power end mud pump free sample

The 2,200-hp mud pump for offshore applications is a single-acting reciprocating triplex mud pump designed for high fluid flow rates, even at low operating speeds, and with a long stroke design. These features reduce the number of load reversals in critical components and increase the life of fluid end parts.

The pump’s critical components are strategically placed to make maintenance and inspection far easier and safer. The two-piece, quick-release piston rod lets you remove the piston without disturbing the liner, minimizing downtime when you’re replacing fluid parts.

I’ve run into several instances of insufficient suction stabilization on rigs where a “standpipe” is installed off the suction manifold. The thought behind this design was to create a gas-over-fluid column for the reciprocating pump and eliminate cavitation.

When the standpipe is installed on the suction manifold’s deadhead side, there’s little opportunity to get fluid into all the cylinders to prevent cavitation. Also, the reciprocating pump and charge pump are not isolated.

The suction stabilizer’s compressible feature is designed to absorb the negative energies and promote smooth fluid flow. As a result, pump isolation is achieved between the charge pump and the reciprocating pump.

The isolation eliminates pump chatter, and because the reciprocating pump’s negative energies never reach the charge pump, the pump’s expendable life is extended.

Investing in suction stabilizers will ensure your pumps operate consistently and efficiently. They can also prevent most challenges related to pressure surges or pulsations in the most difficult piping environments.

Sigma Drilling Technologies’ Charge Free Suction Stabilizer is recommended for installation. If rigs have gas-charged cartridges installed in the suction stabilizers on the rig, another suggested upgrade is the Charge Free Conversion Kits.

Deep water drilling from a floating vessel typically involves the use of a large- diameter marine riser, e.g. a 21 -inch marine riser, to connect the floating vessel"s surface equipment to a blowout preventer stack on a subsea wellhead. The floating vessel may be moored or dynamically positioned at the drill site. However, dynamically-positioned drilling vessels are predominantly used in deep water drilling. The primary functions of the marine riser are to guide the drill string and other tools from the floating vessel to the subsea wellhead and to conduct drilling fluid and earth-cuttings from a subsea well to the floating vessel. The marine riser is made up of multiple riser joints, which are special casings with coupling devices that allow them to be interconnected to form a tubular passage for receiving drilling tools and conducting drilling fluid. The lower end of the riser is normally releasably latched to the blowout preventer stack, which usually includes a flexible joint that permits the riser to angularly deflect as the floating vessel moves laterally from directly over the well. The upper end of the riser includes a telescopic joint that compensates for the heave of the floating vessel. The telescopic joint is secured to a drilling rig on the floating vessel via cables that are reeved to sheaves on riser tensioners adjacent the rig"s moon pool. The riser tensioners are arranged to maintain an upward pull on the riser. This upward pull prevents the riser from buckling under its own weight, which can be quite substantial for a riser extending over several hundred feet. The riser tensioners are

adjustable to allow adequate support for the riser as water depth and the number of riser joints needed to reach the blowout preventer stack increases. In very deep water, the weight of the riser can become so great that the riser tensioners would be rendered ineffective. To ensure that the riser tensioners work effectively, buoyant devices are attached to some of the riser joints to make the riser weigh less when submerged in water. The buoyant devices are typically steel cylinders that are filled with air or plastic foam devices.

The maximum practical water depth for current drilling practices with a large diameter marine riser is approximately 7,000 feet. As the need to add to energy reserves increases, the frontiers of energy exploration are being pushed into ever deeper waters, thus making the development of drilling techniques for ever deeper waters increasingly more important. However, several aspects of current drilling practices with a conventional marine riser inherently limit deep water drilling to water depths less than approximately 7,000 feet. The first limiting factor is the severe weight and space penalties imposed on a floating vessel as water depth increases. In deep water drilling, the drilling fluid or mud volume in the riser constitutes a majority of the total mud circulation system and increases with increasing water depth. The capacity of the 21 -inch marine riser is approximately 400 barrels for every 1,000 feet. It has been estimated that the weight attributed to the marine riser and mud volume for a rig drilling at a water depth of 6,000 feet is 1,000 to 1,500 tons. As can be appreciated, the weight and space requirements for a drilling rig that can support the large volumes of fluids required for circulation and the number of riser joints required to reach the seafloor prohibit the use of the 21 -inch riser, or any other large-diameter riser, for drilling at extreme water depths using the existing offshore drilling fleet.

water waves and can result in high levels of energy being imparted on the drilling vessel and the riser, especially when the bottom end of the riser is disconnected from the blowout preventer stack. The dynamic stresses due to the interaction between the heave of the drilling vessel and the riser can result in high compression waves that may exceed the capacity of the riser.

In addition, before disconnecting the riser from the blowout preventer stack, operations must take place to condition the well so that the well may be safely abandoned. This is required because the well depends on the hydrostatic pressure of the mud column extending from the top end of the riser to the bottom of the well to

overcome the pore pressures of the formation. When the mud column in the riser is removed, the hydrostatic pressure gradient is significantly reduced and may not be sufficient to prevent formation fluid influx into the well. Operations to contain well pressure may include setting a plug, such as a storm packer, in the well and closing the blind ram in the blowout preventer stack.

A fourth limiting factor, relates to emergency disconnects such as when a dynamically positioned drilling vessel experiences a drive off. A drive off is a condition when a floating drilling vessel loses station keeping capability, loses power, is in imminent danger of colliding with another marine vessel or object, or experiences other conditions requiring rapid evacuation from the drilling location. As in the case of the storm disconnect, well operations are required to condition the well for abandoning. However, there is usually insufficient time in a drive off to perform all of the necessary safe abandonment procedures. Typically, there is only sufficient time to hang off the drill string from the pipe/hanging rams and close the shear/blind rams in the blowout preventer before disconnecting the riser from the blowout preventer stack.

The well hydrostatic pressure gradient derived from the riser height is trapped below the closed blind rams when the riser is disconnected. Thus, the only barrier to the influx of formation fluid into the well is the closed blind rams since the column of mud below the blind rams is insufficient to prevent influx of formation fluid into the well. Prudent drilling operations require two independent barriers to prevent loss of well control. When the riser is disconnected from the blowout preventer stack, large volumes of mud will be dumped onto the seafloor. This is undesirable from both an economic and environmental standpoint.

These sediments are significantly influenced by the overlying body of water and the circulating mud column need only be slightly denser than seawater to fracture the formation. Fortunately, because of the higher bulk density of the rock, the fracture pressure rapidly increases with the depth of penetration below the seafloor and will present a less serious problem after the first few thousand feet are drilled. However, abnormally high pore pressures which are routinely encountered up to 2,000 feet below the seafloor continue to present a problem both when drilling the initial section of the well with seawater and when drilling beyond the initial section of the well with seawater or weighted drilling fluid. The challenge then becomes balancing the internal pressures of the formation with the hydrostatic pressure of the mud column while continuing drilling of the well. The current practice is to progressively run and cement casings, the next inside the previous, into the hole to protect the "open hole" sections possessing insufficient fracture pressure while allowing weighted drilling fluids to be used to overcome formation pore pressures. It is important that the well be completed with the largest practical casing through the production zone to allow production rates that will justify the high-cost of deep-water developments. Production rates exceeding 10,000 barrels per day are common for deep-water developments, and too small a production casing would limit the productivity of the well, making it uneconomical to complete. The number of casings run into the hole is significantly affected by water depth.

