Patent Description:
During certain drilling operations, MPD may be used to maintain well control by managing wellbore pressure within a safe pressure gradient bounded by the pore pressure and the fracture pressure, where the collapse pressure is sometimes used in place of the pore pressure if it is higher than the pore pressure. In this context, well control generally refers to techniques used to manage the hydrostatic and formation pressure to prevent the unintended influx of unknown formation fluids into the well system. If the pressure in the annulus falls below the pore pressure, unknown formation fluids may flow into the wellbore and well control may be lost. The unintentional influx of unknown formation fluids into the wellbore is commonly referred to as a kick. Kicks are inherently dangerous because the unknown formation fluids may contain explosive gas that increases the risk of a dangerous blowout. Similarly, if the pressure in the annulus rises above the fracture pressure, the formation may hydraulically fracture or crack such that drilling fluids are lost to the formation and, if the fluid level within the wellbore decreases to the extent that wellbore pressure falls below the pore pressure, then a kick may be taken and well control may be lost. As such, standard industry practices seek to maintain well control during drilling and other operations by carefully navigating the safe pressure gradient. However, geological uncertainties, imperfect information, and constantly changing conditions sometimes give rise to unexpected contingencies and it is critically important to have the capability to take appropriate actions when a kick is taken. As such, once a kick is taken, if the volume of the kick and the additional pressure required to kill the well exceeds a predetermined operational limit, MPD operations are stopped and well control operations are manually performed to circulate out the unknown formation fluids in the well system to restore well control such that drilling operations may safely resume.

<CIT> describes a well pressure control method that includes regulating pressure in a wellbore by operating a suction pump which draws fluid from an annulus formed between a drill string and the wellbore, the fluid entering the suction pump proximate the earth's surface. Another well pressure control method is described that includes regulating pressure in a wellbore by operating a suction pump which applies suction pressure to an annulus formed between a drill string and the wellbore.

<CIT> describes methods and systems for controlled delivery of unknown fluids that safely and for efficiently removing entrained gas from unknown fluids in the wellbore and/or marine riser. A control system automatically controls one or more choke manifold(s), and optionally the flow rate of one or more mud pump(s), to maximize the safe flow rate of returning unknown fluids to one or more instrumented mud-gas separator(s) without overloading. The control system may receive the state of the one or more instrumented mud-gas separator(s) to manipulate the choke manifold(s), and optionally the one or more mud pump(s) to maximize the safe flow rate of return fluids and expedite the removal of gases.

<CIT> describes a system for drilling a bore hole into an earth formation, comprising: - a drill string reaching into the bore hole leaving a drilling fluid return passage between the drill string and the bore hole inside wall; a drilling fluid discharge conduit in fluid communication with the return passage; pump means for pumping a drilling fluid through the drill string to the discharge conduit via the return passage; back pressure means for controlling the drilling fluid back pressure; fluid injection means comprising a supply passage fluidly connecting an injection fluid supply with the return passage and further comprising an injection fluid pressure sensor arranged to measure injection fluid pressure in the supply passage; and back pressure control means for controlling the back pressure means, whereby the control means is arranged to regulate the back pressure.

<CIT> describes controlled pressure drilling of a borehole with a drilling system that detects events and identifies the events as being one of a gas-at-surface event, a kick event, a high-pressure low-volume depletion event, and a gas expansion event. Parameters including flow-in, flow-out, density, and standpipe pressure are monitored. A volume increase is detected between the flow-in and flow-out, and an initiation point of the detected volume increase is identified. At this point, an event from the initiation point is identified based on the monitored parameters from the initiation point. To identify a kick event, for example, the standpipe pressure is determined to have increased from the initiation point without the density decreasing since the initiation point, and a cumulative volume value from the initiation point is determined to be above a first threshold. In response to the identified event, an action is initiated in the drilling system.

According to one aspect of one or more embodiments of the present invention, a method of safe dynamic handover between managed pressure drilling and well control includes setting a pressure setpoint of an MPD choke manifold to a surface backpressure setpoint and setting a pressure setpoint of an automated well control choke manifold to a sensed pressure taken from below a blowout preventer or a kill line pressure of the blowout preventer. A pressure imbalance is created by setting the pressure setpoint of the MPD choke manifold above the pressure setpoint of the automated well control choke manifold by a predetermined amount. The pressure imbalance automatically causes an MPD control system to close the MPD choke manifold as the well control control system opens the automated well control choke manifold during handovers between managed pressure drilling and well control operations to maintain the wellbore in a dynamic fluid state.

Other aspects of the present invention will be apparent from the following description and claims.

One or more embodiments of the present invention are described in detail with reference to the accompanying figures. For consistency, like elements in the various figures are denoted by like reference numerals. In the following detailed description of the present invention, specific details are set forth in order to provide a thorough understanding of the present invention. In other instances, well-known features to one of ordinary skill in the art are not described to avoid obscuring the description of the present invention. For purposes of clarity, for wellbore components described herein, top or upper refer to a portion or side that is closer, whether directly or in reference to another component, to the surface above the wellbore and bottom or lower refer to a portion or side that is closer, whether directly or in reference to another component, to the bottom of the wellbore.

<FIG> shows a conventional closed-loop hydraulic drilling system <NUM> for MPD and conventional well control operations. For the purposes of illustration, a drilling system <NUM> for offshore drilling operations is shown. While offshore applications require additional components such as, for example, a marine riser system, to facilitate drilling a subsea wellbore, one of ordinary skill in the art will recognize that onshore, or land-based, applications are substantially similar in configuration and function with respect to those components necessary for MPD and conventional well control manifold. The method further includes verifying that the sensed pressure or kill line pressure increases until the automated well control choke manifold opens enough such that the blowout preventer pressure or kill line pressure remains constant, closing an annular of the blowout preventer after the MPD choke manifold is closed, and diverting unknown formation fluids from the choke line of the blowout preventer to the automated well control choke manifold for delivery to a mud-gas-separator. The wellbore remains fluidly dynamic due to continuous injection of drilling fluids.

