mud pump packages free sample

A comprehensive range of mud pumping, mixing, and processing equipment is designed to streamline many essential but time-consuming operational and maintenance procedures, improve operator safety and productivity, and reduce costly system downtime.

Cameron provides a range of integrated pump packages, including top- or rear-mount AC- or DC-electric drives, controls, manifolds, piping, and accessories for onshore and offshore applications.

Triplex mud pumps pump drilling mud during well operations. An example of a typical triplex mud pump 10 shown in FIG. 1A has a power assembly 12, a crosshead assembly 14, and a fluid assembly 16. Electric motors (not shown) connect to a pinion shaft 30 that drives the power assembly 12. The crosshead assembly 14 converts the rotational movement of the power assembly 12 into reciprocating movement to actuate internal pistons or plungers of the fluid assembly 16. Being triplex, the pump"s fluid assembly 16 has three internal pistons to pump the mud.

As shown in FIG. 1B, the pump"s power assembly 14 has a crankshaft 20 supported at its ends by double roller bearings 22. Positioned along its intermediate extent, the crankshaft 20 has three eccentric sheaves 24-1 . . . 24-3, and three connecting rods 40 mount onto these sheaves 24 with cylindrical roller bearings 26. These connecting rods 40 connect by extension rods (not shown) and the crosshead assembly (14) to the pistons of the pump"s fluid assembly 16.

In addition to the sheaves, the crankshaft 20 also has a bull gear 28 positioned between the second and third sheaves 24-2 and 24-3. The bull gear 28 interfaces with the pinion shaft (30) and drives the crankshaft 20"s rotation. As shown particularly in FIG. 1C, the pinion shaft 30 also mounts in the power assembly 14 with roller bearings 32 supporting its ends. When electric motors couple to the pinion shaft"s ends 34 and rotate the pinion shaft 30, a pinion gear 38 interfacing with the crankshaft"s bull gear 28 drives the crankshaft (20), thereby operating the pistons of the pump"s fluid assembly 16.

When used to pump mud, the triplex mud pump 10 produces flow that varies by approximately 23%. For example, the pump 10 produces a maximum flow level of about 106% during certain crankshaft angles and produces a minimum flow level of 83% during other crankshaft angles, resulting in a total flow variation of 23% as the pump"s pistons are moved in differing exhaust strokes during the crankshaft"s rotation. Because the total flow varies, the pump 10 tends to produce undesirable pressure changes or “noise” in the pumped mud. In turn, this noise interferes with downhole telemetry and other techniques used during measurement-while-drilling (MWD) and logging-while-drilling (LWD) operations.

In contrast to mud pumps, well-service pumps (WSP) are also used during well operations. A well service pump is used to pump fluid at higher pressures than those used to pump mud. Therefore, the well service pumps are typically used to pump high pressure fluid into a well during frac operations or the like. An example of a well-service pump 50 is shown in FIG. 2. Here, the well service pump 50 is a quintuplex well service pump, although triplex well service pumps are also used. The pump 50 has a power assembly 52, a crosshead assembly 54, and a fluid assembly 56. A gear reducer 53 on one side of the pump 50 connects a drive (not shown) to the power assembly 52 to drive the pump 50.

As shown in FIG. 3, the pump"s power assembly 52 has a crankshaft 60 with five crankpins 62 and an internal main bearing sheave 64. The crankpins 62 are offset from the crankshaft 60"s axis of rotation and convert the rotation of the crankshaft 60 in to a reciprocating motion for operating pistons (not shown) in the pump"s fluid assembly 56. Double roller bearings 66 support the crankshaft 60 at both ends of the power assembly 52, and an internal double roller bearing 68 supports the crankshaft 60 at its main bearing sheave 64. One end 61 of the crankshaft 60 extends outside the power assembly 52 for coupling to the gear reducer (53; FIG. 2) and other drive components.

