Note: Descriptions are shown in the official language in which they were submitted.
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TITLE: CLOSED LOOP FLUID-HANDLING SYSTEM
FOR USE DURING DRILLING OF WELLBORES
Field of the Invention
s
This invention relates generally to drilling of wellbores and more
particularly to a fluid-handling system for use in underbalanced drilling of
wellbores.
to Background of the Art
In conventional drilling of wellbores for the production of hydrocarbons
from subsurface formations, wellbores are drilled utilizing a rig. A fluid
comprising water and suitable additive, usually referred to in the art as
"mud,"
is is injected under pressure through a tubing having a drill bit which is
rotated
to drill the wellbores. The pressure in the wellbore is maintained above the
formation pressure to prevent blowouts. The mud is circulated from the
bottom of the drill bit to the surface. The circulating fluid reaching the
surface
comprises the fluid pumped downhole and drill cuttings. Since the fluid
2o pressure in the wellbore is greater than the formation pressure, it causes
the
mud to penetrate into or invade the formations surrounding the wellbore.
Such mud invasion reduces permeability around the wellbore and reduces
accuracy of measurements-while-drilling devices commonly used during
drilling of the wellbores. Such wellbore damage (also known as the skin
2s damage or effect) may extend from a few centimeters to several meters from
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the wellbore. The skin damage results in a decrease in hydrocarbon
productivity.
To address the above-noted problems, some wells are now drilled
s wherein the pressure of the circulating fluid in the wellbore is maintained
below the formation pressure. This is achieved by maintaining a back
pressure at the wellhead. Since the wellbore pressure is less than the
formation pressure, fluids from the formation (oil, gas and water) co-mingles
with the circulating mud. Thus, the fluid reaching the surtace contains four
io phases: cuttings (solids), water, oil and gas. Such drilling systems
require
more complex fluid-handling systems at the surface. The prior art systems
typically discharge the returning fluids ("wellstream") into a pressure vessel
or separator at the surtace to separate sludge (solids), water, oil and gas.
The pressure in the vessel typically exceeds 1000 psi. A number of manually
is controlled valves are utilized to maintain the desired pressure in the
separator and to discharge the fluids from the pressure vessel. These prior
art systems also utilize manually controlled emergency shut down valves to
shut down the drilling operations. Additionally, these systems rely upon
pressure measured at the wellhead to control the mud pressure downhole. In
2o many cases this represents a great margin of error. These prior art fluid-
handling systems require the use of high pressure vessels, which are (a)
relatively expensive and less safe than low pressure vessels, (b) relatively
inefficient, and (c) require several operators to control the fluid-handling
system.
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The present invention addresses the above-noted deficiencies of the
prior art fluid-handling systems and provides a relatively low pressure fluid-
handling system which utilizes remotely controlled fluid flow control devices
s and pressure control devices, along with other sensors to control the
separation of the constituents of the wellstream. The present invention also
provides means for controlling the wellbore pressure from the surface as a
function of the downhole measured pressure.
SUMMARY OF THE INVENTION
This invention provides a fluid-handling system for use in
underbalanced drilling operations. The system includes a first vessel which
acts a tour phase separator. The first vessel includes a first stage for
is separating solids. Oil and gas are separated at a second stage into
separate
reservoirs. A pressure sensor associated with the first vessel provides a
signal to a pressure controller which modulates a gas flow valve coupled to
the vessel for discharging gas from the first vessel. The pressure controller
maintains the pressure in the first vessel at a predetermined value. An oil
20 level sensor placed in the first vessel provides a signal to an oil level
controller. The oil level controller modulates an oil flow valve coupled to
the
vessel to discharge oil from the first vessel into a second vessel. The oil
level controller operates the oil flow valve so as to maintain the oil level
in the
first vessel at a predetermined level. Similarly, water (fluid that is
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substantially free of oil and solids) is discharged into a third vessel. Water
from the third vessel is discharged via a water flow control valve, which is
modulated by a level controller as a function of the water level in the third
vessel. Any gas in the third vessel is discharged by modulating a gas control
s valve as a function of the pressure in the third vessel.
