Multi-Mode Pumped Riser Arrangement and Methods

This patent application is a continuation of U.S. patent application Ser. No. 18/425,384. U.S. patent application Ser. No. 18/425,384 is a continuation of U.S. patent application Ser. No. 17/770,510. U.S. patent application Ser. No. 17/770,510 is a national-stage application of International Application No. PCT/NO2020/050266. International Application No. PCT/NO2020/050266 claims priority from Norwegian patent application No. 20191299. Each of the above-referenced applications is incorporated by reference.

The present invention relates to a riser system and various operational methods to facilitate greater versatility when performing hydrocarbon drilling related operations near or at a bottom of a body of water.

More specifically, the invention relates to a so-called pumped riser, i.e. a riser having an outlet from the riser at a depth below the surface of the body of water, where the outlet is coupled to a return pump to return drilling fluid from the riser to the surface.

Pumped riser operations can be of the closed type, which means that the annulus of the riser is closed by a sealing element above the outlet to a return pump and that the pump is able to regulate the wellbore pressure by (rapidly) changing the pressure at the riser outlet by changing the pressure at the inlet of the return pump.

Pumped riser operations can also be of the open type, which means that the annulus of the riser is open to atmosphere and that the top of the riser is at approximately atmospheric pressure. The return pump of such a system also adjusts the pressure at this outlet of the riser which is given by the level of liquid, such as mud, in the riser in order to regulate the wellbore pressure. Such systems are sometimes referred to as CML (Controlled Mud Level) and have proven to have multiple benefits operating with a riser level below the slip joint during the drilling process, but also during other phases of well-construction, completion, production or abandonment.

Detecting influxes as early as possible is one of the most critical elements of the drilling process, as an influx that gets out of control could have fatal consequences. Any method that allows the driller to identify a small an influx as early as possible, and the ability to quickly respond to it is therefore of great interest to the industry.

Further, when operating in closed mode, drilling fluid volume control relies on observing flow measurements over time and combining these measurements with volume measurements of drilling fluid in the drilling rig's active system. All these measurements are associated by measurement uncertainties related to the accuracy and repeatability of the sensor measurement. This is also true for measurements done under static conditions in closed mode. Alternatively, the system could be connected to the topside trip tank and flow measurements combined with trip tank measurements could be used to determine the volume. With the first alternative, the total volume error increases with time. With the second alternative, the trip tank measurement accuracy is affected by rig motion, and the accuracy of the trip tank volume sensors. In addition, the lines bringing the drilling fluid to and from the trip tank are not full of mud at all times, which also causes uncertainty to the total volume measurements.

On the other hand, with CML in static conditions (i.e. when not circulating), it is possible to isolate the riser and use it as a tank to monitor the wellbore for changes in drilling fluid volume. Using the pressure sensors (which are generally very accurate) or other accurate methods for determining liquid/gas (air or other gas) interface, makes is possible to monitor the volume in the riser and thereby use this as a very accurate method for determining any changes in well fluid volume (influx, loss, temperature effects, wellbore breathing or other). In such a system there are no lines with any void and all volume is measured very accurately at all times. Also, with the liquid level below the slip-joint, the volume measurement is not affected by the change in volume of the riser due to the change in slip joint length associated with rig motion.

In regular drilling operations with a closed riser according to prior art (i.e. with some form of sealing element in the riser), the riser above the sealing element is full. The differential pressure across the sealing element is dictated by static pressure of a full riser above the sealing element (Although this will be affected by slip joint motion) and the operating pressure below the sealing element. With a given mud weight and setting depth of the sealing element, there is no way of actively controlling the pressure above the sealing element. The differential pressure across the sealing element will affect wear and thus lifetime of the sealing element. The pressure above the sealing element together with the pressure rating of the sealing element will also dictate the minimum allowable pressure below the sealing element.