As shown in FIG. 4A, connecting rods 70 connect from the crankpins 62 to pistons or plungers 80 via the crosshead assembly 54. FIG. 4B shows a typical connection of a connecting rod 70 to a crankpin 62 in the well service pump 50. As shown, a bearing cap 74 fits on one side of the crankpin 62 and couples to the profiled end of the connecting rod 70. To reduce friction, the connection uses a sleeve bearing 76 between the rod 70, bearing cap 74, and crankpin 62. From the crankpin 62, the connecting rod 70 connects to a crosshead 55 using a wrist pin 72 as shown in FIG. 4A. The wrist pin 72 allows the connecting rod 70 to pivot with respect to the crosshead 55, which in turn is connected to the plunger 80.

In use, an electric motor or an internal combustion engine (such as a diesel engine) drives the pump 50 by the gear reducer 53. As the crankshaft 60 turns, the crankpins 62 reciprocate the connecting rods 70. Moved by the rods 70, the crossheads 55 reciprocate inside fixed cylinders. In turn, the plunger 80 coupled to the crosshead 55 also reciprocates between suction and power strokes in the fluid assembly 56. Withdrawal of a plunger 80 during a suction stroke pulls fluid into the assembly 56 through the input valve 82 connected to an inlet hose or pipe (not shown). Subsequently pushed during the power stroke, the plunger 80 then forces the fluid under pressure out through the output valve 84 connected to an outlet hose or pipe (not shown).

In contrast to using a crankshaft for a quintuplex well-service pump that has crankpins 62 as discussed above, another type of quintuplex well-service pump uses eccentric sheaves on a direct drive crankshaft. FIG. 4C is an isolated view of such a crankshaft 90 having eccentric sheaves 92-1 . . . 92-5 for use in a quintuplex well-service pump. External main bearings (not shown) support the crankshaft 90 at its ends 96 in the well-service pumps housing (not shown). To drive the crankshaft 90, one end 91 extends beyond the pumps housing for coupling to drive components, such as a gear box. The crankshaft 90 has five eccentric sheaves 92-1 . . . 92-5 for coupling to connecting rods (not shown) with roller bearings. The crankshaft 90 also has two internal main bearing sheaves 94-1, 94-2 for internal main bearings used to support the crankshaft 90 in the pump"s housing.

In the past, quintuplex well-service pumps used for pumping frac fluid or the like have been substituted for mud pumps during drilling operations to pump mud. Unfortunately, the well-service pump has a shorter service life compared to the conventional triplex mud pumps, making use of the well-service pump as a mud pump less desirable in most situations. In addition, a quintuplex well-service pump produces a great deal of white noise that interferes with MWD and LWD operations, further making the pump"s use to pump mud less desirable in most situations. Furthermore, the well-service pump is configured for direct drive by a motor and gear box directly coupling on one end of the crankshaft. This direct coupling limits what drives can be used with the pump. Moreover, the direct drive to the crankshaft can produce various issues with noise, balance, wear, and other associated problems that make use of the well-service pump to pump mud less desirable.

One might expect to provide a quintuplex mud pump by extending the conventional arrangement of a triplex mud pump (e.g., as shown in FIG. 1B) to include components for two additional pistons or plungers. However, the actual design for a quintuplex mud pump is not as easy as extending the conventional arrangement, especially in light of the requirements for a mud pump"s operation such as service life, noise levels, crankshaft deflection, balance, and other considerations. As a result, acceptable implementation of a quintuplex mud pump has not been achieved in the art during the long history of mud pump design.

What is needed is an efficient mud pump that has a long service life and that produces low levels of white noise during operation so as not to interfere with MWD and LWD operations while pumping mud in a well.

