mud pump systems free sample

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

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

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.

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

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

The gas over fluid internal systems has limitations too. The standpipe loses compression due to gas being consumed by the drilling fluid. In the absence of gas, the standpipe becomes virtually defunct because gravity (14.7 psi) is the only force driving the cylinders’ fluid. Also, gas is rarely replenished or charged in the standpipe.

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

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

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

This invention relates to communication systems, and more particularly, to systems and methods for receiving and interpreting data signals being transmitted to the surface of the earth in a logging-while-drilling system.

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.

Heating, Ventilating and Air Conditioning General Office Area: The building shall be equipped with a combination heating, ventilation and air conditioning system. The system shall have ducted supply and return air. The space above the ceiling shall not be used as a supply or return plenum. The systems shall be sized in accordance with the weather conditions identified in Chapter 13, “Energy Conservation” of the 1996 BOCA Building Code and supplemented by the “Building Code Rules”. All HVAC equipment shall be commercial or light industrial grade. If new construction it shall be installed at grade or within mechanical rooms for easy access and maintenance. If existing construction, roof mounted equipment will be considered after all other options have been exhausted, including the elimination of noise and vibration transfer to the structural members. The HVAC systems shall be zoned, with units sized and placed as required by heating and cooling loads on the building. Zoning of systems is dependent on the size, shape and orientation of the building. The HVAC system shall be divided into a minimum of 4 exterior and 1 interior temperature control zones. Return air shall be taken from the area supplied or adjacent to the area in the same temperature control zone. The ventilation and exhaust system shall be sized to maintain a positive pressure throughout the building envelope to limit air and dust infiltration. No HVAC ductwork shall be installed under the floor slab or underground.

Specifically designed for drilling companies and others in the oil and gas industry, the easy to use drilling rig inspections app makes it easy to log information about the drill rigs, including details about the drill rigs operators, miles logged and well numbers. The inspection form app covers everything from the mud pump areas and mud mixing area to the mud tanks and pits, making it easy to identify areas where preventative maintenance is needed. The drilling rig equipment checklist also covers health and safety issues, including the availability of PPE equipment, emergency response and preparedness processes, and other critical elements of the drilling process and drill press equipment.

Another aspect of drilling and well control relates to the drilling fluid, called "mud." The mud is a fluid that is pumped from the surface to the drill bit by way of the drill string. The mud serves to cool and lubricate the drill bit, and it carries the drill cuttings back to the surface. The density of the mud is carefully controlled to maintain the hydrostatic pressure in the borehole at desired levels.

One common method of communication is called "mud pulse telemetry." Mud pulse telemetry is a method of sending signals, either downlinks or unlinks, by creating pressure and/or flow rate pulses in the mud. These pulses may be detected by sensors at the receiving location. For example, in a downlink operation, a change in the pressure or the flow rate of the mud being pumped down the drill string may be detected by a sensor in the BHA. The pattern of the pulses, such as the frequency and the amplitude, may be detected by the sensors and interpreted so that the command may be understood by the BHA.

Mud pulse telemetry is well known in the drilling art. A common prior art technique for downlinking includes the temporary interruption of drilling operations so that the mud pumps at the surface can be cycled on and off to create the pulses. Drilling operations must be interrupted because the drill bit requires a continuous flow of mud to operate properly. Thus, drilling must be stopped while the mud pumps are being cycled.

Figure IA shows a prior art mud pulse telemetry system 100. The system 100 includes a mud pump 102 that pumps the mud from the surface, to the BHA 112, and back to the surface. A typical drilling rig will have multiple mud pumps that cooperate to pump the mud. Mud pumps are positive displacement pumps, which are able to pump at a constant flow rate at any pressure. These pumps are diagrammatically represented as one pump 102.

Mud from the mud storage tank 104 is pumped through the pump 102, into a standpipe 108, and down the drill string 110 to the drill bit 114 at the bottom of the BHA l 12. The mud leaves the drill string 1 10 through ports (not shown) in the drill bit 114, where it cools and lubricates the drill bit 114. The mud also carries the drill cuttings back to the surface as it flows up through the annulus 1 16. Once at the surface, the mud flows through a mud return line 118 that returns the mud to the mud storage tank 104. A downlink operation involves cycling the pump 102 on and off to create pulses in the mud. Sensors in the BHA detect the pulses and interpret them as an instruction.

