METHOD OF OPERATING A DRILLING SYSTEM

Abstract

A method of operating a drilling system. The drilling system includes a drill string extending into a wellbore, a driver which rotates the drill string, a pump to pump drilling fluid down the drill string, a wellhead mounted at the wellbore, a riser extending up from the wellhead around the drill string, a blowout preventer mounted on the wellhead, a riser closure device mounted in the riser, a first return conduit, and a flow outlet arranged in the riser below the riser closure device. The method includes operating the driver to stop a rotation of the drill string, closing the riser closure device if it is not already closed, operating the pump to stop a pumping of drilling fluid down the drill string, closing the blowout preventer, and increasing a wellbore pressure by controlling a rate of the flow of the fluid along the first return conduit.

Description

CROSS REFERENCE TO PRIOR APPLICATIONS

This application is a U.S. National Phase application under 35 U.S.C. § 371 of International Application No. PCT/GB2016/052614, filed on Aug. 23, 2016 and which claims benefit to Great Britain Patent Application No. 1515284.6, filed on Aug. 28, 2015, and to Great Britain Patent Application No. 1517872.6, filed on Oct. 9, 2015. The International Application was published in English on Mar. 9, 2017 as WO 2017/037422 A1 under PCT Article 21(2).

FIELD

The present invention relates to a method of operating a drilling system, in particular 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.

BACKGROUND

The drilling 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 drilling 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 wellbore 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 well control use.

A flow of mud is used to carry the debris created by the drilling process out of the wellbore as drilling progresses. 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 wellbore (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”), 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 drilling 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 air or nitrogen, foamed fluids with air 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 wellbore pressure which is high enough to counter balance the pressure of fluids in the formation (“the formation pore pressure”), thus substantially preventing inflow of fluids from formations penetrated by the wellbore entering into the wellbore. If the wellbore pressure falls below the formation pore pressure, an influx of formation fluid (gas, oil or water) can enter the wellbore 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 wellbore 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 lengthen 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 lines which provide a conduit for the controlled release of fluid from the riser or riser annulus. The diverter therefore provides for a removal of 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 an off-shore drilling installation is described in WO 2013/153135. 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. Various control procedures may be implemented if an influx/kick is detected depending on the extent or severity of the influx.

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, is opened to allow a 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 wellbore 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.

Alternative control procedures have been proposed in an attempt to minimize or at least reduce this problem. It has been proposed, for example, to open the HCR (and the 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 so doing, the BOP could be closed 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 wellbore 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.

WO 2013/153135 describes how the riser gas handling system may be used to remove fluid from the riser while 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.

SUMMARY

An aspect of the present invention is to provide an improved well control procedure which may assist in reducing or eliminating the problems associated with a reduction of wellbore pressure while 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.

In an embodiment, the present invention provides a method of operating a drilling system. The drilling system includes a drill string which extends into a wellbore, a driver configured to rotate the drill string, a pump configured to pump drilling fluid down the drill string, a wellhead mounted at a top of the wellbore, a riser configured to extend up from the wellhead around the drill string so as to provide a riser annulus between the riser and the drill string, a blowout preventer mounted on the wellhead, a riser closure device mounted in the riser, a first return conduit, and a flow outlet arranged in the riser below the riser closure device. The blowout preventer is configured to close around the drill string so as to substantially prevent a flow of a fluid from an annular space around the drill string in the wellbore into the riser annulus. The blowout preventer comprises a sealing element which is configured to engage with the drill string when the blowout preventer is operated to close around the drill string. The riser closure device is configured to close around the drill string so as to substantially prevent the flow of the fluid along the riser annulus. The flow outlet is configured to connect the riser annulus to the first return conduit. After determining that there is or may be a need to close the blowout preventer, the method of operating the drilling system implements a control procedure comprising the steps: a) operating the driver to stop a rotation of the drill string; b) closing the riser closure device if the riser closure device is not already closed; c) operating the pump to stop a pumping of drilling fluid down the drill string; d) closing the blowout preventer; and, e) increasing a wellbore pressure by controlling a rate of the flow of the fluid along the first return conduit.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is described in greater detail below on the basis of embodiments and of the drawings in which:

FIG. 1 is a schematic illustration of an embodiment of an offshore drilling system which may be used in accordance with the present invention;

FIG. 2 is process flow block diagram of the drilling system illustrated in FIG. 1;

FIG. 3 is a process flow block diagram of an alternative embodiment of an offshore drilling system suitable for use in accordance with the present invention; and

FIG. 4 is a schematic illustration of an embodiment of a BOP with a BOP to riser conduit for use in accordance with the present invention.