The leakage rate across a sealing element in the riser at a given differential pressure across the sealing element can be an indication of the wear status. Some sealing elements also use methods for a variable pressure/force acting radially on the sealing element. In such cases the leakage will vary with wear, pre-charge/force and potentially other factors. At any rate, for a given set of the rest of the parameters, the leakage rate at a given differential pressure across the sealing element can be an indication, or in some cases can be correlated to, the actual wear and thus the remaining lifetime. With a riser full to surface (to the bell-nipple), affected by varying volume associated with the slip-joint motion, it is difficult to measure the leakage rate accurately.

Also, the motion of the slip joint means that there is not a constant height from top of liquid level to sealing element even if the system is kept full at all times.

For the sealing element it may be possible to adjust operating parameters, such as, e.g., hydraulic or spring actuated radial force, during operation. Adjusting these adjustable operating parameters will affect leakage rate across the sealing element at a given set of operating parameters. In general, operating with a higher leakage rate will result in a lower wear rate.

In typical SBP (Surface Back Pressure) applications, the operating pressure below the sealing element is higher than (or equal to) the pressure above the sealing element. In a pumped riser solution as described in prior art, the pressure below the sealing element is lower than (or equal to) above the sealing element in normal operating conditions.

In the SBP system, it is typically a desire to avoid having significant leakage of drilling fluids across the sealing elements from below to above.

With a pumped riser in closed mode, it can for some operations be critical to ensure that there is zero or very low leakage across the sealing element but for other operations a significant leakage may be allowed, or even desired. However, in prior art there is no reliable method to achieve this variation in leakage rate. Moreover, there is no reliable method to verify that the desired leakage rate across the sealing element is achieved.

In the known systems the component with the lowest pressure rating will dictate the maximum size and intensity of an influx (kick) that the system can handle. This component is often the return pump. Increasing the pressure rating of the pump will have great implications on weight and size of the pump. In addition, there can be concerns about wear and what implications wear has on pressure integrity. For other components in the system, the wear rate is significantly less and more predictable and therefore typically not a concern from a pressure integrity perspective. Some pump systems may also have sealing functions between the process media and ambient sea that are acceptable for normal operations, but that may be considered an issue when circulating out a kick.

The pump type being used could be according to any pump principle such as centrifugal, positive displacement, eductor and so on.

Current Controlled Mud Level (CML) systems have mainly been operated in open mode.

CML systems are built with conventional auxiliary lines such as kill lines, choke lines and BOP hydraulic fluid lines, required hardware for CML and auxiliary lines needed to operate CML operations. The CML hardware is not built, or ready to be retrofitted, with the auxiliary lines, flow lines and other hardware that is needed to operate SBP

On the other hand, an SBP system is built with conventional auxiliary lines such as kill lines, choke lines and BOP hydraulic fluid lines, in addition to the lines needed to operate the Surface Back Pressure system. Surface Back Pressure hardware is not built, or ready to be retrofitted, with the auxiliary lines other hardware that are needed to operate CML.

The operator must therefore choose which type of system to be used before manufacturing and installing the system. After the system has been installed, it is both expensive and time consuming to convert to another type of system as it will require extensive hardware modifications, or even having to procure new hardware components.

In conventional CML, a top-fill pump pumping drilling fluid into the top of the riser and/or drilling fluid pumped down the boost line to the top of the BOP is utilized to fill the riser. With a closed riser, the riser above the sealing element cannot be filled during operations from the boost line with a conventional set-up, as the entry point is located below the sealing element. Most rigs do not have a top-fill pump installed and the rig's trip tank pumps are typically not well suited for such a filling functionality in a controlled manner. Filling the riser above a closed sealing element is therefore not practicable with existing solutions.

Gas that comes up with the mud may accumulate below the closed sealing element.

When the sealing element is opened or retrieved the accumulated gas would be released up the riser. The result is that gas flows out of the riser at the top and may spill out on the drill floor or cause an explosion hazard.

