WO 96124745 PCT/US96/02182
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COMPUTER CONTRO .RT) TinWmr-rnr t~ ~rnnr c
FOR PRODUCTION WEr.r ~ ~gOr
B~ckero nd of the r,yention
1. Field of the nv n ion
This invention relates generally to a method and apparatus for the control of
oil
and gas production wells. More particularly, this invention relates to a
method and
apparatus for automatically controlling petroleum production wells using
downhole
computerized control systems. This invention also relates to a control system
for
controlling production wells, including multiple zones within a single well,
from a
remote location.
2. The Prior Art
The control of oil and gas production wells constitutes an on-going concern of
the petroleum industry due, in part, to the enormous monetary expense involved
as well
as the risks associated with environmental and safety issues.
Production well control has become particularly important and more complex in
view of the industry wide recognition that wells having multiple branches
(i.e.,
multilateral wells) will be increasingly important and commonplace. Such
multilateral
wells include discrete production zones which produce fluid in either common
or
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discrete production tubing. In either case, there is a need for controlling
zone
production, isolating specific zones and otherwise monitoring each zone in a
particular
well.
Before describing the current state-of the-art relative to such production
well
control systems and methods, a brief description will be made of the
production
systems, per se, in need of control. One type of production system utilizes
electrical
submersible pumps (ESP) for pumping fluids from downhole. In addition, there
are
two other general types of productions systems for oil and gas wells, namely
plunger
lift and gas lift. Plunger lift production systems include the use of a small
cylindrical
plunger which travels through tubing extending from a location adjacent the
producing
formation down in the borehole to surface equipment located at the open end of
the
borehole. In general, fluids which collect in the borehole and inhibit the
flow of fluids
out of the formation and into the wellbore, are collected in the tubing.
Periodically, the
end of the tubing is opened at the surface and the accumulated reservoir
pressure is
sufficient to force the plunger up the tubing. The plunger carries with it to
the surface a
load of accumulated fluids which are ejected out the top of the well thereby
allowing
gas to flow more freely from the formation into the wellbore and be delivered
to a
distribution system at the surface. After the flow of gas has again become
restricted
due to the further accumulation of fluids downhole, a valve in the tubing at
the surface
of the well is closed so that the plunger then falls back down the tubing and
is ready to
lift another load of fluids to the surface upon the reopening of the valve.
A gas lift production system includes a valve system for controlling the
injection of pressurized gas from a source external to the well, such as
another gas well
or a compressor, into the borehole. The increased pressure from the injected
gas forces
accumulated formation fluids up a central tubing extending along the borehole
to
remove the fluids and restore the free flow of gas and/or oil from the
formation into the
well. In wells where liquid fall back is a problem during gas lift, plunger
lift may be
combined with gas lift to improve efficiency.
In both plunger lift and gas lift production systems, there is a requirement
for
the periodic operation of a motor valve at the surface of the wellhead to
control either
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the flow of fluids from the well or the flow of injection gas into the well to
assist in the
production of gas and liquids from the well. These motor valves are
conventionally
controlled by timing mechanisms and are programmed in accordance with
principles of
reservoir engineering which determine the length of time that a well should be
either
"shut in" and restricted from the flowing of gas or liquids to the surface and
the time
the well should be "opened" to freely produce. Generally, the criteria used
for
operation of the motor valve is strictly one of the elapse of a preselected
time period.
In most cases, measured well parameters, such as pressure, temperature, etc.
are used
only to override the timing cycle in special conditions.
It will be appreciated that relatively simple, timed intermittent operation of
motor valves and the like is often not adequate to control either outflow from
the well
or gas injection to the well so as to optimize well production. As a
consequence,
sophisticated computerized controllers have been positioned at the surface of
production wells for control of downhole devices such as the motor valves.
In addition, such computerized controllers have been used to control other
downhole devices such as hydro-mechanical safety valves. These typically
microprocessor based controllers are also used for zone control within a well
and, for
example, can be used to actuate sliding sleeves or packers by the transmission
of a
surface command to downhole microprocessor controllers and/or
electromechanical
control devices.
The surface controllers are often hardwired to downhole sensors which transmit
information to the surface such as pressure, temperature and flow. This data
is then
processed at the surface by the computerized control system. Electrically
submersible
pumps use pressure and temperature readings received at the surface from
downhole
sensors to change the speed of the pump in the borehole. As an alternative to
downhole
sensors, wire line production logging tools are also used to provide downhole
data on
pressure, temperature, flow, gamma ray and pulse neutron using a wire line
surface
unit. This data is then used for control of the production well.
There are numerous prior art patents related to the control of oil and gas
production wells. In general, these prior patents relate to (I ) surface
control systems
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using a surface microprocessor and (2) downhole control systems which are
initiated by
surface control signals.
The surface conttol system patents generally disclose computerized systems for
monitoring and controlling a gas/oil production well whereby the control
electronics is
located at the surface and communicates with sensors and electromechanical
devices
near the surface. An example of a system of this type is described in U.S.
Patent
4,633,954 ('954) to Dixon et al. The system described in the '954 patent
includes a
fully programmable microprocessor controller which monitors downhole
parameters
such as pressure and flow and controls the operation of gas injection to the
well,
outflow of fluids from the well or shutting in of the well to maximize output
of the
well. This particular system includes battery powered solid state circuitry
composing a
keyboard, a programmable memory, a microprocessor, control circuitry and a
liquid
crystal display. Another example of a control system of this type is described
in U.S.
Patent 5,132,904 ('904) to Lamp. The '904 patent discloses a system similar to
the '954
patent and in addition also describes a feature wherein the controller
includes serial and
parallel communication ports through which all communications to and from the
controller pass. Hand held devices or portable computers capable of serial
communication may access the controller. A telephone modem or telemetry link
to a
central host computer may also be used to permit several controllers to be
accessed
remotely.
U.S. Patent 4,757,314 ('314) to Aubin et al describes an apparatus for
controlling and monitoring a well head submerged in water. This system
includes a
plurality of sensors, a plurality of electromechanical valves and an
electronic control
system which communicates with the sensors and valves. The electronic control
~ system is positioned in a water tight enclosure and the water tight
enclosure is
submerged underwater. The electronics located in the submerged enclosure
control and
operate the electromechanical valves based on input from the sensors. In
particular, the
electronics in the enclosure uses the decision making abilities of the
microprocessor to
monitor the cable integrity from the surface to the well head to automatically
open or
close the valves should a break in the line occur.
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The downhole control system patents generally disclose downhole
microprocessor controllers, electromechanical control devices and sensors.
Examples
include U.S. Patent Nos. 4,915,168 ('168) to Upchurch and 5,273,112 ('112) to
Schultz.
However, in each and every case, the microprocessor controllers transmit
control
signals only upon actuation from a surface or other external control signal.
There is no
teaching in any of these patents that the downhole microprocessor controllers
themselves may automatically initiate the control of the electromechanical
devices
based on preprogrammed instructions. Similarly, none of the aforementioned
patents
directed to microprocessor based control systems for controlling the
production from
oil and gas wells, including the aforementioned '954, '904 and '314 patents,
disclose
the use of dowmhole electronic controllers, electromechanical control devices
and
sensors whereby the electronic control units will automatically control the
electromechanical devices based on input from the sensor without the need for
a
surface or other external control signal.
It will be appreciated that the dowmhole control system of the types disclosed
in
the '168 and '112 patents are closely analogous to the surface based control
systems
such as disclosed in the '954, '904 and '314 patents in that a surface
controller is
required at each well to initiate and transmit the control instructions to the
downhole
microprocessor. Thus, in all cases, some type of surface controller and
associated
support platform at each well is needed.
While it is well recognized that petroleum production wells will have
increased
production efficiencies and lower operating costs if surface computer based
controllers
and downhole microprocessor controller (actuated by external or surface
signals) of the
type discussed hereinabove are used, the presently implemented control systems
nevertheless suffer from drawbacks and disadvantages. For example, as
mentioned, all
of these prior art systems generally require a surface platform at each well
for
supporting the control electronics and associated equipment. However, in many
instances, the well operator would rather forego building and maintaining the
costly
platform. Thus, a problem is encountered in that use of present surface
controllers
require the presence of a location for the control system, namely the
platform. Still
WO 96!24745 2 ~ g 7 4 ~ ~ PCT/US9610218~
another problem associated with known surface control systems such as the type
disclosed in the '168 and '112 patents wherein a downhole microprocessor is
actuated
by a surface signal is the reliability of surface to downhole signal
integrity. It will be
appreciated that should the surface signal be in any way compromised on its
way
downhole, then important control operations (such as preventing water from
flowing
into the production tubing) will not take place as needed.
Ll multilateral wells where multiple zones are controlled by a single surface
control system, an inherent risk is that if the surface control system fails
or otherwise
shuts down, then all of the downhole tools and other production equipment in
each
separate zone will similarly shut down leading to a large loss in production
and, of
course, a loss in revenue.
Still another significant drawback of present production well control systems
involves the extremely high cost associated with implementing changes in well
control
and related workover operations. Presently, if a problem is detected at the
well, the
customer is required to send a rig to the wellsite at an extremely high cost
(e.g., 5
million dollars for 30 days of offshore work). The well must then be shut in
during the
workover causing a large loss in revenues (e.g., 1.5 million dollars for a 30
day period).
Associated with these high costs are the relatively high risks of adverse
environmental
impact due to spills and other accidents as well as potential liability of
personnel at the
rig site. Of course, these risks can lead to even further costs. Because of
the high costs
and risks involved, in general, a customer may delay important and necessary
workover
of a single well until other wells in that area encounter problems. This delay
may cause
the production of the well to decrease or be shut in until the rig is brought
in.
Still other problems associated with present production well control systems
!involve the need for wireline formation evaluation to sense changes in the
formation
and fluid composition. Unfortunately, such wireline formation evaluation is
extremely
expensive and time consuming. In addition, it requires shut-in of the well and
does not
provide "real time" information. The need for real time information regarding
the
formation and fluid is especially acute in evaluating undesirable water flow
into the
production fluids.
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Summary of the Invention:
The above-discussed and other problems and deficiencies of the prior art are
overcome or alleviated by the production well control system of the present
invention.
In accordance with a first embodiment of the present invention, a downhole
production
well control system is provided for automatically controlling downhole tools
in
response to sensed selected downhole parameters. An important feature of this
invention is that the automatic control is initiated downhole without an
initial control
signal from the surface or from some other external source.
The first embodiment of the present invention generally comprises downhole
sensors, downhole electromechanical devices and downhole computerized control
electronics whereby the control electronics automatically control the
electromechanical
devices based on input from the downhole sensors. Thus, using the downhole
sensors,
the downhole computerized control system will monitor actual downhole
parameters
(such as pressure, temperature, flow, gas influx, etc.) and automatically
execute control
I S instructions when the monitored downhole parameters are outside a selected
operating
range (e.g., indicating an unsafe condition). The automatic control
instructions will
then cause an electromechanical control device (such as a valve) to actuate a
suitable
tool (for example, actuate a sliding sleeve or packer; or close a pump or
other fluid
flow device).
The downhole control system of this invention also includes transceivers for
two-way communication with the surface as well as a telemetry device for
communicating from the surface of the production well to a remote location.
