NO319810B1 - Method and apparatus for drilling an offshore wellbore - Google Patents

Description

The invention relates to a method and device for drilling an offshore borehole as stated in the introduction in the respective claim 1 and claim 9. In particular, the invention relates to a method and a device for handling the drilling fluid circulation in offshore drilling operations.

Drilling fluids, also known as mud, are used to cool the bit and flush cuttings away from the bit's formation interface and then out of the system, and to stabilize the borehole with a "filter cake" before newly drilled sections are lined. The drilling fluid also performs an important well control function and is monitored and adjusted to maintain pressure with a hydrostatic piece in unlined sections of the borehole, which prevents uncontrolled flow of pressurized well fluid into the borehole from the formation.

In conventional offshore drilling, fluid is circulated down the drill string and up through an annulus between the drill string and the borehole below the seabed. A riser surrounds the drill string from the wellhead at the seabed to the drilling equipment on the surface and the return circuit for the drilling fluid continues from the seabed to the surface through the riser/drill string annulus.

In such a conventional system, the relative weight of the drilling fluid relative to seawater and the length of the riser combine in deepwater applications to exert an elevated hydrostatic pressure in the riser/drillstring cavity and the borehole/drillstring annulus.

US Patent 4,813,495 describes a system to bring the drilling fluid and cuttings out of the annulus at the bottom of the riser and to place a subsea pump to facilitate the return flow through a separate line. However, the reliability and dependence of such a mud circulation system is uncertain in the offshore environment and especially when it comes to fluid with entrained drilling cuttings that is handled in valves and pumps in the return segment of the circuit.

It is therefore an object of the invention to provide a practical method and a device for reducing excess hydrostatic pressure exerted by the return of the mud column in the riser/drill string annulus or in the borehole/drill string annulus.

According to the invention, this purpose is achieved by the method having the characteristic features as stated in claim 1, and the device having the characteristic features as stated in claim 9.

By treating the drilling fluid in the subsea treatment system to remove drilling cuttings, it is achieved that the drilling fluid becomes substantially free of drilling cuttings before it enters the return pump system. The durability and reliability of the return pump system will thereby be significantly improved.

Appropriately, the treated drilling fluid flows from the subsea processing system into a mud tank from which the drilling fluid flows to the return pump system via a suction line. Thus, there will be no need for precisely synchronized operation of the pump on the surface and the subsea treatment system, as the reservoir acts as a buffer that allows variations in the level of the drilling fluid therein.

The invention will now be described below in detail and by way of example and with reference to the drawings, in which fig. 1 is a schematic view of an embodiment of the subsea pump system according to the invention, fig. 2 is a side view of another embodiment of the pump system according to the invention, fig. 3 shows a longitudinal section of the drill string shut-off valve in fig. 2 in a closed position, and fig. 4 shows a longitudinal section of the drill string shut-off valve in fig. 2 in an open position.

Fig. 1 schematically shows an embodiment of a drilling fluid circulation system 10 according to the invention. The drilling fluid is injected into the drill string at the drill rig 12 above the water surface 14. The drilling fluid is transported down a drill string (see fig. 2) through the water and into the drill hole 16 below the seabed 18. Near the lower end of the drill string, the drilling fluid passes through a shut-off valve for the drill string (" DSSOV") 20 and is ejected from the drill string through the drill bit (ref. fig. 2). The drilling fluid flows through the bottom of the borehole 16, carrying cuttings with it and returning to the seabed 18 in the annulus 19. Here, and close to the seabed, the drilling mud is brought to an underwater, primary treatment facility 22 and waste products, see line 24, are separated from the drilling fluid. These waste products include at least the coarse drilling cuttings that are entrained in the drilling fluid. With these waste products 24 separated at facility 22, the treated drilling fluid continues to the subsea return pump 26 where it is pumped to the surface drilling facility 14. A secondary processing facility 28 can be used to separate additional gas at low pressure and remove finer particles from the drilling fluid. The treated drilling fluid is delivered to the surface pumping system 30 and is ready for recirculation into the drill string at the drilling rig 12. This system removes the hydrostatic piece of mud between the surface and the seabed from the formation and improves pump life and reliability in the subsea return pumping system 26.

