CROSS-REFERENCE TO RELATED APPLICATIONS
This application is a non-provisional application that claims priority to provisional
U.S. Patent application Serial No. 61/566,091 filed on December 2, 2011; the disclosure of
which is hereby incorporated by reference.
BACKGROUND
Embodiments disclosed herein relate generally to methods and apparatus for
A controlling well influx within a wellbore. In particular, embodiments disclosed herein relate to
methods to design and assemble well influx control systems.
During the past years, with the increase in price of fossil fuels, the interest in
developing new production fields has dramatically increased. However, the availability of landbased
production fields is limited. Thus, the industry has now extended drilling to offshore
locations, which appear to hold a vast amount of fossil fuel.
A traditional offshore oil and gas installation 10, as illustrated in FIG. 1, includes a
platform 20 (of any other type of vessel at the water surface) connected via a riser 30 to a
wellhead 40 on the seabed 50. It is noted that the elements shown in FIG. 1 are not drawn to
scale and no dimensions should be inferred from relative sizes and distances illustrated in FIG.
#
Inside the riser 30, as shown in the cross-section view, there is a drill string 32 at the
end of which a drill bit (not shown) is rotated to extend the subsea well through layers below the
seabed 50. Mud is circulated from a mud tank (not shown) on the drilling platform 20 through
the drill string 32 to the drill bit, and returned to the drilling platform 20 through an annular
space 34 between the drill string 32 and a casing 36 of the riser 30. The mud maintains a
hydrostatic pressure to counter-balancing the pressure of fluids coming out of the well and cools
the drill bit while also carrying crushed or cut rock to the surface. At the surface, the mud
returning from the well is filtered to remove the rock, and re-circulated.
2
Offshore oil and gas exploration requires many safety well control devices to be put in
place during drilling activities to prevent injury to personnel and destruction of equipment.
During oil and gas exploration, the many layers being drilled through may contain trapped fluids
or gases at different pressures. To balance these varying pressures, during the drilling process,
the pressure in the wellbore is generally adjusted to at least balance the formation pressure.
Some of the methods that may be utilized to balance these pressures include, but are not limited
to, increasing a density of drilling mud in the wellbore or increasing pump pressure at the
surface of the well.
During the drilling process, when a layer is encountered that includes a substantially
^ higher pressure than that of the wellbore, the well may be described as having encountered a
"kick". A kick is commonly detected by monitoring the changes in level of drilling mud which
returns from the annulus on the drilling ship as well as well pressure. If the burst is not
promptly controlled, the well and the equipment of the installation may be damaged. Blowout
preventers (BOPs) are one type of well control device that is often used to close, isolate, and seal
a wellbore during a high pressure event or kick. Blowout preventers are typically installed at the
surface or on the sea floor in deep water drilling arrangements so that kicks may be adequately
controlled and "circulated out" of the system. Blowout preventers operate in a similar manner as
large valves that are connected to the wellhead and comprise closure members configured to seal
and close the well in order to prevent the release of high-pressure gas or liquids from the well.
In addition, choke and kill lines are used to control the kick by adding denser mud. Although
there are many types of blowout preventers, the most common are annular blowout preventers
^ ^ and ram-type blowout preventers. In a preferred arrangement, annular blowout preventers are
typically located at the top of a blowout preventer stack, with one or two annular preventers
positioned above a series of several ram-type preventers.
Referring again to FIG. 1, during drilling, gas, oil or other well fluids at a high
pressure may burst from the drilled formations into the riser 30 and may occur at unpredictable
moments. In order to protect the well and/or the equipment that may be damaged, a blowout
preventer (BOP) stack 60 is located close to the seabed 50. The BOP stack may include a lower
BOP stack 62 attached to the wellhead 40, and a Lower Marine Riser Package ("LMRP") 64,
3
which is attached to a distal end of the riser 30. During drilling, the lower BOP stack 62 and the
LMRP 64 are connected.
A plurality of blowout preventers (BOPs) 66 located in the lower BOP stack 62 or in
the LMRP 64 are in an open state during normal operation, but may be closed (i.e., switched to a
close state) to interrupt a fluid flow through the riser 30 when a "kick" occurs. Electrical cables
and/or hydraulic lines 70 transport control signals from the drilling platform 20 to a controller
80, which is located on the BOP stack 60. The controller 80 controls the BOPs 66 to be in the
open state or in the closed state, according to signals received from the platform 20 via the
electrical cables and/or hydraulic lines 70. The controller 80 also acquires and sends to the
^ platform 20, information related to the current state (open or closed) of the BOPs. The term
"controller" used here covers the well-known configuration with two redundant pods.