The multiple casings needed to protect the "open hole" while providing the largest practical casing through the production zone requires that the surface hole at the seafloor be larger. A larger surface hole in turn requires a larger subsea wellhead and blowout preventer stack and a larger blowout preventer stack requires a larger marine riser. With a larger riser, more mud is required to fill the riser and a larger drilling vessel is required to carry the mud and support the riser. This cycle repeats itself as water depth increases.

It has been identified that the key to breaking this cycle lies in reducing the hydrostatic pressure of the mud in the riser to that of a column of seawater and providing mud with sufficient weight in the well to maintain well control. Various concepts have

been presented in the past for achieving this feat; however, none of these concepts known in the prior art have gained commercial acceptance for drilling in ever deeper waters. These concepts can be generally grouped into two categories: the mud lift drilling with a marine riser concept and the riserless drilling concept. The mud lift drilling with a marine riser concept contemplates a dual-density mud gradient system which includes reducing the density of the mud returns in the riser so that the return mud pressure at the seafloor more closely matches that of seawater. The mud in the well is weighted to maintain well control. For example, U.S. Patent No. 3,603,409 to Watkins et al. and U.S. Patent No. 4,099,583 to Maus et al. disclose methods of injecting gas into the mud column in the marine riser to lighten the weight of the mud.

The riserless drilling concept contemplates eliminating the large-diameter marine riser as a return annulus and replacing it with one or more small-diameter mud return lines. For example, U.S. Patent No. 4,813,495 to Leach removes the marine riser as a return annulus and uses a centrifugal pump to lift mud returns from the seafloor to the surface through a mud return line. A rotating head isolates the mud in the well annulus from the open seawater as the drill string is run in and out of the well.

Drilling rates are significantly affected by the magnitude of the difference between formation pore pressure and mud column pressure. This difference, commonly called "overbalance", is adjusted by changing the density of the mud column. Overbalance is estimated as the additional pressure required to prevent the well from kicking, either during drilling or when pulling a drill string out of the well. This overbalance estimate usually takes into account factors like inaccuracies in predicting formation pore pressures and pressure reductions in the well as a drill string is pulled from the well. Typically, a minimum of 300 to 700 psi overbalance is maintained during drilling operations. Sometimes the overbalance is large enough to damage the formation.

the overbalance is reduced to zero. An even greater increase in drilling rate can be achieved if the mud column pressure is decreased to an underbalanced condition, i.e. mud column pressure is less than formation pressure. Thus, to improve drilling rates, it may be desirable to drill a well in an underbalanced mode or with a minimum of overbalance. In conventional drilling operations, it is impractical to reduce the mud density to allow faster drilling rates and then increase the mud density to permit tripping the drill string. This is because the circulation time for the complete mud system lasts for several hours, thus making it expensive to repeatedly decrease and increase mud density. Furthermore, such a practice would endanger the operation because a miscalculation could result in a kick.

In general, in one aspect, a positive-displacement pump comprises multiple pumping elements, each pumping element comprising a pressure vessel with a first and a second chamber and a separating member disposed between the first and second chambers. The first chambers and the second chambers are hydraulically connected to receive and discharge fluid, wherein the separating members move within the pressure vessels in response to pressure differential between the first and second chambers. A valve assembly having suction and discharge valves communicates with the first chambers. The suction and discharge valves are operable to permit fluid to alternately flow into and out of the first chambers. A hydraulic drive alternately supplies hydraulic fluid to and withdraws hydraulic fluid from the second chambers such that the fluid discharged from the first chambers is substantially free of pulsation.

FIG. 2A is a detailed view of the well control assembly shown in FIG. 1. FIG. 2B is a detailed view of the mud lift module shown in FIG. 1. FIG. 2C is a detailed view of the pressure-balanced mud tank shown in FIG. 1.

FIG. 8 is an elevation view of a subsea mud pump. FIG. 9A is a cross section of a diaphragm pumping element. FIG. 9B is a cross section of a piston pumping element.

FIG. 16 is a diagram of a mud circulation system for the offshore drilling system shown in FIG. 1. FIG. 17 is a graph of depth versus pressure for a well drilled in a water depth of

FIG. 20A is a graph of depth versus pressure for a well drilled in a water depth of 5,000 feet for a dual-density mud gradient system which has a mudline pressure less than seawater pressure.

FIG. 21 illustrates the offshore drilling system of FIG. 1 with a mud lift module mounted on the seafloor. FIGS. 22A and 22B are elevation views of retrievable subsea components of the offshore drilling system shown in FIG. 21.

FIG. 26 is a top view of another embodiment of the return line riser shown in FIG. 23. FIG. 27 illustrates the offshore drilling system of FIG. 1 without a marine riser and with a mud lift module mounted on the seafloor.

DETAILED DESCRIPTION FIG. 1 illustrates an offshore drilling system 10 where a drilling vessel 12 floats on a body of water 14 which overlays a pre-selected formation. The drilling vessel 12 is dynamically positioned above the subsea formation by thrusters 16 which are activated by on-board computers (not shown). An array of subsea beacons (not shown) on the seafloor 17 sends signals which are indicative of the location of the drilling vessel 12 to hydrophones (not shown) on the hull of the drilling vessel 12. The signals received by the hydrophones are transmitted to on-board computers. These on-board computers process the data from the hydrophones along with data from a wind sensor and other auxiliary position-sensing devices and activate the thrusters 16 as needed to maintain the drilling vessel 12 on station. The drilling vessel 12 may. also be maintained on station by using several anchors that are deployed from the drilling vessel to the seafloor. Anchors, however, are generally practical if the water is not too deep.

A drilling rig 20 is positioned in the middle of the drilling vessel 12, above a moon pool 22. The moon pool 22 is a walled opening that extends through the drilling vessel 12 and through which drilling tools are lowered from the drilling vessel 12 to the seafloor 17. At the seafloor 17, a conductor pipe 32 extends into a well 30. A conductor housing 33, which is attached to the upper end of the conductor pipe 32, supports the conductor pipe 32 before the conductor pipe 32 is cemented in the well 30. A guide structure 34 is installed around the conductor housing 33 before the conductor housing 33 is run to the seafloor 17. A wellhead 35 is attached to the upper end of a surface pipe 36 that extends through the conductor pipe 32 into the well 30. The wellhead 35 is of conventional design and provides a method for hanging additional casing strings in the well 30. The wellhead 35 also forms a structural base for a wellhead stack 37.