In an alternative embodiment, a central control unit or circuit is utilized
to control the operations of all the flow valves. Signals from the pressure
sensors and level sensors are fed to the control unit, which controls the
io operations of each of the flow control valves based on the signals received
from the various sensor and in accordance with programmed instructions.
During operations, the control unit maintains the pressure in each of the
vessels at their respective predetermined values. The control unit also
maintains the fluid levels in each of the vessels at their respective
is predetermined values.
The system of the present invention also determines the downhole
pressures, including the formation pressure and controls the drilling fluid
flow
into the wellbore to maintain a desired pressure at the wellhead. The system
2o also automatically controls the drilling fluid mix as a function of one or
more
desired operating parameters to control the density of the circulating fluid.
Examples of the more important features of the invention have been
- summarized rather broadly in order that the detailed description thereof
that
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follows may be better understood, and in order that the contributions to the
art may be appreciated. There are, of course, additional features of the
invention that will be described hereinafter and which will form the subject
of
the claims appended hereto.
s
BRIEF DESCRIPTION OF THE DRAWINGS
For detailed understanding of the present invention, references should
be made to the following detailed description of the preferred embodiment,
io taken in conjunction with the accompanying drawings, in which like elements
have been given like numerals, wherein:
FIG. 1 shows a schematic of a fluid handling system according to the
present invention.
is
FIG. 1A shows a functional block diagram of a control system for use
with the system of FIG. 1 for controlling the operation of the fluid handling
system.
FIG. 2 shows the fluid handling system of FIG. 1 in conjunction with a
2o schematic representation of a wellbore with a drilling assembly conveyed
therein for automatically controlling the wellhead pressure, downhole
circulating fluid pressure and the drilling fluid mix.
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DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
FIG. 1 shows a schematic of a fluid-handling system 100 according to
s the present invention. During underbalanced drilling of a wellbore, a
drilling
fluid (also referred to as the "mud") is circulated through the wellbore to
facilitate drilling of the wellbore. The fluid returning from the wellbore
annulus (referred herein as the "wellstream") typically contains the drilling
fluid originally injected into the wellbore, oil, water and gas from the
to formations, and drilled cuttings produced by the drilling of the wellbore.
In the system 100, the wellstream passes from a wellhead equipment
101 through a choke valve 102 which is duty-cycled at a predetermined rate.
A second choke valve 104 remains on one hundred percent (100%) standby.
1s The duty-cycled valve 102 is electrically controlled so as to maintain a
predetermined back pressure. The wellstream then passes through an
emergency shut-down valve ("ESD") 106 via a suitable line 108 into a four
phase separator (primary separator) 110. The choke valve 102 creates a
predetermined pressure drop between the wellhead equipment 110 and the
2o primary separator 100 and discharges the wellstream into the primary vessel
at a relatively low pressure, typically less than 100 psi. In some
applications,
it may be desirable to utilize more that one choke valve in series to obtain a
sufficient pressure drop. Such choke valves are then preferably
independently and remotely controlled as explained in more detail later.
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The primary separator 110 preferably is a four phase separator. The
wellstream entering into the separator 110 passes to a first stage of the
separator 110. Solids (sludge), such as drilled cuttings, present in the
s wellstream are removed in the first stage by gravity forces that are aided
by
centrifugal action of an involute entry device 112 placed in the separator
110.
Such separation devices 112 are known in the art and, thus, are not
described in detail. Any other suitable device also may be utilized to
separate the solids from the wellstream. The solids being heavier than the
io remaining fluids collect at the bottom of the primary separator 100 and are
removed by a semi-submersible sludge pump 114. A sensor 113 detects the
level of solids build-up in the separator 110 and energizes the pump 114 to
discharge the solids from the separator 110 into a solids waste place 115 via
a line 115a. The operation of the sludge pump 114 is preferably controlled
is by a control system placed at a remote location. FIG. 1A shows a control
system 200 having a control unit or control circuit 201, which receives
signals
from a variety of sensors associated with the fluid-handling system 100,
determines a number of operating parameters and controls the operation of
the fluid-handling system 100 according to programmed instruction and
2o models provided to the control unit 201. The operation of the control
system
200 is described in more detail later.