The embodiment in fig. 1 can be used both for drilling operations with or without a riser. In all cases, the hydrostatic pressure in the mud return through the water column is isolated from the hydrostatic piece below the blowout valve near the seabed. With sufficient insulation, the return path for the mud can actually continue up through the drill riser/drill string annulus. However, it may prove appropriate to have a separate riser for the mud return whether or not a drill riser is used. Even if the return line is not used for the mud through the water column, it may be appropriate to have a drill riser for the blowout valve and separation equipment.

Fig. 2 shows the subsea components in one embodiment of the drilling fluid circulation system 10, here with a drilling riser that is not used to return the mud through the water column. The drilling fluid or mud 32 is injected into the drill string 34 running inside the marine drill riser 36, through the subsea blowout valve ("BOP stack") 38 near the seabed 18 and through the casing 40 down through the lined borehole 16 to the bottom hole assembly 42 at the lower end of the drill string. The downhole assembly comprises DSSOV 20 and the drill bit 44.

The flow of the drilling mud 32 through the drill string 34 and out of the drill bit 44 serves to cool the drill bit and wash cuttings away from the formation interface of the drill bit and stabilize the lined borehole with a "filter cake" before more casing strings 40 are inserted into the newly drilled sections. The drilling mud 32 also performs an important control function by maintaining a pressure in a hydrostatic piece in the lined sections of the borehole 16 which prevents uncontrolled flow of pressurized drilling fluid in the borehole from the formation.

However, in this embodiment the drilling mud is not returned to the surface through the marine riser/drill string annulus 46, but rather is sucked back again from the annulus near the seabed 18, for example immediately above the BOP stack 38 through the mud return line 19. In this illustration with a drill riser, the remainder is filled of the annulus 46 to the water surface, with seawater 48 which has a much lower density than the drilling mud. Subsea drilling can exert a hydrostatic head of 1000 m or more at the bottom of the marine riser 36. However, when this hydrostatic head is from seawater rather than drilling mud in the annulus, the inside of the marine riser will remain substantially at ambient pressure relative to the conditions outside the riser. the tube at that depth. The same is the case for mud leaving the borehole in designs without a riser. This makes it possible to concentrate the drilling mud specification more around fire control from the mud line down.

Drilling mud 32 is returned to the surface in the drilling fluid circulation system 10 which comprises the subsea primary treatment system 22, the subsea return pump 26 and a second riser 50 which serves as a return line for the drilling mud. The subsea primary treatment system 22 is shown with a two-component first stage 22A carried on the lower part of the drill riser 36 and a subsequent stage 22B on the seabed.

In normal operation, the solids removal system 54 first extracts the return of the drilling mud 32. Here, the solids removal system 54 is a gumbo box 68 that operates in a gas-filled, dry chamber 72 with ambient pressure. The mud 32 hydrostatic piece in the annulus 46 propels the mud through the mud return line and over the overflow pipe 74 and out over the cuttings removal equipment, for example a screen or gumbo rail 78. The cuttings 76 that are too coarse to pass through the screen or through the gumbo rail fall off at the far edge outside the mud tank 80 and directly into the water through the open bottom of the chamber 72. The mud without the separated cuttings, passes through the gumbo rail into a mud tank 80 and flows from the mud tank 80 via a line 66 to a lower mud tank 80A.

The remote maintenance inside the gumbo box 68 can be carried out with a washing flush system to wash the gumbo rail with sea water and a TV monitor or other electronic computer system in the chamber.

Drilling cuttings 76 can be prevented from accumulating in the well by placing a disposal pit 84 for drilling cuttings under the chamber 72 to be able to collect the drilling cuttings from the chamber. A jet pump 86 injects seawater past a venturi with a pressure drop that is sufficient for the seawater and possibly brought drilling cuttings to be drawn into the discharge line 88 for the drilling cuttings from the disposal mine 84. The logging line then transports the drilling cuttings to a sufficiently distant location, so that the collected drilling cuttings do not disturb the well operations.