The downhole control system is preferably located in each zone of a well such
that a plurality of wells associated with one or more platforms will have a
plurality of
downhole control systems, one for each zone in each well. The downhole control
systems have the ability to communicate with other downhole control systems in
other
canes in the same or different wells. In addition, as discussed in more detail
with
regard to the second embodiment of this invention, each downhole control
system in a
zone may also communicate with a surface control system. The downhole control
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system of this invention thus is extremely well suited for use in connection
with
multilateral wells which include multiple zones.
The selected operating range for each tool controlled by the downhole control
system of this invention is programmed in a downhole memory either before or
after
the control system is lowered downhole. The aforementioned transceiver may be
used
to change the operating range or alter the programming of the control system
from the
surface of the well or from a remote location.
A power source provides energy to the downhole control system. Power for the
power source can be generated in the borehole (e.g., by a turbine generator),
at the
surface or be supplied by energy storage devices such as batteries (or a
combination of
one or more of these power sources). The power source provides electrical
voltage and
current to the downhole electronics, electromechanical devices and sensors in
the
borehole.
In contrast to the aforementioned prior art well control systems which consist
either of computer systems located wholly at the surface or downhole computer
systems which require an external (e.g., surface) initiation signal (as well
as a surface
control system), the downhole well production control system of this invention
automatically operates based on downhole conditions sensed in real time
without the
need for a surface or other external signal. This important feature
constitutes a
significant advance in the field of production well control. For example, use
of the
downhole control system of this invention obviates the need for a surface
platform
(although such surface platforms may still be desirable in certain
applications such as
when a remote monitoring and control facility is desired as discussed below in
connection with the second embodiment of this invention). The downhole control
~ system of this invention is also inherently more reliable since no surface
to downhole
actuation signal is required and the associated risk that such an actuation
signal will be
compromised is therefore rendered moot. With regard to multilateral (i.e.,
multi-zone)
wells, still another advantage of this invention is that, because the entire
production
well and its multiple zones are not controlled by a single surface controller,
then the
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risk that an entire well including all of its discrete production zones will
be shut-in
simultaneously is greatly reduced.
In accordance with a second embodiment of the present invention, a system
adapted for controlling and/or monitoring a plurality of production wells from
a remote
location is provided. This system is capable of controlling and/or monitoring:
(1 ) a plurality of zones in a single production well;
(2) a plurality of zones/wells in a single location (e.g., a single platform);
or
(3) a plurality of zones/wells located at a plurality of locations (e.g.,
multiple
platforms).
The multizone and/or multiwell control system of this invention is composed of
multiple downhole electronically controlled electromechanical devices
(sometimes
referred to as downhole modules), and multiple computer based surface systems
operated from multiple locations. Important functions for these systems
include the
ability to predict the future flow profile of multiple wells and to monitor
and control the
fluid or gas flow from either the formation into the wellbore, or from the
wellbore to
the surface. The control system of the second embodiment of this invention is
also
capable of receiving and transmitting data from multiple remote locations such
as
inside the borehole, to or from other platforms, or from a location away from
any well
site.
The downhole control devices interface to the surface system using either a
wireless communication system or through an electrical hard wired connection.
The
downhole control systems in the wellbore can transmit and receive data and/or
commands to/from the surface system. The data transmission from inside the
wellbore
can be done by allowing the surface system to poll each individual device in
the hole,
although individual devices will be allowed to take control of the
communications
during an emergency. The devices downhole may be programmed while in the
wellbore by sending the proper command and data to adjust the parameters being
monitored due to changes in borehole and flow conditions and/or to change its
primary
function in the wellbore.
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The surface system may control the activities of the dow~ole modules by
requesting data on a periodic basis, and commanding the modules to open or
close the
electromechanical control devices, and/or change monitoring parameters due to
changes in long term borehole conditions. The surt.'ace system at one location
will be
capable of interfacing with a system in another location via phone lines,
satellite
communication or other comtztunieating means. Preferably, a remote central
control
system controls andlar monitors all of the zones, wells and/or platforms from
a sixtgle
remote location.
In accordance with a third embodiment of the present invention, the downhole
control systems are associated with permanent downhole form.ativn evaluation
sensors
which remain downhole throughout producrion operations. These formation
evaluation sensors for Formation measurements may include, for example, g~unma
ray
detection for formation evaluation, neutron porosity, resistivity, acoustic
sensors and
pulse neutron which can, in real time, sense and evaluate forntation
parameters
including important information regarding water migrating from different
zones.
Significantly, this information can be obtained prior to the water actually
entering the
producing tubing and therefore corrective action (i.e., closing of a valve or
sliding
sleeve) or formation treatment can be taken prior to water being produced.
This real
time acquisition of formation data in the production well constitutes an
important
advance over current wireline techniques in that the present invention is far
less costly
and can anticipate and react to potential problems before they occur. In
addition, the
formation evaluation sensors themselves can be p3aced much closer to the
actual
formation (i.e., adjacent the casing or downhole completion tool) then
wireliae
devices which are restricted to the iutenior of the production tubing.
Accordingly, in one aspect of the present invention there is provided a
subsurface valve position and monitoring system for a production well
comprising:
a dvwnhale valve housing;
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a downhoie valve housed in said valet housing;
a hydraulic control line far controlling said downhole valve;
a first pressure sensor for sensing pressure upstream of said downhole valve;
a second pressure sensor for sensing pressure downstream of said downhole
valve;
a third pressure sensor for sensing pressure at said hydraulic control line;
a Fourth pressure sensor for sensing pressure in an annulus between said valet
housing and a wellbore; and
a proximity sensor associated with said downhole valve.
According to another aspxt of the present invention there is provided a
dawnhole inflationldeflation device comprising:
a valve housing having a valve opening thercthrough, said valve opening
including a larger diameter cavity and said opening also including an
inflation port;
an iz~hatable elemem communicating with said valve housing and adapted far
inflation by fluid transmitted from said valve opening;
a motor in said valve housing;
a valve operatively connected to said motor and movable betweezt out open
position wherein said valve resides in said cavity and a closed position
wherain said
valve resides in said valve opening,
a mandrel housing said inflatable element arid said valve housing,
a first pressure sensor residing in said cavity;
a second pressure sensor residing in said inflation port;
at least one proximity sensor for sensing relative movement between said
valve housing and said mandrel; and
an Electronic controller communicating with said first and second pressure
sensors and said proximity sensor.
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According to yet another aspect of the present invention there is provided a
remotely actuated tpol stop comprising:
a housing which. includes a primary bore;
a motor in said housing;
a shaft opezatively eomZected to said motor,
a stop pivotably conzxeeted to said shaft wherein said stop blocks said
primary
bore when said motor actuates said shag in a first direction and said stop is
removed
from blocking said primary bore when said motor actuates said shaft in a
second
L O direction; and
an electronic controller coznmuxticating with said motor for actuating said
motor.
According to still yet another aspect of the present invention there is
provided
a remotely controlled fluid/gas control system comprising.
a side pocket mandrel having a primary bore and a laterally oi~'sot side
pocket;
an inlet port allowing said side pocket to communicate between said primary
bore and the exterior of said side pocket mandrel;
a fluidlgas control system in said side pocket, said fluid/gas control system
including;
a motor;
an extendable shaft extending from said motor and linearly movable within
said side pocket;
a gas regulator connected to said shaft;
a fluid regulaxor connected to said shaft and spaced from said gas
re~,~ulator;
seals separating said gas and fluid regulators;
an electronic controller in oommunicativn wit>a said zrtotor for actuating
said
motor and moving said shaf3 linearly to sequential positions wherein said gas
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regulator communicates with said inlet port and said fluid regulator
communicates
with said inlet part.
According to still yet another aspect of the present invention there is
provided
a remotely controlled shut-off valve and variable choke assembly comprising:
a housing having a longitudinal passage;
a shut-off valve in said passage;
at least one variable choke valve upstream of said shut-offvalve;
a x-notorized control assembly operatively connected to said shut-off valve
and
said variable choke valve for actuating said valves between open and closed
positions;
'LO an electronic controller in communication with said motorized control
assembly for actuating said motorized control assembly.
The above-discussed and other features and advantages of the present
invention will be appreciated by and understood by those skilled in the art
from the
following detailed description and drawings.
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Brief Description of the Drawi~,:
Referring now to the drawings, wherein like elements are numbered alike in the
several FIGURES:
FIGURE 1 is a diagrammatic view depicting the multiwell/multizone control
system of the present invention for use in controlling a plurality of offshore
well
platforms;
FIGURE 2 is an enlarged diagrammatic view of a portion of FIGURE 1
depicting a selected well and selected zones in such selected well and a
downhole
control system for use therewith;
FIGURE 3 is an enlarged diagrammatic view of a portion of FIGURE 2
depicting control systems for both open hole and cased hole completion zones;
FIGURE 4 is a block diagram depicting the multiwell/multizone control system
in accordance with the present invention;
FIGURE 5 is a block diagram depicting a surface control system for use with
the multiwell/multizone control system of the present invention;
FIGURE SA is a block diagram of a communications system using sensed
downhole pressure conditions;
FIGURE SB is a block diagram of a portion of the communications system of
FIGURE SA;
FIGURE SC is a block diagram of the data acquisition system used in the
surface control system of FIGURE 5;
FIGURE 6 is a block diagram depicting a downhole production well control
system in accordance with the present invention;
FIGURE 7 is an electrical schematic of the downhole production well control
system of FIGURE 6;
FIGURE 8 is a cross-sectional elevation view of a retrievable pressure gauge
side pocket mandrel in accordance with the present invention;
FIGURE 8A is an enlarged view of a portion of FIGURE 8;
FIGURE 9 is a diagrammatic view of a subsurface safety valve position and
pressure monitoring system;
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FIGURE 10 is a diagrammatic view of a remotely controlled inflation/deflation
device for downhole pressure monitoring;
FIGURES 11A and 1 I B are diagrammatic views of a system for remotely
actuated downhole tool stops in respective extended and retracted positions;
FIGURE 12 is a diagrammatic view of a remotely controlled fluid/gas control
system;
FIGURE 13 is a diagrammatic view of a remotely controlled shut off valve and
variable choke assembly;
FIGURE 14 is a cross-sectional side elevation view of a downhole formation
evaluation sensor in accordance with the present invention; and
FIGURES 15A-D are a sequential cross section view of the upside down side
pocket mandrel embodiment of the invention.
pe~crintion ofthe Preferred Embodiment: _ , . ,e ", _ _ ._ _ _
This invention relates to a system for controlling production wells from a
remote location. In particular, in an embodiment of the present invention, a
control and
monitoring system is described for controlling and/or monitoring at least two
zones in a
single well from a remote location. The present invention also includes the
remote
control and/or monitoring of multiple wells at a single platform (or other
location)
and/or multiple wells located at multiple platforms or locations. Thus, the
control
system of the present invention has the ability to control individual zones in
multiple
wells on multiple platforms, all from a remote location. The control and/or
monitoring
system of this invention is comprised of a plurality of surface control
systems or
modules located at each well head and one or more downhole control systems or
modules positioned within zones located in each well. These subsystems allow
monitoring and control from a single remote location of activities in
different zones in a
number of wells in near real time.
As will be discussed in some detail hereinafter in connection with FIGURES 2,
6 and 7, in accordance with a preferred embodiment of the present invention,
the
downhole control system is composed of downhole sensors, downhole control
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electronics and downhole electromechanical modules that can be placed in
different
locations (e.g., zones) in a well, with each downhole control system having a
unique
electronics address. A number of wells can be outfitted with these downhole
control
devices. The surface control and monitoring system interfaces with all of the
wells
where the downhole control devices are located to poll each device for data
related to
the status of the downhole sensors attached to the module being polled. In
general, the
surface system allows the operator to control the position, status, and/or
fluid flow in
each zone of the well by sending a command to the device being controlled in
the
wellbore.
