CA2990333A1 - Method of operating a drilling system - Google Patents
Method of operating a drilling system Download PDFInfo
- Publication number
- CA2990333A1 CA2990333A1 CA2990333A CA2990333A CA2990333A1 CA 2990333 A1 CA2990333 A1 CA 2990333A1 CA 2990333 A CA2990333 A CA 2990333A CA 2990333 A CA2990333 A CA 2990333A CA 2990333 A1 CA2990333 A1 CA 2990333A1
- Authority
- CA
- Canada
- Prior art keywords
- riser
- drill string
- bop
- flow
- carried out
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000000034 method Methods 0.000 title claims abstract description 87
- 238000005553 drilling Methods 0.000 title claims abstract description 79
- 239000012530 fluid Substances 0.000 claims abstract description 84
- 238000007789 sealing Methods 0.000 claims abstract description 15
- 238000005086 pumping Methods 0.000 claims abstract description 7
- 230000015572 biosynthetic process Effects 0.000 claims description 17
- 230000004941 influx Effects 0.000 claims description 16
- 238000002955 isolation Methods 0.000 claims description 10
- 239000011148 porous material Substances 0.000 claims description 6
- 230000009467 reduction Effects 0.000 claims description 5
- GNFTZDOKVXKIBK-UHFFFAOYSA-N 3-(2-methoxyethoxy)benzohydrazide Chemical compound COCCOC1=CC=CC(C(=O)NN)=C1 GNFTZDOKVXKIBK-UHFFFAOYSA-N 0.000 claims description 3
- FGUUSXIOTUKUDN-IBGZPJMESA-N C1(=CC=CC=C1)N1C2=C(NC([C@H](C1)NC=1OC(=NN=1)C1=CC=CC=C1)=O)C=CC=C2 Chemical compound C1(=CC=CC=C1)N1C2=C(NC([C@H](C1)NC=1OC(=NN=1)C1=CC=CC=C1)=O)C=CC=C2 FGUUSXIOTUKUDN-IBGZPJMESA-N 0.000 claims description 2
- YTAHJIFKAKIKAV-XNMGPUDCSA-N [(1R)-3-morpholin-4-yl-1-phenylpropyl] N-[(3S)-2-oxo-5-phenyl-1,3-dihydro-1,4-benzodiazepin-3-yl]carbamate Chemical compound O=C1[C@H](N=C(C2=C(N1)C=CC=C2)C1=CC=CC=C1)NC(O[C@H](CCN1CCOCC1)C1=CC=CC=C1)=O YTAHJIFKAKIKAV-XNMGPUDCSA-N 0.000 claims description 2
- SGPGESCZOCHFCL-UHFFFAOYSA-N Tilisolol hydrochloride Chemical compound [Cl-].C1=CC=C2C(=O)N(C)C=C(OCC(O)C[NH2+]C(C)(C)C)C2=C1 SGPGESCZOCHFCL-UHFFFAOYSA-N 0.000 claims 1
- 239000007789 gas Substances 0.000 description 26
- 238000005755 formation reaction Methods 0.000 description 16
- 230000008569 process Effects 0.000 description 7
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 6
- 238000009844 basic oxygen steelmaking Methods 0.000 description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 5
- 238000012856 packing Methods 0.000 description 4
- 229910052757 nitrogen Inorganic materials 0.000 description 3
- 238000005520 cutting process Methods 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 238000009434 installation Methods 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 229910000831 Steel Inorganic materials 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000013270 controlled release Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000006073 displacement reaction Methods 0.000 description 1
- 230000003628 erosive effect Effects 0.000 description 1
- 238000011010 flushing procedure Methods 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 230000005012 migration Effects 0.000 description 1
- 238000013508 migration Methods 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- UONOETXJSWQNOL-UHFFFAOYSA-N tungsten carbide Chemical compound [W+]#[C-] UONOETXJSWQNOL-UHFFFAOYSA-N 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/001—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor specially adapted for underwater drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
- E21B21/085—Underbalanced techniques, i.e. where borehole fluid pressure is below formation pressure
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/10—Valve arrangements in drilling-fluid circulation systems
- E21B21/103—Down-hole by-pass valve arrangements, i.e. between the inside of the drill string and the annulus
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
- E21B33/064—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers specially adapted for underwater well heads
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/02—Valve arrangements for boreholes or wells in well heads
- E21B34/04—Valve arrangements for boreholes or wells in well heads in underwater well heads
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B7/00—Special methods or apparatus for drilling
- E21B7/12—Underwater drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B3/00—Rotary drilling
- E21B3/02—Surface drives for rotary drilling
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
- E21B47/07—Temperature
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Earth Drilling (AREA)
Abstract
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 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 siring, 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.