A quintuplex mud pump is a continuous duty, reciprocating plunger/piston pump. The mud pump has a crankshaft supported in the pump by external main bearings and uses internal gearing and a pinion shaft to drive the crankshaft. Five eccentric sheaves and two internal main bearing sheaves are provided on the crankshaft. Each of the main bearing sheaves supports the intermediate extent of crankshaft using bearings. One main bearing sheave is disposed between the second and third eccentric sheaves, while the other main bearing sheave is disposed between the third and fourth eccentric sheaves.

One or more bull gears are also provided on the crankshaft, and the pump"s pinion shaft has one or more pinion gears that interface with the one or more bull gears. If one bull gear is used, the interface between the bull and pinion gears can use herringbone or double helical gearing of opposite hand to avoid axial thrust. If two bull gears are used, the interface between the bull and pinion gears can use helical gearing with each having opposite hand to avoid axial thrust. For example, one of two bull gears can be disposed between the first and second eccentric sheaves, while the second bull gear can be disposed between fourth and fifth eccentric sheaves. These bull gears can have opposite hand. The pump"s internal gearing allows the pump to be driven conventionally and packaged in any standard mud pump packaging arrangement. Electric motors (for example, twin motors made by GE) may be used to drive the pump, although the pump"s rated input horsepower may be a factor used to determine the type of motor.

Connecting rods connect to the eccentric sheaves and use roller bearings. During rotation of the crankshaft, these connecting rods transfer the crankshaft"s rotational movement to reciprocating motion of the pistons or plungers in the pump"s fluid assembly. As such, the quintuplex mud pump uses all roller bearings to support its crankshaft and to transfer crankshaft motion to the connecting rods. In this way, the quintuplex mud pump can reduce the white noise typically produced by conventional triplex mud pumps and well service pumps that can interfere with MWD and LWD operations.

Turning to the drawings, a quintuplex mud pump 100 shown in FIGS. 5 and 6A-6B has a power assembly 110, a crosshead assembly 150, and a fluid assembly 170. Twin drives (e.g., electric motors, etc.) couple to ends of the power assembly"s pinion shaft 130 to drive the pump"s power assembly 110. As shown in FIGS. 6A-6B, internal gearing within the power assembly 110 converts the rotation of the pinion shaft 130 to rotation of a crankshaft 120. The gearing uses pinion gears 138 on the pinion shaft 130 that couple to bull gears 128 on the crankshaft 120 and transfer rotation of the pinion shaft 130 to the crankshaft 120.

For support, the crankshaft 120 has external main bearings 122 supporting its ends and two internal main bearings 127 supporting its intermediate extent in the assembly 110. As best shown in FIG. 6A, rotation of the crankshaft 120 reciprocates five independent connecting rods 140. Each of the connecting rods 140 couples to a crosshead 160 of the crosshead assembly 150. In turn, each of the crossheads 160 converts the connecting rod 40"s movement into a reciprocating movement of an intermediate pony rod 166. As it reciprocates, the pony rod 166 drives a coupled piston or plunger (not shown) in the fluid assembly 170 that pumps mud from an intake manifold 192 to an output manifold 198. Being quintuplex, the mud pump 100 has five such pistons movable in the fluid assembly 170 for pumping the mud.

The cross-section in FIG. 10A shows a crosshead 160 for the quintuplex mud pump. The end of the connecting rod 140 couples by a wrist pin 142 and bearing 144 to a crosshead body 162 that is movable in a crosshead guide 164. A pony rod 166 coupled to the crosshead body 162 extends through a stuffing box gasket 168 on a diaphragm plate 169. An end of this pony rod 166 in turn couples to additional components of the fluid assembly (170) as discussed below.

The cross-section in FIG. 10B shows portion of the fluid assembly 170 for the quintuplex mud pump. An intermediate rod 172 has a clamp 174 that couples to the pony rod (166; FIG. 10A) from the crosshead assembly 160 of FIG. 10A. The opposite end of the rod 172 couples by another clamp to a piston rod 180 having a piston head 182 on its end. Although a piston arrangement is shown, the fluid assembly 170 can use a plunger or any other equivalent arrangement so that the terms piston and plunger can be used interchangeably herein. Moved by the pony rod (166), the piston head 182 moves in a liner 184 communicating with a fluid passage 190. As the piston 182 moves, it pulls mud from a suction manifold 192 through a suction valve 194 into the passage 190 and pushes the mud in the passage 190 to a discharge manifold 198 through a discharge valve 196.

