adjustments are needed for the
electrically controllable
valves of the well sections; (xiv) if valve adjustments are needed, sending
command signals
to the communications and control modules of the well sections needing valve
adjustment;
and (xv) also if valve adjustments are needed, adjusting a position of the
electrically
controllable valve via the communications and control module for each of the
well sections
needing valve adjustment.
In accordance with yet another aspect of the-present invention, a method of
controllably injecting fluid into a formation with a well is provided. The
method comprises
the following steps, the order of which may vary: (i) providing a plurality,of
controllable
well sections of the well for the formation, each of the well sections
comprising a
communications and control module, a flow sensor, and an electrically
controllable valve,
and a flow inhibitor, the communications and control module being electrically
connected to
the tubing and/or the casing, the electrically controllable valve and the flow
sensor being
electrically connected to the communications and control module, and the flow
inhibitor
being located within a well casing and about a portion of a tubing string of
the well; (ii)
hindering fluid flow between the well sections within the casing with the flow
inhibitors; (iii)
measuring fluid flow from an interior of the tubing into the formation at each
of the well
sections with its respective flow sensor; (iv) regulating fluid flow from the
tubing interior into
the formation at each of the well sections with its respective electrically
controllable valve,
based on the fluid flow measurements; and (v) controllably injecting fluid
into the formation
with the well.
The method may further comprise the following steps, the order of which may
vary:
(vi) inputting a time-varying current into the tubing and/or the casing from a
current source at
the surface; (vii) impeding the current with an induction choke located about
the tubing
and/or the casing; (viii) creating a voltage potential between one side of the
induction choke
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and another side of the induction choke within the tubing and/or the casing;
(ix) routing the
current through at least one of the communications and control modules at the
voltage
potential using the induction choke; and (x) powering the at least one of the
communications
and control modules using the voltage potential and the current from the
tubing and/or the
casing. Also, the method may further comprise the following steps, the order
of which may
vary: (xi) transmitting the fluid flow measurements to a computer system at
the surface using
the communications and control module via the tubing and/or the casing; (xii)
calculating a
pressure drop along the well sections, with the computer system, using the
fluid flow
measurements; (xiii) determining if adjustments are needed for the
electrically controllable
valves of the well sections; (xiv) if valve adjustments are needed, sending
command signals
to the communications and control modules of the well sections needing valve
adjustment;
and (xv) also if valve adjustments are needed, adjusting a position of the
electrically
controllable valve via the communications and control module for each of the
well sections
needing valve adjustment.
The Related Applications describe ways to deliver electrical power to downhole
devices, and to provide bi-directional communications between the surface and
each
downhole device individually. The downhole devices may contain sensors or
transducers to
measure downhole conditions, such as pressure, flow rate, liquid density, or
acoustic
waveforms. Such measurements can be transmitted to the surface and made
available in
near-real-time. The downhole devices may also comprise electrically
controllable valves,
pressure regulators, or other mechanical control devices that can be operated
or whose set-
points may be changed in real time by commands sent from the surface to each
individual
device downhole. Downhole devices to measure and control inflow or injection
over long
interval completions are placed within well sections. The measured flow rates
are used to
control accompanying devices, which are used to regulate inflow from or
injection into
subsections of the completion.
BRIEF DESCRIPTION OF THE DRAWINGS
Other objects and advantages of the invention will become apparent upon
reading the
following detailed description and upon referencing the accompanying drawings,
in which:
FIG. lA is schematic of an upper portion of a petroleum well in accordance
with a
preferred embodiment of the present invention;
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FIG. 1 B is schematic of an upper portion of a petroleum well in accordance
with
another preferred embodiment of the present invention;
FIG. 2 is a schematic of a downhole portion of a petroleum production well in
accordance with a preferred embodiment of the present invention;
FIG. 3 is an enlarged view of a portion of FIG. 2 showing a well section of
the
petroleum production well;
FIG. 4 graphs cumulative pressure drop along production tubing as a function
of
distance along the tubing for a range of differences between reservoir
pressure and well toe
pressure; and
FIG. 5 graphs relative inflow rate as a function of distance along the tubing
for a
range of differences between the reservoir pressure and the pressure at the
toe of the well.
