mud pump that gives sufficient flowrate but not enough pressure free sample

When choosing a size and type of mud pump for your drilling project, there are several factors to consider. These would include not only cost and size of pump that best fits your drilling rig, but also the diameter, depth and hole conditions you are drilling through. I know that this sounds like a lot to consider, but if you are set up the right way before the job starts, you will thank me later.

Recommended practice is to maintain a minimum of 100 to 150 feet per minute of uphole velocity for drill cuttings. Larger diameter wells for irrigation, agriculture or municipalities may violate this rule, because it may not be economically feasible to pump this much mud for the job. Uphole velocity is determined by the flow rate of the mud system, diameter of the borehole and the diameter of the drill pipe. There are many tools, including handbooks, rule of thumb, slide rule calculators and now apps on your handheld device, to calculate velocity. It is always good to remember the time it takes to get the cuttings off the bottom of the well. If you are drilling at 200 feet, then a 100-foot-per-minute velocity means that it would take two minutes to get the cuttings out of the hole. This is always a good reminder of what you are drilling through and how long ago it was that you drilled it. Ground conditions and rock formations are ever changing as you go deeper. Wouldn’t it be nice if they all remained the same?

Centrifugal-style mud pumps are very popular in our industry due to their size and weight, as well as flow rate capacity for an affordable price. There are many models and brands out there, and most of them are very good value. How does a centrifugal mud pump work? The rotation of the impeller accelerates the fluid into the volute or diffuser chamber. The added energy from the acceleration increases the velocity and pressure of the fluid. These pumps are known to be very inefficient. This means that it takes more energy to increase the flow and pressure of the fluid when compared to a piston-style pump. However, you have a significant advantage in flow rates from a centrifugal pump versus a piston pump. If you are drilling deeper wells with heavier cuttings, you will be forced at some point to use a piston-style mud pump. They have much higher efficiencies in transferring the input energy into flow and pressure, therefore resulting in much higher pressure capabilities.

Piston-style mud pumps utilize a piston or plunger that travels back and forth in a chamber known as a cylinder. These pumps are also called “positive displacement” pumps because they literally push the fluid forward. This fluid builds up pressure and forces a spring-loaded valve to open and allow the fluid to escape into the discharge piping of the pump and then down the borehole. Since the expansion process is much smaller (almost insignificant) compared to a centrifugal pump, there is much lower energy loss. Plunger-style pumps can develop upwards of 15,000 psi for well treatments and hydraulic fracturing. Centrifugal pumps, in comparison, usually operate below 300 psi. If you are comparing most drilling pumps, centrifugal pumps operate from 60 to 125 psi and piston pumps operate around 150 to 300 psi. There are many exceptions and special applications for drilling, but these numbers should cover 80 percent of all equipment operating out there.

The restriction of putting a piston-style mud pump onto drilling rigs has always been the physical size and weight to provide adequate flow and pressure to your drilling fluid. Because of this, the industry needed a new solution to this age-old issue.

Enter Cory Miller of Centerline Manufacturing, who I recently recommended for recognition by the National Ground Water Association (NGWA) for significant contributions to the industry.

As the senior design engineer for Ingersoll-Rand’s Deephole Drilling Business Unit, I had the distinct pleasure of working with him and incorporating his Centerline Mud Pump into our drilling rig platforms.

In the late ’90s — and perhaps even earlier —  Ingersoll-Rand had tried several times to develop a hydraulic-driven mud pump that would last an acceptable life- and duty-cycle for a well drilling contractor. With all of our resources and design wisdom, we were unable to solve this problem. Not only did Miller provide a solution, thus saving the size and weight of a typical gear-driven mud pump, he also provided a new offering — a mono-cylinder mud pump. This double-acting piston pump provided as much mud flow and pressure as a standard 5 X 6 duplex pump with incredible size and weight savings.

The true innovation was providing the well driller a solution for their mud pump requirements that was the right size and weight to integrate into both existing and new drilling rigs. Regardless of drill rig manufacturer and hydraulic system design, Centerline has provided a mud pump integration on hundreds of customer’s drilling rigs. Both mono-cylinder and duplex-cylinder pumps can fit nicely on the deck, across the frame or even be configured for under-deck mounting. This would not be possible with conventional mud pump designs.

