EP3947896B1

EP3947896B1 - Automated system and method for use in well control

Info

Publication number: EP3947896B1
Application number: EP20720733.3A
Authority: EP
Inventors: Bryan ATCHISON; Philip HASSARD; Richard Rose
Original assignee: Safe Influx Ltd
Current assignee: Safe Influx Ltd
Priority date: 2019-04-02
Filing date: 2020-04-01
Publication date: 2023-10-04
Anticipated expiration: 2040-04-01
Also published as: AU2020254965A1; EP3947896A1; ES2965811T3; CA3135675A1; WO2020201322A1; US20200318464A1; EP3947896C0; GB201904615D0; GB2581586B; GB2581586A; GB202001702D0

Description

FIELD

This relates to an automated system and method for use in well control. More particularly, this relates to an automated system and method for detecting the presence of a fluid influx condition in a wellbore and automatically initiating an initial well control protocol.

BACKGROUND

Well control techniques are used in oil and gas operations such as drilling, tripping, well workover, and well completion in order to maintain fluid pressure at certain points in a wellbore above a formation pressure and thereby prevent influx of formation fluids into the wellbore. This is known in the industry as "overbalanced" differential pressure.
With the pumps on and fluid circulating, a combination of hydrostatic pressure, dynamic friction pressure and surface pressure may combine to maintain an overbalanced differential pressure in a wellbore. In the event that an "underbalanced" differential pressure comes to exist in the wellbore, that is where fluid pressure at certain points in the wellbore is less than the formation pressure, formation fluids may flow into the wellbore in what is known in the industry as fluid influx.
The fluid influx will continue until the fluid pressure in the wellbore is increased by fluid flow from the formation to the wellbore. This type of fluid influx may be referred to as a "self-sustained" influx. The self-sustained influx should be stopped as quickly as possible and the unwanted fluid safely removed from the wellbore before continuing with oil and gas operations. Notably, a self-sustained influx is often generally characterised in the industry as a "kick" or "influx" along with other non-self-sustained influxes (e.g. a swabbed influx) requiring different remedial action. As explained below, this exacerbates problems with accurately identifying a self-sustained influx with open-to-atmosphere annulus fluid systems.
Upon suspicion or sign of a self-sustained influx, a driller may attempt to confirm whether such an event is indeed occurring before initiating well control techniques by carrying out a flow check procedure. A typical flow check procedure involves positioning the drill bit at a suitable position above the bottom of the wellbore/borehole, stopping rotation of the drill string, and then stopping the mud pumps. The driller then checks to see if there is any flow returning from the well annulus (i.e., whether the well is "flowing") with the pumps off. If the well is flowing, with the pumps off, the driller may conclude that some type of influx is entering the wellbore. Conventional flow check procedures today are performed entirely with the BOP open, i.e., with an open-to-atmosphere annulus fluid system.
There are a number of challenges with conventional methods.
Very often, using an open-to-atmosphere system is inadequate for the rig crew to accurately and quickly come to a conclusion as to whether a self-sustained influx is indeed happening or not due to a variety of other benign causes for such a perceived influx. For example, on floating installations, relatively small yet significant self-sustained influxes may be difficult to observe because the conventional flow check procedure may be affected by installation motion and heave effects.
Also, flow check procedures take time that is often prescribed by procedure (for example requiring a minimum of 10, 15, or 30 minutes). Drillers may hesitate to risk stopping drilling operations for such periods until and/or unless clear justification exists.
Moreover, a driller who has had the experience of stopping to perform a flow check procedure only to find no self-sustained influx existed may be less likely to quickly do so again, even if new circumstances justify it, if the earlier flow check resulted in delay, costs or operational problems that could otherwise have been avoided by not performing the flow check procedure.
US 2018/187498 A1 describes an early kick detection system including a kick detection computing device coupled to at least one sensor associated with a drilling system of a well. The kick detection computing device is configured to receive measurement data from the at least one sensor. The measurement data includes one or more kick indicators used to identify a well kick. The kick detection computing device generates an estimated value for each of the one or more kick indicators during simulated normal drilling conditions and simulated kick conditions. The kick detection computing device determines a deviation value and generates a signal based on the deviation value. The signal activates a green status, an amber warning, or a red alarm to indicate a kick detection status of the drilling system.
US 2014/048331 A1 describes a method of drilling a subsea wellbore which includes drilling the subsea wellbore and, while drilling the subsea wellbore: measuring a flow rate of the drilling fluid injected into a tubular string; measuring a flow rate of returns; comparing the returns flow rate to the drilling fluid flow rate to detect a kick by a formation being drilled; and exerting backpressure on the returns using a first variable choke valve. The method further includes, in response to detecting the kick: closing a blowout preventer of a subsea pressure control assembly (PCA) against the tubular string; and diverting the flow of returns from the PCA, through a choke line having a second variable choke valve, and through the first variable choke valve.
US 2018/328159 A1 describes systems, devices, and methods for detecting and addressing a kick on a drilling rig. A controller on the drilling rig may receive measurements from one or more sensor systems on the drilling rig and determine a severity index value corresponding to the likelihood of a kick. If the severity index level is determined to reach a specified threshold, an operator may be prompted to perform a flow check and/or activate a blow-out preventer.

SUMMARY

According to a first aspect, there is provided an automated system for use in well control, according to the appended claims.
Beneficially, the system permits an initial well control protocol to be actioned based on preselected criteria, and without the requirement for an operative, such as the driller, to decide and/or action the required initial well control operations. The system is particularly, although not exclusively, beneficial in open-to-atmosphere wellbore systems where it is difficult or impossible using conventional techniques for the driller to accurately and quickly conclude whether a self-sustained influx is occurring.
The system is capable of reducing the size of an influx compared to conventional open-to-atmosphere techniques, which in turn reduces the risk of fracture and potential underground blow out due to lower wellbore pressures, particularly but not exclusively at the open shoe of the wellbore.
The system also has the benefit of reducing delay, costs and/or operational problems that may otherwise occur where a well control operation is initiated unnecessarily, while also obviating the risk that the operative will then subsequently not act promptly when an influx condition does occur.
Moreover, the system permits the initial well control protocol to be initiated based on a single parameter, i.e. fluid flow rate or fluid volumetric rate from the wellbore. The system may be configured to interface with a variety of well control systems. However, the ability to initiate and/or perform the initial well control protocol based on a single parameter provides not only a simple and effective system for use in well control operations, but one which does not rely on interfacing with a variety of systems which are typically provided by different suppliers and which may rely on proprietary systems. The system may thus be readily retrofitted to existing wellbore infrastructure, without significantly impacting on existing systems and/or infrastructure.
The system's ability to detect and automatically initiate the initial well control protocol without manual intervention also facilitates more efficient well operations and/or production. For example, conventional drilling methodologies teach that, where an influx or potential influx event occurs, the well-plan may have to be modified with an additional string of casing thereby increasing the cost of drilling the wellbore and/or reducing future production capacity. The present system permits the operator to work within smaller tolerances and thus require fewer changes to the well-plan, reducing the capital expenditure in drilling the wellbore and utilising larger casing strings to greater depths, and thus increasing production capacity.
As described above, the controller is configured to determine from the input signal whether the fluid flow rate or fluid volumetric rate exceeds a preselected threshold indicative of a fluid influx condition in the wellbore, and on determining that said received fluid flow rate or fluid volumetric rate exceeds said preselected threshold output one or more command signals initiating an initial well control protocol.
The threshold may be set during set up of the system. For example, the threshold may be set by the operative and/or the operator company during set up of the system. Beneficially, this permits the threshold to be tuned/adjusted according to the driller's and/or operator's preferences, experience, environment; given well-plan or the like; but within a range bounded by appropriate factors of safety.
The one or more preselected well control operations may be set during set up of the system. For example, the one or more preselected well control operations may be set by the operative and/or the operator company during set up of the system. Beneficially, this permits the one or more preselected well control operations to be tuned/ adjusted according to the driller's and/or operator's preferences, experience, environment; given well-plan or the like; but within a range bounded by appropriate factors of safety.
In particular embodiments, the initial well control protocol may comprise a plurality of well control operations.
The system is configured for coupling to, to communicate with or may be operatively associated with components of an oil and/or gas installation ("the installation").
The system is configured for coupling to, to communicate with or may be operatively associated with a drawworks of the installation.
More particularly, the system is configured for coupling to, to communicate with, or may be operatively associated with a controller of the drawworks of the installation.
The initial well control protocol comprises a command signal to the drawworks to raise the drill string off the bottom of the wellbore.
The distance that the drawworks is raised may be set by the operative, e.g. driller, during set up of the system, but will occur automatically once the control system has been enabled. Beneficially, this prevents or at least reduces the likelihood that the drawworks could be raised to a position at which a tubing connection is disposed adjacent to the closure mechanism of the blow out preventer.
The system may be configured for coupling to, to communicate with or may be operatively associated with a top drive of the installation.
More particularly, but not exclusively, the system may be configured for coupling to, to communicate with or may be operatively associated with a controller of the top drive.
The initial well control protocol may comprise a command signal to the top drive to stop rotation of the top drive.
The system may be configured for coupling to, to communicate with or may be operatively associated with one or more mud pumps of the installation.
More particularly, but not exclusively, the system may be configured for coupling to, to communicate with or may be operatively associated with a controller of the mud pumps.
The initial well control protocol may comprise a command signal to the mud pumps to stop the mud pumps, or a preselected subset of the mud pumps.
The initial well control process may comprise monitoring the fluid flow rate or fluid volumetric rate over a preset test period.
The preset test period may be 1 second. However, it will be recognised that the preset test period may be any suitable time period.
The preset test period may be preselected by the operative, e.g. driller, during set up of the system.
The system may be configured so that if, after the pre-set test period has elapsed, the fluid flow rate or fluid volumetric rate remains above the preselected threshold the system will determine that an influx condition is present in the wellbore.
Alternatively or additionally, the initial well control process may comprise periodically checking the fluid flow rate or fluid volumetric rate at any point in the well control process.
The initial well control process may comprise checking the fluid flow rate or fluid volumetric rate after a pre-set time delay.
Alternatively or additionally, the system may be configured so that, on receiving confirmation that the mud pumps of the installation have stopped, and a further time period has elapsed, in the event that fluid flow has not reduced to a negligible level the system will determine that an influx condition is present in the wellbore.
The pre-set time period may be adjustable by the operative, e.g. driller, during set up of the system, but will occur automatically once the control system has been enabled.
The further time period may be adjustable by the operative, e.g. driller, during set up of the system, but will occur automatically once the control system has been enabled.
The system may be configured for coupling to, to communicate with or may be operatively associated with a blow out preventer (the "BOP") of the installation.
More particularly, but not exclusively, the system may be configured for coupling to, to communicate with or may be operatively associated with a controller of the BOP.
The initial well control protocol may comprise a command signal to the BOP to close the BOP, and thus shut-in the wellbore.
The system may be configured to action a further well control protocol.
The further well control protocol may comprise or take the form of influx circulation operation.
The further well control protocol may comprise or take the form of a well kill operation, that is placing a column of heavy fluid into a wellbore in order to prevent the flow of reservoir fluids.
The system may be configured for coupling to, to communicate with or may be operatively associated with at least one of a choke panel, choke manifold and/or mud pump of the installation.
Alternatively, the further well control protocol may comprise or take the form of a fluid pumping operation.
Conventionally, a leak off test (LOT) procedure is undertaken during the wellbore construction process after each new string of casing has been secured in the wellbore. This establishes the strength of the formation at the casing shoe. During the wellbore construction process, the Maximum Allowable Annulus Surface Pressure (MAASP), derived from the LOT, must not be exceeded, otherwise an underground blowout may be initiated. This may lead to a breach to surface and must be avoided.
The fluid pumping operation may comprise pumping fluid, in particular drilling mud, into the shut-in wellbore before or after, for example but not exclusively immediately after, the wellbore has been shut.
The fluid pumping operation may comprise pumping mud into the wellbore until a pre-determined pressure is reached.
In particular embodiments, the pre-determined pressure is less than MAASP or shoe fracture pressure, thereby ensuring that an underground blowout does not occur.
The pre-determined pressure may be equal to or greater than the formation pressure that caused the influx.
Beneficially, the fluid pumping operation reduces or minimises the volume of the influx. Minimising the influx volume has several advantages. For example, a reduced influx volume may result in lower pressure being exerted on the wellbore and the rig equipment. There is also a reduced risk of getting stuck and other hole problems. More options to kill the well become available, particularly using the bull-heading technique to displace the influx back into the donor formation. The system assures the operator that the influx volume would be significantly reduced, in particular but not exclusively to a maximum of five barrels of influx.
As described above, the system may be configured for coupling to, to communicate with or may be operatively associated with a choke panel and/or choke manifold of the installation.
As described above, the system comprises a controller configured to receive an input signal indicative of a fluid flow rate or fluid volumetric rate from a wellbore.
The input signal may take the form of fluid flow data from the wellbore, in particular real time fluid flow data or fluid volumetric rate from the wellbore. In particular, the input signal may comprise drilling fluid or mud flow or volume data.
The controller may be configured to additionally receive one or more input signal in the form of: fluid volume data; fluid volumetric displacement data; pressure data; depth data, e.g. indicative of the rate of penetration of the drillstring; weight data, e.g. weight of the drillstring; gas detection data; data indicative of the gas percentage in the drilling fluid; drilling fluid property data (e.g. indicative of fluid weight, yield point and/or plastic viscosity); equipment speed data; equipment condition data, e.g. indicative of valve position and/or choke position; movement data regarding the installation i.e. indicative of heave, sway, surge, roll, pitch and yaw; environmental data e.g. wind speed and/or direction; tidal data; GPS and/or other positioning system data; data from another source.
Alternatively or additionally, the controller may be configured to receive one or more input signal in the form of managed pressure drilling (MPD) system data.
Alternatively or additionally, the controller may be configured to receive one or more input signal in the form of early kick detection system (EKDS) data.
Alternatively or additionally, the controller may be configured to receive one or more input signal in the form of a manual confirmation input, e.g. from the operative. Alternatively or additionally, the controller may be configured to receive one or more input signal in the form of well control procedure data, e.g. a data library of well control procedures from one or more operator and/or leak-off test data (e.g. pressure & depth data), or other data source.
The system may comprise, may be coupled to or may communicate with, a sensor arrangement.
The system may communicate with the sensor arrangement via a wired communication arrangement and/or communication protocol.
Alternatively or additionally, the system may communicate with the sensor arrangement via a wireless communication arrangement and/or communication protocol, in particular but not exclusively a radio frequency (RF) communication arrangement.
The sensor arrangement may comprise one or more sensor configured to detect the fluid flow rate from the wellbore.
The sensor arrangement may comprise or take the form of a fluid flow sensor.
For example, the sensor arrangement may comprise a fluid flow sensor of, or operatively associated with, the mud flow system.
The system may comprise, may be coupled to or may communicate with, a single fluid flow sensor or a plurality of fluid flow sensors.
The sensor arrangement may be located on, disposed in, or operatively associated with a fluid return line of the wellbore.
The sensor arrangement may be located on a return line from the installation's flow control device manifold while the sensors measure drilling parameters elsewhere in the system.
Alternatively or additionally, the sensor arrangement may comprise or take the form of a mass flowmeter, e.g. a Coriolis mass flowmeter.
The mass flowmeter may be disposed either upstream or downstream from the sensor arrangement in the return line.
Alternatively or additionally, the sensor arrangement may be configured to detect the fluid volumetric rate.
The sensor arrangement may comprise one or more sensors configured to detect fluid volume.
Alternatively or additionally, the sensor arrangement may comprise one or more of: a sensor configured to measure fluid volumetric displacement; a pressure sensor; a depth sensor configured to measure the rate of penetration of the drillstring; a weight sensor configured to measure weight of the drillstring; a gas detection sensor configured to detect the presence and/or percentage of gas in the drilling fluid; one or more sensors configured to measure fluid weight, yield point and/or plastic viscosity; a speed sensor configured to measure equipment speed; a condition sensor configured to measure equipment condition, e.g. configured to measure a valve position and/or choke position; a movement sensor configured to measure heave, sway, surge, roll, pitch and yaw of the installation; a wind speed and/or direction sensor configured to wind speed and/or direction.
The sensor arrangement may comprise one or more sensor of, or operatively associated with, a trip tank of the installation.
The sensor arrangement may comprise one or more sensor of, or operatively associated with, a pit volume totalizer of the installation.
The system may be configured for coupling to, to communicate with or may be operatively associated with rig data system of the installation.
The system may comprise, may be coupled to, or operatively associated with a human machine interface (HMI) arrangement.
The HMI arrangement may be disposed on the installation, e.g. drilling rig, platform or the like. In particular, but not exclusively, the HMI arrangement may be disposed on the driller's console.
Alternatively, the HMI arrangement may be disposed at a remote location, such as another drilling rig or platform, onshore facility or other suitable location.
The system may be configured to receive commands through the HMI arrangement.
For example, the operative may set up and/or enable the system via the HMI arrangement.
As described above, the controller is configured to output a command signal to well control infrastructure initiating an initial well control protocol.
The system may comprise a communication arrangement configured to communicate said command signal to the well control infrastructure.
The communication arrangement may comprise a wired communication arrangement.
The wired communication arrangement may comprise an optical fibre arrangement, electrical cable or the like.
Alternatively or additionally, the communication arrangement may comprise a wireless communication arrangement, such as a radio frequency (RF) communication arrangement or the like.
The communication arrangement may be configured to communicate to the operative, e.g. via the HMI arrangement, that the initial well control protocol and/or the further well control protocol have been initiated.
The communication arrangement may communicate the actions carried out as part of the initial well control protocol and/or the further well control protocol to the operative, e.g. via the HMI arrangement. Beneficially, this provides the operative, e.g. driller, with a visual status indicator of the actions being carried out automatically by the system and/or permits the operative to verify those actions as they are carried out.
The method may comprise outputting an output signal to the operative, e.g. driller. In use, the output signal indicates to the operative, e.g. driller, than an increase in flow rate has been detected and that the initial well control process has been initiated; the operative is not required to take action in response to the output signal.
The output signal may comprise an alarm signal.
The output signal may comprise an audible alarm signal.
The output signal may comprise a visual alarm signal.
As described above, the system comprises a controller configured to receive the input signal indicative of a fluid flow rate from a wellbore, the controller configured to determine from said input signal whether the fluid flow rate exceeds a preselected threshold fluid flow rate indicative of a fluid influx condition in the wellbore system.
The controller may comprise a Programmable Logic Controller (PLC).
The controller may comprise a plurality of PLCs.
In particular embodiments, the controller may comprise two PLCs.
The PLCs may be synchronised.
The PLCs may be linked via a wired communication arrangement, such as an optical fibre.
The controller may comprise one or more CPU.
The controller may comprise a memory unit.
The controller may comprise, or may be coupled to, a power supply module.
The power supply module may operate on a DC supply, e.g. a 24V DC supply.
The system may comprise an input/output module.
The input/output module may be configured to provide communication between the controller and the components of the installation.
The input/output module may be configured to provide communication between the controller and the sensor arrangement and/or data source.
The input/output module and the controller may communicate via a wired or wireless communications arrangement and/or protocol. For example, the input/output module and the controller may communicate via a Process Field Bus (Profibus) interface.
The system may comprise, or may be coupled to, an Industrial Personal Computer (IPC).
The IPC may be operable to run the software for the HMI arrangement.
The system may comprise network switch, e.g. an Ethernet switch, or the like.
The network switch, e.g. Ethernet switch, may be configured to facilitate communication with multiple devices of the installation simultaneously.
The system may comprise an uninterruptable power supply (UPS) module.
The system may comprise a battery.
In use, the UPS module and/or the battery may provide back-up power to the components of the system in the event of power failure.
The system may comprise an Intrinsically Safe (IS) barrier unit.
The IS barrier unit may be configured to convert the 24V DC power supply into one that is safe for use in a hazardous area by virtue of the converted supply not being powerful enough to cause an ignition source, spark or the like.
The system may comprise an AC/DC converter unit.
The AC/DC converter unit may be configured to converting a 240V AC supply to a 24V DC supply for the controller and/or other component of the system.
The components of the control system may communicate via a wired or wireless, in particular but not exclusively radio frequency, communications arrangement and/or protocol.
According to a second aspect, there is provided an offshore or onshore oil and gas installation comprising the system of the first aspect.
According to a third aspect, there is provided an automated method for use in well control, according to the appended claims.
Beneficially, the method permits an initial well control protocol to be actioned based on preselected criteria, and without the requirement for the operative, such as the driller or other rig crew, to action the required initial well control operations. The method is particularly, although not exclusively, beneficial in open-to-atmosphere wellbore systems where it is difficult or impossible using conventional techniques for the driller or rig crew to accurately and quickly conclude whether a self-sustained influx is occurring, thereby increasing the safety and/or reducing the risk of damage to the wellbore infrastructure and/or formation due to formation fracture or blow out.
The method also has the benefit of reducing delay, costs and/or operational problems that may otherwise occur where a well control operation is initiated unnecessarily, while also obviating the risk that the operative will then subsequently not act promptly when an influx condition does occur.
Moreover, the method permits the initial well control protocol to be initiated based on a single parameter, i.e. fluid flow rate from the wellbore. The ability to initiate and/or perform the initial well control protocol based on a single parameter provides not only a simple and effective system for use in well control operations, but one which does not rely on interfacing with a variety of systems which are typically provided by different suppliers and which may rely on proprietary systems. The method may thus be readily employed using existing wellbore infrastructure, without significantly impacting on existing systems and/or infrastructure.
The method may comprise actioning a further well control protocol.
The further well control protocol may comprise the control system assuming control of the well control and/or drilling equipment of the installation.
The further well control protocol may comprise or take the form of influx circulation operation.
The further well control protocol may comprise or take the form of a well kill operation, that is placing a column of heavy fluid into a wellbore in order to prevent the flow of reservoir fluids.
Alternatively, the further well control protocol may comprise or take the form of a fluid pumping operation.
The fluid pumping operation may comprise pumping fluid, in particular drilling mud, into the shut-in wellbore immediately after the wellbore has been shut.
The fluid pumping operation may comprise pumping drilling fluid/mud into the wellbore until a pre-determined pressure is reached.
In particular embodiments, the pre-determined pressure is less than MAASP or shoe fracture pressure, thereby ensuring that an underground blowout does not occur.
The pre-determined pressure may be equal to or greater than the formation pressure that caused the influx.
The method may comprise the preliminary step of setting up and/or enabling the system.
The system may be set up and/or enabled by the operative, e.g. driller, via the human machine interface (HMI) arrangement.
The step of setting up the system comprises calibrating the drawworks space out configuration by calibrating set points for movement of the drawworks.
Beneficially, this ensures that the BOP does not close on a connection.
The calibration may be achieved by logging set points for upper, mid and lower positions in the system.
For example, the operative, e.g. driller, may raise the drawworks to a first "space out position" with the tool joint clear of the BOP, then log this position as an "Upper Set Point" via the HMI arrangement. The operative, e.g. driller, may then lower the drawworks to a second "space out position" with the tool joint clear of the BOP, then log this position as a "Mid Set Point" via the HMI arrangement. Finally, the operative, e.g. driller, may then lower the drawworks to a third "space out position" with the tool joint clear of the BOP, then log this position as a "Lower Set Point" via the HMI arrangement. It will be recognised that any number of positions may be logged, as appropriate. The positions may be recorded and displayed on the HMI.
The method may comprise the preliminary step of carrying out drilling or tripping operations.
In use, the operative, e.g. driller, is able to control the drilling equipment and begins drilling operations as if the automated system was not there.
As described above, the method involves determining whether or not the fluid flow rate exceeds the preselected threshold fluid flow rate.
The threshold fluid flow rate may be adapted by the operative, e.g. by the driller.
The ability to adapt the threshold fluid flow rate provides a degree of flexibility within acceptable safety margins while ensuring that the required initial well control operation is carried out automatically when required.
As described above, the method comprises receiving a signal indicative of a flow rate from a wellbore.
The signal may be indicative of an increased fluid flow rate from the wellbore.
The signal indicative of a flow rate from the wellbore may be received from a rig data system or the like.
Alternatively or additionally, the signal indicative of a flow rate from the wellbore may be received from instrumentation. This may be the case, for example, on older installations that do not have a rig data system.
As described above, the method comprises: receiving a signal indicative of a fluid flow rate or fluid volumetric rate from a wellbore; determining from said signal whether the fluid flow rate or fluid volumetric rate exceeds a preselected threshold fluid flow rate, wherein, on determining that said received fluid flow rate or fluid volumetric rate exceeds said preselected threshold fluid flow rate, the method comprises automatically initiating an initial well control operation.
The method may further comprise one or more steps in the form of tests.
The method may comprise one or more of the steps of checking that the complete system operates; and establishing a tolerance window. The one or more steps of checking that the complete system operates; and establishing a tolerance window may be performed prior to establishing mud pump (MP1) and/or mud pump (MP2) flowrates for future tests.
The method may comprise one or more of the steps of:

i) finalising a flowrate for MP1 to be used for all future tests;
ii) finalising a Flowrate for MP2 that triggers a shut-in procedure initiated from Flowcheck 1;
iii) Finalising a Flowrate for MP2 that triggers a shut-in procedure initiated from Flowcheck 2;
iv) Finalising a Flowrate for MP2 that does not trigger a shut-in procedure from either Flowcheck;
v) Finalising Time Delays, No Flow Limit, Flowrate Threshold Limit from Test 1.

The method may comprise the step of checking that the system will shut-in using each of the 3 space-out positions.
The method may comprise the step of comparing the time taken to manually shut-in the well compared with the system shutting in one or more of the positions of i). Flowcheck 1 and ii). Flowcheck 2.
The method may comprise the step of assessing the operation of the system to assess whether all equipment is unselected. The method may comprise a further step of identifying an influx.
The method may comprise the step of assessing the operation of the system to assess whether the top drive is unselected. The method may comprise a further step of identifying an influx.
The method may comprise the step of assessing the operation of the system to assess whether one or more mud pumps are unselected.
The method may comprise a further step of identifying an influx.
The method may comprise the step of assessing the operation of the system to assess whether the drawworks are unselected on the HMI arrangement.
The method may comprise a further step of identifying an influx.
The method may comprise the step of assessing the operation of the system to assess whether a tool joint is in a space-out tolerance window when an influx is identified.
The mud pump flow rate may be adjusted and/or varied during the drilling process, e.g. while drilling. The method of adjusting and/or varying the mud pump flow rate may comprise the steps of:

(i) switching the system off;
(ii) adjusting mud pumps;
(iii) re-setting the base flow rate;
(iv) switching the system on.

Alternatively, the mud pumps may be adjusted whilst the system is switched on. The resulting effects may be noted and/or recorded.
Slow Circulating Rates (SCRs) may be performed during the drilling process, e.g. while drilling.
The method of performing SCRs during the drilling process may comprise the steps of:

(i) switching the system off;
(ii) performing SCRs; and
(iii) switching the system on;

Alternatively, the drilling operator may perform the SCRs with the system switched on.
The top drive may be switched off and/or deactivated during the drilling process, e.g. while drilling. The method of switching off and/or deactivating the top drive during the drilling process may comprise the steps of:

(i) switch the system off;
(ii) switch the top drive off; and
(iii) switch the system on.

