Patent Grant
8640778
This application is a national phase application filed under 35 USC §371 of PCT Application No. PCT/NO2009/000136, International filing date 6 Apr. 2009, which claims priority to NO Patent Application 2008 1668, filed 4 Apr. 2008 and NO Patent Application 2008 3453, filed 8 Aug. 2008. Each of these applications is herein incorporated by reference in their entirety for all purposes.
The present invention relates to systems, methods and arrangements for drilling subsea wells while being able to manage and regulate annular well pressures in drilling operations and in well control procedures. More specifically the invention will solve several basic problems encountered with conventional drilling and with other previous art when encountering higher than expected pressure in underground formations. These are related to pressure increases in wellbore and surface when circulating out hydrocarbon or gas influxes. The intention with the invention is to be able to effectively regulate wellbore pressures more effectively while drilling and when performing drill pipe connections and also being able to handle well control events due to so-called under balanced condition, with minimum or no pressure at surface, making these operations safer and more effective than before. It will be shown that well kicks can be handled effectively and safely without having to close any barrier elements (BOP's) on the seabed or on surface.
Drilling in deep waters or drilling through depleted reservoirs is a challenge due to the narrow margin between the pore pressure and fracture pressure. The narrow margin implies frequent installation of casings, and restricts the mud circulation due to frictional pressure in the annulus. Low flow rate reduces drilling speed and causes problems with transport of drill cuttings in the borehole.
Normally, two independent pressure barriers between the reservoir and the surroundings are required. In a subsea drilling operation, normally, the primary pressure barrier is the drilling fluid (mud) column in the borehole and the Blow Out Preventer (BOP) connected to the wellhead as the secondary barrier.
Floating drilling operations are more critical compared to drilling from bottom supported platforms, since the vessel is moving due to wind, waves and sea current. Further, in offshore drilling the high pressure wellhead and the BOP is placed on or near the seabed. The drilling rig at surface of the water is connected to the subsea BOP and the high pressure wellhead with a marine drilling riser containing the drilling fluid that will transport the drilled out formation to the surface and provide the primary pressure barrier. This marine drilling riser is normally defined as a low pressure marine drilling riser. Due to the great size of this riser, (normally between 14 inch to 21 inch in diameter) it has a lower internal pressure rating than the internal pressure rating requirement for the BOP and high pressure (HP) wellhead. Therefore, smaller in diameter pipes with high internal pressure ratings are running parallel to and being attached to the lower pressure marine drilling riser main bore, the auxiliary HP lines having equal internal pressure rating to the high pressure BOP and wellhead. Normally these lines or pipes are called kill and choke lines. These high pressure lines are needed because if high pressure gas in the underground will enter the wellbore, high pressures on surface will be required to be able to transport this gas out of the well in a controlled manner. The reason for the high pressure lines are the methods and procedures needed up until now on how gas are transported (circulated) out of a well under constant bottom hole pressure. Until now it has not been possible to follow these procedures utilizing and exposing the main marine drilling riser with low pressure ratings to these pressures. Formation influx circulation from bottom/open hole has to be carried out through the high pressure auxiliary lines.
In addition to these high pressure lines, there might be a third line connected to the internal of the main drilling riser in the lower end of the riser. This line is often called the riser booster line. This line is normally used to pump drilling fluid or liquids into the main bore of the riser, so as to establish a circulation loop so that the fluids can be circulated in the marine drilling riser and in addition to circulation down the drill pipe up the annulus of the wellbore and riser to surface. The drilling riser is connected to the subsea BOP with a remotely controlled riser disconnect package often defined as the riser disconnect package (RDP). This means that if the rig looses its position, or for weather reasons the riser can be disconnected from the subsea BOP so that the well can be secured and closed in by the subsea BOP and the rig being able to leave the drilling location or free to move without being subjected to equipment limitations such as positioning or limitation to the riser slip joint stroke length.