Centerline stuck with their original design through all of the typical trials and tribulations that come with a new product integration. Over the course of the first several years, Miller found out that even the best of the highest quality hydraulic cylinders, valves and seals were not truly what they were represented to be. He then set off on an endeavor to bring everything in-house and began manufacturing all of his own components, including hydraulic valves. This gave him complete control over the quality of components that go into the finished product.

The second generation design for the Centerline Mud Pump is expected later this year, and I believe it will be a true game changer for this industry. It also will open up the application to many other industries that require a heavier-duty cycle for a piston pump application.

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 fluid mixture must have a gel strength sufficient to support marble-size gravels and sand to the surface when the fluid is moving. Once the cuttings have been carried to the surface and the velocity of the fluid allowed to slow down, the fluid is designed to allow the sand and gravel to drop out.

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.

When the borehole has reached the desired depth and there is evidence that the formation it has penetrated will yield enough water, then it’s time to make the borehole into a well.

Before the well casing and screens are lowered into the borehole, the recirculating fluid is slowly thinned out by adding fresh water as the fluid no longer needs to support sand and gravel. The driller will typically circulate the drilling from the bottom up the borehole while adding clear water to thin down the viscosity or thickness of the fluid. Once the fluid is sufficiently thinned, the casing and screens are installed and the annular space is gravel packed.

Gravel pack installed between the borehole walls and the outside of the well casing acts like a filter to keep sand out and maintain the borehole walls over time. During gravel packing of the well, the thin layer of bentonite clay that kept the borehole wall from leaking drilling fluid water out of the recirculating system now keeps the formation water from entering the well.

This is where well development is performed to remove the thin bentonite layer or “wall cake” that was left behind. Various methods are used to remove the wall cake and develop the well to its maximum productivity.

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:

We introduced parallel and series pumping systems in the January column of The Water Works with a discussion on parallel pumping installations and possible pitfalls. This month we continue the discussion with series pumping installations.

As opposed to a parallel pumping configuration, a series (often mistakenly referred to as a real booster pump system) pumping installation implies the entire discharged volume (flow rate) of source water working against a proportionally lower amount of the total head will be delivered from a water supply source (a source pump or pressurized water system) and immediately delivered to the inlet (suction) of an inline booster pump to elevate the combined system head (pressure) to the total dynamic head (TDH) in tandem.

An idealized scenario where two identical pumps are used to effectively double the discharge head from 150 feet to 300 feet at a common flow rate of 1000 gallons per minute is shown in Figure 1 (TDH: 1 + 1 = 2). In some cases, up to three to four pumps at different levels are used to generate the TDH in stages and at different intervals, with each pump adding its unique and individual value of head toward the resulting total head, all at a uniform flow rate.

Although the head delivered by each pump may be dissimilar, it is critical that all pumps used in a series pumping configuration are designed for and capable of accepting and producing the same flow (discharge) rate or range, preferably within the best efficiency window.

Even when using a variable frequency drive in many actual applications, depending on the use with each service condition, this type of wide variance in flow rate (more than 25%) between the primary and alternate conditions presents itself as a potentially ideal type of situation to consider using a series pumping installation.

This permits the source pump to be designed for a wider range of flow with a higher efficiency at the more frequently used alternate (usually lower) flow condition and with a lower operating efficiency at the less used primary condition. So long as the source pump is capable of the higher capacity primary condition flow rate from the well and well pump with sufficient head into the suction of the second stage, or booster pump, the system can be an efficient alternative to using a single pump.

As a rule of thumb, I have found a well/booster pump system is most efficient when the well pump is required to produce 50% to 75% of the total head, with the booster pump producing 25% to 50% of the total head at a common flow rate. This percentage range in a two-step pumping arrangement generally allows for the possibility of using the source pump only for the lower system demands.

