FLUID TRANSFER DEVICE USABLE IN MANAGED PRESSURE AND DUAL GRADIENT DRILLING

Abstract

A fluid transfer device for use in wellbore drilling includes at least one pressure vessel having a fluid port at a bottom thereof for entry and discharge of one of a working fluid or a power fluid and a fluid port at a top thereof for entry and discharge of the other of the power fluid or the working fluid. The pressure vessel has a barrier fluid between the power fluid and the working fluid. Valves are coupled to the power fluid port for selective introduction of the power fluid into the at least one pressure vessel. Valves are coupled to the working fluid port such that the working fluid is constrained to flow in only one direction.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

Names of the Parties to a Joint Research Agreement

Not Applicable

BACKGROUND

This disclosure relates generally to the field of fluid transfer devices. More specifically, the invention relates to fluid transfer devices usable in so-called managed pressure drilling or dual-gradient drilling systems.

U.S. Pat. No. 8,783,379 discloses a so-called “barrierless” fluid transfer device wherein a power fluid is introduced into and removed from one or more pressure containment vessels. Movement of the power fluid into and out of the pressure containment vessel(s) causes corresponding, opposite movement of working fluid into and out of the pressure vessel(s) to move the power fluid from a system inlet to a system outlet, and wherein energy of the power fluid is transferred to the working fluid. In the fluid transfer device disclosed in the '379 patent, no physical barrier is disposed between the power fluid and the working fluid. Mixing of the power fluid and the working fluid is minimized by selecting dimensions of the pressure vessel selected with respect to a rate of movement of the power fluid into and out of the at least one pressure vessel.

SUMMARY

One aspect of the present disclosure related to a fluid transfer device for use in wellbore drilling that includes at least one pressure vessel having a fluid port at a bottom thereof for entry and discharge of a working fluid or a power fluid and a fluid port at a top thereof for entry and discharge of a power fluid or a working fluid. The pressure vessel has no physical barrier between the power fluid and the working fluid. Valves are coupled to the power fluid port for selective introduction of the power fluid into the at least one pressure vessel. Valves are coupled to the working fluid port such that the working fluid is constrained to flow in only one direction.

Other aspects and advantages of the invention will be apparent from the description and claims which follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example drilling system using a separate drilling fluid return line having a pump therein to provide a selected fluid pressure in a wellbore annulus.

FIG. 1A shows an alternative drilling system.

FIG. 2 shows one an example of a fluid transfer device according to the disclosure

FIG. 3 shows a pumping system using an energy transfer device according to the disclosure.

DETAILED DESCRIPTION

FIG. 1 shows an example embodiment of a drilling vessel 10 floating on a body of water 12 with the bottom thereof shown at 14. While a floating drilling vessel is shown, it is to be understood that any other type of drilling vessels including bottom supported drilling vessels may be used in accordance with the present disclosure. A riser pipe 16 connects the drilling vessel 10 to a subsea wellhead 18 which may be provided with pressure control devices such as blowout preventers and other necessary valves (not shown separately). The wellhead 18 may be mounted on the upper end of a wellbore casing 20 which extends below the water bottom 14. The upper end of the riser pipe 16 may be supported from the drilling vessel 10 by cables or lines 22 connected to constant tensioning devices 24 in a known manner. A slip joint 26 may be provided in the riser pipe 16 proximate its upper end and a drill string 28 is supported within the riser pipe 16 from a derrick (not shown) or similar hoisting device disposed on the drilling vessel 10.

A seal 30 may be provided in the upper end of the riser pipe 16. The seal 30 can be a Hydril brand Bag Type BOP such as Type GL or GK shown in the 1978-79 Composite Catalog, Pages 36-40. To decrease wear on the seal 30 during operation, an optimal section or joint of polished drill pipe can be threaded into the drill string 28 just below the kelly or top drive (neither shown for clarity of the illustration) and kept in that position during the drilling of a well. A light-weight fluid conduit 32 is connected at a selected point 34 to the interior of the riser pipe 16 and extends to a pump 36 and a supply of lightweight fluid (not shown) which may be on the drilling vessel 10. Lightweight in the present context means a fluid having a specific gravity lower than the specific gravity of a drilling fluid (“mud”) pumped into the wellbore as will be further explained with reference to FIG. 1A.