Another advantage of this design is that the gas from a well control course is removed by means of a gas separator 52 and released near the seabed 18. The pumping operation in such well courses is critical. In a well control process where large volumes of gas penetrate the well, the entire system must handle the gas quantities while creating an acceptable back pressure against the borehole 16 by pumping down a heavier mud in sufficient quantity, speed and pressure. A drop below this pressure in a well control sequence will lead to more gas intrusion, while an increased pressure can blow the borehole. The ability to exchange sludge with weights appropriate to the immediate need is the primary regulation at this critical pressure. However, multiphase flow is a challenge for conventional pumps that are otherwise suitable for subsea return pump system 26. Thus, only substantially gas-free mud is pumped to the surface through the subsea return pump system 26, which makes the pumping operation during critical well regulation processes easier. Additional gas can be removed at atmospheric pressure at the surface with an additional gas separation system not shown.

The gas separator 52 comprises a vertical tank or vessel 58 having an outlet at the top leading to a gas outlet 60 through an inverted U-pipe arrangement 62 and a sludge outlet 64 near the bottom which is connected to the return line 66 downstream of the solids removal system 54.

The subsequent treatment system 22B is also a solids removal system in the form of a second gumbo box 68A in a gas-filled dry chamber 72A at ambient pressure. The hydrostatic piece with the mud 32 in the tank 80 drives the mud over the overflow pipe 74A to eject the mud and entrained cuttings over closely spaced rods or a fine mesh gumbo chute 78A. Sludge that is separated in the sludge/gas separator 52 can join what is in the tank 80 in this second treatment step. The finer drilling cuttings are removed and brought away with the disposal mine 84A and jet pump 86A as before, with treated mud being taken to the mud tank 80A.

It may also be desirable to provide the normal tank outlet and tank volume so that additional cuttings can pass through the gumbo slide. A surface-activated pump valve at the bottom of the mud tank can be used to periodically remove the bottomed cuttings.

The suction line 94 in the subsea return pump 26 is attached to the bottom of the lower sludge tank 80A. A liquid level control 90 in the lower mud tank 80A activates the return pump 26. The removal of the cuttings from the mud greatly improves the pumping operation in this high-pressure pumping operation to return the cuttings from the seabed to the facility above the water surface through the return riser 50. The return riser may be attached at the bottom to a foundation in a conventional manner, for for example an anchorage 98 and supported at the top by surface equipment (not shown), perhaps aided by operating modules (not shown) spaced along its length. In this embodiment, the return pump 26 is housed in a dry chamber 92 with ambient pressure, which improves the working environment and simplifies pump construction and selection.

In the well control process, the BOP stack 38 is closed and the gas separator 52 takes in fluid from subsea choke lines 33 adjacent to the BOP stack 38. In such a well control process, the gas separator 52 will allow the removal of gas from the mud 32, so that the subsea pump system 26 can operate only by a single phase component, i.e. liquid sludge. The gas separator 52 can be suitably mounted to the lower part of the riser 36. Fig. 3 shows the deployed DSSOV 20 at the bottom of the drill string 34 as part of the bottom hole assembly 42 in fig. 2. The DSSOV is an automatic valve that uses piston pressure/spring balance ports to close a valve 112 to accommodate the hydrostatic portion of the drilling fluid 32 in the drill string when the downhole assembly is in place and the normal circulation of the drilling fluid is interrupted, for example to introduce a other section of drill pipe in the drill string. In such cases, the DSSOV is closed to prevent the drilling fluid from flowing down and out of the drill string and up into the annulus 46 and displacing the much lighter seawater until equilibrium is achieved. Fig. 3 and 4 show DSSOV 20 in the closed and open position. The DSSOV has a main body 120 and may suitably be provided with connections such as a threaded box 122 and pin 124 at each end for insertion into the drill string near the bottom hole assembly. The body 120 has a cylinder 128 which receives a piston 116 with a first pressure surface 114 and a second pressure surface 130. The first pressure surface 114 is on the piston surface and is open to the upstream side of the DSSOV 20 through the channel 132 which passes through the piston. The channel 132 can suitably be provided with a waste cup 134.

The second pressure surface 130 is on the back of the piston 116 and is open to the downstream side of the DSSOV 20. Furthermore, the first and second pressure surfaces of the piston 116 are isolated by means of O-rings 136 which seal between the piston and the cylinder.