DETAILED DESCRIPTION

In an embodiment, the present invention provides 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 wellhead 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 wellhead and which is operable to close around the drill string to substantially prevent the 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; and
  • 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; and
  • d) closing the blowout preventer,
  • characterized 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.

The drilling 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 conduit is restricted.

Step e can, for example, be carried out before step d.

Step e may be carried out before step a.

Step e may be carried out at the same time at carrying out step a.

Step e may be carried out after carrying out step a.

Step e may be carried out before, after, or at the same time as carrying out step c.

Step a may be carried out before step b, and step b may be carried out before step c.

Step d may be carried 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 wellbore.

In this case, step f may be carried 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 carried out after step c.

Step g may be carried out after step a.

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, step h can, for example, be 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:

• • j) opening the valve in the further return conduit.

In this case, step j is advantageously 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 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 riser, the riser booster pump being operated at all times while 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 via which the riser may be suspended from a drilling rig. The riser closure device may in this case be located between the flow outlet and the slip joint.

In an 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 present invention will now be described, by way of example only, with reference to the drawings.

Referring now to FIG. 1, there is shown a floating drilling rig 1 for drilling a borehole through a seabed 2 beneath the water surface. A subsea blowout preventer (BOP) stack 3 is disposed on the seabed above a wellhead 4. The BOP stack 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, choke lines 6 and kill lines 7 are provided for well control between the drilling rig 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 a 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 1.

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 diverter 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 5, and are deployed through the rig's rotary system 23 in the same manner as the riser 5. The flow spool assembly 22 is located below the annular BOP 21, and a pressure sensor 74, and temperature sensor 75 are provided to measure the pressure and temperature of fluid in the riser 5 between the annular BOP 21 and the flow spool assembly 22.

The slip joint 10 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 an assembly of the riser 5 to alternately lengthen and shorten as the drilling 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 U.S. Pat. No. 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 closed chamber). The interior of the housing is configured so that a supply of pressurized fluid to the closed 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 GB 1104885.7 and GB 1204310.5, the contents of which are included herein by reference. This means that the housing of the annular BOP 21 is less than the inner diameter of a 49 inch rotary system 23 and diverter housing 24. The annular BOP 21 and flow-spool assembly 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 5000 psi accumulator bottles to close rapidly. A suitable method of operating the annular BOP 21 is described in detail in GB 1204310.5. Briefly, however, in a normal closing operation, hydraulic control fluid enters the close chamber 26 from flow-spool mounted 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 the conduit lines is overcome by permitting large bore conduit lines 33a, 33b (2″ and above) combined with multiple supply ports at the annular that supply an instantly large volumes of hydraulic fluid over short distance (15 ft) from the flow spool mounted accumulator bottles 27, 28 to the annular preventer, thereby minimizing pressure lost.

To assure rapid closure, two separate manifold banks of accumulator bottles 27, 28 are provided. One large bore conduit line 33a 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 500 psi via the pilot operated subsea directional control valve 36.

Fluid in the 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 37a 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.

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 3000 psi.

It should be appreciated that, while 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 present invention is not restricted to use with this configuration and method of operation and annular BOP.

Returning now to FIG. 1, it can be seen that the drilling system includes a booster conduit 37b, 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 37b. The flow meter 39 can be a mud pump stroke counter, a high pressure mass balance type, or a clamp-on active sonar type. This riser auxiliary line 41 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 booster conduit 37b 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 5.

The flow spool assembly 22 in this embodiment is provided with two flow outlets 45, 46 which are each connected to one of two return conduits 47, 48 (a 6 inch flexible hose in the shown embodiment) 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 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, for example, for riser gas.

