mud pump pressure calculation manufacturer

Rig pump output, normally in volume per stroke, of mud pumps on the rig is  one of important figures that we really need to know because we will use pump out put figures to calculate many parameters such as bottom up strokes,  wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump out put for triplex pump and duplex pump in bothOilfield and Metric Unit.

The purpose of this article is to present some guidelines and simplified techniques to size pumps and piping typically used in mud systems. If unusual circumstances exist such as unusually long or complicated pipe runs or if very heavy or viscous drilling muds are used, a qualified engineer should analyze the system in detail and calculate an exact solution.

To write about pumps, one must use words that are known and well understood. For example, the label on the lefthand side of any centrifugal pump curve is Total Head Feet. What does this mean?

Total Head remains constant for a particular pump operated at a constant speed regardless of the fluid being pumped. However, a pump’s pressure will increase as the fluid density (mud weight) increases according to the following relationship:

Note that the pump pressure almost doubled. It follows that the required pump horsepower has increased by the same percentage. If the pump required 50 HP for water service, it will require the following horsepower for 16 lb/gal mud:

To summarize, a pump’s Total Head remains constant for any fluid pumped, only the pump pressure and pump horsepower will change. Therefore, a pump motor must be sized according to the heaviest weight mud to be pumped.

In our example problem, the required desilter pressure head is 75 ft. for any mud weight. However, the pressure would be 30.3 PSIG for water or 43.6 PSIG for 12 lb mud or 58.1 PSIG for 16 lb mud. A good rule of thumb is that the required pressure (PSIG) equals 4 times the mud weight (12 LB/GAL x 4 = 48 PSIG).

Determine the required pressure head and flow rate. If the pump is to supply a device such as a mud mixing hopper or a desilter, consult the manufacturer’s information or sales representative to determine the optimum flow rate and pressure head required at the device. (On devices like desilters the pressure head losses downstream of the device are considered negligible and are usually disregarded.)

Select the basic pump to pump the desired flow rate. Its best to refer to a manufacturer’s pump curve for your particular pump. (See example – Figure 3).

The pump’s impeller may be machined to a smaller diameter to reduce its pressure for a given application. Refer to the manufacturer’s pump curves or manufacturer’s representative to determine the proper impeller diameter. Excessive pressure and flow should be avoided for the following reasons:

The pump must produce more than 75 FT-HD at the pump if 75 FT-HD is to be available at the desilter inlet and the pump’s capacity must be at least 800 GPM. Therefore, we should consider using one of the following pumps from the above list: 4″ x 5″ Pump 1750 RPM – 1000 GPM at 160 FT-HD; or 5″ x 6″ Pump 1750 RPM – 1200 GPM at 160 FT-HD.

The pump suction and discharge piping is generally the same diameter as the pump flange diameters. The resulting fluid velocities will then be within the recommended ranges of 4 to 10 FT/SEC for suction lines and 4 to 12 FT/

SEC for discharge lines. Circumstances may dictate that other pipe diameters be used, but remember to try to stay within the above velocity guidelines. Smaller pump discharge piping will create larger pressure drops in the piping

and the pump may not be able to pump the required amount of fluid. (For example, don’t use a 4″ discharge pipe on a 6″ x 8″ pump and expect the pump’s full fluid flow.)

6″ pipe may be used for the suction pipe since it is relatively short and straight and the pump suction is always flooded. 6″ pipe is fully acceptable for the discharge pipe and is a good choice since the desired header is probably 6″ pipe.

8″ pipe may be used for the suction pipe (V = 5.13 FT/SEC) since V is still greater than 4 FT/SEC. 8″ pipe would be preferred if the suction is long or the suction pit fluid level is low with respect to the pump.

The pressure provided by the rig pump is the sum of all of the individual pressures in the circulating systems. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with:

Pressure losses in the annulus acts as a "back pressure" on the exposed formations, consequently the total pressure at the bottom of the annulus is higher with the pump on than with the pump off.

Assuming a circulating pump pressure is 3000 psi when pumping at 100 spm. The pump speed is increased to 120 spm. To approximate the new circulating pump pressure:

Assuming a circulating pump pressure in 3000 psi with a 10 ppg mud weight pumping at 100 spm. If the mud weight in the system was changed to 12 ppg. To approximate the new circulating pump pressure:

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.

