drilling mud pump rental free sample

Centerline Manu-facturing introduces the CLM 7.5 x 10D hydraulic mud pump, a pump which utilizes common fluid end parts. Its advantages are said to be its flow capacity, rated pressure, size and weight. It is designed to pump 100 percent more rated flow than a standard 5x6 and up to 3.25 times the rated pressure. However, it only has a third of the weight and 77 percent of the length.

The global Industrial Pump Rental market was valued at USD 2881.1 million in 2022 and is anticipated to reach USD 4117.1 million by 2029, witnessing a CAGR of 6.1% during the forecast period 2023-2029.

During the course of the forecast period, it is predicted that the market would grow more rapidly due to the expanding benefits of pump rental services. The introduction of digitization and the increase in internet usage have made it possible for vendors to offer cutting-edge service delivery alternatives, which is further likely to fuel the Industrial Pump Rental market growth in the years to come.

Government-sponsored projects are growing, as are rental pump investments in emerging nations around the world and competition in the industrial pump market. Industrial pumps can be rented much more affordably than purchased. As a result, it is anticipated that demand for rental industrial pumps would increase over the coming years. Additionally, renting a pump gives contractors and operators access to the most recent smart pumping technology for cost-effective process management. Application-specific pumps are provided by large pump rental firms for upstream and downstream activities. This factor is expected to drive the growth of the industrial pump rental market.

Every stage of oil and gas production requires the use of industrial pumps. In essence, they aid in the movement of process fluids from one location to another. For instance, a pump can be used to move crude oil from a storage tank to a pipeline, and mud pumps can move drilling mud around a drill bit"s annulus before returning it to a storage tank for purification. Process fluids in oil and gas operations can be simple or complex. You"ll need the appropriate pump for your needs, depending on the type of substance you wish to transfer and the flow rate you need. This in turn will drive the growth of the industrial pump rental market.

Wastewater pumps are employed in a variety of situations where sewage and seepage water are present. These pumps work by transferring liquid from the pump"s expanding suction end cavity to its contracting discharge end cavity. They do this with the aid of rollers and impellers. Another factor promoting the growth of the industrial pump rental market throughout the predicted period is innovation in service offerings. The types of pumps offered and the service delivery plays a significant influence in the market because there are many sellers in the marketplace. As a result, suppliers are concentrating on innovative service delivery methods to guarantee that their potential clients can rent pumps on time and in accordance with their application requirements.

Also, the introduction of digitalization and the increasing use of the Internet have contributed to the removal of obstacles related to the availability of pumps and daily costs. Mobile apps are being used by vendors to provide real-time information regarding pump services, which speeds up the delivery of pumps based on consumer demand. Industrial pump rental companies throughout the world are attempting to use digitization to reach more customers. Hence, market players will be able to contact more customers by adopting technologically enhanced services, which is anticipated to accelerate the expansion of the global industrial pump rental market during the course of the projected period.

The highest market share is in Asia. The primary markets for the APAC industrial pump rental industry are China, India, Japan, and Australia. The market in this region will grow more quickly than the markets in other regions. The considerable increase in offshore and onshore oil and gas exploration and production operations as well as the expansion of industrialization have resulted in a high demand for water, which will support the expansion of the industrial pump rental market in APAC over the forecast period.

When you"re seeking the field flexibility to complete your drilling faster, easier and safer, count on Geoprobe® drill rigs engineered for versatility and manufactured for reliability. Industry leaders depend on our ongoing commitment to innovation and industry-leading customer support to advance their business ahead of the competition. Digital readouts providing instant feedback, enhanced safety features, easy operation, and availability of training options mean veteran drillers find their jobs simplified while new drillers build confidence, making them productive as they"re quickly coming up the learning curve.

Increase depth advancement and recovery speeds while minimizing waste with the 8150LS sonic drilling rig engineered for driller safety, sampling speed, and operation efficiency.

From crowded street corners to far removed places, tackle various environmental, geotechnical and exploration applications with a single machine combining rotary drilling and direct push, saving time and money required to mobilize multiple drill rigs.

Efficiently complete geotech investigations sliding between drilling functions all without the need for a class A/B CDL, safely bringing new drillers up the learning curve on the drilling truck.