Generally, when drilling an offshore well from a floating rig or Mobile Offshore Drilling Unit (MODU), a so called “riser margin” is wanted. A riser margin means that if the riser is disconnected the hydrostatic pressure from the drilling mud in the borehole and the seawater pressure above the subsea BOP is sufficient to maintain an overbalance against the formation fluid pressure in the exposed formation underground. (When disconnecting the marine drilling riser from the subsea BOP, the hydrostatic head of drilling fluid in the bore hole and the hydrostatic head of sea water should be equal or higher than the formation pore pressure in the open hole to achieve a riser margin.) Riser margin is however difficult to achieve, particular in deep waters. In most case it is not possible due to the low drilling margins (difference between the formation pore pressure and the strength of the underground formation exposed to the hydrostatic or hydrodynamic pressure caused by the drilling fluid)
Managed pressure drilling (MPD) methods have been introduced to reduce some of the above mentioned problems. One method of MPD is the Low Riser Return System (LRRS). Such systems are explained in patent PCT/NO02/00317 and NO 318220. Other earlier reference systems are U.S. Pat. No. 6,454,022, U.S. Pat. No. 4,291,772, U.S. Pat. No. 4,046,191, U.S. Pat. No. 6,454,022.
This new system and methods particularly improves well control and well control procedures when drilling with such systems and allow for fast regulation of annular pressures during drillpipe connections. When a gas is entering the wellbore at some depth, normally at the bottom, the reason is that the hydrostatic or hydrodynamic pressure inside the wellbore due to the drilling mud is lower than the fluid pressure in the pore space of the formation being penetrated. If we now assume that the formation fluid entering the wellbore is lighter than the drilling fluid (mud) in the well, this will have certain implications. In most instances the hydrocarbons (oil & gas) has a lower specific gravity (density) than the drilling fluid in the wellbore. Depending on the amount of carbon molecules, pressure and temperature, the gas density at depth will be in the range of typically 0.1 to 0.25 SG. Compared to the drilling fluid which could range between 0.78 specific gravity (sg) (base oil) to 2.5 (heavy brine). In normal conventional drilling operations the drilling riser is filled with a drilling fluid which is spilling over the top at a fixed level (flow line) and normally gravity feeds into a mud process plant (not shown) and mud pits 1 (
With this new invention, for as long as the gas is allowed to be separated from the drilling fluid/mud inside the marine drilling riser or in a separate auxiliary line/conduit and that the initial drilling fluid level is sufficiently low as indicated in
A variation to this method and procedure is to pump the influxes up the wellbore annulus to a height close to the seabed or riser outlet, then shut down the pumping process completely or to a very low rate, while adjusting the mud level accordingly to keep bottom hole pressure constant, equal to or slightly above the maximum pore pressure and letting the influx raise by gravity separation under constant bottom hole pressure without the need for any interference to the process. This can be an improvement to other known well control processes since experience has shown that it can be very difficult to keep constant bottomhole pressure hen the gas reach the surface and gas must be exchanged with mud and pressure regulation in the wellbore. Now for the first time this process will take place without the need for large surface pressure regulations.
a illustrates a typical arrangement of conventional subsea drilling system under normal drilling.
b illustrates a typical arrangement of conventional subsea drilling system under well control event requiring closed BOP system.
a illustrates allowable annulus pressure loss for conventional drilling vs. drilling with low sea water/mud level in riser.
b illustrates allowable annulus pressure loss for conventional drilling vs. dual gradient drilling with seawater/mud level in the marine drilling riser.
a illustrates a typical arrangement for subsea drilling from a floater. Mud is circulated from mud tanks (1) located on the drilling vessel, trough the rig pumps (2), drill string (3), drill bit (4) and returned up the borehole annulus (5), through the subsea BOP (6) located on the sea bed, the Lower Marine Riser Package (LMRP) (7), marine drilling riser (8), telescope joint (9) before returning to mud processing system through the flowline (17) by gravity and into the mud process plant (separating solids from drilling mud not shown) and into the mud tanks (1) for re-circulation. A booster line (10) is used for increasing the return flow and to improve drill cutting transport in the large diameter marine drilling riser. The high pressure choke line (11) and kill line (12) are used for well control procedures. The BOP, typically has variable pipe rams (13) for closing the annulus between the BOP bore and the drill string, and shear ram (14) to cut the drill string and seal the well bore. The Annular preventers (15) are used to seal on any diameter of tubular in the borehole. A diverter (16) located below drill floor is used for diverting gas from the riser annulus through the gas vent line (18). This element is seldom used in normal operations. A continuous circulation device (50) might be used and allows mud circulation through the entire well bore while making drill string connections. This system avoids large pressure fluctuations caused when pumping and circulation is interrupted every time a length of new drill pipe is added or removed to/from the drill string.