Description
2 PCT/GB2016/052614 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"), 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
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"), 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
3 =
=
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.
=
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.
4 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 =
=
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
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 =
=
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
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
6 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.
=
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.
=
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.
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.
8 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
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
9 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, =
=
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
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, =
=
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
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
11 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-
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-
12 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.
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.
13 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
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
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, 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
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, 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
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
16 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,
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,
17 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 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 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 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, =
=
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, =
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, 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, :==
=
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, 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 =
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 =
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 =
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.
=
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 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 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 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, =
=
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, =
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, 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, :==
=
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, 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 =
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 =
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 =
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.
Claims (33)
1. 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 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.
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 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.
2. The method according to claim 1 wherein step e comprises increasing the wellbore pressure to bring the weHbore pressure up towards, to or above the pore pressure of a formation causing an influx into the weHbore.
3. The method according to claim 1 or 2 wherein step e comprises increasing the wellbore pressure to compensate for a reduction in weHbore pressure resulting from steps a and/or c.
4. The method according to any preceding daim wherein the drffiing system further includes 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,
5. The method according to claim 4 wherein step e comprises 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 conduit is restricted.
6. The method according to any preceding claim wherein step e is carried out before step d.
7. The method according to any preceding claim wherein step e is carried out before step a.
8. The method according to any preceding claim wherein step e is carried out at the same tiMe at carrying out step a.
9. The method according to any preceding claim wherein step e carried out after carrying out step a.
10. The method according to any preceding claim wherein :step e is carried out at the same time as carrying odt step c.
11. The method according to any preceding claim wherein step a is carried out before step b, and step b is carried out before step c.
12, The method according to any preceding claim wherein step d is carried out after steps a, b, and c.
13. The method according to any preceding claim wherein the method further comprises the step of f) liftino the drill string off the bottom of the weHbore,
14. The method according to claim 13 wherein step f is carried out before step a.
15. The method according to any preceding claim wherein the method further comprises the step of g) carrying out a flow check.
16. The method accordina to claim 15 wherein step g is carried out after stop C.
17. The method according to claim 15 wherein step g is carried out after Step a.
18. The method according to any preceding claim wherein the drilling system further comprises 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 srting around the drill string above the sealing element of the BOP, the BOP to riser conduit being provided with a valva 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 dell string above the sealing element of the BOP is permitted, and a dosed 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,
19. The method according to claim 18 wherein step h is carried out before step d.
20. The method according to claim 19 wherein step h is carried out before step a.
21. The method according to claim 19 wherein step h is carried out after steps a and b and before step d.
22. The method according to any one of claims 18 to 21 wherein step d is carried out before step c.
23. The method according to any one of claims 18 to 22 wherein step i is carried out after step c.
24. The method according to any preceding claim wherein step e comprises increasing the rate of operation of the pump.
25. The method according to any preceding claim wherein the drilling system includes 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 further return conduit, and a valve which is normally closed but which is operable to avow or prevent flow of fluid along the further return conduit, the method further including the step of j) opening the valve in the further return conduit.
to the further return conduit, and a valve which is normally closed but which is operable to avow or prevent flow of fluid along the further return conduit, the method further including the step of j) opening the valve in the further return conduit.
26. The method according to claim 25 wherein step j is carried out after all the other method steps.
27. The method according to any preceding claim wherein the return conduit is 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 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.
28. The method according to any preceding claim wherein the drilling system is further provided with a riser booster conduit which extends from a riser booster pump into a lower end of the riser, 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.
29. The method according to any preceding claim wherein the flow outlet is provided in a flow spool.
30. The method according to any preceding claim wherein drilling system further comprises a slip joint by means of which the riser may be suspended from a drilling rig.
31. The method according to claim 30 wherein the riser closure device is located between the flow outlet and the slip joint.