Traditionally, as described, for example, in U.S. Patents No. 7395,878, 7,562,723, and
7,650,950 (the entire contents of which are incorporated by reference herein), a mud flow output
from the well is measured at the surface of the water by sensing device including a float in a
mud tank. The mud flow input into the well may be adjusted to maintain a pressure at the
bottom of the well within a targeted range or around a desired value, or to compensate for kicks
and fluid losses.
In one particular scenario, when a kick is detected based on feedback from the sensing
device, drilling is stopped, the blowout preventer valves (internal and external to the drill pipe)
^ ^ are closed and heavier drilling mud is pumped down the well bore through kill lines, while a
^ choke line is used to control the flow. When the kick has been controlled, heavier drilling mud
replaces the earlier lighter mud in the drill pipe, the choke and kill lines are closed, the blowout
preventers are opened and drilling is resumed. As stated, when a kick is detected, the drilling
must be stopped, in part due to the lack of a rotating wellhead. Alternative devices have been
proposed that allow for continuation of drilling through the use of a rotating wellhead that must
be configured as an additional, separate device assembled as part of the drill string below the
drill ship and prior to the commencement of drilling. The rotating wellheads are not configured
as an integral part of the BOP stack and require substantial amounts of additional seals to stop
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the flow of mud through the annulus. In addition, hydrostatic bearings and external lubrication
systems are needed to allow for rotation of the drill pipe within the rotating wellhead.
Another problem with the existing methods and devices is the relative long time (e.g.,
tens of minutes) between a moment when a disturbance of the mud flow occurs at the bottom of
the well and when a change of the mud flow is measured at the surface. Even if information
indicating a potential disturbance of the mud flow is received from the controller 80 faster, a
relative long time passes between when an input mud flow is changed and when this change has
a counter-balancing impact at the bottom of the well.
At Accordingly, there exists a need for an influx control system that allows for the
continuation of drilling activities during the presence of a substantially higher pressure than that
of the wellbore. More particularly, there exists a need for an influx control system that
eliminates the need to stop drilling during the presence of a potential blowout condition and
during regulation of the mud flow to prevent a blowout from occurring. In addition, there exists
a need for an influx control system that allows for sensing of the presence of a substantially
higher pressure in a manner that allows for a reduction in response time than current
technologies.
BRIEF DESCRIPTION
In accordance with an embodiment, an apparatus useable in an offshore drilling
installation close to the seabed for controlling well influx within a wellbore is provided. The
^ F apparatus including a centralizer and flow constrictor assembly, a sensor, and a controller. The
centralizer and flow constrictor assembly is configured to centralize a drill string within a drill
riser and regulate a return mud flow. The sensor is located close to the centralizer and flow
constrictor assembly and configured to acquire values of at least one parameter related to the
return mud flow. The controller is coupled to the centralizer and flow constrictor assembly and
the sensor. The controller is configured to control the centralizer and flow constrictor assembly
to achieve a value of a control parameter close to a predetermined value, based on the values
acquired by the sensor.
5
In accordance with another embodiment, an apparatus useable in an offshore drilling
installation close to the seabed for controlling well influx within a wellbore is provided. The
apparatus including a drill riser, a centralizer and flow constrictor assembly, a sensor and a
controller. The drill riser including a cavity extending from an annular space through which a
return mud flow passes. The annular space surrounding a drill string through which mud flows
towards a top of the well. The centralizer and flow constrictor assembly comprising a centralizer
component configured to centralize the drill string within the drill riser and a flow constrictor
component configured to regulate the return mud flow. The sensor is located close to the seabed
and configured to acquire values of at least one parameter related to the return mud flow. The
^ controller is coupled to the centralizer and flow constrictor assembly and the sensor. The
controller is configured to control the centralizer and flow constrictor assembly to achieve a
value of a control parameter close to a predetermined value, based on the values acquired by the
sensor.
In accordance with another embodiment, an apparatus useable in an offshore drilling
installation close to the seabed for controlling well influx within a wellbore is provided. The
apparatus including a drill riser, a centralizer and flow constrictor assembly, a sensor and a
controller. The drill riser including a cavity extending from an annular space through which a
return mud flow passes. The annular space surrounding a drill string through which mud flows
towards a top of the well. The centralizer and flow constrictor assembly including a first
centralizer component, a spaced apart second centralizer component and a flow constrictor
^ component. The sensor being disposed between the first and second centralizer components.