The body 120 also has a main flow path 140 which is interrupted by the valve 112, but which is interconnected by drilling mud flow channels 126. Several O-rings 142 between the valve 112 and the body 120 isolate the flow from the drilling mud flow channels 126, except through the ports 118 in the valve 112.

DSSOV is used to maintain a positive surface drill pipe pressure. When the surface mud pumping system 30 (see Fig. 1) is shut down, for example to introduce a section of drill string 134 during drilling, a valve shut-off spring 110 shifts the valve 112 to a closed position where the valve ports 118 have been moved out of alignment with the mud channels 126 in the body. 120. The spring 110, the surface of the first pressure surface 114 and the surface of the second pressure surface 130 of the piston 116 are balanced to close the valve 112 and maintain a pressure margin created by the difference in density between seawater 48 and mud 32 over the distance between the water surface 14 and the seabed 18. Thus, the excess positive pressure in the drill string 34 is prevented from being dispersed by driving drilling mud down through the drill string and up through the annulus 46 at the same time as the excess pressure from the drill hole 16 is isolated.

After the new drill pipe section has been installed or drilling has otherwise resumed, the surface pumping system 30 (Fig. 1) is used to build pressure against the valve 112 until the surface pressure 114 against the piston 116 overcomes the bias of the spring 110, opening the valve 112 and resuming circulation , see fig. 4.

DSSOV 20 also makes a procedure for determining the required mud weight in a well management process easier. When the DSSOV is closed, pump pressure is slowly increased while closely monitoring for signs of leakage, which is observed as an interruption of pressure build-up despite continuous pumping. This signals that the flow has been established and the pressure is recorded as the pressure to open the DSSOV. The surface pumping system 30 is then brought up to a reduced pumping rate to pump out drilling fluids while the pressures are carefully monitored to prevent further intrusion from the formation. The opening pressure, the reduced pumping rate and the circulating pressure are then recorded periodically or when a significant adjustment of the mud weight has been made by the mud weight.

With such information, the bottom hole pressure can be determined if a well management procedure should become relevant. Shutting down the surface pumping system 30 after a flow is detected will shut off the DSSOV 20. The excess pressure causing the flow, that is, the unbalanced pressure of the formation, will be in addition to the pressure required to open the valve 112. The pumping pressure then becomes reintroduced and increased slowly while monitoring for leakage which entails the resumption of flow. The pressure difference between the previously unrecorded opening pressure and the pressure after the flow is the unbalanced pressure that must be compensated for when adjusting the density of the mud 32. The killing mud weight is then calculated and drilling and adjustments are carried out in accordance with this during the mud preparation.

In the illustrated embodiment, some of the components of the subsea primary treatment system 22 are placed on the marine drill riser 36 and others are placed directly on the seabed 18. In the case of components placed on the seabed, it may be appropriate to place a minimum drilling template or at least interlocking guide pilings and receiving channels for the most important components, placed as undersea packages into safe, predetermined, relative positions. This facilitates connection between the components deployed as separate subsea packages using Remotely Operated Vehicles ("ROVs"). Such connections include electrical lines, gas supply lines, mud transport lines and drill cutting transport lines. A system of gas supply lines (not shown) supplies each of the dry chambers 72, 72A and 92 with gas to compensate for the volumetric compression of gas in the open bottom dry chambers when air trapped at atmospheric pressure at the surface is lowered to great depths. Other combinations of subsea primary treatment components and their locations are possible. Furthermore, certain components can be deployed on the return riser 50 analogously to the deployment on the marine drilling riser 36.

In an alternative embodiment, the first and second stages of the processing systems and the gas separator are located on a particular riser section. The particular riser section must be sized to be driven through the basement deck hole in the surface drilling rig, and which preferably has a horizontal cross-section no larger than the outline of the BOP stack. The components of such a system, for example a pair of gumbo boxes and a pair of horizontal gas/sludge separators are mounted on a frame attached to the dedicated riser section. Ducts for cuttings, jet pumps and cuttings lines can also be mounted on this riser section. This makes it possible to assemble the connections completely modularly between these components and the annulus within the marine drill riser and the BOP stack on the surface before the drill riser is installed in the subsea well.

