Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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Title: Method of Operating a Drilling System
Description of Invention
The present invention relates to a method of operating a drilling system,
particularly to a method for use in the offshore drilling of a well for oil
and/or
gas production, in particular for controlling the well in the event of an
influx or
kick or during an emergency disconnect procedure.
The drng of a wellbore is typically carried out using a steel pipe known as a
drill string with a drill bit on the lowermost end. The entire drill string
may be
rotated using an over-ground drng motor, or the drill bit may be rotated
independently of the drill string using a fluid powered motor or motors
mounted
in the drill string just above the drill bit. In offshore drilling, a drilling
rig, having
a rig floor, is provided for drilling a wellbore through the seabed beneath
water
=
surface. The drill string extends from the drilling rig into the weilbore via
a
blowout preventer (BOP) stack which is disposed on the seafloor above a =
:===
wellhead. A riser extends up from the BOP stack around the drill string, and
..==
=
choke and kill lines are provided between the rig and blowout preventer stack,
:=
=
for use well control,
:==
As drilling progresses, a flow of mud is used to carry the debris created by
the
drilling process out of the wellbore. Mud is pumped through an inlet line down
the drill string to pass through the drill bit, and returns to the surface via
the
annular space between the outer diameter of the drill string and the weilbore
(generally referred to as the annulus). The annular space between the riser
and the drill string, hereinafter referred to as the riser annulus, serves as
an
extension to the annulus, and provides a conduit for return of the mud to mud
reservoirs. The frictional forces arising from circulation of mud through the
wellbore contribute to the fluid pressure in the wellbore ("wellbore
pressure"),
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2
õ==
and the theoretical density of the mud which, when static, would provide the
wellbore pressure achieved when mud of the actual density is circulating is
known as the equivalent circulating density (ECD).
Mud is a very broad drng term, and in this context it is used to describe any
fluid or fluid mixture used during drilling and covers a broad spectrum from
air,
=
nitrogen, misted fluids in aft or nitrogen, foamed fluids with aft or
nitrogen,
aerated or nitrified fluids to heavily weighted mixtures of oil or water with
solid
particles.
The mud flow also serves to cool the drill bit, and in conventional
overbalanced
drilling, the density of the mud is selected so that it produces a weilbore
pressure which is high enough to counter balance the pressure of fluids in the
formation ("the formation pore pressure"), thus substantially preventing
ifflow
of fluids from formations penetrated by the weilbore entering into the
wellbore.
If the welibore pressure falls below the formation pore pressure, an influx of
formation fluid ¨ gas, oil or water, can enter the weilbore in what is known
as a
kick. On the other hand, if the wellbore pressure is excessively high, it
might
be higher than the fracture strength of the rock in the formation. If this is
the
case, the pressure of mud in the wellbore fractures the formation, and mud
can enter the formation. This loss of mud causes a momentary reduction in
welibore pressure which can, in turn, lead to the formation of a kick.
:==
When offshore drilling of the wellbore is carried out using a floating rig
such as
a drill ship, a semi-submersible, floating drilling or production platform, it
is
known to provide the riser with a slip joint which allows the riser to
le.ngthen
and shorten as the rig moves up and down as the sea level rises and falls with
the tides, heave and waves. A diverter is typically mounted above the upper
flex joint and the slip joint, and is a low pressure annular sealing device
used
to close and pack-off the annulus around the drilling string or, if no drill
string is
present to close the riser completely. The diverter is provided with diverter
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=
=
ones which provide a conduit for the controlled release of fluid from the
riser or
=
riser annulus. As such, the diverter provides a means of removing gas in the
=
=
riser by routing the contents overboard in a direction where the wind will not
=
carry the diverted fluids back to the drilling rig.
=
An alternative configuration of off-shore drilling installation is described
in =
õ===
W02013/153135, In this installation, there is an annular blowout preventer
provided in the riser below the slip joint, which is operable to seal around
the
drill string to close the riser annulus A flow spool is mounted in the riser
below the annular blowout preventer and is provided with two flow outlets
which are each connected to one of two conduits up to the drilling rig, where
=
each of the conduits is connected to an inlet of a gas handling manifold. The
flow spool is also provided with isolation valves which are operable to close
the first and second conduits.
