Mud Pump

When the mud pumps are shut off to make a connection, a computer starts a surface pump that circulates drilling fluid into the wellbore under the rotating control device.

From: Blowout and Well Control Handbook (Second Edition), 2017

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Equipment in Mud Circulating Systems

Boyun Guo Ph.D, Gefei Liu, in Applied Drilling Circulation Systems, 2011

1.2 Mud Pumps

Mud pumps serve as the heart of the mud circulating system. Reciprocating piston pumps (also called slush pumps or power pumps) are widely used for drilling oil and gas wells. The advantages of the reciprocating positive-displacement pump include the ability to move high-solids-content fluids laden with abrasives, the ability to pump large particles, ease of operation and maintenance, reliability, and the ability to operate over a wide range of pressures and flow rates by changing the diameters of the compression cylinders (pump liners) and pistons.

The two types of piston strokes are the single-action piston stroke and the double-action piston stroke. A pump that has double-action strokes in two cylinders is called a duplex pump (Figure 1.2). A pump that has single-action strokes in three cylinders is called a triplex pump (Figure 1.3). Triplex pumps are lighter and more compact than duplex pumps, their output pressure pulsations are not as great, and they are cheaper to operate. For these reasons, the majority of new pumps being placed into operation are of the triplex design. Normally, duplex pumps can handle higher flow rates, and triplex pumps can provide higher working pressure. However, for a given pump of fixed horsepower, the flow rate and working pressure can be adjusted by changing the sizes of the liners inside the pump. Some types of pump liners are shown in Figure 1.4. Changing the speed of the prime mover can also affect the mud flow rate in a certain range.

Figure 1.2. A duplex pump.

Courtesy of Great American.

Figure 1.3. A triplex pump.

Courtesy of TSC.

Figure 1.4. Pump liners.

Courtesy of TSC.
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Mud Pumps

Boyun Guo Ph.D, Gefei Liu, in Applied Drilling Circulation Systems, 2011

3.4 Horsepower Requirements

In rotary drilling, the engines that supply power are rated on output horsepower, sometimes called brake horsepower. Fluid pumps that receive power are rated on the basis of input horsepower. For this reason, a 1,600-hp pump classification means that the horsepower fed into the pump should not exceed 1,600. Output horsepower from pumps used in rotary drilling is determined from charts of maximum permissible surface pressure and maximum circulation rate.

Mud pumps are rated by horsepower PH and the maximum working pressure ppm. Figure 3.5 shows a theoretical pump performance curve. The mud hydraulic horsepower from the pump is expressed as (Moore, 1986)

Figure 3.5. A theoretical pump performance curve.

(3.8)Ph=qp1,714

where

Ph = hydraulic horsepower, hp

q = mud flow rate, gpm or m3/min

p = pump pressure, psi or kPa

The constant 1,714 in U.S. units is 44.14 in SI units.

For a given pump having a horsepower rating PH, the value of the right-hand side of Eq. (3.8) should not exceed PH; that is, Ph < PH. If a pump runs at the maximum working pressure ppm, the maximum available flow rate is expressed as

(3.9)qmax=1,714EpPHppm

where

qmax = maximum mud flow rate, gpm or m3/min

PH = Horsepower rating of pump, hp

Ep = pump efficiency, dimensionless

ppm = maximum working pressure of pump, psi or MPa

If a pump runs at a flow rate q < qmax, the maximum available pump pressure is expressed as

(3.10)pmax=1,714EpPHq

However, the pump pressure should always be kept lower than the maximum working pressure—that is, pmax < ppm.

Illustrative Example 3.3

For the data in Illustrative Examples 3.1 and 3.2, determine the required horsepower rating of the pump.

Solution

The pump should be able to provide adequate horsepower while drilling all hole sections. The extreme hole conditions occur when the surface hole and the total hole depth are drilled. Drilling the surface hole requires the highest mud flow, and drilling at the total depth requires the highest pump pressure.

Surface Hole Drilling. Illustrative Example 3.1 shows that the minimum required flow rate to drill the surface hole is 990 gpm (3.75 m3/min). The required pressure at the bottom of the hole section with 60 feet (18.3 m) of a 7-inch (178 mm) drill collar is calculated using the spreadsheet program Pump Pressure.xls. The result of the pressure loss is 364 psi (2,509 kPa). Considering a pressure drop at the bit of twice the pressure loss, the circulating pressure will be 1,092 psi (7,529 kPa). Substituting these data into Eq. (3.9) gives

Ph=(990)(1,092)1,714=631hp

Drilling at the Total Depth. Using the flow rate of 350 gpm (1.325 m3/min) and the required pressure of 3,461 psi (23,863 kPa) calculated with the spreadsheet program Pump Pressure.xls, Eq. (3.9) gives

Ph=(350)(3,641)1,714=743hp

Therefore, the minimum required horsepower rating of the pump is 743 hp.