The wellhead stack 37 includes a well control assembly 38, a mud lift module 40, and a pressure-balanced mud tank 42. A marine riser 52 between the drilling rig 20 and the wellhead stack 37 is positioned to guide drilling tools, casing strings, and other equipment from the drilling vessel 12 to the wellhead stack 37. The lower end of the marine riser 52 is releasably latched to the pressure-balanced mud tank 42, and the upper end of the marine riser 52 is secured to the drilling rig 20. Riser tensioners 54 are provided to maintain an upward pull on the marine riser 52. Mud return lines 56 and 58, which may be attached to the outside of the marine riser 52, connect flow outlets (not shown) in the mud lift module 40 to flow ports in the moon pool 22. The flow ports in the moon pool 22 serve as an interface between the mud return lines 56 and 58 and a mud return system (not shown) on the drilling vessel 12. The mud return lines 56 and 58 are also connected to flow outlets (not shown) in the well control assembly 38, thus allowing them to be used as choke/kill lines. Alternatively, the mud return lines 56 and 58 may be existing choke/kill lines on the riser.

A drill string 60 extends from a derrick 62 on the drilling rig 20 into the well 30 through the marine riser 52 and the wellhead stack 37. Attached to the end of the drill string 60 is a bottom hole assembly 63, which includes a drill bit 64 and one or more drill collars 65. The bottom hole assembly 63 may also include stabilizers, mud motor, and

other selected components required for drilling a planned trajectory, as is well known in the art. During normal drilling operations, the mud pumped down the bore of the drill string 60 by a surface pump (not shown) is forced out of the nozzles of the drill bit 64 into the bottom of the well 30. The mud at the bottom of the well 30 rises up the well annulus 66 to the mud lift module 40, where it is diverted to the suction ends of subsea mud pumps (not shown). The subsea mud pumps boost the pressure of the returning mud flow and discharge the mud into the mud return lines 56 and/or 58. The mud return lines 56 and/or 58 then conduct the discharged mud to the mud return system (not shown) on the drilling vessel 12. The drilling system 10 is illustrated with two mud return lines 56 and 58, but it should be clear that a single mud return line or more than two mud return lines may also be used. Clearly the diameter and number of the return lines will affect the pumping requirements for the subsea mud pumps in the mud lift module 40. The subsea mud pumps must provide enough pressure to the returning mud flow to overcome the frictional pressure losses and the hydrostatic head of the mud column in the return lines. The wellhead stack 37 includes subsea diverters (not shown) which seal around the drill string 60 and form a separating barrier between the riser 52 and the well annulus 66. The riser 52 is filled with seawater so that the hydrostatic pressure of the fluid column at the seafloor or mudline or separating barrier formed by the subsea diverters is that of seawater. Filling the riser with seawater, as opposed to mud, reduces the riser tension requirements. The riser may also be filled with other fluids which have a lower specific gravity than the mud in the well annulus.

be used. Additional preventers may also be required depending on the preferences of the drilling operator. The ram preventers are equipped with pipe rams for sealing around a pipe and shear/blind rams for shearing the pipe and sealing the well. The ram preventers 70 and 72 have flow ports 76 and 78, respectively, that may be connected to choke/kill lines (not shown). A wellhead connector 88 is secured to the lower end of the ram preventer 70. The wellhead connector 88 is adapted to mate with the upper end of the wellhead 35 (shown in FIG. 1).

The LMRP 44 includes annular preventers 90 and 92 and a flexible joint 94. However, the LMRP 44 may take on other configurations, e.g., a single annular preventer and a flexible joint. The annular preventers 90 and 92 have flow ports 98 and 100 that may be connected to choke/kill lines (not shown). The lower end of the annular preventer 90 is connected to the upper end of the ram preventers 72 by a LMRP connector 93. The flexible joint 94 is mounted on the upper end of the annular preventer 92. A riser connector 114 is attached to the upper end of the flexible joint 94. The riser connector 114 includes flow ports 113 which may be hydraulically connected to the flow ports 76, 78, 98, and 100. The LMRP 44 includes control modules (not shown) for operating the ram preventers 70 and 72, the annular preventers 90 and 92, various connectors and valves in the wellhead stack 37, and other controls as needed. Hydraulic fluid is supplied to the control modules from the surface through hydraulic lines (not shown) that may be attached to the outside of the riser 52 (shown in FIG. 1).

Mud lift module FIG. 2B shows the components of the mud lift module 40 which was previously illustrated in FIG. 1. As shown, the mud lift module 40 includes subsea mud pumps 102, a flow tube 104, a non-rotating subsea diverter 106, and a rotating subsea diverter 108. The lower end of the flow tube 104 includes a riser connector 110 which is adapted to mate with the riser connector 114 (shown in FIG. 2 A) at the upper end of the flexible joint 94. When the riser connector 110 mates with the riser connector 114, the flow ports 111 in the riser connector 110 are in communication with the flow ports 113 (shown in

FIG. 2 A) in the riser connector 114. A riser connector 112 is mounted at the upper end of the subsea diverter 108. The flow ports 111 in the riser connector 110 are connected to flow ports 116 in the riser connector 112 by pipes 118 and 120, and the pipes 118 and 120 are in turn hydraulically connected to the discharge ends of the subsea mud pumps 102. The suction ends of the subsea mud pumps 102 are hydraulically connected to flow outlets 125 in the flow tube 104.

The subsea diverters 106 and 108 are arranged to divert mud from the well annulus 66 (shown in FIG. 1) to the suction ends of the subsea mud pumps 102. The diverters 106 and 108 are also adapted to slidingly receive and seal around a drill string, e.g., drill string 60. When the diverters seal around the drill string 60, the fluid in the flow tube 104 or below the diverters is isolated from the fluid in the riser 52 (shown in FIG. 1) or above the diverters. The diverters 106 and 108 may be used alternately or together to sealingly engage a drill string and, thereby, isolate the fluid in the annulus of the riser 52 from the fluid in the well annulus 66. It should be clear that either the diverter 106 or 108 may be used alone as the separating medium between the fluid in the riser 52 and the fluid in the well annulus 66. A rotating blowout preventer (not shown), which could be included in the well control assembly 38 (shown in FIG. 2 A), may also be used in place of the diverters. The diverter 108 may also be mounted on the annular preventer 92 (shown in FIG. 2 A), and mud flow into the suction ends of the subsea pumps 102 may be taken from a point below the diverter.

Non-rotating subsea diverter FIG. 3 A shows a vertical cross section of the non-rotating subsea diverter 106 which was previously illustrated in FIG. 2B. As shown, the non-rotating subsea diverter 106 includes a head 126 that is fastened to a body 128 by bolts 130. However, other means, such as a screwed or radial latched connection, may be used in place of bolts 130. The body 128 has a flange 131 that may be bolted to the upper end of the flow tube 104, as shown in FIG. 2B. The head 126 and body 128 are provided with bores 132 and 134, respectively. The bores 132 and 134 form a passageway 136 for receiving a drill string,

e.g., drill string 60. The body 128 has a closing cavity 138 and an opening cavity 139. A piston 140 is arranged to move inside the cavities 138 and 139 in response to pressure of the hydraulic fluid fed into these cavities. At the upper end of the body 128 is a sleeve 142 and cover 143 which guide the piston 140 as it moves inside the cavities 138 and 139.