^ ^ The flow constrictor component including a throttle plate disposed on an uppermost surface of
the second centralizer component and including an opening therein for the return mud flow. The
throttle plate operable to regulate the return mud flow. The centralizer and flow constrictor
assembly further including a flexible bearing and a ram plate. The flexible bearing including a
bearing surface configured to seal about the drill string while allowing rotation of the drill string.
The ram plate having an opening therein for the return mud flow. The sensor is located close to
the seabed and configured to acquire values of at least one parameter related to the return mud
flow. The controller is coupled to the centralizer and flow constrictor assembly and the sensor.
The controller is configured to control the centralizer and flow constrictor assembly to achieve a
6
value of a control parameter close to a predetermined value, based on the values acquired by the
sensor.
Other aspects and advantages of the invention will be apparent upon reading the
following detailed description and the appended claims with reference to the accompanying
drawings.
BRIEF DESCRIPTION OF THE FIGURES
Jfc The above and other features, aspects, and advantages of the present disclosure will
become better understood when the following detailed description is read with reference to the
accompanying drawings in which like characters represent like parts throughout the drawings,
wherein
FIG. 1 is a schematic diagram of a conventional offshore drilling rig;
FIG. 2 is a schematic diagram of an apparatus for controlling well influx within a
wellbore, according to an exemplary embodiment;
FIG. 3 is a schematic diagram of a portion of a centralizer and flow constrictor
assembly installed about a drill string of FIG. 2, according to an exemplary embodiment;
FIG. 4 is a schematic diagram illustrating the lubrication feeds in a ram plate and a
^ ^ flexible element bearing of FIG. 2, according to an exemplary embodiment;
FIG. 5 is a schematic diagram illustrating a portion of a flexible element bearing of
FIG. 2, according to an exemplary embodiment; and
FIG. 6 is a schematic diagram of an apparatus for controlling well influx within a
wellbore, according to another exemplary embodiment; and
FIG. 7 is a schematic diagram of an apparatus for controlling well influx within a
wellbore, according to another exemplary embodiment.
7
DETAILED DESCRIPTION
Preferred embodiments of the present disclosure are illustrated in the figures like
numerals being used to refer to like and corresponding parts of the various drawings. It is also
understood that terms such as "top", "bottom", "outward", "inward", and the like are words of
convenience and are not to be construed as limiting terms. It is to be noted that the terms "first,"
"second," and the like, as used herein do not denote any order, quantity, or importance, but rather
are used to distinguish one element from another. The terms "a" and "an" do not denote a
limitation of quantity, but rather denote the presence of at least one of the referenced item. The
modifier "about" used in connection with a quantity is inclusive of the stated value and has the
( P meaning dictated by the context (e.g., includes the degree of error associated with measurement
of the particular quantity).
In one aspect, embodiments disclosed herein relate to subsea stack assemblies. FIGs.
2-5 illustrate schematic diagrams of an exemplary embodiment of an apparatus 100 useable in an
offshore drilling installation and more particularly a seabed well influx control system 102 for
controlling well influx within a wellbore. FIG. 3 is a partial cut-away view of a centralizer and
flow constrictor assembly of the apparatus 100. FIG. 4 is a schematic diagram illustrating a
plurality of lubrication feeds in the apparatus 100 and FIG. 5 is a schematic diagram illustrating a
portion of a flexible element bearing of the apparatus 100, all according to an exemplary
embodiment.
^. The apparatus 100 includes a centralizer component 101 and a flow constrictor
component 103 and is configured to automatically sense and regulate a returning mud flow in a
mud loop as a means for detecting an increase in pressure and preventing a potential blowout
condition. As illustrated in FIG. 2, the apparatus includes a platform (not shown) or any other
type of vessel at the water surface 104 connected via a riser 106 to a wellhead 108 on the seabed
110. It is noted that the elements shown in the Figures are not drawn to scale and no dimensions
should be inferred from relative sizes and distances illustrated in the Figures.