As will be discussed hereinafter, the downhole control modules for use in the
multizone or multiwell control system of this invention may either be
controlled using
an external or surface command as is known in the art or the downhole control
system
may be actuated automatically in accordance with a novel control system which
controls the activities in the wellbore by monitoring the well sensors
connected to the
data acquisition electronics. In the latter case, a downhole computer (e.g.,
microprocessor) will command a downhole tool such as a packer, sliding sleeve
or
valve to open, close, change state or do whatever other action is required if
certain
sensed parameters are outside the normal or preselected well zone operating
range.
This operating range may be programmed into the system either prior to being
placed
in the borehole or such programming may be effected by a command from the
surface
after the downhole control module has been positioned downhole in the
wellbore.
Referring now to FIGURES 1 and 4, the multiwell/multizone monitoring and
control system of the present invention may include a remote central control
center 10
which communicates either wirelessly or via telephone wires to a plurality of
well
platforms 12. It will be appreciated that any number of well platforms may be
encompassed by the control system of the present invention with three
platforms
namely, platform 1, platform 2, and platform N being shown in FIGURES 1 and 4.
Each well platform has associated therewith a plurality of wells 14 which
extend from
each platform 12 through water 16 to the surface of the ocean floor 18 and
then
downwardly into formations under the ocean floor. It will be appreciated that
while
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offshore platforms 12 have been shown in FIGU>;tE l, the group of wells 14
associated
with each platfon~z~ are analogous to goups of walls positioned together in an
area of
land; and the present invention therefore is also weh suited for control of
land based
wells.
As mentioned, each platform 12 is associated with a plurality of wells 14. For
purposes of illustration, three wells are depicted as being associated with
platibml
number 1 with each well being identified as well number 1, well number~2 and
well
number N. As is lanown, a given well may be divided into a plurality of
separate zones
which are required to isolate specific areas of a well for purposes of
producing selected
i0 fluids, preventing blowouts and preventing water intal~e_ Such zones may be
positioned
in a single vertical well such as well 19 associated with platform 2 shown in
FIGURE 1
or such zones can result when multiple wells are linked or otherwise joined
tog~her. A
particularly significant contemporary feature of well production is the
drilling and
completion of lateral or branch wells ~.vhich extend from a particular primary
wellbore.
i 5 These lateral or branch walls can be completed such that each lateral well
constitutes a
separable zone and can be isolated fpr selected production. A more complete
description of wellbores containing one or more laterals (lrnown as
multiIaterals) eats be
found in U.S. Pattnt'!~Tos_ 4,807,407, 5,325,924 and U.S. Patent No.
5,411,082.
With reference to ?~ IGU1ZES 1-4., each of the wells 1, 2 and 3 associated
with
20 platform 1 include a plurality of zones which need to be monitored andlar
controlled
for efficient production and management of the well fluids. For example, with
reference
to FIGURE 2, well number 2 includes three zones, namely zone number 1, zone
number 2 and zone number N. Each of zones 1,2 and N have been completed in a
known meaner; and more paxhicularly have been completed in the maimer
disclosed in
25 aforementioned U.S. Patent No. 5,411,082. Zone number 1 has been completed
using a
known slotted liner completion, zone number 2 has been completed using an open
hole
selective cozrtpletion and zone number N has been completed using a cased hale
selective completion with sliding sleeves. Associated with each of zones
WO 96124745 218' 4 3 ~ PCT/LTS96/02182
.. '.' a =. ~ ..:
-1 S-
1, 2 and N is a downhole control system 22. Similarly, associated with each
well
platform 1, 2 and N is a surface control system 24.
As discussed, the multiwell/multizone control system of the present invention
is
comprised of multiple downhole electronically controlled electromechanical
devices
and multiple computer based surface systems operated from multiple locations.
An important function of these systems is to predict the future flow profile
of multiple
wells and monitor and control the fluid or gas flow from the formation into
the
wellbore and from the wellbore into the surface. The system is also capable of
receiving and transmitting data from multiple locations such as inside the
borehole, and
to or from other platforms 1, 2 or N or from a location away from any well
site such as
central control center 10.
The downhole control systems 22 will interface to the surface system 24 using
a
wireless communication system or through an electrical wire (i.e., hardwired)
connection. The downhole systems in the wellbore can transmit and receive data
and/or commands to or from the surface and/or to or from other devices in the
borehole. Referring now to FIGURE 5, the surface system 24 is composed of a
computer system 30 used for processing, storing and displaying the information
acquired downhole and interfacing with the operator. Computer system 30 may be
comprised of a personal computer or a work station with a processor board,
short term
and long term storage media, video and sound capabilities as is well know.
Computer
control 30 is powered by power source 32 for providing energy necessary to
operate the
surface system 24 as well as any downhole system 22 if the interface is
accomplished
using a wire or cable. Power will be regulated and converted to the
appropriate values
required to operate any surface sensors (as well as a downhole system if a
wire
connection between surface and downhole is available).
A surface to borehole trutsceiver 34 is used for sending data downhole and for
receiving the information transmitted from inside the wellbore to the surface.
The
transceiver converts the pulses received from downhole into signals compatible
with
the surface computer system and converts signals from the computer 30 to an
appropriate communications means for communicating downhole to downhole
control
CA 02187434 2005-04-27
-16-
system 22. Communications downhole may be effected by a variety of known
methods
including hardwiring and wireless communications techniques. A preferred
technique
transmits acoustic signals down a tubing string such as production tubing
string 38 (see
FIGURE 2) or coiled tubing. Acoustical communication may include variations of
signal frequencies, specific frequencies, or codes ox acoustical signals or
combinations
of these. The acoustical transmission media may include the tubing string as
illustrated
in U.S. Patent Nos. 4,375,239; 4,347,900 or 4,378,850. Alternatively, the
acoustical
transmission xnay be transmitted through the casing stream, electrical line,
stick line,
subterranean soil around the well, tubing fluid or azmulus fluid. A preferred
acoustic
transmitter is desczibed in U.S. Patent No. 5,222,049, which discloses a
ceramic
piezoelectric based transceiver_ The piezoelectric wafers that compose the
transducer
are stacked and compressed for proper coupling to the medium used to carry the
data
information to the sensors in the borehole. This transducer will generate a
mechanical
force when alternating current voltage is applied to the two power inputs of
the
transducer. The signal generated by s~essing the piezoelectric wafers will
travel along
tlxe axis of the borehole to the receivers located in the tool assembly where
the signal is
detected and processed. The transmission medium where the acoustic signal will
travel
in the borehole can be production tubing or coil tubing.
Communications can also be effected by sensed downhole pressure conditions
which may be natural conditions or which may be a codod pressure pulse or the
like
introduced into floe well at the surface by the operator of the well. Suitable
systems
descrt'bing in mare detail the nature of such coded pressure pulses are
described in U.S.
Patent Nos. 4,712,613 to Nieuwstad, A.=468,665 to Thawley, 3,233,674 to
Leutwyler
and 4,078,620 to Wesdake; 5,226,494 to Rubbo et a1 and 5,343,963 to Bouldin et
al.
Similarly, the aforementioned '168 patent to Upchurch and '112 patent to
Schultt also
disclose the use of coded pressure pulses in communicating from the surface
downttole_
A preferred system ;far sensing downhole pressure conditions is depicted in
FIGURES SA and SB. Referring to FIGURE SA, ihis system includes a handheld
WO 96/24745 PCTIU596/02182
218'~~34
-17-
terminal 300 used for programming the tool at the surface , batteries (not
shown) for
powering the electronics and actuation downhoIe, a microprocessor 302 used for
interfacing with the handheld terminal and for setting the frequencies to be
used by the
Erasable Programmable Logic Device (EPLD) 304 for activation of the drivers,
preamplifiers 306 used for conditioning the pulses from the surface, counters
(EPLD)
304 used for the acquisition of the pulses transmitted from the surface for
determination
of the pulse frequencies, and to enable the actuators 30b in the tool; and
actuators 308
used for the control and operation of electromechanical devices and/or
ignitors.
Referring to FIGURE SB, the EPLD system 304 is preferably comprised of six
counters: A four bit counter for surface pulse count and for control of the
actuation of
the electromechanical devices. A 10 bit counter to reduce the frequency of
Clock in
from 32_768 KHz to 32 Hz; and a 10 bit counter to count the deadtime
frequency. Two
counters are used to determine the proper frequency of pulses. Only one
frequency
counter is enabled at any time. A shift register is set by the processor to
retain the
frequency settings. The 10 bit devices also enable the pulse counter to
increment the
count if a pulse is received after the deadtlme elapse, and before the pulse
window
count of six seconds expire. The system will be reset if a pulse is not
received during
the six seconds valid period. An AND gate is located between the input pulses
and the
clock in the pulse counter. The AND gate will allow the pulse from a strain
gauge to
reach the counter if the enable line from the 10 bit counter is low. A two
input OR gate
will reset the pulse counter from the 10 bit counter or the master reset from
the
processor. A three input OR gate will be used for resetting the 11, 10 bit
counters, as
well as the frequency counters.
The communications system of of FIGURES SA and SB may operate as
follows:
Set the tool address (frequencies) using the handheld terminal at the
surface;
2. Use the handheld terminal to also set the time delay for the tool to tur
itself on and listen to the pulses transmitted from the surface;
R'O 96124745 PCTIUS96102182
-18-
3. The processor 302 will set the shift register with a binary number which
will indicate to the counters the frequencies (address) it should acknowledge
for
operation of the actuators;
4. The operator will use an appropriate transmitter at the surface system 24
to generate the proper frequencies to be sent to the tool downhole;
5. The downhole electronics 22 will receive the pulses from the surface,
determine if they are valid, and turn on or off the actuators;
6. In one preferred embodiment described in steps 6-8, there are a total of
sixteen different frequencies that can be used to activate the systems
downhole. Each
downhole system will require two frequencies to be sent from the surface for
proper
activation.
The surface system 24 will interface to the tools' processor 302 to set the
two frequencies for communication and activation of the systems in the
borehole. Each
frequency spaced at multiples of 30 seconds intervals is composed of four
pulses. A
system downhole will be activated when 8 pulses at the two preset frequencies
are
received by the electronics in the tool. There has to be 4 pulses at one
frequency
followed by 4 pulses at a second frequency.
5. A counter will monitor the frequencies downhole and will reset the
hardware if a pulse is not received within a 6 second window.
Also, other suitable communications techniques include radio transmission from
the surface location or firom a subsurface location, with corresponding radio
feedback
from the downhole tools to the surface location or subsurface location; the
use of
microwave transmission and reception; the use of fiber optic communications
through a
fiber optic cable suspended from the surface to the downhole control package;
the use
of electrical signaling from a wire line suspended transmitter to the downhole
control
package with subsequent feedback from the control package to the wire line
suspended
transmitterlreceiver. Communication may also consist of frequencies,
amplitudes,
codes or variations or combinations of these parameters or a transformer
coupled
technique which involves wire line conveyance of a partial transformer to a
downhole
tool. Either the primary or secondary of the transformer is conveyed on a wire
line
2184.34.
WO 96/24745 ~ PCT/US96/OZd82
-19-
with the other half of the transformer residing within the downhole tool. When
the two
portions of the transformer are mated, data can be interchanged.