The gas handling manifold comprises two selectively adjustable restriction
devices such as a pressure control valves, each of which is connected to one
of the inlets. Each pressure control valve is coupled with an actuator and a
riser gas handling controller which comprises a microprocessor which is
=
programmed with the supervisory control and data acquisition software
=
SCADA. The gas handling manifold is provided with a main outlet, to which
outlets of both pressure control valves are connected. The outlet is connected
a mud gas separator (MGS).
It is known to monitor the fluid pressure and/or the rate of flow of fluid at
various points throughout the drilling system in order to determine whether an
influx or kick has occurred, if an influx / kick is detected, various control
procedures may be implemented, depending on the extent or severity of the
influx.
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In conventional well control, a set of procedures are executed in preparation
to
shut in the wellbore by closing the BOP. These procedures include picking up
the drill string of the bottom of the wellbore, stopping drill string
rotation,
carrying out a flow check, and shutting down the mud pumps. Once the BOP
is closed, a remotely operated valve on the BOP, known in the art as an HCR
valve, ¨ a¨is opened to allow flow of fluid from the wellbore up the choke
line
to the rig choke,
Carrying out these procedures takes time, however, and, although it may only
:==
:==
=
take less than 60 seconds to actually close the BOP, the time taken in
=
executing the additional procedures means that it is typically four or five
:==
==
minutes after the start of the control intervention that the BOP is actually
=
closed, During this period of time, mud in the wellbore is displaced by
lighter
formation fluid, and the resulting reduction of the density of the column
fluid
extending up from the bottom of the wellbore decreases the welibore pressure.
Moreover, when the drill string rotation and mud pumps are stopped during the
:=
control intervention, the resulting loss of the ECD causes a further decrease
in
the wellbore pressure. These factors may ultimately cause the wellbore
=
:==
pressure to drop even further below the pore pressure, which can cause the
influx to enter the wellbore at an accelerated rate, further increasing the
size of =
the influx.
In an attempt to minimise or at least reduce this problem, alternative control
procedures have been proposed. For example, it has been proposed to open
the HCR (and rig choke if not already open) before closing the BOP. In this
=
case, the mud pumps continue pumping while flow from the wellbore is
=
diverted up the choke line and through the rig choke. in doing so, the BOP
could be dosed without a drop in wellbore pressure from a loss in circulating
=
=:
friction. This method caused the opposite problem, however, as the high
frictional forces in the choke line increased the welibore pressure, in some
=
=
cases to more than the fracture pressure of the formation. This significantly
=
=
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increased the risk of formation fracture, especially in narrow margin drilling
projects, and, as a result was not recommended for deepwater drilling
operations, or narrow drilling margin projects in general.
W02013/153135 describes how the riser gas handling system may be used to
5 remove fluid from the riser whilst closing the subsea BOP in a well
control
procedure, and how it may also be used to circulate a kick or influx out of
the
riser after a subsea BOP in the BOP stack has been closed.
The present invention relates to an improved well control procedure which may
assist in reducing or eliminating the problems associated with a reduction of
wellbore pressure whilst closing the BOP in a well control procedure. This
procedure can also mitigate the drop in wellbore pressure associated with
closing the subsea BOP for purposes outside of well control as well. Another
common example is an emergency disconnection sequence, where the BOP
must be closed in a rapid fashion prior to disconnecting the riser system from
the subsea BOP.