In this embodiment, the flow spool assembly 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 can, for example, be of the Hemi-wedge type such as those disclosed in U.S. Pat. No. 7,357,145 B2. A tungsten carbide coating can, for example, be 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.

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 56 can be found in WO 2013/153135.

A 3-way valve non closing 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 protect against overpressure, as described in more detail in WO 2013/153135. 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 discharge overboard.

Referring now to FIG. 2, this illustrates, schematically, the key elements of the drilling system described above in relation to FIG. 1, with some additional elements not shown, for clarity, in FIG. 1. These include the shakers 71 to which mud from the MGS 66 can be directed, and the main rig 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 part, 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 present invention is illustrated schematically in FIG. 3, this contains all the elements of the drilling system shown in FIG. 2 with the addition of a rotating control device (RCD) 130 which is provided between the slip joint 10 and the annular 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 gas handling manifold 49 is replaced by a managed pressure drilling (MPD) manifold 132. The MPD manifold 132 is, however, for the purposes of the present invention, at least substantially the same as the gas handling manifold 49 in that fluid exiting the riser annulus is 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 present invention relates to how these drilling systems are operated in the event that it is determined that it is necessary to shut in the wellbore by closing the 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 BOP stack 3 involves closing one or more of the BOPs 3a, 3b, 3c in the BOP stack 3 around the drill string 34 so that these prevent a flow of fluid up the wellbore annulus into the riser annulus.

Considering first, the drilling system illustrated in FIGS. 1 and 2, which is used for non-managed pressure drilling, if it is determined that it is necessary to close the 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 annular BOP 21 is closed;
  • 4) the isolation valves 76, 77, 78, 79 in the first and second return line conduits 47, 48 to the riser gas manifold 49 are opened;
  • 5) the pressure control valves 53, 54 are operated to increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted, thus reducing the underbalance and offsetting the ECD loss;
  • 6) the main rig mud pump 120 is shut down while the pressure control valves 53, 54 are operated to further increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted;
  • 7) a flow check is carried out;
  • 8) the BOP stack 3 is closed; and
  • 9) the HCR valve is opened so that fluid from the wellbore 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 FIG. 3, the system may be operated as follows:

• • 1) the pressure control valves in the MPD manifold 132 are operated to increase the degree to which a return flow of fluid along the first and second return line 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 34 is stopped, while the pressure control valves in the MPD manifold 132 are operated to further increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted;
  • 4) the main rig mud pump 120 is shut down while the pressure control valves in the MPD manifold 132 are operated to further increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted;
  • 5) a flow check is carried out;
  • 6) the BOP stack 3 is closed; and
  • 7) the HCR valve is opened so that fluid from the wellbore 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 drilling, the RCD 130 is already closed so that the RCD 130 acts as the riser closure device required to contain the fluid pressure in the riser annulus instead of the annular BOP 21, and so there is no need to close the annular BOP 21 as part of this procedure.

The systems illustrated in the drawings can be further modified to include a short, wide bore conduit 140 (the BOP to riser conduit 140) from the 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 FIG. 4. In this case, the BOP to riser conduit 140 extends from below the RAM-type BOPs 3c to the top of the BOP stack 3 above the uppermost annular BOP 3a. The BOP to riser conduit 140 need not be configured in this way, and could be configured 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 BOP stack 3.

The BOP to riser conduit 140 can, for example, be provided with at least one remotely operable isolation valve 142 which may be shut to substantially prevent a flow of fluid along the BOP to riser conduit 140 and opened to allow a flow of fluid along this conduit. Four such isolation valves 142 are provided in the embodiment shown in FIG. 4.

If, during non-MPD drilling, it is determined that an influx has occurred, and, as a result, it is necessary to close the 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 34 is stopped;
  • 3) the annular BOP 21 is closed;
  • 4) the isolation valves 76, 77, 78, 78 in the first and second return line conduits 47, 48 to the riser gas manifold 49 are opened;
  • 5) the pressure control valves 53, 54 are operated to increase the degree to which return flow of fluid along the first and second return line conduits 47, 48 is restricted, and/or the rate of pumping of mud into the drill string 34 by the main rig mud pump 120 is increased, thus reducing the underbalance and offsetting the ECD loss;
  • 6) the BOP to riser conduit 140 is opened;
  • 7) a flow check is carried out;
  • 8) the BOP stack 3 is closed;
  • 9) the main rig mud pump 120 is shut down while the pressure control valves 53, 54 are operated to further increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted;
  • 10) the BOP to riser conduit 140 is closed; and
  • 11) the HCR valve is opened so that fluid from the wellbore below the BOP stack 3 can be evacuated from the wellbore and directed to the rig via the choke line 6.