Referring again to FIGURE 5, the control surface system 24 fiuther includes a
printer/plotter 40 which is used to create a paper record of the events
occurring in the
well. The hard copy generated by computer 30 can be used to compare the status
of
different wells, compare previous events to events occurring in existing wells
and to get
formation evaluation logs. Also communicating with computer control 30 is a
data
acquisition system 42 which is used for interfacing the well transceiver 34 to
the
computer 30 for processing. The data acquisition system 42 is comprised of
analog
and digital inputs and outputs, computer bus interfaces, high voltage
interfaces and
signal processing electronics. An embodiment of data acquisition sensor 42 is
shown
in FIGURE SC and includes a pre-amplifier 320, band pass filter 322, gain
controlled
amplifier 324 and analog to digital converter 326. The data acquisition system
(ADC)
will process the analog signals detected by the surface receiver to conform to
the
I S required input specifications to the microprocessor based data processing
and control
system. The surface receiver 34 is used to detect the pulses received at the
surface
from inside the wellbore and convert them into signals compatible with the
data
acquisition preamplifier 320. The signals from the transducer will be low
level analog
voltages. The preamplifier 320 is used to increase the voltage levels and to
decrease the
noise levels encountered in the original signals from the transducers.
Preamplifier 320
will also buffer the data to prevent any changes in impedance or problems with
the
transducer from damaging the electronics. The bandpass filter 322 eliminates
the high
and low frequency noises that are generated firom external sources. The filter
will
allow the signals associated with the transducer frequencies to pass without
any
significant distortion or attenuation. The gain controlled amplifier 324
monitors the
voltage level on the input signal and amplifies or attenuates it to assure
that it stays
within the acquired voltage ranges. The signals are conditioned to have the
highest
possible range to provide the largest resolution that can be achieved within
the system.
Finally, the analog to digital converter 326 will transform the analog signal
received
from the amplifier into a digital value equivalent to the voltage level of the
analog
WO 96!24745 ,. ~ - ~ PCTIUS961021~
2f8~'~3'~
-20-
signal. The conversion from analog to digital will occur after the
microprocessor 30
commands the tool to start a conversion. The processor system 30 will set the
ADC to
process the analog signal into 8 or 16 bits of information. The ADC will
inform the
processor when a conversion is taking place and when it is competed. The
processor
30 can at any time request the ADC to transfer the acquired data to the
processor.
Still referring to FIGURE 5, the electrical pulses from the transceiver 34
will be
conditioned to fit within a range where the data can be digitized for
processing by
computer control 30. Communicating with both computer control 30 and
transceiver
34 is a previously mentioned modem 36. Modem 36 is available to surface system
24
for transmission of the data from the well site to a remote location such as
remote
location 10 or a different control surface system 24 located on, for example,
platform 2
or platform N. At this remote location, the data can be viewed and evaluated,
or again,
simply be communicated to other computers controlling other platforms. The
remote
computer 10 can take control over system 24 interfacing with the downhole
control
1 S modules 22 and acquired data from the wellbore and/or control the status
of the
downhole devices and/or control the fluid flow from the well or from the
formation.
Also associated with the control surface system 24 is a depth measurement
system
which interfaces with computer control system 30 for providing information
related to
the location of the tools in the borehole as the tool string is lowered into
the ground.
Finally, control surface system 24 also includes one or more surface sensors
46 which
are installed at the surface for monitoring well parameters such as pressure,
rig pumps
and heave, all of which can be connected to the surface system to provide the
operator
with additional information on the status of the well.
Surface system 24 can control the activities of the downhole control modules
22
' by requesting data on a periodic basis and commanding the downhole modules
to open,
or close electromechanical devices and to change monitoring parameters due to
changes in long term borehole conditions. As shown diagrammatically in FIGURE
I,
surface system 24, at one location such as platform I, can interface with a
surface
system 24 at a different location such as platforms 2 or N or the central
remote control
sensor 10 via phone lines or via wireless transmission. For example, in FIGURE
1,
CA 02187434 2005-04-27
-21-
each surface system 24 is associated with an antenna 48 for direst
commutucation with
each other (i.e., from platform 2 to platform ~, for direct catttmunication
with an
antenxla 50 located at central control system 10 (i.e., from platform 2 to
control system
10) or far indirect comtnunication via a satellite 52. Thus, each surface
control center
24 includes the following ii~nctions:
I . Polis the dowzJ~ole sensors for data information;
2. Processes the acquired information front floe wellbore to provide the
operator
with formation, tools and flow status;
3. Interfaces with other surface systems for transfer of data and commands;
and
14 4. Provides the interface between the operator and the dawnhole tools and
sensors.
In a less preferred embodiment of the present invention, the downhale control
systnrn 22 may be comprised of any number of latown downhole conlzol systems
which
require a signal from the surface for actuation. Examples of such downhole
oontral
systems include those described in ~(J.S. Patent Nos. 3,227,228; 4,796,669;
4,896,722;
15 4,915,168; 5,050,675; 4,856,595; 4,971,160; 5,273,112; 5,273,113;
5,332,035;
5,293,937; 5,226,494 and 5,343,963. A.ll of these patents disclose various
apparatus
and methods wherein a microprocessor based controller downhole is actuated by
a
surface or other external signal such that the microprocessor executes a
control signal
which is transmitted to an electromechanical control device which then
actuat4s a
20 down,hale tool such as a sliding sleeve, packer or valve. In this case, the
surface control
system 24 transmits the actuation signal to downhole controller 22_
Thus, in accordance with an embodiment of this invention, the aforementioned
remote central control censer lU, surface control centers 24 and downhole
control
systems 22 all cooperate to provide one or more of the following functions:
25 I. Provide one pr two-way communication between the surface system 24 and a
downhale tool via downhole control system 22;
2. Acquire, process, display and/or stare at the surface data trailsmitted
from
downhole relating to the wellbore fluids, gases and tool status parameters
acquired by sensors in the wellbore;
WO 96124745 PCTIUS9610218!
2187434
3. Provide an operator with the ability to control tools downhole by sending a
specific address and command information from the central control center 10 or
from an individual surface control center 24 down into the wellbore;
4. Control multiple tools in multiple zones within any single well by a single
remote surface system 24 or the remote central control center 10;
5. Monitor andlor control multiple wells with a single surface system 10 or 24
;
6. Monitor multiple platforms from a single or multiple surface system working
together through a remote communications link or working individually;
7. Acquire, process and transmit to the surface from inside the wellbore
multiple
parameters related to the well status, fluid condition and flow, tool state
and
geological evaluation;
8. Monitor the well gas and fluid parameters and perform functions
automatically
such as interrupting the fluid flow to the surface, opening or closing of
valves
when certain acquired downhole parameters such as pressure, flow, temperature
or fluid content are determined to be outside the normal ranges stored in the
systems' memory (as described below with respect to FIGURES 6 and ~; and
9. Provide operator to system and system to operator interface at the surface
using
a computer control surface control system.
10. Provide data and control information among systems in the wellbore.
In a preferred embodiment and in accordance with an important feature of the
present invention, rather than using a downhole control system of the type
described in
the aforementioned patents wherein the downhole activities are only actuated
by
surface commands, the present invention utilizes a downhole control system
which
automatically controls downhole tools in response to sensed selected downhole
'parameters without the need for an initial control signal from the surface or
from some
other external source. Referring to FIGURES 2, 3, 6 and 7, this downhole
computer
based control system includes a microprocessor based data processing and
control
system 50.
Electronics control system 50 acquires and processes data sent from the
surface
as received from transceiver system 52 and also transmits downhole sensor
information
WO 96124745 _ . PCTlUS96/02182
2187434
as received from the data acquisition system 54 to the surface. Data
acquisition system
54 will preprocess the analog and digital sensor data by sampling the data
periodically
and formatting it for transfer to processor 50. Included among this data is
data from
flow sensors 56, formation evaluation sensors 58 and electromechanical
position sensor
59 (these latter sensors 59 provide information on position, orientation and
the like of
downhole tools). The formation evaluation data is processed for the
determination of
reservoir parameters related to the well production zone being monitored by
the
downhole control module. The flow sensor data is processed and evaluated
against
parameters stored in the downhole module's memory to determine if a condition
exists
which requires the intervention of the processor electronics 50 to
automatically control
the electromechanical devices. It will be appreciated that in accordance with
an
important feature of this invention, the automatic control executed by
processor 50 is
initiated without the need for a initiation or control signal from the surface
or from
some other external source. Instead, the processor 50 simply evaluates
parameters
existing in real time in the borehole as sensed by flow sensors 56 andlor
formation
evaluations sensors 58 and then automatically executes instructions for
appropriate
control. Note that while such automatic initiation is an important feature of
this
invention, in certain situations, an operator from the surface may also send
control
instructions downwardly from the surface to the transceiver system 52 and into
the
processor 50 for executing control of downhole tools and other electronic
equipment.
As a result of this control, the control system 50 may initiate or stop the
fluid/gas flow
from the geological formation into the borehole or from the borehole to the
surface.
The downhole sensors associated with flow sensors 56 and formation
evaluations sensors 58 may include, but are not limited to, sensors for
sensing pressure,
flow, temperature, oil/water content, geological formation, gamma ray
detectors and
formation evaluation sensors which utilize acoustic, nuclear, resistivity and
electromagnetic technology. It will be appreciated that typically, the
pressure, flow,
temperature and fluid/gas content sensors will be used for monitoring the
production of
hydrocarbons while the formation evaluation sensors will measure, among other
things,
the movement of hydrocarbons and water in the formation. The downhole computer
WO 96124745
PCT/U596102t
-24- 2187434
(processor 50) may automatically execute instructions for actuating
electromechanical
drivers 60 or other electronic control apparatus 62. In tum, the
electromechanical
driver 60 will actuate an electromechanical device for controlling a downhole
tool such
as a sliding sleeve, shut off device, valve, variable choke, penetrator, perf
valve or gas
lift tool. As mentioned, downhole computer 50 may also control other
electronic
control apparatus such as apparatus that may effect flow characteristics of
the fluids in
the well.
In addition, downhole computer 50 is capable of recording downhole data
acquired by flow sensors 56, formation evaluation sensors 58 and
electromechanical
I 0 position sensors 59. This downhole data is recorded in recorder 66.
Information stored
in recorder 66 may either be reirieved from the surface at some later date
when the
control system is brought to the surface or data in the recorder may be sent
to the
transceiver system 52 and then communicated to the surface.
The borehole transxnitter/receiver 52 transfers data from downhole to the
15 surface and receives commands and data from the surface and between other
downhole
modules. Transceiver assembly 52 may consist of any known and suitable
transceiver
mechanism and preferably includes a device that can be used to transmit as
well as to
receive the data in a half duplex communication mode, such as an acoustic
piezoelectric device (i.e., disclosed in aforementioned patent 5,222,049), or
individual
20 receivers such as accelerometers for full duplex communications where data
can be
transmitted and received by the downhole tools simultaneously. Electronics
drivers
may be used to control the electric power delivered to the transceiver during
data
transmission.
It will be appreciated that the downhole control system 22 requires a power
2$ ' source 66 for operation of the system. Power source 66 can be generated
in the
borehole, at the surface or it can be supplied by energy storage devices such
as
batteries. Power is used to provide electrical voltage and current to the
electronics and
electromechanical devices connected to a particular sensor in the borehole.