Generally, two independent pressure barriers between the reservoir and surroundings are required. Primary barrier is the drilling fluid and the secondary barrier is the drilling subsea BOP.
Low Riser Return System (LRRS)
General
In order to improve drilling performance, Managed Pressure Drilling (MPD) has been introduced. One method of MPD is the Low Riser Return System (LRRS), where a higher density mud is used than in conventional drilling and a method to control the low mud level (typically below sea level and above seabed) with the help of a subsea pump and several pressure sensors.
One version of the LRRS system is illustrated in
Any gas escaping from the subsurface formation and circulated out of the well will be released in the riser and migrate towards the lower pressure above. The majority of the gas will hence be separated in the riser while the liquid mud will flow into the pump and return conduit which is full of liquid and hence have a higher pressure than the main riser bore. For relatively smaller amount of gas contents it will not be necessary to close any valves in the BOP or well control system to operate under these conditions. Pressure in the well is simply controlled by regulating the mud liquid level. Since the vertical height of the drilling fluid acting on the well below is lower than conventional mud that flow to the top of the riser, the density of the drilling fluid in the LRRS is higher than conventional. Hence the primary barrier in the well is the drilling mud and the secondary barrier is the subsea BOP.
Allowable annulus pressure loss for conventional drilling vs. single gradient drilling using low fluid level in the marine drilling riser is illustrated in
The primary barrier in place is the column of drilling fluid and the secondary barrier is the subsea BOP. Depending on the pressure conditions in the formation, etc., a riser margin may be achieved. With a low fluid level in the marine drilling riser the fluid vertical height which exerts hydrostatic pressure in the bore hole is lower than when the drilling fluid level is at surface. Hence the fluid weight (density) is higher than when the drilling fluid (mud) level is at surface to have equal pressure in the bottom of the borehole. This means that the density of the drilling fluid in this case is so high that it would exceed the formation fracture pressure if the level of the fluid in the riser reached the surface or flow line level of conventional drilling. Hence even with a considerable gas influx at the bottom of the well, the formation would not withstand a drilling mud fluid level at flow line level (17
Alternatively, the borehole can be filled with a high density mud in combination with a low density fluid, i.e., sea water in the upper part of the marine drilling riser as illustrated in
One important issue using the dual gradient compared to the single gradient system (LRRS) is the handling of large and high gas flow into the borehole from the subsurface formation (kicks).
Method for Gas Kick Handling
Generally, the subsea BOP is typically rated for 10 000 or 15 000 Psi while the riser and riser lift pump system are rated for low pressure, typical 1000 Psi. Therefore, high pressure fluids should not be allowed to enter the riser and/or subsea mud lift pump system. Another limitation of the subsea mud lift pump is the limitation for handling fluids with a significant amount of gas. So, for increased efficiency, the majority of gas should be removed from the drilling fluid before entering the pump. For the same reason the gas can not be allowed to enter the riser if it is filled with drilling mud or liquid to the surface as in conventional drilling or with dual gradient drilling, since it would create an added positive pressure on the riser main bore (8). Since the main drilling riser can not resist any substantial pressure, this can not be allowed to happen in order to remain within the safe working pressure of the marine drilling riser (8) and slip joint (9).
Due to the high density of the mud in use and the low mud level in the riser, conventional choke line and surface choke manifold can not be used for well kick circulation. A fluid column all the way back to surface will most likely fracture the formation of the borehole because this new process use mud of much higher density than when the mud flows back to the drilling installation on surface as in conventional drilling.
A possible solution to the above mentioned limitations is to introduce a tie-in to the marine drilling riser main bore (39) as illustrated in
An alternative is to divert the fluid and gas from the choke valve (101) directly to the pump (40) via valve (110) as illustrated in
Using a continuous circulation system (50), the fluid flow through the drill string and annulus of the bore hole can be kept constant during drill pipe connection. Otherwise the fluid level in the riser would have to be adjusted when making drill pipe connection in order to keep constant bottomhole pressure during a connection (adding a new stand of drill pipe).