It is also a valid scenario when an existing or lower horsepower well pump is present and desired to be retained which may be capable of producing the required higher flow rate but is not capable of the required higher head without boosting, the power supply is limited or not capable of starting a single large (50 HP for example) motor, or the client does not wish to use a variable frequency drive in the installation.

In this case, the well pump would generally be designed as a single speed, lower HP unit that would be capable of delivering the primary flow of 500 GPM into the booster pump and efficiently pumping at a reduced flow rate of 156 GPM at the required lower head (approximately 240 feet).

In our revised design example using a submersible well pump and end-suction centrifugal booster pump combination, we begin by examining and deducting the 90 feet well lift (pumping water level, PWL) added to the riser pipe and discharge friction loss (7 feet), which at 500 GPM totals an adjusted pumping water level (APWL) of 97 feet. This means, at a minimum, enough of the well pump’s head must be reserved to lift the water to the top of the well and into the booster pump under maximum flow conditions.

Typically, in these cases I try to add a minimum safety factor of no less than 10 psi (23 feet) to this value of head. I actually prefer to add 20 psi (46 feet) of reserve head to the APWL, when available, to account for a possible future decline in the PWL and to provide adequate inlet head into the booster pump at all times, which ensures the booster pump will not cavitate from inadequate inlet pressure or NPSHA.

Well lift (PWL) and riser pipe friction loss: 97 feet (90 feet + 7 feet riser pipe hf= 97 feet APWL) + 20 psi of booster pump inlet head: 46 feet = required minimum well pump head: 143 feet (55% of the total of 260 feet).

The alternate submersible well pump we have now selected is a 9-inch-diameter × five-stage bowl assembly (81.5% efficient) with a 25 HP motor, instead of the 50 HP sub motor originally selected. The revised design condition for this pump is now 500 GPM at 152 feet TDH, 9 feet more than required. The well pump curve is shown in Figure 2.

Originally required total system head (TDH): 260 feet (at 500 GPM) – less head from well pump: 152 feet (57.4% of 265 feet) = 108 feet + added inlet head for booster losses: 5 feet = required (net) booster pump head: 113 feet (42.6% of 265 feet).

The booster pump required COS of 500 GPM at 113 feet TDH can easily be met from an end-suction centrifugal pump as the required head may be too low for many multistage VTP or submersible units. The booster pump curve (Figure 3) indicates the booster pump will deliver 500 GPM at 116 feet TDH, 3 feet more than required (the booster pump impeller can be trimmed to fit precise conditions).

Unless otherwise determined, I routinely recommend adding 5 feet of head to the booster pump head requirement to account for the energy losses associated with the pump and manifold assembly.

In our example, an 18.60 BHP demand is calculated for the booster pump; therefore, a 20 HP motor is needed. The combined brake horsepower from both pumps is now: 23.55 HP (well pump) + 18.60 HP (booster pump) = 42.15 BHP, only 1.54% higher in BHP than the original single 50 HP submersible pump BHP of 41.50, indicative of an efficient pumping tandem.

Although the alternate condition of 156 GPM for the well pump is slightly less than the original design head of 240 feet (230 feet actual TDH or about 4 psi less pressure), after consultation with the client this small difference in delivery pressure is not felt to be important.

Incorporate a check valve bypass for primary pump operation.While this may seem a no-brainer, I have witnessed numerous examples where a system was designed with the primary or “source” pump always pushing water through and out the booster pump, even when the booster pump is disabled. In addition to the extreme and unnecessary head loss associated with routing the flow through the booster pump, this type of operation generally results in a slower speed rotation of the pump and motor.

This lower rotational speed of the booster pump and motor does not usually generate sufficient lubrication of the motor bearings. This will be outlined in our next column.

Be aware of possible system or booster pump overpressurization.This is one of the most critical considerations for a high-pressure (less than 150 psig) series pumping installation since the residual pressure or head developed from the source pump is added to the pressure (head) from the booster pump at a common flow rate to generate much higher finished pressure.

This is particularly true on irrigation applications using hard hose reels with big guns or other high-pressure systems. In extreme cases, particularly if the booster flow rate is throttled or reduced, the combined pressure can reach enough of a dangerous level to result in pipe or pump case rupture.