The fluid that is substantially free of solids passes to a second stage,
which is generally denoted herein by numeral 116. The second stage 116
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essentially acts as a three phase separator to separate gas, oil and water
present in the fluids entering the second stage. The gas leaves the separator
110 via a control valve 120 and line 122. The gas may be flared or utilized in
any other manner. A pressure sensor 118 placed in the separator 110 and
s coupled to the control unit 201 is used to continually monitor the pressure
in
the separator 110. The control unit 201 adjusts the control valve 120 so as to
maintain the pressure in the vessel 110 at a predetermined value or within a
predetermined range. Alternatively, a signal from the pressure sensor 118
may be provided to a pressure controller 118a, which in turn modulates the
io control valve 120 to maintain the pressure in the separator at a
predetermined value. Both a high and a low pressure alarm signals are also
generated from the pressure sensor 118 signal. Alternatively, two pressure
switches may be utilized, wherein one switch is set to provide a high pressure
signal and the other to provide a low pressure signal. The control unit 201
is activates an alarm 210 (FIG. 1a) when the pressure in the separator is
either
above the high level or when it falls below the low level.
The control unit 201 may also be programmed to shut down the system
100 when the pressure in the separator is above a predetermined maximum
20 level ("high-high") or below a predetermined minimum level ("low-low")
Alternatively, the system 100 may be shut down upon the activation of
pressure switches placed in the separator, wherein one such switch is
activated at the high-high pressure and another switch is activated at the low-
low pressure. The high-high pressure trip protects against failure of the
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upstream choke valves 102 and 104, while the low-low trip protects the
system against loss of containment within the vessel 110.
The oil contained in the fluid at the second stage 116 collects in a
s bucket 124 placed in the second stage 116 of the separator 110. A level
sensor 126 associated with the bucket 124 is coupled to the control unit 201,
which determines the level of the oil in the bucket 124. The control unit 201
controls a valve 128 to discharge the oil from the separator 110 into an oil
surge tank 160. Alternatively, the level sensor 126 may provide a signs! to a
io level controller 126a, which modulates the control valve 128 to control the
oil
flow from the bucket 124 into the oil surge tank 160. The oil level sensor
signals also may be used to activate alarms 210 when the oil level is above a
maximum level or below a minimum level.
is In the second stage 116, fluid that is substantially free of oil (referred
to herein as the "water" for convenience) flows under the oil bucket 124 in
the
area 116 and then over a weir 134 and collects into a water chamber or
reservoir 136. A level sensor 138 is placed in the water reservoir 136 and is
coupled to the control unit 201, which continually determines the water level
2o in the reservoir 136. The control unit 201 is programmed to control a valve
140 to discharge the water from the separator 110 into a water tank 145 via a
line 142. Alternatively, the level sensor 128 may provide a signal to a level
controller 138a which modulates the control valve 140 to discharge the water
from the separator 110 into the water tank 145. Additionally, the liquid level
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in the main body of the separator is monitored by a level switch 142 which
provides a signal when the liquid level in the main body of the separator 110
is above a maximum level, which signal initiates the emergency shut down.
This emergency shut down prevents any liquid passing into the gas vent or
into any flare system used.
Any gas present in the water discharged into the water tank separates
within the water tank 145. Such gas is discharged via a control valve 147 to
flare 122a. A pressure sensor 148 associated with the water tank 145 is
utilized to control the control valve 147 to maintain a desired pressure in
the
water tank 145. The control valve 147 may be modulated by a pressure
controller 148a in response to signals from the pressure sensor 148.
Alternatively, the control valve 147 may be controlled by the control unit 201
in
response to the signals from the pressure sensor 148. Alarms are activated
when the pressure in the water tank 145 is above or below predetermined
lirnits. Water level in the water tank 145 is monitored by a level sensor 150.