According to a first aspect of the invention we provide a method of operating
a
drilling system, the drilling system comprising:
a drill string which extends into a wellbore,
:==
a driver operable to rotate the drilling string,
:=
a pump operable to pump drilling fluid down the drill string,
=
=
a well head mounted at the top of the wellbore,
:==
a riser extending up from the wellhead around the drill string,
=
=
a blowout preventer which is mounted on the well head and which is
:==
operable to close around the drill string to substantially prevent flow of
fluid from the annular space around the drill string in the wellbore into
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the annular space around the drill string in the riser (the riser annulus)
the BOP having a .sealing element which engages with the drill string
when the BOP is operated to close around the drill string,
a riser closure device which is mounted in the riser and which is
operable to close around the drill string to substantially prevent flow of
fluid along the riser annulus,
a return conduit,
a flow outlet which is provided in the riser below the riser closure device
and which connects the riser annulus to the return conduit,
wherein the method comprises the steps of, after determining that there
is or may be a need to close the BOP, implementing a control
procedure comprising the following steps:
a) operating the driver to stop rotation of the drill string,
b) closing the riser closure device (if not already closed),
c) operating the pump to stop the pumping of mud into the drill string,
d) closing the blowout preventer,
characterised in that the method further includes the step of
e) increasing the wellbore pressure by controlling the rate of flow of
fluid along the. return conduit,
Step e may comprise increasing the wellbore pressure to bring the wellbore
pressure up towards, to or above the pore pressure of a formation causing an
influx into the wellbore. Step e may comprise increasing the wellbore pressure
to compensate for a reduction in wellbore pressure resulting from step a
and/or c.
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=
7
The drng system may further include a flow restriction device which is
mounted in the return conduit and which is operable to vary the extent to
which
=
flow along the return conduit is restricted. In this case, step e may comprise
=
increasing the back pressure on the riser annulus by operating the flow
=
restriction device to increase the extent to which flow of fluid along the
return
õ==
conduit is restricted.
Step e is preferably carried out before step d.
Step e may be carded out before step a.
Step e may be carded out at the same time at carrying out step a.
'10 Step e may be carded out after carrying out step a.
Step e may be carded out before, after or at the same time as carrying out
step c.
Step a may be carded out before step b, and step b carded out before step c.
Step d may be carded out after steps a, b, and c.
The method may further comprise the step of
f) lifting the drill string off the bottom of the welibore,
in this case, step f may be carded out before step a.
The method may further comprise the step of
g) carrying out a flow check which may comprise measuring the rate of
flow of fluid along the return line.
in this case, step g may be carded out after step C.
Step o may be carded out after step a.
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The drilling system may further comprise a BOP to riser conduit which
connects the annular space around the drill string below the sealing element
of
the BOP with the annular space in the drill string around the drill string
above
the sealing element of the BOP, the BOP to riser conduit being provided with a
valve which is movable between an open position in which flow of fluid along
the BOP to riser conduit from the annular space around the drill string below
the sealing element of the BOP to the annular space in the drill string around
the drill string above the sealing element of the BOP is permitted, and a
closed
position in which flow of fluid along the BOP to riser conduit is prevented,
the
method further comprising the step of
h) opening the valve in the BOP to riser conduit, and
i) closing the valve in the BOP to riser conduit,
in this case, preferably step h is carried out before step d, although the
process of opening the BOP to riser conduit could be carried out at the same
time as initiating the closure of the blowout preventer, providing that the
BOP
to riser conduit is fully opened before the blowout preventer is fully closed,
Step h may be carried out before step a. Alternatively, step h may be carried
out after steps a and b and before step d.
In this case, step d may be carried out before step c.
Advantageously, step i is carried out after step c.
Step e may also comprise increasing the rate of operation of the pump.
The drilling system may include a further return conduit which extends from an
outlet which connects the annular space around the drill string below the
sealing element of the BOP to the drilling rig, and a valve which is normally
closed but which is operable to allow or prevent flow of fluid along the
further
return conduit, the method further including the step of
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j) opening the valve in the further return conduit,
In this case, advantageously, step j is carried out after all the other method
steps.
The return conduit may be provided with an isolation valve which is movable
between a closed position in which flow of fluid along the return conduit is
substantially prevented, and an open position which the flow of fluid along
the
õ==
return conduit is permitted, the method further including the step of
:==
k) moving the isolation valve from the closed position to the open
position immediately prior to carrying out step b.
=
The drilling system may further be provided with a riser booster conduit which
extends from a riser booster pump .into a lower end of the riserõ the riser
booster pump being operated at all times whilst =carrying out the method to
pump drilling fluid into the lower end of the riser.
The flow outlet may be provided in a flow spool.