Power for
the power source may come from the surface through hardwiring or may be
provided in
30 the borehole such as by using a turbine. Other power sources include
chemical
W0 96124745 PCT/US96/OZI82
-25- ~ 187434
reactions, flow control, thermal, conventional batteries, borehole electrical
potential
differential, solids production or hydraulic power methods.
Referring to FIGURE 7, an electrical schematic of downhole controller 22 is
shown. As discussed in detail above, the downhole electronics system will
control the
electromechanical systems, monitor formation and flow parameters, process data
acquired in the borehole, and transmit and receive commands and data to and
from
other modules and the surface systems. The electronics controller is composed
of a
microprocessor 70, an analog to digital converter 72, analog conditioning
hardware 74,
digital signal processor 76, communications interface 78, serial bus interface
80, non-
volatile solid state memory 82 and electromechanical drivers 60.
The microprocessor 70 provides the control and processing capabilities of the
system. The processor will control the data acquisition, the data processing,
and the
evaluation of the data for determination if it is within the proper operating
ranges. The
controller will also prepare the data for transmission to the surface, and
drive the
transmitter to send the information to the surface. The processor also has the
responsibility of controlling the electromechanical devices 64.
The analog to digital converter 72 transforms the data from the conditioner
circuitry into a binary number. That binary number relates to an electrical
current or
voltage value used to designate a physical parameter acquired from the
geological
formation, the fluid flow, or status of the electromechanical devices. The
analog
conditioning hardware processes the signals from the sensors into voltage
values that
are at the range required by the analog to digital converter.
The digital signal processor 76 provides the capability of exchanging data
with
'the processor to support the evaluation of the acquired downhole information,
as well
as to encode/decode data for transmitter 52. The processor 70 also provides
the control
and timing for the drivers 78.
The communication drivers 70 are electronic switches used to control the flow
of electrical power to the transmitter. The processor 70 provides the control
and timing
for the drivers 78.
W0 96124745 PCT/US96/0218~
2187434
-26-
The serial bus interface 80 allows the processor 70 to interact with the
surface
data acquisition and control system 42 (see FIGURES S and SC). The serial bus
80
allows the surface system 74 to transfer codes and set parameters to the micro
controller 70 to execute its functions downhole.
The electromechanical drivers 60 control the flow of electrical power to the
electromechanical devices 64 used for operation of the sliding sleeves,
packers, safety
valves, plugs and any other fluid control device downhole. The drivers are
operated by
the microprocessor 70.
The non-volatile memory 82 stores the code commands used by the micro
controller 70 to perform its functions downhole. The memory 82 also holds the
variables used by the processor 70 to determine if the acquired parameters are
in the
proper operating range.
It will be appreciated that downhole valves are used for opening and closing
of
devices used in the control of fluid flow in the wellbore. Such
electromechanical
downhole valve devices will be actuated by downhole computer 50 either in the
event
that a borehole sensor value is determined to be outside a safe to operate
range set by
the operator or if a command is sent from the surface. As has been discussed,
it is a
particularly significant feature of this invention that the downhole control
system 22
permits automatic control of downhole tools and other downhole electronic
control
apparatus without requiring an initiation or actuation signal from the surface
or from
some other external source. This is in distinct contrast to prior art control
systems
wherein control is either actuated from the surface or is actuated by a
downhole control
device which requires an actuation signal from the surface as discussed above.
It will
be appreciated that the novel downhole control system of this invention
whereby the
~control of electromechanical devices and/or electronic control apparatus is
accomplished automatically without the requirement for a surface or other
external
actuation signal can be used separately from the remote well production
control scheme
shown in FIGURE 1. -
Turning now to FIGURES 2 and 3, an example of the downhole control system
22 is shown in an enlarged view of well-number 2 from platform 1 depicting
zones 1, 2
CA 02187434 2005-04-27
and N_ Each of zones l, 2 and N is associated with a downhole control system
22 of the
type shoran in FIGLrRBS 6 and 7. In zone 1, a slotted loner completion is
shown at 69
associated with a packer 71. In zone 2, an open hole completion is shown with
a series
of packers 73 and intermittent sliding sleeves 75. In zone N, a cased hole
completion is
shown again with the series of packers 77, sliding sleeve 79 and perforating
tools 8I.
The control system 22 in zone 1 includes electromechanical drivers and
electromechanical devices which control the packers 69 and valuing associated
with the
slotted liner so as to control fluid flow. Similarly, control system 22 in
zone 2 include
electromechanical drivers and electromechanical devices which control the
packers,
sliding sleeves and valves associated with that open ftole completion system.
The
control system 22 in zone N also includes eiectroznechanical drivers and
electromechanical control devices for controlling the packers, sliding sleeves
and
perforating equipment depicted therein. Any known electromechanical driver 60
or
electromechanical control device 64 may be used in coimection with this
invention to
control a down~hole tool or valve. Examples of suitable control apparatus are
shown, for
example, in commonly assigned U.S. Patent Nos. 5,343,963; 5,199,497;
5,346,014; and
5,188,183; FIGURES 2, 10 and 11 of the '168 pateunt to Upchurch and FIGURES 10
and 1 i of the '160 patent to Upchurch; FIGURES I 1-14 of the '112 patent to
Schultz;
and FIGURES 1-4 of patent 3,227,228 to Bannister.
Controllers 22 in each of zones 1,2 and N have the ability not only to control
the electromechanical devices associated with each of the downltole tools, but
also have
the ability to control other electronic control apparatus which may be
associated with,
for example, valuing for additional fluid control. The downhole control
systems 22 in
zones 1,2 and N further have the ability to communicate with each other (for
example
through hard wiring) so that actions in one zone may be used to effect the
actions in
another zone. ?his zone to zone communication constitutes still another
important
feature of the present invention. In addition, not only can the downhole
computers 50 in
each of control systems 22 communicate with each other, but the computers 5~3
also
have ability (via transceiver system 52) to communicate through the
WO 96/24745 PCTIUS96102182
_28_
surface control system 24 and thereby communicate with other surface control
systems
24 at other well platforms (i.e., platforms 2 or N), at a remote central
control position
such as shown at 10 in FIGURE 1, or each ofthe processors SO in each downhole
control system 22 in each zone 1, 2 or N can have the ability to communicate
through
its transceiver system 52 to other downhole computers SO in other wells. For
example,
the downhole computer system 22 in zone 1 of well 2 in platform 1 may
communicate
with a downhole control system on platform 2 located in one of the zones or
one of the
wells associated therewith. Thus, the downhole control system of the present
invention
permits communication between computers in different welIbores, communication
between computers in different zones and communication between computers from
one
specific zone to a central remote location.
Information sent from the surface to transceiver S2 may consist of actual
control
information, or may consist of data which is used to reprogram the memory in
processor SO for initiating of automatic control based on sensor information.
In-
addition to reprogramming information, the information sent from the surface
may also
be used to recalibrate a particular sensor. Processor SO ir<tummay not only
send raw
data and status information to the surface through transceiver S2, but may
also process
data downhole using appropriate algorithms and other methods so that the
information
sent to the surface constitutes derived data in a form well suited for
analysis.
Referring to FIGURE 3, an enlarged view of zones 2 and N from well 2 of
platform 1 is shown. As discussed, a plurality of downhole flow sensors S6 and
downhole formation evaluation sensors 58 communicate with downhole controller
22.
The sensors are permanently located downhole and are positioned in the
completion
string and/or in the borehole casing. In accordance with still another
important feature
2S df this invention, formation evaluation sensors may be incorporated in the
completion
string such as shown at S8A-C in zone 2; or may be positioned adjacent the
borehole
casing 78 such as shown at 58D-F in zone N. In the latter case, the formation
evaluation sensors are hardwired back to control system 22. The formation
evaluation
sensors may be of the type described above including density, porosity and
resistivity
Iypes. These sensors measure formation geology, formation saturation,
formation
CA 02187434 2005-04-27
-a9-
porosity, gas influx, water content, petroleum content and formation chemical
elements
such as potassium, uranium and thorium. Examples of suitable sensors are
descc7ibed in
commonly assigned U.S. patents 5,278,768 (porosity}, 5,134,285 (density) and
5,001,675 (electromagnetic resistivity
S Referring to FIGURE 14, an example of a downhole formation evaluation
sensor for permanent placement in a production well is shown at 280. This
sensor 280
is comprised of a side pocket mandrel 282 which includes a primary longitude
nal bore
284 and a laterally displaced side pocket 286. lVl~drel 282 includes threading
Z88 at
both ends for attachment to production tubing. Positiozred sequentially in
spaced
relation longitudinahy along side pocket 286 arc a plurality (in this case 3}
of acoustic,
electromagnetic or nuclear receivers 290 which are sandwiched between a pair
of
respective acoustic, electromagnetic or nuclear transmitters 292.
~'zansmitters 292 and
receivers 290 all communicate with appropriate and lmown electronics for
carrying out
formation evaluation measurements.
The information regarding the formation which is obtained by transmitters 292
and receivers 286 vial be forwarded to a downhole module 22 and transmitted to
the
surface using any of the aforementioned hardwired or wireless
corrnnunicatior>s
techniques. In the embodixnexit shown in FIGURE 14, the fonmataon evaluation
information is transmitted to the surface on inductive coupler 294 and tubular
encased
conductor (TEC) 295, bout of wluch will be described in detail hereinafter.
.As mentioned above, in the prior art, formation evaluation in production
wells
was accomplished using expensive and time consturui~og wire line devices which
was
positioned through the production tubing. The only sensors per~nnanently
positioned in a
production well were those used to measure temperature, pressure and fluid
flow. In
contrast, the present invention permanently locates formation evaluation
sensors
downhole in the production well. The permanently positioned formation
evaluation
sensors of the present invention will monitor both fluid flow and, more
importantly,
will measure formadion parameters so that changing conditions in the
fortnatian will be
sensed before problems occur. For example, water in the formation can be
measured
w0 96124745 PCTlUS9610218!
-30-
prior to such water reaching the borehole and therefore water will be
prevented from
being produced in the borehole. At present, water is sensed only after it
enters the
production tubing.
The formation evaluation sensors of this invention are located closer to the
formation as compared to wireline sensors in the production tubing and will
therefore
provide more accurate results. Since the formation evaluation data will
constantly be
available in real or near real time, there will be no need to periodically
shut in the well
and perform costly wireline evaluations.
The multiwell/multizone production well control system of the present
invention may be operated as follows:
Place the downhole systems 22 in the tubing string 38.
2. Use the surface computer system 24 to test the downhole modules 22 going
into
the borehole to assure that they are working properly.
Program the modules 22 for the proper downhole parameters to be monitored.
4. Install and interface the surface sensors 46 to the computer controlled
system
24.
5. Place the downhole modules 22 in the borehole, and assure that they reach
the
proper zones to be monitored and/or controlled by gathering the formation
natural gamma rays in the borehole, and comparing the data to existing MWD
or wireline logs, and monitoring the information provided by the depth
measurement module 44.
6. Collect data at fixed intervals after all downhole modules 22 have been
installed
by polling each of the downhole systems 22 in the borehole using the surface
computer based system 24.
~ 7. If the electromechanical devices 64 need to be actuated to control the
formation
and/or well flow, the operator may send a command to the downhole electronics
module 50 instructing it to actuate the electromechanical device. A message
will be sent to the surface from the electronics control module 50 indicating
that
the command was executed. Alternatively, the downhole electronics module
W0 96124745 PCT/US96/02I82
-31-
may automatically actuate the electromechanical device without an external
command
from the surface.