This type of risk is most apparent in high head applications using an end-suction centrifugal pump with a cast iron or plastic volute or the upper stages of a multistage vertical turbine or submersible pump used as the booster pump, especially when an inline booster pump or pressure-reducing valve is used for on/offline flow transition or pressure control.

As an illustration and using our well example: If the flow rate was totally shut down with both source and booster pumps running, the residual wellhead pressure could reach 255 feet (from well pump) + 145 feet (added from booster pump) = 400 feet TDH – 50 feet minimum SWL = 350 feet (152 psi).

While this pressure may not be immediately injurious to the pumping units or manifold, it could conceivably be higher than the pressure rating of the booster pump case or a lower pressure rated PVC pipeline, potentially resulting in bursting either of them.

The designer must always be aware of this potential, and if necessary, specify a ductile iron or steel volute or bowl assembly whenever the discharge pressure can exceed the maximum working pressure of the well or booster pump. This factor should be examined on every series pump design with effective measures—such as a high-pressure cutout switch or pressure relief valve incorporated into the design if needed to avoid serious equipment damage or personal injury.

Verify that the source pump is not overpumping.When applying a booster pump to an existing well installation, the well pump and, by association, the well may be asked to pump at a lower pressure and thus a higher flow rate than formerly the case. The designer should verify the well will not be operating above the safe capacity of the well and the well pump will not surge or overload at higher flows.

Use a low-pressure cutout and electrical interlock to operate and protect the booster pump.Incorporating a low-pressure cutoff switch is an effective and simple way of protecting the booster pump from dry running conditions. Although an inline flowmeter can be used for the same purpose, a pressure switch with a time delay is a much cheaper and more reliable alternative, plus it provides a method of automatically starting and stopping the booster pump, particularly for irrigation systems.

With systems in which the supply water is provided from a separate pressurized water source, a low-pressure cutoff switch is also an effective method of protecting the booster pump and supply from operating during extreme low-pressure conditions occurring with the source or from potentially developing negative pressures within a pressurized water system, such as booster pumps used in cities and water districts.

Using a minimum booster pump inlet operating pressure of 20 psig ensures adequate inlet pressure is always available to the booster pump and is not starved, nor is the water system functioning at potentially low or even negative pressures, which can introduce dangerous contaminants into the system.

In two-pump systems, using an electrical interlock between the booster pump control with the source pump control is also recommended to ensure the booster pump can run only when the source pump is operating.

Do not forget the well lift and head for well pumps.Once again, this is an important design factor when applying a booster pump to an existing well and pump. It is critical that adequate head developed by the well pump be reserved to lift the water from the well, plus deliver the needed flow rate into the booster pump.

This type of error can occur if the well has been pumping for years at one flow rate and associated water level and is asked (or assumed) to be able to operate at a higher flow rate without determining or verifying the revised pumping water level. If feasible, I recommend adding no less than 20 psi (46 feet) (10 psi, minimum) of head to the maximum pumping lift (in feet) as the minimum well pump design head.

Use extra precautions with well pumps.Although the procedure shown here for using an end-suction centrifugal pump as a booster pump can also apply to either a vertical turbine or submersible pump, when adding a pressurized pump or piping directly into the suction port of a vertical turbine pump, there are a few additional precautions to be observed.

The primary consideration relates to the axial thrust (downthrust) developed by the pump and resisted by the motor during high head service. In many cases the relatively low values of allowable downthrust in smaller vertical or submersible pump motors may not be adequate to resist the higher thrust developed from the pressure values associated with high-pressure booster (series) pumping.

In order to avoid these potential situations, I suggest the maximum downthrust rating for a motor intended for booster (series) service be initially checked and verified against the actual downthrust for adequacy, particularly if the design calls for prolonged operation at service conditions approaching the shutoff head of the booster pump or a 4- or 6-inch-diameter submersible motor is used as the booster pump driver. If needed, using a 175%-rated thrust bearing may be required for a VTP motor or a larger HP or diameter motor for a submersible application.