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.

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.

Density of the Kick, ppg = initial mud weight, ppg – (initial stabilized drillpipe pressure, psi – initial stabilized casing pressure, psi)/(0.052 x Length of the kick, ft)

Riser margin is = (drilling fluid gradient to control the formation pressure with riser, psi/ft x depth of the hole (TVD), ft – seawater gradient, psi/ft

Continental Emsco Drilling Products, Inc., which consisted of Emsco drilling machinery and Wilson mobile rigs, was purchased by National-Oilwell, Inc on July 7, 1999. To our knowledge, no pumps have been manufactured and sold under the Emsco brand name since National-Oilwell acquired them.

Fairbanks Morse pumps are currently manufactured in Kansas City, Kansas. Fairbanks Morse is a division of Pentair ever since August, 1997 when Pentair purchased the General Signal Pump Group.

Gaso pumps are manufactured by National Oilwell Varco. Gaso was acquired as "Wheatley Gaso" by National-Oilwell in the year 2000. At the time, Wheatley Gaso was owned by Halliburton.

Skytop Brewster pumps are no longer available as new pumps. Skytop Brewster(Cnsld Gold), a unit of Hansen PLC"s Consolidated Gold Fields subsidiary, was acquired while in bankruptcy by National-Oilwell, Inc. in November, 1999.

Mud pump liner selection in today"s drilling operations seldom (at best) considers electrical implications. Perhaps, with more available useful information about the relationships between mud pump liner size and operational effects on the electrical system, certain potential problems can be avoided. The intent of this paper is to develop those relationships and show how they affect an electrical system on example SCR rigs.Introduction

There, seems to be little consideration for the relationships between liner size and demand on a rig"s engine/generator set(s). Yet, consideration for this relationship can prove to be very helpful to drillers and operators in efficiency of a rig"s electrical system. In order to develop the relationships and help drillers and operators understand the importance of each, relationships between liner size, pump speed, pump pressure, and electrical power will be developed. Only basic physical laws will be used to develop the relationships; and, once developed, the relationships are readily applied to realistic examples utilizing a mud pump manufacturer"s pump data. Finally, conclusions will be drawn from the examples.DEVELOPMENT OF RELATIONSHIPS BASIC RELATIONSHIPS

where HHP= Hydraulic horsepower, GPM = Mud pump volumetric flow rate in gallons per minute, and PST Mud pump output pressure in pounds peer square inch.

Hydraulic horsepower is reflected to the mud pump motor via a multiplier for mechanical efficiency. it follows that motor horsepower is then represented by

Drilling in the North Sea is confronted with an ever more challenging pressure management issue due to narrow geo-pressure windows in depleted reservoirs. Further, the occurrence of pack-offs can cause serious damage to the formation and contribute to non-productive time. To address these problems, automation of mud pump management has been developed over the last four years to minimize the chance of fracturing the formation while starting the mud pumps or circulating. To account for abnormal flow restrictions in the annulus, automatic actions are also an integral part of the mud pump automation described in this paper.

Since the downhole conditions are continuously changing (depth, temperature, flow-rate, gel time, cuttings proportion, etc), the necessary safe guards to operate the mud pumps need to be updated constantly. Advanced transient temperature and hydraulic models are used to estimate, in real-time, the downhole situation. Based on the current context, evaluation of maximum pump rates and acceptable flow accelerations are performed and sent to the mud pump control system to be used as an envelope of protection. Furthermore, to assist the Driller during connections, the pump start-up procedure has been semi-automated in order to decrease connection time. Finally, an automatically triggered pump shutdown procedure is also available to minimize the consequences of a pack-off on formation fracturing.

A first version of the system has been tested during the drilling of one well in 2008 in the North Sea. Based on the initial experience, a revised version has been used during the drilling of three wells drilled on the Norwegian Continental Shelf in 2009. The feedback from the Drillers involved in the testing has been used to improve the user friendliness of the system. The automation of the mud pump management has been well accepted by the drilling crews. However, the testing has shown that additional instrumentation at the rig site is necessary before such automation can be rolled out safely.

Formation fluid can enter the wellbore if the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation being drilled (pore pressure).

Failure to manage and control these pressure effects can cause serious equipment damage and injury, or loss of life. Improperly managed well control situations can cause blowouts, which are uncontrolled and explosive expulsions of formation hydrocarbons from the well, potentially resulting in a fire.