Inside the riser 106, there is disposed a drill string 112 at the end of which a drill bit
114 is rotated to extend the subsea well through layers 116 below the seabed 110. Mud,
indicated by arrows 118, is circulated in a mud loop, from a mud tank (not shown) on the
8
drilling platform through the drill string 112 to the drill bit 114, and returned to the drilling
platform through an annular space 120 between the drill string 112 and a casing 122 of the riser
106. In order to protect the well and/or the equipment that may be damaged during increased
pressure conditions, the seabed well influx control system 102 includes a plurality of spaced
apart centralizer and flow constrictor assemblies 128 positioned proximate the drill string 112
and located close to the seabed 110. The plurality of centralizer and flow constrictor assemblies
128 are configured in a vertical spaced apart relationship about the drill string 112 and in a
manner to center and hold the drill string 112 within the casing 122 and provide for constriction
of the mud flow therethrough, as desired.
^ F Each of the centralizer and flow constrictor assemblies 128, and more particularly
the centralizer component 101, includes a flexible element bearing 130 integrally formed
therewith a blowout preventer (BOP) 140. As best illustrated in FIGs. 3-5, each of the flexible
element bearings 130 includes a flexible face 132 and a plurality of high pressure lubrication
feeds, or orifices, 134 formed therethrough. In an embodiment, each of the plurality of flexible
element bearings 130 is formed of a plurality of segments 131, each of which may include steel
inserts, such as steel springs, wedges, or as illustrated in FIG. 5, a leaf spring 133. Each of the
plurality of flexible element bearings are formed of a flexible material, such as elastomer,
rubber, or the like.
During the drilling process, the flexible element bearing 130 is capable of flexing to
provide for insertion therethrough of a drill string tool joint 124. The flexible face 132 of each
^ P flexible bearing 130 is configured to provide sealing between the drill string 112 and the flexible
face 134 during drilling operations. The plurality of high pressure lubrication feeds 134 are
configured in fluidic communication with a plurality of high pressure fluid feeds 136 formed in
each of the blow out preventers 140, and more particularly ram plates (described presently).
Lubrication may be provided by pumping drilling mud or an external fluid at pressures above
that of the wellbore to ensure bias leakage of mud/fluid into the well, thus sealing any mud 118
to travel in an upward direction and around the drill string 112 due to kick. In an embodiment,
the high pressure lubrication feeds 134, 136 are configured to supply a drilling fluid which acts
as a lubricant between the drill string 112 and the flexible face 132 during the drilling operation,
9
as well as between the flexible element bearing 130 and the drill string tool joint 124 during
drilling operations.
In the disclosed embodiment, each of the plurality of flexible element bearings 130 is
integrally formed with one of the plurality of blowout preventers (BOPs) 140. Each of the
plurality of blow out preventers 140 is configured as split ram blow out preventers, such as those
commonly known in the art and additionally serves to centralize and hold the drill string 112
centered within the riser 106. In an embodiment, a first ram plate 142 is positioned proximate
the seabed 110 and a second ram plate 144 is positioned in a spaced apart relationship from the
first ram plate 142, and above the first ram plate 142, relative to the seabed 110. Each of the
^ P first and second ram plates 142, 144 include an opening 146 formed therein in a manner
providing for the flow of mud 118, initially pumped in a downward direction through the drill
string 112, to flow in an opposed, upward direction and back toward the water surface 104
through the riser 106 via the openings 146.
In addition, in the illustrated embodiment, at least an upper centralizer and flow
restrictor assembly 128, and more particularly the flow constrictor component 103, includes a
throttle plate 148. In an embodiment the throttle plate 148 is disposed on an uppermost surface
150 of the second ram plate 144, and having an opening 152 provided therein. The throttle plate
148 is operable to provide adjustment and/or constriction in the flow of mud 118 as it is returned
through the riser 106 toward the water surface 104. Although only a single throttle plate 152 is
illustrated in FIG. 2, it is anticipated that in an alternate embodiment a second redundant throttle
^fc plate (not shown) may be positioned on an uppermost surface of the first ram plate 142 and
operable in case of failure of the primary throttle plate 148. The throttle plate 148 is configured
as a valve and capable of regulating the returning mud flow 118, by modifying (increasing or
decreasing) a surface of an annular opening 152 formed therein and in operable
alignment/misalignment with the opening 146 formed in the second ram plate 144 to increase or
decrease in size. The throttle plate 148 is in an open state, with openings 152 in alignment with
openings 146, during normal operation, but may be closed (i.e., switched to a closed state) with
openings 152 in misalignment, or at least partial misalignment, with openings 146, to interrupt a
fluid flow through the riser 106 when under a high pressure event, such as when a "kick" occurs.