According to one aspect of one or more embodiments of the present invention, a system for safe dynamic handover between managed pressure drilling and well control includes an annular sealing system capable of controllably sealing an annulus surrounding a drillstring forming an MPD annular seal, a blowout preventer capable of controllably sealing an annulus surrounding the drillstring forming a well control annular seal, an MPD choke manifold comprising a plurality of choke valves with at least one choke valve in fluid communication with a flow line capable of diverting returning fluids from or below the MPD annular seal to a fluids processing system, an automated well control choke manifold comprising a plurality of choke valves with at least one choke valve in fluid communication with a choke line capable of diverting returning fluids from or below the well control annular seal to a mud-gas separator, and a well control control system that automates the settings of the automated well control choke manifold during handovers between managed pressure drilling and well control operations to maintain the wellbore in a dynamic fluid state.

<FIG> shows a conventional closed-loop hydraulic drilling system <NUM> for MPD and conventional well control operations. For the purposes of illustration, a drilling system <NUM> for offshore drilling operations is shown. While offshore applications require additional components such as, for example, a marine riser system, to facilitate drilling a subsea wellbore, one of ordinary skill in the art will recognize that onshore, or land-based, applications are substantially similar in configuration and function with respect to those components necessary for MPD and conventional well control operations. As such, the description that follows applies with equal force to land-based drilling systems that include MPD and conventional well control capabilities.

Drilling system <NUM> includes a drilling rig <NUM>, in this instance, a semi-submersible-type of drilling rig disposed in a body of water <NUM>, that includes various equipment configured to drill a subsea wellbore <NUM> below the seafloor <NUM> to recover hydrocarbons disposed therein. One of ordinary skill in the art will appreciate that the type or kind of drilling rig may vary based on an application. In deepwater applications, the seafloor <NUM> may be more than <NUM> metre (<NUM>,<NUM> feet) below the water's surface <NUM>. In ultra-deepwater applications, the seafloor <NUM> may be <NUM>,<NUM> metre (<NUM>,<NUM> feet) or more below the water's surface <NUM>. Drilling system <NUM> may include an MPD system (e.g., annular sealing system <NUM>, annular closing system <NUM>, and return flow spool <NUM>), a marine riser system <NUM>, and a blowout preventer ("BOP") <NUM>, in the offshore example depicted, a subsea BOP ("SSBOP"). One of ordinary skill in the art will recognize that drilling system <NUM> may include other components such as, for example, a diverter of last resort (not shown), a ball joint (not shown), and a telescopic joint (not shown) that are typically disposed above the MPD system, that are not shown or necessary for understanding the discussion that follows.

For high-specification drilling systems <NUM>, the MPD system typically includes an annular sealing system <NUM>, an annular closing system <NUM> disposed below annular sealing system <NUM>, and a return flow spool <NUM> disposed below annular closing system <NUM>. Annular sealing system <NUM> controllably seals the annulus <NUM> surrounding drillstring <NUM> such that it is encapsulated. Annular sealing system <NUM> may be a Rotating Control Device ("RCD"), an Active Control Device ("ACD"), or any other type or kind of system capable of creating an annular seal such that wellbore pressure may be controlled by the application of surface backpressure. Annular closing system <NUM> is a redundant system for maintaining the annular seal when annular closing system <NUM>, or components thereof, are being installed, serviced, or replaced. Return flow spool <NUM> diverts returning fluids from or below the annular seal to MPD choke manifold <NUM> that directs the returning fluids to the fluids processing systems (e.g., MGS <NUM> or shale shakers <NUM>) for recycling and reuse. Return flow spool <NUM> is disposed above, and in fluid communication with, the lower portion of marine riser system <NUM>. One of ordinary skill in the art will recognize that, in lower-specification drilling systems, one or more of the above-noted components may be combined or excluded, but all MPD systems require at least an annular closing system disposed above the BOP <NUM> and means to controllably divert returning fluids from or below the annular seal.

The lower portion of marine riser system <NUM> is disposed above, and in fluid communication with, SSBOP <NUM> disposed on or near seafloor <NUM>. SSBOP <NUM> may include a lower marine riser package ("LMRP") connector (not labeled), an upper annular preventer <NUM>, a lower annular preventer <NUM>, one or more blind shear rams <NUM>, one or more casing shear rams <NUM>, an upper variable bore ram <NUM>, a lower variable bore ram <NUM>, and a wellhead connector (not labeled). The kill line <NUM> fluidly connects one or more mud pumps (e.g., <NUM>) disposed on the surface to the SSBOP <NUM> for injecting fluids below the annular of SSBOP <NUM> during conventional well control operations described in more detail herein. The choke line <NUM> fluidly connects an outlet of SSBOP <NUM> below the annular to a well control choke manifold <NUM> disposed on the surface to take fluid returns through the choke line <NUM> during conventional well control operations, also described in more detail herein. SSBOP <NUM> is disposed above, and in fluid communication with, a wellhead (not independently illustrated) that is disposed above, and in fluid communication with, a wellbore <NUM> being drilled. A central lumen extends through the conventional MPD system (e.g., annular sealing system <NUM>, annular closing system <NUM>, and return flow spool <NUM>), marine riser system <NUM>, SSBOP <NUM>, wellhead (not independently shown), and into wellbore <NUM> to facilitate drilling and other operations. Drillstring <NUM> may be disposed through the central lumen and include, on a distal end, a bottomhole assembly or drill bit <NUM> configured to drill wellbore <NUM>.