A return mud flow line 38 hydraulically connects into the annulus of the riser pipe 16 at a selected position above the wellhead 18, e.g., at outlet 35, and extends to mud return tanks and facilities 40 which may be disposed on the drilling vessel 10. The return mud line 38 can be one of the “kill and choke” lines with appropriate bypass valving for a fluid transfer device system 42. A fluid transfer device system 42 according to the present disclosure may be hydraulically connected in the lower end of the return mud return flow line 38.

In FIG. 1, the fluid transfer device system 42 may be controlled by a level control 43 to sense and control the level of the interface 45 between the lightweight fluid 33 and the heavier (higher specific gravity) drilling mud 37. This prevents a full head of drilling mud in the riser pipe 16 from being applied to the drilling mud at depth below the wellhead 18. In some embodiments, there may be a plurality of spaced apart of level controls 43, 43A along the riser pipe 16 with output lines 41, 41A extending to the surface where it is then possible to select which level 45, 45A, etc., is needed to obtain the desired fluid pressure gradient inside the riser pipe 16 and the wellbore (below wellhead 18). The output from the selected level control 43, 43A is used to send a control signal along a control line 39 to the fluid transfer device system 42. The level of the lightweight fluid interface 45 may be controlled by a liquid level control sensor 47 with a suitable circuit to average any heave effect on the length of the riser pipe 16. Elevation of the interface 45 is detected in container 49 which is connected to line 32. In the case where the lightweight fluid is a gas, an interface level between the gas and the drilling mud may be controlled by a pressure regulator instead of the level sensor 47. The output of the liquid level control sensor 47 or of the pressure regular controls pump 36 so as to maintain a constant level 45 or selected pressure.

The lightweight fluid 33 may, for example, be sea water, which has a specific gravity of approximately 8.6 pounds per gallon or the lightweight fluid 33 may be a gas such as nitrogen gas. The drilling mud 37 which it replaced may have specific gravity as much as 18 pounds per gallon or more. Without the system shown in FIG. 1, the tension needed to be applied to riser 16 from the vessel 10 would typically be 400,000 pounds, depending on the depth of the water 12. With the system, using a lightweight fluid such as sea water, in the same water depth the tension which needs to be applied is only 200,000 pounds. This example is for a 16 inch diameter riser with flotation, in 1260 feet of water, and 18 pounds per gallon specific gravity drilling fluid.

Regardless of what kind of light fluid 33 is used (liquid or gas), pressure sensors may be used to control the interface level 45 by measuring the hydrostatic head of the fluid above the pressure sensor (not shown for clarity). In such cases the seal 30 may be omitted. See U.S. Pat. No. 7,677,329 issued to Stave and incorporated herein by reference.

It is to be clearly understood that the example drilling system shown in FIG. 1 is only one possible drilling system that can use a fluid transfer device according to the invention. Any other known configuration of drilling system using a fluid transfer device in the mud return line 38 may be used with the present fluid transfer device. Examples of such systems include, without limitation, systems shown in U.S. Pat. No. 7,264,058 issued to Fossli; U.S. Pat. No. 6,454,022 issued to Sangesland and U.S. Pat. No. 6,415,877 issued to Fincher et al., U.S. Pat. No. 7,677,329 issued to Stave, U.S. Pat. No. 6,505,691 issued to Judge et al., each of which is incorporated fully herein by reference.

For example, in another drilling system shown schematically in FIG. 1A, a mud suction pit 126 at the surface (at or above water surface 101) may be used as a source of drilling mud that is pumped into a drill pipe 142 by a surface mud pump 128. After passing through the drill pipe 142, the mud is used to operate the BHA 130 and returns through the annulus 146 between the drill pipe 142 and the riser pipe (16 in FIG. 1) or directly to the wellhead 125. Together the tubing 142, annulus 146 and the return line 132 constitute a subsea fluid circulation system.