10
Throttling the flow using throttle plate is just one way to control flow. Other valve
types may be designed/incorporated in to the RAM plates to allow control of flow.
A sensor 154 is located on the riser 106, and more particularly, on an outer surface
156 of the casing 122, disposed between the first ram plate 122 and the second ram plate 124.
The sensor 154 is configured to acquire information related to a mud flow returning from the
bottom of the well. A distance from a source of the mud (i.e., a mud tank of a platform at the
water surface) to the seabed may be thousands of feet. Therefore it may take a significant time
interval (minutes or even tens of minutes) until a change of a parameter (e.g., pressure or flow
rate) related to the mud flow becomes measurable at the surface. Placement of the sensor
f P between the first ram plate 122 and the second ram plate 124 minimizes errors in reading flow
rate which arise due to the orbiting of the drill string 112 and minimizes response time.
The throttle plate 148 is actuated via actuators 149 (hydraulic or electrical) after
receiving commands from a controller 157 that has received a signal from the sensor 154.
Sensor 154 primarily measures flow velocity as a means of detecting kick. Change in velocity
above a certain percentage of normal velocity is considered a kick which starts the control
process. In an embodiment, the controller 156 is configured to automatically control the throttle
plate 148 based on the values received by the sensor 154, in order to regulate the returning mud
flow towards achieving a value of a control parameter close to a predetermined value.
Automatically controlling means that no signal from the surface is expected or required.
However, this mode of operating does not exclude a connection between the control loop and an
^fc external operator that may enable occasional manual operation or receiving new parameters,
such as, the predetermined value.
In one embodiment, the sensor 154 may include a pressure sensor and the control
parameter may be the measured pressure or another parameter that may be calculated based on
the measured pressure. The controller 156 controls the throttle plate 148 to slideably misalign
the opening 152 relative to the opening 146 thereby decreasing the flow and, thus, the dynamic
pressure if the pressure is larger than a set value, such as when under a high pressure event.
Likewise, the controller 156 controls the throttle plate 148 to slideably align the opening 152
relative to the opening 146 thereby increasing the flow and, thus, the dynamic pressure if the
11
pressure is smaller than the set value. The controlled pressure may be the pressure below the
throttle plate 148 or near a bottom of the well.
In another embodiment, the sensor 154 may also include a flow meter measuring the
mud flow therethrough, and the control parameter may be the mud flow itself. The controller
156 then controls the throttle plate 148 to close off the opening 152 if the mud flow is larger
than a set value, or to maintain the opening 152 in an open position if the mud flow is smaller
than the set value. Yet in another embodiment the controller 156 may receive information about
both the amount of returning mud flow from a mud flow meter and pressure from a pressure
sensor.
W In addition, as illustrated in FIG. 2, included are choke and kill (C/K) feed-thrus (or
lines) 158, 160, respectively, running alongside an exterior of the drilling riser 106, as commonly
known in the art. The C/K feed-thrus 158, 160 are operational to provide an input of heavier
drilling mud down the well bore through the kill feed-thru 160, while the choke feed-thru 158 is
used to control the flow during drilling and high pressure events.
Referring now to FIG. 6, illustrated is a schematic diagram of an exemplary
embodiment of an apparatus 200 useable in an offshore drilling installation and more
particularly, a seabed well influx control system 202. As previously indicated, it should be
understood that like numerals are used to refer to like and corresponding parts of the various
drawings.
^B In contrast to the previously disclosed embodiment, the apparatus 200 includes a
single centralizer and flow constrictor assembly 228, and more particularly a single centralizer
component 101 and a single flow constrictor component 103. As illustrated in FIG. 6, the
apparatus includes a riser 106 to connect a platform, or the like (not shown), to a wellhead 108
on the seabed 110. Inside the riser 106, is the drill string 112 at the end of which is the drill bit
114 to extend the subsea well through layers 116 below the seabed 110. Mud, indicated by
arrows 118, is circulated through the drill string 112 to the drill bit 114, and returned to the
drilling platform through an annular space 120 between the drill string 112 and a casing 122 of
the riser 106 via the single flow constrictor component 103. In order to protect the well and/or
the equipment that may be damaged during increased pressure conditions, the seabed well influx
12
control system 202 includes the single centralizer and flow constrictor assembly 228 positioned
proximate the drill string 112 and located close to the seabed 110. The centralizer and flow
constrictor assembly 228 is configured about the drill string 112 and in a manner to center and
hold the drill string 112 within the casing 122 and provide for constriction of the flow
therethrough.