Maximize the value of your investment by choosing a CPT drilling platform best suited to your specific business model. Whether you’re seeking a dedicated CPT drilling rig or a versatile drilling rig to run a variety of applications, you’ll find the combination of features to push your business ahead.

Generating a name for itself and redefining the way sites are investigated in the environmental industry, Geoprobe® continues to advance direct push drilling through continued innovation of its line of high-quality, hydraulically-powered direct push drilling rigs

With the necessary tophead rotation speed, head feed speed, and plenty of mud pump options to get the job done, complete your water well drilling, geothermal drilling, and cathodic protection drilling jobs with a single, compact water well drill.

Tophead offering both torque and speed to the impressive power to weight ratio make the DM450 well suited for water well, geothermal, and/or cathodic protection drilling while minimizing maintenance.

Outfit as down the hole drill or mud drill with the power of 28.5-foot stroke, 40,000 lb pullback, and 8,000 ft-lb torque to handle deeper wells along with weight of steel casing.

Mud recycling systems were once considered optional equipment. Environmental regulations continue to become more stringent and we must all responsibly make a contribution to protect our fragile ecosystem.

Using mud recyclers are a valuable asset to drilling contractors, as well-conditioned drilling fluid can save resources, time and money by reducing the amount of water and chemicals needed by reusing your bentonite and water. This helps maintain borehole stability with consistent mud properties through the entire circulation of the fluid and you haul off mainly the drilled solids, not the entire mud returns, including the liquid.

Drillers considering a mud recycler often ask: “Where do I start?” There are factors to consider before purchasing (or renting) a mud recycler, and, just like sizing the drill rig, sizing the recycler is equally important to your success. The following are some of the questions to ask yourself before making your purchase:

These factors are important to know so that you use a recycler that is sized to clean the mud and protect the components on the rig, pump and cleaner.

Drilling rigs are generally classified as “maxi,” “midsize” and “compact. While you can put a maxi recycler with a compact rig, it would not be advisable to do the reverse. Lesson: size accordingly.

As a general rule, size the recycler cleaning capacity to one and a half to two times the pumping volume (max gpm) of the triplex pump. HDD drillers normally run thicker fluids due to the low vertical height and long horizontal lengths of their bores; thicker fluid makes it more difficult for the shakers and cones to process (separate) the solids from the liquids. This is largely due to the natural coating ability of bentonite — It wants to encapsulate the solids and “hold on” to them. By upsizing the recycler, the solid particles have a second or third opportunity to process through the mud recycler for removal before going back to the rig.

Some mud recyclers provide an “onboard” mud pump that was sized specifically to the recycler. This enables the driller to use all available drill rig horsepower toward the rotation and push-pull of the drill pipe, thereby not “robbing” it for an onboard triplex pump.

Most recyclers today use orbital, elliptical or linear motion shakers, and each has a place in different drilling scenarios. With that being said, linear motion shakers generate high G-Forces and are especially effective in shallow formation sections where high-volume, heavy solids are encountered, and have the ability to remove the solids quickly.

When choosing a linear shaker for your mud system, look for a long runway (area of length from the front of the shaker to the end where the cuttings dump off). The longer length shaker bed allows extra time for solids to separate from the liquid, and result in drier solids leaving the mud system for disposal. You can also increase the angle of the shaker bed by five degrees to further increase the travel time of the solids.

Proper shaker screen selection enhances the results of the mud recycler, and, combined with the G-Force of the shaker, works in tandem to maximize solids dryness. In the past, shaker screens were sized by mesh size.

Identification of particle sizes from core samples taken on each drilling location provides drillers valuable information and aids in selecting screens. Drilling contractors should carry a couple of testing tools to measure the effectiveness of a of the mud recycler while drilling. These tools are: a Marsh funnel and cup, sand content kit and mud weight scales. Taking mud samples from the return pit or possum belly before the mud is processed, the underflow and overflow of the cones and the clean mud tank help monitor the effectiveness of each component of the recycler, and the driller can make component adjustments to achieve maximum efficiency.

In addition to the shale shakers, another way to size the processing capability of the mud recycler is to look at the hydrocyclone. Depending on the size of the mud recycling system, cone size will be 4, 5, 10 or 12 in. Each size cone has a micron “cut point,” and represents the size of the smallest particle the cone can “pull.” Four- and 5-in. cones have a 20-micron “cut point,” and 10- and 12-in. cones have a 74-micron “cut point.” Smaller mud systems normally have two section tanks, with a ”dirty” tank under the scalping shaker and a “clean” tank under the mud cleaner (shaker with desilting cones), while larger systems can have three section tanks with scalping, desanding and desilting.