=
The drilling system may further comprise a slip joint by means of which the
riser may be suspended from a drilling rig. In this case, the riser closure
device may be located between the flow outlet and the slip joint.
In one embodiment, the drilling system is provided with a diverter which is
mounted in an upper portion of the riser above the Slip joint the flow outlet
being provided in a flow spool between the slip joint and the diverter,
Embodiments .of the invention will now be described; by way of example only,.
.with reference to the following drawings, of which
FIGURE 1 is a schematic illustration of an example of an offshore drilling
system which may be used in accordance with the invention,
=
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=
FIGURE 2 is process flow block diagram of the drilling system illustrated in
Figure 1,
FIGURE 3 is a process flow block diagram of an alternative example of an
offshore drilling system suitable for use in accordance with the invention,
and
5 FIGURE 4 is a schematic illustration of an example of BOP with BOP to
riser
conduit for use in accordance with the invention.
Referring now to Figure 1, there is shown a floating drilling rig 1 for
drilling a
borehole through a seabed 2 beneath water surface. A blowout preventer
(BOP) stack 3 is disposed on the seabed above a wellhead 4. The BOP stack
10 3 may comprise an upper annular BOP 3a, a lower annular BOP 3b, and
below these, a plurality of RAM-type BOPS 3c. A riser 5 and choke 6 and kill
.õ
lines 7 are provided for well control between the floating vessel 1 and BOP
stack 3. The BOP stack 3 is provided with a remotely operable valve --- known
as an HCR ¨ which when closed, substantially prevents flow of fluid along the
choke line 6, and which is operable to open the choke line 6. The choke line 6
extends to a rig choke provided on the drilling rig.
A drill string 34 extends from the drilling rig 1 through a rotary system 23
(top
drive or rotary table) along the riser 5 and into the well bore. The riser 5
extends down from a diver-ter 8 located just below the floor 14 of the
drilling rig
1 to the BOP stack 3, a slip joint 10 being provided in an uppermost portion
of
the riser 5, below the diverter 8 and a lower flex joint 11 being provided in
the
lowermost portion of the riser 5 just above the BOP stack 3.
An annular BOP 21 and flow spool assembly 22 are also provided as part of
the riser string 5, and are deployed through the rig's rotary system 23 in the
=
same manner as the riser string 5. The flow spool 22 is located below the
annular BOP 21, and a pressure sensor 74, and temperature sensor 75 are
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provided to measure the pressure and temperature of fluid in the riser 5
between the annular BOP 21 and the flow spool 22.
The slip joint /0 has an inner barrel 9a which extends down from the diverter
8, and an outer barrel 9b which extends down to the annular BOP 21. The
outer barrel 9b is provided with a tension ring 25 which is suspended from the
drilling rig 11. Advantageously the annular BOP 21 and flow-spool assembly
22 are placed below the tension ring 25 so that the slip joint 10
configuration
and heave capability remains unchanged compared with prior art
arrangements. The slip joint 10 allows a riser assembly 5 to alternately
lengthen and shorten as the rig 1 moves up and down (heaves) in response to
wave action.
The annular BOP 21 may be based on the original Shaffer annular BOP
design set out in US patent number 2, 609, 836. The annular BOP 21 has a
housing having a central passage through which a drill string may extend.
Within the housing is located a piston and a torus shaped packing element
(commonly referred to as an annular spherical packer), both of which surround
a drill string extending through the BOP. The piston divides the interior of
the
housing into two chambers an open chamber and a close chamber. The
interior of the housing is configured such that supply of pressurised fluid to
the
close chamber causes the piston to push the packing element against the
interior of the housing, which, in turn, causes the packing element to
constrict
and form a substantially fluid tight seal around the drill string 34.
Advantageously, the outer diameter of the annular BOP 21 is 46.5 inches, and
one such configuration of annular BOP, suitable for use in this system is
disclosed in our co-pending UK patent applications, GB1104885/ and
G31204310.5, the contents of which are included herein by reference. This
means that the housing of the BOP 21 is less than the inner diameter of a 49
inch rotary table 23 and diverter housing 24. The annular BOP 21 and flow-
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z
=
spool 22 have the same tensile capacity as the riser 5 and can support the
full
load of the riser 5 and subsea BOP assembly 3 beneath it.