The cavity 138 is enveloped by the body 128, the piston 140, and the sleeve 142. The cavity 139 is enveloped by the body 128, the piston 140, and cover 143. As the piston 140 moves inside the cavities 138 and 139, seal rings 144 contain hydraulic fluid in the cavities. The sleeve 142 is provided with holes 148 for venting fluid out of a cavity 145 below the piston 140. A resilient, elastomeric, toroid-shaped, sealing element 150 is located between the upper end of the piston 140 and a tapered portion 152 of the internal wall of the head 126. The sealing element 150 may be actuated to seal around a drill string, e.g., drill string 60, in the passageway 136.

Rotating subsea diverter FIG. 4A shows a vertical cross section of the rotating subsea diverter 108 which was previously illustrated in FIG. 2B. As shown, the rotating subsea diverter 108 includes a housing body 162 with flanges 164 and 166. The flange 164 is arranged to mate with the upper end of the diverter 106 (shown in FIG. 3 A). The housing body 162 is provided with a bore 168 and pockets 170. The pockets 170 are distributed along a circumference of the housing body 162. Inside each pocket 170 is a retractable landing shoulder 174 and a lock 176. Hydraulic actuators 177 are provided to operate the locks 176. Although the lock 176 is shown as being hydraulically actuated, it should be clear that the lock 176 may be actuated by other means, e.g., the lock 176 may be radially loaded with springs. The lock 176 may also incorporate a mechanism that permits intervention by a remote operated vehicle (ROV) such as a "T" handle in series with the actuator for gripping by the ROV manipulator.

As shown in FIG. 4E, the spindle assembly 1740 further comprises a spindle 1760 which extends through the spindle housing 1742. The spindle 1760 is suspended in the spindle housing 1742 by bearings 1762 and 1764. The bearing 1762 is secured between the spindle housing 1742 and the spindle 1760 by a bearing cap 1765. The spindle housing 1742, the spindle 1760, and the bearings 1762 and 1764 define a chamber 1768 which holds lubricating fluid for the bearings. The bearing cap 1765 may be removed to access the chamber 1768. Pressure intensifiers 1766 are provided to boost the pressure in the chamber 1768 as necessary so that the pressure in the chamber 1768 balances or exceeds the pressure above and below the spindle 1760. Referring back to FIG. 4C, the spindle 1760 includes an upper packer element 1772, a lower packer element 1774, and a central passageway 1776 for receiving a drill string, e.g., drill string 1770.

A landing shoulder 1778 is disposed in a pocket 1780 in the body 1716. The landing shoulder 1778 may be extended out of the pocket 1780 or retracted into the pocket 1780 by a hydraulic actuator 1782. When the landing shoulder 1778 is extended out of the pocket 1780, it prevents the spindle assembly 1740 from falling out of the body 1716. As shown in FIG. 4F, the hydraulic actuator 1782 comprises a cylinder 1784 which houses a piston 1786. The cylinder 1784 is arranged in a cavity 1788 on the outside of the body 1716 and held in place by a cap 1790. A threaded connection 1792 attaches one side of the piston 1786 to the landing shoulder 1778. The piston 1786 extends from the landing shoulder 1778 into a cavity 1794 in the cap 1790. The cap 1790 and the cylinder 1784 include ports 1796 and 1798 through which fluid may be fed into or discharged from the cavity 1794 and the interior of the cylinder 1784, respectively. Dynamic seals 1800 are provided on the piston 1786 to contain fluid in the cylinder 1784 and the cavity 1794. Additional static seals 1802 are provided between the cylinder 1784 and cap 1790 and the body 1716 to keep fluid and debris out of the cylinder 1784.

The landing shoulder 1778 is in the fully extended position when the piston 1786 touches a surface 1804 in the cylinder 1784. The landing shoulder 1778 is in the fully retracted position when it touches a surface 1806 in the body 1716. The piston 1786 is normally biased toward the surface 1804 by a spring 1808. In this position, the landing

shoulder 1778 is fully extended and the spindle assembly 1740 seats on the landing shoulder 1778. The spring force must overcome the force due to the pressure at the lower end of the spindle 1760 to keep the piston 1786 in contact with the surface 1804. If the spring force is not sufficient, fluid may be fed into the cavity 1794 at a higher pressure than the fluid pressure in the cylinder 1784. The pressure differential between the cavity 1794 and the cylinder 1784 would provide the additional force necessary to move the piston 1786 against the surface 1804 and retain the landing shoulder 1778 in the fully extended position.

When it is desired to retract the landing shoulder 1778, fluid pressure may be fed into the cylinder 1784 at a higher pressure than the fluid pressure in the cavity 1794. The pressure differential between the cylinder 1784 and cavity 1794 moves the piston 1786 to the retracted position. The ports 1796 in the cap 1790 allow fluid to be exhausted from the cavity 1794 as the piston 1786 moves to the retracted position. Again, to move the piston 1786 back to the extended position, fluid pressure is released from the cylinder 1784, and, if necessary, additional fluid pressure is introduced into the cavity 1794. Pressure sensors may be used to monitor the pressure below the spindle assembly 1740 and in the cavity 1794 and cylinder 1784 to help determine how pressure may be applied to fully extend or retract the landing shoulder 1778. A position indicator (not shown) may be added to signal the drilling operator that the piston is in the extended or retracted position.

A connector 1810 on the head 1712 and the mounting flange 1812 at the lower end of the body 1716 allow the diverter 1710 to be interconnected in the wellhead stack 37. In one embodiment, the mounting flange 1812 may be attached to the upper end of the flow tube 104 (shown in FIG. 2B) and the connector 1810 may provide an interface between the mud lift module 40 (shown in FIG. 2B) and the pressure-balanced mud tank 42 or the riser 52 (shown in FIG. 1). When the mounting flange 1812 is attached to the upper end of the flow tube 104, the space 1818 below the packer 1774 is in fluid communication with the well annulus 66 (shown in FIG. 1).

The diameters of the vertical bores 1714 and 1718 are such that any tool that can pass through the marine riser 52 (shown in FIG. 1) can also pass through them. The retractable landing shoulder 1778 may be retracted to allow passage of large tools and may be extended to allow proper positioning of the spindle assembly 1740 within the bores 1714 and 1718. The spindle assembly 1740 can be appropriately sized to pass through the marine riser 52 and can be run into and retrieved from the vertical bores 1714 and 1718 on a drill string, e.g., drill string 1770. As shown, a handling tool 1771 on the drill string 1770 is adapted to engage the lower packer element 1774 of the spindle 1760 such that the spindle assembly 1740 can be run into the vertical bores 1714 and 1718. When the spindle assembly 1740 lands on the landing shoulder 1774, the inner elastomeric element 1748 is energized to engage the spindle assembly 1740. Once the spindle assembly 1740 is engaged, the handling tool 1771 can be disengaged from the spindle assembly 1740 by further lowering the drill string 1770. The handling tool 1771 will again engage the spindle assembly 1740 when it is pulled to the lower packer element 1774, thus allowing the spindle assembly 1740 to be retrieved to the surface.