Pressure is a very important concept in the oil and gas industry. Pressure can be defined as: the force exerted per unit area. Its SI unit is newtons per square metre or pascals. Another unit, bar, is also widely used as a measure of pressure, with 1 bar equal to 100 kilopascals. Normally pressure is measured in the U.S. petroleum industry in units of pounds force per square inch of area, or psi. 1000  psi equals 6894.76 kilo-pascals.

Hydrostatic pressure (HSP), as stated, is defined as pressure due to a column of fluid that is not moving. That is, a column of fluid that is static, or at rest, exerts pressure due to local force of gravity on the column of the fluid.

All fluids in a wellbore exert hydrostatic pressure, which is a function of density and vertical height of the fluid column. In US oil field units, hydrostatic pressure can be expressed as:

HSP = 0.052 × MW × TVD", where MW (Mud Weight or density) is the drilling-fluid density in pounds per gallon (ppg), TVD is the true vertical depth in feet and HSP is the hydrostatic pressure in psi.

The pressure gradient is described as the pressure per unit length. Often in oil well control, pressure exerted by fluid is expressed in terms of its pressure gradient. The SI unit is pascals/metre. The hydrostatic pressure gradient can be written as:

Formation pressure is the pressure exerted by the formation fluids, which are the liquids and gases contained in the geologic formations encountered while drilling for oil or gas. It can also be said to be the pressure contained within the pores of the formation or reservoir being drilled. Formation pressure is a result of the hydrostatic pressure of the formation fluids, above the depth of interest, together with pressure trapped in the formation. Under formation pressure, there are 3 levels:

Normally pressured formation has a formation pressure that is the same with the hydrostatic pressure of the fluids above it. As the fluids above the formation are usually some form of water, this pressure can be defined as the pressure exerted by a column of water from the formation"s depth to sea level.

The normal hydrostatic pressure gradient for freshwater is 0.433 pounds per square inch per foot (psi/ft), or 9.792 kilopascals per meter (kPa/m), and 0.465 psi/ft for water with dissolved solids like in Gulf Coast waters, or 10.516 kPa/m. The density of formation water in saline or marine environments, such as along the Gulf Coast, is about 9.0 ppg or 1078.43 kg/m3. Since this is the highest for both Gulf Coast water and fresh water, a normally pressured formation can be controlled with a 9.0 ppg mud.

Sometimes the weight of the overburden, which refers to the rocks and fluids above the formation, will tend to compact the formation, resulting in pressure built-up within the formation if the fluids are trapped in place. The formation in this case will retain its normal pressure only if there is a communication with the surface. Otherwise, an abnormal formation pressure will result.

As discussed above, once the fluids are trapped within the formation and not allow to escape there is a pressure build-up leading to abnormally high formation pressures. This will generally require a mud weight of greater than 9.0 ppg to control. Excess pressure, called "overpressure" or "geopressure", can cause a well to blow out or become uncontrollable during drilling.

Subnormal formation pressure is a formation pressure that is less than the normal pressure for the given depth. It is common in formations that had undergone production of original hydrocarbon or formation fluid in them.

Overburden pressure is the pressure exerted by the weight of the rocks and contained fluids above the zone of interest. Overburden pressure varies in different regions and formations. It is the force that tends to compact a formation vertically. The density of these usual ranges of rocks is about 18 to 22 ppg (2,157 to 2,636 kg/m3). This range of densities will generate an overburden pressure gradient of about 1 psi/ft (22.7 kPa/m). Usually, the 1 psi/ft is not applicable for shallow marine sediments or massive salt. In offshore however, there is a lighter column of sea water, and the column of underwater rock does not go all the way to the surface. Therefore, a lower overburden pressure is usually generated at an offshore depth, than would be found at the same depth on land.

Fracture pressure can be defined as pressure required to cause a formation to fail or split. As the name implies, it is the pressure that causes the formation to fracture and the circulating fluid to be lost. Fracture pressure is usually expressed as a gradient, with the common units being psi/ft (kPa/m) or ppg (kg/m3).

Pump pressure, which is also referred to as system pressure loss, is the sum total of all the pressure losses from the oil well surface equipment, the drill pipe, the drill collar, the drill bit, and annular friction losses around the drill collar and drill pipe. It measures the system pressure loss at the start of the circulating system and measures the total friction pressure.