Advantageously, the annular BOP 21 is configured to retain pressures up to
3000 psi, and uses 5000psi accumulator bottles to close rapidly. A suitable
method of operating the annular BOP 21 is described in detail in
GB1204310.5. Briefly, however, in a normal closing operation, hydraulic
=
control fluid enters the close chamber 26 from flow-spool mounted
=
õ==
accumulator bottles 27, 28. The hydraulic fluid forces piston upwardly
deforming torus shaped packing element into sealing contact with drill string
=
34 and closes off the bore of the annular preventer surrounding a drill string
=
34. The issue of pressure drop in conduit lines is overcome by permitting
large
bore conduit lines 33, 34 (2" and above) combined with multiple supply ports
at
the annular that supply an instantly large volumes of hydraulic fluid over
short
distance (15ft) from the flow spool mounted accumulator banks 27, 28 to the
annular preventer thereby minimizing pressure lost.
=
To assure rapid closure, two separately manifold banks of accumulator bottles
27, 28 are provided. One accumulator bank 33 bypasses the subsea regulator
35 and supplies sufficient power fluid required at a set operating pressure to
close the annular BOP 21 to a stripping pressure of 500psi via the pilot
operated subsea directional control valve 36.
Fluid in opening chamber above the piston is expelled through multiple ports
in
=
the annular to the opening conduit line directly to atmosphere via a quick
dump
shuttle valve 37 instead of going back to the control fluid tank on surface.
The
aforementioned method provides the least resistance to the piston travel to
improve actuation time since it does not exert pressure loss of the opening
conduit line against the operating piston.
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To regulate the closing pressure of the annular preventer, another bank of
accumulator bottle 28 provides the additional hydraulic fluid required to
regulate the closing pressure up to 3000psi,
it should be appreciated that, whilst this configuration and method of
operation =
of annular BOP 21 and associated control system is particularly
advantageous, as it provides the desired quick close time, the invention is
not
restricted to use with this configuration and method of operation and annular
BOP,=
Returning now to Figure 1, it can be seen that the drilling system includes a
booster conduit 37, typically a flexible hose, that is connected to one of the
riser auxiliary lines 41 on the termination joint (upper most joint with
respect to
seabed) with one or more mud pump 38 which draw mud from a mud tank 62.
A flow meter 39 and a pressure sensor 40 are provided with one or more mud
pumps 38 either on the mud pump 38 itself or on the booster conduit 37. The
flow meter 39 can be a mud pump stroke counter, a high pressure mass
balance type or preferably a clamp-on active sonar type. This riser auxiliary
line is generally referred to as the booster line 41 and the pressure sensor
measurement is termed the booster pressure. During drilling using deepwater
rigs, it is known to pump drilling fluid down this booster conduit 37 and
booster
line 41 to the bottom of the riser 5 where it exits the booster line 41 and
circulates up the riser string annulus 42 to increase the return velocity of
the
fluid column in the riser 5. This may assist in the transport of cuttings up
the
riser.
The flow spool 22 in this embodiment is provided with two flow outlets 45, 46
which are each connected to one of two return conduits 47, 48 (in this example
6 inch flexible hose) and up to the drilling rig 1, It should be appreciated
that
fewer or more than two flow outlets and conduits could be used. At the
drilling
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14.
rig 1, the first conduit 47 is connected to a first inlet and the second
conduit 48 :==
is connected to a second inlet of a gas handling manifold 49,
=
=
In this example, the flow spool 22 is also provided with four isolation valves
76,
77, 78, 79, two of which 76, 77 are operable to close the first conduit 47,
and
the other two of which 78, 79 are operable to close the second conduit 48.