Pressure-Balanced Mud Tank FIG. 2C shows the pressure-balanced mud tank 42, which was previously illustrated in FIG. 1, in greater detail. As shown, the pressure-balanced mud tank 42 includes a generally cylindrical body 230 with a bore 231 running through it. The bore 231 is arranged to receive a drill string, e.g., drill string 60, a bottom hole assembly, and other drilling tools. An annular chamber 235 which houses an annular piston 236 is defined inside the body 230. The annular piston engages and seals against the inner walls 238 and 240 of the body 230 to define a seawater chamber 242 and a mud chamber 244 in the mud tank 42. The seawater chamber 242 is connected to open seawater through the port 246. This allows ambient seawater pressure to be maintained in the seawater chamber 242 at all times. Alternatively, a pump (not shown) may be provided at the port 246 to allow the pressure in the seawater chamber 242 to be maintained at, above, or below that of ambient seawater pressure. The mud chamber 244 is connected through a

The piston 236 reciprocates axially inside the annular chamber 235 when a pressure differential exists between the seawater chamber 242 and the mud chamber 244. A flow meter (not shown) aπanged at the port 246 measures the rate at which seawater enters or leaves the seawater chamber 242 as the piston 236 reciprocates inside the chamber 235. Flow readings from the flow meter provide the necessary information to determine mud level changes in the mud tank 42. A position locator (not shown) may also be provided to track the position of the piston 236 inside the annular chamber 235. The position of the piston 236 may then be used to calculate the mud volume in the mud tank 42.

A wiper 232 is mounted on the body 230. The wiper 232 includes a wiper receptacle 233 which houses a wiper element 234 (shown in FIG. 5). As shown in FIG. 5, the wiper element 234 includes a cartridge 256 which is made of a stack of multiple elastomer disks 258. The elastomer disks 258 are arranged to receive and provide a low- pressure pack-off around a drill string, e.g., drill string 60. The elastomer disks 258 also wipe mud off the drill string as the drill string is pulled through the wiper element 234. The arrangement of the elastomer disks 258 gives a step-type seal which allows each disk to contain only a fraction of the overall pressure differential across the wiper element 234. The wiper element 234 will be carried into and out of the wiper receptacle 233 on a handling tool (not shown) that is mounted on the drill string 60.

Referring back to FIG. 2C, a riser connector 260 is mounted on the wiper receptacle 233. The riser connector 260 mates with a riser connector 262 at the lower end of the marine riser 52. A riser connector 115 is also provided at the lower end of the body 230. The riser connector 115 is arranged to mate with the riser connector 112 (shown in FIG. 2B) in the mud lift module 40. Flow ports in the riser connector 115 are connected to the mud return lines 56 and 58 through the pipes 122 and 124 and flow ports in the riser connectors 260 and 262. When the riser connector 115 mates with the riser connector 112, the pipes 122 and 124 are in communication with the pipes 118 and 120.

Referring now to FIGS. 2A-2C, when the mud lift module 40, the pressure- balanced mud tank 42, and the riser 52 are mounted on the well control assembly 38, the flexible joint 94 permits angular movement of these assemblies as the drilling vessel 12 (shown in FIG. 1) moves laterally. The angular movement or pivoting of the mud lift module 40 can be prevented by removing the flexible joint 94 from the LMRP 44 and locating it between the mud lift module 40 and the pressure-balanced mud tank 42 or between the pressure-balanced mud tank 42 and the riser 52. When the flexible joint 94 is removed from the LMRP 44, the mud lift module 40 may then be mounted on the LMRP 44 by connecting the flow tube 104 to the upper end of the annular preventer 92. The height of the wellhead stack 37 (illustrated in FIG. 1) may be reduced by replacing the pressure-balanced mud tank 42 with smaller pressure-balanced mud tanks which may be incorporated with the mud lift module 40. In this embodiment, the connector 262 at the lower end of the riser 52 would then mate with the connector 112 on the rotating subsea diverter 108. Instead of directly connecting the connector 262 to the connector 112, a flexible joint, similar to the flexible joint 94, may be mounted between the connectors 112 and 262. As shown in FIG. 6, a smaller pressure-balanced mud tank 234 includes a seawater chamber 265 which is separated from a mud chamber 266 by a floating, inflatable elastomer sphere 267. Of course, any other separating medium, such as a floating piston, may be used to isolate the seawater chamber 265 from the mud chamber 266.

Seawater may enter or leave the seawater chamber 265 through a port 268. One or more pumps (not shown) may be connected to port 268 to maintain the pressure in the chamber 265 at, above, or below that of ambient seawater pressure. A flow meter (not shown) may be connected to port 268 to measure the rate at which seawater enters or leaves the seawater chamber 265. Mud may enter or be discharged from the mud chamber 266 through a port 269. The port 269 could be connected to the piping that links the well annulus to the suction ends of the subsea pumps 102 (shown in FIG. 2B) or to the flow outlet 125 in the flow tube 104 (shown in FIG. 2B). A position locator (not

The height of the wellhead stack 37 (illustrated in FIG. 1) may also be reduced by eliminating the pressure-balanced mud tank 42 and employing the riser 52 to perform the function of the pressure-balanced mud tank. As shown in FIG. 7, when the pressure- balanced mud tank 42 is eliminated, a subsea diverter, e.g., the rotating subsea diverter 1710 which was previously illustrated in FIG. 4C, may provide the interface between the mud lift module 40 and the riser 52. In this embodiment, the connector 1810 at the upper end of the rotating subsea diverter 1710 mates with the connector 262, and the mounting flange 1812 mates with the upper end of the flow tube 104. The outlet 1816 in the connector 1810 is connected to a port 1820 in the flow tube 104 by piping 1822 so that mud from the well annulus 66 may flow into the riser 52. Because the mud in the well annulus 66 is heavier than the seawater in the riser 52, the mud 1821 from the well annulus 66 will remain at the bottom of the riser 52 with the seawater 1823 floating on top. This allows the bottom of the riser 52 to function as a chamber for holding mud from the well annulus 66. Mud may be discharged from the riser 52 to the well annulus 66 as necessary. A bypass valve 1824 in the piping 1822 may be operated to control fluid communication between the well annulus 66 and the riser 52.