As noted previously, a triplex mud pump produces a total flow variation of about 23%. Because the present mud pump 100 is quintuplex, the pump 100 offers a lower variation in total flow, making the pump 100 better suited for pumping mud and producing less noise that can interfere with MWD and LWD operations. In particular, the quintuplex mud pump 100 can produce a total flow variation as low as about 7%. For example, the quintuplex mud pump 100 can produce a maximum flow level of about 102% during certain crankshaft angles and can produce a minimum flow level of 95% during other crankshaft angles as the pump"s five pistons move in their differing strokes during the crankshaft"s rotation. Being smoother and closer to ideal, the lower total flow variation of 7% produces less pressure changes or “noise” in the pumped mud that can interfere with MWD and LWD operations.

Although a quintuplex mud pump is described above, it will be appreciated that the teachings of the present disclosure can be applied to multiplex mud pumps having at least more than three eccentric sheaves, connecting rods, and fluid assembly pistons. Preferably, the arrangement involves an odd number of these components so such mud pumps may be septuplex, nonuplex, etc. For example, a septuplex mud pump according to the present disclosure may have seven eccentric sheaves, connecting rods, and fluid assembly pistons with at least two bull gears and at least two bearing sheaves on the crankshaft. The bull gears can be arranged between first and second eccentric sheaves and sixth and seventh eccentric sheaves on the crankshaft. The internal main bearings supporting the crankshaft can be positioned between third and fourth eccentric sheaves and the fourth and fifth eccentric sheaves on the crankshaft.

The most common scheme for transmitting measurement information utilizes the drilling fluid within the borehole as a transmission medium for acoustic waves modulated to represent the measurement information. Typically, drilling fluid or "mud" is circulated downward through the drill string and drill bit and upward through the annulus defined by the portion of the borehole surrounding the drill string. The drilling fluid not only removes drill cuttings and maintains a desired hydrostatic pressure in the borehole, but cools the drill bit. In a species of the technique referred to above, a downhole acoustic transmitter known as a rotary valve or "mud siren", repeatedly interrupts the flow of the drilling fluid, and this causes a varying pressure wave to be generated in the drilling fluid at a frequency that is proportional to the rate of interruption. Logging data is transmitted by modulating the acoustic carrier as a function of the downhole measured data.

One difficulty in transmitting measurement information via the drilling mud is that the signal received is typically of low amplitude relative to the noise generated by the mud pumps which circulate the mud, as the downhole signal is generated remote from the uphole sensors while the mud pumps are close to the uphole sensors. In particular, where the downhole tool generates a pressure wave that is phase modulated to encode binary data, such as is disclosed in U.S. Pat. No. 4,847,815 and assigned to the assignee hereof, and where the periodic noise sources are at frequencies which are at or near the frequency of the carrier wave (e.g. 12 Hz), difficulties arise.

Mud pumps are large positive displacement pumps which generate flow by moving a piston back and forth within a cylinder while simultaneously opening and closing intake and exhaust valves. A mud pump typically has three pistons attached to a common drive shaft. These pistons are one hundred and twenty degrees out of phase with one another to minimize pressure variations. Mud pump noise is caused primarily by pressure variations while forcing mud through the exhaust valve.

The fundamental frequency in Hertz of the noise generated by the mud pumps is equal to the strokes per minute of the mud pump divided by sixty. Due to the physical nature and operation of mud pumps, harmonics are also generated, leading to noise peaks of varying amplitude at all integer values of the fundamental frequency. The highest amplitudes generally occur at integer multiples of the number of pistons per pump times the fundamental frequency, e.g., 3F, 6F, 9F, etc. for a pump with three pistons.