If, 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 BOP stack 3, the system is operated as follows:

• • 1) the BOP to riser conduit 140 is opened;
  • 2) the pressure control valves in the MPD manifold 132 are operated to increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted and/or the rate of pumping of mud into the drill string 34 by the main rig 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 34 is stopped, while the pressure control valves in the MPD manifold 132 are operated to further increase the degree to which a return flow of fluid along the first and second return line conduits 47, 48 is restricted and/or the rate of pumping of mud into the drill string 34 by the main rig mud pump 120 is increased;
  • 5) a flow check is carried out;
  • 6) the BOP stack 3 is closed;
  • 7) the main rig mud pump 120 is shut down while the pressure control valves in the MPD manifold 132 are operated to further increase the degree to which return flow of fluid along the first and second return line conduits 47, 48 is restricted;
  • 8) the BOP to riser conduit 140 is closed; and
  • 9) the HCR valve is opened so that fluid from the wellbore below the BOP stack 3 can be evacuated from the wellbore and directed to the rig via the choke line 6.

The use of a BOP to riser conduit 140 in this way may allow the BOP stack 3 to be closed even more quickly because the process of shutting down the main rig mud pump 120 does not need to occur first. The fact that the main rig mud pump 120 can be kept running while the BOP stack 3 is closed 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 gas handling manifold 49 or MPD manifold 132.

It should be noted that, while 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 return line 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 132, 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.

While advantageous, it should be appreciated, however, that carrying out a 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 while 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 34 off the bottom of the wellbore, or to do this at the points set out above. Lifting the drill string 34 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 annular BOP 21 and the BOP stack 3 to provide that these 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 their 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 present invention in diverse forms thereof. Reference should also be had to the appended claims.

Claims

1-33. (canceled)

34. A method of operating a drilling system,

the drilling system comprising: a drill string which extends into a wellbore; a driver configured to rotate the drill string; a pump configured to pump drilling fluid down the drill string; a wellhead mounted at a top of the wellbore; a riser configured to extend up from the wellhead around the drill string so as to provide a riser annulus between the riser and the drill string; a blowout preventer mounted on the wellhead, the blowout preventer being configured to close around the drill string so as to substantially prevent a flow of a fluid from an annular space around the drill string in the wellbore into the riser annulus, the blowout preventer comprising a sealing element which is configured to engage with the drill string when the blowout preventer is operated to close around the drill string; a riser closure device mounted in the riser, the riser closure device being configured to close around the drill string so as to substantially prevent the flow of the fluid along the riser annulus; a first return conduit; and a flow outlet arranged in the riser below the riser closure device, the flow outlet being configured to connect the riser annulus to the first return conduit,

wherein, after determining that there is or may be a need to close the blowout preventer, the method of operating the drilling system implements a control procedure comprising the steps:

a) operating the driver to stop a rotation of the drill string;

b) closing the riser closure device if the riser closure device is not already closed;

c) operating the pump to stop a pumping of drilling fluid down the drill string;

d) closing the blowout preventer; and

e) increasing a wellbore pressure by controlling a rate of the flow of the fluid along the first return conduit.

35. The method as recited in claim 34, wherein step e) comprises increasing the wellbore pressure to bring the wellbore pressure up towards, to, or above a pore pressure of a formation causing an influx into the wellbore.

36. The method as recited in claim 34, wherein step e) comprises increasing the wellbore pressure to compensate for a reduction in the wellbore pressure resulting from at least one of step a) and step c).

37. The method as recited in claim 34, wherein the drilling system further comprises:

a flow restriction device mounted in the first return conduit, the flow restriction device being configured to vary an extent to which the flow of the fluid along the first return conduit is restricted.