Another prior art downlink technique is shown in Figure 1B. The downlink signal system 120 is a bypass from the standpipe 108 to the mud return line 118. The system 120 operates by allowing some of the mud to bypass the drilling system. Instead of passing through the drill string (110 in Figure IA), the BHA (112 in Figure IA), and returning through the annulus (116 in Figure I A), a relatively small fraction of the mud flowing through the standpipe 108 is allowed to flow directly into the mud return line 118. The mud flow rate to the BHA (not shown) is decreased by the amount that flows through the bypass system 120.

The full output of the mud pump 102 will flow to the BHA (not shown) during normal operations. When an operator desires to send an instruction to the BHA (not shown), a downlink signal may be generated by sequentially opening and closing the choke valve 124. The opening and closing of the choke valve 124 creates fluctuations in the mud flow rate to the BHA (not shown) by allowing a fraction of the mud to flow through the bypass 120. These pulses are detected and interpreted by the sensors in the BHA (not shown). The bypass system 120 may include flow restrictors 122, 126 to help regulate the flow rate through the system 120.

One advantage to this type of system is that a bypass system diverts only a fraction of the total flow rate of mud to the BHA. With mud still flowing to the BHA and the drill bit, drilling operations may continue, even while a downlink signal is being sent.

One aspect of the invention relates to a downlink system comprising at least one mud pump for pumping drilling fluid from a drilling fluid storage tank to a drilling system, a standpipe in fluid communication with the mud pump and in fluid communication with the drilling system, a return line in fluid communication with the drilling system for returning the drilling fluid to the drilling fluid storage tank, and a drilling fluid modulator in fluid communication with at least one of the group consisting of the standpipe and the return line.

Another aspect of the invention relates to a method of transmitting a downlink signal comprising pumping drilling fluid to a drilling system and selectively operating a modulator to create pulses in a drilling fluid flow. In some embodiments the modulator is disposed in a standpipe.

Yet another aspect of the invention relates to a drilling fluid pump controller comprising at least one actuation device coupled to a control console, and at least one connector coupled to the at least one actuation device and a pump control mechanism.

A still further aspect of the invention relates to a method for generating a downlink signal comprising coupling an actuation device to a pump control panel, coupling the actuation device to a pump control device on the pump control panel, and creating a pulse in a drilling fluid flow by selectively controlling the pump control device with the actuation device.

Another aspect of the invention relates to a downlink system comprising a drilling fluid pump in fluid communication with a drilling system, the drilling fluid pump having a plurality of pumping elements, and a pump inefficiency controller operatively coupled to at least one of the plurality of pumping elements for selectively reducing the efficiency of the at least one of the plurality of pumping elements.

Another aspect of the invention relates to a method of generating a downlink signal comprising pumping drilling fluid using at least one drilling fluid pump having a plurality of pumping elements, and creating a pulse in a drilling fluid flow by selectively reducing the efficiency of at least one of the plurality of pumping elements.

Another aspect of the invention relates to a downlink system comprising at least one primary drilling fluid pump in fluid communication with a drilling fluid tank at an intake of the at least one drilling fluid pump and in fluid communication with a standpipe at a discharge of the at least one drilling fluid pump, and a downlink pump in fluid communication with the standpipe at a discharge of the reciprocating downlink pump.

Another aspect of the invention relates to a method of generating a downlink signal comprising pumping drilling fluid to a drilling system at a nominal flow rate, and selectively alternately increasing and decreasing the mud flow rate of the drilling fluid using a downlink pump having an intake that is in fluid communication with a standpipe and having a discharge that is in fluid communication with the standpipe.

Another aspect of the invention relates to a downlink system comprising at least one primary drilling fluid pump in fluid communication with a drilling fluid tank at an intake of the at least one drilling fluid pump and in fluid communication with a standpipe at a discharge of the at least one drilling fluid pump, and an electronic circuitry operatively coupled to the at least one primary drilling fluid pump and adapted to modulate a speed of the at least one primary drilling fluid pump.

Another aspect of the invention relates to a method of generating a downlink signal comprising operating at least one primary drilling fluid pump to pump drilling fluid through a drilling system, and engaging an electronic circuitry that is operatively coupled to the at least one primary drilling fluid pump to modulate a speed of the at least one primary drilling fluid pump.

In certain embodiments, the present invention relates to downlink systems and methods for sending a downlink signal. A downlink signal may be generated by creating pulses in the pressure or flow rate of the mud being pumped to the drill bit.

"Standpipe" is a term that is known in the art, and it typically refers to the high- pressure fluid passageway that extends about one-third of the way up a drilling rig. In this disclosure, however, "standpipe" is used more generally to mean the fluid passageway between the mud pump and the drill string, which may include pipes, tubes, hoses, and other fluid passageways.

A "drilling system" typically includes a drill string, a BHA with sensors, and a drill bit located at the bottom of the BHA. Mud that flows to the drilling system must return through the annulus between the drill string and the borehole wall. In the art, a "drilling system" may be known to include the rig, the rotary table, and other drilling equipment, but in this disclosure it is intended to refer to those components that come into contact with the drilling fluid.

Figure 2 shows a schematic of a downlink system in accordance with one embodiment of the invention. The system includes a bypass line 200 with a shutoff valve 204, a flow restrictor 205, a flow diverter 206, a modulator 210 coupled to a control circuitry 231, and a second flow restrictor 215. The bypass 200 is in fluid communication with the standpipe 208 at an upstream end and with the mud return line 218 on a downstream end. This arrangement enables the bypass line 200 to divert mud flow from the standpipe 208, thereby reducing the flow rate to the BHA (not shown).

The bypass system 200 includes a modulator 210 for varying the flow rate of mud through the bypass system 200. The frequency and amplitude of the flow rate changes define the downlink signal. One embodiment of a modulator will be described in more detail later, with respect to Figure 3A.

The downlink system in Figure 2 includes a shutoff valve 204. The shutoff valve 204 is used to isolate the bypass line 200 when no downlink signal is being transmitted. By closing the shutoff valve 204, the downlink system is protected from erosion that can occur when mud flows through the components of the system. When the bypass line 200 is in use, the shutoff valve 204 may be in a fully open position so that it will not be exposed to the high mud velocities that erode the choke valves (e.g., 124 in Figure I B) of the prior art. In a preferred embodiment, the shutoff valve 204 is disposed up stream of a flow restrictor (e.g., 205) so that the shutoff valve 204 will not experience the high mud flow rates present downstream of a flow restrictor.

In some embodiments, a bypass line 200 according to the invention includes a flow restrictor 205. The flow restrictor 205 provides a resistance to flow that restricts the amount of mud that may flow through the bypass line 200. The flow restrictor 205 is also relatively low cost and easily replaced. This enables the flow restrictor 205 to be eroded by the mud flow without damaging more expensive parts of the system.

When the flow restrictor 205 is located upstream from the modulator 210, it may also serve as a pressure pulse reflector that reduces the amount of noise generated in the standpipe 208. For example, the modulator 210 may be used to create pulses in the mud flow. This has a side effect of creating back pulses of pressure that will propagate through the standpipe 208 and create noise. In drilling systems that also use uplink telemetry, noise may interfere with the detection of the uplink signal. A flow restrictor 205 will reflect a large portion of these back pressure pulses so that the standpipe 208 will be much less affected by noise.

A flow diverter 206 may be advantageous because the mud flow downstream of a flow restriction 205 is often a turbulent flow. A flow diverter 206 may be used to bring the mud flow back to a less turbulent flow regime. This will reduce the erosion effect that the mud flow will have on the modulator 210.

The second flow restrictor serves to generate enough back pressure to avoid cavitation in the modulator 210. Cavitation is a danger because it affects the mud pulse signal and it causes severe erosion in the modulator 210. In situations where cavitation is not a danger, it may be advantageous to use embodiments of the invention that do not include a second or downstream flow restrictor 215.

As the rotor 302 rotates, the passages 311, 312, 313 in the rotor 302 alternately cover and uncover the passages 321, 322, 323 in the stator 304. When the passages 321, 322, 323 in the stator are covered, flow through the modulator 301 is restricted. The continuous rotation of the rotor 302 causes the flow restriction in the modulator 301 to alternately close to a minimum size and open to a maximum size. This creates sine wave pulses in the mud flow.

One or more embodiments of a downlink system with a modulator may present some of the following advantages. A modulator may generate sine waves with a frequency and amplitude that are easily detectable by sensors in a BHA. The frequency of the sine waves may also enable a much faster transmission rate than was possible with prior art systems. Advantageously, a sine wave has less harmonics and generates less noise that other types of signals. Certain embodiments of the invention may enable the transmission of a downlink signal in only a few minutes, compared to the twenty to

Advantageously, certain embodiments of the invention enable a downlink signal to be transmitted simultaneous with drilling operations. This means that a downlink signal may be transmitted while drilling operations continue and without the need to interrupt the drilling process. Some embodiments enable the adjustment of the modulator so that an operator can balance the need for signal strength with the need for mud flow. Moreover, in situations where it becomes necessary to interrupt drilling operations, the improved rate of transmission will enable drilling to continue in a much shorter time.

Figure 4A shows another embodiment of a downlink system 400 in accordance with the invention. A modulator 410 is disposed in-line with the standpipe 408 and down stream of the mud pump 402. Instead of regulating the flow of mud through a bypass, the modulator 410 in the embodiment shown in Figure 4A regulates the pressure in the standpipe 408.

In the embodiment shown in Figure 4A, the downlink system 400 includes a flow diverter 406 downstream of the mud pump 402 and upstream of the modulator 410. The mud flow from the mud pump is often turbulent, and it may be desirable to create a normal flow regime upstream of the modulator 410. As was described above with reference to Figure 3A, the flow diverter 406 may be coated on its inside with an erosion resistant coating, such as carbide or diamonds. In some embodiments, the flow diverter 406 may include a carbide insert designed to be easily replaced.

The modulator 410 shown in Figure 4A is in parallel with a second flow restrictor 411. The second flow restrictor 411 enables some of the mud to flow past the modulator without being modulated. This has the effect of dampening the signal generated by the modulator 410. While this dampening will decrease the signal strength, it may nevertheless be desirable. The second flow restrictor 411 may enable enough mud to flow through the downlink system 400 so that drilling operations can continue when a downlink signal is being transmitted. Those having skill in the art will be able to balance the need for mud flow with the need for signal strength, when selecting the components of a downlink system.

in another embodiment, shown in Figure 4B, a downlink system 450 may be disposed in the mud return line 418. The embodiment shown in Figure 4B includes a flow diverter 406, a modulator 410 in parallel with a flow restrictor 411, and a down stream flow restrictor 415. Each operates substantially the same as the same components described with reference to Figure 4A. In this case, however, the downlink system 450 is located in the return line 418 instead of the standpipe (408 in Figure 4A).

The downlink system 450 is still able to modulate the mud pressure in the drilling system (not shown) so that the pulses may be detected by sensors in the BHA.

Advantageously, a downlink system disposed in the mud return linegenerates a very small amount of noise in the standpipe that would affect uplink transmissions.

One embodiment of a downlink control system 500 in accordance with the invention is shown in Figure 5A. An operator"s control console 502 typically includes pump control mechanisms. As shown in Figure 5A the pump control mechanisms may comprise knobs 504, 505, 506 that control the speed of the mud pumps (not shown).

Figure 5A shows three control knobs 504, 505, 506 that may control three mud pumps (not shown). A drilling system may contain more or less than three mud pumps.

Accordingly, the control console can have more or less mud pump control knobs. The number of control knobs on the control console is not intended to limit the invention.

A typical prior art method of sending a downlink system involves interrupting drilling operations and manually operating the control knobs 504, 505, 506 to cause the mud pumps to cycle on and off. Alternatively, the control knobs 504, 505, 506 may be operated to modulate the pumping rate so that a downlink signal may be sent while drilling continues. In both of these situations, a human driller operates the control knobs 504, 505, 506. It is noted that, in the art, the term "driller" often refers to a particular person on a drilling rig. As used herein, the term "driller" is used to refer to any person on the drilling rig.

The actuation devices 511, 513, 515 may be coupled to the control knobs 504, 505, 506 by methods other than belts 511, 513, 515. For example, Figure 5B shows a pump control knob 504 that is coupled to an actuation device 521 using a drive wheel 523. The actuation device causes the drive wheel 523 to rotate, which, in turn, causes the stem 509 of the control knob 504 to rotate. In some embodiments, such as the one shown in Figure 5B, an actuation device 521 includes a tension arm 524 to hold the actuation device 521 and the drive wheel 523 in place. The tension arm 524 in Figure 5B includes two free rotating wheels 528, 529 that contact an opposite side of the stem 509 of the control knob 504 from the drive wheel 523.

Figure 5C shows another embodiment of an actuation device 531 coupled to a pump control lever 535. The actuation device 531 includes a drive wheel 533 that is coupled to the pump control lever 535 by a connecting rod 534. When the drive wheel 533 is rotated by the actuation mechanism 531, the lever 535 is moved in a corresponding direction by the connecting rod 534.

Figure 5D shows another embodiment of an actuation device 541 in accordance with the invention. The actuation device 541 mounts on top of the pump control lever 546. The actuation device 541 includes an internal shape that conforms to the shape of the pump control lever 546. As the internal drive 544 of the actuation device 541 rotates, the pump control lever 546 is also rotated.

One or more embodiments of an actuation device may present some of the following advantages. Actuation devices may be coupled to already existing drilling systems. Thus, an improved downlink system may be achieved without adding expensive equipment to the pumping system.

Advantageously, the mechanical control of an actuation device may be quicker and more precise than human control. As a result, a downlink signal may be transmitted more quickly and with a higher probability that the transmission will be correctly received on the first attempt. The precision of a mechanical actuation device may also enable sufficient mud flow and a downlink signal to be transmitted during drilling operation.

Advantageously, the mechanical control of an actuation device provides a downlink system where no additional components are needed that could erode due to mud flow. Because no other modifications are needed to the drilling system, operators and drillers may be more accepting of a downlink system. Further, such a system could be easily removed if it became necessary.

In some other embodiments, a downlink system comprises a device that causes the mud pumps to operate inefficiently or that causes at least a portion of the mud pumps to temporarily stop operating. For example, Figure 6 diagrammatically shows a pump inefficiency controller 601 attached to a mud pump 602a. Figure 6 shows three mud pumps 602a, 602b, 602c. Drilling rigs can include more or fewer than three mud pumps. Three are shown in Figure 6A for illustrative purposes.

Each of the mud pumps 602a, 602b, 602c draws mud from the mud storage tank 604 and pumps the mud into the standpipe 608. Ideally, the mud pumps 602a, 602b, 602c will pump at a constant flow rate. The pump inefficiency controller 601 is connected to the first mud pump 602a so that the controller 601 may affect the efficiency of the first mud pump 602a.

Figure 6B diagrammatically shows the internal pumping elements of the first mud pump 602a. The pumping elements of pump 602a include three pistons 621, 622, 623 that are used to pump the mud. For example, the third piston 623 has an intake stroke, where the piston 623 moves away from the intake valve 625, and mud is drawn from the mud tank into the piston chamber. The third piston 623 also has an exhaust stroke, where the piston 623 moves in the opposite direction and pushes the mud out an exhaust valve 626 and into the standpipe (608 in Figure 6A). Each of the other pistons 621, 622 has a similar operation that will not be separately described.

The first piston 621 includes a valve controller 628 that forms part of, or is operatively coupled to, the pump inefficiency controller (604 in Figure 6A). When it is desired to send a downlink signal, the valve controller 628 prevents the intake valve 627 on the first piston 621 from opening during the intake stroke. As a result, the first piston 621 will not draw in any mud that could be pumped out during the exhaust stroke. By preventing the intake valve 627 from opening, the efficiency of the first pump 603 is reduced by about 33%. The efficiency of the entire pumping system (including all three mud pumps 602a, 602b, 602c in the embodiment shown in Figure 6A, for example) is reduced by about 11 %.

By operating the pump inefficiency controller (604 in Figure 6A), the efficiency, and thus the flow rate, of the mud pumping system can be reduced. Intermittent or selective operation of the pump efficiency controller creates pulses in the mud flow rate that may be detected by sensors in the BHA.

One or more embodiments of a pump inefficiency controller may present some of the following advantages. An inefficiency controller may be coupled to any preexisting mud pump system. The downlink system may operate without the need to add any equipment to the pump system. The pump inefficiency controlled may be controlled by a computer or other automated process so that human error in the pulse generation is eliminated. Without human error, the downlink signal may be transmitted more quickly with a greater chance of the signal being received correctly on the first attempt.

Figure 7A diagrammatically shows another embodiment of a downlink system 700 in accordance with the invention. A downlink pump 711 is connected to the mud manifold 707 that leads to the standpipe 708, but it is not connected to the mud tanks 704. As with a typical mud pump system, several mud pumps 702a, 702b, 702c are connected to the mud tank 704. Mud from the tank is pumped into the mud manifold 707 and then into the standpipe 708.

Pumps also have a "discharge," where fluid is pumped out of the pump. In Figure 7A, the intake end of each of the mud pumps 702a, 702b, 702c is connected to the mud storage tank 704, and the discharge end of each of the mud pumps 702a, 702b, 702c is connected to the mud manifold 707. Both the intake and the discharge of the downlink pump 711 are connected to the mud manifold 707.

The downlink pump 711 shown in Figure 7A is a reciprocating piston pump that has intake and exhaust strokes like that described above with respect to Figure 6B. On the intake stroke, mud is drawn into the downlink pump 711, and on the exhaust stroke, mud is forced out of the downlink pump 711. The operation of the downlink pump 711 differs from that of the other pumps 702a, 702b, 702c in the mud pump system because it is not connected to the mud tank 704. Instead, both the intake and exhaust valves (not shown) of the downlink pump 711 are connected to the mud manifold 707. Thus, on the intake stroke, the downlink pump 711 draws in mud from the mud manifold 707, decreasing the overall flow rate from the mud pump system. On the exhaust stroke, the downlink pump 711 pumps mud into the mud manifold 707 and increases the overall flow rate from the mud pump system. In some embodiments, one valve serves as both the inlet and the discharge for the downlink pump. In at least one embodiment, a downlink pump is connected to the manifold, but it does not include any valves. The mud is allowed to flow in and out of the downlink pump through the connection to the manifold.

Selected operation of the downlink pump 711 will create a modulation of the mud flow rate to the BHA (not shown). The modulation will not only include a decrease in the flow rate-as with the bypass systems described above-but it will also include an increase in the flow rate that is created on the exhaust stroke of the downlink pump 711. The frequency of the downlink signal may be controlled by varying the speed of the downlink pump 711. The amplitude of the downlink signal may be controlled by changing the stroke length or piston and sleeve diameter of the downlink pump 711.

Those having ordinary skill in the art will also appreciate that the location of a downlink pump is not restricted to the mud manifold. A downlink pump could be located in other locations, such as, for example, at any position along the standpipe.

Figure 8 diagrammatically shows another embodiment of a downlink system 820 in accordance with the invention. The mud pumping system includes mud pumps 802a, 802b, 802c that are connected between a mud tank 804 and a standpipe 808. The operation of these components has been described above and, for the sake of brevity, it will not be repeated here.

The downlink system includes two diaphragm pumps 821, 825 whose intakes and discharges are connected to the mud manifold 807. The diaphragm pumps 821, 825 include a diaphragm 822, 826 that separates the pumps 821, 825 into two sections. The position of the diaphragm 822 may be pneumatically controlled with air pressure on the back side of the diaphragm 822. In some embodiments, the position of the diaphragm 822 may be controlled with a hydraulic actuator mechanically linked to diaphragm 822 or with an electromechanical actuator mechanically linked to diaphragm 822. When the air pressure is allowed to drop below the pressure in the mud manifold 807, mud will flow from the manifold 807 into the diaphragm pump 821. Conversely, when the pressure behind the diaphragm 822 is increased above the pressure in the mud manifold 807, the diaphragm pump 821 will pump mud into the mud manifold 807.

Figure 7 shows one piston downlink pump, and Figure 8 shows two diaphragm downlink pumps. The invention is not intended to be limited to either of these types of pumps, nor is the invention intended to be limited to one or two downlink pumps.

Figure 9 diagrammatically shows another embodiment of a downlink pump 911 in accordance with the invention. The discharge of the downlink pump 911 is connected to the mud manifold 907, and the intake of the downlink pump 911 is connected to the mud tank 904. The downlink pump 911 in this embodiment pumps mud from the mud tank 904 into the mud manifold 907, thereby increasing the nominal flow rate produced by the mud pumps 902a, 902b, 902c.