An adjustable fluid transfer device 130 in the mud return line 132 may provide the ability to control the bottom hole pressure during drilling of the wellbore 90. The fluid transfer device 130 will be discussed below with reference to FIG. 3. A sensor P1 measures the pressure in the drill pipe 142 above an adjustable choke 150 in the drill pipe 142. Mud returning to the surface through the mud return line 132 may pass through solids removal and treatment devices, shown collectively as “shaker” 124 before being returned to the pit 126 for reuse.

A sensor P2 may be provided to measure the bottom hole fluid pressure and a sensor P3 may be provided to measure parameters indicative of the pressure or flow rate of the fluid in the annulus 146. Above the wellhead 125, a sensor P4 may be provided to measure parameters similar to those of P3 for the fluid in the return line 132 and a controlled valve 152 such as an adjustable choke may be provided to hold fluid in the return line 132. In operation, a control unit 140 and the sensor P1 operate to gather measurements relating to the drill pipe 142 pressure to ensure that the surface pump 128 is operating against a positive pressure, such as at sensor P5, to prevent cavitation, with the control unit 140 adjusting the choke 150 to increase the flow resistance it offers and/or to stop operation of the surface pump 128 as may be required. Similarly, the control system 140 together with sensors P2, P3 and/or P4 gather pressure measurements, relative to the desired bottom hole pressure and the pressure and/or flow rate of the fluid in the return line 132 and the annulus 146, necessary to achieve a predetermined pressure at any point along the wellbore 90. More particularly, the control system 140 acting at least in part in response to the data from sensors P2, P3 and/or P4 controls the operation of the adjustable fluid transfer device 130 to provide the predetermined downhole pressure operations, such as drilling, tripping, reentry, intervention and recompletion. In addition, the control system 140 controls the operation of the fluid circulation system to prevent undesired flow of fluid within the system when the fluid transfer device is not in operation. More particularly, when operation of the pumps 128, 130 is stopped a pressure differential may be present in the fluid circulation system tending to cause fluid to flow from one part of the system to another. To prevent this undesired situation, the control system operates to close choke 150 in the drill pipe 142, valve 152 in the return line 132 or both devices. The adjustable fluid transfer device 130 will be explained below in more detail with reference to FIGS. 2 and 3. A surface disposed control system 40 may obtain measurements from all of the sensors P1 through P5 and provide control signals to the control system 140 to operate the fluid transfer device 130 and the adjustable chokes 150, 152 as may be required.

In the embodiment shown in FIG. 1A, the fluid transfer device 130 may be used with the separate return line 132, as shown, or may be used in conjunction with a conventional mud-filled riser (not shown).

The fluid transfer device 130 may be used in conjunction with any kind of subsea drilling system; riserless tophole drilling (pre-blowput preventer or pre-BOP), riserless post-BOP drilling (as shown in FIG. 1A) as well as drilling with a marine drilling riser as shown in FIG. 1.