38. The method as recited in claim 37, wherein step e) comprises increasing a back pressure on the riser annulus by operating the flow restriction device to increase the extent to which the flow of fluid along the first return conduit is restricted.

39. The method as recited in claim 34, wherein step e) is performed before performing step d).

40. The method as recited in claim 34, wherein,

step e) is performed before performing step a), or

step e) is performed at the same time as performing step a), or

step e) is performed after performing step a).

41. The method as recited in claim 34, wherein step e) is performed at the same time as performing step c).

42. The method as recited in claim 34, wherein,

step a) is performed before performing step b), and

step b) is performed before performing step c).

43. The method as recited in claim 34, wherein step d) is performed after performing step a), step b), and step c).

44. The method as recited in claim 34, wherein the method further comprises the step of:

f) lifting the drill string off a bottom of the wellbore.

45. The method as recited in claim 44, wherein step f) is performed before performing step a).

46. The method as recited in claim 44, wherein the method further comprises the step of:

g) performing a flow check.

47. The method as recited in claim 46, wherein step g) is performed after performing step c).

48. The method as recited in claim 46, wherein step g) is performed after performing step a).

49. The method as recited in claim 46, wherein,

the drilling system further comprises: a BOP to riser conduit which connects a lower annular space around the drill string below the sealing element of the blowout preventer with an upper annular space around the drill string above the sealing element of the blowout preventer, the BOP to riser conduit comprising a valve which is movable between an open position in which a flow of the fluid along the BOP to riser conduit from the lower annular space to the upper annular space is permitted, and a closed position in which the flow of the fluid along the BOP to riser conduit is prevented, and

the method further comprising the steps of: h) opening the valve in the BOP to riser conduit; and i) closing the valve in the BOP to riser conduit.

50. The method as recited in claim 49, wherein step h) is performed before performing step d).

51. The method as recited in claim 50, wherein step h) is performed before performing step a).

52. The method as recited in claim 50, wherein step h) is performed after performing step a) and step b), and before performing step d).

53. The method as recited in claim 49, wherein step d) is performed before performing step c).

54. The method as recited in claim 49, wherein step i) is performed after performing step c).

55. The method as recited in claim 49, wherein step e) comprises increasing a rate of operation of the pump.

56. The method as recited in claim 49, wherein,

the drilling system further includes: a second return conduit configured to extend from an outlet arranged at the lower annular space around the drill string below the sealing element of the blow out preventer, and a valve arranged in the second return conduit, the valve normally being closed so as to prevent a flow of the fluid along the second return conduit, but which is configured to allow or to prevent the flow of the fluid along the second return conduit, and

the method further comprises the step of: j) opening the valve in the second return conduit.

57. The method as recited in claim 56, wherein step j) is performed after each of step a), step b), step c), step d), step e), step f), step g), step h), and step i).

58. The method as recited in claim 56, wherein,

each of the first return conduit and the second return conduit comprise an isolation valve which is configured to be movable between a closed position in which the flow of the fluid along the respective first return conduit and second return conduit is substantially prevented, and an open position which the flow of the fluid along the respective first return conduit and second return conduit is permitted, and

the method further comprises the step of: k) moving each isolation valve from the closed position to the open position immediately prior to performing step b).

59. The method as recited in claim 58, wherein the drilling system further comprises:

a riser booster pump arranged at a lower end of the riser; and

a riser booster conduit which is configured to extend from the riser booster pump,

wherein,

the riser booster pump is operated at all times while performing the method to pump drilling fluid into the lower end of the riser.

60. The method as recited in claim 34, wherein,

the drilling system further comprises a flow spool, and

the flow outlet is arranged in the flow spool.

61. The method as recited in claim 60, wherein,

the drilling system further comprises a slip joint via which the riser is suspendable from a drilling rig.

62. The method as recited in claim 61, wherein the riser closure device is located between the flow outlet and the slip joint.

63. The method as recited in claim 61, wherein,

the drilling system further comprises a diverter mounted in an upper portion of the riser above the slip joint, and

the flow outlet is arranged in the flow spool between the slip joint and the diverter.