In another embodiment, as shown in FIG. 7B, a floating barrier 1825 which has a bore for receiving a drill string, e.g., drill string 60, may be disposed in the riser 52 to separate the seawater in the riser from the drilling mud. The floating barrier 1825 may have a specific gravity greater than the specific gravity of seawater but less than the specific gravity of the drilling mud so that it floats on the drilling mud and, thereby, separates the drilling mud 1821 from the seawater 1823. In this way, the mixing action created by rotation of the drill string in the riser can be minimized. Means, e.g., spring- loaded ribs, can be provided between the floating barrier 1825 and the riser 52 to reduce the rotation of the floating barrier within the riser. When the floating barrier 1825 is disposed in the riser 52 as shown, the diverter 1710 (shown in FIG. 7 A) may be eliminated from the mud lift module. However, it may also be desirable to use the

Referring now to FIGS. 1-5, preparation for drilling begins with positioning the drilling vessel 12 at a drill site and may include installing beacons or other reference devices on the seafloor 17. It may be necessary to provide remotely operated vehicles, underwater cameras or other devices to guide drilling equipment to the seafloor 17. The use of guidelines to guide the drilling equipment to the seafloor may not be practical if the water is too deep. After positioning of the drilling vessel 12 is completed, drilling operations usually begin with lowering the guide structure 36, conductor housing 33, and conductor pipe 32 on a running tool attached above a bottom hole assembly. The bottom hole assembly, which includes a drill bit and other selected components to drill a planned trajectory, is attached to a drill string that is supported by the drilling rig 20. The bottom hole assembly is lowered to the seafloor and the conductor pipe 32 is jetted into place in the seafloor. After jetting the conductor pipe 32 in place, the bottom hole assembly is unlocked to drill a hole for the surface pipe 36. Drilling of the hole starts by rotating the drill bit using a rotary table or a top drive. A mud motor located above the drill bit may alternatively be used to rotate the drill bit. While the drill bit is rotated, fluid is pumped down the bore of the drill string. The fluid in the drill string jets out of the nozzles of the drill bit, flushing drill cuttings away from the drill bit. In this initial drilling stage, the fluid pumped down the bore of the drill string may be seawater. After the hole for the surface pipe 36 is drilled, the drill string and the bottom hole assembly are retrieved. Then, the surface pipe 36 is run into the hole and cemented in place. The surface pipe 36 has the subsea wellhead 35 secured to its upper end. The subsea wellhead 35 is locked in place inside the conductor housing 33.

The mud lift drilling operations begin by lowering the wellhead stack 37 to the seafloor through the moon pool 22. This is accomplished by latching the lower end of the marine riser 52 to the upper end of the mud tank 42 at the top of the wellhead stack 37. Then, the marine riser 52 is run towards the seafloor 17 until the subsea BOP stack

46 at the bottom of the wellhead stack 37 lands on and latches to the wellhead 35. The seawater chamber 242 of the mud tank 42 fills with seawater as the wellhead stack 37 is lowered. The mud return lines 56 and 58 are connected to the flow ports in the moon pool 22 after the wellhead stack 37 is secured in place on the wellhead 35. The drill string 60 with the spindle 178 is lowered through the riser 52 into the housing body 162 of the stripper 108. When the spindle 178 lands on the retractable landing shoulder 174 inside the housing body 162, the drill string is rotated to allow the locks in the housing body to latch into the recesses in the spindle 178. Then the drill string is lowered to the bottom of the well through the diverter 106, the flow tube 104, and the well control assembly 38. When the drill bit 64 touches the bottom of the well 30, the surface pump is started and mud is pumped down the bore of the drill string 60 from the drilling vessel 12. The drill string 60 is rotated from the surface by a rotary table or top drive. A mud motor located above the drill bit may alternatively be used to rotate the drill bit. As the drill string 60 or the drill bit 64 is rotated, the drill bit 64 cuts the formation.

The mud pumped into the bore of the drill string 60 is forced through the nozzles of the drill bit 64 into the bottom of the well. The mud jetting from the bit 64 rises back up through the well annulus 66 to the stripper 108, where it gets diverted to the suction ends of the subsea pumps 102 and to the port 248 of the mud chamber 244 of the mud tank 42. The pumps 102 discharge the mud to the mud return lines 56 and 58. The mud return lines 56 and 58 carry the mud to the mud return system on the drilling vessel 12. The pressure-balanced mud tank 42 is open to receive mud from the well annulus 66 when the pressure of mud at the inlet of the mud chamber 244 is higher than the seawater pressure inside the seawater chamber 242. The riser annulus is filled with seawater so that the pressure of the fluid column in the riser matches that of seawater at any given depth. Of course, any other lightweight fluid may also be used to fill the riser annulus.

Subsea Mud Pump FIG. 8 shows the components of the subsea mud pump 102 which was previously illustrated in FIG. 2B. As shown, the subsea mud pump 102 includes a multi-element pump 350, a hydraulic drive 352, and an electric motor 354. The electric motor 354 supplies power to the hydraulic drive 352 which delivers pressurized hydraulic fluid to the multi-element pump 350. The multi-element pump 350 includes diaphragm pumping elements 355. However, other types of pumping elements, as will be subsequently described, may be used in place of the diaphragm pumping elements 355.

FIG. 9A shows a vertical cross section of the diaphragm pumping element 355 which was previously illustrated in FIG. 8. As shown, the diaphragm pumping element 355 includes a spherical pressure vessel 356 with end caps 358 and 360. An elastomeric diaphragm 362 is mounted in the lower portion of the pressure vessel 356. The elastomeric diaphragm 362 isolates a hydraulic power chamber 370 from a mud chamber 372 and displaces fluid inside the vessel 356 in response to pressure differential between the hydraulic power chamber 370 and the mud chamber 372. The elastomeric diaphragm 362 also protects the vessel 356 from the abrasive and corrosive mud that maybe received in the mud chamber 372. The end cap 358 includes a port 374 through which hydraulic fluid may be fed into or discharged from the hydraulic power chamber 370. The end cap 360 includes a port 376 through which fluid may be fed into or discharged from the mud chamber 372. The end cap 360 is preferably constructed from a corrosion-resistant material to protect the port 376 from the abrasive mud entering and leaving mud chamber 372. The end cap 360 is connected to a valve manifold 378 which includes suction and discharge valves for controlling mud flow into and out of the mud chamber 372. The valve manifold 378 has an inlet port 380 and an outlet port 382. The ports 380 and 382 may be selectively connected to the port 376 in the end cap 360. As shown in FIG. 8, the inlet ports 380 are linked to a conduit 384 which may be connected to the flow outlet 125 in the flow tube

Piston pumping element FIG. 9B shows a piston pumping element 390 that may be used in place of the diaphragm pumping element 355 which was previously illustrated in FIG. 8. As shown, the piston pumping element 390 includes a cylindrical pressure vessel 392 with an upper end 394 and a lower end 396. A piston 398 is disposed inside the vessel 392. Seals 400 seal between the piston 398 and the pressure vessel 392. The piston 398 defines a hydraulic power chamber 402 and a mud chamber 404 inside the pressure vessel 392 and moves axially within the vessel 392 in response to pressure differential between the chambers 402 and 404. The piston 398 and pressure vessel 392 are preferably constructed from a corrosion resistant material. Hydraulic fluid may be fed into or discharged from the hydraulic power chamber 402 through a port 406 at the end 394 of the vessel 392. Mud may be fed into or discharged from the mud chamber 404 through a port 408 at the end 396 of the vessel 392. A valve manifold 410 is connected to the end 396 of the vessel 392. The valve manifold 410 includes suction and discharge valves for controlling mud flow into and out of the mud chamber 404. The valve manifold 410 has an inlet port 412 and an outlet port 414 which are in selective communication with the port 408.