FIG. 2 shows an example embodiment of a fluid transfer device (FTD) system 42 according to the present disclosure. The FTD system 42 may include at least one, shown at 60, or more, a second being shown at 62, pressure containment vessels (“pressure vessels”). The pressure containment vessel(s) 60, 62 are preferably relatively large diameter as compared with similar pressure vessels used with pumps known in the art. See, e.g., U.S. Pat. No. 6,505,691 issued to Judge et al.; in the present example embodiment the pressure vessels 60, 62 may be 40 inches in diameter and about 20 feet in height. These example dimensions are not a limitation on the scope of the present disclosure. In the example embodiment shown in FIG. 2, a level of a barrier fluid L between a power fluid 69 in the upper part of the pressure vessel(s) 60, 62 and a working fluid M in the lower part of the pressure vessel(s) 60, 62 is shown. In the present example embodiment the working fluid M may be the drilling mud (shown entering the riser pipe 16 in FIG. 1 at 37). The power fluid 69 is introduced into the each pressure vessels 60, 62 from a line 38A extending to the drilling vessel (10 in FIG. 1). In the present example embodiment of fluid transfer device, separation between the power fluid 69 and the working fluid M may be provided by a barrier fluid L. The power fluid 69 may be any kind of light weight liquid (e.g., sea water) or it may be gas or combinations thereof. For purposes of the present disclosure, the dimensions of the pressure vessel(s) 60, 62 and the rate at which the power fluid 69 is introduced into the pressure vessel(s) 60, 62 may be selected such that very little, if any, mixing of the power fluid 69 and the working fluid M takes place. Thus, the power fluid 69 should be less dense (have a lower specific gravity) than the working fluid M and should in the short term be relatively immiscible in the working fluid M. As will be explained in more detail with reference to FIG. 3, as the power fluid 69 is introduced into the pressure vessel(s), 60, 62 the working fluid M is discharged through the bottom of the pressure vessel(s) 60, 62 and enters the mud return line 38. As the working fluid M is discharged into the mud return line 38, the level of the interface between the power fluid 69 and the working fluid M is lowered. When the level reaches a predetermined minimum height inside the pressure vessel(s), 60, 62 the power fluid 69 may be released from the pressure vessel(s) 60, 62 so that working fluid M from the well (e.g., below wellhead 18 in FIG. 1) can enter the pressure vessel(s) 60, 62 and cause the level to rise until a predetermined height is reached.

In some embodiments, the power fluid 69 may be less dense than the working fluid M. In such embodiments, the valves to be explained with reference to FIG. 3 would be inverted from the positions shown in FIG. 3, that is valves 64 would be at the port(s) at the bottom and valves 66 would be at the top port(s).

FIG. 3 shows the system of FIG. 2 in more detail. Introduction of power fluid 69 into each of the pressure vessels 60, 62 may be controlled by power (e.g., electric or hydraulic) operated valves 64 each in hydraulic communication proximate the top of the respective pressure vessel 60, 62 through a respective port 71. Two ports 71 are shown in each pressure vessel 60, 62, however only one port may also be used. Pressure of the power fluid 69 may be limited by a safety and/or regulator valve 74, which may be fixed pressure or selectable pressure. For each pressure vessel 60, 62, the valve 64 is opened until the level of the barrier fluid L drops to a selected height inside the pressure vessel 60, 62. The level of the barrier fluid L may be measured by a level transducer LT of types well known in the art, for example, acoustic ranging devices. When the selected level is reached, the power operated valve 64 that enables the power fluid 69 to enter the pressure vessel(s) 60, 62 (inlet valve) is closed. An adjustable choke 72 may be used to control the rate of fluid transfer in the pressure vessels(s) 60, 62. Each pressure vessel 60, 62 includes respective ports 71 proximate the bottom thereof. To admit drilling fluid from the riser pipe outlet (e.g., 35 in FIG. 1). Two ports 71 on the bottom of each pressure vessel 60, 62 are shown in the example embodiment of FIG. 3, however only one port may be used in other embodiments. In some embodiments, in order to provide a more or less continuous pumping or fluid movement from the wellbore to the surface, pressure vessels 60 and 62 may be be used in an alternating manner, where one pressure vessel is filled with working fluid while the other pressure vessel is being emptied of drilling fluid.

As explained above, in some embodiments the working fluid M may be less dense than the power fluid 69. In such embodiments, valves 66 (explained further below) may be coupled to the ports 71 at the top of the pressure vessel(s) 60, 62. Valves 64 would be coupled to the corresponding ports 71 at the bottom of the pressure vessel(s) 60, 62.

The system shown in FIG. 3 may in some embodiments include a pump 75 such as an electrically powered or hydraulically powered pump, coupled at its intake to the power fluid discharge (e.g., in line 72A after adjustable choke 72) to reduce the pressure at the power fluid discharge to below the hydrostatic pressure of the water (12 in FIG. 1) at the depth of the fluid transfer device system 42.

In some embodiments, a device 77 may be included between the wellbore discharge (35 in FIG. 1) and the working fluid intake (i.e., through valves 66) to the fluid transfer device system 42 to break up formation cuttings and coagulated drilling fluid and cuttings (“gumbo”) and to provide a nominal feed in pressure to the fluid transfer device system 42. In some embodiments the device 77 may be a slurry pump, which may, in addition to breaking up cuttings and coagulated fluid, provide a nominal pressure at the intake to the fluid transfer device system 42.