Borehole returns require transport into the recycler via a “trash” pump properly sized for the job. Different pumps are available, but the three most common are: 1) submersible, 2) semi-submersible, and 3) aboveground centrifugal with a foot valve. Totally submersible pumps are generally the smallest in size, have a flooded suction to help in priming, and though the most convenient option, are usually the most expensive. Semi-submersible trash pumps still have a flooded suction, but the drive motor is not submerged into the fluid. Semi-submersible pumps work well, but are heavier, and longer than the submersible pumps.  Another option is an above ground centrifugal pump with a foot valve, and once primed, is dependable and normally used on larger recyclers for their increased volume capacities.

If your drilling crew has never operated a mud recycler, be sure that you are provided with training and try renting a unit to make sure it is the right “fit” prior to purchase. Be familiar with the maintenance requirements of your mud system; usually the owner’s manual is sufficient, but inquire if the manufacturer offers training videos, onsite or plant training sessions and — the most important — technical support.

In an age where protection of our planet is a major concern, so should your choice of mud systems. Choose a recycler that is respectful to the environment and leaves your jobsite as clean as possible.  Do your research, talk to other drillers, decide what you need and you will be able to make the best decision for you and your company.

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.

Mud pumps are the heart of your drilling operation. Bridges Equipment is the leading authority on the unitization of triplex mud pumps. As an OEM distributor for Caterpillar Rig Power, Detroit Diesel, and Joliet motors, we provide our customers with a wide range of options to meet their pump needs.

A malfunctioning mud pump can throw an entire drilling operation off schedule. Our fleet of mud pump packages are available to rent while the broken unit is being repaired, so your drilling operation never misses a beat.

Our Gardner Denver, RSF, and Continental Emsco triplex pump packages range from 500-1600 HP and can be fully customized to suit your project. Contracts are offered for as few as 10 days, so whether you need to replace a broken unit or need a long-term rental to act as a backup pump, we’ve got you covered.

The invention relates generally to offshore drilling systems which are employed for drilling subsea wells. More particularly, the invention relates to an offshore drilling system which maintains a dual pressure gradient, one pressure gradient above the well and another pressure gradient in the well, during a drilling operation.

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

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 water depths 6,000 feet and greater, the 21 -in riser is flexible enough that angular and lateral deflections over the entire length of the riser will occur due to the water currents acting on the riser. Therefore, in order to keep the riser deflections within acceptable limits during drilling operations, tight station keeping is required. Frequently, the water currents are severe enough that station keeping is not sufficient to permit drilling operations to continue. Occasionally, water currents are so severe that the riser must be disconnected from the blowout preventer stack to avoid damage or permanent deformation. To prevent frequent disconnection of the riser, an expensive fairing may have to be deployed or additional tension applied to the riser. From an operational standpoint, a fairing is not desirable because it is heavy and difficult to install and disconnect. On the other hand, additional riser tensioners may over-stress the riser and impose even greater loads on the drilling vessel.

A third limiting factor is the difficulty of retrieving the riser in the event of a storm. Based on the large forces that the riser and the drilling vessel are already subjected to, it is reasonable to conclude that neither the riser nor the drilling vessel would be capable of sustaining the loads imposed by a hurricane. In such a condition, if the drilling vessel is a dynamically positioned type, the drilling vessel will attempt to evade the storm. Storm evasion would be impossible with 10,000 feet of riser hanging from the drilling vessel. Thus, in such a situation, the riser would have to be pulled up entirely.

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.

After the storm, the drilling vessel would return to the drill site and deploy the riser to reconnect and resume drilling. In locations like Gulf of Mexico where the average annual number of hurricanes is 2.8 and the maximum warning time of an approaching hurricane is 72 hours, it would be necessary to disconnect and retrieve the riser every time there is a threat of hurricane in the vicinity of the drilling location. This, of course, would translate to huge financial losses to the well operator.

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.