The centralizer and flow constrictor assembly 228 includes a flexible element
bearing 130 integrally formed therewith a blowout preventer (BOP) 140 as previously described
with regard to FIG. 2-5. The flexible element bearing 130 includes a flexible face 132 and a
plurality of high pressure lubrication feeds, or orifices, 134 formed therethrough. The flexible
^ F element 130 is configured to flex for insertion and lubrication of the drill string tool joint 124.
The flexible element bearing 130 provides sealing between the drill string 112 and the flexible
face 132 during drilling operation. The plurality of high pressure lubrication feeds 134 are
configured in fluidic communication with a plurality of high pressure fluid feeds 136 formed in
the ram plate (described presently).
Similar to the previously disclosed embodiment, the blow out preventer 140 is
configured as split ram blow out preventer and serves to centralize and hold the drill string 112
centered within the riser 106. In this particular embodiment, due to the inclusion of a bypass
assembly as will be described, the drill string 112 is sufficiently maintained in a centralized
position with the use of a single centralizer component 101. Illustrated in FIG. 6 is a ram plate
242 positioned proximate the seabed 110. In contrast to the previously described embodiment,
4 p the ram plate 242 does not include an opening formed therein in a manner providing for the flow
of mud 118 therethrough as it is returned to the water surface 104. In this particular
embodiment, the flow of mud 118 is initially pumped in a downward direction through the drill
string 112, to flow in an opposed, upward direction and back toward the water surface 104
through a bypass assembly 244 and into the riser 106.
In an embodiment, the bypass assembly 244 includes a conduit 246 in fluidic
communication with the riser 106 at a conduit inlet 248 and a conduit outlet 250. The conduit
246 includes a throttle assembly 252 disposed therein. The throttle assembly 252 includes a
plurality of throttle plates 148 each having an opening 152 provided therein. The throttle plates
13
148 are operable to provide adjustment and/or constriction in the flow of mud 118 as it is
returned through the riser 106 toward the water surface 104 via the conduit 246, and more
particularly from a first side 255 of the single centralizer component 10) to a second side 257 of
the single centralizer component 10. More specifically, at least one of the throttle plates 252 is
moveable relative to the additional throttle plate 148 to align/misalign the openings 152 formed
therein, respectively. The throttle assembly 252 is in an open state during normal operation, but
may be closed (i.e., switched to a closed state) to interrupt a fluid flow through the riser 106
when under a high pressure event, such as when a "kick" occurs.
A sensor 154 is located on the conduit 246, and more particularly, on an outer surface
^ ^ 254 of the conduit 246. The sensor 154 is configured similar to that described in FIG. 2.
Placement of the sensor on the bypass assembly 244, and more particularly the conduit 246,
provides for a decrease in sensitivity of the sensor 154 to movement or vibration due to the drill
string 112 orbiting and minimizes throttle constriction response time.
The throttle plates 148 are configured as a valve and capable of regulating the
returning mud flow 118, by modifying (increasing or decreasing) a surface of the annular
openings 152 formed therein and operable by alignment/misalignment of the openings 152 to
increase or decrease in size. It is anticipated that in an alternate embodiment, the throttle plates
148 may be replaced by any type of valve operational to constrict the flow therethrough the
conduit 246, such as a gate valve, or the like. In an embodiment, the throttle plates 148 are
controlled by a controller 156 connected to the sensor 154 and operational as previously
^fc described. More particularly, the controller 156 controls the throttle plates 148 to slideably
misalign the openings 152 thereby decreasing the flow and, thus, the dynamic pressure if the
pressure is larger than a set value. The controller 156 controls the throttle plates 148 to slideably
align the openings 152 thereby increasing the flow and, thus, the dynamic pressure if the
pressure is smaller than the set value. In addition, as illustrated in FIG. 6, included are kill and
choke lines 158, 160, respectively, running alongside an exterior of the drilling riser 106, as
commonly known in the art.