Diaphragm Pumping Element with Diaphragm Position Locator FIG. 9C shows the diaphragm pumping element 355, which was previously illustrated in FIG. 9 A, with a diaphragm position locator, e.g., a magnetostrictive linear displacement transducer (LDT) 2011. The magnetostrictive LDT 2011 includes a magnetostrictive waveguide tube 2012 which is located within a housing 2013 on the upper end of the diaphragm pumping element 355. A ring-like magnet assembly 2014 is located about and spaced from the magnetostrictive waveguide tube 2012. The magnet assembly 2014 is mounted on one end of a magnet carrier 2015. The other end of the

The hydraulic power chamber 370 is in communication with the interior of the housing 2013. A port 2017 in the housing allows hydraulic fluid to be supplied to and withdrawn from the hydraulic power chamber 370. In operation, as hydraulic fluid is alternately supplied to and withdrawn from the hydraulic power chamber 370, the center of the elastomeric diaphragm 360 moves vertically within the pressure vessel 356. As the center of the elastomeric diaphragm 360 moves, the magnetic assembly 2014 also moves the same distance along the magnetostrictive waveguide tube 2012. The magnetostrictive waveguide tube 2012 has an area within the magnetic assembly 2014 that is magnetized as the magnet assembly is translated along the magnetostrictive waveguide tube. The conducting wire in the magnetostrictive waveguide tube 2012 periodically receives an interrogation current pulse from the transducer 2016. This interrogation current pulse produces a toroidal magnetic field around the conducting wire and in the magnetostrictive waveguide tube 2012. When the toroidal magnetic field encounters the magnetized area of the magnetostrictive waveguide tube 2012, a helical sonic return signal is produced in the waveguide tube 2012. The transducer 2016 senses the helical return signal and produces an electrical signal to a meter (not shown) or other indicator as an indication of the position of the magnet assembly 2014 and, thus, the position of the elastomeric diaphragm 362.

of the elastomeric diaphragm 362 within the pressure vessel 356 to be measured. This absolute position measurements can be reliably related to the volumes within the hydraulic power chamber 370 and the mud chamber 372. This volume information can be used to efficiently control the pump hydraulic drive (not shown) and the activated pump suction and discharge valves (not shown). It will be understood that other means besides the magnetostrictive LDT may be employed to measure the absolute position of the elastomeric diaphragm 362 within the spherical vessel 356, including linear variable differential transformer and ultrasonic measurement. It will be further understood that the diaphragm pumping element 355 can be employed in different applications as a pulsation dampener provided that the hydraulic power chamber 370 is filled with a compressible fluid, such as nitrogen gas, rather than hydraulic fluid. In a pulsation dampener application, means to measure the absolute position of the elastomeric diaphragm 362 within the spherical pressure vessel 356 can provide important information about pulsation and surges in hydraulic systems. The magnetostrictive LDT 2011 may also be used with the piston pumping element 390 (shown in FIG. 9B) to track the position of the piston 398 as the piston moves within the pressure vessel 392

Hydraulic drive circuits for the subsea mud pump FIG. 10A shows an open-circuit diagram for the hydraulic drive 352 (shown in FIG. 8). As shown, the open-circuit hydraulic drive includes a variable-displacement, pressure-compensated pump 420 and an auxiliary pump 490. The pumps 420 and 490 are submersed in a pressure-balanced, hydraulic fluid reservoir 424. Alternately, the pumps 420 and 490 may be located external to the reservoir 424. The hydraulic fluid in the reservoir 424 may be oil or other suitable fluid power transmission media. The pump 420 is driven by an electric motor 432 which receives electricity from the drilling vessel. The electric motor 432 represents the electric motor 354 which was previously illustrated in FIG. 8. The pump 490 is coupled to the pump 420 and driven by the electric motor 432. The pump 490 may also be driven by another source, such as its own electric motor.

The pump 420 draws hydraulic fluid from the reservoir 424 and discharges pressurized fluid to the hydraulic power chambers 2020b and 2022b of the pumping elements 2020 and 2022 through the valves 426b and 428b, respectively. The positions of the valves 426b and 428b are determined by the control logic in the control module 2034. The pump 490 draws fluid from the reservoir 424 and pumps the fluid through the bearings (not shown) in pump 420. A volume compensator 425 is provided on the reservoir 424 to compensate for volume fluctuations in the reservoir that arise when the rate at which fluid is pumped out of the reservoir 424 is different from the rate at which fluid is returned to the reservoir through the valves 426a and 428a. The positions of the valves 426a and 428a are also determined by the control logic in the control module 2034. The valves 426a, 426b, 428a and 428b are two-way, solenoid-actuated, spring- return, two-position valves. However, other directional control valves can also be used to control hydraulic flow in and out of the hydraulic power chambers 2020b and 2022b.

Each of the pumping elements 2020 and 2022 have position indicators 2026, which transmit signals to the control module 2034. The indicators 2026 measure the volume of mud in the mud chambers 2020a and 2022a. The mud chambers 2020a and 2022a of the pumping elements 2020 and 2022, respectively, are connected to the conduit 456 through suction valves 1890a and to the conduit 458 through discharge valves 1890b. The valves 1890a and 1890b are check valves which permit mud to flow from the conduit 456 into the mud chambers 2020a and 2022a and from the mud chambers into the conduit 458, respectively. Although individual valves 1890a and 1890b are shown, it would be understood that these valves can be replaced with a three-way valve that would permit alternating connection of the mud chambers 2020a and 2022a to the conduits 456 or 458. In operation, the conduit 456 may be hydraulically connected to the flow outlet 125 in the flow tube 104 of the mud lift module 40 (shown in FIG. 2B), and the conduit 458 may be hydraulically connected to the mud return lines 56 and 58 (shown in FIG. 1).

In the circuit of FIG. 10A, the hydraulic power chamber 2022b is being filled with hydraulic fluid while the mud chamber 2022a is discharging mud. Also, the mud chamber 2020a is being filled with mud while the hydraulic power chamber 2020b is

discharging hydraulic fluid. The timing sequence of filing one power chamber with hydraulic fluid while discharging hydraulic fluid from the other power chamber or discharging mud from one mud chamber while filling the other mud chamber with mud is such that the total mud flow from the pumping elements 2020 and 2022 is relatively free of pulsation. The pumping elements 2020 and 2022 are depicted as diaphragm pumping elements, e.g., diaphragm pumping elements 355, but the pumping elements 2020 and 2022 may be of other pumping element type, e.g., piston pumping element 390. One or more pumping elements may also be added to the pumping elements 2020 and 2022 to change the output of the subsea mud pump. FIG. 10B depicts the time and position relationship between the mud chambers

2020a and 2022a as the pumping action takes place. At the start of the chart, the mud volume in mud chamber 2022a is decreasing while the mud volume in mud chamber 2020a is increasing. The flow rate into the mud chamber 2020a is greater than the flow rate out of the mud chamber 2022a. Mud flows into the mud chamber 2020a as a result of the positive pressure differential which is maintained between the mud in the conduit 456 and the hydraulic fluid contained in the reservoir 424.