DETAILED DESCRIPTION OF THE INVENTION
Referring now to the drawings, wherein like reference numbers are used herein
to
designate like elements throughout the various views, a preferred einbodiment
of the present
invention is illustrated and further described, and other possible embodiments
of the present
invention are described. The figures are not necessarily drawn to scale, and
in some
instances the drawings have been exaggerated and/or simplified in places for
illustrative
purposes only. One of ordinary skill in the art will appreciate the many
possible applications
and variations of the present invention based on the following examples of
possible
embodiments of the present invention, as well as based on those embodiments
illustrated and
discussed in the Related Applications, which are incorporated by reference
herein to the
maximum extent allowed by law.
As used in the present application, a "piping structure" can be one single
pipe, a
tubing string, a well casing, a pumping rod, a series of interconnected pipes,
rods, rails,
trusses, lattices, supports, a branch or lateral extension of a well, a
network of interconnected
pipes, or other similar structures known to one of ordinary skill in the art.
A preferred
embodiment makes use of the invention in the context of a petroleum well where
the piping
structure comprises tubular, metallic, electrically-conductive pipe or tubing
strings, but the
invention is not so limited. For the present invention, at least a portion of
the piping structure
needs to be electrically conductive, such electrically conductive portion may
be the entire
piping structure (e.g., steel pipes, copper pipes) or a longitudinal extending
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conductive portion combined with a longitudinally extending non-conductive
portion. In
other words, an electrically conductive piping structure is one that provides
an electrical
conducting path from a first portion where a power source is electrically
connected to a
second portion where a device and/or electrical return is electrically
connected. The piping
structure will typically be conventional round metal tubing, but the cross-
section geometry of
the piping structure, or any portion thereof, can vary in shape (e.g., round,
rectangular,
square, oval) and size (e.g., length, diameter, wall thickness) along any
portion of the piping
structure. Hence, a piping structure must have an electrically conductive
portion extending
from a first portion of the piping structure to a second portion of the piping
structure, wherein'
the first portion is distally spaced from the second portion along the piping
structure.
Also note that the term "modem" is used herein to generically refer to any
communications device for transmitting and/or receiving electrical
communication signals
via an electrical conductor (e.g., metal). Hence, the term "modem" as used
herein is not
limited to the acronym for a modulator (device that converts a voice or data
signal into a form
that can be transmitted)/demodulator (a device that recovers an original
signal after it has
modulated a high frequency carrier). Also, the term "modem" as used herein is
not limited to
conventional computer modems that convert digital signals to analog signals
and vice versa
(e.g., to send digital data signals over the analog Public Switched Telephone
Network). For
example, if a sensor outputs measurements in an analog format, then such
measurements may
only need to be modulated (e.g., spread spectrum modulation) and transmitted--
hence no
analog/digital conversion needed. As another example, a relay/slave modem or
communication device may only need to identify, filter, amplify, and/or
retransmit a signal
received.
The term "valve" as used herein generally refers to any device that functions
to
regulate the flow of a fluid. Examples of valves include, but are not limited
to, bellows-type
gas-lift valves and controllable gas-lift valves, each of which may be used to
regulate the
flow of lift gas into a tubing string of a well. The internal and/or external
workings of valves
can vary greatly, and in the present application, it is not intended to limit
the valves described
to any particular configuration, so long as the valve functions to regulate
flow. Some of the
various types of flow regulating mechanisms include, but are not limited to,
ball valve
configurations, needle valve configurations, gate valve configurations, and
cage valve
configurations. The methods of installation for valves discussed in the
present application
can vary widely.
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The term "electrically controllable valve" as used herein generally refers to
a "valve"
(as just described) that can be opened, closed, adjusted, altered, or
throttled continuously in
response to an electrical control signal (e.g., signal from a surface computer
or from a
downhole electronic controller module). The mechanism that actually moves the
valve
position can comprise, but is not limited to: an electric motor; an electric
servo; an electric
solenoid; an electric switch; a hydraulic actuator controlled by at least one
electrical servo,
electrical motor, electrical switch, electric solenoid, or combinations
thereof; a pneumatic
actuator controlled by at least one electrical servo, electrical motor,
electrical switch, electric
solenoid, or combinations thereof; or a spring biased device in combination
with at least one
electrical servo, electrical motor, electrical switch, electric solenoid, or
combinations thereof.
An "electrically controllable valve" may or may not include a position
feedback sensor for
providing a feedback signal corresponding to the actual position of the valve.