During a gas kick circulation, the bottomhole pressure is maintained as the gas in the borehole expands on its way to surface simply by increasing the fluid head in the riser or an auxiliary line. As long as the fluid head is lower than the manageable fluid level in the riser (the fluid must not flow to the mud tank (1)).
For normal drilling operation, it is expected that the volume of gas in the return fluid from the well is limited and can be handled through the subsea riser mud lift pump. Some of the gas will be separated in the riser and diverted using a wiper element or Rotating BOP (120), or a standard diverter element (16), through the vent line (18) as illustrated in
The subsea choke valve allows for low mud pump circulation rates since pressure in the annulus is regulated by the choke pressure. This option allows more time for the gas and mud to separate in the riser (more controllable). However, subsea chokes are more complicated to control compared to surface chokes due to the remoteness. Replacement of the choke valve and plugging of the flow bore in the choke, are challenges. One option is to install two chokes in parallel. A further option is to pump additional fluid into the well bore using the kill line (12). Higher flow from the borehole and kill line requires larger opening of the choke valve and the likelihood for plugging is thus reduced. Also the pressure drop will be easier to control with a higher flow rate through the choke valve. Using a small orifice (fixed choke) instead of a variable remotely controlled valve/choke might be an option.
Also the booster line could be used to avoid settling of formation cuttings in the riser annulus between the closed subsea BOP and the outlet to the subsea pump. Hence it will be possible to mange the mud level in the riser upwards and use the subsea pump to regulate the level down. Managing the riser level up or down to control the annular well pressures between the closed BOP is also an option.
The choke valve can be located on the BOP level, or in the choke line between the BOP and inlet to the riser (39) as illustrated in
An alternative embodiment of a LRRS system according to the present invention is illustrated in
Allowable annulus pressure loss for conventional drilling vs. single gradient drilling using low fluid level in the marine drilling riser (LRRS) is illustrated in
Alternatively, the borehole can be filled with a high density mud in combination with a low density fluid, i.e., sea water in the upper part of the marine drilling riser as illustrated in
Alternatively, the borehole can be filled with a high density mud in combination with a low density fluid, i.e., sea water in the marine drilling riser as illustrated in
However the maximum drilling depth is achieved using the LRRS shown in
Description of Different Modes of Operations with the LRRS Option 1
Drilling Mode—Annular Seal (37) Open—
Low mud level (41) and 42) in riser and auxiliary vent line (39), respectively. Mud return is via subsea lift pump (40). The fluid level in the riser/vent line dictates the bottomhole pressure (BHP). There is no closing element in the system. However, there is an option to have a wiper, stripper element (120) installed in the diverter element or above to keep drill gas released from the drill mud in the riser to enter the drill floor area or if an inert gas is used to purge the riser, this gas is diverted out through the diverter line.
Drill Pipe Connection Mode—Annular Seal (37) Closed—
This procedure and method is used in order to compensate for the reduction in wellbore annulus pressure when the pumping down drill pipe is stopped, as when making a connection of drill pipe.
In this situation there is a low mud level (41) in marine drilling riser (8) and a high mud level (42) in the vent line (39). Mud is return via the subsea lift pump. The level of drilling fluid is regulated in the much smaller auxiliary line, making the regulation process much faster and more efficient than having to regulate the level in the main marine drilling riser. The seal element in the riser will isolate the pressure above the seal element in the drilling riser and the wellbore pressures is now regulated by the level (42) in the auxiliary vent line.
Proper spacing of the annular seal (37) in the riser section in combination with long single drill pipe (15 m is standard) is preferred to avoid tool joint (TJ) passing through the closed BOP annular seal. BOP annular seal can handle TJ passing through, but the lifetime will then be reduced. Alternatively, a pup joint is used in the drill string for proper space out. When a pup joint is passing through the annular seal (37), a new pup joint is added to the drill string. The main benefit is that seal element will last longer when not activated permanently in the drilling operation when drilling and rotating. The element is only closed when not rotating and only during interruption in the circulating process.
The procedures for drill pipe connection will be as follows:
The heave compensator is active except when the drill string is suspended in the slips to minimize wear on the annular seal (37) due to sliding of the drill pipe section through the sealing element.