This test may assess the effect of switching off or attempting to switch off the top drive on the HMI whilst the system is switched on.
The method may assess the effect that the installation experiencing an Emergency Shut Down (ESD) has on the system while the system is switched on.
The method may assess whether the steady circulating flowrate (of MP1) is sufficiently disturbed by the drill-string being run in hole (RIH) such that flowrate transients are created that will cause the flowrate to increase to beyond the set Flowrate Threshold Limit.
The method may assess if the steady circulating flowrate (of MP1) is disturbed sufficiently by the drill-string being pulled out of hole (POOH) such that flowrate transients are created that may cause the flowrate to increase to beyond the set flowrate threshold limit.
The system may be configured for operation with an oil and/or gas installation having a rig control system or may be used with a conventional/traditional installation, i.e. without a rig control system.
The system may be connected to at least one of the installation, rig control unit and master BOP control panel via suitable connection arrangement. The suitable connections arrangement may comprise a wired connection arrangement, or may comprise a wireless communication arrangement.
Data from the system may be transferred between, e.g. to and/or from the rig equipment control units and/or master BOP control panel.
Various methods for adapting the system to a traditional installation without a rig control system may be employed.
According to a first method, connections may be hardwired or data from the system may be transferred to the installation's equipment control units in the silicon controller rectifier room and master BOP control panel. The system may be connected to at least one of the top drive, mud pumps, drawworks and BOP via the suitable connection arrangement.
Alternatively or additionally, at least one of the top drive, mud pumps, drawworks and BOP may be connected, e.g. wired from the control system to a remote panel which may be located at and/or on the rig floor. The remote panel may be connected, e.g. wired to relays in the rig's drillers' panel. The remote panel may be suitable for control of at least one of the top drive, mud pumps and drawworks equipment.
The BOP connection may be wired from the remote panel to relays. The remote panel relays may be located in one or more of the system enclosure; in the installation's BOP remote control panel; or to other BOP control panel.
Alternatively or additionally, the relays may be disposed in the remote panel or other separate enclosure which may be disposed on the rig floor.
The relays may be connected, e.g. wired to at least one of the rig's drillers' panel and the installation's BOP Remote control panel.
The system may comprise, may be configured for coupling to, or operatively associated with, a brake system.
The brake system may comprise a manual brake.
The brake system may be operated via a connection from one or more of the remote panel; pneumatic controls to the installation's brake, or relay interface to electrical brake controls.
The brake system may be, or take the form of a band brake or disc brake or the like.
The brake system may comprise a travelling equipment protection arrangement.
The travelling equipment protection arrangement may comprise or take the form of an automated or partially automated system.
The travelling equipment protection arrangement may comprise an electronic travelling equipment protection arrangement.
The brake system may comprise, or may be configured for coupling to, a Crown-o-matic and/or Crown-saver system, or the like.
The drawworks height may be controlled via a connection between, e.g. to and/or from the remote panel and a drawworks encoder.
The drawworks height may be controlled via data connections to a rig instrumentation data logging system.
The system may be connected to a installation flowrate sensor. The flowrate sensor may be of the paddle, J-tube, Coriolis meter type or other suitable flow metering device.
The system may be connected to one or more of mud pit level or trip tank level sensors.
The system may comprise, may be configured for connection to or may be operatively associated with a managed pressure drilling system of the installation.
The system may comprise an early kick detection system.
The system may be configured for connection to and/or operatively associated with an early kick detection system of the installation.
Also described is a processing system configured to implement one or more of the previous aspects.
The processing system may comprise at least one processor. The processing system may comprise and/or be configured to access at least one data store or memory. The data store or memory may comprise or be configured to receive operating instructions or a program specifying operations of the at least one processor. The at least one processor may be configured to process and implement the operating instructions or program.
The at least one data store may comprise, and/or comprise a reader, drive or other means configured to access, optical storage or disk such as a CD or DVD, flash drive, SD device, one or more memory chips such as DRAMs, a network attached drive (NAD), cloud storage, magnetic storage such as tape or magnetic disk or a hard-drive, and/or the like.
The processing system may comprise a network or interface module. The network or interface module may be connected or connectable to a network connection or data carrier, which may comprise a wired or wireless network connection or data carrier, such as a data cable, power line data carrier, Wi-Fi, Bluetooth, Zigbee, internet connection or other similar connection. The network interface may comprise a router, modem, gateway and/or the like. The system or processing system may be configured to transmit or otherwise provide the signal via the network or interface module, for example over the internet, intranet, network or cloud.
The processing system may comprise a processing apparatus or a plurality of processing apparatus. Each processing apparatus may comprise at least a processor and optionally a memory or data store and/or a network or interface module. The plurality of processing apparatus may communicate via respective network or interface modules. The plurality of processing apparatus may form, comprise or be comprised in a distributed or server/client based processing system.
According to another aspect, there is provided a computer program product configured such that when processed by a suitable processing system configures the processing system to implement one or more of the previous aspects.
The computer program product may be provided on or comprised in a carrier medium. The carrier medium may be transient or non-transient.
The carrier medium may be tangible or non-tangible.
The carrier medium may comprise a signal such as an electromagnetic or electronic signal. The carrier medium may comprise a physical medium, such as a disk, a memory card, a memory, and/or the like.
According to another aspect, there is provided a carrier medium, the carrier medium comprising a signal, the signal when processed by a suitable processing system causes the processing system to implement one or more of the previous aspects.
It will be well understood by persons of ordinary skill in the art that whilst some embodiments may implement certain functionality by means of a computer program having computer-readable instructions that are executable to perform the method of the embodiments. The computer program functionality could be implemented in hardware (for example by means of a CPU or by one or more ASICs (application specific integrated circuits)) or by a mix of hardware and software.
Whilst particular pieces of apparatus have been described herein, in alternative embodiments, functionality of one or more of those pieces of apparatus can be provided by a single unit, processing resource or other component, or functionality provided by a single unit can be provided by two or more units or other components in combination. For example, one or more functions of the processing system may be performed by a single processing device, such as a personal computer or the like, or one or more of each function may be performed in a distributed manner by a plurality of processing devices, which may be locally connected or remotely distributed.
The control system and method may be utilised in a range of different applications during operation of the oil and gas installation, as described below. Each application may be implemented in a software module forming part of the control software of the control system or forming a standalone software module operatively associated with the control software of the control system.
In one application, the control system may be configured to detect and react to an influx during the process of making and/or breaking a connection, that is adding a joint or stand of drill pipe to the top of the drillstring.
The control system may be coupled to a flow line sensor and may be configured to receive real time sensor data from the sensor, thereby permitting the control system to monitor the fluid flow rate from the wellbore during any one of the sub-phases of making the connection. The control system may be configured to determine from the sensor data whether the fluid flow rate exceeds a preselected threshold fluid flow rate set by the operative, e.g. driller when setting up and enabling the control system at the HMI arrangement, this being indicative of a fluid influx condition in the wellbore. On determining that the fluid flow rate does exceed the preselected threshold fluid flow rate, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. On receiving the alarm signal, the operative, e.g. driller, may in some circumstances be required to respond, via the HMI arrangement, with a confirmation signal confirming that drill string pressure integrity is in place. Once there is a positive indicator of an influx, the control system may initiate an initial well control protocol by outputting a number of command signals to rig and well control equipment of the oil and gas installation.
Beneficially, while the operative, e.g. driller, is performing the manual operation of making the connection, the control system may thus be operable to detect and react to an influx that occurs during any one of the sub-phases of making a connection.
Alternatively or additionally, the control system may be configured to detect and react to an influx during a tripping operation, that is pulling the drillstring from the wellbore and/or running the drill string back into the wellbore, for example to replace a drill bit.
The control system may be connected to a level sensor in one or more trip tank of the oil and/or gas installation, the level sensor may be configured to provide accurate real time data indicative of the fluid level in the trip tank. The control system may be connected to a drill bit depth sensor, the drill bit depth sensor configured to provide real time data indicative of the depth of the drillstring in the wellbore.
The control system may be configured to determine, from the data provided by the drill bit depth sensor, the volumetric displacement of the drill pipe as it trips into and/or out of the wellbore.
The control system may be configured to compare the data from level sensor relating to the fluid level in the trip tank with the volumetric displacement of the drill pipe determined from drill bit depth sensor; a deviation in the form of an increase in the fluid level in the trip tank relative to the determined volumetric displacement being indicative of an influx.
In the event a small deviation is detected by the control system, the control system may be configured to relay a warning signal to the operative, e.g. driller, via the HMI arrangement. In the event of a larger deviation exceeding a preselected threshold set by the operative, e.g. driller, when setting up and enabling the control system, the control system may be configured to relay an alarm signal (different from the warning alarm) to the operative, e.g. driller via the HMI arrangement. On receiving the alarm signal, the operative, e.g. driller, may in some circumstances be required to respond, via the HMI arrangement, with a confirmation signal confirming that drill string pressure integrity is in place.
Once there is a positive indicator of an influx, the control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment of the oil and gas installation.
Beneficially, the control system may thus be configured to detect and react to an influx that occurs during a tripping operation, such as tripping in, tripping out, pulling wet, pulling dry, and with or without a float in the drillstring.
In addition to being connected to the level sensor and the drill bit depth sensor, the control system may also be connected to a flow rate sensor, thereby permitting the control system to monitor the fluid flow rate from the wellbore.
Beneficially, the addition of fluid flow rate data from the flow rate sensor permits the control system to take account of how the mud flowrate effect of tripping in and tripping out of the wellbore would add or subtract to a potential influx flow rate.
Alternatively or additionally, the control system may be configured to action a further well control protocol in the form of an influx circulation operation, that is flowing the influx fluid out of the wellbore.
The control system may be connected to sensors configured to monitor drill pipe pressure, casing pressure, mud pump speed, mud pump strokes, and choke position. The control system may be configured to calculate the required information to perform the circulation operation such as kill-weight, mud weight, initial circulating pressure (ICP), and slow circulating rates (SCR).
The further well control protocol may comprise the control system assuming control of the well control and/or drilling equipment of the installation.
In use, when an influx has been shut-in, and the installation is ready to circulate out the influx, the control system may automatically takes control of well control and/or drilling equipment of the installation, e.g. mud pumps and the choke to perform the influx circulation operation or operations, as required, whilst maintaining the hydrostatic pressure above the pore pressure by the required overbalance margin, and maintaining that overbalance steady, throughout the circulation operation(s).
Beneficially, the system may thus be configured to cater for all types of common well kill methodologies, including the Drillers' Method and/or the Wait and Weight Method known in the art.
Moreover, the control system may be configured to identify problematic issues during well kill operations, such as plugged nozzles, plug choke, washed choked, washed drill pipe, or the like. On identification of such issues, the control system may be configured to stop operations. The control system may relay a warning signal to the operative, e.g. driller, via the HMI arrangement, together with a recommended corrective procedure. The control system may automatically initiate the recommended corrective procedure. Alternatively, in some circumstances the operative, e.g. driller, may be required to accept, via the HMI arrangement, the recommended solution before the control system completes the well kill operation. At any time, the HMI arrangement may be adaptable to display a range of displays in terms of pressure, time, and strokes pumps or the like.
Alternatively or additionally, the control system may be connected to a managed pressure drilling (MPD) system of the installation.
The control system may be configured to receive a signal from the MPD system indicating that an influx may have been detected.
The control system may be configured to check the signal from the MPD system and determine from the received signal whether or not the preselected threshold has been exceeded.
On determining that the preselected threshold has been exceeded, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement.
The control system may also initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment of the oil and gas installation.
Prior to initiation of the initial well control protocol and/or prior to initiation of the command signal to shut-in the well, the control system may look for further confirmation checks from the MPD system that such an action is still valid.
Beneficially, the control system may facilitate automated well control systems and operations to be combined with pre-existing MPD systems on an oil and/or gas installations. Moreover, the control system may be operable such that if the volume of an influx is greater than the maximum influx that the MPD system can circulate out (nominally 5 bbls), the control system facilitates at least the initial shut-in of the well quickly, efficiently and with minimal or no human intervention.
Alternatively or additionally, the control system may be connected to an early kick detection system (EKDS).
The control system may be configured to receive a signal from the EKDS indicating that an influx may have been detected.
The control system may be configured to check the signal from the EKDS and determine from the received signal whether or not the preselected threshold has been exceeded.
On determining that the preselected threshold has been exceeded, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement.
The control system may also initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment of the oil and gas installation.
Prior to initiation of the initial well control protocol and/or prior to initiation of the command signal to shut-in the well, the control system may look for further confirmation checks from the EKDS that such an action is still valid.
The control system and/or EKDS may be connected to the sensor package, e.g. wellsite information transfer standard markup language (WITSML) system, of the installation and/or configured to receive sensor data from the sensor arrangement, including one or more of: a flow line flow rate sensor; a pit volume totalizer (PVT) sensor; a rate of penetration (ROP) sensor; a mud pump speed (strokes per minute or SPM) sensor; a mud pump pressure (MPP) sensor; a drill string weight (DSW) sensor; a mudflow sensor; a connection gas sensor; a movement sensor; and/or a mud property (mud weight, plastic viscosity) sensor.
The EKDS may be connected to the HMI arrangement, in particular but not exclusively, via the control system, and may be configured so that the configuration of the sensor arrangement can be adjusted by the operative, e.g. driller, via the HMI arrangement.
The EKDS may comprise control software configured to receive, compute, process and combine the sensor data from the sensor arrangement, the resultant information then being tested against pre-set criteria (of a voting/delegation form) set by the operator. If the received and processed sensor information satisfies the pre-set criteria, then a signal may be relayed from the EKDS to the control system to initiate the command sequence to begin the initial well control protocol.
The sensor arrangement may comprise one or more pit volume totalizer (PVT) sensors configured to measure changes in the active mud pit fluid level, this being a primary kick indicator. The EKDS may be configured to process the information obtained from the (active) PVT sensors to compute an average fluid level height at a given time: i) whilst drilling ahead; and ii) during connections but only after fluid flow back of the flow line. The average fluid level would need to be compared with previous readings (e.g. every 15 secs) and also for trending changes.
The sensor arrangement may comprise one or more ROP sensor, the ROP sensor configured to detect an instantaneous increase in the rate of penetration of the drillstring, this being a secondary kick indicator. The ROP sensor may use information from the drawworks encoder sensor (that effectively measures the block height and thus the rate at which the drill pipe goes into the well). Alternatively or additionally, the ROP sensor may take the information from other height measurement sources.
The EKDS may be configured to process the information from the ROP sensor by comparing the current ROP with the recorded average and instantaneous ROP values over a selected distance, e.g. the last 100ft drilled.
The sensor arrangement may comprise one or more SPM sensor, the SPM sensor configured to detect an increase in mud pump strokes per minute (SPM), this being another secondary kick indicator. The SPM sensor may use information from the active mud pump speed controller/measurement device.
The EKDS may be configured to process the information obtained by the SPM sensor by comparing the current total mud pumps' strokes per minute with the recorded average and instantaneous strokes per minute over a selected past time period, e.g. the previous 5 minutes.
The sensor arrangement may comprise one or more mud pump pressure (MPP) sensor, the MPP sensor configured to detect a decrease in mud pump pressure (MPP), this being another secondary kick indicator. The MPP sensor may use information from the mud pump pressure output measurement device.
The EKDS is configured to process the information obtained by the MPP sensor by comparing the current mud pump pressure with the recorded average and instantaneous mud pump pressures over a selected past time period, e.g. the previous 5 minutes.
The sensor arrangement may comprise a drill string weight (DSW) sensor, the DSW sensor configured to detect a sudden change (in particular but not exclusively an increase in weight/reduction in buoyancy) in drill string weight (DSW), this being a secondary kick indicator. The DSW sensor may use information from the drillstring weight indicator.
The EKDS may be configured to process the information obtained by the DSW sensor by comparing the current DSW with the recorded average and instantaneous drill string weights over a selected time period, e.g. the previous 5 minutes.
The sensor arrangement may comprise a mud pump mudflow sensor, the mud pump mudflow sensor configured to measure the mud pump flow rate. The mud pump mudflow sensor may comprise a Coriolis type flowmeter on the input to one or more of the mud pumps and/or a Coriolis type flowmeter in the flow line. Alternatively, flowrate information may be determined by taking the input and output flowrate information feeds from the stroke counters.
The EKDS may be configured to process the information obtained by comparing the instantaneous total flowrate going into the wellbore (by combining mud pump input Coriolis flowrate) with the instantaneous exit flowrate coming out of the wellbore.
The sensor arrangement may comprise a connection gas sensor comprising online instrumentation configured to measure the size of each gas peak associated with each successive connection.
The EKDS may be configured to process the information obtained by the connection gas sensor by comparing the size and/or position of each gas peak with that of the previous gas peak. An increasing trend, subject to pre-set criteria, could indicate a kick, and the EKDS may process this information, along with information from other module sensors.
The oil and/or gas installation may comprise a floating platform and the sensor arrangement may comprise or may be operatively associated with one or more movement sensor configured to measure movement of the platform in terms of heave, sway, surge, roll, pitch and yaw.