Mud pumps are capable of generating very large noise peaks if pump pressure variations are not dampened. Thus, drilling rigs are typically provided with pulsation dampeners at the output of each pump. Despite the pulsation dampeners, however, the mud pump noise amplitude is typically much greater than the amplitude of the signal being received from the downhole acoustic transmitter. To reduce or eliminate the mud pump noise so that the downhole signal can be recovered, different techniques have been proposed, such as may be found in U.S. Pat. Nos. 3,488,629 to Claycomb, 3,555,504 to Fields, 3,716,830 to Garcia, 4,215,425 to Waggener, 4,215,427 to Waggener et al., 4,262,343 to Claycomb, 4,590,593 to Rodney, and 4,642,800 to Umeda. What is common to all of the techniques is that they try to eliminate the mud pump noise by adding the mud pump noise to an inverted version of itself. Most of the techniques utilize two sensors in the mud stream (usually two pressure sensors) and take the difference of signals in an attempt to cancel the mud pump noise without canceling the data signal. Various of the techniques require particular physical arrangements.

The Umeda U.S. Pat. No. 4,642,800 takes a slightly different approach to eliminating mud pump noise. Umeda teaches that an average pump signature may be found by obtaining the pump signatures in the presence of data over a certain number of pump cycles. The updated average pump signature is corrected by interpolation to match the current pump cycle length and is subtracted from the current pump signature to provide the residual data signal. While the technique disclosed in Umeda may be effective for particular arrangements, it has several drawbacks. First, because Umeda averages pump signatures which include data pulses, unless the effect of the data signal over any averaging period is zero (i.e. non-carrier frequency systems), the data signal which is to be recovered will tend to be undesirably subtracted from itself. Second, because Umeda uses only a single strobe per pump cycle, estimates (e.g. interpolations) are utilized which can introduce significant error. Third, Umeda does not disclose in detail how to treat a multi-pump system. In particular, if Umeda assumes that the pump signature for each pump of a multi-pump system is the same as it would be for a single pump system, large errors are introduced in attempting to cancel out the pump noise, as pumps which are working in multi-pump systems will have different signatures than they would it they were working in a single pump system. In addition, because estimates are required for each pump in the multi-pump system, additional error in the multi-pump system is introduced.

It is therefore an object of the invention to provide methods and systems for accurately recovering data signals introduced into drilling mud in the presence of mud pump noise.

It is another object of the invention to provide methods and systems for accurately recovering logging-while-drilling (LWD) or measurement-while-drilling (MWD) information which is modulated in drilling mud by correlating mud pump piston positions to a mud pressure signature in a calibration procedure.

It is a further object of the invention to provide methods and systems for accurately obtaining LWD or MWD information in multiple mud pump systems by allocating noise attributable to each mud pump and by tracking the mud pump piston position of each mud pump.

Another object of the invention is to provide method and systems for recovering LWD or MWD information transmitted through drilling mud by varying the pressure of the drilling mud regardless of the manner in which the information is coded.

In accord with the objects of the invention, methods for recovering a LWD or MWD data signal in the presence of mud pump noise are provided, and generally comprise calibrating the drilling mud pressure as a function of the mud pump piston position, and then tracking the piston position during transmission of the LWD or MWD data signal and using the calibration information to subtract out the mud pump noise. More particularly, calibration is accomplished in the absence of the LWD or MWD data signal to provide a correlation between mud pump piston position and the drilling mud pressure; i.e., the pressure signature as a function of mud pump piston position is obtained. Then, when the LWD or MWD data signal is being provided, the mud pump piston position is tracked such that the pressure due to the pump can be subtracted; i.e., by knowing the mud pump piston position, the pressure due to the mud pump is found and subtracted from the total received signal to provide the LWD or MWD signal. Where a plurality of mud pumps are used, calibration is accomplished by running the mud pumps together in the absence of the LWD or MWD data signal, and processing the received mud pressure signals in the Fourier domain to allocated respective portions of the mud pressure signals to respective mud pumps such that each mud pump is provided with a signature as a function of its own piston position. With the piston position of each mud pump being tracked, the sum of the mud pressure signals generated by the mud pumps based on their piston positions is subtracted from the total received signal to provide the LWD or MWD signal.