The gas handling manifold 49 comprises two selectively adjustable flow
restriction devices such as a pressure control valves 53, 54, each of which is
connected to one of the inlets, and each of which is operable to vary to
extent
to which flow through the gas handling manifold 49 is restricted. The pressure
control valves 53, 54 are preferably Hemi-wedge type such as those disclosed
in US patent no, 7357145 B2, Preferably a tungsten carbide coating is
provided on the valve core and seat for erosion protection so that the valves
are capable of operating in an environment where the drilling fluid contains
substantial formation cuttings. Each pressure control valve 53, 54 is coupled
with an actuator and a riser gas handling controller which comprises a
microprocessor which is programmed with the supervisory control and data
acquisition software SCADA,
=i
Between each inlet and associated pressure control valve 53, 54 there is, in
this embodiment, a pressure sensor and optional flow meter. The flow meters
may be a high resolution mass balance type or active sonar clamp-on type
flow meter.
The gas handling manifold 49 is provided with a main outlet, to which outlets
of
both pressure control valves 53, 54 are connected. The outlet is connected to
a mud gas separator (MGS) 56, The MGS 56 is provided with a vent line 60 at
its uppermost end, and a drain 110 at its lowermost end. More details of the
MGS can be found in our co-pending patent application W02013/153135,
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A 3-way valve non dosing valve 66 is installed in the drain 110, this valve
being operable to direct fluid from the drain 110 to either the mud tanks via
the
rig's solids control equipment (such as a shaker table) or overboard.
The drilling system may be provided with various pressure relief valves to
5 protect against overpressure, as described in more detail in our co-
pending
patent application W02013/153135. In this embodiment, these include a
backup flow spool pressure relief valve 106 which is a programmable relief
=
valve with a manual override to allow for back flushing of the discharge
conduit =
112 which is connected to a three Way valve 113 just above water level 2a, for
õ===
10 discharge overboard.
Referring now to Figure 2, this illustrates, schematically,: the key elements
of
the drilling system described above in relation to Figure 1, with some
additional elements not shown, for clarity, in Figure 1. These include the
shakers 71 to which mud from the MGS 66 can be directed, and the main rig
15 mud pumps 120 which are operable to draw mud from the mud tank 62 and
pump it into the uppermost end of the drill string 34, a rig manifold 122 to
which the choke line 6 extends, and the main rig mud gas separator 124 which
is connected to the choke line 6 downstream of the rig manifold 122. The
main rig mud gas separator 124 has a derrick vent 126 at its uppermost gas,
for the release of gas, and a drain which is connected to the shakers 71.
An alternative embodiment of drilling system suitable for use in accordance
with the invention is illustrated schematically in Figure 3, this contains all
the
elements of the drilling system shown in Figure 2 with the addition of a
rotating
control device (RCD) 130 which is provided between the slip joint 10 and the
BOP 21. The RCD 130 is operable to provide a substantially fluid tight seal
around the drill string to close the riser annulus during drilling (i.e. while
the
drill string is rotating). This drilling system may thus be used for managed
pressure drilling. In such a system, the riser gas manifold 49 is replaced by
a
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managed pressure drilling (MPD) manifold 132. The MPD manifold 132 is,
however, for the purposes for this invention at least, substantially the same
as
the riser gas handling manifold 49 in that fluid exiting the riser annulus is
õ==
directed to the MGS 56 via the MPD manifold 132, and the MDP manifold 132
includes at least one adjustable choke or pressure control valve which is
=
operable to vary the extent to which flow of fluid through the MPD manifold
132 is restricted.
The invention relates to how these drilling systems are operated in the event
that it is determined that it is necessary to shut in the welibore by closing
the
subsea BOP stack 3, for example, because there may have been an influx of
formation fluid into the riser. It will be appreciated that closing the subsea
BOP 3 stack involves closing one or more of the BOPs 3a, 3b, 3c in the BOP
stack 3 around the drill string so that these prevent flow of fluid up the
wellbore,
annulus into the riser annulus,
Considering first, the drilling system illustrated in Figures 1 and 2, which
is
used for non-managed pressure drilling, if it is determined that it is
necessary
to close the subsea BOP stack 3, for example because an influx has occurred,
the system may be operated as follows:
1) the drill string 34 is lifted off the bottom of the well bore,
2) rotation of the drill string is stopped,
3) the riser annular BOP 21 is closed,
4) the isolation valves 76, 77, 78, 79 in the first and second conduits 47,
48 to the riser gas manifold are opened,
5) the pressure control valves 53, 54 are operated to increase the degree
to which return flow of fluid along the conduits 47, 48 is restricted, thus
reducing the underbalance and offsetting the ECD loss,
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6) the main mud pump 120 is shut down whilst the pressure control valves
53, 54 are operated to further increase the degree to which return flow
=
=
of fluid along the conduits 47, 48 is restricted,
:==
7) a flow check is carried out,
8) the subsea BOP stack 3 is closed, and
9) the HCR valve is opened so that fluid from the wellhore below the BOP
stack 3 can be evacuated from the wellbore and directed to the rig via
the choke line 6.