The EKDS may be configured to receive and process the information from the movement sensor. Movement of the platform may be measured: i) using movement sensors; ii) using the motion reference unit (MRU) on the platform and/or iii) predicted based upon expected Response Amplitude Operator (RAO) values based upon the given weather and sea states. The resultant movement information may then be used to predict the effect of the movement of the platform on the flowrate in the flow line and/or the active pit fluid level. This prediction may take into effect fluid movement lag times and the design of fluid flow lines, circulation paths, and fluid pits on the installation, and the actual ongoing operations on the installation (e.g. drilling ahead, tripping, connections) at the time. The overall predicted fluid flowrate and fluid level characteristics may then be compared with the instantaneous readings on the platform. Comparisons may be made in terms of absolute values at a given time, and in terms of trending values. Deviations may be compared against predicted information on a pre-set criteria basis.
The sensor arrangement may comprise one or more mud property sensor. The EKDS and/or control system may be configured to take the automated mud measurements from an automated mud parameter measurement device, and run a series of algorithms looking at mud weights, gas cut percentages, salts, oil and water phases etc. then, as required, activate the initial well control protocol.
Each of the EKDS and the sensors of the sensor arrangement above can be provided as a separate module implemented in software.
The control system may be configured to detect and react to an influx during normal circulating activities. The control system may be connected to a flowmeter and may be configured to receive real time sensor data from the sensor, thereby permitting the control system to monitor the fluid flow rate from the wellbore during circulation. The control system may also be connected to a mud pump speed sensor configured to measure the speed of the mud pumps. The control system may be configured so that the base level flowrate held by control system is adaptable to, typically frequent, alterations to the mud pump speed/flowrate made by the operative, e.g. driller. The incremental flowrate that triggers the initial well control protocol may be inputted as a percentage increase. However, it will be understood that the incremental flowrate that triggers the initial well control protocol may alternatively be input as a fixed incremental amount above the instantaneous flowrate.
The control system may be configured to monitor the well when static. The control system may be connected to a level sensor configured to measure fluid level in the trip tank, a flow line sensor configured to measure fluid flow rate, and a sensor configured to measure the active pit volume.
During initial set up, the operative, e.g. driller, may preselect, via the HMI arrangement, which of the sensors are monitored. The decision as to which of the sensors are monitored may depend on whether the operation is being carried out in open hole or cased hole and/or how the mud flow system is lined up. The control system may be configured to determine from the sensor data received from the selected sensors, whether a detected volume change in the trip tank and/or in the active pit, or a detected flowrate change in the flow line exceeds a preselected threshold set by the operative, e.g. driller, when setting up and enabling the control system, this being indicative of a fluid influx condition in the wellbore. On determining that the fluid flow rate does exceed the preselected threshold fluid flow rate, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. The control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment.
The control system may be connected to a level sensor configured to measure fluid level in the trip tank. The control system may be configured to determine from the sensor data received from the sensors, whether a detected volume change in the trip tank exceeds a preselected threshold set by the operative, e.g. driller, when setting up and enabling the control system at the HMI arrangement, this being indicative of a fluid influx condition in the wellbore. On determining that the detected volume change does exceed the preselected threshold fluid flow rate, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. The control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment.
Beneficially, the control system can be utilised to monitor inflow tests on liner packers or on certain lower completions.
As described above, following initiation of the initial well control protocol the control system may be configured to initiate a further well control protocol in the form of a fluid pumping operation.
The control system may be configured to monitor the well during such a fluid pumping operation.
The control system may be connected to a sensor arrangement comprising one or more flow rate sensor, casing pressure gauge, mud pump speed and pressure sensors, mud property sensor. The control system may also receive leak-off test data and drill bit depth data.
Beneficially, the control system may be configured to limit the influx size that is shut-in by turning off the mud pump(s) slowly rather than with the normal turn on/off approach. This means that the loss of hydrostatic pressure due to the mud pump(s) being turned off (i.e. loss of the equivalent circulating density (ECD) occurs more slowly, thus limiting the size of influx coming into the wellbore and allowing pressures to equalise more quickly in the wellbore after shutting in. The control system may be configured to ensure that the Leak Off Test value (LOT) at the previous casing shoe will not be exceeded.
The control system may be connected to a sensor arrangement comprising one or more flow rate sensor, casing pressure gauge, mud pump speed and pressure sensors, mud property sensor. The control system may also receive drill bit depth data.
Beneficially, the control system may thus address a problem that is relatively common in clastic formations and in High Pressure High Temperature (HPHT) wells, called Ballooning, whereby the dynamic mud weight pressure approaches the formation pressure resulting of small amounts of drilling fluid leaking into the formation. On a connection, when the mud pumps are turned off and the drilling fluid pressure reduces, the leaked fluid will flow back into the wellbore. This can be a substantial volume over a long open hole section. It can be difficult to decipher this flow back from a true influx. The flow back will give a signature "flowrate with time" at surface.
During normal drilling operations, the control system may measure every signature on every connection, the control system determining from the data received from the sensor arrangement and optionally utilising an Artificial Intelligence algorithm, an expected signature at the next connection, the expected signature taking into account the extra amount of ballooning-prone formation now exposed.
The control system may compare the actual flow back signature at surface with the predicted signature, and subject to certain pre-set criteria, will action the initial well control protocol to shut in the well.
The control system may be configured to detect and react to an influx during a swabbing operation. The control system may be connected to a sensor arrangement, comprising one or more mud property sensor. The control system may also receive wellbore dimension data, drill bit depth data and leak-off test data. The control system may be configured to calculate the maximum pull out of hole (POOH) speed on a continuous basis. In the event an influx is detected, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. The control system may initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment to shut in the wellbore.
Beneficially, the control system may permit the POOH speed to be maximised while avoiding or at least mitigating the risk of swabbing an influx into the wellbore.
The control system may be configured to detect and react to an influx during a run-in operation. The control system may be connected to a sensor arrangement, comprising one or more mud property sensor. The control system may also receive wellbore dimension data, drill bit depth data and leak-off test data. Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the wellbore. Down hole mud losses may occur if care is not taken and fracture pressure is exceeded while running in hole (RIH). The control system may be configured to calculate the maximum RIH speed on a continuous basis. In the event an influx is detected, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. The control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment to shut in the wellbore.
The control system may be configured to detect and/or react to an influx, for example, during a run-in operation.
The control system may be connected to a sensor arrangement. The sensor arrangement may comprise one or more of a mud property, flowrate, speed and/or pressure sensor or the like. The control system may receive wellbore dimension data, casing depth data and/or leak-off test data or the like.
The control system may be configured to determine from the received data whether an influx is occurring. In the event an influx is detected, the control system may be configured to generate one or more output signal, which may be in the form of, for example, an alarm signal on the HMI in the control station. The alarm signal may comprise an audible and/or visual alarm signal. The control system may initiate an initial well control protocol by, for example, outputting a number of command signals to the installation and/or well control equipment to shut in the wellbore.
The control system may detect and/or react to an influx during the running of casing or liners.
The control system may receive wellbore dimension data, completion depth data and/or leak-off test data or the like.
The control system may detect and/or react to an influx during the running of completions.
The control system may detect and/or reacts to an influx during the cementing of casing or liner.
The control system may receive flowrate data. The flow rate data may be with or without the riser. The control system may receive wind direction data.
The control system may be designed for drilling the upper sections of the wellbore. The control system may be designed for drilling the upper sections without the BOP. The control system may be designed for drilling where it may not be safe to shut in the well due to, for example, the risk of casing shoe fracture. If the drilling encounters a pocket of shallow gas, the control system may detect a high mud flowrate return out of the well annulus. The methodology to detect the flowrate may be determined by the drilling mode; i.e. whether or not a riser is in place.
The control system may relay an alarm signal to the driller. The alarm signal may be related via the HMI arrangement.
The control system may continually and/or continuously pre-assess wind direction. The wind direction may be assessed at all times. Following the alarm signal, the control system may send a signal to open the downwind overboard line valve. A signal may be sent to close the diverter. Closing the diverter may divert the flow away from the installation.
The control system may be connected to a sensor arrangement. The sensor arrangement may comprise trip tank pump and/or level sensors.
For installations without a riser gas handling system, once BOPs are activated by the control system, the control system may automatically switch on the Trip Tank (TT) pump and/or switch the surface valves to monitor the riser contents.
The control system may monitor the trip tank. If the trip tank level increases over a period of time, the control system may determine that the BOP has not closed properly, sufficiently or completely and/or that there may be migrating gas in the riser.
The control system may initiate an increase in the closing pressure on the BOP.
Alternatively or additionally, the control system may initiate closure of an alternative BOP and/or may initiate directing the flow to the poor boy degasser (PBD) and/or initiate operation of the diverter system (having also assessed wind direction).
The consideration of routing may take account of the capacity of the PBD from the vessel throughput aspect and/or from a U-tube aspect.
If either of these are exceeded, the control system may initiate diversion of the flow through the diverter.
In either case, the control system may close another BOP, e.g. an alternative BOP and/or may automatically function the riser gas annular simultaneously.
The control system may be connected to a BOP sensor.
The control system may be configured to detect the pressure below a closed BOP. The control system may, for example, on detection of pressure below a closed BOP, execute an interlock to prevent any party from opening the BOP.
The control system may be connected to a library, of operator and/or drilling contractor well control procedures for, for example, tripping, connections drilling or the like.
The link to the library may permit sequencing of the control system operations to be tailored to a given operator and/or drilling contractor's well control procedures.
The control system may be connected to a multi-rig sensor arrangement.
The control system may be configured to determine, for example, using the data from the multi-rig sensor arrangement, the particular phase of well construction at a given time. The control system may automatically ensure that the appropriate control system module is in operation for that phase.
The control system may be switched on at all times. Alternatively, the control system may be switched on only when needed, or in use.
The control system may be configured to receive at least one of tidal data, selected space-out position data and time linking data.
The control system may be configured, based on the at least one of tidal data, selected space-out position data and time linking data, to automatically adjust the space-out position in response to changes in tide.
In use, the driller may select the space out positions on the control system via the HMI arrangement at initial set-up. Those positions may be logged, as may be the time at which they were logged. Where certain changes of tide make a previously selected space-out position unusable, the control system may relay an alter signal to the drill requesting an updated set of space-out positions.
Beneficially, the system may be particularly adapted for use on a floating rig that is subject to a large tidal range.
The control system may be configured to receive at least one of BOP dimension data, tidal data, space-out position data and BOP preference information.
The control system may be configured, based on the at least one of BOP dimension data, tidal data, space-out position data and BOP preference information, to automatically assess the position of the tool joint in relation to the exact BOP configuration on the installation, and to then auto-select which is the best BOP to close at any given time.
The control system may be configured to receive at least one of wireline depth meter data, rig floor depth data and safety distance data.
In use, the control system may be configured, based on the at least one of wireline depth meter data, rig floor depth data and safety distance data, to relay an alert signal to the driller, via the HMI, and/or wireline supervisor via a suitable data link, when pulling out of hole indicating that the tooling is near/at surface or is becoming held up and/or when running in hole that is close to target depth, or if it become held up.
Beneficially, the system may provide an automated warning for control of slickline, wireline, coil tubing etc.
The control system may be connected to a flowrate sensor. The sensor may be associated with the coiled tubing system of the installation.
In the event an influx is detected during coiled tubing operations, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement. The alarm signal may comprise audible and/or visual alarm signals.
The control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment, for example including the BOP operatively associated with the coiled tubing, to shut in the wellbore.
The control system may be connected to a flowrate sensor. The sensor may be associated with the wireline system of the installation.
In the event an influx is detected during wireline operations, the control system may be configured to generate one or more output signal in the form of an alarm signal on the HMI arrangement in the control station. The alarm signal may comprise audible and/or visual alarm signals.
The control system may initiate an initial well control protocol by outputting a number of command signals to the installation and well control equipment, for example including the BOP operatively associated with the wireline, to shut in the wellbore.
The control system may be configured to receive GPS and/or other positioning system data and/or vessel propulsion control data. The control system may be configured, based on the received GPS and/or other positioning system data and/or vessel propulsion control data, to output a number of command signals to the installation and well control equipment to close blind/shear, disconnect the Lower Marine Riser Package (LMRP), and perform installation drive off.
The control system may be configured to receive GPS and/or other positioning system data and/or vessel propulsion control data, and/or gas sensor data.
The control system may be configured, based on the received GPS and/or vessel propulsion control data, and/or gas sensor data, to output a number of command signals to the installation and well control equipment to close the blind/shear, disconnect the Lower Marine Riser Package (LMRP), and drive off.
The control system may be configured to receive GPS and/or other positioning system data and/or vessel propulsion control data, and/or excursion limit pre-integrity failure data.
The control system may be configured, based on the received GPS and/or other positioning system data and/or vessel propulsion control data, and/or excursion limit pre-integrity failure data, to output a number of command signals to the rig and well control equipment 102 to close the blind/shear, disconnect the Lower Marine Riser Package (LMRP), and perform a drive off.
Beneficially, the control system may be configured to shut-in the well where e.g. an excursion of the installation (e.g. due to a failed Dynamic Positioning system) reaches a point where the integrity of the riser/BOP system would otherwise be compromised.
The control system may be connected to a BOP sensor arrangement. The BOP sensor arrangement may be configured to receive data from the BOP.
The control system may be configured, based on the BOP sensor arrangement, to automatically and continually perform BOP fault finding and, in the event of an influx, automatically a required change (e.g. Pod Change or next lower BOP activation) to make the BOP function.
The control system may be connected to a sensor arrangement configured to receive data from all well control equipment on the installation.
The control system may be configured to monitor the status/health of key well control equipment (BOP, mud pumps, choke) and the associated equipment instrumentation on the HMI arrangement, and relay an audible alarm and/or visual signal in the event of a discrepancy in performance beyond a selected threshold.
The control system may be connected to a sensor arrangement configured to receive flowmeter data, trip tank sensor data, and active pit volume sensor data.
The control system may be configured to monitor the wellbore during a plug drill out operation during well decommissioning.
This is particularly important where previously-installed downhole barriers may be of questionable nature, or where insufficient mud weight cannot be properly achieved prior to drilling out a plug with a potential high pressure below.
The control system may be connected to a sensor arrangement configured to receive flowmeter data, trip tank sensor data, and/or active pit volume sensor data.
The control system may be configured to output command signals to a mechanical arm, to be used for example to automatically install, torque up, and/or close a full opening safety valve (FOSV).
The system topology may be implemented within the control software of the control system or may be a standalone module.
The control system may comprise or may be operatively associated with a software module that may determine the health of a flow meter e.g. the module, flowmeter paddle, the health of a Coriolis meter, or any other flow meter. For example, the control system may be configured to determine the health of a flow meter where, for example: there are no fluctuations in flow rate detected over a specified period; the flow meter outputs a minimum reading when mud pumps are operating well above that level; the flow meter outputs a maximum reading when the mud pumps are operating well below that level; and/or the flow meter outputs a significantly different reading to previously observed recent readings.
The control system, on identifying a deviation in the health of the flow meter, may then relay a warning signal to the operative via the HMI arrangement.
The control system may comprise or may be operatively associated with a software module that can record data critical to the decision to shut-in the well and may record all relevant instrumentation, actions and timing throughout the process of automatically safely shutting in the well to provide historical record for future analysis of the effectiveness of the system responses, and any human interventions.
The control system may pass data in real time over a secure internet link enabling management to view status of control system at any time. This may provide all data critical to the decision to shut-in the well ensuring a safe remote record all relevant instrumentation, actions and timing throughout the process of automatically safely shutting in the well to provide historical record for future (and immediate) analysis of the effectiveness of the system responses, and any human interventions.
The control system program may be accessible over a secure internet link enabling technical support for fault finding diagnostics, configuration and/or upgrades to be affected from a remote location. This may provide enhanced efficiency of commissioning and support to ensure maximum up-time for the control system equipment, and may reduce the need for high skilled technical support in remote locations.
The control system may comprise or may be operatively associated with a biometric security software module. The biometric security module may be used where pre-operation or post-operation authorisation is required (e.g. opening of a closed BOP). The biometric security module may require e.g. thumb-print, or face recognition identification of higher authority (e.g. a toolpusher), on the HMI arrangement.
The control system may be configured to allow the driller the ability to shut-in the wellbore without having to switch the control system off very quickly, e.g. in an emergency situation. There may be a button on the HMI arrangement that may enable a one or two touch action to perform the full shut in sequence including space out, stop drilling equipment and/or close the BOP.
It will be understood that any one of the features defined above or described below may be utilised in isolation or in combination.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects will now be described by way of example with reference to the accompanying drawings, of which:

Figure 1 shows an oil and gas installation comprising an automated well control system;
Figure 2 shows an enlarged view of the driller's cabin of the oil and gas installation shown in Figure 1;
Figure 3 is a diagrammatic view of the automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 4 shows a schematic view of components of the automated well control system;
Figure 5 shows components of the automated well control system;
Figure 6 shows a flow chart showing a method for use in well control;
Figure 7 is a flow chart showing a further method for use in well control;
Figure 8A and 8B are flow charts together showing an alternative method for use in well control;
Figure 9 is a pore pressure/fracture gradient diagram illustrating the method shown in Figures 8A and 8B;
Figure 10 is a flow chart showing a further method for use in well control;
Figure 11 is a flow chart showing a further method for use in well control;
Figure 12 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 13 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 14 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 15 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 16 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 17 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 18 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 19 shows a diagrammatic view of the EKDS shown in Figure 18;
Figure 20 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 21 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 22 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 23 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 24 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 25 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 26 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 27 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 28 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 29 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 30 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 31 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 32 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 33 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 34 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 35 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 36 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 37 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 38 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 39 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 40 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 41 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 42 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 43 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 44 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 45 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1;
Figure 46 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1; and
Figure 47 is a diagrammatic view of an alternative automated well control system topology, showing the integration of the automated well control system with components of the oil and gas installation shown in Figure 1.