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Routine well control methods

Gerald Raabe, Scott Jortner, in Universal Well Control, 2022

Drain back

Drain back occurs when the mud pumps are shut down from a normal operating rate. When the pumps are shut off, fluid in the circulating system gradually slow down and will come to a stop. This stoppage may take several minutes to observe. The operating pump rate will affect the rate and volume of the drain back. This rate and volume of drain back should be known by the driller. Drain back tests should be conducted prior to drilling out of casing to establish a baseline trend. Each connection should be compared to the baseline and previous connections to help distinguish normal drain back from a kick. There should not be a sudden increase in drain back rate after a single or stand has been drilled down.

When first establishing trends, caution should be taken to ensure the drain back is not a kick. Continuations of the established trend are clearly evidence of drain back. Deviations from the trend may or may not be indications of a kick; however, drain back is to be treated as a kick until proven otherwise. When monitoring the drain back, limit the volume of drain back in the event an actual kick has occurred. Tracking where the connections are in the wellbore by the mud logger will assist the Driller in mitigating the risk associated with expansion of any entrained gas as the connections nears the surface.

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Well Control Surface Equipment

Howard Crumpton, in Well Control for Completions and Interventions, 2018

4.12 Fluid Storage

During drilling and completion operations, a large volume of fluid needs to be held at the wellsite. On land rigs, most of the fluid is stored in partitioned rectangular steel tanks, with each compartment holding approximately 200 bbls. In addition to the bulk storage, several smaller tanks are used for specific purposes, for example the storage of a kill pill. At some land locations, large volume pits are made by forming earth into raised banks then lining the construction with impermeable sheeting (normally plastic). In recent years, earth pits have become less common, principally because of environmental concerns. Where they are used, it is usually for the storage of waste mud and cuttings prior to disposal.

On offshore drilling rigs and platforms, fluid is stored in several large tanks each holding as much as 1000 bbls. Although individual tanks are generally larger, the cumulative volume stored is often less than at a land location, since space is limited. Table 4.4 is representative of the pit capacity of a medium sized jack-up drilling rig (Fig. 4.30).

Table 4.4. Jack-up rig mud pit capacity

Pit number Working volume (bbl) Max volume (bbl)
Active 1 450 460
Active 2 490 500
Active 3 440 450
Reserve 1 540 550
Reserve 2 510 520
Reserve 3 575 580
Reserve 4 250 260
Pill pit 80 90
Slug pit 80 90
Water pit 180 190
Degasser 1 40 50
Degasser 2 40 50
Desilter 1 40 50
Desilter 2 40 50
Centrifuge 40 50

Figure 4.30. Mud pit layout on a jack-up rig—corresponding to Table 4.4.

Insufficient fluid storage can create logistical problems, especially when transitioning from the drilling to the completion phase of the well construction process. For some completion operations, for example open-hole gravel packing, a large volume of completion brine is required. Moreover, the entire fluid system needs to be thoroughly cleaned before the fluid can be stored. In practical terms, this normally means that when the drilling mud is displaced from the well and replaced by completion brine, it must be sent to a support vessel rather than returned to the pits. The need to transfer the drilling mud to a vessel rather than back to the pits has obvious implications for well control. It becomes more difficult to monitor fluid returns, and an influx can go unnoticed for longer. In some circumstances, the overbalanced drill fluids are replaced with underbalanced completion fluids, adding to the risk.

For both land and offshore fluid systems, the pits are normally categorized as “active” and “reserve.”

Active pits: During most operations that require fluid circulation, fluid from the active pit is returned to the active pit in a closed loop system. Consequently, if the active pit capacity is too large, it becomes more difficult to spot the pit gains or losses that are an early indication of a well control problem. The active pits should ideally be equipped with a pit volume totalizer (PVT) that accurately monitors the level (volume) in the pit. Modern PVT systems normally feature visible and audible alarms set to warn the rig crew if there are pit gains.