A level controller 150a modulates a control valve 152 in response to the level
sE:nsor signals to maintain a desired liquid level in the water tank 145.
Alternatively, control unit 201 may be utilized to control the valve 152 in
response to the level sensor signals. The fluid level in the water tank 145
also
is monitored by a level switch 151, which initiates an emergency shutdown of
the system if the level inadvertently reaches a predetermined maximum level.
A pump 155 passes the fluids from the water tank 145 to the control valve
152. The fluid leaving the valve 152 discharges via a line 153 into a drilling
fluid tank 154.
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Any gas present in the oil surge tank 160 separates within the oil
surge tank 1fi0. The separated gas is discharged via a control valve 1fi4 and
a line 165 to the gas line 122 to flare 122a. A pressure sensor 162 associated
with the oil surge tank 160 is utilized to control the control valve 164 in
order
to maintain a desired pressure in the oil surge tank 1fi0. The control valve
164 may be modulated by a pressure controller 1fi2a in response to signals
from the pressure sensor 162. Alternatively, the operation of the control
valve
1fi4 may be controlled by the control unit 201 in response to the signals from
the pressure sensor 1fi2. Alarms 210 are activated when the pressure in the
oil surge tank 160 is either above or below their respective predetermined
limits. Oil level in the oil surge tank 1fi0 is monitored by a level sensor
168. A
level controller 168a modulates a control valve 170 in response to the level
sensor signals to maintain a desired liquid level in the oil surge tank 160.
Alternatively, the control unit 201 may be utilized to control the valve 170
in
reaponse to the signals from the level sensor 1fi8. The liquid level in the
oil
surge tank 1fi0 also is monitored by a level switch 169, which initiates an
emergency shutdown of the system if the level inadvertently reaches a
predetermined maximum level. A pump 172 passes the fluids from the oil
surge tank 160 to the control valve 170. The fluid leaving the valve 170
discharges via a line 174 into an oil tank or oil reservoir 176.
Still referring to FIGS. 1 and 1A, the control unit 201 may be placed at
a suitable place in the field or in a control cabin having other control
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equipment for controlling the overall operation of the drilling rig used for
drilling the wellbore. The control unit 201 is coupled to one or more monitors
or display screens 212 for displaying various parameters relating to the fluid-
handling system 100. The control unit 201 is also coupled to peripherals 214.
Suitable data entry devices, such as touch-screens or keyboards are utilized
to enter information and instructions into the control unit 201. The control
unit
201 contains one or more data processing units, such as a computer,
programs and models for operating the fluid-handling system 100.
In general, the control unit 201 receives signals from the various
sensors described above and any other sensors associated with the fluid-
handling system 100 or the drilling system. The control unit 201 determines
oar computes the values of a number of operating parameters of the fluid-
handling system and controls the operation of the various devices based on
such parameters according to the programs and models provided to the
control unit 201. The ingoing or input lines S1-S~ connected to the control
unit 201 indicate that the control unit 201 receives signals and inputs from
various sources, including the sensors of the system 100. The outgoing or
output lines C1-Cm are shown to indicate that the control unit 201 is coupled
to the various devices in the system 201 for controlling the operations of
such
devices, including the control valves 102, 104, 120, 128, 147, 152, 164, 168
and 170, and pumps 114, 155 and 172.
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Referring now to FIGS. 1, 1A and 2, prior to the operation of the
system 100, an operation stationed at the control unit 201, which is
preferably
placed at a safe distance from the fluid-handling system 100, enters desired
control parameters, including the desired levels or ranges of the various
parameters, such as the fluid levels and pressure levels. As the drilling
starts, the control unit 201 starts to control the flow of the wellstream from
the
wellbore 225 by controlling the valves 102 and 104 so as to maintain a
desired back pressure. The control unit 201 also controls the pressure in the
separator 110, the fluid levels in the separator 110 and each of the tanks 145
and 160, the discharge of solids from the separator 110 and the discharge of
the gases and fluids from the tanks 145 and 160.