Slow pump pressure is the circulating pressure (pressure used to pump fluid through the whole active fluid system, including the borehole and all the surface tanks that constitute the primary system during drilling) at a reduced rate. SPP is very important during a well kill operation in which circulation (a process in which drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus, and back to the pits while drilling proceeds) is done at a reduced rate to allow better control of circulating pressures and to enable the mud properties (density and viscosity) to be kept at desired values. The slow pump pressure can also be referred to as "kill rate pressure" or "slow circulating pressure" or "kill speed pressure" and so on.

Shut-in drill pipe pressure (SIDPP), which is recorded when a well is shut in on a kick, is a measure of the difference between the pressure at the bottom of the hole and the hydrostatic pressure (HSP) in the drillpipe. During a well shut-in, the pressure of the wellbore stabilizes, and the formation pressure equals the pressure at the bottom of the hole. The drillpipe at this time should be full of known-density fluid. Therefore, the formation pressure can be easily calculated using the SIDPP. This means that the SIDPP gives a direct of formation pressure during a kick.

Bottom-hole pressure (BHP) is the pressure at the bottom of a well. The pressure is usually measured at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation:

In Canada the formula is depth in meters x density in kgs x the constant gravity factor (0.00981), which will give the hydrostatic pressure of the well bore or (hp) hp=bhp with pumps off.

There are some basic calculations that need to be carried during oil well control. A few of these essential calculations will be discussed below. Most of the units here are in US oil field units, but these units can be converted to their SI units equivalent by using this Conversion of units link.

Fluid level drop is the distance the mud level will drop when a dry string(a bit that is not plugged) is being pulled from the wellbore and it is given by:

Kick is the entry of formation fluid into the wellbore during drilling operations. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. The whole essence of oil well control is to prevent kick from occurring and if it happens to prevent it from developing into blowout. An uncontrolled kick usually results from not deploying the proper equipment, using poor practices, or a lack of training of the rig crews. Loss of oil well control may lead into blowout, which represents one of the most severe threats associated with the exploration of petroleum resources involving the risk of lives and environmental and economic consequences.

A kick will occur when the bottom hole pressure(BHP) of a well falls below the formation pressure and the formation fluid flows into the wellbore. There are usually causes for kicks some of which are:

Tripping out of the hole means that the entire volume of steel (of drillstring) is being removed, or has been removed, from the well. This displacement of the drill string (the steel) will leave out a volume of space that must be replaced with an equal volume of mud. If the replacement is not done, the fluid level in the wellbore will drop, resulting in a loss of hydrostatic pressure (HSP) and bottom hole pressure (BHP). If this bottom hole pressure reduction goes below the formation pressure, a kick will definitely occur.

Swabbing occurs when bottom hole pressure is reduced due to the effects of pulling the drill string upward in the bored hole. During the tripping out of the hole, the space formed by the drillpipe, drill collar, or tubing (which are being removed) must be replaced by something, usually mud. If the rate of tripping out is greater than the rate the mud is being pumped into the void space (created by the removal of the drill string), then swab will occur. If the reduction in bottom hole pressure caused by swabbing is below formation pressure, then a kick will occur.

Lost circulation usually occurs when the hydrostatic pressure fractures an open formation. When this occurs, there is loss in circulation, and the height of the fluid column decreases, leading to lower HSP in the wellbore. A kick can occur if steps are not taken to keep the hole full. Lost circulation can be caused by:

If the density of the drilling fluid or mud in the well bore is not sufficient to keep the formation pressure in check, then a kick can occur. Insufficient density of the drilling fluid can be as a result of the following :

Another cause of kicks is drilling accidentally into abnormally-pressured permeable zones. The increased formation pressure may be greater than the bottom hole pressure, resulting in a kick.

A sudden increase in penetration rate (drilling break) is usually caused by a change in the type of formation being drilled. However, it may also signal an increase in formation pore pressure, which may indicate a possible kick.

If the rate at which the pumps are running is held constant, then the flow from the annulus should be constant. If the annulus flow increases without a corresponding change in pumping rate, the additional flow is caused by formation fluid(s) feeding into the well bore or gas expansion. This will indicate an impending kick.