Drill Pipe Connection Mode—Annular Seal Open
The fluid level in the marine drilling riser (41) and vent line (42) is raised for making drill pipe connection. However, this is a time consuming process. It is required if the annular do not seal properly or is not installed. The riser will be filled also through the booster line, or kill line, etc.
The procedures for drill pipe connection will be as follows:
In this situation the riser annular seal is closed (see
As long as the fluid level (42) in the vent line (39) is below surface, the gas kick is circulated out of the well using the annular seal (37) and the lift pump (40).
The procedures for gas kick circulation will be as follows (modified drillers method):
Circulate out kick while keeping drillpipe pump pressure (DPP) constant while regulating vent line level.
The gas from the subsea separator is diverted into the open vent line which is used to balance the BHP. In case of a larger gas influx, the hydrostatic column of drilling fluid in the vent line is increased until balance is achieved. As the gas is circulated out of the bore hole and expanded, the hydrostatic head in the vent line is increased.
There are several more methods or procedures that can be followed without diverging from the embodiments of the invention
The separated fluid is diverted through to the subsea lift pump. The subsea lift pump should not be exposed to high pressure mainly due to the low pressure suction hose, return hose and separator, etc. If high pressure is expected due to a large column of gas in the bore hole, the vent line (39) may be completely filled. In this case, the subsea lift pump and separator must be by-passed and isolated. Well circulation and well killing can then performed using the conventional well control equipment and procedures, i.e., pipe ram (13) in the subsea BOP closed and return fluid through choke line (11) and surface choke manifold. However this can be achieved only if the formation strength of the open hole section will allow this procedure to be performed. In the end of well control operation, the required hydrostatic head will be reduced and further well circulation operation can take place using the lift pump and a low mud7air interface level in one of the auxiliary lines.
One option would be to use a pipe ram (13) or annular preventer (15) in the subsea BOP (6) when circulating a small gas kick through the pump. In this case, communication valve (85) to the separator and lift pump is open as illustrated in
Surge and Swab Pressure Compensation. Drill Pipe Connection Mode—Annular Seal (37) Closed—
Vent line (39) closed. Mud return via subsea lift pump. Surge and swab pressure fluctuation due to rig heave can be compensated for using the subsea lift pump with bypass to a choke valve (90).
The Procedures for compensating for surge and swab pressure would be;
Compensating for surge and swab pressure is a challenge on a MODU. However, with proper measurements of the rig heave motion, and predictive control, this method will make it feasible.
Disconnection of Marine Drilling Riser—
Disconnection of marine drilling riser takes place conventionally. All connections for the lift pump are above the riser connector.
In conventional drilling displacing riser and other conduits to sea water before disconnection will avoid spillage of drilling fluid to sea. In an emergency case, no time for fluid displacement is possible hence the fluid in the riser, etc., will be discharged to sea. With the LRRS system no spillage to the sea will normally occur. Since the pressure inside the marine riser at the disconnect point will be lower or equal to the seawater pressure, seawater will flow into the riser and hence the entire drilling riser and return system can be displaced to seawater after the disconnect by the subsea pump system without any spillage to the sea.
Other and various embodiments of the invention include a system for drilling subsea wells from a Mobile Offshore Drilling Unit (MODU), comprising a marine drilling riser arranged from the MODU to a seabed located Blow Out Preventer (BOP), a drill string arranged from the MODU through the marine drilling riser and BOP and further down a wellbore, at least one closing device arranged in the marine drilling riser, or in a high pressure part of the system below the marine drilling riser, such as integral with the BOP, the closing device being adapted to close the annulus outside the drill string, characterized in that the system further comprises at least one mud return outlet and mud conduit fluidly connected to the annulus at a lower part of the marine drilling riser or below, at a level below a low mud level (an interface gas/mud or liquid/mud typically lower than sea level) in the marine drilling riser, the at least one mud return outlet being connected to the annulus above the closing device, and being adapted for flowing drilling mud to a subsea lift pump, the pump being adapted to pump the received mud from the wellbore annulus to above sea level, and a means for separating gas from mud, coupled into the path of flow from the annulus to the subsea lift pump, and a means for dynamic regulation of annular well pressure, coupled to the path of flow from the annulus to the subsea lift pump.