According to a preferred aspect of the invention, the calibration procedure is periodically repeated, e.g., each time additional pipe is added to the drill string, thereby eliminating the effects of depth and mud property variation on the system.

FIGS. 8a, 8b, and 8c are respectively the total pump signal, and the signals from pump one and pump two in the multiple pump system calibrated according to FIGS 7a and 7b.

Referring to FIG. 1, the operation of the present invention in a typical drilling arrangement is illustrated schematically. Drilling mud 10 is picked up from mud pit 11 by one or more mud pumps 12 which are typically of the piston reciprocating type. The mud 10 is circulated through mud line 13, down through the drill string 14, through the drill bit 15, and back to the surface of the formation via the annulus 16 between the drill stem and the wall of the well bore 29. Upon reaching the earth"s surface 31, the mud is discharged through line 17 back into the mud pit 11 where cuttings of rock or other well debris are allowed to settle out before the mud is recirculated.

A downhole pressure pulse signaling device 18 is incorporated in the drill string for transmission of data signals derived during the drilling operation by the measurement instrument package 19. Signaling device 18 may be of the valve or variable orifice type which generates pressure pulses in the drilling fluid by varying the speed of flow. A preferred signaling device which generates sinusoidal signals is disclosed in U.S. Pat. No. 4,847,815 assigned to the assignee hereof. Data signals are encoded in a desired form by appropriate electronic means in the downhole tool. Arrows 21, 22, and 23 illustrate the path taken by the pressure pulses provided by the downhole signaling device 18 under typical well conditions. Pump 12 also produces pressure pulses in the mud line 13 and these are indicated by arrows, 24, 25, 26 and 26a which also illustrate the flow of the mud through the annulus 16.

In order for the downhole pressure pulse signals to be recoverable at the surface, some means must be provided to remove or substantially eliminate the portion of the mud pressure signal due to the mud pumps. Subsystem 30, including pressure transducer 32, mud pump piston position sensors 34, and computer or processor 36, comprises such a means.

The preferred pressure transducer 32 of subsystem 30 is a piezoelectric pressure transducer which provides an analog signal which is preferably bandpass filtered by a filter (not shown) or by the computer 36. The preferred mud pump piston position sensor 34 may either comprise an LVDT which utilizes a linear position transducer, or an RVDT which utilizes a rotary position transducer. The LVDT, as shown in FIG. 2a, has an arm 40a, a rod 42a, and a linear position transducer 44a with leads 46a. Arm 40a is coupled to one of the piston rods 47 of the mud pump 12 as well as to rod 42a of the LVDT. Rod 42a moves coaxially within the linear position transducer 44a, which provides a high precision digital indication of the location of piston 48 in the mud pump 12. The RVDT, as shown in FIG. 2b, has an arm 40b, a cable 42b, and an encoder or rotary position transducer 44b with a spring loaded sheave takeup reel 45b. The RVDT also includes leads 46b. Arm 40b of the RVDT of FIG. 2b is coupled to one of the piston rods 47 of the mud pump 12 as well as to the cable 42b of the RBDT. As arm 40b moves with the pump piston rod 47, the cable 42b is let out or reeled onto the takeup reel 45b takeup reel. The rotation of the takeup reel 45b provides a high precision digital indication of the location of piston 48 in the mud pump 12.