32. The method according to claim 30 wherein 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.
33. Any novel feature or novel combination of features described herein with reference to the accompanying drawings,
Applications Claiming Priority (5)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GBGB1515284.6A GB201515284D0 (en) | 2015-08-28 | 2015-08-28 | Well control method |
| GB1515284.6 | 2015-08-28 | ||
| GB1517872.6 | 2015-10-09 | ||
| GB1517872.6A GB2541755B (en) | 2015-08-28 | 2015-10-09 | Method of operating a drilling system |
| PCT/GB2016/052614 WO2017037422A1 (en) | 2015-08-28 | 2016-08-23 | Method of operating a drilling system |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2990333A1 true CA2990333A1 (en) | 2017-03-09 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2990333A Abandoned CA2990333A1 (en) | 2015-08-28 | 2016-08-23 | Method of operating a drilling system |
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|---|---|
| US (1) | US20180245411A1 (en) |
| BR (1) | BR112018002080A2 (en) |
| CA (1) | CA2990333A1 (en) |
| GB (2) | GB201515284D0 (en) |
| MX (1) | MX2018002418A (en) |
| NO (1) | NO20180424A1 (en) |
| WO (1) | WO2017037422A1 (en) |
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| CN106917596A (en) * | 2015-12-25 | 2017-07-04 | 通用电气公司 | For the well kick detecting system and method and related well system of drill well bores |
| US10648315B2 (en) * | 2016-06-29 | 2020-05-12 | Schlumberger Technology Corporation | Automated well pressure control and gas handling system and method |
| EP3665356B1 (en) * | 2017-08-11 | 2024-07-31 | Services Pétroliers Schlumberger | Universal riser joint for managed pressure drilling and subsea mudlift drilling |
| US10513887B1 (en) * | 2018-10-29 | 2019-12-24 | Thomas G Drysdale | Self-elevating drilling unit drills petroleum well offshore with wellhead on seabed |
| US11136841B2 (en) * | 2019-07-10 | 2021-10-05 | Safekick Americas Llc | Hierarchical pressure management for managed pressure drilling operations |
| CN111075379B (en) * | 2020-01-19 | 2024-06-11 | 西南石油大学 | Safe drilling system and method for preventing water-sensitive stratum at upper part of high-pressure brine layer from collapsing |
| CN113586002B (en) * | 2021-09-28 | 2021-12-03 | 山东尤科斯石油装备有限公司 | Oil field well head safety blowout preventer |
Family Cites Families (12)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4046191A (en) * | 1975-07-07 | 1977-09-06 | Exxon Production Research Company | Subsea hydraulic choke |
| US4626135A (en) * | 1984-10-22 | 1986-12-02 | Hydril Company | Marine riser well control method and apparatus |
| US6474422B2 (en) * | 2000-12-06 | 2002-11-05 | Texas A&M University System | Method for controlling a well in a subsea mudlift drilling system |
| WO2002068787A2 (en) * | 2001-02-23 | 2002-09-06 | Exxonmobil Upstream Research Company | Method and apparatus for controlling bottom-hole pressure during dual-gradient drilling |
| US8640778B2 (en) * | 2008-04-04 | 2014-02-04 | Ocean Riser Systems As | Systems and methods for subsea drilling |
| EP2499328B1 (en) * | 2009-11-10 | 2014-03-19 | Ocean Riser Systems AS | System and method for drilling a subsea well |
| US8347982B2 (en) * | 2010-04-16 | 2013-01-08 | Weatherford/Lamb, Inc. | System and method for managing heave pressure from a floating rig |
| CN201963231U (en) * | 2010-12-22 | 2011-09-07 | 中国海洋石油总公司 | Subsea mud suction system for realizing riser-free mud recovery drilling |
| EP2659082A4 (en) * | 2010-12-29 | 2017-11-08 | Halliburton Energy Services, Inc. | Subsea pressure control system |
| GB2501094A (en) * | 2012-04-11 | 2013-10-16 | Managed Pressure Operations | Method of handling a gas influx in a riser |
| US20140048331A1 (en) * | 2012-08-14 | 2014-02-20 | Weatherford/Lamb, Inc. | Managed pressure drilling system having well control mode |
| GB2506400B (en) * | 2012-09-28 | 2019-11-20 | Managed Pressure Operations | Drilling method for drilling a subterranean borehole |
-
2015
- 2015-08-28 GB GBGB1515284.6A patent/GB201515284D0/en not_active Ceased
- 2015-10-09 GB GB1517872.6A patent/GB2541755B/en not_active Expired - Fee Related
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2016
- 2016-08-23 US US15/755,094 patent/US20180245411A1/en not_active Abandoned
- 2016-08-23 CA CA2990333A patent/CA2990333A1/en not_active Abandoned
- 2016-08-23 BR BR112018002080A patent/BR112018002080A2/en not_active Application Discontinuation
- 2016-08-23 WO PCT/GB2016/052614 patent/WO2017037422A1/en active Application Filing
- 2016-08-23 MX MX2018002418A patent/MX2018002418A/en unknown
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2018
- 2018-03-25 NO NO20180424A patent/NO20180424A1/en not_active Application Discontinuation
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