The means for separating gas from mud and the means for dynamic regulation of annular well pressure may comprise the same structural parts. The system may comprise a well flow outlet from the well below the closing device, which is connected to a well flow inlet into the marine drilling riser above the at least one mud return outlet from the marine riser. The system may be configured so that during normal operation, mud is directed from the mud outlet to the subsea lift pump, while during unstable mode of operation, such as when encountering a gas kick, the closing device is closed and drilling fluid is directed from the annulus below the closed device to the subsea lift pump, via the means for separating gas and optionally via the means for dynamic regulation of annular well pressures.
Another embodiment of the invention is a system for drilling subsea wells from a Mobile Offshore Drilling Unit (MODU), comprising a marine drilling riser arranged from the MODU to a seabed located Blow Out Preventer (BOP), a drill string arranged from the MODU through the marine drilling riser and BOP and further down a wellbore, at least one closing devise arranged in the marine drilling riser, or in a high pressure part of the system below the marine drilling riser, such as integral with the BOP, the closing device can close the annulus outside the drill string, characterized in that the system further comprises at least one mud return outlet and mud conduit fluidly connected to the annulus at a lower part of the marine drilling riser or below, at a level below a low mud level (an interface gas/mud or liquid/mud typical lower than sea level) in the marine drilling riser, of which outlets and conduits at least one is fluidly connected to the annulus below said closing device, for flowing mud to a subsea lift pump that via piping or conduits can pump the received mud to above sea level, and a means for maintenance of a constant well bore annulus pressure, having fluid connection to the subsea lift pump, including valves and piping for fluidly connecting said means to the path of flow from the annulus to the subsea lift pump, the means including a pipe extending upwards from seabed or near seabed level through the sea, to a level above sea level and located upstream the subsea pump, providing a distance between the levels for adjustment of a liquid mud/gas interface or mud liquid level in the pipe in order to adjust and regulate the annular well pressure.
In either of these embodiments, the means for dynamically adjusting the well pressure may include a pipe extending upwards from a separator through the sea, a mud/gas interface level in the pipe being adjustable in order to adjust the bottom hole pressure. The means for dynamically adjusting the well pressure may include the annulus outside the drill string above the closing device, including the annulus of the marine drilling riser, and the fluid conduit from the annulus below the closing device, towards the means and pump, may be via a choke line.
In either of these embodiments, a subsea choke valve may be provided in a choke line fluidly connecting the annulus below the closed device with the means for dynamically adjusting the well pressure, such that a choked flow of mud can be directed to the subsea lift pump via the means for separating gas from mud if the mud contains significant quantities of gas or if the bottom hole pressure is unstable, and the pipes and valves may be provided in order to by-pass the means for separating gas from mud and connect the choke line to the subsea lift pump.
In either of these embodiments, the means for dynamically adjusting the well pressure may include a pipe extending upwards from seabed or near seabed level through the sea, to a level above sea level, providing a distance between the levels for adjustment of a liquid mud/gas interface or mud/liquid level in the pipe in order to adjust and regulate the annular well pressure, and the pipe may include one of: a part of a booster line, a part of a choke line, a part of a kill line and the annulus of a drill string and the marine drilling riser, operatively connected to function as the pipe whenever the means is in operation.
Yet another embodiment of the invention is a subsea drilling system where drilling fluid is pumped down into the borehole through a drill string and returned back through the annulus between the drill string and the well bore, out of the drilling riser at a level between the seabed and the sea water, characterized in that a subsea located Blow Out Preventer (BOP) can be closed to seal off the annulus bore between the drill string and the bore hole, and drilling fluids are diverted from below the closed element in the subsea BOP in a separate line to above the BOP via at least one pressure reduction device (subsea choke valve) into the riser at a higher level than the pump outlet to a subsea mud pump that is connected to a conduit fluidly connected the mud process plant on the MODU above sea level.