Conversely, in other extreme cases, modifying an existing VTP or submersible pump installation to generate a higher flow into a booster pump can lower the well pump’s discharge pressure enough to result in a potential upthrust condition to occur to the well pump or motor. This situation is much more common and sensitive for a shallow set (20 feet to 50 feet), high capacity mixed flow well pump. However, it can potentially occur to any well pump, particularly during startup, so designers are cautioned to verify this possible anomaly and correct by applying higher pressures against the well pump, especially during a pipeline fill or system startup.

Next, when using a submersible pump and motor for an inline booster pump application, it is just as important to generate an adequate velocity past the motor as it is for a well installation. Designers must verify the intended pump design either routes the inlet water into the bottom and past the motor or incorporates a motor-surrounding shroud with a sufficient annular velocity (less than or equal to .50 fps) to maintain adequate motor cooling.

Finally, in other cases, modifying a well pump to a higher flow rate for booster service can negatively impact the NPSHR (requirement) of the pump, especially for applications using a tailpipe with a suction lift upwards to the bowl assembly. In these examples, the designer must verify the well pump will not cavitate or lose prime during higher capacity demands.

In other cases using a high-speed submersible pump as the booster pump, the inlet head or submergence over the pump’s inlet may not be sufficient to avoid cavitation. This can generally be determined through an examination of the bowl’s NPSH and submergence requirements. The actual procedure and methods for using well pumps as canned booster pumps will be outlined in our next column.

Be cautious when using mismatched pumping units.Although most pumps with dissimilar H-Q curves will eventually find a common ground of flow to function, there are conditions in which a series pumping installation will not be effective using pumps with dissimilar curves. Certainly, the easiest way to avoid this is by using units in which the shape of both H-Q curves match or are similar throughout the range of flow.

However, units in which either pump is asked to produce more than 75%-80% of the total head may not be as efficient as simply using a single larger unit to perform the entire service. In some applications where the rated capacity of the booster pump is much higher than the source pump, errant operating conditions can occur, particularly during startup or line fill.

Surging conditions or a short duration loss of flow between the pumping units can occur where the booster pump can actually develop a severe loss of inlet head, creating a suction lift upon the source pump—causing a sudden but momentary loss of flow from the source into the booster pump, often resulting in air entrainment or vapor lock in the booster pump or piping manifold. This is usually rapidly supplanted by an immediate resumption of pumping.

In water well conditions, this can lead to hydraulic surging resulting in an undulating thrust condition upon the well pump and motor, possibly leading to premature failure. This situation can generally be avoided by making sure both pumps in a series configuration are designed for the same rough capacity range and that adequate discharge head is developed by the well pump under all flow conditions to avoid damaging upthrust.

To be certain, these potential conditions are rare in actual practice. However, designers are nonetheless cautioned to recognize the potential, and when present, ensure the booster pump design condition and flow range closely matches the flow rate range of the source system or pump or to incorporate an automatic control valve to maintain a minimal value of discharge pressure from the booster pump under all flow conditions.

This concludes this month’s edition of The Water Works. The upcoming July and October editions will apply many of these same concepts into the actual design and layout of a booster pump application or station for open or closed applications.

Your water pump is primed and the liquid is flowing… kind of. One of the more common problems with water pumps is a reduced or lower than expected water flow. When you need to dewater the jobsite, low flow means more downtime for the crew, costing money and putting deadlines at risk. Often, low water flow is less about your water pump and more to do with the situation. Below are a few things to review to troubleshoot water pump problems involving low water flow.

The greater the distance a pump has to pull the water, the lower the flow rate will be. Get too far from the water source and the more power is dedicated to ‘sucking’ the water and less to discharging, reducing the flow rate.

Typically, pumps should be with 20 feet of the water source. Depending on the typography, how high the pump is relative to the water, the flow may be reduced at even shorter distances. Your pump has individual specification, so be sure you read the spec and operate within them.

Your pump is designed to operate with a certain diameter input line. In some cases, we have seen people attach a smaller than recommended hose or line (using a reduction couplings). Depending on the intake line you use, it is also possible that the line crimps, or is “sucked in” on itself.