Testing has shown that the drilling mud pressure generated by the mud pump 12 is determined by the position of the mud pump piston for a given set of operating conditions. FIG. 3 illustrates how mud pump piston position correlates to mud pump noise. By coupling the linear position transducer 44a or rotary position transducer 44b to the piston rod 47 of the mud pump, a calibration can be performed that measures the pressure generated as a function of piston position.

The preferred calibration procedure for correlating mud pressure generated as a function of piston position for a single mud pump system is seen in FIG. 4. After the pump noise stabilizes in the system, and before the LWD and MWD tool turns on (i.e. before the data signal starts), the signals output by the position sensor 34 and the signals output by the pressure transducer 32 which are bandpass filtered at 39 are preferably recorded at 52 as related position and pressure arrays 55, 57 in the computer (e.g. in computer memory). Preferably, approximately eight seconds of data (e.g., five to ten pump cycles) are accumulated. Then, averages of the pressure as a function of position are calculated (thereby reducing random pressure variations) at 58 to produced a single position vs. pump noise calibration array 59. Indications of the average calibration array or the inverse thereof are stored and used for canceling mud pump noise as is hereinafter described.

The noise cancellation procedure according to the invention is set forth in FIG. 5. Upon the turning on of the downhole tool and the transmission of LWD or MWD data (hereinafter referred to simply as LWD data for sake of brevity), the position sensor 34 and pressure transducer 32 continue to provide indications of piston location and mud pressure; except that the piston position data is used in real time to determine the electrical signal (based on the calibration array 59) which must be subtracted from the composite LWD/noise signal to cancel the noise component of the signal and leave only the LWD signal. Thus, as shown in FIG. 5, the position sensor signal is sampled at 62 (i.e. based on the position sensor signal, the average calibration array is accessed and a corresponding pump noise is provided), and the corresponding pump noise pressure 64 is subtracted at 66 from the real time sensed pressure 32 which was bandpass filtered at 67 to eliminate high frequency components. The difference between the real time sensed pressure and the pump noise pressure provides an indication of the LWD data signal 68.

Test results of a real time sensed pressure pump noise signal are seen in FIG. 6a, where the amplitude of the signal as expressed in dB (in 10 dB increments) is plotted versus the frequency expressed in Hz (in 4 Hz increments). As seen in FIG. 6a, the noise signal includes several peaks having amplitudes between -10 dB and 0 dB, and even includes a peak having an amplitude exceeding 10 dB. The noise signal of FIG. 6a was then subjected to the noise cancellation procedure of FIG. 5. The noise signal remaining after mud pump noise cancellation is seen in FIG. 6b, and shows that the calibration and noise cancellation procedures reduced noise considerably. In fact, the largest remaining noise peak found at about 5 Hz, has an amplitude of approximately -15 dB, which is more than 25 dB less than the largest peak seen in FIG. 6a prior to noise cancellation.

Turing to FIGS. 7, 7a and 7b, a flow chart of the mud pump calibration procedure for a system utilizing two mud pumps is seen. After the pump noise stabilizes in the system, and before the LWD tool turns on (i.e. before the data signal starts), the signals output by each position sensor 34a, 34b and the signal output by the pressure transducer 32 and filtered at 39 by a bandpass filter which measures composite pump noise are recorded as related position arrays 55a, 55b and pressure array 57 in the computer (e.g. in computer memory). Preferably, approximately twelve seconds of data are accumulated in computer memory at 52; FIG. 8a showing an example of the analog pressure signal which is digitized and stored as part of the array. A fast Fourier transform (FFT) of the composite pump noise signal is then conducted at 70 by the computer. As a result of the FFT, the amplitude and phase of all frequencies contained in the composite mud pump noise signal is obtained at 70 (see FIG. 9a). Utilizing the operating speed of each pump which can be computed from the position sensor of each mud pump, the fundamental frequency and harmonics for each pump are calculated at 72. The, at 75, the amplitude and phase information for each fundamental and harmonic frequency are extracted from the FFT and assigned to its source (i.e. a particular one of the mud pumps) to provide results as seen in FIGS. 9b and 9c. Taking an inverse Fourier transform of the frequency spectra of FIGS. 9b and 9c at 76a and 76b, signals attributable to each of the pumps are obtained as seen in FIGS. 8b and 8c. As indicated in FIG. 7b at 58a and 58b, the position of each mud pump position sensor is related to the mud pressure generated by the respective mud pump, and an average of the pressure as a function of position is calculated for each mud pump to produce two position vs. pump noise calibration arrays 59a and 59b. Indications of the average calibration arrays are stored in computer memory and used for canceling mud pump noise as is described above with reference to FIG. 10.

Referring now to FIG. 10, the noise cancellation procedure for a system using multiple mud pumps is seen. Upon the turning on of the downhole tool and the transmission of LWD data, the position sensors 34a and 34b and pressure transducer 32 continue to provide indications of piston location and mud pressure; except that the piston position data is used in real time to determine the electrical signal (based on the calibration arrays 59a and 59b) which must be subtracted from the composite LWD/noise signal to cancel the noise component of the signal and leave only the LWD signal. Thus, as shown in FIG. 10, the position sensor signals are sampled at 62a and 62b (i.e. based on the position sensor signals, the average calibration arrays 59a and 59b are accessed and corresponding pump noises are provided), and the corresponding pump noise pressures 64a and 64b are subtracted at 66 from the real time sensed pressure 32 which was bandpass filtered at 67 to eliminate high frequency components. The difference between the real time sensed pressure and the pump noise pressures provides an indication of the LWD data signal 68. That signal is then decoded according to techniques known in the art which are not part of the present invention.

Test results of a real time sensed pressure containing pump noise for two mud pumps is seen in FIG. 11a where amplitude is plotted against frequency. As seen in FIG. 11a, numerous noise peaks having amplitudes of -20 dB or higher are seen, with the largest peak of about -5 dB at 5 Hz. The pressure signal obtained after utilizing the calibration and noise cancellation steps of FIGS. 7 and 10 in order to substantially cancel mud pump noise from the signal of FIG. 10a is seen in FIG. 10b. As seen in FIG. 10b, the remaining noise is substantially reduced relative to the noise of FIG. 10a, with the largest peak of about -18 dB occurring at approximately 18 Hz.

There have been described and illustrated herein methods and apparatus for canceling mud pump noise in order to recover a logging while drilling signal. While particular embodiments of the invention have been described it is not intended that the the invention be limited exactly thereto, as it is intended that the invention be as broad in scope as the art will allow. Thus, while particular pressure transducers, position sensors, pump-types, computers, FFT programs, and the like have been disclosed, it will be appreciated that other equipment and programs can be utilized effectively. Similarly, while certain preferred data gathering time periods were disclosed prior to running the LWD or MWD tool, it will be appreciated that other time frames could be utilized. Also, while the invention was described with reference to LWD and MWD procedures, it will be appreciated that the terms LWD and MWD are intended to include any other data signaling procedure where data is transmitted in drilling mud in the presence of mud pump noise. Further, while the invention was disclosed with reference to systems utilizing one or two mud pumps, it will be appreciated that the teachings equally apply to systems utilizing additional mud pumps. All that is required is that the pressure signature of each mud pump relative to its piston position be obtained via transforming the total signal into the Fourier domain, dividing the Fourier response among the various mud pumps based on their fundamental and harmonic frequencies, and converting the responses back into respective pressure signatures. It will be understood, of course, that where two mud pumps are working in unison (i.e. at the same frequency), their signatures can be treated together. Therefore, it will be apparent to those skilled in the art that other changes and modifications may be made to the invention as described in the specification without departing from the spirit and scope of the invention as so claimed.

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.

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.

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.

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.

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.

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. T