When the selected level of working fluid M is reached such that the inlet valve is closed, another power operated valve 74 (outlet valve) may be opened to discharge the power fluid 69 into the water 12. When the power fluid 69 is so depressurized, working fluid M can then flow into the bottom of the pressure vessel 60, 62 until the level of the barrier fluid L reaches a predetermined height inside the pressure vessel 60, 62. One way (check) valves 66 may be provided between the drilling fluid (mud) outlet on the wellbore (35 in FIG. 1) and inlet and outlet lines on the bottom of each pressure vessel 60, 62 so that the working fluid M flows only in the direction from the well connection (35 in FIG. 1) to the drilling vessel (10 in FIG. 1) up the mud return line 38. The check valves 66 may be passive or may be power actuated as are the inlet and outlet valves 64 for the power fluid 69. In some embodiments, under certain circumstances to be explained below, the power fluid 69 is preferably not discharged into the water but maybe returned to the surface or to a portion of the riser above the drilling fluid interface level. Valves 72 and 74 in such implementations may each have a corresponding discharge line 72A, 74A to conduct the discharged power fluid 69 to the surface or to the upper portion of the riser.

In certain situations, particularly during a gas kick (uncontrolled entry of formation gas into the wellbore), there may be a risk of gas-hydrates forming. The extent of gas hydrate formation will be dependent on the amount of free gas present in the well bore, in combination with the existing specific pressure and temperature near the bottom of the riser.

To prevent hydrate formation, it may be desirable to use a power fluid 69 that has certain chemical properties to resist hydrate formation. Such properties may result in the fact that the power fluid cannot be discharged to the water (12 in FIG. 1). Non-limiting examples of such power fluids are glycol or base oil. In such cases it may be necessary to have a separate path (as explained above with reference to 74A and 72A in FIG. 3) to return the power fluid 69 back to the drilling vessel (or to the riser above the mud interface 45 in FIG. 1) such that discharge to the water is avoided, and that the power fluid 69 can be reused. The return path can be either at separate return conduit (hard pipe or flexible) as shown in FIG. 3, or the power fluid 69 can be retuned back into the riser pipe (16 in FIG. 1). In the case of returning the fluid back into the riser pipe, the riser pipe must be liquid filled with a “blanket fluid” that preferably is the same as the power fluid. The power fluid return path may preferably be at an elevation above the mud/blanket fluid interface level. See, for example, 45 in FIG. 1.

Valves 64 and 66 may be one way vales or combined into two way valves as appropriate.

Near the top of the interior of each pressure vessel 60, 62, a permeable plate 70 such as a perforated plate or other type of flow diffuser may be included to reduce the possibility of the power fluid 69 “jetting” into the working fluid M, thus reducing the possibility of mixing the power fluid 69, the barrier fluid L and the working fluid M.

Generally speaking deep water drilling muds have specific gravity in the 10 to 18 pounds per gallon range or higher, nominally thus being dimensionless specific gravity of 1.2 to 2.16 or greater. Seawater is generally understood to have specific gravity of 1.025, however seawater specific gravity can vary based on pressure, salinity and temperature. In wellbore drilling, the specific gravity of seawater may be slightly greater based on the temperatures and pressures existing along the riser, but could be effectively less that at the bottom of the wellbore if the drill pipe is pulled from the surface. Using 1.025 as the specific gravity of seawater translates to 8.54 pounds per gallon as contrasted with distilled water at 8.33 pounds per gallon or fresh water at a nominal 8.34 pounds per gallon.