The fluids from below the closed BOP may be diverted directly from the choke valve to the subsea lift pump via the valve bypassing the marine drilling riser. A separate liquid type with a lower liquid density compared to the drilling fluid in use may be located in the marine riser above the lower than sea level drilling fluid. A section in the marine drilling riser, above the fluid outlet for the pump and below the mud inlet may have a larger diameter compared to the riser below or above in order to reduce the downward fluid velocity and thus improve the gas-mud separation process. A continuous circulation system may be used.
An additional fluid may be supplied upstream of the choke valve to improve the performance of the pressure control system. An additional fluid may be supplied below/(upstream) of the subsea lift pump to improve the performance and avoid settling of drill cutting in the drilling riser above the BOP.
In still yet another embodiment of the invention, a subsea drilling system for controlling drilling fluid/well annular pressure, comprising a drill string, a marine drilling riser, a system for circulating drilling fluid by pumping it down into the borehole through a drill string and returning it back through the annulus between the drill string and the well bore, and a system for controlling annular well pressure by draining drilling fluid out of the drilling riser or BOP at a level between the seabed and the sea water level in order to adjust the hydrostatic head of drilling fluid, is characterized in that it further comprises a separator communication with the marine drilling riser and a gas vent line to the surface located upsteam a liquid line to the surface.
A pump may be coupled to the liquid line downstream the connection to the gas vent line in order to pump the liquid to the surface. The vent line may be a separate conduit line or the choke line, or kill line, or riser booster line. The fluid return line from the bore hole to the gas separator, subsea lift pump and pump discharge line to surface may be connected to the riser at the riser section above the BOP. The fluid return from the bore hole to the gas separator, subsea lift pump and pump discharge line to surface may be connected via the choke line from the well bore below the BOP closing device. The separator may be an integrated part of the riser, or it may be located outside the riser.
An additional embodiment of the invention is a subsea drilling method where drilling fluid is pumped down into the borehole through a drill string and returned back through the annulus between the drill string and the well bore, and where the annulus wellbore pressure caused by the drilling fluid is controlled and regulated by draining drilling fluid out of the drilling riser at a level between the seabed and the sea water, thereby creating a lower mud/gas or mud/liquid interface level in the marine drilling riser, to a subsea mud lift pump that is fluidly connected to the mud process plant above the surface of water, in order to adjust the hydrostatic head and wellbore annulus pressures by regulating the mud/gas or mud/liquid interface level up or down, characterized in that a subsea located Blow Out Preventer (BOP) can be closed to seal off the annulus bore between the drill string and the bore hole, and any fluids are diverted from below the BOP in a separate line to above the BOP into the marine drilling riser at a higher level compared to the pump outlet level.
The line connecting the wellbore annulus below the closed BOP and the inlet to the marine drilling riser may contain at least one pressure reduction device (subsea choke valve) that can regulate the amount of flow into the marine drilling riser. The fluids from below the BOP may be diverted from the choke valve directly via a valve and piping to the subsea lift pump. The fluid velocity in the riser between the choke line inlet and the pump out let may be diverted downwards in the riser with a velocity lower than the rising velocity of the less dense gas in order to achieve gravity type separation and a net upwards rising velocity of the gas bubbles. The separated gas in the return fluid may be vented via the marine drilling riser and diverter system to the atmosphere.
A separate fluid type with a lower fluid density compared to the drilling fluid in use, may be located in the marine drilling riser above the drilling fluid level. A section in the marine riser, above the fluid outlet for the pump and below the fluid inlet from the well may have a larger diameter compared to the marine drilling riser above and below in order to reduce the downward fluid velocity and thus improve the separation process. A continuous circulation system may be used in combination with the circulation/drilling method.
Additional fluids may be supplied into the wellbore other than through the drill string upstream of the choke valve to improve the performance of the pressure control system. Additional fluids may be supplied upstream (e.g. through a booster line) of the subsea lift pump to improve the performance and avoid settling of formation particles in the suction line, discharge line and subsea lift pump. Additional fluids may be supplied below/upstream the subsea lift pump to improve the performance and avoid settling of drill cutting in the drilling riser above the BOP.
Gas escaping from a submarine formation into a borehole may be transported/circulated out of the borehole to the surface in the annulus between the drill string and the borehole and separated from the drilling fluid within the drilling riser which is kept open to the atmosphere above the sea level under ambient atmospheric pressure, and the combined hydrostatic and dynamic pressure at any one particular depth in the wellbore may be kept constant during the drilling process by regulation of the height of the liquid mud level in the main drilling riser.