DETAILED DESCRIPTION OF THE DRAWINGS

Referring first to Figures 1 and 2 of the accompanying drawings, there is shown an oil and/or gas installation 10 utilising an automated well control system (represented generally at 12 in Figure 2). As shown in Figure 1, the oil and/or gas installation 10 comprises a floating platform 14 which is coupled to a subsea wellhead 16 of wellbore 18 by a marine riser 20. A driller's control station 22 is located on a drill deck 24 of the platform 14 and, as shown in Figure 2 of the accompanying drawings, the control system 12 communicates with the driller 26 via human machine interface (HMI) 28 located within the driller's control station 22. In the illustrated system 12, the control system 12 communicates with the HMI 28 via an optical fibre communication arrangement 30, although it will be recognised that other wired or wireless communication arrangements may be provided.
Figure 3 of the accompanying drawings shows a diagrammatic view of the system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10 shown in Figure 1.
As shown in Figure 3, the control system 12 is operatively coupled to flow sensors 32 of mud pump system 34 and, in use, the control system 12 is configured to receive real time sensor data 36 from the sensors 32, thereby permitting the control system 12 to monitor the fluid flow rate from the wellbore 18 in Figure 1.
As also shown in Figure 3, the illustrated control system 12 is also operatively coupled to a rig data system 38 and, in use, is configured to receive real time downhole data 40 from the rig data system 38.
In use, the control system 12 is configured to determine from the sensor data 32 whether the fluid flow rate exceeds a preselected threshold fluid flow rate set by the driller 26 when setting up and enabling the control system 12 at the HMI 28, this being indicative of a fluid influx condition in the wellbore 12.
On determining whether the fluid flow rate seen by the sensors 32 does exceed the preselected threshold fluid flow rate, the control system 12 is configured to initiate an initial well control protocol by outputting a number of command signals to components of the installation 10 as will be described. In the illustrated control system 12, for example, on determining that the fluid flow rate seen by the sensors 32 does exceed the preselected threshold fluid flow rate, the control system 12 implements an initial well control protocol in the form of a well shut-in procedure involving:

communicating a command signal 42 to controller 44 of drawworks 46 to instruct the drawworks 46 to raise the drill string 48 (shown in Figure 1) off the bottom of the wellbore 18;
communicating a command signal 50 to controller 52 of top-drive 54 to instruct the top drive 54 to stop rotating;
communicating a command signal 56 to controller 58 of mud pumps 60 to instruct the mud pumps 60 to stop pumping fluid into the wellbore 18; and
communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12.

The controllers 44, 52, 58, and 64 each control components 46,54,60 and 66 respectively. It will be recognised that in other instances, for example in traditional installations, the components may be directly controlled rather than via controllers.
As shown in Figure 3, the control system 12 is also operatively coupled to choke manifold 68 and choke panel 70.
Figures 4 and 5 of the accompanying drawings show components of the automated well control system 12 in more detail. As shown, the control system 12 comprises a controller 72 which in the illustrated system 12 takes the form of two synchronised Programmable Logic Controllers (PLCs) 74 each containing a CPU 76 and a memory unit 78. Each PLC 74 is coupled to a power supply module 80 operating on 24V DC. The PLCs 74 are linked via a fibre optic cable 82. However, it will be understood that any suitable wired or wireless communications protocol may be utilised.
The control system 12 further comprises an input/output module 84 for providing communication between the controller 72 and the components of the installation 10 in the manner described above with reference to Figure 3.
The input/output module 84 and the PLCs 74 of the controller 72 communicate via a Process Field Bus (Profibus) interface 86. However, it will be understood that any suitable wired or wireless communications protocol may be utilised.
The control system 12 further comprises an Industrial Personal Computer (IPC) 88, the IPC 88 operable to run the software for the HMI 28 (shown in Figure 2).
The control system 12 further comprises an Ethernet switch 90 facilitating communication with multiple devices simultaneously.
Figure 4 also shows the fibre optic cable 30 for linking the IPC and the HMI 28.
As shown in Figure 5, the control system 12 further comprises an uninterruptable power supply (UPS) module 92 and battery 94. In use, the UPS 92 and battery 94 provide back-up power to the 24V DC components of the control system 12 in the event of power failure.
The control system 12 further comprises an Intrinsically Safe (IS) barrier unit 96 configured to convert the 24V power supply into one that is safe for use in a hazardous area by virtue of the converted supply not being powerful enough to cause an ignition source, spark or the like.
The control system 12 further comprises an AC/DC converter 98 for converting a 240V AC supply to a 24V DC supply for the PLCs.
Operation of the control system 12 will now be described with reference to Figures 6, 7 and 8 of the accompanying drawings.
As shown in Figure 6, the control system 12 is first set up and enabled by the driller 26 at the HMI 28.
The driller 26 then controls the drilling equipment, including amongst other things the drawworks 46, the top-drive 54, and mud pumps 60, to begin drilling operations. At this point, from the driller's 26 perspective the control system 12 is operating in the background, that is the drilling operations are not affected by the control system 12. However, the control system 12 is monitoring the fluid flow rate, in particular mud flow returns rate from the wellbore 18. The fluid flow rate data may be sourced from the rig data system (not shown). Alternatively, for older installations which do not employ a rig data system the fluid flow rate data may be sourced directly from instrumentation.
On detecting an increase in fluid flow rate from the wellbore 18 which exceeds a preselected threshold set by the driller 26 when setting up and enabling the control system 12, the control system 12 generates output signals in the form of an audible alarm and visual warning on the HMI in the control station 22.
The control system 12 also implements the initial well control protocol in the form of a well shut-in procedure, as will be described below.
The control system 12 generates command signal 42 to the controller 44 of the drawworks 46 to instruct the drawworks 46 to raise the string 48 off the bottom of the wellbore 18.
Data on the height of the drawworks 46 will be sourced from the drawworks controller 44.
When the drawworks reaches the first available set height, the control system controller will command the drawworks controller to stop raising the drill string 48.
The control system 12 also generates command signal 50 to the top drive controller 52 to instruct the top drive 54 to stop rotation.
The control system 12 also generates command signal 56 to the mud pumps controller 58 to stop a number of pre-selected mud pumps 60.
After a pre-set delay time set by the driller 26 when setting up and enabling the control system 12, if the control system 12 detects that the flow rate remains above the preselected threshold flow rate, or following confirmation the mud pumps 60 have stopped and a further time delay has been completed, if flow has not reduced to a negligible level the system 12 determines that an influx condition is present and ongoing. In the illustrated method, the pre-set delay time set by the driller 26 when setting up and enabling the control system 12 is 1 second and the further time delay is 30 seconds. The pre-set delay time and further time delay are adjustable by the driller 26 when setting up the control system 12, but occur automatically once the control system 12 has been enabled.
On determining that an influx condition is present, the control system controller 72 will generate a command signal to the BOP 66 to immediately close the annular preventer or pipe ram (depending on which option has been preselected by the driller during set up of the control system 12).
Once the BOP 66 has been closed, and the wellbore 18 shut-in, the alarm signal is cancelled and the control system controller 72 returns to a dormant condition, i.e., continues to monitor data from the other systems but makes no operational demands on the components of the installation 10 until the driller 26 initiates an operation to circulate the influx as will be described below with reference to Figure 7. The system 12 may be dormant from 30 minutes to 2 hours depending on what option has been chosen by the driller 26 when setting up the system 12.
As shown in Figure 7, after the wellbore 18 has been shut in, the system 12 performs the necessary calculations to produce a kill sheet used to confirm pressure and required details required to circulate out the influx from the wellbore 18 automatically.
The system logic determines max pressure on the drill pipe and casing sides, using the auto choke to maintain the safety margins pressure required from the drill pipe and casing sides.
The choke or kill line valve on the choke manifold 70 is opened to then line up the choke panel 68, to monitor drill pipe and casing pressures until they stabilise.
Once drill pipe and casing pressures have stabilised, on the preset instructions from the HMI 28 the system 12 will automatically start the selected mud pumps 60 to circulate the influx out of the wellbore 18 at a set speed pre-selected by the driller 26 on the HMI 28. By way of example, the set speed may be in the range of 5 strokes per minute (SPM) up to 40 strokes per minute (SPM).
The control system 12 will automatically operate the choke valve and/or panel 68 to the correct opening or closing percentages depending on the safety margins required in the wellbore 18, until the influx is circulated out of the wellbore 18.
The control system 12 continuously monitors the actual versus calculated pressures and automatically adjusts the choke valve or panel 68 opening or closing positions to ensure the correct pressures are maintained until the influx is safely circulated out of the wellbore 18.
Referring now to Figures 8A and 8B of the accompanying drawings, there is shown an alternative automated method for use in well control.
As shown in Figure 8A, the control system 12 is first set up and enabled by the driller 26 at the HMI 28.
The driller 26 then controls the drilling equipment, including for example the drawworks 46, the top drive 54, and mud pumps 60, to begin drilling operations. At this point, from the driller's 26 perspective the control system 12 is operating in the background, that is the drilling operations are not affected by the control system 12. However, the control system 12 is monitoring the fluid flow rate, in particular mud flow returns from the wellbore 18. The fluid flow rate data may be sourced from the rig data system 38. Alternatively, for older installations which do not employ a rig data system 38 the fluid flow rate data may be sourced directly from instrumentation.
On detecting an increase in fluid flow rate from the wellbore 18 which exceeds a preselected threshold set by the driller 26 when setting up and enabling the control system 12, the control system 12 generates output signals in the form of an audible alarm and visual warning on the HMI 28 in the control station 22.
The control system 12 also implements the initial well control protocol in the form of a well shut-in procedure, as will be described below.
The control system 12 generates command signal 42 to the controller 44 of the drawworks 46 to instruct the drawworks 46 to raise the string 48 off the bottom of the wellbore 18.
Data on the height of the drawworks 46 will be sourced from the drawworks controller 44.
When the drawworks 46 reaches the first available set height, the control system controller 72 will command the drawworks controller 44 to stop raising the drill string 48.
The control system 12 also generates command signal 50 to the top drive controller 52 to instruct the top drive 54 to stop rotation.
The control system 12 also generates command signal 56 to the mud pumps controller 58 to stop the pre-selected mud pumps 60. However, in the alternative method illustrated in Figure 8A, one of the mud pumps 60 continues to pump, for example at 30 strokes per minute (SPM).
On determining that an influx condition is present, the control system controller 72 will generate command signal 62 to the BOP 66 to immediately close the annular preventer or pipe ram (depending on which option has been preselected by the driller 26 during set up of the control system 12).
Once the BOP 66 has been closed, and the wellbore 18 shut-in, the mud pump 60 continues to pump at a low rate, e.g. 30 strokes per minute, until the appropriate drill pipe pressure is achieved.
The appropriate drill pipe pressure to which the mud pump 60 continues to pump is determined as the lower of Pmax and Psc, where Pmax is the maximum pressure that can be achieved without damaging the formation, and where Psc is the pressure at which the pumped fluid equals the pressure of the influx (the "supercharge" pressure).
As described above, during the well construction process the Maximum Allowable Annulus Surface Pressure (MAASP) must not be exceeded, otherwise an underground blowout may be initiated. This may lead to a breach to surface and must be avoided.
Pmax may be defined with reference to MAASP by equation (1): $Pmax = MAASP - 100 psi$
MAASP itself may be calculated from equation (2): $MAASP = (FG - MW) \times 0.052 \times TVD,$

where FG is the fracture gradient,
where MW is the mud weight in pounds per gallon,
where TVD is the total vertical depth of the casing shoe in ft

Psc = X \times 0.052 \times TVD,

where TVD is the total vertical depth of the casing shoe in ft,
where X is the additional mud weight in pounds per gallon (ppg) which the drilling engineer and geologist determine is derived from the maximum probable increase in mud weight for the hole section being drilled. It is determined by hole section and depth of the well. For instance a relatively shallow hole section, down to 2,500ft in an area where the pore pressure is well known might have an X value of 0.5ppg. In a deeper hole section, 12,000ft with a large potential for higher pore pressures, may have an X value of 4ppg.

The control system 12 logic determines if Pmax or Psc is lower and continues pumping to whichever is the lower pressure.
The mud pump 60 is then slowed down incrementally from 30 strokes per minute to 20 strokes per minute to 10 strokes per minute over the last 100 psi. Within 100 psi, the system 12 reduces to 20 strokes per minute. Within 50 psi it reduces to 10 strokes per minute.
At the predetermined value the mud pump 60 stops pumping.
The alarm is cancelled and the control system controller 72 returns to a dormant condition, continues to monitor data from the other systems but makes no operational demands on the other equipment.
Having addressed the influx, and when safe to do so, operations may then be resumed by the driller 26.
Beneficially, the fluid pumping operation of Figures 8A and 8B reduces or minimises the volume of the influx. Minimising the influx volume has several advantages. For example, a reduced influx volume may result in lower pressure being exerted on the wellbore 18 and the rig equipment. There is also a reduced risk of getting stuck and other hole problems. More options to kill the well become available, particularly using the bull-heading technique to displace the influx back into the donor formation. The system 12 assures the operator that the influx volume would be significantly reduced, in particular but not exclusively to a maximum of five barrels of influx.
Referring now also to Figure 9 of the accompanying drawings, which shows a pore pressure/fracture gradient diagram of a given wellbore, a kick event is detected at 11,000 ft (3.35km) whilst drilling with 14.2ppg (pounds per gallon) drilling mud.
The shoe at 9,000 ft has a fracture gradient of around 15.2ppg.
The MAASP is therefore 1ppg x 0.052 x 9,000ft = 468psi.
The uncertainty of the pore pressure, determined by the operations geologist and drilling engineer was 2ppg, meaning the probability of the anticipated pore pressure to be greater than 2ppg is very low. Therefore, X = 2 ppg.