When managed pressure drilling using the system illustrated in Figure 3, the
system may be operated as follows:
1) the pressure control valves in the MPD manifold 32 are operated to
increase the degree to which return flow of fluid along the conduits 47,
48 is restricted, thus reducing the underbalance,
2) the drill string 34 is lifted off the bottom of the well bore,
3) rotation of the drill string is stopped, whilst the pressure control valves
in
the MPD manifold 132 are operated to further increase the degree to
which return flow of fluid along the conduits 47, 48 is restricted,
4) the main mud pump 120 is shut down whilst the pressure control valves
in the MPD manifold are operated to further increase the degree to
which return flow of fluid along the conduits 47, 48 is restricted,
5) a flow check is carried out,
6) the subsea BOP stack 3 is closed, and
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7) the HCR valve is opened so that fluid from the welibore below the BOP
stack 3 can be evacuated from the wellbore and directed to the rig via
the choke line 6.
It will be appreciated that, in the case of managed pressure drng, the RCD
130 is already closed, so the RCD 130 acts as the riser closure device
required to contain the fluid pressure in the riser annulus instead of the BOP
21, and so there is no need to close the BOP 21 as part of this procedure.
The systems illustrated in the figures can be further modified to include a
short, wide bore conduit 140 (the BOP to riser conduit 140) from the subsea
BOP stack 3 below the at least one of the BOPs 3a, 3b, 3c in the BOP stack 3
to the riser 5 above at least that BOP. An example of such a BOP to riser
conduit 140 is illustrated in Figure 4, in this case, the BOP to riser conduit
140
extends from below the RAM-type BOPs 3c to the top of the BOP stack 3
above the uppermost annular BOP 3a, The BOP to riser conduit: 140 need not
be configured in this way, and could be configure to extend from directly
below
any one of the BOPs 3a, 3b, 3c in the BOP stack 3 to directly above that BOP
3a, 3b, 3c or to extend across any number of BOPs in the stack 3,
The BOP to riser conduit 140 is preferably provided with at least one remotely
operable isolation valve 142 which may be shut to substantially prevent flow
of
fluid along the BOP to riser conduit and opened to allow flow of fluid along
this
conduit. In the example illustrated in Figure 4, four such isolation valves
142
are provided.
If, during non-MPD drilling, it is determined that an influx has occurred,
and, as
a result, it is necessary to close the subsea BOP stack 3, the system may be
operated as follows:
1) the drill string 34 is lifted off the bottom of the well bore,
2) rotation of the drill string is stopped,
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19
3) the riser annular BOP 21 is closed,
4) the isolation valves 76, 77, 78, 78 in the first and second conduits 47,
48 to the riser gas manifold are opened,
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5) the pressure control valves 53, 54 are operated to increase the degree
to which return flow of fluid along the conduits 47, 48 is restricted,
and/or the rate of pumping of mud into the drill string by mud pump 120
is increased, thus reducing the underbalance and offsetting the ECD
kiss,
6) the BOP to riser conduit is opened,
7) a flow check is carried out,
8) the subsea BOP stack 3 is closed,
9) the main mud pump 120 is shut down whilst the pressure control valves
53, 54 are operated to further increase the degree to which return flow
of fluid along the conduits 47, 48 is restricted,
10) the BOP to riser conduit is closed, and
11) the HCR valve is opened so that fluid from the wellbore below the BOP
stack $ can be evacuated from the wellbore and directed to the rig via
the choke line 6.