The term "sensor" as used herein refers to any device that detects,
determines,
monitors, records, or otherwise senses the absolute value of or a change in a
physical
quantity. A sensor as described herein can be used to measure physical
quantities including,
but not limited to: temperature, pressure (both absolute and differential),
flow rate, seismic
data, acoustic data, pH level, salinity levels, valve positions, or almost any
other physical
data.
The phrase "at the surface" as used herein refers to a location that is above
about fifty
feet deep within the Earth. In other words, the phrase "at the surface" does
not necessarily
mean sitting on the ground at ground level, but is used more broadly herein to
refer to a
location that is often easily or conveniently accessible at a wellhead where
people may be
working. For example, "at the surface" can be on a table in a work shed that
is located on the
ground at the well platform, it can be on an ocean floor or a lake floor, it
can be on a deep-sea
oil rig platform, or, it can be on the 100th floor of a building. Also, the
term "surface" may be
used herein as an adjective to designate a location of a component or region
that is located "at
the surface." For example, as used herein, a "surface" computer would be a
computer located
"at the surface."
The term "downhole" as used herein refers to a location or position below
about fifty
feet deep within the Earth. In other words, "downhole" is used broadly herein
to refer to a
location that is often not easily or conveniently accessible from a wellhead
where people may
be working. For example in a petroleum well, a "downhole" location is often at
or proximate
to a subsurface petroleum production zone, irrespective of whether the
production zone is
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accessed vertically, horizontally, or any other angle therebetween. Also, the
term
"downhole" is used herein as an adjective describing the location of a
component or region.
For example, a "downhole" device in a well would be a device located
"downhole," as
opposed to being located "at the surface."
Similarly, in accordance with conventional terminology of oilfield practice,
the
descriptors "upper," "lower," "uphole," and "downhole" are relative and refer
to distance
along hole depth from the surface, which in deviated or horizontal wells may
or may not
accord with vertical elevation measured with respect to a survey datum.
As used in the present application, "wireless" means the absence of a
conventional,
insulated wire conductor e.g. extending from a downhole device to the surface.
Using the
tubing and/or casing as a conductor is considered "wireless."
Conventional horizontal wells are typically completed with perforated casings
or
screened liners, some of which may be several thousand feet long and four to
six inches in
diameter. For wells that are prolific producers, the horizontal liner conducts
all of the flow to
a vertical section. Production tubing and a packer may be placed within a
vertical well casing
of the vertical section, where gas lift or other artificial lift may be
employed. However in
such conventional horizontal wells, the inflow rates of fluids from a
production zone at
various places along the extent of the horizontal well can vary greatly as the
zone is depleted.
Such variations can lead to an increased pressure drop along the horizontal
well and the
consequent excessive inflow rate near the heel of the well relative to the
toe, which is
typically not desirable. The present invention presents a solution to such
problems, as well as
others, by providing a well with controllable well sections.
FIG. lA is schematic of an upper portion of a petroleum well 20 in accordance
with a
preferred embodiment of the present invention. A well casing 30 and the tubing
string 40 act
as electrical conductors for the system. An insulating tubing joint 56 is
incorporated at the
wellhead to electrically insulate the tubing 40 from casing 30. Thus, the
insulators 58 of the
joint 56 prevent an electrical short circuit between lower sections of the
tubing 40 and casing
30 at the hanger 34. A surface computer system 36 comprising a master modem 37
and a
source of time-varying current 38 is electrically connected to the tubing
string 40 below the
hanger 34 by a first source terminal 39. The first source terminal 39 is
insulated from the
hanger 34 where it passes through it. A second source terminal 41 is
electrically connected to
the well casing 30, either directly (as in FIG. lA) or via the hanger 34
(arrangement not
shown).
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The time-varying current source 38 provides the time-varying electrical
current,
which carries power and communication signals downhole. The time-varying
electrical
current is preferably alternating current (AC), but it can also be a varying
direct current (DC).
The communication signals can be generated by the master modem 37 and embedded
within
the current produced by the source 38. Preferably, the communication signal is
a spread
spectrum signal, but other forms of modulation can be used in alternative.