Referring now to FIG. 7, illustrated is an embodiment similar to the embodiment
illustrated in FIG. 6, except in this particular embodiment, disclosed is an apparatus 300
14
including a single centralizer and flow constrictor assembly 228, and more particularly a single
flow constrictor component 103 and a single centralizer component 101, including a one-piece
annular head 302 and means for lubrication. As illustrated in FIG. 7, the apparatus is configured
generally similar to the previously described embodiment illustrated in FIG. 6 including a riser
106, a drill string 112, a ram plate 242 and bypass assembly 244.
In the embodiment illustrated in FIG. 7, the centralizer component 101 includes the
one-piece annular bearing 302 having formed therein plurality of high pressure fluid feeds 134 in
alignment with a plurality of high pressure feeds 136 formed in the ram plate 140. Additional
information on the one-piece annular bearing 302 can be found, for example, in U.S. Publication
^ ^ No. 2008/0023917 (the entire contents of which are incorporated by reference herein). The
inclusion of the one-piece annular bearing 302 provides an improved design that serves to
improve the stability of the drill string 112 and bearing surfaces during orbiting of the drill string
112.
Although the above-described embodiments have been described for an offshore
drilling installation, similar embodiments may be integrated in land-based drilling installations.
The disclosed exemplary embodiments provide apparatuses for well influx control,
and more particularly provide for the continuation of drilling operation when a potential well
bore kick condition is detected in an offshore installation. In addition, due to the proximity of
the sensor, flow constrictor assembly and controller, the control is performed promptly (e.g., less
_ than a tenth of a second between detection and corrective action, as opposed to minutes in the
^ ^ conventional approach) and can be performed frequently (e.g., few times every second).
At least some of the embodiments result in an increase of safety. A response time for
return flow variation is significantly reduced without requiring expensive equipment or shut
down of the drilling operation. The rotating wellhead areis configured as an integral part of the
BOP stack and therefore require minimal seals to stop the flow of mud through the annulus.
These enhancements result in better control of the pressure of the bottom of the well and
maintaining the equivalent circulating pressure within a narrower range. Due to the better
control of the pressure at the bottom of the well the formation damage and shut down
occurrences are reduced and fewer situations of stuck drill pipe occur.
15
It should be understood that this description is not intended to limit the invention. On
the contrary, the exemplary embodiments are intended to cover alternatives, modifications and
equivalents, which are included in the spirit and scope of the invention as defined by the
appended claims. Further, in the detailed description of the exemplary embodiments, numerous
specific details are set forth in order to provide a comprehensive understanding of the claimed
invention. However, one skilled in the art would understand that various embodiments may be
practiced without such specific details.
Although the features and elements of the present exemplary embodiments are
described in the embodiments in particular combinations, each feature or element can be used
^ } alone without the other features and elements of the embodiments or in various combinations
with or without other features and elements disclosed herein.
This written description uses examples of the subject matter disclosed to enable any
person skilled in the art to practice the same, including making and using any devices or systems
and performing any incorporated methods. The patentable scope of the subject matter is defined
by the claims, and may include other examples that occur to those skilled in the art. Such other
examples are intended to be within the scope of the claims.
While the present disclosure has been described with respect to a limited number of
embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other
embodiments may be devised which do not depart from the scope of the disclosure as described
herein. While the present disclosure has been described with reference to exemplary
^ ^ embodiments, it will be understood by those skilled in the art that various changes may be made
and equivalents may be substituted for elements thereof without departing from the scope of the
disclosure. In addition, many modifications may be made to adapt a particular situation or
material to the teachings of the present disclosure without departing from the essential scope
thereof. Therefore, it is intended that the present disclosure not be limited to the particular
embodiment disclosed as the best mode contemplated for carrying out the disclosure. It is,
therefore, to be understood that the appended claims are intended to cover all such modifications
and changes as fall within the true spirit of the disclosure.