The barrier fluid L fluid specific gravity (SG) may be intermediate to the SG of the power fluid 69 and the working fluid M. In some embodiments the barrier fluid L SG may be roughly midway between the power fluid 69 SG and the drilling mud or working fluid M SG. For example, the barrier fluid SG may be intermediate (midway) between seawater SG if seawater is used as the power fluid 69 and the drilling mud SG when drilling mud is the working fluid M. A suitable range of SG for the barrier fluid L in this example may thus be in a range from about 9.27 to 13.27 pounds per gallon or 1.11 to 1.59 dimensionless specific gravity (DSG). In some embodiments, the SG of the barrier fluid L may be more or less than midway between the SG of the power fluid 69 and the drilling mud (working fluid M) in order to optimize properties of the barrier interfaces for certain considerations, such as minimizing mixing or to enhance mixing with one or the other, improving ‘wiping’ properties within the pressure vessel 60, 62. In some embodiments, the barrier fluid L may be supplemented by a movable disk D which has a SG selected to cause the movable disk D to float on the top of the barrier fluid L or to float on the top of the working fluid M (thus being at the bottom of the barrier fluid L). A movable disk D may further reduce mixing of the power fluid 69, the barrier fluid L and the working fluid M. In some embodiments, a plurality of axially spaced apart disks may be used. Each of the plurality of disks may be axially separated by a rod or support, may be free floating on top of and at the bottom of the barrier fluid L or may be separated, e.g., by magnetic repulsion and/or magnetorheologically active compositions for the barrier fluid L.

The disk(s) D may be made from engineered materials such as plastics, phenolic, composites and or combinations of the materials for both density selection and mechanical/structural/wiping properties. The disk(s) may be, for example:

• 1. solids;
• 2. mostly solids;
• 3. solids with controlled void volumes to reduce specific gravity;
• 4. solids with controlled void volumes filled to add specific gravity;
• 5. cast from one or more materials for mechanical property and SG management; and
• 6. cast/poured and contain weighting or lightening materials within the cast or poured materialsThe disks D could be linked together to control the nominal separation distance between them, for example the link could be:
• 1. fixed length;
• 2. variable length and set during rig-up of any particular pressure vessel(s);
• 3. variable by control during operation, using means to power and communicate that are known to those skilled in the art.

If the link(s) were long in relationship to the working length of the vessel and working/drilling fluid, then a change in the SG of the barrier fluid L may be used to be used to precisely adjust the bottom hole pressure (BHP) in the wellbore (below wellhead 18 in FIG. 1). Such precise adjustment may be also obtained without disks or links by changing the properties and thickness of the barrier fluid L layer.

More generally, when using an upper and lower disk having different effective densities to create a composite SG, the upper disk should be designed and weighted such as to be slightly ‘lighter’ (less dense) than the barrier fluid L but more dense than the power fluid 69 (e.g., seawater) above. This will cause the upper disk to remain substantially atop the barrier fluid L. The lower disk may be slightly more dense than the barrier fluid L and less dense than the working (drilling fluid) M. This will cause the lower disk to remain substantially atop the working fluid M. These disked could be linked by rod, chain or other device to further control their respective behavior,

The disks should have diameter to thickness ratio so to ensure the upper and lower surfaces thereof remain substantially perpendicular to the longitudinal axis of the pressure vessel and their desired motion. The value of this ratio likely in the range of 2, but will be a factor of the clearance between the disks/pucks and the bore and length of the working chamber.

In some embodiments multiple disks (more than two) could be used within the barrier fluid L to further improve the barrier fluid capacity to act to reduce mixing of the power fluid 69 and the working fluid M. Multiple disks would likely work best in a system where the disks are in some way linked by one or more ‘rods’. The ‘rod’ like device could be singularly mostly in the center of the disks, or the ‘rods’/links could be distributed in a radial fashion between the center and the disk edge.

The barrier fluid L may have a viscosity, polar/non polar solvent activity and surface tension properties such that the barrier fluid L tends to remain in a single contiguous mass; depending on surface tension properties and the polar/non-polar nature of the barrier fluid L it may or may not ‘wet’ the interior walls of the pressure vessel 60, 62. The barrier fluid L may act as a mass of jelly that tends to remain intact after being dropped into a container of fresh water or other fluid as might be considered for the working or drilling fluid. The barrier fluid L may also be a mass of selected SG non-polar liquid, such as oil, that floats within, above or below a water based fluid or other fluid type. In some embodiments the barrier fluid L may be hydrophobic to seawater (or the working fluid) and in the best case also hydrophobic to the drilling mud (working fluid M). The hydrophobic effect is the observed tendency of non-polar substances to aggregate when disposed in polar (aqueous) solutions and to thereby exclude polar liquid molecules from intermixing with the non-polar material.