As shown in FIG. 113, in alternative to or in addition to the insulated hanger
34, an
upper induction choke 43 can be placed about the tubing 40 above the
electrical connection
location for the first source terminal 39 to the tubing. The upper induction
choke 43
comprises a ferromagnetic material and is located generally concentrically
about the tubing
40. The upper induction choke 43 functions based on its size, geometry,
spatial relationship
to the tubing 40, and magnetic properties. When time-varying current is
imparted into the
tubing 40 below the upper choke 43, the upper choke 43 acts as an inductor
inhibiting the
flow of the current between the tubing 40 below the upper choke 43 and the
tubing 40 above
the upper choke 43 due to the magnetic flux created within the upper choke 43
by the current.
Thus, most of the current is routed down the tubing 40 (i.e., downhole),
rather than shorting
across the hanger 45 to the casing 30.
FIG. 2 is schematic of a downhole portion of a petroleum production well 20 in
accordance with a preferred embodiment of the present invention. The well 20
has a vertical
section 22 and a horizontal section 24. The well has a well casing 30
extending within a
wellbore and through a formation 32, and a production tubing 40 extends within
the well
casing. Hence, the we1120 shown in FIG. 2 is similar to a conventional well in
construction,
but with the incorporation of the present invention.
The vertical section 22 in this embodiment incorporates a packer 44 which is
furnished with an electrically insulating sleeve 76 such that the tubing 40 is
electrically
insulated from casing 30. The vertical section 22 is also furnished with a gas-
lift valve 42 to
provide artificial lift for fluids within the tubing using gas bubbles 46.
However, in
alternative, other ways of providing artificial lift may be incorporated to
form other possible
embodiments (e.g., rod pumping). Also, the vertical portion 22 can further
vary to form
many other possible embodiments. For example in an enhanced form, the vertical
portion 22
may incorporate one or more electrically controllable gas-lift valves, one or
more induction
chokes, and/or one or more controllable packers comprising electrically
controllable packer
valves, as described in the Related Applications.
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The horizontal section 24 of the we1120 extends through a petroleum production
zone
48 (e.g., oil zone) of the formation 32. The location where the vertical
section 22 and the
horizontal section 24 meet is referred to as the hee150, and the distal end of
the horizontal
section is referred to as the toe 52. At various locations along the
horizontal section 24, the
casing 30 has perforated sections 54 that allow fluids to pass from the
production zone 48
into the casing 30. Numerous flow inhibitors 61-65 are placed along the
horizontal section
24 in the annular space 68 between the casing 30 and the tubing 40. The
purpose of these
flow inhibitors 61-65 is to hinder or prevent fluid flow along the annulus 68
within the casing
30, and to thus separate or form a series of controllable well sections 71-75.
In the
embodiment shown in FIG. 2, the flow inhibitors 61-65 are conventional packers
with
electrically insulating sleeves to maintain electrical isolation between
tubing 104 and casing
54 (functionally equivalent to packer 44 with sleeve 76), which themselves are
known in the
art. However, any of the flow inhibitors 61-65 can be provided by any other
way that makes
the cross-sectional area of the annular space 68 (between the casing 30 and
the tubing 40)
small compared to the internal cross-sectional area of the tubing 40, while
maintaining
electrical isolation between tubing and casing. In other words, the flow
inhibitors 61-65 do
not necessarily need to forin fluid-tight seals between the well sections 71-
75, as
conventional packers typically do. Thus, for example, any of the flow
inhibitors 61-65 may
be (but is not limited to being): a conventional packer; a controllable packer
comprising an
electrically controllable packer valve, as described in the Related
Applications; a close-fitting
tubular section; an enlarged portion of tubing; a collar about the tubing; or
an inflatable collar
about the tubing. In an enhanced form, a controllable packer as a flow
inhibitor can provide
variable control over the fluid communication among well sections-such
controllable
packers are further described in the Related Applications.
Referring to FIGs. 2 and 3, each controllable well section 71-75 comprises a
communications and control module 80, a sensor 82, and an electrically
controllable valve
84. In a preferred embodiment, each well section 71-75 further comprises a
ferromagnetic
induction choke 90. But in alternative embodiments, the number of downhole
induction
chokes 90 may vary. For example, there may be one downhole induction choke 90
for two or
more well sections 71-75, and hence some of the well sections would not
comprise an
induction choke.