Pmax = 468psi-100psi = 368 psi with 14.2ppg mud.
Psc = 2ppg x 0.052 x 9000ft = 936 psi, with 14.2ppg mud.

Thus, after the wellbore has been the shut in, the selected mud pump 60 continues pumping to 368psi. The selected mud pump 60 is then stopped as described above.
Figure 10 of the accompanying drawings shows a flow chart showing a further method for use in well control. In this method, the drill pipe is being run in or being pulled out of the wellbore 18.
As shown in Figure 10, the control system 12 is set-up & enabled by the driller 26 at the HMI 28.
The driller 26 then controls the drilling equipment and begins tripping operations.
The driller 26 enters differential mud volume data into the HMI 28 as the drill pipe is run in or pulled out of the wellbore 18.
The control system 12 receives a signal from a sensor in the trip-tank, while the drill pipe is being pulled out or run in hole.
When the sensor identifies an inconsistency in mud volumes, the driller 26 is alerted on the HMI 28.
After a pre-set time delay, if the threshold is still exceeded or if, following a further time delay, flow has not reduced to a negligible level, the system 12 determines that an influx is ongoing, and initiates the initial well control protocol.
The control system 12 sends a command to the drawworks controller 44 instructing it to immediately lower the drawworks 46. When the drawworks 46 reaches the connection height, the control system 12 commands the drawworks controller 44 to stop.
As the initial well control protocol progresses, the HMI 28 displays the steps of the process, e.g. "Stab in Full Open Safety Valve", "Make Up Valve", "Close Valve". Once the three actions are taken, the driller 26 presses the validation button on the HMI 28.
The control system PLC 74 then commands the BOP controller 64 to immediately close the annular preventer of BOP 66.
The alarm is cancelled and the control system controller 72 returns to a dormant condition, continues to monitor data from the other systems but makes no operational demands on the other equipment.
Having addressed the influx, and when safe to do so, operations may then be resumed by the driller 26.
Figure 11 is a flow chart showing a further method, for use when drill pipe connections are made for drilling-in the wellbore 18.
The control system 12 is first set up and enabled by the driller 26 at the HMI 28.
The driller 26 then controls the drilling equipment, including for example the drawworks 46, the top drive 54, and mud pumps 60, to begin drilling operations. At this point, from the driller's 26 perspective the control system 12 is operating in the background, that is the drilling operations are not affected by the control system 12. However, the control system 12 is monitoring the fluid flow rate, in particular mud flow returns from the wellbore 18. The fluid flow rate data may be sourced from the rig data system 38. Alternatively, for older installations which do not employ a rig data system 38 the fluid flow rate data may be sourced directly from instrumentation.
If the control system 12 determines from the input signal received from sensor 32 that the fluid flow rate exceeds a pre-set threshold flowrate for when the drill pipe is stationary, the control system 12 generates output signals in the form of an audible alarm and visual warning on the HMI 28 in the control station 22.
The control system 12 then sends a signal to a control arm to install a valve on the top of the drill pipe.
When the valve is installed, the control system 12 will send a command to BOP controller 64 to close the BOP 66.
The above system and method provides a number of benefits over conventional well control techniques. For example, in addition to providing automated detection and actioning of the initial well control protocol, e.g. shut-in procedure, the system and method provides automation of the maximum pressure calculations on a continuous basis, since mud weight (MW) varies during the drilling process and the system 12 is configured to continuously monitor the mud weight, e.g. from the installation sensor arrangement.
It will be recognised that the above is merely exemplary and that various modifications may be made without departing from the scope of the claims.
For example, the control system 12 may be configured to additionally monitor the level in the mud pit as indicative of an increase in fluid flow rate from the wellbore 18.
The control system 12 may also read the pump pressure on a continuous basis and present this to the driller 26 in order to communicate the proximity to shoe fracture pressures.
It will be recognised that the control system 12 may be utilised in a range of different applications during operation of the oil and gas installation 10, as described below.
For example, Figure 12 of the accompanying drawings shows a diagrammatic view of a system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during the process of making and/or breaking a connection, that is adding a joint or stand of drill pipe to the top of the drillstring.
As shown in Figure 12, the control system 12 is coupled to flow line sensor 100 and is configured to receive real time sensor data from the sensor 100, thereby permitting the control system 12 to monitor the fluid flow rate from the wellbore 18 during any one of the sub-phases of making the connection. The flow line sensor 100 may be identical to the sensor 32 described above, or may take the form of another flow rate sensor.
The control system 12 is configured to determine from the sensor data whether the fluid flow rate exceeds a preselected threshold fluid flow rate set by the driller 26 when setting up and enabling the control system 12 at the HMI 28, this being indicative of a fluid influx condition in the wellbore 12.
On determining that the fluid flow rate does exceed the preselected threshold fluid flow rate, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
On receiving the alarm signal, the driller 26 is required to respond, via the HMI 28, with a confirmation signal confirming that drill string pressure integrity is in place. Once there is a positive indicator of an influx, and the driller 26 has confirmed that the drill string pressure integrity is in place, the control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment, generally and collectively referred to at 102, of the oil and gas installation 10.
In the illustrated system shown in Figure 12, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a drawworks command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controller 64 controls the BOP 66. It will be recognised that in other instances, for example in traditional rigs, the BOP 66 may be directly controlled rather than via a controller 64.
Beneficially, while the driller 26 is performing the manual operation of making the connection, the control system 12 is operable to detect and react to an influx that occurs during any one of the sub-phases of making a connection.
Figure 13 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during a tripping operation, that is pulling the drillstring from the wellbore 18 and/or running the drill string back into the wellbore 18,for example to replace a drill bit.
As shown in Figure 13, the control system 12 is connected to a level sensor 104 in trip tank 106 of the oil and/or gas installation 10, the level sensor 104 configured to provide accurate real time data indicative of the fluid level in the trip tank 106. The control system 12 is also connected to drill bit depth sensor 108, the drill bit depth sensor 108 configured to provide real time data indicative of the depth of the drillstring in the wellbore 18.
The control system 12 is configured to determine, from the data provided by the drill bit depth sensor 108, the volumetric displacement of the drill pipe as it trips into and/or out of the wellbore 18.
The control system 12 is configured to compare the data from level sensor 104 relating to the fluid level in the trip tank 106 with the volumetric displacement of the drill pipe determined from drill bit depth sensor 108; a deviation in the form of an increase in the fluid level in the trip tank 106 relative to the determined volumetric displacement being indicative of an influx.
In the event a small deviation is detected by the control system 12, the control system 12 is configured to relay a warning signal to the driller 26 via the HMI 28. In the illustrated system, the warning signal takes the form of an audible alarm signal. However, it will be understood that the warning signal may take any other suitable form, such as a visual and/or haptic signal or the like.
In the event of a larger deviation exceeding a preselected threshold set by the driller 26 when setting up and enabling the control system 12 at HMI 28, the control system 12 is configured to relay an alarm signal (different from the warning alarm) to the driller 26 via the HMI 28. In the illustrated system, the alarm signal comprises audible and visual alarm signals. However, it will be understood that the alarm signal may take any other suitable form, such as a visual and/or haptic signal or the like.
On receiving the alarm signal, the driller 26 is required to respond, via the HMI 28, with a confirmation signal confirming that drill string pressure integrity is in place.
Once there is a positive indicator of an influx, and the driller 26 has confirmed that the drill string pressure integrity is in place, the control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment, generally and collectively referred to at 102, of the oil and gas installation 10.
In the illustrated system, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a drawworks command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12.
The controller 64 controls the BOP 66. It will be recognised that in other instances, for example in traditional installations, the BOP 66 may be directly controlled rather than via controller 64.
On receiving the audible alarm and/or visual warning, the driller 26 is required to respond, via the HMI 28, with a confirmation signal confirming that drill string pressure integrity is in place before the well shut-in operation is initiated.
Beneficially, the control system 12 is configured to detect and react to an influx that occurs during a tripping operation, such as tripping in, tripping out, pulling wet, pulling dry, and with or without a float in the drillstring.
Figure 14 of the accompanying drawings shows an alternative system topology of the control system 12 for detecting and reacting to an influx during a tripping operation to that shown in Figure 13.
As shown in Figure 14, in addition to being connected to the level sensor 104 and the drill bit depth sensor 108, the control system 12 is also connected to a flow rate sensor 110, thereby permitting the control system 12 to monitor the fluid flow rate from the wellbore 18. The flow rate sensor 110 may be identical or similar to the sensor 32 or flow line flow rate sensor 100 described above, or may take the form of another flow rate sensor.
Beneficially, the addition of fluid flow rate data from flow rate sensor 110 permits the control system 12 to take account of how the mud flowrate effect of tripping in and tripping out of the wellbore 18 would add or subtract to a potential influx flow rate.
As described above, following initiation of the initial well control protocol, the system 12 may be configured to action a further well control protocol in the form of an influx circulation operation.
Figure 15 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to perform an influx circulation operation, that is flowing the influx fluid out of the wellbore 18.
For clarity, the components required to detect and react to an influx and initiate the initial well control protocol have been omitted.
As shown in Figure 15, the control system 12 is connected to sensors, shown collectively at 112, configured to monitor drill pipe pressure, casing pressure, mud pump speed, mud pump strokes, and choke position.
The control system 12 is configured to calculate the required information to perform the circulation operation such as kill-weight, mud weight, initial circulating pressure (ICP), and slow circulating rates (SCR).
In use, when an influx has been shut-in, and the installation 10 is ready to circulate out the influx, the control system 12 automatically takes control of the mud pumps 60 and the choke 68 to perform the influx circulation operation or operations, as required, whilst maintaining the hydrostatic pressure above the pore pressure by the required overbalance margin, and maintaining that overbalance steady, throughout the circulation operation(s).
Beneficially, the system is configured to cater for all types of common well kill methodologies, including the Drillers' Method and/or the Wait and Weight Method known in the art.
Moreover, the control system 12 is configured to identify problematic issues during well kill operations, such as plugged nozzles, plug choke, washed choked, washed drill pipe, or the like. On identification of such issues, the control system 12 is configured to stop operations and relay a warning signal to the driller 26 via the HMI 28, together with the recommended corrective procedure. The driller 26 will be required to accept, via the HMI 28, the recommended solution before the control system completes the well kill operation.
At any time, the HMI 28 is adaptable to display a range of displays in terms of pressure, time, and strokes pumps or the like.
Figure 16 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, in this instance a managed pressure drilling (MPD) system 114 of the oil and/or gas installation 10.
As shown in Figure 16, the control system 12 is connected to the MPD system 114, the control system 12 configured to receive a signal from the MPD system 114 indicating that an influx may have been detected.
The control system 12 is configured to check the signal from the MPD system 114 and determine from the received signal whether or not the preselected threshold has been exceeded.
On determining that the preselected threshold has been exceeded, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22.
The control system 12 also initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 of the oil and gas installation 10.
In the illustrated system shown in Figure 16, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a command signal 42 to controller 44 of drawworks 46 to instruct the drawworks 46 to raise the drill string 48 off the bottom of the wellbore 18; communicating a command signal 50 to controller 52 of top-drive 54 to instruct the top drive 54 to stop rotating; communicating a command signal 56 to controller 58 of mud pumps 60 to instruct the mud pumps 60 to stop pumping fluid into the wellbore 18; and communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controllers 44, 52, 58, and 64 each control components 46,54,60 and 66 respectively. It will be recognised that in other instances, for example in traditional installations, the components may be directly controlled rather than via controllers.
Prior to initiation of the shut-in, the control system 12 will look for further confirmation checks from the MPD system 114 that such an action is still valid.
Beneficially, the control system 12 facilitates automated well control systems and operations to be combined with pre-existing MPD systems on an oil and/or gas installations. Moreover, the control system 12 is operable such that if the volume of an influx is greater than the maximum influx that the MPD system 114 can circulate out (nominally 5 bbls), the control system 12 facilitates at least the initial shut-in of the well quickly, efficiently and with minimal or no human intervention.
Figure 17 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, in this instance an early kick detection system (EKDS) 116. In the illustrated system shown in Figure 17, the EKDS 116 is a pre-existing third party EKDS 116 of the oil and/or gas installation 10.
As shown in Figure 17, the control system 12 is connected to the EKDS 116, the control system 12 configured to receive a signal from the EKDS 116 indicating that an influx may have been detected.
The control system 12 is configured to check the signal from the EKDS 116 and determine from the received signal whether or not the preselected threshold has been exceeded.
On determining that the preselected threshold has been exceeded, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22.
The control system 12 also initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 of the oil and gas installation 10.
In the illustrated system shown in Figure 17, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a command signal 42 to controller 44 of drawworks 46 to instruct the drawworks 46 to raise the drill string 48 off the bottom of the wellbore 18; communicating a command signal 50 to controller 52 of top-drive 54 to instruct the top drive 54 to stop rotating; communicating a command signal 56 to controller 58 of mud pumps 60 to instruct the mud pumps 60 to stop pumping fluid into the wellbore 18; and communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controllers 44, 52, 58, and 64 each control components 46,54,60 and 66 respectively. It will be recognised that in other instances, for example in traditional installations, the components may be directly controlled rather than via controllers.
Prior to initiation of the shut-in, the control system 12 will look for further confirmation checks from the EKDS 116 that such an action is still valid.
Figure 18 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, in this instance an early kick detection system (EKDS) 118.
As shown in Figure 18, the control system 12 is connected to the EKDS 118, the control system 12 configured to receive a signal from the EKDS 118 indicating that an influx may have been detected.
Referring now also to Figure 19 of the accompanying drawings, the EKDS 118 is connected to and configured to receive sensor data from a sensor arrangement, generally designated 120, including one or more of: a flow line flow rate sensor 122; a pit volume totalizer (PVT) sensor 124; a rate of penetration (ROP) sensor 126; a mud pump speed (strokes per minute or SPM) sensor 128; a mud pump pressure (MPP) sensor 130; a drill string weight (DSW) sensor 132; a mudflow sensor 134; a connection gas sensor 136; a movement sensor 138; and a mud property (mud weight, plastic viscosity) sensor 140.
As shown in Figure 18, the EKDS 118 is connected to the control system 12 and HMI 28 and the configured so that the configuration of the sensor arrangement 120 can be adjusted by the driller 26 via the HMI 28.
The EKDS 118 comprises control software configured to receive, compute, process and combine the sensor data from the sensor arrangement 120, the resultant information then being tested against pre-set criteria (of a voting/delegation form) set by the operator. If the received and processed sensor information satisfies the pre-set criteria, then the signal will be relayed from the EKDS 118 to the control system 12 to initiate the command sequence to begin the initial well control protocol.
Prior to initiation of the shut-in, the control system 12 will look for further confirmation checks from the EKDS 118 that such an action is still valid.
As described above, the sensor arrangement 120 comprises one or more flow line flow rate sensor 122, the flow rate sensor 122 configured to measure flow rate from the wellbore 18. The flow rate sensor 122 may be identical or similar to the sensor 32, flow line flow rate sensor 100 or flow rate sensor 110 described above, or may take the form of another flow rate sensor.
The sensor arrangement 120 in the illustrated system comprises a plurality of PVT sensors 124 placed around the active mud pit and configured to measure changes in the active mud pit fluid level, this being a primary kick indicator.
As regards the PVT sensors 124, the EKDS 118 is configured to process the information obtained from the (active) PVT sensors 124 to compute an average fluid level height at a given time: i) whilst drilling ahead; and ii) during connections but only after fluid flow back of the flow line. The average fluid level would need to be compared with previous readings (e.g. every 15 secs) and also for trending changes. Data should be excluded for a short period during the start up and/or stopping of the mud pumps 60 and/or for intentional changes in the speed of the mud pumps 60 instructed by the driller 26.
As described above, the sensor arrangement 120 comprises one or more ROP sensor 126, the ROP sensor 126 configured to detect an instantaneous increase in the rate of penetration of the drillstring, this being a secondary kick indicator.
The ROP sensor 126 uses information from the drawworks encoder sensor (that effectively measures the block height and thus the rate at which the drill pipe goes into the well). Alternatively or additionally, the ROP sensor 126 may take the information from other height measurement sources.
As regards the ROP sensor 126, the EKDS 118 is configured to process the information from the ROP sensor 126 by comparing the current ROP with the recorded average and instantaneous ROP values over a selected distance, e.g. the last 100ft drilled.
As described above, the sensor arrangement 120 comprises one or more SPM sensor 128, the SPM sensor 128 configured to detect an increase in mud pump strokes per minute (SPM), this being another secondary kick indicator. The SPM sensor 128 uses information from the active mud pump speed controller/measurement device.
As regards the SPM sensor 128, the EKDS 118 is configured to process the information obtained by the SPM sensor 128 by compare the current total mud pumps' strokes per minute with the recorded average and instantaneous strokes per minute over a selected past time period, e.g. the previous 5 minutes.
As described above, the sensor arrangement 120 comprises one or more mud pump pressure (MPP) sensor 130, the MPP sensor 130 configured to detect a decrease in mud pump pressure (MPP), this being another secondary kick indicator. The MPP sensor 130 uses information from the mud pump pressure output measurement device.
As regards the MPP sensor 130, the EKDS 118 is configured to process the information obtained by the MPP sensor 130 by comparing the current mud pump pressure with the recorded average and instantaneous mud pump pressures over a selected past time period, e.g. the previous 5 minutes.
As described above, the sensor arrangement 120 comprises a drill string weight (DSW) sensor 132, the DSW sensor 132 configured to detect a sudden change (in particular an increase in weight/reduction in buoyancy) in drill string weight (DSW), this being a secondary kick indicator. The DSW sensor 132 uses information from the drillstring weight indicator.
As regards the DSW sensor 132, the EKDS 118 is configured to process the information obtained by the DSW sensor 132 by comparing the current DSW with the recorded average and instantaneous drill string weights over a selected time period, e.g. the previous 5 minutes.
As described above, the sensor arrangement 120 comprises a mud pump mudflow sensor 134, the mud pump mudflow sensor 134 configured to measure the mud pump flow rate.
In the illustrated system, the mud pump mudflow sensor 134 comprises a Coriolis type flowmeter on the input to each mud pump 60 and a Coriolis type flowmeter in the flow line.
Alternatively, flowrate information may be determined by taking the input and output flowrate information feeds from the stroke counters.
As regards the mud pump mudflow sensor 134, the EKDS 118 is configured to process the information obtained by comparing the instantaneous total flowrate going into the wellbore 18 (by combining mud pump input Coriolis flowrate) with the instantaneous exit flowrate coming out of the wellbore 18.
As described above, the sensor arrangement 120 comprises a connection gas sensor 136 comprising online instrumentation configured to measure the size of each gas peak associated with each successive connection.
As regards the connection gas sensor 136, the EKDS 118 is configured to process the information obtained by the connection gas sensor 136 by comparing the size and/or position of each gas peak with that of the previous gas peak. An increasing trend, subject to pre-set criteria, could indicate a kick, and the EKDS 118 will process this information, along with information from other module sensors.
As described above, the illustrated oil and/or gas installation 10 comprises a floating platform 14 and the sensor arrangement 120 comprises or is operatively associated with one or more movement sensor 138 configured to measure movement of the platform 14 in terms of heave, sway, surge, roll, pitch and yaw.
As regards the movement sensor 138, the EKDS 118 is configured to receive and process the information from the movement sensor 138. Movement of the platform 14 is measured: i) using movement sensors; ii) using the motion reference unit (MRU) on the platform 14 and/or iii) predicted based upon expected Response Amplitude Operator (RAO) values based upon the given weather and sea states.
The resultant movement information will then be used to predict the effect of the movement of the platform 14 on the flowrate in the flow line and/or the active pit fluid level. This prediction takes into effect fluid movement lag times and the design of fluid flow lines, circulation paths, and fluid pits on the installation, and the actual ongoing operations on the installation (e.g. drilling ahead, tripping, connections) at the time. The overall predicted fluid flowrate and fluid level characteristics will then be compared with the instantaneous readings on the platform 14. Comparisons will be made in terms of absolute values at a given time, and in terms of trending values. Deviations will be compared against predicted information on a pre-set criteria basis.
As described above, the sensor arrangement 120 comprises one or more mud property sensor 140. The EKDS 118 and/or control system 12 is configured to take the automated mud measurements from an automated mud parameter measurement device 140, and run a series of algorithms looking at mud weights, gas cut percentages, salts, oil and water phases etc. then, as required, activate the initial well control protocol.