During MPD operations, such as drilling ahead, one or more mud pumps <NUM> controllably pump drilling fluids (not shown) from mud tank <NUM> downhole through an interior passageway of drillstring <NUM>. The returning fluids (not shown) return through annulus <NUM> surrounding drillstring <NUM> and are controllably diverted by return flow spool <NUM> via flow line <NUM> to one or more choke valves (not independently illustrated) of MPD choke manifold <NUM>. The one or more choke valves of MPD choke manifold <NUM> controllably flow via flow line <NUM> to flow meter <NUM> and flow meter <NUM> flows via flow line <NUM> to one or more fluids processing systems including, for example, MGS <NUM> and/or shale shakers <NUM> for processing prior to returning the processed fluids (not shown) to mud tank <NUM> for reuse. One or more pressure sensors (not shown) are disposed in the fluid path at different locations to measure pressure of the returning fluids (not shown).

MPD control system <NUM> may receive pressure sensor data and flow meter <NUM> data in approximate or near real-time. One of ordinary skill in the art will recognize that approximate or near real-time means very nearly when measured, delayed by measurement, calculation, and/or transmission only, but typically on the order of magnitude of mere fractions of a second or seconds. MPD control system <NUM> may command one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> to a desired choke position and/or command the flow rate of mud pumps <NUM>, to achieve a desired pressure. The pressure tight seal on the annulus provided by annular sealing system <NUM> allows for the precise control of wellbore pressure by manipulation of the choke position of one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> and the corresponding application of surface backpressure. The choke position of one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> corresponds to an amount, typically represented as a percentage, that one or more choke valves (not independently illustrated), or MPD choke manifold <NUM> itself, is open and capable of flowing. If the choke operator wishes to increase wellbore pressure, the choke position of one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> may be reduced to further restrict fluid flow and apply additional surface backpressure. Similarly, if the choke operator wishes to decrease wellbore pressure, the choke position of one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> may be increased to increase fluid flow and reduce the amount of applied surface backpressure. As such, MPD systems typically manage wellbore pressure by manipulating the choke position of one or more choke valves (not independently illustrated) of MPD choke manifold <NUM> and/or the flow rate of mud pumps <NUM> that inject fluids downhole, based on, at least, pressure sensor data.

In certain applications, a hydraulic model (not independently shown) may be used during MPD and other operations to calculate wellbore pressure, or equivalent circulating density ("ECD"), in approximate or near real-time based on information about the wellbore, equipment, and sensor data including, but not limited to, one or more of well depth, casing depth, internal diameter, inclination angles, water depth, riser diameter, drillstring configuration, geothermal gradient, hydrothermal gradient, real-time drilling parameters such as flow rate, rotation rate, block position (or bit depth), block speed, and mud properties, and surface-based or downhole sensor data that provides actual measurements of various parameters in approximate or near real-time. ECD refers to the effective density exerted by a circulating fluid against the formation that takes into account the pressure drop in the annulus above the point being considered. In this way, ECD may be thought of as the wellbore pressure expressed in terms of mud weight equivalent at a given depth. During drilling operations, the use of ECD is typically preferred over the use of wellbore pressure as it is more descriptive to those operating the rig, however, one or ordinary skill in the art will recognize that they are alternative representations of the same concept and may be used interchangeably with simple conversion. The MPD system may be operated in one of several modes of operation. During drilling and other operations, the MPD system may be used to perform what is referred to as surface backpressure control. In this mode of operation, the choke position of one or more choke valves of the MPD choke manifold <NUM> may be adjusted, either directly or under automation, to achieve a desired pressure at the MPD choke manifold <NUM> on the surface. However, the MPD system may also be used to manage downhole pressure. In this mode of operation, the hydraulic model may be used to calculate the pressure and the choke programmable logic device ("PLC") of the MPD control system <NUM> may determine the choke position of one or more choke valves of the MPD choke manifold <NUM> to achieve the calculated pressure downhole at depth, taking into account the particulars of the wellbore, equipment, and sensor data.

As noted above, during conventional MPD operations, drilling fluids are pumped through the interior passage of drillstring <NUM>, out of drill bit <NUM>, and then return through annulus <NUM>. The drilling fluids cool and lubricate the drill bit <NUM>, flush cuttings from the bottom of the hole, and counterbalance the formation pressure. The returning fluids are typically processed on the surface and the drilling fluids are separated and recycled for reuse downhole. While the wellbore pressure is effectively managed, under normal operating conditions, the flow out of returning fluids is substantially equal to the flow in of drilling fluids. As such, there is no substantive loss of drilling fluids to the formation and there is no substantive influx of unknown formation fluids into the wellbore. However, due to geological uncertainties, kicks are sometimes taken while drilling ahead. Kicks may be identified by, for example, an imbalance where flow out exceeds flow in for a period of time. When a kick is detected while drilling ahead, the MPD system is the first equipment used to respond. Upon detection of the kick, the MPD control system will start closing the MPD choke manifold <NUM> to apply further pressure on the well in order to suppress the kicking formation, sometimes referred to as killing the well. Once the wellbore pressure equals or exceeds the pore pressure, the flow out should return to expected levels. When flow out is substantially equal to flow in, a determination is made as to whether the volume of formation fluids taken during the kick requires well control operations. The driller will typically place the total kick volume with the additional pressure required to balance the formation in an operational matrix that determines whether the influx may be circulated out of the well through the MPD system. If the total kick volume exceeds the operational matrix, regulations, technical limitations of equipment, or agreed limits on what may be circulated out through the MPD system, then a decision is made to invoke manually-performed well control operations to circulate the kick out through the well control choke manifold <NUM> under a closed BOP <NUM>. It is important to recognize that MPD operations are sometimes conducted under automation and the determination to invoke well control operations requires the intervention of a human operator to make the decision to invoke, as well as manually perform, the following well control operations.

Once the decision is made to circulate the kick out via manually-performed well control operations, a first transition, or handover, is performed from MPD operations to conventional well control operations. The mud pumps <NUM> are shut down, rotation of the drillstring <NUM> is stopped, and the MPD choke manifold <NUM> is closed to maintain bottomhole pressure, resulting in the first static condition with respect to fluids within the wellbore <NUM>, meaning there is no circulation of fluids therein during this period of time. This is the first of two times that the wellbore goes static during handovers. Then, the BOP <NUM> is closed, via annular <NUM> or <NUM> or ram <NUM>, <NUM>, <NUM>, or <NUM>, and the choke line <NUM> is pressured down against the Hydraulic Controlled Remote ("HCR") valve (not shown) of BOP <NUM>, which is then opened, permitting returns to be taken through the choke line <NUM>. The mud pumps <NUM> are then turned back on and ramped up to start injecting drilling fluids down drillstring <NUM>, while manually adjusting the choke position of the well control choke manifold <NUM> in an attempt to regulate downhole pressure while taking returns via choke line <NUM>, based on pressure measurements taken at the well control choke manifold <NUM> or at the BOP <NUM>. The regulation of downhole pressure is manually controlled, typically by a choke operator that adjusts the choke position of the well control choke manifold <NUM> until the kill line <NUM> pressure, as measured on the surface, or BOP <NUM> pressure, as measured underwater by a sensor (not shown), is constant. One of ordinary skill in the art will appreciate that measuring the BOP <NUM> pressure is preferred, however, in systems that do not have such a sensor (not shown), the kill line <NUM> pressure may be used. The choke operator rotates a physical wheel or, on electronically controlled choke manifolds, manually presses a position up or down button on an industrial control system (not shown) while monitoring the kill line <NUM> or BOP <NUM> pressure to achieve stability.

After establishing the desired mud pump <NUM> speed, the choke operator manipulates the choke position of one or more valves of the well control choke manifold <NUM>, keeping the standpipe pressure constant, until the kick is circulated out of the wellbore <NUM>. The density of returning fluids is continuously measured at the surface. Whenever the density of returning fluids is substantially equal to the density of injected fluids (i.e., meaning there is no explosive gases remaining in the returning fluids), the kick volume has been circulated out of the wellbore <NUM> and the well control operation is complete. At this point, a second handover is performed, this time from well control operations to MPD, so that the MPD system may resume drilling ahead. The mud pumps <NUM> are shut down once again and the well control choke manifold <NUM> is closed as the mud pumps <NUM> shut down such that, when the mud pumps <NUM> are fully stopped the well control choke manifold <NUM> is fully closed. This represents the second static condition with respect to fluids within the wellbore <NUM>, as circulation has stopped. Downhole pressure is maintained at a constant pressure at the kill line <NUM> or below the BOP <NUM> seal while the mud pumps <NUM> are ramping down. The marine riser <NUM> is then pressurized to equalize pressure across the BOP <NUM>, then the BOP <NUM> is opened. The HCR valve (not independently illustrated) is closed after the mud pumps <NUM> have stopped or after pressure is equalized across the BOP <NUM>, at the driller's discretion. Circulation is then reestablished by starting the mud pumps <NUM>, injecting drilling fluids down drillstring <NUM>, and taking returns via flow line <NUM> from return flow spool <NUM>. The MPD choke manifold <NUM> is then re-engaged to manage wellbore <NUM> pressure during drilling operations, typically under automation.

While MPD operations are usually automated, meaning, the hydraulic model is used to calculate the desired pressure and the MPD control system <NUM> determines the appropriate choke position of one or more choke valves of the MPD choke manifold <NUM> to achieve the desired pressure, conventional well control operations are performed manually, including the decision to invoke well control operations. During the first handover, from MPD to conventional well control operations, the mud pumps <NUM> are stopped and the wellbore <NUM> goes fluidly static below the BOP <NUM> for the first time. During the substantive portion of well control operations, the kick volume is manually circulated out of the wellbore <NUM>. Again, during the second handover, from conventional well control operations to MPD, the mud pumps <NUM> are stopped and the wellbore <NUM> goes fluidly static for the second time. In both instances, the fluidly static state of the wellbore gives rise to the formation of gels. When the fluids within the wellbore <NUM> go static, there are solids in the mixture of wellbore fluids and those solids react creating what is referred to in the industry as gels. Gels are undesirable as they tend to create pressure spikes during the start-up of the mud pumps <NUM>, in addition to creating difficulty in transmitting pressure through the well system as is required for precise pressure management inside the wellbore <NUM>. So, every time circulation stops and the wellbore <NUM> goes static, gels are formed and additional force must be applied to break the gels reaction and reduce friction.

Accordingly, in one or more embodiments of the present invention, safe dynamic handover between MPD and well control operations provides, for the very first time, the ability to automate MPD, well control operations, and transitions therebetween, that maintain the wellbore in a dynamic fluid state at all times that increases the reliability, efficiency, and safety of operations. In the event of a kick, a safe handover from MPD to well control operations is made without ever going static with respect to fluids within the wellbore, unknown formation fluids within the wellbore are circulated out of the wellbore in a safe and efficient manner, and a safe handover from well control operations to MPD is also made without ever going static with respect to fluids within the wellbore. Advantageously, since the wellbore remains dynamic, even during handovers, the formation of gels is prevented, thereby preventing pressure spikes during the start-up of the mud pumps. In addition, pressure transmission is improved, thereby allowing for more precise pressure management during all phases of MPD operations, well control operations, and transitions therebetween.

<FIG> shows an improved closed-loop hydraulic drilling system <NUM> with an automated well control choke manifold <NUM> for safe dynamic handover between MPD and well control operations in accordance with one or more embodiments of the present invention. Safe dynamic handover means a handover or transition between MPD and well control or well control and MPD where the wellbore remains fluidly dynamic due to continuous injection of drilling fluids. For the purposes of illustration, a drilling system <NUM> for offshore drilling operations is shown. While offshore applications require additional components such as, for example, a marine riser system, to facilitate drilling a subsea wellbore, one of ordinary skill in the art will recognize that onshore, or land-based, applications are substantially similar in configuration and function with respect to those components necessary for MPD and well control operations. As such, the description that follows applies with equal force to land-based drilling systems that include MPD and well control capabilities.

Drilling system <NUM> may include an automated well control choke manifold <NUM>, an independent well control control system <NUM>, and optionally a downstream flow meter <NUM> that enable automation of handover and well control operations as discussed in more detail herein. Similar to the conventional well control choke manifold <NUM> of <FIG>, automated well control choke manifold <NUM> may take fluid returns from the choke line <NUM> below the BOP <NUM> seal. An optional flow meter <NUM> may be disposed downstream of automated well control choke manifold <NUM> and fluidly connect automated well control choke manifold <NUM> to mud-gas separator <NUM>. Independent well control control system <NUM> may automatically control the choke position of one or more choke valves of automated well control choke manifold <NUM> during handovers between managed pressure drilling and well control operations and during well control operations to maintain the wellbore in a dynamic fluid state at all times. In embodiments including optional flow meter <NUM>, flow meter <NUM> may provide sensor data to the well control control system <NUM>.

Automated well control choke manifold <NUM> may be substantially similar to the conventional well control choke manifold (e.g., <NUM> of <FIG>) in terms of core choke functionality but differ in that it includes an interface that allows for independent control by the well control control system <NUM>. The well control control system <NUM> and automated well control choke manifold <NUM> may include connectivity that facilitates control of the choke manifold <NUM> by well control control system <NUM>. In this way, well control control system <NUM> may dictate the choke position of automated well control choke manifold <NUM>. For example, software executing on the well control control system <NUM>, or related system, may govern operations of automated well control choke manifold <NUM> including commanding one or more choke valves of automated well control choke manifold <NUM> to a desired choke position to achieve a desired surface pressure or wellbore pressure. Assuming for the purpose of discussion, that drilling system <NUM> is drilling ahead using the MPD system (e.g., annular sealing system <NUM>, annular closing system <NUM>, and return flow spool <NUM>), potentially under automation. Due to geological uncertainties, a kick may be unexpectantly taken. When a kick is detected, the MPD system may be the first equipment used to respond to the contingency. Upon detection of the kick, the MPD control system may start closing one or more choke valves of the MPD choke manifold <NUM> to apply further pressure on the well in order to suppress the kicking formation. For example, under automation, MPD control system <NUM> may start closing one or more choke valves of MPD choke manifold <NUM> until flow out is substantially equal to flow in. Once the wellbore pressure equals or exceeds the pore pressure, the flow out should return to expected levels. When flow out is substantially equal to flow in, a determination may be made as to whether the volume of unknown formation fluids taken during the kick requires well control operations. The driller will typically place the total kick volume with the additional pressure required to balance the formation in an operational matrix to determine if the unknown formation fluids may be circulated out of the well through the MPD system. If the total kick volume exceeds the operational matrix, regulations, technical limitations of equipment, or agreed limits on what may be circulated out through the MPD system, then a decision is made to invoke well control operations.

In certain embodiments, a Dynamic Formation Integrity Test ("DFIT") may be performed to determine the maximum mud pump speed that may be used to circulate out the volume of unknown formation fluids within the wellbore <NUM>. In this way, the MPD system may be used to apply additional surface backpressure into the well while the mud pumps <NUM> are running. The flow in and flow out may be monitored to identify if the well <NUM> enters into losses such that flow in exceeds flow out. The result of the DFIT is a determination of the pressure range that the formation holds integrally. The higher the pressure, the greater mud pump <NUM> speed that may be used so long as choke line <NUM> friction is not exceeded while doing so. In an ideal situation, the preference is to fully open the fluid path through automated well control choke manifold <NUM> to shorten the time required to circulate out the kick volimie.

At this point, the kick was taken, it was determined that the kick must be circulated out using well control operations, and the MPD system has been used to kill the well. The MPD system is in downhole pressure mode where the hydraulic model is used to calculate downhole pressure. With this information the choke PLC (not independently illustrated) of the MPD control system <NUM> determines whether the pressure setpoint of the MPD choke manifold <NUM> on the surface needs to be increased or decreased to achieve the desired downhole pressure, thereby regulating downhole pressure by application of surface backpressure. The drillstring rotation may be stopped, or significantly reduced, then the drillstring may be spaced out, such that the drillstring <NUM> is moved up or down, typically up since drill bit <NUM> is likely on the surface of the bottom of the hole <NUM> when drilling ahead, to ensure that there is no tool joint in the path of the blind shear rams <NUM> or the pipe rams <NUM>, <NUM>, and <NUM>. Then stop rotation of drillstring <NUM> and booster. The real-time hydraulic model may calculate the loss of friction in the well <NUM> and, since the MPD system is in downhole pressure mode, the MPD control system <NUM> may automatically adjust the choke position of one or more choke valves of the MPD choke manifold <NUM> to compensate for the change. The injection rate of drilling fluids may be reduced to the maximum flow rate for the automated well control choke manifold <NUM>. If the DFIT indicates that sufficient flow is possible, it may be possible to leave the Pressure While Drilling ("PWD") tool on. It may be simulated before using forward simulations to define the contribution of choke line <NUM> friction with enough flow rate to keep the PWD tool alive. At this point, the MPD system may be regulating to surface pressure. With the automated well control choke manifold <NUM> fully closed at this point, the HCR valve (not independently shown) may be opened, which may be verified by a pressure increase in the kill <NUM> and choke <NUM> lines. While differences in kill <NUM> and choke <NUM> line pressures may be expected due to possible differences in mud weight and temperature between the marine riser <NUM> and the lines <NUM> and <NUM>, the differences must make sense and be of the same order of magnitude.

At this point, returns could potentially be taken through both the MPD choke manifold <NUM> and the automated well control choke manifold <NUM>, and the automated well control choke manifold <NUM> is regulating to a sensed pressure taken from below the BOP <NUM> or kill line <NUM> pressure. However, standard industry practice is to isolate the marine riser <NUM> from the wellbore <NUM> for safety reasons. In order to automatically start closing the MPD choke manifold <NUM> as the automated well control choke manifold <NUM> opens, a small pressure imbalance is created between the MPD choke manifold <NUM> and the automated well control choke manifold <NUM>, that causes the MPD control system <NUM> to automatically close one or more valves of MPD choke manifold <NUM>. For example, the MPD control system <NUM> may set the pressure setpoint of the MPD choke manifold <NUM> to a value higher than the pressure setpoint of the automated well control choke manifold <NUM> by a predetermined amount, such as, for example, <NUM> N/m<NUM> (Pascals). One of ordinary skill in the art will recognize that the predetermined amount may vary based on an application or design. Then verify that the sensed pressure taken from below the BOP <NUM> or kill line <NUM> increases until the automated well control choke manifold <NUM> starts to open as needed to keep the BOP <NUM> pressure or kill line <NUM> pressure constant. For example, well control control system <NUM> starts to open automated well control choke manifold <NUM> as need to keep BOP <NUM> or kill line <NUM> pressure constant. The MPD flow meter <NUM> will likely see a loss while the optional well control flow meter <NUM>, if included, will display a substantially equivalent gain. When the MPD choke manifold <NUM> is fully closed, all wellbore <NUM> returns may flow through the automated well control choke manifold <NUM>. At this point, the BOP <NUM> may be closed, via annular <NUM> or <NUM> or ram <NUM>, <NUM>, <NUM>, or <NUM>. Returning fluids may be routed from the choke line <NUM> of the BOP <NUM> to the automated well control choke manifold <NUM> for delivery to the mud-gas separator <NUM>. Advantageously, the entire process, including drilling ahead with MPD, detecting the kick, handing over from the MPD system to well control, and the performance of well control operations is done with the wellbore remaining in a fluidly dynamic state below BOP <NUM>, with consistent fluid injection. With the marine riser <NUM> isolated, the MPD control system <NUM> may monitor for potential gas within the riser <NUM> and in the event gas is present, it may be circulated out using the MPD system.

Similarly, once the well control operations are complete, the handover from well control operations to the MPD system may be performed without ever going static with respect to wellbore fluids. To transition from well control operations to MPD, the MPD choke manifold <NUM> may be used to pressurize the marine riser <NUM> to equalize pressure across the BOP <NUM>. Once equalized, the BOP <NUM> may be opened and the automated well control choke manifold <NUM> may be operated in a mode that seeks to manage pressure at the BOP <NUM>. In order to automatically start closing the automated well choke manifold <NUM> as the MPD choke manifold <NUM> opens, a small pressure imbalance may be created between the automated well control choke manifold <NUM> and the MPD choke manifold <NUM>. For example, well control control system <NUM> may set a pressure setpoint of the automated well control choke manifold <NUM> to a value higher than the pressure setpoint of the MPD choke manifold <NUM> by a predetermined amount, such as, for example, <NUM>,<NUM> N/m2 (Pascals). One of ordinary skill in the art will recognize that the predetermined amount may vary based on an application or design. Then verify that the sensed pressure taken from below the annular closing system <NUM> increases until the MPD choke manifold <NUM> starts to open as needed to keep pressure below the annular closing system <NUM> constant. For example, MPD control system <NUM> starts to open MPD choke manifold <NUM> as need to keep pressure below annular closing system <NUM> constant. The optional well control flow meter <NUM>, if any, will see a loss while the MPD flow meter <NUM> will display an equivalent gain during the transition whereby the well control choke manifold <NUM> closes as the MPD choke manifold <NUM> opens. When the automated well control choke manifold <NUM> is fully closed the HCR valve (not independently illustrated) may be closed and all wellbore <NUM> returns may flow through the MPD choke manifold <NUM>. At this point, MPD operations, including drilling ahead, may be resumed.

One of ordinary skill in the art, having the benefit of this disclosure, will recognize that the above-noted steps may be performed in a different order based on one or more of the operator, driller, or rig procedures. One of ordinary skill in the art will also recognize that the safe dynamic handover between MPD and well control maintains wellbore fluids in a dynamic state. The methods disclosed herein enable the safe transition from MPD to well control and from well control to MPD in a manner that does not require the mud pumps to be stopped, thereby ensuring a fluidly dynamic state in the wellbore that advantageously prevents the formation of gels.

<FIG> shows an exemplary computer or control system <NUM> in accordance with one or more embodiments of the present invention. One of ordinary skill in the art will recognize that, as discussed above, a system for safe dynamic handover between MPD and well control (e.g., <NUM> of <FIG>) may include a plurality of control systems (e.g., MPD control system <NUM>, well control control system <NUM>, and others not necessarily shown) that function independent of one another from a device perspective, but may optionally work together systemically to achieve the objectives of the safe dynamic handover method disclosed herein. Notwithstanding the above, in certain embodiments, such control systems, or the functions or features they implement, may be integrated, or distributed based on an application or design in accordance with one or more embodiments of the present invention. One of ordinary skill in the art will also recognize that the type or kind of MPD control system <NUM> and well control control system <NUM> may vary from one another, and from application to application, based on an application or design in accordance with one or more embodiments of the present invention.

An exemplary computer or control system <NUM> may include one or more of Central Processing Unit ("CPU") <NUM>, host bridge <NUM>, Input/Output ("IO") bridge <NUM>, Graphics Processing Unit ("GPUs") <NUM>, Application-Specific Integrated Circuit ("ASIC") (not shown), and Programmable Logic Controller ("PLC") (not shown) disposed on one or more printed circuit boards (not shown) that perform computational or logical operations. Each CPU <NUM>, GPU <NUM>, ASIC (not shown), and PLC (not shown) may be a single-core device or a multi-core device. Multi-core devices typically include a plurality of cores (not shown) disposed on the same physical die (not shown) or a plurality of cores (not shown) disposed on multiple die (not shown) that are collectively disposed within the same mechanical package (not shown).

CPU <NUM> may be a general-purpose computational device that executes software instructions. CPU <NUM> may include one or more of interface <NUM> to host bridge <NUM>, interface <NUM> to system memory <NUM>, and interface <NUM> to one or more IO devices, such as, for example, one or more GPUs <NUM>. GPU <NUM> may serve as a specialized computational device that typically performs graphics functions related to frame buffer manipulation. However, one of ordinary skill in the art will recognize that GPU <NUM> may be used to perform non-graphics related functions that are computationally intensive. In certain embodiments, GPU <NUM> may interface <NUM> directly with CPU <NUM> (and indirectly interface <NUM> with system memory <NUM> through CPU <NUM>). In other embodiments, GPU <NUM> may interface <NUM> directly with host bridge <NUM> (and indirectly interface <NUM> or <NUM> with system memory <NUM> through host bridge <NUM> or CPU <NUM> depending on the application or design). In still other embodiments, GPU <NUM> may directly interface <NUM> with IO bridge <NUM> (and indirectly interface <NUM> or <NUM> with system memory <NUM> through host bridge <NUM> or CPU <NUM> depending on the application or design). One of ordinary skill in the art will recognize that GPU <NUM> includes on-board memory as well. In certain embodiments, the functionality of GPU <NUM> may be integrated, in whole or in part, with CPU <NUM> and/or host bridge <NUM>.

Host bridge <NUM> may be an interface device that interfaces between the one or more computational devices and IO bridge <NUM> and, in some embodiments, system memory <NUM>. Host bridge <NUM> may include interface <NUM> to CPU <NUM>, interface <NUM> to IO bridge <NUM>, for embodiments where CPU <NUM> does not include interface <NUM> to system memory <NUM>, interface <NUM> to system memory <NUM>, and for embodiments where CPU <NUM> does not include an integrated GPU <NUM> or interface <NUM> to GPU <NUM>, interface <NUM> to GPU <NUM>. The functionality of host bridge <NUM> may be integrated, in whole or in part, with CPU <NUM> and/or GPU <NUM>.

IO bridge <NUM> may be an interface device that interfaces between the one or more computational devices and various IO devices (e.g., <NUM>, <NUM>) and IO expansion, or add-on, devices (not independently illustrated). IO bridge <NUM> may include interface <NUM> to host bridge <NUM>, one or more interfaces <NUM> to one or more IO expansion devices <NUM>, interface <NUM> to keyboard <NUM>, interface <NUM> to mouse <NUM>, interface <NUM> to one or more local storage devices <NUM>, and interface <NUM> to one or more network interface devices <NUM>. The functionality of IO bridge <NUM> may be integrated, in whole or in part, with CPU <NUM>, host bridge <NUM>, and/or GPU <NUM>. Each local storage device <NUM>, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network interface device <NUM> may provide one or more network interfaces including any network protocol suitable to facilitate networked communications.

Control system <NUM> may include one or more network-attached storage devices <NUM> in addition to, or instead of, one or more local storage devices <NUM>. Each network-attached storage device <NUM>, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network-attached storage device <NUM> may or may not be collocated with control system <NUM> and may be accessible to control system <NUM> via one or more network interfaces provided by one or more network interface devices <NUM>.

One of ordinary skill in the art will recognize that control system <NUM> may be a conventional computing system or an application-specific computing system (not shown) configured for industrial applications. In certain embodiments, an application-specific computing system (not shown) may include one or more ASICs (not shown) PLCs (not shown) that perform one or more specialized functions in a more efficient manner. The one or more ASICs (not shown) may interface directly with CPU <NUM>, host bridge <NUM>, or GPU <NUM> or interface through IO bridge <NUM>. Alternatively, in other embodiments, an application-specific computing system (not shown) may represent a reduced number of components that are necessary to perform a desired function or functions in an effort to reduce one or more of chip count, printed circuit board footprint, thermal design power, and power consumption. In such embodiments, the one or more ASICs (not shown) and/or PLCs (not shown) may be used instead of one or more of CPU <NUM>, host bridge <NUM>, IO bridge <NUM>, or GPU <NUM>, and may execute software instructions. In such systems, the one or more ASICs (not shown) or PLCs (not shown) may incorporate sufficient functionality to perform certain network, computational, or logical functions in a minimal footprint with substantially fewer component devices.

As such, one of ordinary skill in the art will recognize that CPU <NUM>, host bridge <NUM>, IO bridge <NUM>, GPU <NUM>, ASIC (not shown), or PLC (not shown) or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, in whole or in part, based on an application, design, or form factor in accordance with one or more embodiments of the present invention. Thus, the description of control system <NUM> is merely exemplary and not intended to limit the type, kind, or configuration of component devices that constitute a control system <NUM> suitable for performing computing operations in accordance with one or more embodiments of the present invention. Notwithstanding the above, one of ordinary skill in the art will recognize that control system <NUM> may be an industrial, standalone, laptop, desktop, server, blade, or rack mountable system and may vary based on an application or design.

In one or more embodiments of the present invention, a method of safe dynamic handover between managed pressure drilling and well control may include identifying an unintentional influx of unknown formation fluids into a wellbore. One or more valves of the MPD choke manifold may close until the downhole pressure is sufficient to suppress further influx of unknown formation fluids into the wellbore, sometimes referred to as killing the well. After the kick is taken, a determination may be made as to whether the volume of unknown formation fluids and the additional downhole pressure required to suppress further influx exceeds an operational matrix or limit. If so, the kick volume requires circulation out by the well control choke manifold and a safe dynamic handover from MPD to well control may include a first transition that maintains a fluidly dynamic state with respect to wellbore fluids. In certain embodiments, an optional DFIT test may be performed to determine the maximum pump speed that may be used to circulate out the volume of unknown formation fluids within the wellbore, while the formation holds integrally. Then the drillstring may be spaced out to ensure that there is no tool joint in the path of a blind shear ram of the blowout preventer. A pressure setpoint of the MPD choke manifold may be set to a surface backpressure setpoint and a pressure setpoint of the automated well control choke manifold may be set to a sensed pressure taken from below a blowout preventer or a kill line pressure of the blowout preventer. The injection rate of drilling fluids may be reduced to maximize the flow rate through the automated well control choke manifold. A pressure imbalance may be created by setting the pressure setpoint of the MPD choke manifold above the pressure setpoint of the automated well control choke manifold by a predetermined amount, such that the pressure imbalance automatically causes the MPD control system to close the MPD choke manifold as the well control control system opens the automated well control choke manifold. The sensed pressure or kill line pressure may be sensed to verify that it increases until the automated well control choke manifold opens enough such that the blowout preventer pressure or kill line pressure remains constant. Then, after the MPD choke manifold has fully closed, an annular of the blowout preventer may be closed. The HCR valve of the blowout preventer may then be opened to enable flow through the choke line of the blowout preventer. Unknown formation fluids may be diverted from the choke line of the blowout preventer to the automated well control choke manifold for delivery to a mud-gas-separator. During this entire process, the wellbore remains fluidly dynamic due to the continuous, but not necessarily same speed of, injection of drilling fluids. In certain embodiments, a flow meter may be disposed downstream of the automated well control choke manifold. A determination may be made that the unknown formation fluids have been circulated out of the wellbore by a substantial equivalence in the fluid density between flow out and flow in. During the transition to, as well as during, well control operations, the wellbore remains fluidly dynamic. In certain embodiments, including offshore applications, fluids containing gas may be in the marine riser. If there is gas within the now isolated marine riser, the unknown formation fluids may be circulated out of the marine riser using the MPD choke manifold.

Once the unknown formation fluids are safely circulated out of the wellbore and potentially the marine riser in offshore embodiments, a safe dynamic handover from well control to MPD may include a second transition that also maintains a fluidly dynamic state with respect to wellbore fluids. In offshore applications, the marine riser may be pressurized to equalize pressure across the blowout preventer. Continuing, in all applications, the annular of the blowout preventer may be opened. The pressure setpoint of the automated well control choke manifold may be set to the sensed pressure taken from below the blowout preventer or the kill line pressure of the blowout preventer. A second pressure imbalance may be created by setting the pressure setpoint of the automated well control choke manifold above the pressure setpoint of the MPD choke manifold by a second predetermined amount, where the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold as the MPD control system opens the MPD choke manifold. The second predetermined amount may be the less than, equal to, or more than the predetermined amount used to create the pressure imbalance during the first transition from MPD to well control. Then, the HCR valve of the blowout preventer may be closed after the well control choke manifold has closed. The wellbore remains fluidly dynamic due to continuous, but not necessarily the same rate of, injection of drilling fluids. At this point, the MPD system may be used to drill ahead once again. In certain embodiments, the operation of both MPD and well control operations, including transitions therebetween, may be automated. While a human operator typically makes the decision as to whether to circulate fluids out through the MPD system or the well control system, all other steps may be performed by the MPD control system, well control control system, and potentially a computer executing the hydraulic model. One of ordinary skill in the art will recognize that a non-transitory computer-readable medium comprising software instructions that, when executed by a process, may perform one or more of the above-noted methods in accordance with one or more embodiments of the present invention.

Advantages of one or more embodiments of the present invention may include one or more of the following:.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control provides, for the very first time, the ability to automate MPD, well control operations, and transitions therebetween while maintaining the wellbore in a dynamic fluid state at all times, thereby increasing the reliability, efficiency, and safety of operations.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control provides, for the very first time, an automated well control choke manifold capable of regulating based on pressure rather than choke position to maintain the wellbore in a dynamic fluid state during transitions between MPD and well control operations.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control governs transitions from MPD to well control and from well control to MPD, where each transition is fluidly dynamic with respect to fluids within the wellbore, advantageously preventing the formation of gels.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control ensures that unknown formation fluids within the wellbore are contained and circulated out of the wellbore in a safe and efficient manner, without ever going static with respect to wellbore fluids.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control prevents the formation of gels, thereby preventing pressure spikes during the start-up of the mud pumps.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control improves pressure transmission through the well system, thereby allowing for precise pressure management during all phases of MPD, well control operations, and transitions therebetween, while maintaining a fluidly dynamic state within the wellbore.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control increases the safety of operations by precisely managing pressure during all phases of MPD, well control, and transitions therebetween.

In one or more embodiments of the present invention, safe dynamic handover between MPD and well control maintains a dynamic fluid state with respect to fluids within the wellbore even though rotation has stopped, preventing reactions that form gels that must be forcefully broken to resume MPD operations, such as drilling ahead.

Claim 1:
A method of safe dynamic handover between managed pressure drilling and well control comprising:
setting a pressure setpoint of an MPD choke manifold (<NUM>) to a surface backpressure setpoint;
setting a pressure setpoint of an automated well control choke manifold (<NUM>) to a sensed pressure taken from below a blowout preventer (<NUM>) or a kill line (<NUM>) pressure of the blowout preventer (<NUM>);
creating a pressure imbalance by setting the pressure setpoint of the MPD choke manifold (<NUM>) above the pressure setpoint of the automated well control choke manifold (<NUM>) by a predetermined amount, wherein the pressure imbalance automatically causes an MPD control system (<NUM>) to close the MPD choke manifold (<NUM>) as the well control control system (<NUM>) opens the automated well control choke manifold (<NUM>);
verifying that the sensed pressure or kill line (<NUM>) pressure increases until the automated well control choke manifold (<NUM>) opens enough such that the blowout preventer (<NUM>) pressure or kill line (<NUM>) pressure remains constant;
closing the blowout preventer (<NUM>) after the MPD choke manifold (<NUM>) is closed; and
diverting unknown formation fluids from a choke line (<NUM>) of the blowout preventer (<NUM>) to the automated well control choke manifold (<NUM>) for delivery to a mud-gas-separator (<NUM>),
wherein the wellbore (<NUM>) remains fluidly dynamic due to continuous injection of drilling fluids.