Power for the electrical components of the well sections 71-75 is provided
from the
surface using the tubing 40 and casing 30 as electrical conductors. Hence, in
a preferred
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embodiment, the tubing 40 acts as a piping structure and the casing 30 acts as
an electrical
return to form an electrical circuit in the well 20. Also, the tubing 40 and
casing 30 are used
as electrical conductors for communications signals between the surface (e.g.,
a surface
computer) and the downhole electrical devices within the controllable well
sections 71-75.
In the embodiment shown in FIGs. 2 and 3, there is a downhole induction choke
90
for each controllable well section 71-75. The downhole induction chokes 90
comprise a
ferromagnetic material and are unpowered. The downhole chokes 90 are located
about the
tubing 40, and each choke acts as a large inductor to AC in the well circuit
formed by the
tubing 40 and casing 30. The downhole chokes 90 function based on their size
(mass),
geometry, and magnetic properties, as described above regarding the upper
choke. The
material composition of the chokes 43, 90 may vary, as long as they exhibit
the requisite
magnetic properties needed to act as an inductor to the time-varying current,
which will
depend (in part) on the size of the current.
FIG. 3 is an enlarged view of a controllable well section 71 from FIG. 2.
Focusing on
the well section 71 of FIG. 3 as an example, the communications and control
module 80 is
electrically connected to the tubing 40 for power and/or communications. A
first device
terminal 91 of the communications and control module 80 is electrically
connected to the
tubing 40 on a source-side 94 of the downhole induction choke 90. And, a
second device
terminal 92 of the communications and control module 80 is electrically
connected to the
tubing 40 on an electrical-return-side 96 of the downhole induction choke 90.
When AC is
imparted into the tubing 40 at the surface, it travels freely downhole along
the tubing until it
encounters the downhole induction choke 90, which impedes the current flow
through the
tubing at the choke. This creates a voltage potential between the tubing 40 on
the source-side
94 of the downhole choke 90 and the tubing on the electrical-return-side 96 of
the choke.
Because the communications and control module 80 is electrically connected
across the
voltage potential formed by the downhole choke 90 when AC flows in the tubing
40, the
downhole induction choke 90 effectively routes most of the current through the
communications and control module 80. The voltage potential also forms between
the
source-side 94 of the tubing 40 and the casing 30 because the casing acts as
an electrical
return for the well circuit. Thus in alternative, the communications and
control module 80
can be electrically connected across the voltage potential between the tubing
40 and the
casing 30. If in an enhanced form one or more of the flow inhibitors 61-65 is
a packer
comprising an electrically powered device (e.g., sensor, electrically
controllable packer
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valve), the electrically powered device of the packer will likely also be
electrically connected
across the voltage potential created by the downhole choke 90, either directly
or via a nearby
communications and control module 80.
Referring again to FIG. 2, the packer 65 at the toe 52 provides an electrical
connection between the tubing 40 and the casing 30, and the casing 30 is
electrically
connected to the surface computer system (not shown) to complete the
electrical circuit
formed by the well 20. Because in this embodiment it is not desirable to have
the tubing 40
electrically shorted to casing 30 between the surface and the toe 52, it is
necessary to
electrically insulate part of the packers 44, 61, 62, 63, 64 between the
surface and the toe so
that they do not act as a shorts between the tubing 40 and the casing 30. Such
electrical
insulation of a flow inhibitor may be achieved in various ways apparent to one
of ordinary
skill in the art, including (but not limited to): an insulating sleeve about
the tubing at the flow
inhibitor location or about the flow inhibitor; an insulating coating on the
tubing at the flow
inhibitor location or on the radial extent of the flow inhibitor; a rubber or
urethane portion at
the radial extent of packer slips; forming packer slips from non-electrically-
conductive
materials; other known insulating means; or any combination thereof. In FIG.
3, the
intermediate packers 44, 61, 62, 63, 64 have an insulator at the radial extent
of each packer
where the packer contacts the casing 30 (e.g., the slips).
Other alternative ways to develop an electrical circuit using a piping
structure of a
well and at least one induction choke are described in the Related
Applications, many of
which can be applied in conjunction with the present invention to provide
power and/or
communications to the electrically powered downhole devices and to form other
embodiments of the present invention.