8. The operator can inquire the status of wells from a remote location 10 by
establishing a phone or satellite link to the desired location. The remote
surface
computer 24 will ask the operator for a password for proper access to the
remote system.
9. A message will be sent from the downhole module 22 in the well to the
surface
system 24 indicating that an electromechanical device 64 was actuated by the
downhole electronics 50 if a flow or borehole parameter changed outside the
normal operating range. The operator will have the option to question the
downhole module as to why the action was taken in the borehole and overwrite
the action by commanding the downhole module to go back to the original
status. The operator may optionally send to the module a new set of parameters
that will reflect the new operating ranges.
10. During an emergency situation or loss of power all devices will revert to
a
known fail safe mode.
The production well control system of this invention may utilize a wide
variety
of conventional as well as novel downhole tools, sensors, valuing and the
like.
Examples of certain preferred and novel downhole tools for use in the system
of the
present invention include:
a retrievable sensor gauge side pocket mandrel;
2. subsurface safety valve position and pressure monitoring system;
3. remotely controlled inflation/deflation device with pressure monitoring;
4. remotely actuated downhole tool stop system;
5. remotely controlled fluid/gas control system; and
6. remotely controlled variable choke and shut-off valve system.
The foregoing listed tools will now be described with reference to FIGURES 8-
13.
Retrievable Pressure Game Side p~r><Pt Man~irPl ~+1, r a +' r ,
Traditional permanent downhole gauge (e.g. sensor) installations require the
WO 96!24745 PCTIUS9610218~
-32-
mounting and installation of a pressure gauge external to the production
tubing thus
making the gauge an integral part of the tubing string. This is done so that
tubing
and/or annulus pressure can be monitored without restricting the flow diameter
of the
tubing. However, a drawback to this conventional gauge design is that should a
gauge
fail or drift out of calibration requiring replacement, the entire tubing
string must be
pulled to retrieve and replace the gauge. In accordance with the present
invention an
improved gauge or sensor construction (relative to the prior art permanent
gauge
installations), is to mount the gauge or sensor in such a manner that it can
be retrieved
by common wireline practices through the production tubing without restricting
the
flow path. This is accomplished by mounting the gauge in a side pocket
mandrel.
Side pocket mandrels have been used for many years in the oil industry to
provide a convenient means of retrieving or changing out service devices
needed to be
in close proximity to the bottom of the well or located at a particular depth.
Side
pocket mandrels perform a variety of functions, the most common of which is
allowing
gas from the annulus to communicate with oil in the production tubing to
lighten it for
enhanced production. Another popular application for side pocket mandrels is
the
chemical injection valve, which allows chemicals pumped from the surface, to
be
introduced at strategic depths to mix with the produced fluids or gas. These
chemicals
inhibit corrosion, particle build up on the LD. of the tubing and many other
functions.
As mentioned above, permanently mounted pressure gauges have traditionally
been mounted to the tubing which in effect makes them part of the tubing. By
utilizing
a side pocket mandrel however, a pressure gauge or other sensor may be
installed in the
pocket making it possible to retrieve when necessary. This novel mounting
method for
a pressure gauge or other downhole sensor is shown in FIGURES 8 and 8A. In
~ FIGURE 8, a side pocket mandrel (similar to side pocket mandrel 282 in
FIGURE 14)
is shown at 86 and includes a primary through bore 88 and a laterally
displaced side
pocket 90. Mandrel 86 is threadably connected to the production tubing using
threaded
connection 92. Positioned in side pocket 90 is a sensor 94 which may comprise
any
suitable transducer for measuring flow, pressure, temperature or the like. In
the
FTGURE 8 embodiment, a pressure/temperature transducer 94 (Model 2225A or
2250A
W096I24745 " , PGT/US96102182
-33-
commercially available from Panex Corporation of Houston, Texas) is depicted
having
been inserted into side pocket 90 through an opening 96 in the upper surface
(e.g.,
shoulder) 97 of side pocket 90 (see FIGURE 8A).
Information derived from downhole sensor 94 may be transmitted to a
downhole electronic module 22 as discussed in detail above or may be
transmitted
(through wireless or hardwired means) directly to a surface system 24. In the
FIGURES 8 and 8A embodiments, a hardwired cable 98 is used for transmission.
Preferably the cable 98 comprises tubular encased conductor or TEC available
from
Baker Oil Tools of Houston, Texas. TEC comprises a centralized conductor or
conductors encapsulated in a stainless steel or other steel jacket with or
without epoxy
filling. An oil or other pneumatic or hydraulic fluid fills the annular area
between the
steel jacket and the central conductor or conductors. Thus, a hydraulic or
pneumatic
control line is obtained which contains an electrical conductor. The control
line can be
used to convey pneumatic pressure or fluid pressure over long distances with
the
I S electrical insulated wire or wires utilized to convey an electrical signal
(power and/or
data) to or from an instnunent, pressure reading device, switch contact, motor
or other
electrical device. Alternatively, the cable may be comprised of Center-Y
tubing
encased conductor wire which is also available from Baker Oil Tools. This
latter cable
comprises one or more centralized conductor encased in a Y-shaped insulation,
all of
which is further encased in an epoxy filled steel jacket. It will be
appreciated that the
TEC cable must be connected to a pressure sealed penetrating device to make
signal
transfer with gauge 94. Various methods including mechanical (e.g.,
conductive),
capacitive, inductive or optical methods are available to accomplish this
coupling of
gauge 94 and cable 92. A preferred method which is believed most reliable and
most
likely to survive the harsh downhole environment is a known "inductive
coupler" 99.
Transmission of electronic signals by means of induction have been in use for
many years most commonly by transformers. Transformers are also referred to as
inductors, provide a means of transmitting electrical current without a
physical
connection by the terminal devices. Sufficient electrical current flowing
through a coil
of wire can induce a like current in a second coil if it is in very close
proximity to the
WO 96124745 PCTIUS96/0218~
-34- 2187434
first. The drawback of this type of transmission is that efficiency is Iow. A
loss of
power is experienced because there is no physical contact of conductors; only
the
influence of one magnetic field in the source coil driving an electric current
in the
second. To achieve communication through the inductive device 99, an
alternating
current (AC) must be used to create the operating voltage. The AC is then
rectified or
changed to direct current (DC) to power the electronic components.
Much like the inductive coupler or transformer method of signal transmission,
a
very similar principle exists for what are known as "capacitive couplers".
These
capacitance devices utilize the axiom that when two conductors or poles in
close
proximity to each other are charged with voltages or potential differences of
opposite
polarity, a current can be made to flow through the circuit by influencing one
of the
poles to become more positive or more negative with respect to the other pole.
When
the process is repeated several times a second, a frequency is established.
When the
frequency is high enough, (several thousand times per second), a voltage is
generated
"across" the two poles. Sufficient voltage can be created to provide enough
power for
microprocessing and digital circuitry in the downhole instruments. Once
powered up,
the downhole device can transmit; radio- metric, digital or time shared
frequency trains
which can be modulated on the generated voltage and interpreted by the surface
readout device. Thus, a communication is established between downhole device
and
the surface. As with inductive devices, capacitive devices can suffer line
loss through
long lengths of cable if the communication frequency is too high causing the
signal to
be attenuated by the inherent capacitance of the cable itself. Again, as with
the
inductive devices, capacitive devices must use the alternating current (AC)
method of
transmission with rectification to DC to power the electronics.
~ J~y transmitting beams of light through a glass fiber cable, electronic
devices
can also communicate with one another using a light beam as a conductor as
opposed to
a solid metal conductor in conventional cable. Data transmission is
accomplished by
pulsing the light beam at the source (surface instrument which is received by
an end
device (downhole instrument) which translates the pulses and converts them
into
electronic signals.
WO 96/24745 PCT/US96IOZI82
5_ ~ ~ &134
Conductive or mechanical coupling is simply making a direct physical
connection of one conductor to another. In the side pocket mandrel 86, a
conductor is
present in the pocket 90, pressure sealed as it penetrates the body of the
side pocket and
mated to an external device to transmit the signal to the surface (i.e., solid
conductor
cable, wireless transceiver or other device). The hard wired coupler may exist
in any
form conducive to proper electronic signal transmission while not compromising
the
pressure sealing integrity of the tool. The coupler must also be capable of
surviving
exposure to harsh downhole conditions while in the unmated condition as would
be the
case when an instrument 94 was not installed in the pocket 90.
The preferred inductive coupler 99 is connected to TEC cable 98 using a
pressure sealed connector 95.
With the gauge or other sensor 90 being internal and exposed to the LD. of the
tubing
88, and the cable 98 being external to the mandrel 86, but exposed to the
annulus
environment, the connector 95 must penetrate the mandrel pocket 90 allowing
gauge 94
and cable 98 to be mated. Due to pressure differences between the tubing LD.
and the
annulus, connector 95 also provides a pressure seal so as to prevent
communication
between the mandrel and annulus.
An electronic monitoring device 94 which is "landed" in side pocket 90 of
mandrel 86, includes a latching mechanism 101 to keep sensor 94 in place as
pressure
is exerted on it either from the interior of the mandrel or the annulus side.
This latching
mechanism 101 also provides a means of being unlatched so the device may be
retrieved. Several methods exist to accomplish this latching, such as using
specific
profiles in pocket 90 that align with spring loaded dogs (not shown) on the
sensor
device 94. Once aligned, the springs force the locking dogs out to meet the
profile of
the pocket 90 providing a lock, much like tumblers in an ordinary household
key
operated lock. This locking action prevents the sensor tool 94 from being
dislodged
from its landing seat. This is important as any movement up or down could
cause
misalignment and impair the integrity of the electronic coupling device 99 to
which the
sensor tool 94 is now mated.
w0 96124745 PCTlUS961021~
-36-
The latching mechanism 101 must be of sufficient robustness as to be able to
withstand several landing and retrieval operations without comprising the
integrity of
the latching and release properties of sensor tool 94.
As mentioned, pressure integrity should be maintained to keep the mandrel
isolated from the annulus. When the sensor tool 94 is being landed in pocket
90, it
should activate or deactivate pressure sealing device 95 to expose the sensing
portion
of the sensor tool 94, to either the mandrel or annulus. Similarly, when
sensor tool 94
is retrieved from pocket 90, it must also seal off any pressure port that was
opened
during the landing procedure.
The pressure porting mechanism is capable of being selectively opened to
either
the annulus or the mandrel. The selection device can be, but is not limited
to> a specific
profile machined to the outer housing of the sensor tool 94 combined with
different
configurations of locking/actuating dogs to: open a sliding sleeve, sting into
a dedicated
pressure port, displace a piston or any suitable configuration of pressure
port opening
or closing devices. Once activating the selected port, a positive seal must be
maintained on the unselected port to prevent leakage or sensing of an
undesired
condition (pressure, flow, water cut etc.) while in the unmated condition as
would be
the case when an instrument was not installed in the pocket.
Subsm ace Safetv Valve Position and Pressure Monitoring System, _.._ ,
Referring to FIGURE 9, a subsurface safety valve position and pressure
monitoring system is shown generally at 100. System 100 includes a valve
housing
102 which houses a downhole valve such as a shut-in valve 104. Various
pressure and
positioning parameters of shut-in valve 104 are determined through the
interaction of
five sensors which are preferably tied to a single electrical single conductor
or multi
~ -conductor line (e.g., the aforementioned TEC cable). These five sensors
remotely
monitor the critical pressures and valve positions relative to safe, reliable
remotely
controlled subsurface safety valve operations. The downhole sensors include
four
pressure sensors 106, 108, 110 and 112 and one proximity sensor 114. Pressure
sensor
or transducer 106 is positioned to sense tubing pressure upstream of shut-in
valve 104.