Yet an additional embodiment of the invention is a subsea drilling method for controlling the wellbore annular pressure, where drilling fluid is pumped down into the borehole through a drill string and returned back through the annulus between the drill string and the well bore, and where wellbore annular pressure is controlled by draining drilling fluid out of the drilling riser or BOP at a level between the seabed and the sea water in order to adjust the hydrostatic head of drilling fluid, characterized in that the drained drilling fluid and gas is separated in a subsea separator where the gas is vented to surface through a vent line, and the fluid is pumped to surface via a pump.
An annular seal, located above an outlet from the riser to the separator, may be used to seal the annulus before the flow through the drill string is stopped and preferably after the drill string rotation is stopped, characterized in that the level of liquid in the vent line may be increased to compensate for the loss in annulus pressure when the flow of mud/fluid through the drill pipe is reduced or stopped. The liquid level in the vent line may be reduced when the flow circulation is commenced or increased in order to maintain a substantially constant bottom hole pressure.
An annular seal, located above an outlet from the riser to the separator, may be used to seal the annulus of the wellbore in the event that well fluids enter the bore hole, preferably after the drill string rotation has stopped. The lower density influx volume into the larger diameter bore hole may cause the higher density mud and gas interface in the small diameter vent line to increase, and the increase in height of mud/gas in the vent line or the corresponding pressure effect to the wellbore annulus due to the higher level being larger than the vertical height of influx of formation fluid in the borehole annulus or the corresponding lower bottomhole pressure due to the lower density influx height, to achieve a self adjusted pressure balance method in the bore hole annulus with formation pressure. An annular seal, located above an outlet from the riser to a separator, may be used to seal the annulus before the flow through the drill string is stopped and preferable after the drill string rotation is stopped where the pump and a hydrostatic head in the pump discharge line are used to compensate for surge and swab pressure.
And yet still another embodiment of the invention is a subsea drilling method for controlling the annular wellbore pressure, where drilling fluid is pumped down into the borehole through a drill string and returned back through the annulus between the drill string and the well bore, and where the wellbore annulus pressure caused by the drilling fluid is controlled by draining drilling fluid out of the drilling riser or BOP at a level between the seabed and the sea water in order to adjust the hydrostatic head of drilling fluid, characterized in that the drained drilling fluid and gas is separated in a subsea separator where the gas is vented to surface through a vent line, and the fluid is pumped to surface via a subsea mud pump. A liquid mud/gas interface level in the vent line may be regulated up or down with the subsea mud lift pump in order to regulate the wellbore pressure accordingly.
Another additional embodiment of the invention is a subsea drilling method for maintaining constant bottom hole pressure in a well during drilling and well circulation, after an influx of formation fluid containing gas into the wellbore annulus has occurred, where drilling fluid is pumped down into the borehole through a drill string and returned back through the annulus between the drill string and the well bore, characterized in that the wellbore bottom hole pressure is maintained or regulated by draining more or less drilling fluid out of the wellbore annulus than what is being pumped into the wellbore annulus, from a level between the seabed and the sea water surface, in order to adjust the hydrostatic head of drilling fluid (mud)/gas interface level up or down, the gas phase being open to atmospheric pressure, that the influxes (influxed volume) is pumped from the influx depth up the annulus of the wellbore to a height preferably close to the annulus outlet, stopping completely or reducing the pumping process down the drill string and/or into the wellbore annulus to a minimum, while regulating the wellbore annulus pressure to equal or above that of the open hole formation pressure by regulating the mud/gas interface level, letting the influx raise to surface by gravity separation under constant bottomhole pressure without any other physical interference or regulation needed.
All the features mentioned above and in the dependent claims, in addition to the obligatory features of the independent claims but excluding prior art features in conflict with the invention, can be included into the systems and methods of the present invention, in any combination, and such combinations are a part of the present invention.
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| 20081668 | Apr 2008 | NO | national |
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| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/NO2009/000136 | 4/6/2009 | WO | 00 | 11/30/2010 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2009/123476 | 10/8/2009 | WO | A |
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| 20110100710 A1 | May 2011 | US |