Sensor modules (individually)

Each of the EKDS 118 and the sensors 122,124,126,128,130,132,134,136,138, 140 of the sensor arrangement 120 above can be provided as a separate module implemented in software.
Figure 20 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during normal circulating activities.
As shown in Figure 20, the control system 12 is connected to a flowmeter 142 and is configured to receive real time sensor data from the sensor 142, thereby permitting the control system 12 to monitor the fluid flow rate from the wellbore 18 during circulation. The sensor 142 may be identical to the sensor 32 described above, or may take the form of another flow rate sensor. The control system 12 is also connected to a mud pump speed sensor 144 configured to measure the speed of the mud pumps 60.
The control system 12 is configured so that the base level flowrate held by control system 12 is adaptable to, typically frequent, alterations to the mud pump speed/flowrate made by the driller 26.
The incremental flowrate that triggers the initial well control protocol is inputted as a percentage increase. However, it will be understood that the incremental flowrate that triggers the initial well control protocol may alternatively be inputting as a fixed incremental amount above the instantaneous flowrate.
In the illustrated system shown in Figure 20, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a command signal 42 to controller 44 of drawworks 46 to instruct the drawworks 46 to space out; communicating a command signal 50 to controller 52 of top-drive 54 to instruct the top drive 54 to stop rotating; communicating a command signal 56 to controller 58 of mud pumps 60 to instruct the mud pumps 60 to stop pumping fluid into the wellbore 18; and communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controllers 44, 52, 58, and 64 each control components 46,54,60 and 66 respectively. It will be recognised that in other instances, for example in traditional installations, the components may be directly controlled rather than via controllers.
However, the driller 26 can pre-select whether or not the space-out is required. If de-selected, then the control system 12 defaults to the annular BOP as the BOP to close.
Figure 21 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to monitor the well when static.
As shown in Figure 21, the control system 12 is connected to a level sensor 146 configured to measure fluid level in the trip tank 106, a flow line sensor 148 configured to measure fluid flow rate, and a sensor 150 configured to measure the active pit volume.
In the illustrated system, during initial set up the driller 26 preselects, via the HMI 28, which of the sensors 146,148,150 are monitored. The decision as to which of the sensors 146, 148,150 are monitored may depend on whether the operation is being carried out in open hole or cased hole and/or how the mud flow system is lined up.
The control system 12 is configured to determine from the sensor data received from the selected sensors 146,148,150, whether a detected volume change in the trip tank and/or in the active pit, or a detected flowrate change in the flow line exceeds a preselected threshold set by the driller 26 when setting up and enabling the control system 12 at the HMI 28, this being indicative of a fluid influx condition in the wellbore 12.
On determining that the fluid flow rate does exceed the preselected threshold fluid flow rate, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102.
In the illustrated system shown in Figure 21, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a command signal 42 to controller 44 of drawworks 46 to instruct the drawworks 46 to space out; communicating a command signal 50 to controller 52 of top-drive 54 to instruct the top drive 54 to stop rotating; communicating a command signal 56 to controller 58 of mud pumps 60 to instruct the mud pumps 60 to stop pumping fluid into the wellbore 18; and communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controllers 44, 52, 58, and 64 each control components 46,54,60 and 66 respectively. It will be recognised that in other instances, for example in traditional installations, the components may be directly controlled rather than via controllers.
However, the driller 26 can pre-select whether or not the space-out is required. If de-selected, then the control system 12 defaults to the annular BOP as the BOP to close.
Figure 22 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to monitor the well when static.
As shown in Figure 22, the control system 12 is connected to a level sensor 152 configured to measure fluid level in the trip tank 106.
The control system 12 is configured to determine from the sensor data received from the sensors 152, whether a detected volume change in the trip tank exceeds a preselected threshold set by the driller 26 when setting up and enabling the control system 12 at the HMI 28, this being indicative of a fluid influx condition in the wellbore 12.
On determining that the detected volume change does exceed the preselected threshold fluid flow rate, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102.
In the illustrated system shown in Figure 22, the initial well control protocol takes the form of a well shut-in procedure involving: communicating a command signal 62 to controller 64 of blow out preventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-in the wellbore 12. The controller 64 controls the BOP 66. It will be recognised that in other instances, for example in traditional rigs, the BOP 66 may be directly controlled rather than via controller 64.
Beneficially, the control system 12 can be utilised to monitor inflow tests on liner packers or on certain lower completions.
As described above, following initiation of the initial well control protocol the control system 12 may be configured to initiate a further well control protocol in the form of a fluid pumping operation.
Figure 23 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to monitor the well during such a fluid pumping operation.
As shown in Figure 23, the control system 12 is connected to a sensor arrangement, generally denoted 154, comprising one or more flow rate sensor, casing pressure gauge, mud pump speed and pressure sensors, mud property sensor. The control system 12 also receives leak-off test data and drill bit depth data.
Beneficially, the control system 12 is configured to limit the influx size that is shut-in by turning off the mud pump(s) 60 slowly rather than with the normal turn on/off approach. This means that the loss of hydrostatic pressure due to the mud pump(s) 60 being turned off (i.e. loss of the equivalent circulating density (ECD) occurs more slowly, thus limiting the size of influx coming into the wellbore 18 and allowing pressures to equalise more quickly in the wellbore 18 after shutting in.
The control system 12 is configured to ensure that the Leak Off Test value (LOT) at the previous casing shoe will not be exceeded.
Figure 24 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 24, the control system 12 is connected to a sensor arrangement, generally denoted 156, comprising one or more flow rate sensor, casing pressure gauge, mud pump speed and pressure sensors, mud property sensor. The control system 12 also receives drill bit depth data.
Beneficially, the control system 12 addresses a problem that is relatively common in clastic formations and in High Pressure High Temperature (HPHT) wells, called Ballooning, whereby the dynamic mud weight pressure approaches the formation pressure resulting of small amounts of drilling fluid leaking into the formation. On a connection, when the mud pumps 60 are turned off and the drilling fluid pressure reduces, the leaked fluid will flow back into the wellbore 18. This can be a substantial volume over a long open hole section. It can be difficult to decipher this flow back from a true influx. The flow back will give a signature "flowrate with time" at surface.
During normal drilling operations, the control system 12 measures every signature on every connection, the control system 12 determining from the data received from the sensor arrangement 156 and optionally utilising an Artificial Intelligence algorithm, an expected signature at the next connection, the expected signature taking into account the extra amount of ballooning-prone formation now exposed.
The control system 12 compares the actual flow back signature at surface with the predicted signature, and subject to certain pre-set criteria, will action the initial well control protocol to shut in the well.
This module could be connected to the EKDS 118, or could be a standalone module.
Figure 25 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during a swabbing operation.
As shown in Figure 25, the control system 12 is connected to a sensor arrangement, generally denoted 158, comprising one or more mud property sensor. The control system 12 also receives wellbore dimension data, drill bit depth data and leak-off test data.
The control system 12 is configured to calculate the maximum pull out of hole (POOH) speed on a continuous basis.
In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals. The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to shut in the wellbore 18.
Beneficially, the control system 12 permits the POOH speed to be maximised while avoiding or at least mitigating the risk of swabbing an influx into the wellbore 18.
Figure 26 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during a run-in operation.
As shown in Figure 26, the control system 12 is connected to a sensor arrangement, generally denoted 160, comprising one or more mud property sensor. The control system 12 also receives wellbore dimension data, drill bit depth data and leak-off test data.
Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the wellbore 18. Downhole mud losses may occur if care is not taken and fracture pressure is exceeded while running in hole (RIH).
The control system 12 is configured to calculate the maximum RIH speed on a continuous basis.
In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals. The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to shut in the wellbore 18.
Figure 27 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, the control system 12 configured to detect and react to an influx during a run-in operation.
As shown in Figure 27, the control system 12 is connected to a sensor arrangement, generally denoted 162, comprising one or more mud property, flowrate, speed and pressure sensors. The control system 12 also receives wellbore dimension data, casing depth data and leak-off test data.
The control system 12 is configured to determine from the received data whether an influx is occurring. In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals. The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to shut in the wellbore 18.
Beneficially, the control system 12 detects and reacts to an influx during the running of casing or liners.
Figure 28 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 28, the control system 12 is connected to a sensor arrangement, generally denoted 164, comprising one or more mud property, flowrate, speed and pressure sensors. The control system 12 also receives wellbore dimension data, completion depth data and leak-off test data.
The control system 12 is configured to determine from the received data whether an influx is occurring.
In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to shut in the wellbore 18.
Beneficially, the control system 12 detects and reacts to an influx during the running of completions.
Figure 29 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 29, the control system 12 is connected to a sensor arrangement, generally denoted 166, comprising one or more mud property, flowrate, speed and pressure sensors. The control system 12 also receives wellbore dimension data, casing depth data and leak-off test data.
The control system 12 is configured to determine from the received data whether an influx is occurring.
In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to shut in the wellbore 18.
Beneficially, the control system 12 detects and reacts to an influx during the cementing of casing or liner.
Figure 30 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 30, the control system 12 is connected to a sensor arrangement, generally denoted 168, comprising one or more mud property, flowrate, speed and pressure sensors. The control system 12 also receives flowrate (with or without riser) data, and wind direction data.
The control system 12 is configured to determine from the received data whether an influx is occurring.
In the event an influx is detected, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102 to divert the flow from the well to a safe area.
The control system 12 is designed for drilling the upper sections of the wellbore 18 which are drilled without the BOP, and where it would not have been safe to shut in the well due to the risk of casing shoe fracture. If the drilling encounters a pocket of shallow gas, the control system 12 will detect the high mud flowrate return out of the well annulus. The methodology to detect the flowrate will be determined by the drilling mode; i.e. whether or not a riser is in place.
The control system 12 will relay an alarm signal to the driller 26 via the HMI 28.
The control system will continually pre-assess wind direction at all times, and following the alarm signal, would then send a signal to open the downwind overboard line valve. A signal would then be sent to close the diverter, and thus divert the flow away from the installation 10. The system will then initiate a shallow gas protocol, including for example automated pumping of higher density drilling fluid.
Figure 31 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 31, the control system 12 is connected to a sensor arrangement, generally denoted 170, comprising trip tank pump and level sensors.
For installations without a riser gas handling system, once BOPs are activated by the control system 12, the control system 12 will automatically switch on the Trip Tank (TT) pump and switch the surface valves to monitor the riser contents.
The control system 12 will monitor the trip tank 106. If the trip tank 106 level increases, over a period of time, the BOP has either not closed properly, or there is migrating gas in the riser, or both.
In either case, the control system 12 will close another BOP and will consider directing the flow to the poor boy degasser (PBD) or operate the diverter system (having also assessed wind direction).
The consideration of routing will take account of the capacity of the PBD both from the vessel throughput aspect and from a U-tube aspect.
If either of these are exceeded, then the control system 12 will instruct to divert the flow through the diverter.
Figure 32 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 32, the control system 12 is connected to a sensor arrangement, generally denoted 170, comprising trip tank pump and level sensors.
For installations with a riser gas handling system, once the BOPs are activated by the control system 12, the control system 12 will automatically switch on the Trip Tank (TT) pump and switch the surface valves to monitor the riser contents.
The control system 12 will monitor the trip tank.
If the trip tank level increases, over a period of time, the BOP has either not closed properly, or there is migrating gas in the riser, or both.
In either case, the control system 12 will initiate an increase in closing pressure on the BOP and/or close another BOP and/or automatically function the riser gas annular simultaneously.
Figure 33 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 33, the control system 12 is connected to BOP sensors 174.
The control system 12 is configured to detect the pressure below a closed BOP, and then execute an interlock to prevent any party from opening the BOP.
Figure 34 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 34, the control system 12 is connected to a library, generally denoted 176, of operator and/or drilling contractor well control procedures for tripping, connections drilling etc.
Beneficially, the link to the library 176 permits the sequencing of the control system 12 operations to be tailored to ta given operator and/or drilling contractor's well control procedures.
Figure 35 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 35, the control system 12 is connected to a multi-rig sensor arrangement, generally denoted 178.
The control system 12 is configured to determine, using the data from the multi-rig sensor arrangement 178, the particular phase of well construction at a given time, and then automatically ensure that the appropriate control system 12 module is in operation for that phase.
Beneficially, this permits the control system 12 to be on at all times.
Figure 36 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 36, the control system 12 is configured to receive tidal data, selected space-out position data and time linking data, generally denoted 180.
The control system 12 is configured, based on the data 180, to automatically adjust the space-out position in response to changes in tide and select another BOP such as the annular.
In use, the driller 26 would select the space out positions on the control system 12 via the HMI 28 at initial set-up. Those positions would be logged as would be the time at which they were logged. Where certain changes of tide make a previously selected space-out position unusable, the control system 12 relays an alter signal to the drill 26 requesting a updated set of space-out positions.
Beneficially, the system is particularly adapted for use on a floating rig that is subject to a large tidal range.
Figure 37 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 37, the control system 12 is configured to receive BOP dimension data, tidal data, space-out position data and BOP preference information, generally denoted 182.
The control system 12 is configured, based on the data 182, to automatically assess the position of the tool joint in relation to the exact BOP configuration on the installation, and to then auto-select which is the best BOP to close at any given time.
Figure 38 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 38, the control system 12 is configured to receive wireline depth meter data, rig floor depth data and safety distance data, generally denoted 184.
In use, the control system 12 is configured, based on the data 184, to relay an alert signal to the driller 26, via the HMI 28, and/or wireline supervisor via a suitable data link, when pulling out of hole indicating that the tooling is near/at surface or is becoming held up and/or when running in hole that is close to target depth, or if it become held up.
Beneficially, the system provides an automated warning for control of slickline, wireline, coil tubing etc.
Figure 39 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, during coiled tubing operations.
As shown in Figure 39, the control system 12 is connected to a flowrate sensor 186, the sensor 186 associated with the coiled tubing system of the installation 10.
In the event an influx is detected during coiled tubing operations, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 also initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102, in this instance including the BOP operatively associated with the coiled tubing, to shut in the wellbore 18.
Figure 40 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10, during wireline operations.
As shown in Figure 40, the control system 12 is connected to a flowrate sensor 188, the sensor 188 associated with the wireline system of the installation 10.
In the event an influx is detected during wireline operations, the control system 12 is configured to generate one or more output signal in the form of an alarm signal on the HMI 28 in the control station 22. In the illustrated system, the alarm signal comprises audible and visual alarm signals.
The control system 12 also initiates an initial well control protocol by outputting a number of command signals to the installation and well control equipment 102, in this instance including the BOP operatively associated with the wireline, to shut in the wellbore 18.
Figure 41 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 41, the control system 12 is configured to receive GPS and/or other positioning system data and vessel propulsion control data, generally denoted 190. The control system 12 is configured, based on the received data 190, to output a number of command signals to the installation and well control equipment 102 to close blind/shear, disconnect the Lower Marine Riser Package (LMRP), and perform installation drive off.
Figure 42 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 42, the control system 12 is configured to receive GPS and/or other positioning system data and vessel propulsion control data, and gas sensor data, generally denoted 192.
The control system 12 is configured, based on the received data 192, to output a number of command signals to the installation and well control equipment 102 to close the blind/shear, disconnect the Lower Marine Riser Package (LMRP), and drive off.
Figure 43 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 43, the control system 12 is configured to receive GPS and/or other positioning system data and vessel propulsion control data, and excursion limit pre-integrity failure data, generally denoted 194.
The control system 12 is configured, based on the received data 194, to output a number of command signals to the installation and well control equipment 102 to close the blind/shear, disconnect the Lower Marine Riser Package (LMRP), and perform a drive off.
Beneficially, the control system 12 is configured to shut-in the well where e.g. an excursion of the installation (e.g. due to a failed Dynamic Positioning system) reaches a point where the integrity of the riser/BOP system would otherwise be compromised.
Figure 44 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 44, the control system 12 is connected to a BOP sensor arrangement, generally denoted 196, the BOP sensor arrangement 196 configured to receive data from the BOP 66.
The control system 12 is configured, based on the data 196, to automatically and continually perform BOP fault finding and, in the event of an influx, automatically initiate a required change (e.g. Pod Change or next lower BOP activation) to make the BOP 66 function.
Figure 45 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 45, the control system 12 is connected to a sensor arrangement, generally denoted 198, configured to receive data from all well control equipment on the installation 10.
The control system 12 is configured to monitor the status/health of key well control equipment (BOP, mud pumps, choke) and the associated equipment instrumentation on the HMI 28, and relay an audible alarm and/or visual signal in the event of a discrepancy in performance beyond a selected threshold.
Figure 46 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 46, the control system 12 is connected to a sensor arrangement, generally denoted 200, configured to receive flowmeter data, trip tank sensor data, and active pit volume sensor data.
The control system 12 is configured to monitor the wellbore 18 during a plug drill out operation during well decommissioning.
This is particularly important where previously-installed downhole barriers may be of questionable nature, or where insufficient mud weight cannot be properly achieved prior to drilling out a plug with a potential high pressure below.
Figure 47 of the accompanying drawings shows an alternative system topology of the control system 12, illustrating the integration of the control system 12 with components of the oil and/or gas installation 10.
As shown in Figure 47, the control system 12 is connected to a sensor arrangement, generally denoted 202, configured to receive flowmeter data, trip tank sensor data, and active pit volume sensor data.
The control system 12 is configured to output command signals to a mechanical arm, to be used for example to automatically install, torque up, and close a full opening safety valve (FOSV).
Each of the system topologies described above with reference to Figures 12 to 47 may be implemented within the control software of the control system 12 or may be a standalone module.
Various modifications can be made without departing from the scope of the claimed invention.
For example, the control system 12 may comprise or may be operatively associated with a software module that can determine the health of a flow meter. The module, flowmeter paddle, and even the health of a Coriolis meter, or any other flow meter. For example, the control system may be configured to determine the health of a flow meter where, for example: there are no fluctuations in flow rate detected over a specified period; the flow meter outputs a minimum reading when mud pumps are operating well above that level; the flow meter outputs a maximum reading when the mud pumps are operating well below that level; and/or the flow meter outputs a significantly different reading to previously observed recent readings.
The control system 12 may comprise or may be operatively associated with a software module that can record data critical to the decision to shut-in the well and will record all relevant instrumentation, actions and timing throughout the process of automatically safely shutting in the well to provide historical record for future analysis of the effectiveness of the system responses, and any human interventions.
The control system 12 may pass data in real time over a secure internet link enabling management to view status of control system at any time. This will also provide all data critical to the decision to shut-in the well ensuring a safe remote record all relevant instrumentation, actions and timing throughout the process of automatically safely shutting in the well to provide historical record for future (and immediate) analysis of the effectiveness of the system responses, and any human interventions.
The control system 12 program may be accessible over a secure internet link enabling technical support for fault finding diagnostics, configuration & upgrades to be affected from Safe Influx office or other remote location. This will provide enhanced efficiency of commissioning and support to ensure maximum up-time for the control system 12 equipment, and reduce the need for high skilled technical support in remote locations.
The control system 12 may comprise or may be operatively associated with a biometric security software module. The biometric security module is used where pre-operation or post-operation authorisation is required (e.g. opening of a closed BOP). The biometric security module requires e.g. thumb-print, or face recognition identification of higher authority (e.g. a toolpusher), on the HMI 28.
The control system 12 may be configured to allow the driller 26 the ability to shut-in the wellbore 18 without having to switch the control system 12 off, e.g. in an emergency situation. There would be a button on the HMI 28, that would enable a one or two touch action to perform the full shut in sequence including space out, stop drilling equipment and close the BOP 66.
The scope of protection of the current invention is defined by the appended claims.

Claims

An automated system for use in well control (12), the system (12) comprising:
a controller (72) configured to receive an input signal indicative of a fluid flow rate or fluid volumetric rate from a wellbore (18), the controller (72) configured to determine from said input signal whether the fluid flow rate or fluid volumetric rate exceeds a preselected threshold indicative of a fluid influx condition in the wellbore (18) system,

wherein, on determining that said fluid flow rate or fluid volumetric rate exceeds said preselected threshold, the controller (72) is configured to automatically output one or more command signals (42, 50, 56, 62) initiating an initial well control protocol,

wherein the initial well control protocol comprises a well shut-in protocol, the initial well control protocol comprising one or more preselected well control operations actioned based on preselected criteria without requiring an operative to decide and/or action said required initial well control operations, and

wherein the system (12) is configured for coupling to, to communicate with, or is operatively associated with components of an oil and/or gas installation, the system configured for coupling to, to communicate with or being operatively associated with a drawworks (46) of the oil and/or gas installation (10), the initial well control protocol comprising a command signal (42) to the drawworks (46) to automatically raise the drill string (48) off the bottom of the wellbore (18), characterised by a drawworks (46) space out configuration comprising calibrated set points for movement of the drawworks (46) set during set up of the system (12).
The system (12) of claim 1, wherein the system (12) is configured to initiate the initial well control protocol based on a single parameter in the form of said fluid flow rate or fluid volumetric rate from the wellbore (18).
The system (12) of claim 1 or 2, wherein the initial well control protocol comprises a plurality of well control operations.
The system (12) of claim 1, wherein at least one of:
the system (12) is configured for coupling to, to communicate with or may be operatively associated with a top drive (54) of the installation (10), the initial well control protocol comprising a command signal (50) to the top drive (54) to stop rotation of the top drive (54);

the system (12) is configured for coupling to, to communicate with or may be operatively associated with one or more mud pumps (60) of the installation, the initial well control protocol comprising a command signal (56) to the one or more mud pumps (60) to stop the one or more mud pumps (60), or a preselected subset of the one or more mud pumps (60);

the system (12) is configured for coupling to, to communicate with or may be operatively associated with a blow out preventer (BOP) (66) of the installation (10), the initial well control protocol comprising a command signal (62) to the BOP (66) to close the BOP (66).
The system (12) of any preceding claim, wherein the system (12) is configured to monitor the fluid flow rate over a preset test period.
The system (12) of any preceding claim, wherein the system (12) is configured to action a further well control protocol, and wherein the further well control protocol comprises at least one of:
an influx circulation operation;

a well kill operation;

a fluid pumping operation.
The system of any preceding claim, wherein the system comprises, is coupled to or communicates with, a sensor arrangement for detecting the fluid flow rate or fluid volumetric rate from the wellbore.
The system (12) of any preceding claim, comprising a communication arrangement configured to communicate said one or more command signals to a well control infrastructure.
The system (12) of any preceding claim, wherein at least one of:
the system (12) comprises, is configured for connection to or is operatively associated with a managed pressure drilling system (114) of the installation (10);

the system (12) comprises an early kick detection system (116, 118);

the system (12) is configured for connection to and/or operatively associated with an early kick detection system (118) of the oil and/or gas installation (10).
An offshore or onshore oil and/or gas installation (10) comprising the automated system (12) for use in well control of any preceding claim.
An automated method for use in well control, using the automated system (12) of any one of claims 1 to 9, the method comprising:
receiving the signal indicative of the fluid flow rate or fluid volumetric rate from the wellbore (18); and

determining from said signal whether the fluid flow rate or fluid volumetric rate exceeds the preselected threshold,

wherein, on determining that said received fluid flow rate or fluid volumetric rate exceeds said preselected threshold, the method comprises automatically initiating an initial well control operation,

wherein the initial well control protocol comprises the well shut-in protocol, the initial well control protocol comprising one or more preselected well control operations actioned based on preselected criteria without requiring an operative to decide and/or action said required initial well control operations,

wherein the system (12) is configured for coupling to, to communicate with, or is operatively associated with, components of an oil and/or gas installation, the system configured for coupling to, to communicate with or being operatively associated with a drawworks (46) of the oil and/or gas installation (10), the initial well control protocol comprising the command signal (42) to the drawworks (46) to automatically raise the drill string (48) off the bottom of the wellbore (18), characterised by the drawworks (46) space out configuration comprising calibrated set points for movement of the drawworks (46) set during set up of the system (12).
The method of claim 11, wherein the system (12) initiates the initial well control protocol based on a single parameter in the form of said fluid flow rate or fluid volumetric rate from the wellbore (18).
The method of claim 11, wherein the controller (72) additionally receives one or more input signals in the form of: fluid volume data; fluid volumetric displacement data; pressure data; depth data; drillstring weight data; gas detection data; data indicative of the gas percentage in the drilling fluid; drilling fluid property data; equipment speed data; equipment condition data; movement data regarding the installation; environmental data; tidal data; GPS and/or other positioning system data; managed pressure drilling (MPD) system (114) data; early kick detection system (EKDS) (116, 118) data; a manual confirmation input; well control procedure data; and/or leak-off test data.
A computer program product comprising instructions to cause the system of claims 1-9 to execute the method of claims 11-13.
A computer-readable carrier medium having stored thereon the computer program product of claim 14.