Pressure transducer 108 is positioned to sense the hydraulic control-line
pressure from
WO 96f24745 ~ 18 °7 4 3 4 PC17US96/02182
x
F
-37-
hydraulic control-line 116. Pressure transducer 110 is positioned to sense the
annulus
pressure at a given depth while pressure transducer 112 is positioned to sense
the
tubing pressure downstream of valve 104. Proximity sensor 114 is positioned
external
to the valve or closure member 104 and functions so as to enable confirmation
of the
position of the valve 104. Encoded signals from each of the sensors 106
through 114
are fed back to the surface system 24 or to a downhole module 22 through a
power
supply/data cable 118 connected to the surface system 24 or downhole module
22.
Alternatively, the encoded signals may be transmitted by a wireless
transmission
mechanism. Preferably cable I I 8 comprises tubing encapsulated single or
I O multiconductor line (e.g., the aforementioned TEC cable) which is run
external to the
tubing stream downhole and serves as a data path between the sensors and the
surface
control system.
A downhole module 22 may automatically or upon control signals sent from the
surface, actuate a downhole control device to open or shut valve 104 based on
input
15 from the downhole sensors 106 through 114.
The foregoing subsurface valve position and pressure monitoring system
provides many features and advantages relative to prior art devices. For
example, the
present invention provides a means for absolute remote confirmation of valve
position
dovvnhole. This is crucial for confident through tubing operations with
vvireline or
20 other conveyance means and is also crucial for accurate diagnosis of any
valve system
malfunctions. In addition, the use of the subsurface safety valve position and
pressure
monitoring system of this invention provides real time surface confirmation of
proper
pressure conditions for fail-safe operation in all modes. Also, this system
provides a
means for determination of changes in downhole conditions which could render
the
25 safety system inoperative under adverse or disaster conditions and the
present invention
provides a means for surface confirmation of proper valve equalization prior
to
reopening after downhole valve closure.
$emotelv Controlled flafon eflarion l~ev;cP with a preca"rP tvt~.,;tn,;ng
Svstem
Referring now to FIGURE 10, a microprocessor based device for monitoring of
30 pressures associated with the inflation of dovvnhole tools is presented.
This
VUO 96!24745 ~ ~ g ~ 4 3 ~ PCT/US96/021>~
-38-
microprocessor based device can be actuated either automatically by the
downhole
control module 22 or the downhole control module 22 may actuate the present
device
via a surface signal which is transmitted downhole from the surface system 24.
In
FIGURE 10, the inflatable element (such as a packer) is shown at 124 and is
mounted
in a-suitable mandrel 126. Associated with inflatable element 124 is a valve
housing
128 which includes an axial opening 130 having a first diameter and a coaxial
cavity
132 having a second diameter larger than the first diameter. Also within valve
housing
128 is a motor 134 which actuates appropriate gearing 136 so as to provide
linear
translation to a shaft 138 having a piston-type valve 140 mounted to one end
thereof.
As shown by the arrows in FIGURE 10, motor 130 actuates gearing 136 so as to
move
piston 140 between a closed or shut-off position in which piston 140 resides
completely
in axial opening I30 and an open position wherein piston 140 resides within
the central
cavity 132. Axial opening 130 terminates in the interior of valve housing 128
at an
inflation port 142 through which fluid from an inflation fluid source 144
enters and
I S exits in the interior of valve housing 128.
In accordance with an important feature of the present invention, the
inflationldeflation device 124 is remotely controlled and/or monitored using a
plurality
of sensors in conjunction with a microprocessor based controller 146. Of
course
controller 146 is analogous to the downhole modules 22 discussed in great
detail above
in connection with for example, FIGURES 6 and 7. .In a preferred embodiment of
this
invention, a pair of pressure transducers communicate with microprocessor
controller
146. One pressure transducer is shown at 148 and resides within the internal
cavity 132
of valve housing 128. The second pressure transducer is shown at 150 and
resides in
the inflation port 142. In addition, a pair of cooperating proximity sensors
152 and 154
~ are positioned between valve housing 128 and the mandrel 126. Preferably,
both
power and data are supplied to controller 146 through appropriate cable 156
via a
pressure fitting 158. This cable is preferably the TEC cable described above.
Power
may also be supplied by batteries or the like and data may be transmitted
using wireless
methods.
218'~4i,4~' x''
WO 96124745 PCTlUS96/02182
-39-
It will be appreciated that the sealing device of this invention functions as
a
valve and serves to positively open and close the inflation fluid passage
thereby
permitting movement of inflation fluid from the fluid source 144 to the
sealing element
124. In the particular embodiment described in FIGURE 10, the valve 140
operates by
axially displacing the sealing element 124 between the two diametrical bores
within the
fluid passageway by way of the motor gearing mechanism 134/136 all of which is
driven by the on-board microprocessor 146. Valve 140 has two functional
positions
i.e., open and closed. Of course, the valve could function in alternative
manners such
as a solenoid. The electronic controller 146 serves to integrate the pressure
inputs from
pressure transducers 148 and 150 and the proximity inputs from proximity
sensors 152
and 154 along with the data/control path 156 to appropriately drive the
control valve
mechanism during tool inflation. Thereafter, the sensors 148, 150, 152 and 154
serve
to ensure pressure integrity and other tool position functions.
The remotely controlled inflation/deflation device of the present invention
offers many features and advantages. For example, the present invention
eliminates the
present standard industry design for pressure actuated shear mechanisms which
are
subject to wide variations in actuation pressures and premature inflation. The
present
invention provides a directly controllable mechanism for initiation of
downhole tool
inflation and through the unique self cleaning inflation contrrol valve
configuration
shown in FIGURE 10, obsoletes present design configurations which are subject
to
fouling by debris in the inflation fluid. In addition, the present invention
enables direct
control of closure of the inflation valve whereas in the prior art, spring
loaded and
pressure actuated designs resulted in pressure loss during operation and
unreliable
positive sealing action. The use of a motor driven, mechanical inflation
control valve
also constitutes an important feature of this invention. Still another feature
of this
invention is the incorporation of electronic proximity sensors in relation to
inflatable
tools so as to ensure correct positioning of selective inflation tools. High
angle/horizontal orientation of inflatable tools requires conveyance of
inflation tools
via coil tubing which is subject to substantial drag. In contrast to the
present invention,
the prior art has been limited to positioning of inflation tools by collet
type devices or
_ x y~, _.
WO 96!24745 PCT/US961021~
-40-
pressure operated devices, both of which were highly unreliable under these
conditions.
The use of a microprocessor in conjunction with an inflatable downhole tool
and the
use of a microprocessor based system to provide both inflation and deflation
to control
the downhole tools also constitute important features of this invention. The
present
invention thus enables multiple, resettable operations in the event that
procedures may
so require or in the event of initially incorrect positioning of tools within
a wellbore.
Finally, the present invention provides a continuous electronic pressure
monitoring
system to provide positive, real time wellbore and/ zonal isolation integrity
downhole.
Reaxlotelv Actuated Downhole Tool Stop Svstem _ . __.___ _ _ _ __
Referring to FIGURES 11 A and 11 B, a remotely actuated tool stop in
accordance with the present invention is shown generally at 160. In the
embodiment
shown, the remotely actuated tool stop includes a side pocket mandrel 162
having a
primary bore 164 and a side bore 166. A tool stop 168 is pivotally mounted
onto a
threaded shaft 170 with shaft 170 being sealed by seal 172 to prevent the flow
of fluid
or other debris into sidebore 166. Threaded shaft 170 is connected to a
holddown 174
which in tum is connected to appropriate gearing 176 and a motor 178. While
motor
178 may be powered by a variety of known means, preferably an inductive
coupler I 80
of the type described above is used to power the motor through a tubular
encased
conductor or TEC 192 as described above. Note that a pressure relief port 184
is
provided between sidebore 166 and primary bore 164.
The foregoing system described in FIGURE 11A functions to provide a
remotely actuated device which positively limits the downward movement of any
tools
used within the wellbore. A primary utilization of the tool stop includes use
as a
positioning device at close proximity (i.e. below) to a tool, for example or
the side
. pocket mandrel 162. The system of this invention may also be used with other
difficult
to locate devices in high angle or horizontal wellbores. 1n this manner, when
activated
as shown in FIGURE I lA, the surface operator may proceed downward with a work
string until contact is made with tool stop 168. The tools and/or work string
being
delivered downhole may then be pulled back up a known distance thus ensuring
proper
positioning to perform the intended funotion in the targeted receptacle. An
alternative
WO 96124745 PCT/US96/02182
-41-
function would be as a general purpose safety device, positioned close to the
bottom of
the tubing string in the wellbore. The tool stop system of this invention
would then be
activated whenever wireline or coiled tubing operations are being performed
above
and within the wellbore. In the event that the work string or individual tools
are
accidentally dropped, the tool stop of this invention ensures that they are
not lost
downhole and provides for easy retrieval at the tool stop depth. After through
tubing
operations are concluded, the tool stop system of this invention is
deactivated/retracted
as shown in FIGURE 11 B to provide a clear tubing bore 164 for normal well
production or injection. It will be appreciated that during use, motor 178
will actuate
gearing 176 which in tum will rotate threaded shaft 170 so as to raise tool
stop 168 to
the position shown in FIGURE 11A or lower (deactivate or withdraw) tool stop
168 to
the retracted position shown in FIGURE I 1B. The motor will be digitally
controlled
by an electronics control module 22 provided in inductive coupler section I
80. Control
module 22 can either be actuated by a surface or external control signal or
may be
I S automatically actuated downhole based on preprogrammed instructions as
described
above with regard to FIGURE 7.
The remotely actuated tool stop of the present invention offers many features
and advantages including a means for selective surface actuation of a downhole
device
to prevent tool loss; a means for selective surface actuation of a downhole
device to
provide for positive tool location downhole and as a means to prevent
accidental
impact damage to sensitive tools downhole such as subsurface safety valves and
inflatable tubing plugs.
Remotely Controlled Fluids/Gas Control System
Referring now to FIGURE 12, a remotely controlled fluid/gas control system is
shown and includes a side pocket mandrel 190 having a primary bore 192 and a
side
bore 194. Located within side bore 194 is a removable flow control assembly in
accordance with the present invention. This flow control assembly includes a
locking
device 196 which is attached to a telescopic section 198 followed by a gas
regulator
section 200, a fluid regulator section 202, a gear section 204 and motor 206.
Associated with motor 206 is an electronics control module 208. Three spaced
seal
WO 96!24745 ' PCT/U596/0218~
-42-
sections 210, 212 and 214 retain the flow control assembly within the side
bore or side
pocket 194. Upon actuation by electronics module 208, control signals are sent
to
motor 206 which in tum actuate gears 204 and move gas regulator section 200
and fluid
regulator section 202 in a linear manner upwardly or downwardly within the
side
pocket 194. This linear movement will position either the gas regulator
section 200 or
the fluid regulator section 202 on either side of an inlet port 216.