Some systems with sealing elements use two or more sealing elements in series spaced vertically along the riser and inject a barrier fluid between the seals at a pressure higher than the pressure below the lower sealing element. This ensures that no well fluids pass the sealing elements to flow into the riser above the sealing elements. In such a system it is possible to measure the leakage rate of barrier fluid into the system accurately. However, it may be impossible, or at least very difficult, to accurately measure how much liquid that goes upwards and how much liquid goes downwards at any given time.

Prior art riser systems have generally no means of detecting the position of a detected influx by measuring the density of the mixture of gas and mud and use this as a means for deciding when to isolate the pump and when to circulate out an influx using the closed riser system.

Sometimes a formation with a very narrow drilling window is encountered. A narrow drilling window means a formation where the difference between the minimum and maximum allowable pressure, typically given by the pore pressure and the fracturing pressure respectively, of the formation is very small. This means that only small pressure variations in the well are acceptable during operations. The existing topside choke on the rig is in many cases manual, or if automated, it does not have the ability to keep the pressure upstream the choke very accurate when the composition of the fluid flowing through the choke changes. Also, drilling contractors often have internal policies against using rig chokes for anything but well control events. For Surface Back Pressure operations today, an additional topside choke system is commonly used as a part of the Surface Back Pressure set up. Typically, the Surface Back Pressure choke is not the rig's well control choke, for fear of wearing it out. A significant piping network with separate flow paths involving, sensors, flow meters, valves piping etc. need to be constructed for typical Surface Back Pressure (SBP) operations.

On the one hand conventional pumped riser open mode CML systems are built with the infrastructure to support the needs of the CML functions including a dedicated umbilical. On the other hand, conventional Surface Back Pressure equipment is built with a dedicated umbilical to provide the required support functionality for that type of system. This covers electricity, hydraulics, sensor signals etc. CML systems and SBP systems have been seen as competing systems, where the driller choses one or the other. A combination of the two types of systems has not been described in prior art hitherto.

In line with the above, no prior art has suggested how to facilitate easy conversion of a system designed to perform CML to a system designed to perform SBP, or vice versa while using the same basic main building blocks. Prior art does also not describe a system that enables the driller to use a single hardware setup to perform both SBP and CML operations and that can switch seamlessly between the two methods in the matter of seconds or minutes.

In some cases, during well-construction, the encountered formation pressures are higher than what was anticipated when making the drilling plan. These higher than anticipated pressures may cause an influx and need to be dealt with before normal operations can continue. In order to deal with these pressures using conventional 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 closing the Blow Out Preventer is limited by what is possible to achieve from the hydrostatic pressure of a riser column full of drilling mud.

In the present invention, several methods are shown that allow the driller to achieve a wellbore pressure that is higher than what could be achieved with prior art systems, which are doing this either by coupling the pumped riser system with a choke or by changing out the mud in the upper portion of the riser, above the riser sealing device, with a heavier mud, i.e. creating a column of heavier mud in the upper part of the riser. This column is sometimes called an “Upper Riser Cap”.

Prior art closed loop systems are either for pumped riser systems where the system is used to reduce the wellbore pressure, or for back-pressure systems where a topside choke is used for adding wellbore pressure. In some situations, the desired wellbore pressure may be such that for a given mud weight and dynamic annular friction drop, pressure needs to be removed while circulating, but added when not circulating. A system able to seamlessly switch between removing and adding pressure in a controlled manner using a subsea pump and a topside choke in combination has not been described in prior art

Based on prior art and techniques currently in use in Surface Back Pressure operations, it is either known, or obvious to the person skilled in the art, how an influx of hydrocarbons could be circulated out of the well using the riser sealing device, a return conduit and a topside choke. During such a process, a so-called well control event, it is important that the pressure in the wellbore is not too low, as it would allow further influxes of hydrocarbons, and not too high, as it would exceed the formation strength and fracture it. This lower limit is often referred to as the pore pressure and the upper limit as the formation fracture pressure, or in some cases just as the fracture pressure. In certain cases, the difference between the pore and fracture pressures is low, often referred to as a “narrow drilling window”. During the process of circulating out the influx, where the objective is to keep the pressure in the wellbore between the maximum and the minimum limits, gas at high pressures is being circulated up the annulus. Due to the gas expansion effect with changing pressures, this means that the amount of additional pressure that needs to be applied during the well control event will typically increase throughout the process. A person skilled in the art is familiar with the above concepts.