Referring again to FIG. 3, preferably, a tubing pod 100 holds or contains the
communications and control module 80, sensors 82, and electrically
controllable valves 84
together as one module for ease of handling and installation, as well as to
protect these
components from the surrounding environment. However, in other embodiments of
the
present invention, the components of the tubing pod 100 can be separate (i.e.,
no tubing pod)
or combined in other combinations. Also, there may be multiple tubing pods per
well
section, which may be powered using one or more induction chokes for creating
voltage
potential. Furthermore, multiple tubing pods may share a single communications
and control
module. The various combinations possible are vast, but the core of a
controllable well
section is having at least one communications and control module, at least one
sensor, and at
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least one electrically controllable valve therein. The contents of a
communications and
control module may be as simple as a wire connector terminal for distributing
electrical
connections from the tubing 40, or it may be very complex comprising, for
example (but not
limited to), a modem, a rechargeable battery, a power transformer, a
microprocessor, a
memory storage device, a data acquisition card, and a motion control card.
The tubing pod 100 shown in FIG. 3 has two sensors 82 and two electrically
controllable valves 84. Each valve 84 has an electric motor 102 coupled
thereto, via a set of
gears, for opening, closing, adjusting, or continuously throttling the valve
position in
response to command signals from the communications and control module 80. The
electrically controllable valves 84 regulate fluid flow between an exterior
(e.g., annulus 68,
production zone 48) of the tubing 40 and an interior 104 of the tubing 40. In
other
embodiments, the controlled-opening orifice of the tubing created by the valve
84 may be
controlled by the sensor 82, and may be actuated by the natural hydraulic
power in the
flowing well, by stored electrical power, or other ways. The orifice of the
valve 84 may
comprise a standard ball valve, a rotating sleeve, a linear sleeve valve, or
any other device
suitable to regulate flow. It may never be necessary to effect a complete shut-
off or closing
of the valve 84, but if needed, that type of valve may be used. Hence during
petroleum
production, fluids (e.g., oil) from the production zone 48 flow into the
casing 30 via the
perforated casing sections 54, and then into the tubing 40 via the
electrically controllable
valves 84. Each electrically controllable valve 84 can be independently
adjusted. Thus, for
example, differential pressures can be created between separate controllable
well sections 71-
75 along the producing interval to prevent excessive inflow rates near the
hee150 of the well
20 relative to the toe 52.
The sensors 82 in FIG. 3 are fluid flow sensors adapted to measure the fluid
flow
between the production zone 48 and the tubing interior 104. Flow sensors may
be used that
detect the fluid velocity quantitatively or only the relative rates compared
to the sensors in the
other well sections. Such sensors may utilize sonic, thermal conduction, or
other principles
known to those skilled in the art. Furthermore, in otlier embodiments, the
sensor or sensors
82 in a controllable well section 71-75 may be adapted to measure other
physical qualities,
including (but not limited to): absolute pressure, differential pressure,
fluid density, fluid
viscosity, acoustic transmission or reflection properties, temperature, or
chemical make-up.
The fluid flow measurements from the sensors 82 are provided to the
communications and
control module 80, which further handles the measurements.
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Preferably the communications and control module 80 comprises a modem and
transmits the flow measurements to the surface computer system within an AC
signal (e.g.,
spread spectrum modulation) via the tubing 40 and casing 30. Then, the surface
computer
system uses the measurements from one, some, or all of the sensors 82 in the
we1120 to
calculate the pressure drop along the horizontal well section 24, as further
described below.
Based on the downliole sensor measurements, it is determined whether
adjustments to the
downhole valves 84 are needed. If an electrically controllable downhole valve
84 needs
adjustment, the surface computer system transmits control commands to the
relevant
communications and control module 80 using the master modem and via the tubing
40 and
casing 30. The communications and control module 80 receives the control
commands from
the surface computer system and controls the adjustment of the respective
valve(s) 84
accordingly. In another embodiment, one or more of the communications and
control
modules 80 may comprise an internal logic circuit and/or a microprocessor to
locally
(downhole) calculate pressure differential based on the sensor measurements,
and locally
generate valve control command signals for adjusting the valves 84.
During operation, pressure draw-down in the well 20 may be accomplished by the
surface tubing valve/orifice 84 in a flowing well, or by artificial lift at
the bottom of the
vertical section 22. For example, such artificial lift may be provided by gas
lift, rod pumping,
submersible pumps, or other standard oil field methods.