Preferably, electronics control module 208 is powered andlor data signals are
sent thereto via an inductive coupler 218 which is connected via a suitable
electrical
pressure fitting 220 to the TEC cable 192 of the type discussed above. A
pressure
transducer 224 senses pressure in the side pocket 194 and communicates the
sensed
pressure to the electronics control module 208 (which is analogous to downhole
module 22). A pressure relief port is provided to side pocket 194 in the area
surrounding electronics module 208.
The flow control assembly shown in FIGURE42 provides for regulation of
liquid and/or gas flow from the wellbore to the tubing/casing annulus or vice
versa.
Flow control is exercised by separate fluid and gas flow regulator subsystems
within
the device. Encoded data/control signals are supplied either externally from
the surface
or subsurface via a data control path 222 and/or internally via the
interaction of the
pressure sensors 224 (which are located either upstream or downstream in the
tubing
conduit and in the annulus) and/or other appropriate sensors together with the
on-board
microprocessor 208 in a manner discussed above with regard to FIGURES 6 and 7.
The flow control assembly of this invention provides for two unique and
distinct subsystems, a respective fluid and gas flow stream regulation. These
subsystems are pressure/fluid isolated and are contained with the flow control
, assembly. Each of the systems is constructed for the specific respective
requirements
of flow control and resistance to damage, both of which are uniquely different
to the
two control mediums. Axial reciprocation of the two subsystems, by means of
the
motor 206 and gear assembly 204 as well as the telescopic section 198 permits
positioning of the appropriate fluid or gas flow subsystem in conjunction with
the
single fluid/gas passages into and out of the side pocket mandrel 190 which
serves as
W096124745 ~ ~ PCTIUS96102182
-43-
the mounting/conrirol platform for the valve system downhole. Both the fluid
and gas
flow subsystems allow for fixed or adjustable flow rate mechanisms.
The external sensing and control signal inputs are supplied in a preferred
embodiment via the encapsulated, insulated single or multiconductor wire 222
which is
electrically connected to the inductive coupler system 218 (or alternatively
to a
mechanical, capacitive or optical connector), the two halves of which are
mounted in
the lower portion of the side pocket 194 of mandrel 190, and the lower portion
of a
regulating valve assembly respectively. Internal inputs are supplied from the
side
pocket 194 and/or the flow control assembly. All signal inputs (both external
and
internal) are supplied to the on-board computerized controller 208 for all
processing
and distributive control. 1n addition to processing of off boards inputs, an
ability for
on-board storage and manipulation of encoded electronic operational "models"
constitutes one application of the present invention providing for autonomous
optimization of many parameters, including supply gas utilization, fluid
production,
annulus to tubing flow and the like.
The remotely controlled fluid/gas control system of this invention eliminates
known prior art designs for gas lift valves which forces fluid flow through
gas regulator
systems. This results in prolonged life and eliminates premature failure due
to fluid
flow off the gas regulation system. Still another feature of this invention is
the ability
to provide separately adjustable flow rate control of both gas and liquid in
the single
valve. Also, remote actuation, control and/or adjustment of downhole flow
regulator is
provided by this invention. Still another feature of this invention is the
selected
implementation of two devices within one side pocket mandrel by axial
-manipulation/displacement as described above. Still another feature of this
invention is
the use of a motor driven, inductively coupled device in a side pocket. The
device of
this invention reduces total quantity of circulating devices in a gas lift
well by
prolonging circulating mechanism life. As mentioned, an important feature of
this
invention is the use of a microprocessor 208 in conjunction with a downhole
gas
lifllregulation device as well as the use of a microprocessor in conjunction
with a
downhole liquid flow control device.
WO 96!24745 PCT/US961021~
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Contr911ed Variable Choke and Shut-Off Valve Svstem
Referring to FIGURE 13, a remotely controlled downhole device is shown
which provides for actuation of a variable downhole choke and positively seals
offthe
wellbore above from downhole well pressure. This variable choke and shut-off
valve
system is subject to actuation from the surface, autonomously or interactively
with
other intelligent downhole tools in response to changing downhole conditions
without
the need for physical reentry of the wellbore to position a choke. This system
may also
be automatically controlled downhole as discussed with regard to FIGURES 6 and
7.
As will be discussed hereinafter, this system contains pressure sensors
upstream and
downstream of the choke/valve members and real time monitoring of the response
of
the well allows for a continuous adjustment of choke combination to achieve
the
desired wellbore pressure parameters. The choke body members are actuated
selectively and sequentially, thus providing for wireline replacement of choke
orifices
if necessary.
Turning to FIGURE 13, the variable choke and shut off valve system of this
invention includes a housing 230 having an axial opening 232 therethrough.
Within
axial opening 232 are a series (in this case two) of ball valve chokes 234 and
236
which are capable of being actuated to provide sequentially smaller apertures;
for
example, the aperture in ball valve choke 234 is smaller than the relatively
larger
aperture in ball valve choke 236. A shut-offvalve 238, may be completely shut
offto
provide a full bore flow position through axial opening 232. Each ball valve
choke 234
and 236 and shut-offvalve 238 are releasably engageable to an engaging gear
240, 242
and 244, respectively. These engaging gears are attached to a threaded drive
shaft 246
and drive shaft 246 is attached to appropriate motor gearing 248 which in turn
is
ZS , attached to stepper motor 250. A computerized electronic controller 252
provides
actuation control signals to stepper motor 250. Downhole controller 252
communicates
with a pair of pressure transducers, one transducer 254 being located upstream
of the
ball valve chokes and a second pressure transducer 2d6 being located
downstream of
the ball valve chokes. Microprocessor controller 252 can communicate with the
surface either by wireless means of the type described in detail above or, as
shown in
.;
~j 1 .~
218'~~34
W 0 96124745 PCTlUS96/02182
-4$-
FIGURE 13 by hard wired means such as the power/data supply cable 258 which is
preferably of the TEC type described above.
As shown in FIGURE 13, the ball valve chokes are positioned in a stacked
configuration within the system and are sequentially actuated by the control
rotation
mechanism of the stepper motor, motor gearing and threaded drive shaft. Each
ball
valve choke is configured to have two functional positions: an "open" position
with a
fully open bore and an "actuated" position where the choke bore or closure
valve is
introduced into the wellbore axis. Each member rotates 90° pivoting
about its
respective central axis into each of the two functional positions. Rotation of
each of the
members is accomplished by actuation of the stepper motor which actuates the
motor
gearing which in turn drives the threaded drive sha8 246 such that the
engaging gears
240, 242 or 244 will engage a respective ball valve choke 234 or 236 or shut-
off valve
238. Actuation by the electronic controller 252 may be based, in part upon
readings
from pressure transducers 254 and 256 or by a control signal from the surface.
The variable choke and shut-off valve system of the present invention provides
important features and advantages including a novel means for the selective
actuation
of a downhole adjustable choke as well as a novel means for installation of
multiple,
remotely or interactively controlled downhole chokes and shut-off valves to
provide
tunedloptimized wellbore performance.
In an alternate construction of the invention hereinbefore described and
referring to FIGURES 15A-D, a side pocket 290 is oriented upside down to
conventional side pockets. In other words, rather than orienting the side
pocket
opening 296 downhole, the side pocket opening 296 is oriented uphole thereby
rendering the side pocket structure extending downhole rather than uphole.
This
alleviates the problem of silt collecting in the side pocket. As one of skill
in the art will
appreciate, in a normally oriented (upward) side pocket a cup is created which
allows
silt carried with the production fluid to settle into the pocket. This may
interfere with
the operation of sensors and certainly cause problems related to changing
sensors since
once the original sensor is removed, the silt will settle into the opening 96
thus
completely or at least partially occluding the same. With the alternate
construction,
PCT/US9610218~
WO 96124745
-46-
however, pocket 296 does not become occluded with silt since falling or
settling
particles fall down the production tube and are not collected in the pocket
290.
Moreover, any silt flushed into pocket 290 will settle back into the
production tube via
down angled section 297 thus maintaining the pocket opening 290 iri a clear
condition.
Because of the clearer condition of the pocket, changing of sensors is
simplified. 1n
other respects, the pocket 290 is the same as the other embodiments discussed
herein.
It is capable of supporting all of the same sensors in equivalent positions
(albeit upside
down) and merely provides the added benefit discussed herein.
In addition, the side pocket 290 is particularly adapted to receive
gauge~nductive coupler 310 (FIGURE 15C). Gaugelinductive coupler 310 is, in
commercial form, available from Panex Corporation, Sugarland Texas and is
protected
under U.S. Patent No. 5,457,988 and 5,455,573 the entire disclosures of both
of which
are incorporated herein by reference. The inductive couple is composed of
female
inductive coupler 348 and male inductive coupler 349.
As will be clearly understood by one of skill in the art from a perusal of
FIGURES I SA-D, the side pocket 290 depends firom main bore 288 similarly to
those
embodiments hereinbefore described, however being oriented upside down. The
side
pocket 290 of the invention includes a relatively broad shoulder area 312
having a
through bore 313 adapted to sealingly receive a connector assembly 336 which
inductively, or alternatively conductively, communicates with a sensor or
gauge 318
disposed within side pocket 290. Side pocket 290 is defined by said shoulder
area 312
and an outer wall 330 and inner wall 332.- Inner wall 332 extends a shorter
distance
than the entire extent of side pocket 290 so as to expose latch 320 of gauge
318. batch
320 provides the triple function of sealing the lower end of the side pocket
290, and
, providing a structure to maintain the sensor in the side pocket and also is
adapted to
engage a removal tool for when the sensor is changed. Seal 334 is of a metal-
to-metal
type and prevents primary bore fluid from "washing" the side pocket and
sensor. This
is advantageous because it reduces wear of the components. batch 320 includes
dogs
322 and 324 which are in a recessed position during installation of the gauge
318 but
extend into recesses 326 and 328 upon loading of the sensorin a known manner.
Once
WO 96/24745 PGT/US96/02182
2187434
. -4~_
the dogs 322, 324 are engaged with recesses 326 and 328, the sensor is secured
in the
side pocket. In order to remove the sensor from the side pocket, a removal
tool (not
shown) is run below the side pocket; next a kickover tool (not shown) is
employed to
push the removal tool over into the side pocket so that engagement with the
latch is
possible; a jerk upward to release the dogs and a jerk downward to withdraw
the sensor
is all that is necessary. The sensor can then be moved along in the primary
bore 288 as
desired. Inner wall 332 also includes a port 333 to allow pressure from the
primary
bore to reach the sensor or gauge 318. The port does not create any risk of
"washing"
but does as is known to one of skill in the art allow pressure to be read by
the sensor or
gauge. Also importantly, side pocket 290 of the invention is maintained in a
parallel
relationship to main bore 288 as opposed to some prior art side pocket
mandrels where
side pockets are positioned at an angle to the main bore. The arrangement of
the
present invention provides the advantage of a smaller overall diameter than
the prior
art. This allows entry into smaller identified boreholes and thus is clearly
beneficial to
the industry.
Also beneficial are the metal-to-metal high pressure fittings 338 and 340 of
the
invention which are disposed, one on the surface connection assembly 336 (338)
and
one in the throughbore 313 (340). The metal-to-metal fittings provide an
excellent high
pressure seal which has proven extremely reliable. The seal is aided by o-
rings 350 and
351.
The arrangement of the invention is advantageous not only for the reasons
discussed above but because it enables easy exchange of surface connection
assemblies.
While preferred embodiments have been shown and described, modifications
and substitutions may be made thereto without departing from the spirit and
scope of
the invention. Accordingly, it is to be understood that the present invention
has been
described by way of illustrations and not limitation.
What is claimed is:
