Multi-mode pumping riser arrangement and method

Abstract

The invention relates to a riser system in the form of a pumping riser (1), i.e. a riser (1) having an outlet (6) of the riser (1) at a certain depth below the surface (S) of a body of water, wherein the outlet (6) is connected to a return pump (7) for returning fluid from the riser (1) to said surface (S), as well as various methods of operation in order to have greater versatility when performing operations related to oil and gas drilling. The device also comprises a sealing element (15, 16) for sealing the annulus (5) of the riser (1) and a bypass line (17) surrounding the sealing element (15, 16). The various methods make it possible to switch between an open mode and a closed mode, and vice versa, to monitor leaks through the sealing element (15, 16), and to perform other operations using the advantages of the two different modes.

Description

Technical Field

[0001] The present invention relates to a riser system and various operating methods to provide greater versatility in hydrocarbon drilling related operations conducted near or on the bottom of a body of water.

[0002] More particularly, the present invention relates to a so-called pumping riser, ie a riser having a riser outlet at a depth below the surface of a body of water, wherein the outlet is connected to a return pump for returning drilling fluid from the riser to the surface. Background Art

[0003] Pumping riser operations can be closed, meaning the riser annulus is closed by a sealing element above the return pump outlet, and the pump is able to (quickly) change the pressure at the riser outlet by changing the pressure at the return pump inlet to regulate the wellbore pressure.

[0004] Pumping riser operations can also be open-end, meaning the riser annulus is open to the atmosphere and the top of the riser is at approximately atmospheric pressure. The return pump in such systems also regulates the pressure at the riser outlet, which is determined by the level of a fluid, such as mud, in the riser to regulate wellbore pressure. Such systems, sometimes referred to as CML (controlled mud level), have demonstrated multiple advantages when operating with a riser level below the slip joint during drilling, as well as other phases of well construction, completion, production, or abandonment.

[0005] Detecting influx early is one of the most critical factors in the drilling process, as uncontrolled influx can have fatal consequences. Therefore, any method that allows drillers to detect small influxes early and respond quickly is of great interest to the industry.

[0006] Furthermore, when operating in closed mode, drilling fluid volume control relies on observing flow measurements over time and combining these measurements with drilling fluid volume measurements from the rig motion system. All of these measurements are associated with measurement uncertainties related to the accuracy and repeatability of the sensor measurements. This is also true for measurements taken in closed mode under static conditions. Alternatively, the system can be connected to the top well control monitoring tank and the flow measurements combined with the well control monitoring tank measurements can be used to determine the volume. For the first option, the total volume error increases over time. For the second option, the measurement accuracy of the well control monitoring tank is affected by the rig motion and the accuracy of the well control monitoring tank volume sensor. Additionally, the pipelines that carry drilling fluid to and from the well control monitoring tank are not always filled with mud, which also contributes to uncertainty in the total volume measurement.

[0007] On the other hand, a CML can isolate the riser under static conditions (i.e., when not circulating) and use it as a storage tank to monitor changes in drilling fluid volume within the wellbore. Using a pressure sensor (usually very accurate) or other accurate method to determine the liquid / gas (air or other gas) interface, the volume in the riser can be monitored, providing a very accurate method to determine any changes in well fluid volume (inflow, loss, temperature effects, wellbore breathing, or other). In such a system, there is no empty line, and all volumes are measured very accurately at all times. In addition, because the fluid level is below the slip joint, the volume measurement is not affected by changes in riser volume caused by changes in slip joint length when the drilling rig is in motion.

[0008] In conventional drilling operations using a prior art closed riser (i.e., a riser with some form of sealing element in it), the riser is full above the sealing element. The pressure differential across the sealing element is determined by the static pressure of the entire riser above the sealing element (although this will be affected by the movement of the sliding joint) and the operating pressure below the sealing element. For a given mud weight and sealing element setting depth, the pressure above the sealing element cannot be actively controlled. The pressure differential across the sealing element affects wear and, therefore, the life of the sealing element. The pressure above the sealing element and the pressure rating of the sealing element will also determine the minimum allowable pressure below the sealing element.

[0009] The leakage rate of a sealing element in a riser at a given pressure differential across the sealing element can be an indication of the wear state. Some sealing elements also utilize a variable pressure / force acting radially on the sealing element. In this case, leakage will vary with wear, precharge / force, and potentially other factors. Regardless, for a given set of remaining parameters, the leakage rate of the sealing element at a given pressure differential can be an indication, or in some cases can be correlated with actual wear and, therefore, remaining service life. Since the riser has full contact surfaces (to the bell joint), it is affected by the volume changes associated with the movement of the sliding joint, making it difficult to accurately measure the leakage rate.

[0010] Additionally, the movement of the sliding joint means that the height from the top of the liquid level to the sealing element is not constant, even if the system remains fully loaded.

[0011] For sealing elements, operating parameters can be adjusted during operation, such as hydraulic or spring-driven radial force. Adjusting these adjustable operating parameters will affect the leakage rate of the sealing element under given operating parameters. Generally speaking, operating with a higher leakage rate will result in a lower wear rate.

[0012] In a typical SBP (surface back pressure) application, the operating pressure below the sealing element is higher than (or equal to) the pressure above the sealing element. In the pumping riser solutions described in the prior art, under normal operating conditions, the pressure below the sealing element is lower than (or equal to) the pressure above the sealing element.

[0013] In SBP systems, it is generally desirable to avoid significant leakage of drilling fluid from below the sealing element to above it.

[0014] When pumping risers in closed mode, ensuring zero or very low leakage through the sealing element is critical for some operations, but for other operations, significant leakage may be tolerated or even occur. However, in the prior art, there is no reliable method to achieve this variation in leakage rate. Furthermore, there is no reliable method to verify that the desired leakage rate through the sealing element has been achieved.

[0015] In a given system, the component with the lowest pressure rating will determine the size and strength of the largest influx (kick) that the system can handle. This component is typically the return pump. Increasing the pressure rating of the pump will have a significant impact on the weight and size of the pump. Additionally, there may be concerns about wear and the effect of wear on pressure integrity. For other components in the system, the wear rate is much less and more predictable, so it is not usually an issue from a pressure integrity perspective. Some pump systems may also have a seal between the process media and the ambient water that is acceptable in normal operation, but may be considered an issue when circulating a kick.

[0016] The type of pump used may be based on any pump principle, such as centrifugal, positive displacement, displacement, etc.

[0017] The current controlled mud level (CML) system operates primarily in open mode.

[0018] The CML system is constructed with conventional auxiliary lines, such as kill lines, choke lines, and BOP hydraulic fluid lines, as well as the hardware required to operate the CML and the auxiliary lines needed to operate the CML. The CML hardware has not yet been constructed or prepared for modification with the auxiliary lines, fluid lines, and other hardware required to operate the SBP.

[0019] On the other hand, in addition to the pipelines required to operate the surface backpressure system, the SBP system also includes conventional auxiliary pipelines such as the kill line, choke line, and BOP hydraulic fluid line. The surface backpressure hardware has not yet been constructed or prepared for modification with the auxiliary pipelines and other hardware required to operate the CML.

[0020] Therefore, operators must select the type of system to use before the system is manufactured and installed. Once the system is installed, converting to another type of system is expensive and time-consuming because it requires extensive hardware modifications or even the procurement of new hardware components.

[0021] In a traditional CML, the riser is filled by pumping drilling fluid into the top of the riser using a topfill pump and / or pumping drilling fluid along a boost line into the top of the BOP. In a closed riser, because the entry point is below the sealing element, the riser above the sealing element cannot be filled during operation of a conventional boost line setup. Most drilling rigs are not equipped with a topfill pump, and the rig's well control tank pump is often not well-suited to performing this filling function in a controlled manner. Therefore, filling the riser above the closed sealing element is not feasible with existing solutions.

[0022] Gas that comes with the mud can accumulate beneath closed sealing elements. When the sealing elements are opened or retracted, the accumulated gas is released onto the riser. As a result, the gas flows out of the riser at the top and can spill onto the rig floor or create an explosion hazard.

[0023] Some systems with sealing elements use two or more sealing elements spaced vertically along the riser in series, with a barrier fluid injected between the seal elements at a higher pressure than below the lower seal element. This ensures that no well fluid flows past the seal elements into the riser above them. In such systems, it is possible to accurately measure the leakage rate of the barrier fluid entering the system. However, accurately measuring the amount of fluid flowing upward and downward at any given time may be impossible, or at least very difficult.

[0024] Prior art riser systems are generally unable to detect where an inflow is detected by measuring the density of the gas and mud mixture and use that as a method for deciding when to isolate the pump and when to circulate the inflow out using a closed riser system.

[0025] Sometimes, formations with very narrow drilling windows are encountered. This narrow drilling window means that the difference between the minimum and maximum allowable pressures of the formation, typically given by pore pressure and fracture pressure, respectively, is very small. This means that only small pressure variations within the well are acceptable during operation. Existing upper chokes on drilling rigs are often manual or, if automated, unable to maintain accurate pressure upstream of the choke when the composition of the fluid flowing through the choke changes. Furthermore, drilling contractors often have internal policies against using drilling chokes for anything other than well control. For today's surface backpressure operations, an additional upper choke system is often used as part of the surface backpressure setup. Typically, the surface backpressure choke is separate from the drilling rig's well control choke to avoid wear. Typical surface backpressure (SBP) operations require the construction of a significant piping network with independent flow paths, including sensors, flowmeters, valves, and piping.

[0026] On the one hand, conventional pumped riser open CML systems utilize infrastructure built to support the necessary CML functions, including dedicated umbilicals. On the other hand, conventional surface backpressure equipment utilizes dedicated umbilicals to provide the necessary support functions for this type of system. These include electrical power, hydraulics, and sensor signals. CML and SBP systems are considered competing systems, with drillers choosing between them. To date, a combination of these two types of systems has not been described in the prior art.

[0027] Consistent with the above, the prior art does not address how to facilitate the easy conversion of a system designed to perform CML to a system designed to perform SBP, or vice versa, using the same basic major building blocks. The prior art also does not describe a system that enables a driller to use a single hardware setup to perform both SBP and CML operations and to be able to seamlessly switch between the two methods in seconds or minutes.

[0028] In some cases, during well construction, formation pressures higher than anticipated when the drilling plan was developed are encountered. These higher-than-expected pressures can result in an influx that needs to be addressed before normal operations can resume. To manage these pressures with traditional well control methods, the pressure in the wellbore needs to be higher than the formation pressure. In prior art pumped riser systems, the maximum wellbore pressure that can be achieved without shutting off the blowout preventer is limited by the pressure that can be achieved from the hydrostatic pressure of the riser string filled with drilling mud.

[0029] In this invention, several methods are shown that allow the driller to achieve higher wellbore pressures than can be achieved with prior art systems. These methods include coupling the pumping riser system with a choke in conjunction with prior art systems, or replacing the mud in the upper portion of the riser, above the riser seal, with a heavier mud column, sometimes referred to as the "upper riser cap."

[0030] Prior art closed-loop systems are used in pumping riser systems, where the system is used to reduce wellbore pressure, or in backpressure systems, where a top choke is used to increase wellbore pressure. In some cases, the desired wellbore pressure may be such that, for a given mud weight and dynamic annular friction drop, pressure needs to be removed when circulating but increased when not circulating. The prior art has not yet described a system that can seamlessly switch between removing and increasing pressure in a controlled manner using a subsea pump and top choke combination.

[0031] Based on existing processes and techniques currently used in surface backpressure operations, it is known or readily apparent to those skilled in the art how to circulate influxing hydrocarbons out of the wellbore using riser seals, return conduits, and top chokes. During such processes, known as well control events, it is crucial that the pressure in the wellbore is neither too low, which would allow further hydrocarbon influx, nor too high, which would exceed the formation strength and cause fracture. This lower limit is often referred to as the pore pressure, while the upper limit is referred to as the formation fracture pressure, or in some cases, simply the fracture pressure. In some cases, the difference between the pore pressure and fracture pressure is minimal, often referred to as the "narrow drilling window." During the process of circulating the influent, the goal is to maintain the wellbore pressure between the upper and lower limits, with high-pressure gas circulating upward through the annulus. Due to the gas expansion effect as pressure changes, this means that the amount of additional pressure required during a well control event typically increases throughout the process. Those skilled in the art are familiar with these concepts.

[0032] When constructing a well using a pumped riser system, drillers typically select a higher mud weight than when drilling conventionally. Because of this, the pressure exerted on the wellbore from the hydrostatic column to the surface is often close to or even higher than the fracture pressure. During the well control process, as the gas expands, it takes up more space in the annulus, reducing the mud weight in the wellbore and, in turn, the wellbore pressure. In traditional well control, this is compensated for by increasing the back pressure applied by the choke. This means that for well control activities using a pumped riser system, it may be necessary to reduce pressure at the beginning of the process compared to a full riser, and then reduce the amount of pressure reduced during the well control cycle. The prior art does not describe how to handle such a well control event. The present invention describes how to handle this situation by reducing the pressure using a riser pump, in some cases in conjunction with a choke to apply additional pressure to compensate for the hydrostatic losses associated with gas expansion. During well control, a choke used in conjunction with a subsea pump can also be used to mitigate any slugging in the return line, as the choke can be used to ensure that the pressure in the return line remains high enough to ensure a low gas void fraction upstream of the choke.

[0033] In some cases, in the absence of a kick, the desired wellbore pressure may be such that, for a given mud weight and dynamic annular friction drop, pressure needs to be removed when circulating but increased when not circulating. The prior art has not described a system that can seamlessly switch between removing and increasing pressure in a controlled manner using a subsea pump and a top choke.

[0034] The prior art does not describe how to replace the volume of liquid above the riser sealing element and / or how to change the liquid level during operation using a pumped riser system. During operation, this may be useful for many reasons, such as controlling the pressure above the riser sealing element or replacing mud laden with cuttings with clean mud before a stationary operation.

[0035] The prior art also does not describe, for a pumped riser solution, how to flush the return line with clean mud using liquid above the riser sealing element, or to maintain circulation in the return line without pumping the drill pipe or one of the auxiliary lines.

[0036] Prior art systems describe using a riser as a return line. In the absence of a dedicated return line, a pump draws fluid from below the riser seal and discharges above it, creating a pressure differential from above to below the seal. One of the primary advantages of this system is its lower cost compared to other pumping riser systems, as it requires no modifications to the riser joints above the pumping riser components or alterations to the top of the conventional mud return path. With such systems, drill cuttings can accumulate on top of the riser seal, so prior art systems describe deflectors and flushing systems to overcome this problem. Furthermore, in such systems, the fluid level in the riser is always full, making it impossible to perform any operations if the fluid level in the riser is low.

[0037] The prior art also describes using one of the auxiliary lines as a return line for the entire well operation, effectively rendering the return line unable to perform its original intended role in the overall operation, or as a contingency measure, such as when dealing with an influx event, by circulating the auxiliary line, possibly connected to a top choke, while dealing with the influx event.

[0038] In prior art pumping riser systems without a dedicated return line, the riser needs to be kept full at all times because there is no way to reduce the liquid level in the riser. If the system is operated in open mode, full riser pressure is applied to the well.

[0039] Another method of reducing drilling rig integration costs described in the prior art is to use existing auxiliary pipelines, such as booster lines, as return lines. When such modifications are made in the prior art, the original functions of the existing auxiliary pipelines cannot be used during closed riser operations.

[0040] Some examples of prior art can be found in:

[0041] US2003 / 066650 describes a drilling system for drilling a subsea wellbore, comprising a drill bit conveyed by tubing extending through a subsea wellhead. Drilling fluid supplied from the surface flows through the tubing, is discharged at the drill bit, returns to the wellhead through the wellbore annulus, and flows to the surface through a riser extending from the wellhead. A flow restriction device located in the riser restricts the flow of the return fluid, while an active fluid device controllably discharges the fluid from below the flow restriction device in the riser to a position just above the flow restriction device, thereby controlling the bottomhole pressure and equivalent circulating density ("ECD"). Alternatively, the fluid is discharged to a separate return line, thereby providing dual gradient drilling with simultaneous control of bottomhole pressure and ECD. A controller controls energy based on downhole measurements, thereby controlling the speed of the pump to maintain the ECD at a predetermined value or within a predetermined range. This solution is only capable of closed riser operation.

[0042] WO 2013 / 055226 describes an apparatus and method for controlling borehole return flow, in which drilling fluid is supplied from a surface drilling rig to a bottomhole assembly via multiple sections of drill pipe. The sections have tool joints with enlarged outer diameters, and an annular space is formed between the drill pipes. The annular space communicates with or forms part of the return flow path of the drilling fluid. A choke is positioned in the annular space, the length of which exceeds the distance between the enlarged outer diameter sections of two adjacent tool joints. This solution also only operates with closed risers.

[0043] WO 2017 / 195175 describes an underwater drilling method for controlling bottom hole annular pressure and downward injection rate from a mobile offshore drilling unit with a low-pressure marine riser and an underwater blowout preventer during mud cap drilling operations. The method, known as controlled mud cap drilling, uses a managed or observed hydrostatic head of a heavy annular mud (fluid) to balance the peak pore pressure in the well and control the injection rate by using a subsea mud lift pump and a control system to regulate the process. A riser seal device may also be included in the system. The purpose of the riser seal device is to create a riser void that can be used for various reasons, but not to create a closed riser system to control downhole pressure.

[0044] GB 2502626 describes a system for controlling the pressure of a borehole fluid during drilling. A drill pipe is provided in the borehole for supplying drilling fluid into the borehole. A sealing device is provided and arranged to seal around the outer surface of the drill pipe, thereby separating the drilling fluid in the borehole on a first side of the sealing device from the fluid on a second side of the sealing device. In addition, a submersible pump is arranged to receive a flow of drilling fluid from the borehole. The pump device is operated to pump the drilling fluid out of the pump device and to generate a fluid pressure of the drilling fluid at a position upstream of the pump device. The generated pressure is less than or equal to the hydrostatic pressure of the fluid on the second side of the sealing device. The system can only be operated in a closed mode.

[0045] WO 2016 / 135480 describes a riser assembly comprising a body enclosing a main passage, the main passage extending from a first end of the body to a second end of the body, generally parallel to the longitudinal axis of the body, the body being adapted to be mounted in a riser such that the main passage forms part of the main passage of the riser. The riser assembly further comprises a sealing assembly configured to provide a seal between the body and a tubular extending along the main passage of the body to substantially prevent fluid from flowing along the main passage and around the tubular. Furthermore, the riser assembly comprises two or more shunt lines, each shunt line extending from a first port in the body to a second port in the body, the ports extending through the body to connect the main passage to an exterior of the body, the sealing assembly being positioned between the first and second ports in the body, wherein a pump is positioned within each shunt line, the pump being operable to pump fluid along the shunt line in which it is positioned. Summary of the Invention

[0046] In a first aspect of the invention, it is intended to facilitate all aspects of drilling operations by controlling the pressure below the sealing element in the pump riser closed mode and lowering the fluid level in the pump riser open mode without removing the sealing element. The sealing element may be a rotating sealing device (RSD) or a non-rotating annular sealing element.

[0047] This is achieved by adding a bypass line to the riser that bypasses the fluid around the seal element, a mud return line, and operating the riser fluid level below the depth of the slip joint at the upper end of the riser, even when operating in closed mode. Therefore, by opening and closing the valve on the bypass line, it is possible to seamlessly switch between closed and open modes, and vice versa. A level sensor located above the seal element, such as a pressure sensor that can calculate the liquid level, is key to operating this system.

[0048] If the design of the sealing element permits, the bypass function can also be achieved by opening the sealing element to allow flow through it.

[0049] In a second aspect of the present invention, a system is created that operates in a closed mode but can be switched to an open mode to more accurately measure volume changes of the slurry in the system using a riser.

[0050] By adding a bypass line around the sealing element, a mud return line, and operating with the riser fluid level below the slip joint (if required), when the system is set up to operate in closed mode, it is possible to seamlessly switch from closed mode to open mode, or vice versa, by opening the bypass valve to open the flow path between below and above the sealing element. This can be accomplished by maintaining the pressure above the riser sealing element at a level that is primarily higher, equal to, or lower than the operating pressure below the sealing element. The riser volume measurement associated with open mode can then be used even with the sealing element installed. This is particularly useful in static conditions, as the riser can be isolated and used as a storage tank, where volume measurements are unaffected by rig motion and higher volume accuracy can be achieved compared to other methods. The bypass arrangement, combined with pressure measurement below the sealing element, also serves as a relief mechanism to prevent over-pressurization of the system below the sealing element in the event of a system failure, a clogged mud return line, or similar situations.

[0051] When the sealing element design permits, a bypass line function may also be achieved by opening the sealing element to allow flow through it.

[0052] In a third aspect of the present invention, using the same hardware setup as described in the second aspect, the riser fluid level is set or adjusted to a desired level and the bypass line is opened to allow operation in an open mode in an emergency situation such as a stuck pipe. This situation may include energizing a downhole drilling tank mounted on the drill pipe or violently operating the drill pipe. These activities may damage the sealing element. By using the present invention, the sealing element can be moved to a more relaxed state with less potential for damage while maintaining the desired pressure in the well. After the bypass is opened and the sealing element is relaxed, the fluid level in the riser can be further changed to adjust the wellbore pressure to help remedy the situation. Due to the presence of a sealing element that can be closed quickly, it can further allow for a reduction in downhole pressure compared to the reduced downhole pressure allowed without a fixed sealing element.

[0053] In a fourth aspect of the invention, using the same hardware as described in the second and third aspects, the system operates in open mode but can be quickly converted to closed mode by simply closing the bypass line. This is particularly useful for well sections identified as presenting some form of risk that could be mitigated with a closed system, but it is also useful for exploiting one of the advantages of an open system. Examples include reducing drill pipe connection time by not having to move the riser fluid level when compensating for annular friction losses due to pumping, or when using the volumetric accuracy of an open system when pulling out a hole. When drilling high-pressure, high-temperature (HPHT) wells, measuring the volumetric expansion effect of the fluid as it heats up, calculating the density drop of the associated fluid, estimating the wellbore pressure drop associated with the associated fluid density drop, and leveraging the ability to raise the fluid level in the riser in a controlled manner to compensate for the drop in wellbore pressure.

[0054] In a fifth aspect of the present invention, the life of the sealing element can be extended. This is achieved by lowering the riser fluid level above the sealing element, thereby also lowering the pressure above the sealing element. Consequently, the pressure differential across the sealing element can be reduced, thereby extending the service life of the sealing element.

[0055] In a sixth aspect of the invention, the object is to determine the leakage rate across the sealing element. According to the invention, this is achieved by providing a level or pressure sensor to monitor changes in the liquid level in the riser above the sealing element. The leakage rate can then be calculated based on the geometry of the riser and the piping between the sealing element and the liquid / gas interface. If the operation is performed at the riser level below the slip joint, the uncertainties associated with the movement of the drilling rig and the movement of the slip joint can be eliminated. These measurements can be operated in conjunction with some form of top fill pump, or from a subsea connection of a pipeline such as a boost line, choke line or kill line, and some method of measuring flow, such as a flow meter, to monitor the total volume in the riser above the slip joint, and thus the rate of loss or gain.

[0056] In a seventh aspect of the invention, the present invention provides for operation of a significant leakage rate from top to bottom across the sealing element in order to reduce wear of the sealing element.

[0057] As long as leakage can be verified from above to below the sealing element and the required operating pressure can be achieved below the sealing element, it can be determined that the sealing element is performing its primary function.

[0058] This means that, depending on the criticality of the operation being performed, it may be decided that a significant leakage rate across the sealing element is acceptable in some wells, as long as it can be demonstrated that the leakage is from above to below the sealing element.

[0059] In an eighth aspect of the invention, the slurry level in the riser above the sealing element is monitored by a level / pressure sensor and leakage from the sealing element is compensated for by using a pump and flow meter or other alternative method of measuring inflow to fill the riser and thereby maintain a nearly constant riser level.

[0060] The constant liquid level in the standpipe is conveniently controlled by an automatic controller that has an algorithm that monitors the standpipe level and operates the pump fill to maintain the standpipe level within predetermined parameters.

[0061] In an operating mode where the pressure below the sealing element is higher than above, leakage will be from below to above and the measured riser level will increase. In this case, the level will not remain constant but may need to be lowered in steps at given intervals using a submersible pump.

[0062] In a ninth aspect of the invention, the operating parameters of the sealing element can be adjusted in a controlled manner to switch the sealing element between an allowed or expected leakage and zero or minimal leakage. This can be accomplished in an automated manner by a controller having an algorithm. The automated system uses a riser pressure sensor(s) / liquid level sensor(s) above the sealing element to adjust the closing pressure / force on the sealing element to control the leakage rate and incorporates any other flow readings from the riser above the sealing element into the method for determining the flow through the sealing element.

[0063] In a tenth aspect of the invention, the return pump has a lower pressure rating than the rest of the system, which is circumvented by a valve arrangement that allows the pump to be used for normal operation, but provides a bypass line to the pump for influent handling so that the gaseous influent can be circulated up the riser through an outlet below the sealing element and above the return line. This increases the operating margin when circulating the influent (kick).

[0064] In an eleventh aspect of the present invention, there is provided a system that can be easily retrofitted to convert an SBP system to operate as a CML system, or vice versa. The system, when installed, is provided with the required wiring or with space for additional hardware, and has cutouts and other features for CML wiring (typically 4 to 6 inches) at its maximum outer diameter.

[0065] In a twelfth aspect of the present invention, the boost line serves as a pressure equalization line to mitigate the U-tube effect in the drill pipe when operating without a U-tube choke valve. This aspect of the present invention also enables improved shut-in drill pipe pressure measurement during low-intensity kicks.

[0066] In a thirteenth aspect of the present invention, it is intended to prevent gas from flowing toward the top of the riser when the sealing element is opened or retracted. This is accomplished by filling the riser from the top, opening the bypass line, and operating the pump to generate a high volume of flow from above, through the bypass line, around the sealing element, downward through the pump, and upward through the return line. This high velocity of flow can be used to flush the gas above the return line via the return pump, thereby transporting the gas to a safe location on the surface, such as a mud / gas separator.

[0067] In a fourteenth aspect, the present invention provides an alternative to the second aspect of the invention. When the system is operating in closed mode, i.e., with a sealing element in the riser, it may be necessary to switch to open mode and perform a static volume check by opening the aforementioned bypass pipe or allowing communication between the element above and below the sealing element. In this case, if the pressure above the sealing element is significantly different from the pressure below the sealing element when the drilling rig pump is turned off (i.e., when increasing the pump suction pressure to compensate for dynamic friction losses in the well), the riser fluid level needs to be adjusted. This will take time and mean increased costs for the operator.

[0068] An alternative to the above is to use the return line from the return pump as an online well control monitoring tank when switching from closed to open mode. By providing a branch line from the riser above the sealing element to the return line, this line can be opened during or after the rig pump is ramped down. The return line can then be drained to a predetermined level by allowing mud to flow from the return line into the riser above the sealing element. Alternatively, a bypass line around the sealing element can be opened, or the annular sealing element can be loosened to allow flow from below to above the sealing element. For centrifugal pumps, this can be achieved without opening the pump's bypass line, while for positive displacement pumps, the bypass line must be opened. Once the liquid level drops to or below the desired level, the flow path opened to allow the level to drop is closed. A pressure sensor in the return line or riser can be used to determine the mud level in the return line. As an alternative to using a pressure sensor in the return line to determine the liquid level, the liquid level can be allowed to drop to balance the level in the standpipe, and then the MRL level can be adjusted to the desired level using a pump with associated flow measurement or calculation. Those skilled in the art of pump control can find many different ways to accomplish this, depending on the type of pump being used.

[0069] This approach is particularly useful in situations where we are operating on seals with very low pressure differentials under dynamic conditions, i.e. flow through the drill pipe, and when the pump is shut off, the seal closes with zero flow through it (and the pressure below the seal is higher than above it). In this case, the fluid level in the riser needs to be significantly increased to maintain the correct downhole pressure at zero flow.

[0070] In the system of the present invention, when operating in closed mode, it is possible for the pressure below the sealing element to be higher than the pressure of the drilling fluid filling the well in open mode. This is most likely to occur if there is an influx of gas moving upward into the riser, and the operator is compensating for this to maintain the wellbore pressure within an acceptable pressure range. In this case, the leakage rate of the sealing element must be zero or very low to prevent hydrocarbons, especially gas, from entering the riser above the sealing element, which could lead to uncontrolled flow to the platform deck and / or the risk of ignition on the platform.

[0071] Because the return line has a smaller diameter than the riser, any volume change in the well will result in a larger change in the return line level than in the riser. This means that volume changes can be read more accurately using this method than when using the riser as a storage tank. Since the level changes more rapidly than when using the riser, for a given volume change in the well, in the event of an influx, the pressure exerted on the well will increase rapidly as the level in the return line increases. Since, in most cases, except when drilling very fine holes, the well diameter is larger than the diameter of the mud return line, this system will have a self-regulating effect on preventing influx.

[0072] As an alternative to using the return line for this purpose, the boost line can be fitted with a pressure sensor or level sensor and the level adjusted in a similar manner as described above so that the boost line can be used as an online well control monitoring tank when operating in a closed system.

[0073] A fifteenth aspect of the present invention provides a method for measuring the leakage rate of a barrier fluid injected upward and downward between two sealing elements. This is accomplished by monitoring the mud level below the sliding joint above the upper sealing element using a level sensor or pressure sensor. This provides a measure of the amount of barrier fluid leaking upward. When this upward leakage volume is compared with the total volume of barrier fluid consumed, the downward leakage volume can also be calculated.

[0074] In a sixteenth aspect of the present invention, a method is provided for determining how best to treat influent and how best to circulate it out of a riser.

[0075] The present invention provides for circulating the influent through one of two different outlets in the riser: either through a return pump or through a bypass line around the return pump. To determine when to switch from pumping through the pump to using the bypass line, the position of the gas / liquid mixture in the riser is calculated. To this end, pressure measurements are taken over time in the riser, such as by pressure sensors below the sealing element and on the BOP (Blowout Preventer). These measurements are spaced substantially apart to determine the average density and its variation over time. By combining this with known gas pressure and density models and mud weight, the approximate position of the gas as it propagates in the riser can be determined.

[0076] If the gas volume is relatively small, it can be circulated out through the return pump when it reaches the pump outlet. If the gas volume is large, it is best to isolate the pump and allow the gas to flow through a bypass line around the return pump. In this case, the top restrictor can be used with or without it.

[0077] In a seventeenth aspect of the present invention, the problem of accurately regulating wellbore pressure when drilling in formations with narrow drilling windows is addressed by introducing an automated choke with a high-quality hydraulic model controller upstream of the existing drilling rig choke, with the mud return line acting as a low-pressure choke for the influent handled through the riser. This approach allows for very precise control of wellbore pressure during kick cycles while avoiding the need for extensive additional piping and valves. Fluid will still pass through the drilling rig's drilling choke, but this may be left in a fully open position or used to throttle back some of the pressure. In this setup, it is possible to connect the return line directly to the drilling rig's existing choke, saving significant costs. This setup is generally unacceptable for conventional SBP-type operations, as SBP operations require constant choke operation and raise concerns about wear and tear on the drilling rig's choke, which, even when left in an open position, may not be fully functional when needed. On the other hand, with a pumped riser solution, the choke is only operated very rarely, so such a setup may be found acceptable from a risk perspective. Alternatively, the drill choke can be bypassed to divert the flow path to the mud-gas separator.

[0078] In an eighteenth aspect of the invention, it provides a novel combination of a system designed to perform CML operations and a system designed to perform SBP operations. However, initially, the construction cost of a system combining the full functionality of both systems would be very high. Surface backpressure riser installation equipment is typically placed less than 100 meters below the surface or waterline. Pumping riser equipment is typically placed deeper, typically 200-400 meters below the waterline. If sealing elements and / or annuli from a system originally designed for surface backpressure equipment are used, the existing umbilicals for that system should be lengthened to allow the system to be placed deeper in the combined system. This not only means longer umbilicals, but also requires a larger container to accommodate the larger number of umbilicals. However, this would mean that the sealing elements and the return pump would have separate umbilicals. It would be best to have as few umbilicals as possible in the slip.

[0079] The challenge of integrating the two systems and their disparate infrastructures has been overcome by taking the pump module used in pumping riser operations without sealing element functionality and adding a pump-mounted hardware module, or one or more modules not necessarily mounted on the pump, that incorporates not only the required additional valves, hydraulics, and sensors, but also the necessary electronics and hydraulic functionality for operating and monitoring the sealing elements and annuli. When the annuli and / or sealing elements are used in the pumping riser, this additional electronics and hydraulic functionality of the present invention is connected to the annuli / sealing element junction, rather than to the umbilical used in SBP operations. This allows for a more cost-effective and versatile system. In this system, some components of the entire system will also be installed on the existing RSD / annuli junction. Jumpers will be installed between the additional module and the RSD riser junction. This additional equipment, installed in the newly added hardware module(s), will use the same umbilical cable for signals, power, hydraulics, and other supplies as the equipment that drives and controls the pump. This umbilical cable will conveniently be the same design as the umbilical cable used when operating in pumping riser open mode (CML) only.

[0080] In a nineteenth aspect, the present invention provides for the modification of a riser joint designed to perform SBP operations so that the same joint can be used for CML operations. This is accomplished by including features required for CML, such as an outlet for a mud return line, mounting areas for additional components (such as sensors), an outlet for a bypass line, and a pressure sensor on the riser body, so that a component originally designed for SBP can later be modified for pumping riser operations.

[0081] The hardware can be modular so components from CML and SBP are mixed and can operate together as a single system.

[0082] In a twentieth aspect of the invention, with the riser seal in place, suction can be pumped from above the riser seal to lower the fluid level in the riser above the seal to maintain flow in the pump return line without outflow from below the riser seal. Replacing the fluid in the riser with a lighter or heavier fluid, purging a slurry containing hydrocarbons through the pump system, or for any other reason, it may be necessary to change the fluid level or the fluid itself in the riser above the riser seal. This is accomplished by having a riser outlet above the riser seal connected to the pump suction port. This outlet is equipped with an isolation valve. The slurry above the seal can be replaced by flowing upward into the riser with the riser seal open, or by filling the riser above the riser seal and suctioning it through the pump.

[0083] In a twenty-first aspect of the present invention, a specific method is described for ensuring that cuttings do not accumulate on top of a riser sealing element. This is particularly important for operations where the riser above the riser sealing element is used for retrieval during drilling when the riser sealing element closes the return mud and is filled with cuttings. This method for ensuring that cuttings do not accumulate on top of the riser sealing element is achieved by evacuating the boost line or any other auxiliary line connected to the riser above the riser closure device with an isolation valve and combined with an insert within the riser above the riser closure device. The insert is such that only a small portion of the cross-sectional area is open to the fluid. Typically, this will be the radial gap between the drill pipe and the insert, but there are other configurations with gaps elsewhere in the insert. Alternatively, the insert can be a riser closure device that completely seals the annular space in combination with a bypass line arrangement. In this aspect of the invention, liquid is pumped into the cavity between the riser sealing element and the riser insert. Since the riser sealing element does not allow or only allows very limited flow from top to bottom, this injected liquid will flow upward through the gap of the riser insert, and its upward flow velocity ensures that the chips above will not fall into the cavity between the riser closure device and the insert.

[0084] In a twenty-second aspect of the present invention, a method for removing cuttings that may have entered the cavity described in the previous section for any reason is described. This method is performed by opening the riser shut-off device, or a bypass line to the riser shut-off device, and, while the riser pump is running, pumping clean drilling mud, or any other clean liquid, from an auxiliary line into the cavity to create a downward flow, thereby removing the accumulated cuttings. If opening the riser shut-off device using a full riser would exceed the maximum pressure that the well can withstand, the riser fluid level above the riser shut-off device can be lowered using any of the methods described herein before opening the riser shut-off device.

[0085] In a twenty-third aspect of the present invention, a method is described that allows the auxiliary line to be utilized for three distinct purposes. In some cases, it serves as a mud return line, while in all other cases, the auxiliary line's original function is retained. In this aspect of the invention, the primary mode of operation during drilling and well construction is to operate with the riser closure in place, pumping from below the riser closure to above it and recovering the riser. In this aspect of the invention, the pump discharge is also connected to the auxiliary line, typically a booster line, with an isolation valve configured to allow the driller to select whether the discharge should be routed to the riser or the auxiliary line. This allows the driller to adjust the riser fluid level while maintaining the ability to perform all of the auxiliary line's intended functions without having to modify the existing riser connections above the pumping riser assembly. While riser fluid level adjustment and the use of the auxiliary line's intended functions cannot occur simultaneously, in this aspect of the invention, the driller can alternate between these two options. Furthermore, if a booster line is used, the auxiliary line can simultaneously serve as both the booster line and the injection line of the twenty-first aspect.

[0086] Prior art descriptions of pumping risers have primarily focused on controlling wellbore pressure during the drilling process. However, wellbore pressure control is equally important in several other aspects of the well construction process. The challenge is that existing riser closures may not be able to seal well equipment with varying diameters, such as those encountered when running casing, cementing operations, or running completions. In some cases, when operating a riser closure, it may be possible to shut off the blowout preventer to maintain wellbore pressure while running equipment of varying diameters into the well above the BOP, but those skilled in the art will appreciate that it is difficult to maintain active pressure control in all circumstances when operating such equipment. In many cases, being able to regulate the fluid level in the riser and operate the system with the riser closure inactive would overcome this challenge.

[0087] In this aspect of the invention, some modifications to the overhead piping of the auxiliary line will also typically be required to reroute the return flow to the mud handling system.

[0088] In a twenty-fourth aspect of the present invention, the system alternates between open and closed modes and operates in such a manner that, when operating in closed mode, the pressure above the riser seal element is primarily less than or equal to the operating pressure below the seal element. For example, the system operates in open mode when the drill pipe is circulating downhole, and in closed mode when not circulating downhole, leveraging the closed system's ability to rapidly change the pump's suction pressure to compensate for wellbore friction losses caused by stopping the mud pump during connection. Switching between open and closed modes can be accomplished in seconds by closing a bypass line around the RSD, or by shutting down the RSD itself. This aspect of the invention relates to applications where the controlled mud level benefits of an open system are desirable, such as using overbalanced mud to move pipes of varying diameters into and out of an orifice while regulating wellbore pressure, or leveraging the accuracy of riser pressure measurement to accurately measure the volume of drilling fluid within the wellbore, but in certain operations, the advantages of closed mode are desirable. Examples of this include compensating for wellbore friction losses during connection, rapidly increasing pressure to suppress inflow, or cycling out inflow without shutting down the BOP.

[0089] In a twenty-fifth aspect of the present invention, the system further includes a choke downstream of the pump, which is used to regulate wellbore pressure when the system is operating in closed mode. This arrangement introduces a unique capability not described in the prior art: the system seamlessly switches between increasing and decreasing pressure compared to a full riser. In this aspect of the invention, the choke can be operated to increase pressure above the full riser without the pump, and the pump can be operated to reduce pressure below the full riser without the choke. Alternatively, the choke can be used in series with the pump at intervals during well construction to achieve pressures above, below, or equal to the full riser. This aspect of the invention is useful when the system is operated with a mud weight that increases the wellbore pressure above the fracture pressure with the full riser, while increasing friction losses caused by drilling fluid circulation, but in an unbalanced state, i.e., below the pore pressure when drilling fluid circulation ceases, even if the drilling fluid level is increased to the full riser. Alternatively, in a well control scheme, the choke is an integral part of the program, but the pressure required immediately after a kick is the discharge pressure required by the pump. In this aspect of the invention, the driller is able to add and remove pressure compared to a full riser. This mode of operation can also be used to add back pressure to the return line to avoid creating a choke or mitigate the negative effects of foaming that may be associated with certain operating modes. The present invention describes how to address such situations using a riser pump to reduce pressure, in some cases in conjunction with a choke to apply additional pressure to compensate for the hydrostatic pressure loss associated with gas expansion. The choke, used in conjunction with the subsea pump during well control, can also be used to mitigate any slugging in the return line, as the choke can be used to ensure that the pressure in the return line remains high enough to maintain a low gas void fraction upstream of the choke.

[0090] When constructing a well using a pumped riser system, drillers typically choose a higher mud weight than when drilling conventionally. Because of this, the pressure exerted on the wellbore from the hydrostatic column to the surface is often close to or even higher than the fracture pressure. During the well control process, as the gas expands, it takes up more space in the annulus, reducing the mud weight on the wellbore and, in turn, the wellbore pressure. In traditional well control, this is compensated for by increasing the back pressure applied by the choke. The above means that for well control activities using a pumped riser system, it may be necessary to subtract pressure at the beginning of the process compared to a full riser, and then reduce the amount of pressure subtracted during the well control cycle. The prior art does not describe how to handle such a well control event. The present invention describes how to handle this situation using a riser pump to reduce the pressure, and in some cases, in conjunction with a choke to apply additional pressure to compensate for the hydrostatic losses associated with gas expansion. During well control, a choke used in conjunction with a subsea pump can also be used to mitigate any suction effects in the return line, as the choke can be used to ensure that the pressure in the return line is maintained at a high enough level to ensure a low gas void fraction upstream of the choke.

[0091] In some cases, without a kick occurring, the desired wellbore pressure may be such that, for a given mud weight and dynamic annular friction reduction, it is necessary to remove pressure when circulating but increase pressure when not circulating. The prior art has not yet described a system that can seamlessly switch between removing and increasing pressure in a controlled manner using a combination of a subsea pump and an upper choke.

[0092] In a twenty-sixth aspect of the present invention, the system operates with the fluid level in the riser reduced. The system's volumetric accuracy is used to measure the volume change, which, along with the well geometry and known mud properties, is used to calculate the change in downhole mud temperature and associated volume and density effects, without having a bottomhole assembly at the bottom of the well. The system can then compensate for the drop in downhole pressure by increasing the fluid level in the riser, thereby making up for the density loss associated with the temperature increase.

[0093] The prior art does not describe how to replace the volume of liquid above the riser sealing element and / or how to change the liquid level during operation of a pumping riser system. This may be useful for a number of reasons during operation, such as controlling the pressure above the riser sealing element or replacing slurry laden with cuttings with clean slurry before a rest period.

[0094] The prior art also does not describe a solution for pumping the riser, how to flush the return line with clean mud using liquid above the riser sealing element, or to maintain circulation in the return line without first pumping out the drill pipe or some auxiliary pipe. BRIEF DESCRIPTION OF THE DRAWINGS

[0095] FIG1 shows a prior art system of the so-called surface back pressure (SBP) type;

[0096] FIG2 shows a prior art system according to an open pumping riser of the so-called controlled mud level (CML) type without any riser sealing elements;

[0097] FIG2A shows a prior art system of the closed pumping riser type with a riser sealing element;

[0098] Figure 3 A first arrangement of a system according to the invention is shown, with a pumped and closed standpipe, and

[0099] Figure 4 A second arrangement of the system according to the invention is shown, in which an auxiliary line can be used;

[0100] Figure 5 A third arrangement of the system according to the invention is shown, wherein further features are introduced into the system;

[0101] Figure 6 The fourth configuration of the system is shown, Figure 3-5 The system enables the invention to be operated with relatively minor hardware modifications to existing equipment compared to the concepts shown. DETAILED DESCRIPTION

[0102] In order to better understand the subsequent description of the invention, some examples of prior art systems from which the present invention deviates will now be explained.

[0103] Figure 1 shows a system based on the so-called surface back pressure (SBP) type. In this system, the principle is to close the riser so that the pressure in the riser is independent of the surface pressure at the top of the riser. In this system, it is possible to achieve a pressure in the well that is higher than the pressure of the liquid column coming from the surface.

[0104] For such systems, it may be necessary to use so-called unbalanced fluids during drilling, particularly in situations where the drilling window is narrow. This occurs when the pressure in the riser filled with drilling fluid is lower than the pore pressure of the formation being drilled. The drilling fluid can be a liquid or a mixture of liquid and gas, such as foam, depending on the desired specific gravity of the liquid.

[0105] Figure 1 shows a drilling riser 1 extending from a drilling platform or vessel 2 at the surface S of a body of water to the bottom B of the body of water. The drilling riser 1 comprises a sliding joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1.

[0106] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0107] Drilling fluid, also known as mud, is pumped down the drill pipe 4, out the lower end of the drill pipe 4, and upward into the annulus 5. After exiting the lower end of the drill pipe 4, the mud mixes with wellbore materials, such as oil, gas, water, particles, and rock, and flows upward toward the annulus 5. The mud is pumped down the drill pipe 4 by a drilling rig pump (typically a bank of pumps) 40. A pressure sensor 39 is conveniently located at the outlet of the drilling rig pump 40, typically on a support pipe 70 located at or near the drill floor.

[0108] One or more pressure sensors 29 may be arranged in the riser. However, in practice, these sensors are arranged at the top. There is also a pressure sensor 51 on the BOP.

[0109] A choke line 47 extends from the BOP 50. The choke line 47 has an isolation valve 48 and a pressure sensor 49. The choke line 47 is connected to a drill rig choke 52.

[0110] The kill line 45 is connected to the BOP 50 via a choke 46. At the upper end of the kill line 45 are a liquid pump 43 and a pressure sensor 44.

[0111] A boosting line 23 is connected between an inlet 24 arranged close to the BOP 50. The line 23 has an isolation valve 25 and is supplied by a boosting pump 41. A pressure sensor 42 is included in the line 23.

[0112] At a depth below the surface, there is an outlet 6 from riser 1. The outlet is connected to a return line 108 via an isolation valve 109. Return line 108 extends to platform 2, where it is connected to a mud handling facility (not shown) via line 159 using a choke 113 and a flow meter 114. Choke 113 is mounted with an upstream pressure sensor 141 and a downstream pressure sensor 140. A branch line 124 is connected to a booster pump 123. Lines 124, 108, with valves (such as valve 109), can alternatively be duplicated as a second line from a second outlet near riser outlet 6. This duplication ensures that in the event of any failure of line 108, there is an available flow path to the surface.

[0113] At the top of the riser 1 there is an annular sealing element or diverter 38. The annular sealing element 38 is used to close off the riser annulus 5 if gas rises to the top of the riser 1. Below the diverter 38 there is an outlet 61 commonly referred to as a bell joint. This is connected to a fluid line 60 which, when operating at full riser level 245, allows the drilling mud to be transported to a mud processing facility. There is a separate system (not shown) which ensures that the gas is handled in a safe manner when the annular sealing element 38 is in use. This is commonly referred to as a diverter system. The annular sealing element 38 is part of any drilling rig and is not specific to the SBP system. The mud line 60 is used to return the mud to the mud processing facility during conventional drilling operations.

[0114] Between the top of the riser 1 and the outlet 6, there is a rotary seal device (RSD) 15, generally referred to as a sealing element in this specification. The rotary seal device 15 can seal the annulus 5 of the entire riser 1 while allowing the drill pipe 4 to rotate.

[0115] An additional annular sealing element 16 is designed to seal around the non-rotating drill pipe 4. This annular sealing element 16 is used when replacing the RSD 15 and can also serve as a safety measure when the RSD fails.

[0116] When operating the system of Figure 1, the RSD remains closed. The mud that has been pumped out of the drill pipe 4 and returned from the annulus 5 is diverted from the riser through the mud return line 108. The choke 113 is adjusted to maintain a certain pressure in the well.

[0117] The pressure below the RSD 15 is greater than atmospheric pressure. If a leak occurs in the RSD, well fluid will leak into the atmosphere and control measures such as closing the annular sealing element 16 and replacing the RSD 15 will be required.

[0118] The underwater dedicated equipment for the SBP is monitored and controlled via the umbilical cable 180 .

[0119] In Figure 1, a configuration is shown where the RSD 15 and annular sealing element 16 are located on a dedicated riser joint 136 between flanges 35 and 37, while the outlet 6 is located on a separate joint 33 between flanges 34 and 35. This is just one example of how the SBP subsea dedicated equipment can be arranged.

[0120] This known system has many advantages, but does have a number of disadvantages as discussed above in the Background section.

[0121] Figure 2 shows another known system designed to operate in an open pump riser mode. This system may also be referred to as a CML (controlled mud level) system. In this system, the well pressure is controlled by controlling the mud level in the riser.

[0122] 1 , FIG2 shows a drilling riser 1 extending from a drilling platform or vessel 2 at the surface S of the body of water to the bottom B of the body of water. The drilling riser 1 includes a sliding joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1.

[0123] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0124] Drilling fluid, often referred to as mud or drilling mud, is pumped down the drill pipe 4, out the lower end of the drill pipe 4, and pumped upward into the annulus 5. After the mud flows out of the lower end of the drill pipe 4, it mixes with the wellbore materials such as oil, gas, water, particles, rocks, etc., and flows into the annulus 5. The mud is pumped down the drill pipe by the drilling rig pump (usually a group of pumps) 40. The pressure sensor 39 is conveniently placed at the outlet of the drilling rig pump 40.

[0125] A choke line 47 extends from the BOP 50. The choke line 47 has an isolation valve 48 and a pressure sensor 49. The choke line 47 is connected to a choke 52 of the drilling rig.

[0126] The kill line 45 is connected to the BOP 50 via an isolation valve 46. At the upper end of the kill line 45 are a cutoff fluid pump 43 and a pressure sensor 44.

[0127] A boosting line 23 is connected between an inlet 24 arranged close to the BOP 50. The line 23 has an isolation valve 25 and is supplied by a boosting pump 41. A pressure sensor 42 is included in the line 23.

[0128] At a depth below the surface S, there is an outlet 6 from the riser 1. This outlet is connected to a mud return line 8 with an isolation valve 9. The mud return line 8 extends to the platform 2 where a flow meter 14 is installed on the mud return line 8. In normal operation, mud is delivered to the mud handling system through line 59 with valve 53 closed and valve 55 open.

[0129] Alternatively, the mud may be delivered to the mud handling system via line 58 and drill rig choke 52 with valve 55 closed and valve 53 open.

[0130] One or more pressure sensors 29 are arranged in the standpipe. There is also a pressure sensor 51 on the BOP.

[0131] Outlet 6 and pressure sensor 29 are part of a dedicated riser joint 33, which is different from the other riser joints in use. Dedicated riser joint 33 is installed in riser 1 using conventional riser flanges 34 and 35.

[0132] At the top of the riser 1, there is a fluid line 60 for returning the mud and an annular sealing element 38. If gas rises to the top of the riser 1, the annular sealing element 38 is used to close the riser annulus 5. A separate system (not shown) ensures that the gas is handled in a safe manner when the annular sealing element 38 is used, which is generally referred to as a diverter system.

[0133] There is also a fill line 26 connected to the top of the riser 1. A pump 27 can pump mud through the fill line 26. A flow meter 28 or other method of measuring flow is used to control the amount of mud pumped into the riser 1.

[0134] When operating the system of Figure 2, the top of the riser 1 is usually kept open to atmospheric pressure. The mud 45 level in the riser 1 is controlled by the return pump 7 according to the required pressure in the well.

[0135] There is mounted an upstream pressure sensor 56 and a downstream pressure sensor 57 of the pump 7. The sensors 56 and 57 can be used to calculate the pressure generated by the pump 7.

[0136] An umbilical cable 80 extends from the platform 2 down to the pump 7. The umbilical cable provides power to the pump 7 and also transmits signals and power underwater to CML components such as the pressure sensor 29 mounted on the riser, the isolation valve 9, and the pressure sensors 56 and 57 on both sides of the pump 7.

[0137] This system has many advantages but also some disadvantages. Among these are the difficulties associated with dealing with the influx of gas into the riser above the BOP, although methods exist for dealing with this situation which will not be described here.

[0138] Figure 2A is a schematic diagram of another prior art drilling riser system. It is based on a presentation by Statoil and AGR at the SPE / IACD MPD UBO conference held in Madrid on April 8–9, 2014. A paper on the same concept was presented at the 2014 Offshore Technology Conference and documented as OTC-25292-MS. Irrelevant features described in the paper have been excluded, and the figure shows an explanation of the relevant sections.

[0139] 2A shows a drilling riser 1 extending from a drilling platform or vessel 2 at the surface S of a body of water to the bottom B of the body of water. The drilling riser 1 comprises a sliding joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1 .

[0140] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0141] The mud is pumped downward along the drill pipe 4, extracted from the lower end of the drill pipe 4, and pumped upward into the annulus 5. After exiting the lower end of the drill pipe 4, the mud mixes with wellbore materials such as oil, gas, water, particles, and rock, and flows into the annulus 5. The mud is pumped downward along the drill pipe 4 by a drilling rig pump 40 (typically a bank of pumps). The pressure sensor 39 is conveniently located at the outlet of the drilling rig pump 40.

[0142] At a depth, there is a first outlet 6 to which a return pump 7 is connected. The downstream end of the return pump 7 is connected to a return line 208, which is connected to a line 230 connected to the riser 1. The pump 7 has an upstream isolation valve 209 and a downstream isolation valve 210.

[0143] A pump bypass line 211 is also included, and the pump bypass line 211 has an isolation valve 212 .

[0144] There is a riser outlet isolation valve 209 and a riser inlet isolation valve 222.

[0145] Also shown in Figure 2A is a choke line 47 extending from the BOP 50. The choke line 47 has an isolation valve 48 and a pressure sensor 49. The choke line 47 is connected to the drill choke 52. Downstream of the drill choke 52 is a pressure sensor 92.

[0146] There is also a branch line 660 from the pipeline 208 leading to the throttling line 47. On the branch line 660 there is an isolation valve 661.

[0147] A rotary control device (RCD) 215 is located on the riser 1 above the riser outlet 6 and below the inlet pipe 220. The RCD 215 is typically placed below a rotary kelly bushing (RKB) (not shown) at 900-1600 feet (approximately 275-50 meters).

[0148] An optional riser ring 216 may also be provided below the RCD 215 .

[0149] At the top of the riser 1, below the diverter 38, there is an outlet 61 commonly known as a bell joint. This connects to a fluid line 60 which, when operating at full riser level 245, allows the drilling mud to be delivered to a mud processing facility.

[0150] The riser is equipped with pressure sensors 229 and 299. Pressure sensor 229 is located below RCD215, and pressure sensor 299 is located above RCD215.

[0151] The pump 7 receives power from the surface via an umbilical cable 280. The umbilical cable also contains power and signal cables for operating and monitoring subsea valves and sensors.

[0152] In this prior art system, mud is returned to the surface through a riser during drilling. In the event that the system needs to handle a riser gas anomaly, the gas is handled by isolating and bypassing the subsea pump, directing the return gas into a choke line while simultaneously pumping down the boost line and using the drill rig choke to regulate riser pressure.

[0153] The boosting line 23 is connected to an inlet 24 located near the BOP 50. The line 23 is supplied by a boosting pump 41 and has an isolation valve 25. A branch line 292 is connected from the boosting line 23 to the riser 1, with an inlet above the RCD 215. An isolation valve 291 is provided on the branch line 292.

[0154] Detailed description of the invention

[0155] In the following description, it should be noted that although only one isolation valve is described to shut off a specific pipeline, it is common practice to install at least two isolation valves at key locations. Therefore, "a valve" should be understood as "one of multiple valves".

[0156] Furthermore, the drawings are not drawn to scale because the vertical distance compared to the diameter of the riser would be much greater than shown in the drawings.

[0157] In this specification, the term closed riser refers to a system in which the annulus is closed within the riser and it is possible to operate under a pressure differential across some sealing device located within the riser. There are several ways to create and maintain the pressure differential, which are known per se to the skilled person.

[0158] Throughout this specification, pumps are used to remove pressure, and chokes are used to increase pressure. Physically, the opposite is actually happening in these two components: pumps add energy and pressure to the fluid, while chokes dissipate or remove energy and pressure from the fluid. However, in the context of this disclosure, and following driller convention, we'll refer to the effect of operating a pump or choke on wellbore pressure.

[0159] The terms "mud" and "drilling fluid" are used interchangeably to refer to drilling fluids in general. This is meant to encompass all types of fluids commonly used in drilling, such as, but not limited to, liquids, gaseous fluids, gas and liquid mixtures, foams, emulsified water and / or oil, and water-based, oil-based, gaseous, and synthetic-based drilling fluids. The systems of the present invention may also be used for purposes other than drilling, such as cementing, completions, waterflooding, hydration prevention, or fracturing, and thus fluids associated with these operations may be used in place of, in addition to, or in addition to the drilling fluid.

[0160] In this specification, including the claims, when the term "connect" or "connected" is used, it should be understood as "fluidly connected".

[0161] When specialized equipment outside of the conventional hardware setup, such as the return pump 7 or return line, is described in this specification as being mounted on the riser, these components may alternatively be mounted adjacent the riser, for example suspended from a drilling rig, or located on the seafloor.

[0162] Figure 3 A first embodiment of a system according to the invention is shown, which can be regarded as a somewhat novel combination of the two systems of Figures 1 and 2 .

[0163] Figure 3 A drilling riser 1 is shown extending from a drilling platform or vessel 2 at the surface S of a body of water to the bottom B of the body of water. The drilling riser 1 includes a sliding joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1. If the drilling platform 1 is supported on the bottom B, such as in a jack-up drilling rig, the sliding joint 3 may be omitted.

[0164] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0165] Liquids such as drilling fluid, cement for consolidating liners and casings, MEG, water, plug and waste cement, and ethylene glycol are pumped down the drill pipe 4. Drilling mud will be used as an example for the following description. The drilling mud is pumped down the drill pipe 4, exiting the lower end of the drill pipe 4 and ascending into the annulus 5. After exiting the lower end of the drill pipe 4, the mud mixes with wellbore materials such as oil, gas, water, particles, and rock, and flows into the annulus 5. The mud is pumped down the drill pipe 4 by a drilling rig pump 40 (typically a bank of pumps). A pressure sensor 39 is conveniently located at the outlet of the drilling rig pump 40.

[0166] At a depth below the water surface S, which can be 50-1000 meters, but in most cases is around 2-400 meters, there is a first outlet 6 to which a return pump 7 is connected. The downstream end of the return pump 7 is connected to a return line 8. The return line 8 extends to the drilling platform or vessel 2 above the surface S. It may contain a flow meter 14. The flow meter 14 may also be arranged at other locations along the return line 8 than shown.

[0167] The isolation valve groups 9 and 10 are arranged to facilitate isolation of the return pump 7 at the upstream end, the downstream end, or both.

[0168] In normal operation, the mud is delivered to the mud handling system via line 59, wherein valve 53 is closed and valve 55 is open.

[0169] Also shown is a choke line 47 extending from the BOP 50. The choke has an isolation valve 48 and a pressure sensor 49. The choke line 47 is connected to a drilling rig choke 52.

[0170] The return line 8 is also connected to the drilling rig choke 52 via a line 58. Valves 55 and 53 can be used to determine the direction of the return flow.

[0171] A pump bypass line 11 is also included. The pump bypass line 11 has an isolation valve 12. Therefore, when valves 9 and 10 are open and valve 12 is closed, drilling fluid can be pumped to the surface via the return pump 7. Alternatively, when at least one (or preferably both) of the valves 9 and 10 are closed and valve 12 is open, drilling fluid flows through the pump bypass line 11 under its own pressure.

[0172] A pressure sensor 56 is arranged on the inlet side of the return pump 7 , and a pressure sensor 57 is arranged on the outlet side of the pump 7 .

[0173] In addition to providing power and signal paths for operating sensors, valves, and seals, the umbilical cable 80 also provides power to drive the pumps. The power can be hydraulic or electric, depending on the type of pump used.

[0174] At a location on the riser 1 higher than the return pump 7, but still substantially below the surface, a sealing device 15 is arranged, which is a type that seals around the drill pipe 4 even when the drill pipe 4 is rotated. This type of closure device is sometimes called a rotary closure device (RCD), but we will use the more general term rotary sealing device (RSD) 15 hereinafter.

[0175] The riser may also have an additional sealing element in the form of an annular sealing element 16, which is a device with similar functions to the RSD, but is not designed to operate for any length of time as the drill pipe 4 rotates. It is primarily designed to operate without rotating the drill pipe 4. The RSD 15 is typically installed and retrieved together with the drill pipe 4, while the annular sealing element 16 is installed together with the riser 1. More than one RSD may be installed, as may more than one annular sealing element. The annular sealing element 16 is designed to seal around a non-rotating drill pipe 4. The annular sealing element 16 can be used for shorter periods of time in place of the RSD, or with a rotating drill pipe 4. The RSD 15 and the annular sealing element 16 may be arranged in any order. It is also conceivable that the RSD is located within the annular sealing element.

[0176] A bypass line 17 is arranged to bypass the RSD 15 and the annular sealing element 16. The bypass line 17 has a valve 18 that can be opened to allow well fluid to flow through the bypass line 17.

[0177] The return line 8 is also connected to the riser 1 above the RSD 15 and the annular sealing element 16 via an upper branch line 20. This branch line 20 has an isolation valve 22.

[0178] The apparatus may have a conventional kill line 45 connected to the BOP 50 through an isolation valve 46. At the upper end of the kill line 45 is a cutoff fluid pump 43 and a pressure sensor 44.

[0179] A boost line 23 extends from the surface to an inlet 24 on the riser 1. The inlet 24 is located substantially below the pump outlet 6, preferably near the lower end of the riser 1. The boost line 23 is equipped with one or more isolation valves 25. The boost line 23 is also equipped with a pressure sensor 72 to measure the liquid level in the boost line.

[0180] Any suitable line, such as an interceptor line, a throttle, or other existing piping on the riser may be used as the fill line in place of the boost line 23. Alternatively, a dedicated fill line may be installed.

[0181] A filling pump 41 is arranged to draw liquid out of the pressurizing line 23. The line 23 comprises a pressure sensor 42 therein.

[0182] Figure 3 The system also has an upper fill line 26 which is connected to the top of the riser 1, typically through an existing opening in the flow divider 38. A pump 27 can pump slurry through the fill line 26. A flow meter 28 is used to control the amount of slurry pumped into the riser 1.

[0183] At the top of the riser 1, below the diverter 38, there is an outlet 61, commonly known as a bell-joint. This is connected to a fluid line 60, which allows the drilling mud to be transported to a mud processing facility when the riser is operating at full capacity.

[0184] The system can be operated with the riser liquid level 245 at the height of the bell joint, or at any other position down to the riser outlet 6 .

[0185] The riser is equipped with pressure and / or level sensors, such as sensors 29 and 30. Sensor 29 is a pressure sensor, while sensor 30 can be either a pressure sensor or a level sensor. Such sensors are well known in the art. Pressure sensor 29 is located below RSD 15 and annular sealing element 16. Sensor 29 can also be located on BOP 50. Additionally, an additional pressure sensor 51 can be located on BOP 50. Pressure / level sensor 30 is located above RSD 15.

[0186] The pump 7 receives power from the surface via an umbilical 80. The umbilical also contains power and signal cables to operate and monitor subsea valves and sensors located on riser joints 33 and 36 and annular sealing elements, as well as valves and sensors between the outlet 6 and the surface S or drilling rig 2.

[0187] In a preferred embodiment, the pump outlet 6 is arranged on a first dedicated joint 33, extending between flanges 34 and 35. The RSD 15, the annular sealing element 16, the bypass line 17, and the branch lines 19, 20, and 31 are arranged on a second dedicated joint 36, extending between flanges 35 and 37. Alternatively, all of these components may be included in one joint.

[0188] Now refer to Figure 4 The second embodiment of the present invention is described in more detail in the schematic diagram of FIG. Figure 3 The settings in are similar, but please note the following points.

[0189] The return line 8, extending from the drilling platform or vessel 2 above the surface S, includes an additional choke 13 upstream of the drilling rig choke 52. It also includes an additional isolation valve 54. This connects the return line 8 to the drilling rig choke 52, allowing fluid in the return line to be directed through the additional choke 13 to the drilling rig choke 52. Isolation valves 53, 54, and 55 determine the direction of the return flow, depending on the gas content in the fluid. If the gas content exceeds a certain level, or if a higher gas content is expected, the gas is directed to chokes 13 and 52. Choke 13 is equipped with an upstream pressure sensor 90 and a downstream pressure sensor 91.

[0190] Figure 4 The embodiment comprises a lower branch line 19 which can also be used to bypass the pump 7 as will be explained further below.

[0191] Therefore, the return line 8 is connected to the riser 1 below the RSD 15 and the annular sealing element 16 and above the RSD 15 and the annular sealing element 16 through a lower branch line 19 and an upper branch line 20. Both branch lines 19, 20 have isolation valves 21, 22.

[0192] The boost line 23, or alternatively a pipe used as a fill line, is also connected to the riser 1 at a level above the RSD 15 via a branch line 31 which is equipped with an isolation valve 32 to form a lower fill line.

[0193] The system will typically operate with the riser water level 145 below the slip joint 3. The riser water level 145 can operate anywhere between the riser outlet 6 and the bell joint 61.

[0194] The system may include Figure 4 All additional features shown, or only some of them.

[0195] Now refer to Figure 5 The third embodiment of the present invention is described in more detail with reference to the schematic diagram of the apparatus of FIG. Figure 4The device in has some additional features.

[0196] Figure 5 A drilling riser 1 is shown extending from a drilling platform or vessel 2 at the surface S of a body of water to the bottom B of the body of water. The drilling riser 1 includes a slip joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1. If the drilling platform 2 is supported on the bottom B, such as in a jack-up drilling rig, the slip joint 3 may be omitted.

[0197] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0198] Liquids such as drilling fluid, cement for consolidating liners and casings, MEG, water, plug and waste cement, ethylene glycol, etc., are pumped down the drill pipe 4. Drilling mud will be used as an example below. The drilling mud is pumped down the drill pipe 4, exiting the lower end of the drill pipe 4 and traveling upward through the annulus 5. After exiting the lower end of the drill pipe 4, the mud mixes with wellbore materials such as oil, gas, water, particles, and rock, and flows into the annulus 5. The mud is pumped down the drill pipe 4 by a drilling rig pump 40 (typically a bank of pumps). A pressure sensor 39 is conveniently located at the outlet of the drilling rig pump 40.

[0199] At a depth S below the water surface, which can be 50-1000 meters, but is currently around 2-400 meters, there is a first outlet 6 to which a return pump 7 is connected. The downstream end of the return pump 7 is connected to a return line 8. The return line 8 extends to the drilling platform or vessel 2 above the surface S and may include a flow meter 114. The flow meter 114 may also be located at another location along the return line 8, such as at the outlet of the pump 7, as shown by flow meter 599.

[0200] The isolation valve groups 9 and 10 are arranged to facilitate isolation of the return pump 7 at its upstream and downstream ends or both.

[0201] A pump bypass line 11 is also included. The pump bypass line 11 has an isolation valve 12. Thus, when valves 9 and 10 are open and valve 12 is closed, drilling fluid can be pumped to the surface via the return pump 7. Alternatively, when at least one (or preferably both) of the valves 9 and 10 are closed and valve 12 is open, drilling fluid can flow through the pump bypass line 11 under its own pressure.

[0202] Pressure sensors are installed upstream 56 and downstream 57 of the pump 7. The sensors 56 and 57 can be used to calculate the pressure generated by the pump 7.

[0203] In normal operation, mud is delivered to the mud handling system via line 159 with valve 54 closed and valve 155 open. Alternatively, with isolation valve 155 closed and isolation valve 54 open, mud from return line 8 can be delivered to the drill choke 52 via line 168. There is a pressure sensor 92 downstream of the drill choke 52. Mud can also be delivered via lines 159 or 168 and Figure 5 Further lines not shown in the figure lead to the mud gas separator.

[0204] exist Figure 5 Also shown is a choke line 47 extending from the BOP 50. The choke has an isolation valve 48 and a pressure sensor 49, and the choke line 47 is connected to a choke 52 on the drilling rig.

[0205] At a location on the riser 1 higher from the riser outlet 6, but still substantially below the surface, a RSD 15 is arranged.

[0206] The riser may also have an additional sealing element in the form of an annular sealing element 16, which is a device with similar functions to the RSD, but is not designed to operate for any length of time with the rotation of the drill pipe 4. It is primarily designed to operate without rotating the drill pipe 4. While the RSD 15 is typically deployed and retrieved with the drill pipe 4, the annular sealing element 16 is installed with the riser 1. More than one RSD may be installed, as may more than one annular sealing element. The annular sealing element 16 is designed to seal around a non-rotating drill pipe 4. The annular sealing element 16 may also be used for shorter periods of time with a rotating drill pipe 4, in place of the RSD 15. The RSD 15 and the annular sealing element 16 may be arranged in any order. It is also conceivable to place the RSD 15 inside the annular sealing element.

[0207] A bypass line 17 is arranged to bypass the RSD 15 and the annular sealing element 16. The bypass line 17 has an isolation valve 18 which can be opened to allow well fluid to flow through the bypass line 17.

[0208] The return line 8 is also connected to the RSD 15 and the riser 1 above the annular sealing element 16 via an upper branch line 20. The branch line 20 has an isolation valve 22.

[0209] The apparatus may have a conventional kill line 45 connected to the BOP 50 through an isolation valve 46. At the upper end of the kill line 45 is a cutoff fluid pump 43 and a pressure sensor 44.

[0210] A boost line 23 extends from the surface to an inlet 24 on the riser 1. The inlet 24 is located substantially below the pump outlet 6, preferably near the lower end of the riser 1. The boost line 23 is equipped with one or more isolation valves 25. The boost line 23 is also equipped with a pressure sensor 72 to measure the liquid level in the boost line.

[0211] Any suitable pipeline, such as an interceptor line, a throttle or other existing pipeline on a riser, can be used as a filling line instead of the boost line 23. Alternatively, a dedicated filling line can be installed.

[0212] A filling pump 41 is arranged to draw liquid from the pressurizing line 23. The line 23 comprises a pressure sensor 42 therein.

[0213] Figure 5 The system also has an upper fill line 26 that is connected to the top of the riser 1, typically through an existing opening in the flow divider 38. A pump 27 can pump slurry through the fill line 26. A flow meter 28 is used to control the amount of slurry pumped into the riser 1.

[0214] At the top of the riser 1, below the diverter 38, there is an outlet 61, commonly known as a bell-joint. This is connected to a fluid line 60 which, when the riser is operating at full capacity, delivers drilling mud to a mud processing facility.

[0215] The riser is equipped with pressure sensors and / or level sensors, such as sensors 29 and 30. Sensor 29 is a pressure sensor, while sensor 30 can be either a pressure sensor or a level sensor. Such sensors are well known in the art. Pressure sensor 29 is located below RSD 15 and annular sealing element 16. Sensor 29 can also be located on BOP 50. Alternatively, an additional pressure sensor 51 can be located on BOP 50. Pressure / level sensor 30 is located above RSD 15.

[0216] The pump 7 receives power from the surface via an umbilical cable 80. The umbilical cable also contains power and signal cables for operating and monitoring subsea valves and sensors located on riser joints 33 and 36, as well as annular sealing elements. Figure 5 Between the upper outlet 6 and the surface S are shown the valves, sensors and other equipment of the present invention.

[0217] In a preferred embodiment, the pump outlet 6 is arranged on a first dedicated joint 33, extending between flanges 34 and 35. The RSD 15, annular sealing element 16, pressure or level sensor 30, pressure sensor 72, and branch lines 17, 20, 31, and 550 with isolation valves 32, 22, 18, and 551 are arranged on a second dedicated joint 36 extending between flanges 35 and 37. All of these components may alternatively be included in one joint from flange 34 to 37.

[0218] The mud level 505 in the riser is normally maintained below the slip joint 3, but can rise to the bell joint 61 during certain operations.

[0219] A restrictor 113 is located in the return line 8. Pressure sensors 190 and 191 are located upstream and downstream of the restrictor 113. These can be used to calculate the pressure drop across the restrictor 113. The system may also include a bypass line arrangement around the restrictor 113 (not shown).

[0220] Flow meter 114 is shown upstream of flow restrictor 113. The flow meter 114 can also be located downstream of flow restrictor 113.

[0221] A pressure sensor 29 can be used to measure the pressure in the riser below the RSD 15 or annular seal 16. When the system is in open mode, this pressure is driven by the riser level and the weight of the mud. In closed mode, this pressure can be regulated by a pump, a choke, or a combination of the two.

[0222] A pressure or level sensor 30 measures the mud level above the seal and can be used to monitor the upper riser when operating in closed mode.

[0223] The boost line 23, or alternatively the fill line, is also connected to the riser 1 at a level above the RSD 15 via a branch line 31 fitted with an isolation valve 32 to form a lower fill line.

[0224] When the system is in closed mode, i.e., with RSD 15 in place and bypass line 18 closed, pump 7 can maintain the pressure below RSD 15 at any pressure between the return line 8, which is filled with mud, and the minimum suction pressure allowed by the pump, typically around 1 bara. The pressure at outlet 6 below RSD 15 can be higher, equal to, or lower than the pressure above RSD 15. Also significantly, compared to the dual-gradient concepts described in the prior art, it is possible to achieve a pressure at the riser outlet 6 that is lower than the pressure of the seawater gradient, i.e., the water column from the bell-joint.

[0225] By operating the flow restrictor 113, back pressure can be added to the return line 8. When the flow restrictor 113 is operated, the pump 7 can be used to generate some boost pressure, stopped so that no boost pressure is generated, or isolated by closing the isolation valves 9 and 10 and opening the isolation valve 12 to allow flow through the pump 7. Closing the isolation valves 9 and 10 to isolate the pump 7 can, in some cases, increase the maximum pressure rating of the system because the pump can, in some cases, be the lowest pressure rated system component.

[0226] This unique combination of subsea pump 7 and choke 113 allows for seamless increases and decreases in pressure throughout the riser, giving the system the ability to regulate pressure throughout the riser, a capability not possible with prior art solutions. This is important for drillers because it increases the operating window and allows them greater flexibility in selecting mud weights while still maintaining bottomhole pressure within the drilling window at all times. The control algorithms that synchronize and seamlessly operate choke 113 and pump 7 are familiar to those skilled in the art.

[0227] Next, it will be described how to control the liquid level above the RSD 15, also when operating in closed mode. Figure 5 Shown is a riser outlet line 550, also referred to as an upper riser suction line, with the outlet of riser 1 located above RSD 15. Riser outlet 550 allows the driller to lower the riser fluid level 505 even when RSD 15 is in place and bypass line 18 is closed.

[0228] This is accomplished by opening isolation valve 551, keeping isolation valves 9 and 12 closed, opening isolation valve 10, and operating pump 7. Fluid can then be drained from the upper portion of riser 1. By operating the system in this manner, the driller can reduce the riser fluid level 505. The driller can also use this function in conjunction with pump 27 or pump 41, or both, to inject new fluid into the upper portion of the riser, i.e., above RSD 15, to raise the fluid level 505, change the mud weight, or alter other properties of the mud in the riser.

[0229] Once the driller has completed mud circulation above the RSD 15, isolation valve 551 can be closed and isolation valve 9 or isolation valve 12 can be opened to continue operations. There are many reasons why a driller may want to circulate fluid above the RSD 15. For example, to lower the fluid level above the RSD 15 before opening the RSD bypass line 18, or to lower the riser fluid level 505 to a lower level than before the bypass line 18 was last closed, or to clear fluid that has leaked through the RSD 15 during operations.

[0230] By using the methods described above, it is also possible to make the mud above RSD 15 have different properties than the mud below RSD 15. Of particular interest to drillers is the ability to add static pressure to the well without changing the entire mud system, to increase pressure above RSD 15 as an additional barrier, or, in some cases, to operate with a lower density mud in the upper portion of the riser than in the rest of the well.

[0231] The prior art describes how pressure control can be achieved by using a pumped riser system with a seal arrangement, where suction is drawn from below the seal and discharged into a riser above the seal. An example of such a system is shown in Figure 2A described above. When operating such a system, cuttings may accumulate on top of the seal. Because there is typically a differential driving pressure from above to below the seal, these cuttings present a problem for the driller, as they can cause wear and damage to the seal. This problem has long been known, and various devices are described in the prior art.

[0232] In prior art pumping riser systems, such as the one shown in FIG2A , which aims to reduce drilling rig integration costs by eliminating the need for a dedicated return line, either the riser is used as the return line, without being able to lower the fluid level in the riser, or existing auxiliary lines, such as boost lines, are used as the return line. Using existing auxiliary lines also makes it impossible to operate the pumping riser system to regulate wellbore pressure while the auxiliary lines are used for their intended functions. The present invention provides a solution to these shortcomings of the prior art.

[0233] Now refer to Figure 6 , a fourth embodiment of the present invention is described in detail.

[0234] In an embodiment of the present invention, a unique combination is introduced that utilizes existing auxiliary lines (typically booster lines) in conjunction with the riser insert to create a flushing system to ensure that swarf does not accumulate on top of the seal causing damage and wear.

[0235] This embodiment also introduces the possibility of using the auxiliary line alternately for three different purposes, either for its original purpose, or as an injection line for the flushing system (as described above), or as a return line for the slurry loaded with cuttings. The first two uses mentioned here can also be used simultaneously.

[0236] Figure 6 A drilling riser 1 is shown extending from a drilling platform or vessel 2 at the surface S of a body of water to the bottom B of the body of water. The drilling riser 1 includes a sliding joint 3 adapted to accommodate relative movement between the drilling platform or vessel 2 and the riser 1. If the drilling platform 2 is supported on the bottom B, such as in a jack-up drilling rig, the sliding joint 3 may be omitted.

[0237] The drill pipe 4 extends along the interior of the drilling riser 1 and into the well (not shown). An annulus 5 is formed between the drill pipe 4 and the riser 1.

[0238] Liquids such as drilling fluid, cement for consolidating liners and casings, MEG, water, plug and waste cement, and ethylene glycol are pumped down the drill pipe 4. Drilling mud will be used as an example below. The drilling mud is pumped down the drill pipe 4, exiting the lower end of the drill pipe 4 and flowing into the annulus 5. After exiting the lower end of the drill pipe 4, the mud mixes with wellbore materials such as oil, gas, water, particles, and rock, and flows into the annulus 5. The mud is pumped down the drill pipe 4 by a drilling rig pump 40 (typically a bank of pumps). A pressure sensor 39 is conveniently located at the outlet of the drilling rig pump 40.

[0239] At a depth below the water surface S, which can be 50-1000 meters, but is currently around 2-400 meters in most cases, there is a first outlet 6, to which a return pump 7 is connected. The downstream end of the return pump 7 is connected to a return line 608. Return line 608 is connected to pipeline 220, which is connected to riser 1 and, via pipeline 223, to auxiliary pipeline 23. By selectively operating isolation valves 122 and 222, the driller can choose which fluid path is open. Pipeline 608 may have a flow meter 599 installed near pump 7.

[0240] The isolation valve groups 9 and 10 are arranged to facilitate isolation of the return pump 7 at either the upstream or downstream end or in between.

[0241] A pump bypass line 11 is also included. The pump bypass line 11 has an isolation valve 12. Thus, when valves 9 and 10 are open and valve 12 is closed, drilling fluid can be pumped to the surface via the return pump 7. Alternatively, when at least one (or preferably both) of the valves 9 and 10 are closed and valve 12 is open, drilling fluid can flow through the pump bypass line 11 under its own pressure.

[0242] An upstream pressure sensor 56 and a downstream pressure sensor 57 are arranged at the pump 7. Sensors 56 and 57 can be used to calculate the pressure generated by the pump 7.

[0243] In normal operation, mud is delivered to the mud handling system via line 220 with isolation valve 122 open and moves up the riser 1 to a riser mud level 606 at the bell joint 61 .

[0244] exist Figure 6 Also shown is a choke line 47 extending from the BOP 50. The choke line has an isolation valve 48 and a pressure sensor 49. The choke line 47 is connected to the drill choke 52. Downstream of the drill choke 52 is a pressure sensor 92.

[0245] At a position on the riser 1 higher from the riser outlet 6, but still substantially below the surface, an RSD 15 is arranged.

[0246] The riser may also have an additional sealing element in the form of an annular sealing element 16, which is a device with a similar function to the RSD, but is not designed to operate for any length of time with the rotation of the drill pipe 4. It is primarily designed to operate when the drill pipe 4 is not rotating. The RSD 15 is typically deployed and retrieved together with the drill pipe 4, while the annular sealing element 16 is installed together with the riser 1. More than one RSD may be installed, as may more than one annular sealing element. The annular sealing element 16 is designed to seal around a non-rotating drill pipe 4. The annular sealing element 16 can be used for shorter periods of time in place of the RSD, and can also be used with a rotating drill pipe 4. The RSD 15 and the annular sealing element 16 can be arranged in any order. It is also conceivable that the RSD is located within the annular sealing element.

[0247] The riser insert 616 is installed in the riser joint 36 located above the RSD 15. The connecting line 31 from the auxiliary line 23 is connected to the riser joint 36, located above the RSD 15 and below the riser insert 616

[0248] The axial cross-sectional opening area of ​​riser insert 616 is small compared to the internal cross-sectional area of ​​riser joint 36, typically 5% or less of the riser cross-section.

[0249] The bypass line 617 is arranged to bypass the RSD 15, the annular sealing element 16 and the riser 616. The bypass line 617 has an isolation valve 18 that can be opened to allow well fluid to flow through the bypass line 617.

[0250] The arrangement may have a conventional kill line 45 connected to the BOP 50 via an isolation valve 46. At the upper end of the kill line 45 there is a cutoff fluid pump 43 and a pressure sensor 44.

[0251] A boost line 23 extends from the surface to an inlet 24 on the riser 1. The inlet 24 is located substantially below the pump outlet 6, preferably near the lower end of the riser 1. The boost line 23 is equipped with one or more isolation valves 25. The boost line 23 is also equipped with a pressure sensor 72 to measure the liquid level in the boost line.

[0252] Any suitable pipeline, such as an interceptor line, a throttle or other existing line on the riser can be used as the fill line instead of the boost line 23. Alternatively, a dedicated fill line can be installed.

[0253] A filling pump 41 is arranged to pump liquid to the pressurizing line 23. A pressure sensor 42 is included in the line 23.

[0254] Figure 6The system also has an upper fill line 26 connected to the top of the riser 1, typically through an existing opening in the flow diverter 38. A pump 27 can pump mud through the fill line 26. A flow meter 28 is used to control the amount of mud pumped into the riser 1.

[0255] At the top of the riser 1, below the diverter 38, there is an outlet 61, commonly known as a bell-joint. This connects to a fluid line 60 which, when operating at full riser level, allows the drilling mud to be transported to a mud processing facility.

[0256] The riser is equipped with pressure and / or level sensors, such as sensors 29 and 130. Sensor 29 is a pressure sensor, while sensor 130 can be either a pressure sensor or a level sensor. Such sensors are well known in the art. Pressure sensor 29 is located below RSD 15 and annular sealing element 16. Sensor 29 can also be located on BOP 50. Alternatively, additional pressure sensor 51 can be located on BOP 50. Pressure / level sensor 130 is located above riser insert 616.

[0257] The pump 7 receives power from the surface via an umbilical cable 80. In addition to the valves, sensors and other equipment used in this embodiment, the umbilical cable also contains power and signal cables to operate and monitor the subsea valves and sensors located on the riser joints 33 and 36, as well as annular sealing elements, which are arranged at the Figure 6 between the outlet 6 and the surface S.

[0258] In the preferred embodiment, the pump outlet 6 is arranged on a first dedicated joint 33, extending between flanges 134 and 135. The RSD 15, the annular sealing element 16, the pressure or level sensor 30, the pressure sensor 72, and the branch lines 617, 220, and 223 with the isolation valves 222, 122, 32, and 18 are arranged on a second dedicated joint 36 extending between flanges 135 and 137. All of these components may alternatively be included in one joint of the flanges 134 to 137.

[0259] When the return flow is directed upwardly along the auxiliary line 23, a new top flow path is introduced, as will be described below.

[0260] To isolate pump 41 and ensure that no mud containing cuttings enters the pump, isolation valve 233 is closed. Isolation valve 232 is opened, and mud is pumped from pump 7 through lines 608, 220, 223, 23, and 236 to top flow meter 114 and through choke 113. From there, the fluid can be directed to a conventional mud handling system via line 159 with isolation valve 155 open and isolation valve 54 closed, or to drill rig choke 52 with isolation valve 54 open and isolation valve 155 closed. Top choke 113 has upstream and downstream pressure sensors 190 and 191.

[0261] The mud level in the riser 605 is normally maintained below the slip joint 3 , but for certain operations it may be raised to the bell joint 61 as shown at 606 .

[0262] Pressure sensors 190 and 191 are located upstream and downstream of the restrictor 113. These can be used to calculate the pressure drop across the restrictor 113.

[0263] The flow meter 114 is shown upstream of the flow restrictor 113. The flow meter 114 could also be located downstream of the flow restrictor 113. This is the case for all embodiments.

[0264] Only one return line is shown 608. The system may have a second return line to reduce the risk of blockage.

[0265] As an alternative to having a second return line 8, a bypass line 617 with an isolation valve 18 can be used as an instrument overpressure protection system. This is achieved by using the reading from the pressure sensor 29. When the pressure from the sensor 29 exceeds a predetermined set point, the isolation valve 18 will open.

[0266] To ensure that cuttings do not fall onto RSD 15 as the slurry containing cuttings is pumped into the riser above RSD 15, drilling fluid is pumped along auxiliary line 23 through line 31 into the cavity of riser 1 between RSD 15 and riser insert 616. Because RSD 15 seals the annulus, the flow is forced upward through the openings of riser insert 616, where it mixes with the drilling fluid above. The upward flow rate through riser insert 616 is sufficient to generate a rising velocity for the drilling fluid through the openings of riser insert 616, which is greater than the sliding velocity of the cuttings in the drilling mud. This flow rate is typically 100-500 liters per minute.

[0267] The driller may wish to use the boost line for its original purpose. This is easily accomplished by opening isolation valve 25 and closing isolation valve 32. For these operations, valve 222 is already closed. If clean mud is not pumped into line 31, some cuttings could theoretically enter the cavity between riser insert 616 and RSD 15. To avoid this, the driller can partially open isolation valves 25 and 32 to create the correct blocking effect, allowing a controlled flow simultaneously into the riser through inlet 24 and into the flushing cavity through line 31. Alternatively, the driller may choose to accept the risk of cuttings accumulating on top of RSD 15 rather than circulating them through line 31.

[0268] Figure 6 The system can also be Figure 5 The pipeline 550 with the isolation valve 551 is installed in the manner described, but Figure 6In the embodiment of FIG. 6 , suction is drawn from above the riser insert 616 .

[0269] Various possible operational procedures utilizing the above-described arrangement will now be described. Most procedures can be performed using any of the embodiments described herein, but specific embodiments may be necessary for certain procedures. It should be apparent from the explanation whether a specific embodiment is being referred to. Sometimes a particular component is given a single reference number, while the same component may be given different reference numbers in different figures.

[0270] Quickly convert from closed riser with pressure control to pumping riser with controlled mud level (CML).

[0271] The RSD 15 remains closed around the drill pipe 4 and, with the bypass line 18 closed, the pressure in the riser 1 below the RSD 15 can be controlled by adjusting the suction pressure of the pump.

[0272] If circumstances necessitate or facilitate a change in control mode to an open system, where the pressure in the well is controlled by the mud level in the riser, this can be quickly accomplished by opening the bypass line 18. There is no need to retrieve the RSD 15, as it can remain closed. Alternatively, if the RSD is designed for it, it can be opened to switch to an open system. In open mode, the fluid level in the riser 1 can be set to any height between the pump outlet 6 and the top of the riser 1 and controlled by the pump 7. Thus, the pressure above the RSD 15 can be adjusted to the same or higher pressure than below the RSD before the valve 18 in the bypass line 617, 17 is opened.

[0273] Of course, the riser closed mode can also be entered from the riser open mode by closing the bypass line 18 .

[0274] Measure the mud volume by switching between closed and open modes.

[0275] When the system is in closed mode—that is, when the isolation valve 18 of the bypass line 17 is closed and under pressure control—it is difficult to measure the mud volume in the system with high accuracy. Current measurement methods rely on cumulative flow measurements over time, i.e., the flow rate of mud flowing into the well versus the flow rate of mud flowing out of the well, and / or have uncertainties related to the effects of factors such as rig motion, heave, poor sensor resolution, and incompletely filled pipes on the upper volume measurement system. Flow measurements have inherent inaccuracies that, over time, combine to produce large uncertainties in volume estimates. Pumping the riser in open mode allows for higher-accuracy measurements.

[0276] By switching from closed to open mode and stopping flow into and out of the riser, any volume changes in the well can be accurately determined by the mud level in riser 1 under static conditions. When the pressure above the RSD in the riser is above, below, or equal to below the RSD, it is safe to switch from closed to open mode. When switching between modes, care must be taken to stay within the allowable drilling window, typically given by pore pressure and fracture pressure.

[0277] Additionally, the open mode allows very rapid detection of gain or loss conditions in the well by observing the riser fluid level during circulation.

[0278] When operating in closed mode, the present invention allows switching to CML open mode by opening valve 18 in bypass line 17 or allowing flow between above and below RSD 15 directly through RSD 15. This allows riser 1 to be used as a storage tank to perform flow checks or for any other reason to measure volume changes in the well under static conditions. The liquid level in the riser can be set so that when the drilling pump is shut off, the pressure above and below RSD 15 is different. For operational reasons, it may not be desirable to open the bypass line unless the pressure above and below the RSD is close to equal. In this case, the liquid level in the riser needs to be changed. This change in liquid level takes time.

[0279] As an alternative to the above, and also within the scope of the present invention, the mud return line 8 can be used as a reservoir to monitor the well when switching from closed mode to open mode and using the riser as a reservoir to monitor the well and any volume changes. To use this line 8, it must be partially evacuated to the correct level to obtain the required wellbore pressure. This can be done by opening valve 22 to allow the mud return line 8 to drain through branch line 20 into the riser above or below the RSD 15 or by opening valve 12 to bypass the line 11 (or for embodiments such as the RSD 15) through the pump. Figure 4 As shown, by opening valve 22) through branch line 19.

[0280] Because return line 8 has a smaller diameter than riser 1, any volume change in the well will result in a larger change in the fluid level in return line 8 than in riser 1. Therefore, this method provides a more accurate reading of volume change than when using riser 1 as a storage tank. Because the fluid level in return line 8 changes more rapidly than when using riser 1, the pressure exerted on the well during an influx will increase rapidly as the fluid level in return line 8 increases. Since the well diameter is larger than the diameter of mud return line 8 in most situations, except when drilling very narrow holes, the system will have a self-regulating effect on preventing influx.

[0281] As a second alternative to the above, boost line 23 can be used as a storage tank to monitor the well. To use this line, valve 25 must be opened and pump 41 must be stopped. The liquid level and associated pressure in boost line 23 will now be equal to the pressure in the riser below the RSD. The actual liquid level in the boost line can be verified at any time using boost line pressure sensor 72. Once the desired level is reached, the boost line can be used to monitor the volume in the same manner as an open riser. For this purpose, boost line pressure sensor 72 can be used.

[0282] Reduces wear on the RSD by reducing pressure differential

[0283] In the closed mode, the pressure above the RSD 15 can be equal to or lower than the pressure below the RSD, but can also be maintained above the pressure below the RSD in certain operating modes. This ensures that any leakage from above the RSD to below through the RSD is contained, so the pressure above the RSD is an additional safety measure to prevent uncontrolled flow of well fluid to the surface.

[0284] However, the higher the pressure differential across the RSD 15, the greater the wear on the RSD. To reduce wear, the pressure differential should be kept low.

[0285] Level / pressure sensors 29 and 30 are used to monitor the pressure below and above the RSD 15. The permissible pressure variation below the RSD 15 is determined by the operating parameters of the well, which dictate that the wellbore pressure must be maintained within certain limits, such as the formation's fracture pressure and the formation's pore pressure, as well as associated safety margins. If the pressure differential across the RSD 15 exceeds a predetermined limit, the mud level above the RSD 15 is reduced by opening the bypass line isolation valve 18 in a controlled (gradual) manner or by increasing the leakage rate by adjusting the RSD until the pressure differential is again below the predetermined limit.

[0286] If the pressure differential falls below a predetermined limit, the mud level above the RSD 15 is raised by filling mud into the riser 1. This can conveniently be done via the fill line 26 or via the lower fill line 23 and branch line 31.

[0287] Monitoring RSD wear

[0288] Since the RSD 15 is subject to wear during use, in particular due to the rotation of the drill rod relative to the RSD, it must be replaced at regular intervals. In the absence of any monitoring of the condition of the RSD, the periodic replacement required will be based on the expected life of the RSD 15.

[0289] The present invention makes it possible to monitor the wear of the RSD 15, even when only a single RSD 15 is used, without the need for an external supply of fluid. This is based on the fact that as the RSD 15 wears, leakage from the RSD increases. By using level / pressure sensors 29 and 30 to monitor the pressure below and the pressure or level above the RSD 15, and by tracking the flow of mud into and out of the well, as described above, the system of the present invention can monitor mud leakage from the RSD 15, thereby monitoring the wear of the RSD. The measured leakage rate can also be combined with measurements of the RSD, such as the hydraulic pressure or spring load on the RSD, to determine the wear state.

[0290] Reduce wear on RSD

[0291] As a further example of the above-described RSD 15 wear monitoring, the system of the present invention may also be used to reduce wear on the RSD 15 .

[0292] It's well known that wear on an RSD depends on the friction between the drill pipe and the RSD; the higher the friction, the higher the wear. Friction depends, among other factors, on the force the RSD is set to exert on the drill pipe. The greater this force, the greater the friction. Although higher forces and higher friction lead to increased wear, the RSD is set to exert a relatively high force against the drill pipe. This is to avoid excessive leakage through the RSD.

[0293] The present invention allows leaks to be monitored on an RSD. Therefore, a certain amount of leakage can be tolerated as long as the leakage does not exceed a predetermined limit. By adjusting the settings of the RSD to be close to the maximum permissible leakage rate, the wear rate will be reduced and the service life of the RSD will be extended.

[0294] Compensate for increased leakage on RSD

[0295] In the present invention, when in the pumped riser closed mode, there will be leakage at the RSD 15. In at least one operating mode, this leakage will be from top to bottom and will cause the drilling fluid level in the riser to drop. This can be compensated by filling the riser with mud to maintain a constant mud level above the RSD. In conventional drilling, the riser is filled with drill pipe or a booster line. However, with the present invention, this is not possible. Therefore, filling is completed through the upper fill line 26 or the lower fill line 23 and branch line 31, all of which end above the RSD.

[0296] Using the present invention, the leakage monitoring described above can be used to determine the volume of slurry that must be filled into the riser above the RSD.

[0297] Compensation for increased leakage, for example caused by wear of the RSD, can also be achieved by increasing the force with which the RSD presses against the drill pipe. However, according to the present invention, the mud level above the RSD and the filling rate of the riser above the RSD are taken into account when determining the pressure with which the RSD presses against the drill pipe 4. According to the present invention, leakage can be compensated by filling the riser at a controlled rate as described above and by regulating the pressure of the RSD against the drill pipe. Thus, the mud level above the RSD 15 in the riser 1 can be maintained at a constant level. For this purpose, a pump 27 and a flow meter 28 are used. This process can be fully automated and controlled by an algorithm.

[0298] Stop RSD Leakage

[0299] During certain operations, for example when a circulation kick occurs, or in a (static) connection process, when the pressure above the sealing element during operation approaches the pressure under dynamic conditions, but when lower than the pressure under static conditions, leakage by the RSD 15 is often unacceptable. In these cases, leakage can be stopped, or at least made to reach an acceptable range, by increasing the force of the RSD 15 pressing on the drill pipe 4 so that it and the drill pipe maintain a tight seal. How to increase the RSD force on the drill pipe 4 will depend on the type of RSD, and therefore does not belong to the scope of the present invention. This process can be automatically completed by using a controller.

[0300] Dealing with influx and gas in slurry

[0301] In normal operation, whether in closed or open mode, mud in the well is returned through return pump 7. However, if gas is flowing into the well, it is often undesirable to allow the gas to flow through the pump. In this case, valves 9 and 10 are closed. Instead, valve 21 is opened, allowing the gas to flow through the lower branch line 19 and up to the choke 13.

[0302] Alternatively, the inflow can be allowed to flow through the pump bypass line 11 to the throttle.

[0303] Gas coming up with the mud can accumulate below the RSD. In order not to release this gas in an uncontrolled manner when the RSD 15 is opened or pulled, the bypass line 17 is opened to allow mud to flow downward from above the RSD with the aim of flushing the gas downward, through the pump 7 and into the mud return line 8 in a controlled manner. Depending on conditions, this may involve increasing the liquid level above the RSD 15 to allow the pump 7 speed to be higher, thereby creating a greater downward flow. At the same time, the riser 1 is filled from the top above the RSD (as described above). As a result, a large amount of downward flow is generated in the riser 1 through the bypass line 17. The accumulated gas is caught in the mud flow and is flushed through the return pump 7. This fluid continues to flow upward along the return line 8. At the surface, it can be conveyed to a mud / gas separator for safe disposal of the gas.

[0304] When the speed of pump 7 is increased, thereby reducing the pressure below RSD 15, the pressure above the well will be reduced, and the BOP may be closed to ensure that the pressure in the well does not drop below acceptable limits. When closing the BOP, known methods can be used to ensure sufficient pressure below the BOP, such as opening a valve in a mud-filled kill line. Methods for maintaining the well below the BOP above an acceptable fluid level are not part of the present invention.

[0305] Preparing for Riser System Renovation

[0306] In some cases, the functionality of the RSD 15 and possible additional closure devices, such as the annular sealing element 16, may be present in a riser joint intended for other drilling activities, such as surface back pressure (SBP) or riser gas handling (RGH). With the system of the present invention, riser joints used for these other activities can be used and modified to be controlled using the control system described above and some or all of the functionality of the system of the present invention.

[0307] The riser joint used for these other well activities can be additionally fitted with additional connections and equipment to facilitate dual use as an SBP or RGH and as part of the system of the present invention. The riser joint used for other operations will initially have its own control lines coming to the surface via an umbilical. In the present invention, it can be equipped with a number of features that allow it to be reconfigured by adding pipelines and other hardware required for use as part of the system of the present invention. Most notable is the reconfiguration that allows the existing system to receive control functions from the surface via the umbilical of the newly added pumping riser equipment. The dual use of the riser joint can be expanded to include facilities for mounting a riser pump 7 and associated pressure sensors 29 and outlets 6. These facilities can be optimized between the two uses.

[0308] Use chokes and pumps simultaneously to control wellbore pressure

[0309] In some cases, when operating this system, the total pressure in the wellbore at full riser, or ECD, will be too high when circulating, but too low when not circulating. Therefore, pressure control is needed. Other influences, such as cuttings, may also cause the need to control pressure. In this case, pressure needs to be increased when the mud column is at rest (i.e., not circulating), and excess pressure needs to be removed when circulating. There are many reasons why a driller may need to control pressure. This operating mode may be a planned mode, the mud weight may change more than expected during the operation, the wellbore conditions may have changed, such as a sudden increase in pore pressure when drilling a pressure ramp, or many other reasons. Regardless, in this situation, the driller may want to control the downhole pressure using a choke, a pump, or a combination of the two.

[0310] Using a choke or pump alone to control downhole pressure in closed-hole mode is known in the art. However, in some situations, the driller may want to switch between adding and removing pressure. This refers to the pressure in an open riser filled with mud. For efficient and safe operations, the transition between pressurization and depressurization should be seamless. There are many operational scenarios that may be relevant. Two examples are mentioned below.

[0311] When the connection is made, circulation is stopped and therefore the dynamic component of the ECD is removed. Downhole pressure drops because there is no flow through the annulus. This pressure drop needs to be compensated for by increasing the standpipe pressure when the drilling pumps are slowed down and reducing the standpipe pressure when the drilling pumps are speeded up. When the system is operating in a depressurization mode, the driller may encounter a kick that needs to be circulated out. In such a process, additional pressure needs to be applied to the system during the circulation process to account for the low density of the gas being circulated out. The methods and concepts for handling kicks are known to those skilled in the art. For certain combinations of mud weight and kick size, the driller needs to increase pressure at the beginning of the kick circulation and remove pressure at the end of the kick circulation.

[0312] For this situation, the driller can operate the pump 7 and the choke 13, 113 simultaneously and in series. Figure 4 、 5 or 6 systems, in which the pump eliminates pressure and the throttle increases it. By adjusting the speed of the pump and the opening of the throttle in a controlled manner, any negative or positive pressure can be generated in seconds within the physical limitations of the operation.

[0313] During this process, when the pressure built up by the choke exceeds the pump's discharge pressure, the driller has the option of isolating the pump by closing valves 9 and 10 and opening valve 12. This is particularly important if the system pressure approaches the pump's rated pressure, or if a significant amount of gas is suspected to have entered the pump, potentially affecting system operation. While the driller can manually control the system's operation, the system typically incorporates an automated control system that sets the choke and pump in a master-slave configuration, using sensor readings to maintain the desired wellbore pressure. This type of control system for wellbore pressure is common in surface backpressure operations. Adding subsea pump control and mud compressibility in the return line to this control system, and automating the closing of the pump isolation valve and the opening of the pump bypass line, is well known to those skilled in the control system art.

[0314] Change the riser level or change the slurry above the RSD

[0315] During closed system operation, the driller may want to change the mud in the riser above the closed RSD 15. There are many reasons why a driller might want to do this. Here are a few examples. Perhaps the driller wants to open the RSD 15, and the mud level above it is too high. Perhaps the driller wants to add mud weight to the upper portion of the riser. Or perhaps the driller wants to clear cuttings from the upper portion of the riser.

[0316] With the system in closed mode and the standpipe outlet 6 isolated, the upper standpipe suction line 550 is used to draw suction from the standpipe. A top fill pump, or boost line, can simultaneously be used to fill the upper standpipe. This will obviously facilitate changing the mud level or changing the mud.

[0317] Pressure above the riser can be controlled by varying the mud weight above the RSD 15, the riser fluid level, or a combination of both. The concept of a riser cap is well known in other drilling operations, where a kill line, choke line, or boost line is used to vary the mud weight in the riser, creating a system with two mud weights, typically to increase wellbore pressure. With such a system, drillers cannot circulate fluid down the drillpipe and maintain the integrity of the riser cap. In this system, by utilizing the outlet below the RSD 15, drillers can circulate fluid down the drillpipe and up the annulus while maintaining the integrity of the upper riser cap and without diluting it with mud in the annulus. Because the upper mud is heavier, the heavier mud tends to migrate downward and mix with the lighter mud below. This can be controlled by allowing only a small opening through or through the RSD 15—large enough to provide adequate pressure flow but small enough to allow only limited fluid flow. Leakage rates from top to bottom can reach levels of 1-50 liters per minute, which can be easily managed by the driller.

[0318] During drilling, gas may have accumulated below RSD 15. If downhole pressure permits, before opening the RSD, as a safety precaution, the mud level in the upper portion of the riser can be lowered to prevent any gas from migrating up the riser.

[0319] When handling a kick, there will be a period during the kick cycle when gas will be present below the RSD 15. To avoid the problem of return line blockage during this period, the system can be equipped with an overpressure protection system that acts as a bypass line through the RSD, allowing pressurized gas to enter the upper riser. To reduce the risk of negative consequences of this event, the upper riser suction line 550 can be used to lower the riser liquid level. The upper riser then acts as a tall separator, with the distance from the liquid level to the surface much higher than a traditional separator. This reduces the risk of a riser unloading event.

[0320] Operate in open mode - quickly revert to closed mode

[0321] It is foreseeable that, except Figure 6 In addition to the modes described above, the primary operation of the present invention involves operating the system in an open mode, but switching to a closed mode at regular or irregular intervals. This switch to closed mode may be planned, such as to set pressure at a connection, or unplanned, such as during a well kick, when it is desirable to quickly return to an overbalanced state. The required pressure may be a level that can be managed by the pump alone, or it may be a pressure that requires the addition of a choke, potentially requiring the pump and choke to operate in tandem. This operation has been described in detail above.

[0322] When the RSD is operating in open mode, the driller can quickly transition to closed mode by closing the bypass line isolation valve or, depending on the RSD design, by closing the RSD itself. Closing the bypass line can be accomplished in 1 to 5 seconds. The RSD can also be configured to close in 1 to 5 seconds. For the driller, switching from open to closed in 1 to 5 seconds is extremely fast and does not impose any operational restrictions. With this unique feature, the driller can take advantage of all the benefits of an open CML system while being able to quickly transition to a closed system to utilize its efficiency or safety features.

[0323] Use a bypass line or RSD as a choke device to protect the casing shoe

[0324] When operating in closed mode, a continuous increase in riser and downhole pressure can occur due to blockage, equipment misoperation, or similar conditions. In this situation, casing shoe pressure may exceed the fracture pressure, and the formation may rupture, leading to severe losses. To prevent this, the RSD bypass line isolation valve, or the RSD itself, if designed to reduce preload, can act as a simple choke, allowing riser pressure to be released in a controlled manner before the casing shoe ruptures. The accuracy of the choke effect will not reach the quality of a conventional drilling choke, but this is acceptable to the driller, as the primary goal is to utilize the choke effect to avoid casing shoe damage, but in a controlled manner rather than rapidly releasing pressure, which could fall below pore pressure and have adverse effects. If the bypass line isolation valve is a ball valve, those skilled in the art will understand how to partially open such a valve to act as a choke. Given that the normal operating mode of the invention is to lower the riser fluid level to a sufficient level to reach the drilling rig, fluid can in many cases be safely bypassed to the riser above the RSD. There is no description in the prior art of intentionally operating a closed riser system with a reduced riser liquid level.

[0325] Calculate and compensate for temperature-induced density effects when not drilling into the bottom layer

[0326] When drilling out of the wellbore, especially in high-temperature wells, the drilling mud in the annulus is heated by the formation. As a result of this heating, the density decreases, and the volume of the mud in the hole increases. By using the riser as a storage tank in open mode and lowering the fluid level in the riser, the volume change of the mud in the wellbore can be continuously monitored. Any equipment entering or leaving the well has a volume that can be pre-measured and factored into the mud volume measurement. Since the volume of each piece of equipment is very accurate, and the well geometry and dimensions are known, the change in volume can be used to calculate the change in overall density. The temperature of the formation into which the well is drilled is known and can be measured or estimated during drilling. Based on this, the temperature profile of the mud in the wellbore can be calculated. By combining this temperature measurement or estimate with the known physical properties of the mud and the well geometry, the temperature profile over time when not circulating on the drillpipe can be calculated. Changes in downhole temperature will cause the mud's density to decrease as it heats up, which in turn causes the mud's volume to expand in the wellbore and an associated pressure drop. The expanded volume will expand from the smaller diameter wellbore into the larger diameter riser, so the net effect will be a drop in wellbore pressure. The temperature-induced drop in wellbore pressure can be calculated based on known mud properties, volume measurements, and observed or predicted formation temperatures and the associated downhole temperature profile of the mud in the well. To compensate for this drop in wellbore pressure, the mud level in the riser can be increased to achieve a near-steady wellbore pressure.

[0327] If a sudden inrush occurs during this process, the other methods described in this article can be used to shut down the riser and safely handle the inrush.

Claims

1. A method of operating a drilling system in an open mode and a closed mode, comprising: - providing a standpipe having a return outlet connected to a return pump, the return pump being arranged to pump fluid from the standpipe through the return line to above the surface of the body of water; - positioning a sealing element above the return outlet in the riser; - providing a bypass function by providing a bypass line with a selectively controllable isolation valve around the sealing element or through the sealing element, wherein the sealing element is designed to open to allow the passage of fluid; - arranging a throttle downstream of the pump; - operating in a closed mode, wherein the sealing element is substantially closed to prevent fluid from flowing therethrough; - when the drilling system is in closed mode, returning drilling fluid from the pump through the choke; - adjusting the throttle and / or the pumping rate of the pump to regulate the pressure in the riser below the sealing element; - Switching between open and closed mode is performed by opening or closing the sealing element or by opening or closing the bypass line, respectively.

2. The method according to claim 1, characterized in that The bypass line is connected to the outlet of the riser, and the outlet connected to the bypass line and the reflux outlet are both independent outlets.

3. The method according to claim 1 or 2, further comprising: - providing a bypass line around the pump; - isolating the pump from the bypass line; - Allow drilling fluid to flow through a bypass line to the pump; - Adjusting the restrictor to regulate the pressure in the riser below the sealing element.

4. The method according to claim 3, further comprising: A bypass line of the pump is connected to the return line between the pump and the restrictor.

5. The method according to claim 3, further comprising: A bypass line from the pump is connected to the standpipe at a separate outlet from the return outlet.

6. The method according to claim 3, further comprising: A bypass line of the pump is connected to a portion of the return line that extends from the return outlet to the pump.

7. The method according to claim 1, further comprising: In closed mode, switch between: - by operating the pump, removing the pressure below the sealing element compared to the equivalent pressure of a full mud column in the riser, and - By operating the throttle valve, the pressure below the sealing element is increased compared to the equivalent pressure of a full mud column in the riser.

8. The method according to claim 7, further comprising: By operating the combination of the choke valve and the pump, back pressure is added to the return line to avoid slugging or foaming during the kick relief process.

9. The method according to claim 1, further comprising: The return line is provided as a separate line.

10. The method according to claim 1, further comprising: The step of switching to the open mode is prepared by reducing or increasing the pressure below the sealing element until the pressure above and below the sealing element are substantially the same.

11. The method according to claim 1, wherein In the open mode, the pressure in the well is controlled by adjusting the level of drilling fluid in the riser using the return pump.

12. The method according to claim 1, characterized in that The pressure in the riser below the sealing element is monitored by a pressure sensor.

13. The method according to claim 1, wherein The liquid level in the riser above the sealing element is monitored by a level sensor or a pressure sensor.

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