In yet another embodiment the barrier fluid L may be two fluids where the upper fluid is hydrophobic to the seawater and the lower fluid is phobic to the drilling mud. The two barrier fluids may be slightly phobic with respect to each other; in some embodiments a SG difference keeps the two fluids substantially separated. Using one or more disks as explained above may improve performance.

A fluid transfer device used in a drilling system according to the various aspects of the present disclosure may provide lower maintenance costs, more efficient operation and lower cost to make than similar devices known in the art which rely on solid barriers to separate the working fluid from the power fluid.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A fluid transfer device for use in wellbore drilling, comprising: at least one pressure vessel having at least one fluid port proximate bottom thereof for entry and discharge of one of a working fluid or a power fluid and at least one fluid port proximate a top thereof for entry and discharge the other one of a power fluid or a working fluid;wherein the pressure vessel has a barrier fluid disposed between the power fluid and the working fluid, the barrier fluid having a specific gravity intermediate a specific gravity of the power fluid and a specific gravity of the working fluid, the power fluid having a different specific gravity than the working fluid;valves coupled to the power fluid port for selective introduction of the power fluid into the at least one pressure vessel; andvalves coupled to the working fluid port such that the working fluid is constrained to flow in only one direction.

2. The fluid transfer device of claim 1 further comprising a flow diffuser proximate a top of the interior of the at least one pressure vessel to reduce jetting of the power fluid and consequent mixing of the power fluid and the working fluid.

3. The fluid transfer device of claim 1 wherein the barrier fluid is phobic with respect to the power fluid.

4. The fluid transfer device of claim 1 wherein the barrier fluid is phobic with respect to the working fluid.

5. The fluid transfer device of claim 1 wherein the barrier fluid has a viscosity, polar/non polar solvent activity and surface tension properties such that the barrier fluid remains in a single contiguous mass during movement of the power fluid and the working fluid through the at least one pressure vessel.

6. The fluid transfer device of claim 1 wherein one of the valves coupled to the working fluid inlet is coupled to a drilling mud outlet of a subsea wellbore.

7. The fluid transfer device of claim 1 wherein one of the valves coupled to the working fluid port is coupled to a mud return line extending to a drilling vessel on the surface of a body of water.

8. The fluid transfer device of claim 1 wherein the power fluid comprises sea water.

9. The fluid transfer device of claim 1 further comprising an adjustable choke disposed in a power fluid discharge line to control a rate of fluid transfer.

10. The fluid transfer device of claim 1 further comprising a pump coupled at its intake to a power fluid discharge such that a pressure of the power fluid discharge is maintainable below a hydrostatic pressure of a body of water at a depth at which the fluid transfer device is disposed.

11. The fluid transfer device of claim 1 further comprising at least one disk disposed proximate the barrier fluid, the at least one disk having a specific gravity such that the at least one disk is disposed at a selected elevation with respect to the power fluid, the barrier fluid and the working fluid.

12. The fluid transfer device of claim 11 further comprising at least two disks spaced apart from each other by at least one link.

13. The fluid transfer device of claim 12 wherein a first one of the at least two disks has a specific gravity lower than a second one of the at least two disks such that the at least two disks such that the first one of the at least two disks is disposed proximate an interface between the barrier fluid and the power fluid and the second one of the at least two disks is disposed proximate an interface between the barrier fluid and the working fluid.

14. The fluid transfer device of claim 11 wherein the at least one disk has a diameter to thickness ratio so to ensure the upper and lower surfaces of the at least one disk remain substantially perpendicular to a longitudinal axis of the at least one pressure vessel and a direction of motion of the at least one disk within the at least one pressure vessel.

15. The fluid transfer device of claim 1 wherein the power fluid has a lower specific gravity than the working fluid and wherein the power fluid enters the at least one port on the top of the at least one pressure vessel.