During normal operation, the downlink pump 911 is not in operation. The downlink pump 911 is only operated when a downlink signal is being sent to the BHA (not shown). The downlink pump 911 may be intermittently operated to create pulses of increased flow rate that can be detected by sensors in the BHA (not shown). These pulses are of an increased flow rate, so the mud flow to the BHA remains sufficient to continue drilling operations while a downlink signal is being sent.

One or more embodiments of a downlink pump may present some of the following advantages. A reciprocating pump enables the control of both the frequency and the amplitude of the signal by selecting the speed and stroke length of the downlink pump. Advantageously, a reciprocating pump enables the transmission of complicated mud pulse signals in a small amount of time.

A pump of this type is well known in the art, as are the necessary maintenance schedules and procedures. A downlink pump may be maintained and repaired at the same time as the mud pumps. The downlink pump does not require additional lost drilling time due to maintenance and repair.

Advantageously, a diaphragm pump may have no moving parts that could wear out or fail. A diaphragm pump may require less maintenance and repair than other types of pumps.

Advantageously, a downlink pump that is coupled to both the mud tanks and the standpipe may operate by increasing the nominal mud flow rate. Thus, there is no need to interrupt drilling operations to send a downlink signal.

In some embodiments, a downlink system includes electronic circuitry that is operatively coupled to the motor for at least one mud pump. The electronic circuitry controls and varies the speed of the mud pump to modulate the flow rate of mud through the drilling system.

There are many different ways to drill a domestic water well. One is what we call the “mud rotary” method. Whether or not this is the desired and/or best method for drilling your well is something more fully explained in this brief summary.

One advantage of drilling with compressed air is that it can tell you when you have encountered groundwater and gives you an indication how much water the borehole is producing. When drilling with water using the mud rotary method, the driller must rely on his interpretation of the borehole cuttings and any changes he can observe in the recirculating fluid. Mud rotary drillers can also use borehole geophysical tools to interpret which zones might be productive enough for your water well.

The mud rotary well drilling method is considered a closed-loop system. That is, the mud is cleaned of its cuttings and then is recirculated back down the borehole. Referring to this drilling method as “mud” is a misnomer, but it is one that has stuck with the industry for many years and most people understand what the term actually means.

The water is carefully mixed with a product that should not be called mud because it is a highly refined and formulated clay product—bentonite. It is added, mixed, and carefully monitored throughout the well drilling process.

The purpose of using a bentonite additive to the water is to form a thin film on the walls of the borehole to seal it and prevent water losses while drilling. This film also helps support the borehole wall from sluffing or caving in because of the hydraulic pressure of the bentonite mixture pressing against it. The objective of the fluid mixture is to carry cuttings from the bottom of the borehole up to the surface, where they drop out or are filtered out of the fluid, so it can be pumped back down the borehole again.

When using the mud rotary method, the driller must have a sump, a tank, or a small pond to hold a few thousand gallons of recirculating fluid. If they can’t dig sumps or small ponds, they must have a mud processing piece of equipment that mechanically screens and removes the sands and gravels from the mixture. This device is called a “shale shaker.”

The driller does not want to pump fine sand through the pump and back down the borehole. To avoid that, the shale shaker uses vibrating screens of various sizes and desanding cones to drop the sand out of the fluid as it flows through the shaker—so that the fluid can be used again.

Some drillers use compressed air to blow off the well, starting at the first screened interval and slowly working their way to the bottom—blowing off all the water standing above the drill pipe and allowing it to recover, and repeating this until the water blown from the well is free of sand and relatively clean. If after repeated cycles of airlift pumping and recovery the driller cannot find any sand in the water, it is time to install a well development pump.

Additional development of the well can be done with a development pump that may be of a higher capacity than what the final installation pump will be. Just as with cycles of airlift pumping of the well, the development pump will be cycled at different flow rates until the maximum capacity of the well can be determined. If the development pump can be operated briefly at a flow rate 50% greater than the permanent pump, the well should not pump sand.

Mud rotary well drillers for decades have found ways to make this particular system work to drill and construct domestic water wells. In some areas, it’s the ideal method to use because of the geologic formations there, while other areas of the country favor air rotary methods.

To learn more about the difference between mud rotary drilling and air rotary drilling, click the video below. The video is part of our “NGWA: Industry Connected” YouTube series:

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.

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.

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.

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