If there is an unexplained increase in the volume of surface mud in the pit (a large tank that holds drilling fluid on the rig), it could signify an impending kick. This is because as the formation fluid feeds into the wellbore, it causes more drilling fluid to flow from the annulus than is pumped down the drill string, thus the volume of fluid in the pit(s) increases.

A decrease in pump pressure or increase in pump speed can happen as a result of a decrease in hydrostatic pressure of the annulus as the formation fluids enters the wellbore. As the lighter formation fluid flows into the wellbore, the hydrostatic pressure exerted by the annular column of fluid decreases, and the drilling fluid in the drill pipe tends to U-tube into the annulus. When this occurs, the pump pressure will drop, and the pump speed will increase. The lower pump pressure and increase in pump speed symptoms can also be indicative of a hole in the drill string, commonly referred to as a washout. Until a confirmation can be made whether a washout or a well kick has occurred, a kick should be assumed.

wellbore greater than the pressure of the fluids in the formation being drilled, but less than formation fracture pressure. It uses the mud weight to provide sufficient pressure to prevent an influx of formation fluid into the wellbore. If hydrostatic pressure is less than formation pressure, then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation, then the fluid in the well could be lost into the formation. In an extreme case of lost circulation, the formation pressure may exceed hydrostatic pressure, allowing formation fluids to enter into the well.

Secondary oil well control is done after the Primary oil well control has failed to prevent formation fluids from entering the wellbore. This process uses "blow out preventer", a BOP, to prevent the escape of wellbore fluids from the well. As the rams and choke of the BOP remain closed, a pressure built up test is carried out and a kill mud weight calculated and pumped inside the well to kill the kick and circulate it out.

Source:shut-in on a kick, proper kill procedures must be done immediately. The general idea in well kill procedure is to circulate out any formation fluid already in the wellbore during kick, and then circulate a satisfactory weight of kill mud called Kill Weight Mud (KWM) into the well without allowing further fluid into the hole. If this can be done, then once the kill mud has been fully circulated around the well, it is possible to open up the well and restart normal operations. Generally, a kill weight mud (KWM) mix, which provides just hydrostatic balance for formation pressure, is circulated. This allows approximately constant bottom hole pressure, which is slightly greater than formation pressure to be maintained, as the kill circulation proceeds because of the additional small circulating friction pressure loss. After circulation, the well is opened up again.

Jerome Schubert, "Managed-Pressure Drilling: Kick Detection and Well Control" Section: "Kick Detection While Drilling", Society of Petroleum Engineers, Journal of Petroleum Technology (JPT), archived 2010/01/15.

Whether onshore or offshore, well drilling sites rely on a multitude of systems to successfully perform the drilling operation. The mud pump is a key component tasked with circulating drilling fluid under high pressure downhole. The mud pump can be divided into two key sections: the power end or crosshead and the fluid end. Proper alignment of the pump’s crosshead to the fluid end liner is necessary to maximizing piston and liner life. Misalignment contributes to

accelerated wear on both the piston and the liner, and replacing these components requires downtime of the pump. Traditional methods of inspecting alignment range from using uncalibrated wooden rods, Faro Arms and micrometers to check the vertical and horizontal alignment of the piston rod OD to the piston liner ID. These are time consuming and cumbersome techniques that are ultimately not well suited to troubleshoot and solve alignment issues.

A “Mud Pump Laser Alignment Kit” enables you to measure where the piston will run through the liner at various positions along the pump’s stroke. It will also project a laser centerline from the fluid end back towards the rear power end of the pump that can be used to determine how much shimming is required to correct any alignment issues. The kit can include either a 2-Axis receiver or a 4-Axis which accepts the laser beam and documents where it falls on the active surface of the receiver. The 4-Axis receiver can decrease alignment time by as much as 50% as it will measure angularity as well as X and Y while the 2-Axis does not and will need multiple measurement locations to get the same information. In addition, the alignment system is a non-intrusive service requiring the removal of only the piston rod which allows for much quicker service and less down time on the pump. As the mud pumps in question are located globally both on and offshore, having a small, portable system is another great advantage. Our recommendation would be Pinpoint laser System’s “Mud Pump Alignment Kit”. They are being used by many of the leading repair service companies and have been their main alignment tool for over 15 years. Manufacturers are also utilizing these for new pump set-up.