As noted earlier, prior art systems control the wellbore pressure by
maintaining the pressure at the surface at a desired value. Based on the
depth of the wellbore and the types of fluids utilized during drilling of the
wellbore, the actual downhole pressure can vary from the desired pressure
by several hundred pounds. In order to accurately control the pressure in the
wellbore, the present system includes a pressure sensor 222a for measuring
the pressure at the wellhead 101, a pressure sensor 222b in the drill string
224 for measuring the pressure of the drilling fluid in the drill string 224
and a
pressure sensor 222c in the drill string 224 for measuring the pressure in the
annulus between the drill string 224 and the wellbore 225. Other types of
sE:nsors, such as differential pressure sensors, may also be utilized for
determining the differential pressures downhole. During the drilling
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operations, the control unit 201 periodically or continually monitors the
pressures from the sensors 222a, 222b and 222c and controls the fluid flow
rate into the wellbore 225 by controlling so as to maintain the wellbore
pressure at a predetermined value or within a predetermined range. The drill
s string 224 may also include other sensors, such as a temperature sensor
223, for measuring the temperature in the wellbore 225.
During underbalanced drilling, the drilling fluid is mixed with other
materials, such as nitrogen, air, carbon dioxide, air-filled balls and other
to additives to control the drilling fluid density or the equivalent
circulating
density and to create foam in the drilling fluid to provide gas lift downhole.
FIG. 2 shows an embodiment 100a of the fluid handling system of the present
invention which can automatically control the drilling fluid mix as a function
of
downhole measured operating parameters, such as the formation pressure,
is or any other selected parameters. As shown in !=IG. 2, the system 100a
includes one or more sources 302 of materials (additives) to be mixed with
the drilling mud from the mud tank 154. The drilling fluid from the mud tank
154 passes to a mixer 310 via an electrically-controlled flow valve 304. The
additives from the source 302 pass to the mixer 310 via an electrically-
2o controlled flow valve 306. The controller 201 receives information about
the
dovirnhole parameters from the various sensors S, - S~, including the pressure
sensors 222a, 222b, and 222c, and temperature sensor 223 and determines
the selected parameters to be controlled, such as the formation pressure.
The system 100a is provided with a model 308 for use by the control unit 201
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to determine the drilling fluid mix. The control unit 201 periodically or
continually determines the required fluid mix as a function of one or more of
the selected operating parameters and operates the control valve 304 via
control line CQ to discharge the correct amount of the additive materials to
s obtain the desired mix. The control unit 201 also controls the fluid control
valve 306 via line CP to control the drilling fluid flow into the mixer 310.
The
mixed fluid is discharged into the wellbore 225 from the mixer 310 via line
312 to maintain the desired pressure in the wellbore. The mud from the mud
tank 154 and the additives from the source 302 are preferably mixed at a
io juncture or mixer 310 and discharged into the wellbore via line 312. The
additives and the drilling fluid, however, may be injected separately into the
wellbore 225. In some applications it may be more desirable to inject the
additives at or near the bottom of the drill string 224 via a separate line
(not
shown) so that the mixing occurs near the drill bit 226.
is
Thus, the fluid handling system of the present invention provides a
closed loop fluid handling system which automatically separates the
wellstream into its constituent parts, discharges the separated constituent
parts into their desired storage facilities. The system also automatically
2o controls the pressure in the wellbore and drilling fluid mixture as a
function of
selected operating parameters.
The above-described system requires substantially less manpower to
operate in contrast to known fluid-handling systems utilized during
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underbalanced drilling of wellbores. The pressure in the main separator 110
is relatively low compared to known prior art systems, which typically operate
at a pressure of more than 1000 psi. Low pressure operations reduce the
costs associated with manufacture of separators. More importantly, the low
s pressure operations of the present system are inherently safer that the
relatively high pressure operations of the prior art systems. The control of
the
wellhead pressure and the drilling fluid mix based on the downhole
measurements during the drilling operations provide more accurate control of
the pressure in the wellbore.
io
While the foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be apparent to those
skilled in the art. It is intended that all variations within the scope and
spirit of
the appended claims be embraced by the foregoing disclosure.
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