Debri blockage is a common problem. With murky water it can be hard to see the intake hose. But, operators should check to be sure there is no debris blocking the intake. The blockage usually happens at the filter as it does it’s job to prevent damage to the water pump. Remove the debri and reposition the hose to start pumping again.

The intake filter or screen can also be the culprit even without debri . While you must ensure the filter is fine enough to prevent damaging solids from entering the pump, too fine a filter for the water pump will restrict the flow right as the water enters the intake. Be sure the filter is proper for the pump.

Centrifugal water pumps are designed to operate with the impeller going in one direction. If it is going the opposite direction, the pump will not operate properly. This can happen if the electrical connections to the electric motor is not established correctly. Review the electric motors setup and user instructions to ensure your connections are correct.

Whether you are dewatering a jobsite, irrigating a field or applying your water pump for any other purpose, low flow is an issue. In some cases, like a firefighting pump, it can be a matter of life-or-death. One way to minimize onsite issue it to check all your equipment on a regular basis, replacing worn parts and performing maintenance as needed. But when confronted with low flow rates, follow the above steps and you’ll be able to get your water pump back in action, and your crew back to work.

Wells are generally drilled into the ground to recover natural deposits of hydrocarbons and other desirable materials trapped in geological formations in the Earth"s crust. A well is typically drilled using a drill bit attached to the lower end of a drill string. The well is drilled so that it penetrates the subsurface formations containing the trapped materials and the materials can be recovered.

At the bottom end of the drill string is a “bottom hole assembly” (“BHA”). The BHA includes the drill bit along with sensors, control mechanisms, and the required circuitry. A typical BHA includes sensors that measure various properties of the formation and of the fluid that is contained in the formation. A BHA may also include sensors that measure the BHA"s orientation and position.

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.

Likewise, an “uplink” is a communication from the BHA to the surface. An uplink is typically a transmission of the data collected by the sensors in the BHA. For example, it is often important for an operator to know the BHA orientation. Thus, the orientation data collected by sensors in the BHA is often transmitted to the surface. Uplink communications are also used to confirm that a downlink command was correctly understood.

One common method of communication is called “mud pulse telemetry.” Mud pulse telemetry is a method of sending signals, either downlinks or uplinks, 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.

FIG. 1A 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 112. The mud leaves the drill string 110 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 116. 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 FIG. 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 FIG. 1A), the BHA (112 in FIG. 1A), and returning through the annulus (116 in FIG. 1A), 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 bypass system 120 includes a choke valve 124. During normal operations, the choke valve 124 may be closed to prevent any flow 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 controller for a pump for pumping a drilling fluid from a storage unit to a downhole tool includes at least one actuation device coupled to a control console of the pump, and at least one connector coupled to the at least one actuation device and a pump control mechanism of the control console.

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. The invention will be described with reference to the attached figures.

The following terms have a specialized meaning in this disclosure. While many are consistent with the meanings that would be attributed to them by a person having ordinary skill in the art, the meanings are also specified here.

In this disclosure, “fluid communication” is intended to mean connected in such a way that a fluid in one of the components may travel to the other. For example, a bypass line may be in fluid communication with a standpipe by connecting the bypass line directly to the standpipe. “Fluid communication” may also include situations where there is another component disposed between the components that are in fluid communication. For example, a valve, a hose, or some other piece of equipment used in the production of oil and gas may be disposed between the standpipe and the bypass line. The standpipe and the bypass line may still be in fluid communication so long as fluid may pass from one, through the interposing component or components, to the other.

“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.

In this disclosure, “selectively” is intended to indicate at a time that is selected by a person or by a control circuitry based on some criteria. For example, a drilling operator may select the time when a downlink signal is transmitted. In automated operations, a computer or control circuitry may select when to transmit a downlink signal based on inputs to the system.

FIG. 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 FIG. 3A.

The downlink system in FIG. 2 includes a shutoff valve 204. The shutoff valve 204 is .0.0 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 FIG. 1B) 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.