This positive pressure differential required to fill the mud chamber 2020a may be created in several ways. When the pumping system is used subsea, the pump suction is connected to the well annulus 66 (shown in FIG. 1) through the port 125 in the flow tube 104 (shown in FIG. 2B). The pressure of the mud in the well annulus 66 (shown in FIG. 1) varies depending on the rate at which mud is pumped from the surface mud pumps (not shown) on the drilling rig 20 through the drill string 60 into the well annulus 66 and the rate at which the subsea pumps remove the mud from the well annulus. A pressure sensor 2028 measures the pressure differential between the mud in the well annulus and the seawater surrounding the reservoir 424. The output of the pressure sensor 2028 is transmitted to the control module 2034 which, in turn, sends a rate control signal to the variable-displacement pump 420 (shown in FIG. 10A). The well annulus pressure can, therefore, be increased or decreased by the control module 2034 such that it is maintained higher than the ambient seawater pressure. This control mode insures that the rate at

The control logic contained in the control module 2034 (shown in FIG. 10A) provides for the pumping cycle depicted in FIG. 10B. As discussed above, the mud fill cycle of the mud chamber 2020a is finished when the volume in the mud chamber 2020a reaches point J. At this point, the control module 2034 shifts the position of valve 426a to stop the flow of hydraulic fluid out of the hydraulic power chamber 2020b and, thus, flow of mud into the mud chamber 2020a. The condition of the hydraulic power chamber 2020b is maintained until the mud being discharged from mud chamber 2022a reaches point A. At that moment in time, the valve 426b is shifted to a flow condition, allowing hydraulic fluid to flow into the hydraulic power chamber 2020b to displace mud from the chamber 2020a at the same time that mud is being displaced from the mud chamber 2022a. The hydraulic flow from the variable-displacement pump 420 remains constant, but is split between the two hydraulic power chambers 2020b and 2022b. The total mud flowing into the conduit 458 remains constant.

When the mud volume in the mud chamber 2022a reaches point C, the hydraulic fill valve 428b is shifted by the control module 2034 to a blocked position, stopping the mud flow out of the mud chamber 2022a. After a time delay represented by segment CE, the control module 2034 shifts the hydraulic discharge valve 428a to the flow position, allowing hydraulic fluid to be displaced from the hydraulic power chamber 2020b to the reservoir 424 as mud fills the mud chamber 2022a. The rate at which mud fills the mud chamber 2022a exceeds the rate at which hydraulic fluid is supplied to the hydraulic fluid chamber 2020b by the pump 420 and, thus, the rate at which mud is discharged out of the mud chamber 2020a. The fill cycle for mud chamber 2022a, represented by the line segment EF, stops when the mud volume in 2022a reaches point F. At this point, the control module 2034 shifts the valve 428a to a blocked position, stopping the flow of hydraulic fluid from the hydraulic fluid chamber 2022b to the reservoir 424.

The "full" condition of mud chamber 2022a is maintained until the position indicator 2026 attached to the pumping element 2020 indicates that the mud volume in

2020a has reached the "empty" point G. The control module 2034 then actuates the valve 428b to allow hydraulic fluid to flow into the hydraulic power chamber 2022b to displace the mud in the mud chamber 2022a into the conduit 458. Again, the flow from the pump 420 is split between the hydraulic fluid chambers 2022b and 2020b until the volume in mud chamber 2020a reaches I. This flow split is indicated by the two segments HM and GI on FIG. 10B. When the volume in the mud chamber 2020a reaches I, the control module 2034 signals the valve 426a to shift into a blocked condition, stopping mud flow out of mud chamber 2020a. The full flow of the pump 420 is then used to discharge the mud from the mud chamber 2022a at the rate indicated by the line segment MN. The flow analysis shows that the mud discharge from the mud chambers 2020a and 2022a is uninterrupted. The starting flow rate of mud being discharged from 2022a is defined by the segment LA. The next segment is the combination of the segments BD (from mud chamber 2020a) and AC (from mud chamber 2022a), which equals the flow rate of segment LA. The following segment of mud being displaced from mud chamber 2020a is DG which is the same rate as LA. The flow is then split between mud chambers 2022a and 2020a as shown by segments HM and GI, respectively. The sum of the flow rates of segments HM and GI is equal to the flow rate of segment LA. The mud flow from the mud chamber 2022a continues in segment MN, which, again, is the same as the initial segment LA. The sequence then repeats. The pumping flow rate that is indicated by the line segments MN and DG would be the maximum flow rate for the subsea mud pump, based on the fill rate established by the mud pressure in the conduit 456. If the mud flow into the well annulus starts to decrease, the pressure in the well annulus would also decrease. The control module 2034 would sense the change in the pressure sensor 2028, and reduce the flow rate from pump 420, which in turn would reduce the volume of hydraulic fluid discharged by the pump 420 to the hydraulic power chambers 2020b and 2022b. This reduced rate of mud flow from the well annulus would reestablish the required mud pressure in the conduit 456.

control signals to the control valves 426a, 426b, 428a, and 428b. This control device would have a resident computer (not shown) which is connected to the I/O devices, or a communications linkage with a surface computer (not shown) to the I/O devices. The control for the scaling of sensor inputs and the logic to create the control signals anticipated in FIG. 10A is part of the software that is provided for the computer. This control module 2034 would be used whether the mud pump was operating subsea or on the surface.

FIG. IOC illustrates the performance of the pump circuit shown in FIG. 10A using the control method described in FIG. 10B. As shown, the mud discharge rate is constant with no observable pulsation. However, the suction flow rate is formed by a series of flow pulses. This requires that some type of suction pulsation dampener be provided. The subsea pumping system provides this feature, i.e., reduction of pressure variations in the well annulus, in the pressure-balanced mud tank 42 shown in FIG. 2C or as shown in FIG. 7A when bypass valve 1824 is open to allow mud to move between the riser 52 and the well annulus. Alternatively, one or more additional pumping elements which operate out of phase with the pumping elements 2022a and 2020a may be used to create mud suction that is free of pulsation while maintaining the mud discharge that is free of pulsation.

The pumping rate required to lift mud from the seafloor to the surface when drilling at a water depth of 10,000 feet is estimated to be as high as 1,600 gallons per minute. For example, if the duration of the discharge stroke of each pumping element is six seconds, each pumping element would complete five discharge strokes in one minute. If the pumping elements