Effective use of a flow measurement and regulation system provided by
controllable
well sections 71-75 depends on developing a control strategy that relates
measured flow
values to downhole conditions, and that develops an objective function for
controlling the
settings of the valves 84 (the flow regulators).
In horizontal well sections, the effect of differences in draw-down pressure
on
productivity can be demonstrated by calculating the pressure drop along the
horizontal
section 24 resulting from a distributed inflow of fluid from the formation.
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Example Horizontal Well Analysis:
L = length of entire open interval [ ft]
N = number of monitor points (subsections)
AL = L/N = spacing of monitors [ ft]
n = index of subsection ( from toe to heel )
QN = total flow rate from well [ b/d ]
pN = total pressure drop over open interval [ psi ]
PH = head loss from flow in well [(psi/ft) /(b/d) ]
dqf = specific inflow rate with uniform profile from formation into well [b/d
/ ft]
Aqf = inflow rate from formation into a subsection of the well [ b/d ]
Oqõ = flow rate in the well at subsection (n) [ b/d ]
Ap,, = pressure drop in subsection n = pH(AL)( Aqõ) [ psi ]
Assuming the well is subdivided into N well sections, from upstream (toe to
heel),
n = 1,2,3,4,...N (2)
With uniform inflow,
Aqf = AL(QN/L) [ 1, 1, 1, 1, ... 1] (3)
The flow rate in the well cumulates as inflow occurs from the toe to the heel,
Oqõ = AL(QN/L) [ 1, 2, 3, 4, ... N] (4)
The pressure drop in each subsection is assuined proportional to the flow
rate,
therefore,
Opõ = AL (Aqn )(Px) [ l, 2, 3, 4.... N] (5)
Adding the pressure drops in each subsection, the total pressure drop in the
well from
the toe to the successively downstream subsections is
pn = E~ Apn (6)
pn = y1 AL (Oqn )(Px) (n)(n+0/2) (7)
pn = AL (Aqn )(pH) [ 1, 3, 6, 10, 15.... N(N+1)/2 ] (8)
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ASSUMPTIONS:
length of entire open interval = 2500 ft
spacing of monitors = 100 ft
total flow rate from well = 2500 b/d
specific head loss in well = 10"4 psi / b/d / ft
Case 1: Inflow at Toe of Well, No Inflow along Interval
For a well in which all 2500 barrels are flowing through 2500 feet of the well
the
pressure drop would be:
(QN)( L )( pH ) = (2500)(2500)(10-4) = 625 psi (9)
Case 2: Uniform Inflow
For a well producing uniformly along 25 subdivisions (controllable well
sections), the
total pressure drop in its open interval, as calculated by Equation (8) is:
(Oqõ)( AL )( pH ) [N(N+1)/2] = (100)(100)(10-4) (25)(26)/2 = 325 psi. (10)
Case 3: Inflow Dependent upon Reservoir Pressure
The inflow rate into the well is proportional to the difference between the
reservoir
pressure and the pressure in the well. Because the pressures in the well along
the open
interval depend on flow rate, the inflow profile must be obtained by an
iterative calculation.
We define the reservoir pressure (pres) as some pressure (po) above the
highest pressure in the
well, that is, the pressure at the toe.
Pres = po + Ptoe (11)
The pressure difference between the reservoir pressure and the pressure in the
well at
locations downstream from the toe is:
Api = (P0 + Ptoe) - (Ptoe - pn) = Po + Pn (12)
i
Api = po + AL (Oqn )(Px) (n )(n+1) / 2 (13)
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In the first iteration, the cumulative flow and cumulative pressure drop along
the
tubing may be calculated by summing the inflow differential pressures (po +
p,,) and
normalizing the subsection differential pressures with that sum:
Sum Api = Y-iN Ap; (14)
Api
Normalized Api = Pi = (15)
Sum Api = Y-iN Api
The inflow rate of each subsection is proportional to this normalized
differential
pressure, therefore, the inflow rate of each subsection is:
qi = Pi (QN) / (AL) (16)
The cumulative flow occurring in the well is:
Q; = I q; (OL) , (17)
and the cumulative pressure drop in the well from the toe to the heel is:
pn1 Y, qi (OL)(Px) (18)
A second iteration is made by substituting these values for the pressure drops
into
Equation (12). Convergence is rapid-in this case only a few iterations are
needed. These
can be carried out by substituting successive values of põ1,2,3,.. in Equation
(15).