Flow diverters and flow restrictors are components that are well known in the art. They are shown diagrammatically in several of the Figures, including FIG. 2. Those having skill in the art will be familiar with these components and how they operate. The following describes their specific operation in those embodiments of the invention that include either a flow restrictor or a flow diverter.

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.

It is noted that in the cases where the downlink sensors on the BHA are pressure transducers, it may be desirable to use a downlink system without a flow restrictor upstream of the modulator. Thus, some embodiments of a downlink system in accordance with the invention do not include a flow restrictor 205. Those having ordinary skill in the art will be able to devise a downlink system with selected components to fit the particular application.

In some embodiments, a downlink system in accordance with the invention includes a flow diverter 206 that is located upstream from the modulator 210. A flow diverter 206 may be used to reduce the amount of turbulence in the bypass line 202. The flow diverter 206 is shown as a double branch flow diverter, but other types of flow diverters may be used. For example, a flow diverter with several bends may also be used. Those having ordinary skill in the art will be able to devise other flow diverters without departing from the scope of the invention.

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.

In some embodiments, the flow diverter 206 is coated with an erosion resistant coating. For example, a material such as carbide or a diamond coating could prevent the erosion of the inside of the flow diverter 206. In at least one embodiment, the flow diverter 206 includes carbide inserts that can be easily replaced. In this regard, the insert may be thought of as a sacrificial element designed to wear out and be replaced.

In some embodiments, a downlink system 200 in accordance with the invention includes a second flow restrictor 215 that is disposed downstream of 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.

Those having skill in the art will realize that the above described components may be arranged in a downlink system in any order that may be advantageous for the particular application. For example, the embodiment shown in FIG. 2 may be modified by adding a second flow diverter downstream of the second flow restrictor 215. Those having ordinary skill in the art will be able to devise other component arrangements that do not depart from the scope of the invention.

FIG. 3A shows an exploded view of a modulator 301 in accordance with the invention. The modulator 301 is positioned inside a pipe section 308, such as a bypass line or a standpipe. As shown in FIG. 3A, the modulator 301 includes a rotor 302 and a stator 304 (or restrictor). Preferably, the rotor includes three passages 311, 312, 313 that allow fluid to pass through the rotor 302. The stator includes similar passages 321, 322, 323.

The view in FIG. 3A is exploded. Typically, the rotor 302 and the stator 304 would be connected so that there is no gap or a small gap between them. A typical modulator may also include a motor (not shown in FIG. 3A) to rotate the rotor 302.

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.

In some embodiments, such as the one shown in FIG. 3A, the rotor 302 includes a central passage 331 that enables fluid to pass through the rotor 302. The stator 304 has a similar central passage 332. The central passages 331, 332 enable at least some flow to pass through the modulator so that the flow through the modulator 301 is never completely stopped.

In some embodiments, the passages 311, 312, 313 in the rotor 302 are sized so that they never completely block the passages 321, 322, 323 in the stator 304. Those having skill in the art will be able to devise other embodiments of a rotor and a stator that do not depart from the scope of the invention.

FIG. 3B shows an exploded view of another embodiment of a modulator 351 in accordance with the invention. The modulator 351 includes two sections 361 and 371 that may be arranged to modulate the flow. For example, in one embodiment, section 371 comprises an inner segment that fits into the outer section 361. The modulator may then be installed in a pipe (not shown).

Flow through the pipe may be modulated by rotating one of the sections with respect to the other. For example, the inner section 371 may be rotated with respect to the outer section 361. As the windows 373 in the inner section align with the windows 363 in the outer section 361, the flow though the modulator 351 is maximized. When the windows 373 in the inner section 371 are not aligned with the windows 363 in the outer section 361, the flow through the modulator is minimized.

The modulator 351 may be arranged in different configurations. For example, the modulator 351 may be arranged parallel to the flow in a pipe. In such a configuration, the modulator 351 may be able to completely block flow through the pipe when the windows 363, 373 are not aligned. In some embodiments, the modulator is arranged so that fluid may pass the modulator in the annulus between the modulator 351 and the pipe (not shown). In those embodiments, the flow through the center of the modulator may be modulated by rotating one of the sections 361, 371 with respect to the other. In other embodiments, the modulator may be arranged to completely block the flow through the pipe when the windows 363, 373 are not aligned.