A fifth limiting factor relates to marginal well control and the need for numerous casing points. In any drilling operation, it is important to control the influx of formation fluid from subsurface formations into the well to prevent blowout. Well control procedures typically involve maintaining the hydrostatic pressure of the drilling fluid column above the "open hole" formation pore pressure but, at the same time, not above the formation fracture pressure. In drilling the initial section of the well, the hydrostatic pressure is maintained using seawater as the drilling fluid with the drilling returns discharged onto the seafloor. This is possible because the pore pressures of the formations near the seafloor are close to the seawater hydrostatic pressure at the seafloor. While drilling the initial section of the well with seawater, formations having pore pressures greater than the seawater hydrostatic pressure may be encountered. In such situations, formation fluids may flow freely into the well. This uncontrolled flow of formation fluids into the well may be so great as to cause washouts of the drilled hole and, possibly, destroy the drilling location. To prevent formation fluid flow into the well, the initial section of the well may be drilled with weighted drilling fluids. However, the current practice of discharging fluid to the seafloor while drilling the initial section of the well does not make this option very attractive. This is because the large volumes of drilling fluids dumped onto the seafloor are not recovered. Large volumes of unrecovered weighted drilling fluids are expensive and, possibly, environmentally undesirable.

After the initial section of the well is drilled to an acceptable depth, using either seawater or weighted drilling fluid, a conductor casing string with a wellhead is run and cemented in place. This is followed by running a blowout preventer stack and marine riser to the seafloor to permit drilling fluid circulation from the drilling vessel to the well and back to the drilling vessel in the usual manner.

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 effect of overbalance on drilling rates varies widely with the type of drill bit, formation type, magnitude of overbalance, and many other factors. For example, in a typical drill bit and formation combination with a drilling rate of 30 feet per hour and an overbalance of 500 psi, it is common for the drilling rate to double to 60 feet per hour if

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).

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.

The piston 140 moves downwardly to open the passageway 136 when hydraulic fluid is supplied to the opening cavity 139. As illustrated in the left half of the drawing, when the piston 140 sits on the body 128, the sealing element 150 does not extrude into the passageway 136 and the diverter 106 is fully open. When the diverter 106 is fully open, the passageway 136 is large enough to receive a bottom hole assembly and other drilling tools. When hydraulic fluid is fed into the cavity 138, the piston 140 moves upwardly to close the diverter 106. As illustrated in the right half of the drawing, when the piston 140 moves upwardly, the sealing element 150 is extruded into the passageway 136. If there is a drill string in the passageway 136, the extruded sealing element 150 would contact the drill string and seal the annulus between the passageway 136 and the drill string. FIG. 3B shows a vertical cross section of another non-rotating subsea diverter, i.e., subsea diverter 270, that may be used in place of the non-rotating subsea diverter 106. The subsea diverter 270 includes a housing body 272 with flanges 274 and 276 which are provided for connection with other components of the wellhead stack 37, e.g., the flow tube 104 and the subsea diverter 108 (shown in FIG. 2B). The housing body

In operation, the spindle 178 is carried into the housing body 162 on a handling tool that is mounted on the drill string. When the spindle 178 lands on the shoulder 174, the drill string is rotated until the locks 176 are aligned with the recesses 181 in the upper portion 180 of the spindle 178. Then the hydraulic actuators 177 are operated to push the locks 176 into the recesses 181. The stripper rubber 185 seals against the drill string while allowing the drill string to be lowered into the well. During drilling, friction between the rotating drill string and the stripper rubber 185 provides sufficient force to rotate the lower portion 182 of the spindle 178. While the lower portion 182 is rotated, the stripper rubber 185 is only subjected to the friction forces associated with the vertical motion of the drill string. This has the effect of prolonging the wear life of the stripper rubber 185. When the drill string is pulled out of the well, the hydraulic actuators 177 may be operated to release the locks 176 from the recesses 181 so that the handling tool on the drill string can engage the spindle 178 and pull the spindle 178 out of the housing body 162. FIG. 4B shows a vertical cross section of another rotating subsea diverter, i.e., rotating subsea diverter 186, that may be used in place of the rotating subsea diverter 108. The subsea diverter 186 includes a retrievable spindle 188 which is disposed in a housing body 190. The spindle 188 includes two opposed stripper rubbers 192 and 194. The stripper rubber 192 is oriented to effect a seal around a drill string when the pressure

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).

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

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 repres