lf, during managed pressure drilling (with the RCD 130 closed), it is
determined that an influx has occurred, and, as a result, it is necessary to
close the subsea BOP stack 3, the system is operated as follows:
1) the BOP to riser conduit is opened,
2) the pressure control valves in the MPD manifold 32 are operated to
increase the degree to which return flow of fluid along the conduits 47,
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48 is restricted and/or the rate of pumping of mud into the drill string by
mud pump '120 is increased, thus reducing the underbalance,
3) the drill string 34 is lifted off the bottom of the well bore,
4) rotation of the drill string is stopped, whilst the pressure control valves
in
5 the MPD
manifold 132 are operated to further increase the degree to
which return flow of fluid along the conduits 47, 48 is restricted and/or
the rate of pumping of mud into the drill string by mud pump 120 is
increased,
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5) a flow check is carried out,
10 6) the subsea BOP stack 3 is dosed,
7) the main mud pump 120 is shut down whilst the pressure control valves
in the MPD manifold are operated to further increase the degree to
which return flow of fluid along the conduits 47, 48 is restricted,
8) the BOP to riser conduit is closed, and
15 9) the
FICR valve is opened so that fluid from the wellbore below the BOP
stack 3 can be evacuated from the welibore and directed to the rig via
the choke line 6.
The use of a BOP to riser conduit in this way may allow the subsea BOP stack
3 to be closed even more quickly, because the process of shutting down the
20 mud pump
120 does not need to occur first The fact that the main pump 120
can be kept running whilst the BOP stack 3 is dosed means that the pump
rate can be used as a method of controlling the wellbore pressure, in addition
to or instead of use of the pressure control valves in the riser gas handling
manifold 49 or MPD manifold 132,
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It should be noted that, whilst not essential, the riser booster pump 32 is
advantageously operated to pump mud into the bottom of the riser 5 at all
times during these processes.
If the riser booster pump 32 is operating, the flow check may comprise using a
flow meter to measure the rate of flow of fluid along the first and second
conduits 47, 48, If the measured flow rate is greater than the known flow rate
produced by operation of the riser booster pump 32, this indicates that the
well
is still underbalanced (i.e. the wellbore pressure is below the pore pressure
of
the formation) and/or there is gas expanding in the wellbore.
If riser booster pump 32 is not operating, the flow check could be performed
by
fully shutting the control valves 53, 54 or the pressure control valves in the
MPD manifold, and measuring the fluid pressure at these valves. If there is an
influx in the well, gas migration would cause the choke pressure to increase.
Whilst advantageous, it should be appreciated, however, that carrying out a
=
15. . flow check is not absolutely necessary, particularly if the operator is
very
certain that an influx is occurring, or intends to shut-in the BOP as quickly
as
=
possible for another reason, for example in an emergency disconnect
sequence. Moreover, depending on what metering equipment is available on
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the rig, a flow check can be done at any time in many different forms. The
timings of the flow checks given above are by way of example only. It should
also be noted that any drop in well bore pressure resulting from the
displacement of drilling mud by hydrocarbons whilst the flow check is taking
place can be offset by controlling the rate of flow along the return conduit.
It should also be appreciated that it is not absolutely essential to lift up
the drill
string off the bottom of the wellbore, or to do this at the points set out
above,
Lifting the drill string is, however, required to permit circulation through
the drill
bit nozzles without the risk of blockage, and it is advantageous to lift the
drill
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string before closing the riser annular BOP 21 and the subsea BOP stack 3 to
ensure that theses are not closed on a tool joint.
When used in this specification and claims, the terms "comprises" and
"comprising" and variations thereof mean that the specified features, steps or
integers are included. The terms are not to be interpreted to exclude the
presence of other features, steps or components.
The features disclosed in the foregoing description, or the following claims,
or
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the accompanying drawings, expressed in theft specific forms or in terms of a
means for performing the disclosed function, or a method or process for
attaining the disclosed result, as appropriate, may, separately, or in any
combination of such features, be utilised for realising the invention in
diverse
forms thereof.