FIG. 4 presents the results of these pressure drop calculations for several
inflow
conditions. When all of the flow enters the well at the toe, (Case 1-Open End
Tubing), the
cumulative pressure drop along the tubing is large since each section of the
pipe experiences
the maximum pressure drop. When flow is uniform along the length of the
horizontal well
section, (Case 2-Uniform Inflow), smaller pressure drops occur near the toe
where flow
rates in the well are low. For the same total flow rate of 2500 b/d, the
uniform inflow case
results in only about half the total pressure drop (325 psi) compared to Case
1, where the total
pressure drop is 625 psi. When inflow is dependent on the reservoir pressure
(Case 3-Non-
Uniform Inflow), even lower pressure drops occur. If the reservoir pressure
only slightly
exceeds the well toe pressure, and the pressure drop in the well is large by
comparison, then
most of the inflow occurs near the heel. The lower limit occurs when the
reservoir pressure
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equals the well toe pressure (i.e., po = 0) In that case the total pressure
drop is 125 psi. The
upper limit, when reservoir pressure becomes large (po = oo), results in
uniform inflow.
FIG. 5 shows the calculated flow rates that result from various reservoir
inflow
conditions. The flow rates that occur along the horizontal well section under
the conditions
given above may be normalized with respect to the flow rates in a well with
uniform inflow.
These results demonstrate the high rates that can occur near the heel of a
horizontal well
when the pressure drop at the toe is small.
In operation, the wel120 is placed in production with the valves 84 (flow
regulators)
fully open, and the flow rates along the producing interval are measured by
the sensors 82
and transmitted to the surface computer system for analysis using the methods
previously
described. Based on the results of this analysis, the inflow rates in each
well section 71-75 of
the producing interval are determined. Generally, the goal will be to equalize
production
inflow per unit length along the interval, and this is accomplished by
transmitting commands
to individual inflow valves to reduce flow in controllable well sections 71-75
that are
showing high inflow. The adjusted flow profile is then derived from the flow
measurements
again, and further adjustments are made to the valves 84 to flatten the
production profile and
to try to create a pressure profile like that graphed in FIG. 5 for the
uniform inflow case, or to
modify a profile into any configuration desired.
The illustrative analysis example described above has been derived for the
case of a
horizontal well section 24. It will be clear that similar methods may be
applied to a long
completion in a vertical well or a vertical well section 22, with the same
controllable well
sections 71-75 and a similar analysis to derive the control strategy from the
measurements.
Note that the well management strategy is not assumed to be static. It is to
be
expected that as a reservoir is depleted the inflow profile will change. The
provision of
permanent downhole sensors and control devices allows dynamic control of
production from
controllable well sections to optimize recovery over the full life of the
well.
The same methods and principles are applicable to the inverse task of
controlled
interval injection, where fluids are passed into the tubing and dispersed
selectively into a
formation interval using controllable well sections in accordance with the
present invention,
for instance in a water flooding process.
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In other possible embodiments of the present invention, a controllable well
section
71-75 may further comprise: additional sensors; additional induction chokes;
additional
electrically controllable valves; a packer valve; a tracer injection module; a
tubing valve (e.g.,
for varying the flow within a tubing section, such as an application having
multiple branches
or laterals); a microprocessor; a logic circuit; a computer system; a
rechargeable battery; a
power transformer; a relay modem; other electronic components as needed; or
any
combination thereof.
The present invention also may be applied to other types of wells (other than
petroleum wells), such as a water production well.
It will be appreciated by those skilled in the art having the benefit of this
disclosure that this
invention provides a petroleum production well having controllable well
sections, as well as
methods of utilizing such controllable well sections to manage or optimize the
well
production. It should be understood that the drawings and detailed description
herein are to
be regarded in an illustrative rather than a restrictive manner, and are not
intended to limit the
invention to the particular forms and examples disclosed. On the contrary, the
invention
includes any further modifications, changes, rearrangements, substitutions,
alternatives,
design choices, and embodiments apparent to those of ordinary skill in the
art, without
departing from the spirit and scope of this invention, as defined by the
following claims.
Thus, it is intended that the following claims be interpreted to embrace all
such further
modifications, changes, rearrangements, substitutions, alternatives, design
choices, and
embodiments.
24