When performing well-construction using a pumped riser system, the driller will typically choose a mud weight that is higher than what they would do during conventional drilling. Because of this, the pressure applied to the wellbore from a hydrostatic column to surface, would often be close to, or even above, the fracture pressure. During a well-control event, as the gas expands and takes up more space in the annulus, the weight of mud on the wellbore is reduced, with an associated wellbore pressure drop. In conventional well-control this is compensated for by increasing the back-pressure applied by the choke. The above means that for a well-control event with a pumped riser system, one might need to subtract pressure compared to that of a full riser at the start of the process, and then reduce the amount of subtracted pressure during the well-control circulation. Prior art does not describe how such a well-control event would be handled. The present invention describes how such an instance could be handled using the riser pump to reduce pressure, in some cases in combination with a choke either to apply additional pressure to compensate for the loss of hydrostatic associated with gas expansion. The choke used in combination with a subsea pump during well control could also be used to mitigate any slugging effects in the return line, as the choke could be used to ensure that the pressure in the return line is kept high enough to ensure a low Gas Void Fraction upstream the choke.

In some situations, without having taken 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 while circulating, but added when not circulating. A system able to seamlessly switch between removing and adding pressure in a controlled manner using a subsea pump and a topside choke in combination has not been described in prior art

Prior art does not describe how volume of liquid above the riser sealing element can be replaced and/or how the level can be altered during operations with a pumped riser system. This could be useful to do during operation for many reasons, such as to control the pressure above the riser sealing element, or to change out cuttings-laden mud with clean mud prior to periods of stand-still.

Prior art does also not describe how, for a pumped riser solution, it is possible to use liquid from above the riser sealing element to flush the return line with clean mud, or to maintain circulation in the return line without pumping down the drillstring or one of the auxiliary lines

In prior art it is described how a pumped riser system can be operated without a dedicated return line using the riser as the return line, where the pump draws suction from below the riser sealing element and discharges above the riser sealing element, creating a differential pressure from above to below the riser sealing element. One of the key advantages cited for such a system is that it has less cost than other pumped riser systems as it does not require modifications to riser joints above the pumped riser components, and that there are no changes to the conventional mud return flow path topsides. For such a system, there are concerns about cuttings accumulating on top of the riser sealing element, and therefore prior art systems have described deflector and flushing systems to overcome this issue. Also, in such a system, the level in the riser is always full, and it is not possible to perform any operations with a reduced riser level.

Prior art also describes using one of the auxiliary lines as a return conduit, either for the entire well-operation, effectively rendering the return conduit incapable of performing its initially intended purpose for the entire operation, or as a contingency, for instance if handling an influx and circulating up the auxiliary line, potentially coupled to a topside choke, whilst handling the influx event.

In prior art pumped riser systems without a dedicated return line, the riser needs to remain full at all times as there is no way of lowering the riser level. If the system is then operated in open mode, the full riser pressure is applied on the well.

Another method for reducing the cost of rig integration described in prior art is to use an existing auxiliary line, such as the boost line, as a return line. When performing such modifications in prior art, the original functionality of the existing auxiliary line has not been available when performing closed riser operations.