In some other embodiments, the modulator may be arranged perpendicular to the flow in a pipe (not shown). In such an embodiment, the modulator may act as a valve that modulates the flow rate through the pipe. Those having skill in the art will be able to devise other embodiments and arrangements for a modulator without departing from the scope of the invention.

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 harmonies 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 thirty minutes required in some prior art systems.

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.

FIG. 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 FIG. 4A regulates the pressure in the standpipe 408.

In the embodiment shown in FIG. 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 FIG. 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 FIG. 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 some embodiments, although not illustrated in FIG. 4A, a downlink system includes a flow restrictor downstream of the modulator 410. In many circumstances, the drilling system provides enough resistance that a flow restrictor is not required. When it is beneficial, however, one may be included to provide back pressure for proper operation of the modulator 410.

In another embodiment, shown in FIG. 4B, a downlink system 450 may be disposed in the mud return line 418. The embodiment shown in FIG. 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 FIG. 4A. In this case, however, the downlink system 450 is located in the return line 418 instead of the standpipe (408 in FIG. 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 line generates 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 FIG. 5A. An operator"s control console 502 typically includes pump control mechanisms. As shown in FIG. 5A the pump control mechanisms may comprise knobs 504, 505, 506 that control the speed of the mud pumps (not shown). FIG. 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.

In one embodiment of the invention, the control console 502 includes actuation devices 511, 513, 515 that are coupled the control knobs 504, 505, 506. The actuation devices 511, 513, 515 are coupled to the control knobs 504, 505, 506 by belts 512, 514, 516. For example, actuation device 511 is coupled to control knob 504 by a belt 512 that wraps around the stem of the control knob 504. The other actuation devices 511, 513 may be similarly coupled to control knobs 504, 505.

The actuation devices may operate in a number of different ways. For example, each actuation device may be individually set to operate a control knob to a desired frequency and amplitude. In some embodiments, the actuation devices 511, 513, 515 are coupled to a computer or other electronic control system that controls the operation of the actuation devices 511, 513, 515.

In some embodiments, the actuation devices 511, 513, 515 are integral to the control console 502. In some other embodiments, the actuation devices 511, 513, 515 may be attached to the control console 502 to operate the control knobs 504, 505, 506. For example, the actuation devices 511, 513, 515 may be magnetically coupled to the console 502. Other methods of coupling an actuation device to a console include screws and a latch mechanism. Those having skill in the art will be able to devise other methods for attaching an actuation device to a console that do not depart from the scope of the invention.

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, FIG. 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 SB, 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 FIG. 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.

FIG. 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.

FIG. 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, FIG. 6 diagrammatically shows a pump inefficiency controller 601 attached to a mud pump 602a. FIG. 6 shows three mud pumps 602a, 602b, 602c. Drilling rigs can include more or fewer than three mud pumps. Three are shown in FIG. 6A for illustrative purposes.

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

FIG. 6B diagrammatically shows the internal pumping elements of the first mud pump 602a. The pumping elements of pump 602ainclude 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 FIG. 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 FIG. 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, 602cin the embodiment shown in FIG. 6A, for example) is reduced by about 11%.

By operating the pump inefficiency controller (604 in FIG. 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 an 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.

FIG. 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, 702care connected to the mud tank 704. Mud from the tank is pumped into the mud manifold 707 and then into the standpipe 708.

As is known in the art, pumps have an “intake” where fluid enters the pumps. Pumps also have a “discharge,” where fluid is pumped out of the pump. In FIG. 7A, the intake end of each of the mud pumps 702a, 702b, 702cis connected to the mud storage tank 704, and the discharge end of each of the mud pumps 702a, 702b, 702cis 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 FIG. 7A is a reciprocating piston pump that has intake and exhaust strokes like that described above with respect to FIG. 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 71 1 differs from that of the other pumps 702a, 702b, 702cin 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