Other modifications, changes and substitutions are also intended in this foregoing description. Furthermore, certain features of the invention can be used without corresponding other features as described in these exemplary embodiments.

Claims (10)

1. Method for drilling an offshore borehole in an earth formation comprising: - drilling the borehole (16) using a drill string (34) which extends into the borehole (16); - pumping of drilling fluid from a surface drilling facility through the drill string (34), as the drilling fluid flows from the drill string (34) into the borehole (16), whereby drilling cuttings from the drilling operation are entrained in the drilling fluid; - treating the drilling fluid by causing the drilling fluid to flow into a subsea treatment system (22) to remove the cuttings from the drilling fluid; and - returning the treated drilling fluid to the surface by means of a return pump system (26) where the drilling fluid flows into the subsea treatment system (22) via an outlet opening in the drill riser (36), characterized in that the borehole (16) is provided with a casing (40) and a blowout valve (BOP) (38) arranged between the casing (40) and said outlet opening in the drill riser (36) and that the drilling fluid flows to the riser (36) via said casing (40) and said BOP (38). 2. Method according to claim 1, characterized in that the treated drilling fluid flows from the underwater treatment system (22) into a mud tank (80A) from which the drilling fluid flows to the return pump system (26) via a suction line (94). 3. Method according to claim 1 or 2, characterized by leading the returned drilling fluid to the drilling facility (30, 12) on the surface for re-injection. 4. Method according to one of the claims 1-3, characterized in that the step of treating the drilling fluid comprises leading the drilling fluid into a gas chamber (72) at ambient pressure near the seabed through an overflow pipe (74) and separating the drilling cuttings on gumbo rails and leading the drilling fluid to the mud tank (80A) and transport the cuttings away from the subsea treatment system (22) for disposal. 5. Method according to claim 4, characterized in that the transport of the drilling cuttings away from the underwater treatment system (22) for disposal comprises dropping the drilling cuttings from the end of the gumbo rails into the sea via an open gas chamber (72) at ambient pressure, collection of the drilling cuttings in a disposal mine (84) below the gas chamber (72) with an open bottom and at ambient pressure to draw the cuttings out of the disposal mine (84) by means of a jet pump (86) and transport the cuttings to a disposal site away from the subsea treatment system (22) through a line (88) ) for the drill cuttings. 6. Method according to one of claims 1-5, characterized in that the step of treating the drilling fluid comprises separating gas that may penetrate into the drilling fluid from the soil formation under a well device upstream in relation to the return pump system (26). 7. Method according to one of claims 1-6, characterized by treating the drilling fluid after returning to the surface in a secondary treatment system (28) to remove gas and fine cuttings particles from there. 8. Method according to one of claims 1-7, characterized by selectively isolating the hydrostatic piece with drilling fluid in the drill string (34) from the relatively smaller fluid pressure in the drill hole (16) by means of a pressure-activated drill string shut-off valve (20) arranged in the drill string (34) when drilling fluid circulation is interrupted. 9. Device for drilling an offshore borehole in an earth formation comprising: - a drill string (34) which extends into the borehole (16); - a pump for pumping drilling fluid from a drilling facility (12) on the surface via the drill string (34) and from the drill string (34) into the borehole (16), whereby the cuttings from the drilling operation are entrained in the drilling fluid; - a subsea treatment system (22) for treating the drilling fluid by causing the drilling fluid to flow into the subsea treatment system (22) to remove the cuttings from the drilling fluid; and - a return pump system (26) for returning the treated drilling fluid to the surface, the system further comprising a drill riser (36) provided with an outlet opening so that the drilling fluid can flow to the subsea treatment system (22), characterized in that the borehole (16) is provided with a casing (40) and a blowout valve (BOP) (38) arranged between the casing (40) and said outlet opening in the drill riser (36). 10. Device according to claim 9, characterized in that it further comprises a pressure-activated drill string shut-off valve (20) arranged in the drill string (34), which closes upon a pressure difference across the valve (20) due to the drilling fluid circulation through the drill string (34) being interrupted, in order to prevent outflow of drilling fluid from the drill string (34) into the borehole (16).