Some prior art examples are shown in:

US 2003/066650 describes a drilling system for drilling subsea wellbores includes a tubing-conveyed drill bit that passes through a subsea wellhead. Surface supplied drilling fluid flows through the tubing, discharges at the drill bit, returns to the wellhead through a wellbore annulus, and flows to the surface via a riser extending from the wellhead. A flow restriction device positioned in the riser restricts the flow of the returning fluid while an active fluid device controllably discharges fluid from a location below to just above the flow restriction device in the riser, thereby controlling bottomhole pressure and equivalent circulating density (“ECD”). Alternatively, the fluid is discharged into a separate return line thereby providing dual gradient drilling while controlling bottomhole pressure and ECD. A controller controls the energy and thus the speed of the pump in response to downhole measurement(s) to maintain the ECD at a predetermined value or within a predetermined range. This solution is only capable of performing closed riser operations.

WO 2013/055226 describes a device and method for control of return flow from a borehole where drill fluid is supplied from a surface rig via a multi section drill string to a bottom hole assembly, the drill pipe sections having tool joints that include an enlarged outer diameter portion, and where an annulus is formed between a pipe and the drill string, and where the annulus is in fluid communication with or forms part of a return path for the drill fluid, and where a choke is positioned in the annulus, and where the length of the choke exceeds the distance between the enlarged outer diameter portion of two adjacent tool joints. This solution is also only capable of performing closed riser operations.

WO 2017/195175 describes a subsea drilling method for controlling the bottom hole annular pressure and downward injection rate during mud cap drilling operations from a mobile offshore drilling unit with a low-pressure marine riser and subsea blowout preventer. The method called controlled mud cap drilling uses the hydrostatic head of a heavy annular mud (fluid) managed or observed in order to balance the highest pore pressure in the well and to control the injection rate, by using a subsea mud lift pump and a control system to regulate the process. In this system, a riser sealing device could also be included. The intention of the riser sealing 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 pressures.

GB 2502626 describes a system for controlling the fluid pressure of a borehole during drilling of the borehole. A drill pipe is arranged in the borehole, the pipe is configured to provide drilling fluid in the borehole. Sealing means are provided and arranged to seal about an outer surface of the drill pipe to separate the drilling fluid in the borehole on a first side of the sealing means from a fluid on a second side of the sealing means. Furthermore, a subsea pump arrangement is arranged to receive a flow of the drilling fluid from the borehole. The pump arrangement operates to pump drilling fluid out of the pump arrangement and generate a fluid pressure in the drilling fluid at a location upstream of the pump arrangement. The generated pressure is less than or equal to the hydrostatic pressure of the fluid on the second side of the sealing means. This system is only capable of operating in closed mode.

WO 2016/135480 describes a riser assembly comprising a main body enclosing a main passage which extends from a first end of the main body to a second end of the main body generally parallel to a longitudinal axis of the main body, the main body being suitable for mounting in a riser so that main passage forms a part of a main passage of the riser, the riser assembly further including a scaling assembly which is operable to provide a seal between the main body and a tubular extending along the main passage of the main body so as to substantially prevent flow of fluid of fluid along the main passage around the tubular, and two or more diversion lines each of which extends from a first port in the main body to a second port in the main body, the ports extending through the main body to connect the main passage with the exterior of the main body, the sealing assembly being located in the main body between the first and second ports, wherein a pump is located within each diversion line, the pump being operable to pump fluid along the diversion line in which it is located.

In a first aspect of the present invention it aims to facilitate all aspects of drilling operations, in a pumped riser closed mode with pressure control below a sealing element, and a pumped riser open mode with a reduced level, without having to remove the sealing element. The sealing element may be a Rotary Sealing Device (RSD) or an annular seal intended for non-rotation only

This is achieved by adding a by-pass arrangement to the riser to be able to bypass fluid around the sealing element, a mud return line and operating with a riser level below the depth of the slip-joint at the upper end of the riser, also when operating in closed mode. It is thereby possible to switch seamlessly between a closed mode and an open mode and vice versa by opening and closing the valve on the by-pass arrangement. A level sensor located above the scaling element, such as a pressure sensor from which the level can be calculated, is a key to operating this system.

The bypass functionality may also be achieved by opening up the sealing element to allow flow through it, if the sealing element design allows this.