16
Parts List
10 offshore oil and gas installation
12
14
16
18
20 platform
22
24
w 28
30 riser
32 drill string
34 annular space
36 casing
38
40 wellhead
42
44
46
48
^ ^ 50 seabed
52
54
56
58
60 BOP stack
62 lower BOP stack
64 lower marine riser package (LMRP)
66 blow out preventers
68
17
70 electrical cables and/or hydraulic lines
72
74
76
78
80 controller
82
84
86
90
92
94
96
98
100 apparatus
1 o 1 centralizer component
102 seabed well influx control system
103 flow constrictor component
104 water surface
106 riser
^ ^ 108 wellhead
110 seabed
112 drill string
114 drill bit
116 layers
118 mud
120 annular space
122 casing
124 drill string tool joint
126
18
128 plurality of centralizer and flow constrictor assemblies
130 plurality of flexible element bearings
131 flexible segments
132 flexible face
133 leaf spring
134 high pressure lubrication feeds
135
plurality of high pressure fluid feeds 136 formed in each of the blow out preventers
136 140
^ 137
138
140 blow out preventers
142 first ram plate
144 second ram plate
146 opening
148 throttle plate
149 actuators
150 uppermost surface of 144
152 opening in 148
154 sensing device
156 outer surface of casing
157 controller
^ ^ 158 choke
159
160 kill line
19

WE CLAIM :
1. An apparatus (100, 200, 300) useable in an offshore drilling installation close to the
seabed (110) for controlling well influx within a wellbore comprising:
a centralizer and flow constrictor assembly (128, 228) configured to centralize a drill
string (112) within a drill riser (106) and regulate a return mud flow (118);
a sensor (154) located close to the centralizer and flow constrictor assembly (128, 228)
and configured to acquire values of at least one parameter related to the return mud flow (118);
^k and
a controller (157) coupled to the centralizer and flow constrictor assembly (128, 228) and
the sensor (154), the controller (157) configured to control the centralizer and flow constrictor
assembly (128, 228) to achieve a value of a control parameter close to a predetermined value,
based on the values acquired by the senso (154).
2. The apparatus (100, 200, 300) of claim 1, wherein the centralizer and flow constrictor
assembly (128, 228) comprises:
at least one centralizer component (101); and
a flow constrictor component (103).
3. The apparatus (100, 200, 300) of claim 2, wherein the centralizer component (101) is
( ^ comprised of a ram plate (142, 242) and an integrally formed flexible element bearing (130), the
flexible element bearing (130) including a bearing surface (134) configured to seal about the drill
string (112) while allowing for low friction rotation of the drill string (112).
4. The apparatus (100, 200, 300) of claim 3, wherein the flow constrictor component
(103) is comprised of at least one throttle plate (148), including an opening (152) therein for the
return mud flow (118), the throttle plate (148) operable to regulate the return mud flow (118).
5. The apparatus (100) of claim 4, wherein the centralizer and flow constrictor assembly
comprises:
20
a first centralizer component (101);
a spaced apart second centralizer component (101); and
a throttle plate (148) disposed on an uppermost surface (150) of the second centralizer
component (101),
wherein the first and second centralizer components (101) each comprise a ram plate
(140) having an opening (146) therein for the return mud flow (118).
6. The apparatus (100) of claim 5, wherein the sensor (154) is disposed on the drill riser
(112) between the first centralizer component (101) and the second centralizer component (101).
m
^ 7. The apparatus (200, 300) of claim 3, wherein the centralizer and flow constrictor
assembly (228) comprises a single centralizer component (101) and a bj^jass assembly (244)
configured to provide a return mud flow (118) from a first side (255) of the single centralizer
component (101) to a second side (257) of the single centralizer component (101).
8. The apparatus (200, 300) of claim 7, wherein the bypass assembly (244) comprises a
conduit (246) having a valve (252) disposed between a conduit inlet (248) and a conduit outlet
(250) and operable to regulate the return mud flow (118), wherein the valve(252) is comprised of
a plurality of throttle plates (148) each including an opening (152) therein for the return mud
flow (118).
^ 9. The apparatus (200, 200) of claim 8, wherein the sensor (154) is disposed on the
conduit (246) between the conduit inlet (248) and the valve (252).
10. An apparatus (100, 200, 300) useable in an offshore drilling installation close to the
seabed (110) for controlling well influx within a wellbore comprising:
a drill riser (106) including a cavity extending from an annular space (120) through which
a return mud flow (118) passes, the annular space (120) surrounding a drill string (112) through
which mud flows (118) towards a top of the well;
21
a centralizer and flow constrictor assembly (128, 228) comprising a centralizer
component (101) configured to centralize the drill string (112) within the drill riser (106) and a
flow constrictor component (103) configured to regulate the return mud flow (118);
a sensor (154) located close to the seabed (110) and configiured to acquire values of at
least one parameter related to the return mud flow (118); and
a controller (157) coupled to the centralizer and flow constrictor assembly(128, 228) and
the sensor (154), the controller (157) configured to control the centralizer and flow constrictor
assembly (128, 228) to achieve a value of a control parameter close to a predetermined value,
based on the values acquired by the sensor (154).