Reserve pits: Where possible, the reserve pits should be large enough to store all surface volumes required for the completion of the well. Ideally there should, as an absolute minimum, be enough excess to deal with losses equivalent to 1–1½ times the hole volume.

Trip tank: A trip tank is a low-volume (100 barrels or less), calibrated tank that can be isolated from the remainder of the surface fluid system. It is used to accurately monitor the amount of fluid going into or coming out of the well whilst pipe is being tripped. Properly configured, maintained, and monitored, small volume fluid gains or losses can be detected. Trip tanks are also used to monitor fluid level during static conditions, for example when logging operations are taking place. If pipe is being stripped into the well, a second, stripping tank is used to measure fluid transferred from the trip tank (Fig. 4.31).

Figure 4.31. The trip tank.

4.12.1 Fluid pumps

Most rigs have at least two mud pumps in case of breakdown. They must be able to pump the maximum anticipated weight of kill fluid at the rate required to kill the well. During completion and workover operations, a bullhead kill is common and normally requires a higher pump rate than a circulation kill (to overcome gas migration). Pumps need to be equipped with a functional stroke counter and the number of strokes per barrel recorded on any kill sheets. The maximum discharge pressure that can be obtained from mud pumps is typically 7500 psi, if higher pressure is required to initiate a well kill normally the cement unit would be used.

Cement pump: Most offshore drilling units and offshore platforms with drilling derricks have a cement pump as part of the permanent facilities. Most are diesel driven, and are therefore independent of the rig power supply. On land locations, a trailer-mounted cement unit is brought to the location as and when required. Cement pumps provide a back-up to the mud pumps, and typically operate at much higher discharge pressure (up to 15,000 psi), but at lower rates (6–8 bbls/min).

Positive displacement fluid pumps are described in more detail in Chapter 8, Pumping and Stimulation.

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Gaseated Fluids (Gas-Liquid Mixtures)

Bill Rehm, ... Arash Haghshenas, in Underbalanced Drilling: Limits and Extremes, 2012

3.10.2 Unloading the Casing

To unload a hole full of mud or water, pump the gaseated system until the pressure rises too high for the compressors. Then bypass the compressors and pump just liquid until the pump pressure goes down enough to restart the air. Repeat this procedure until the hole is completely gaseated, then establish a steady state flow before drilling ahead.

This technique pressures up the hole, so if the cement has already been drilled, consider using about three stages for going in the hole instead of going to the bottom and unloading all at once. Staging in is only important if the open formation might lose circulation or cave under repeated pressure surges.

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Sustainability in natural gas reservoir drilling: A review on environmentally and economically friendly fluids and optimal waste management

Majid Tabatabaei, ... David A. Wood, in Sustainable Natural Gas Reservoir and Production Engineering, 2022

3.3.8 Noise pollution

Noise from engines, generators, mud pumps, and shale shakers as well as pump trucks and other transportation vehicles are some of the sources of noise pollution that can cause hearing loss in gas and oil workers and degrade quality of life for people living near drill sites. By exceeding the maximum permissible noise level for residential zones, about 55 dBA (A-weighted decibels), drilling activities create noise levels that can raise the risk of harmful effects on human health, including sleep disruption, cardiovascular disease and other diseases that are adversely affected by stress [87,88].

Also, unwelcome sonic disturbances caused by offshore operations can negatively affect the life of aquatic animals and marine organisms. For example, the echolocation sense of dolphins and other marine mammals, which allows them to hunt, navigate, and communicate, can be disturbed causing them to become disoriented. Thus, their lives are compromised by excessive exposure to disruptive sound waves [89].

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Appendix

Mark S. Ramsey P. E., in Practical Wellbore Hydraulics and Hole Cleaning, 2019

9.9.1.2 Derivation of the optimum jet impact force for the power limited condition (API’s Region 3)

On a drilling rig, the mud pumps are powered by motors with a finite amount of power. Each conversion of energy will entail some loss of efficiency, dealt with in the chapter on pumps. For our purposes, we will confine the discussion to hydraulic horsepower actually output by the pumps at the surface.

This hydraulic horsepower is the product of the surface (or standpipe) pressure and the flow rate.

(9.62)HHP=PSURF×Q1714

where HHP is the hydraulic horsepower (hp); PSURF is the surface (or standpipe) pressure (psi); and Q is the flow rate (GPM).

For the hydraulic case, where the limit condition is the available hydraulic power on the drilling rig, the limit condition could be expressed as

(9.63)HHP=PSURF×Q=K

Since the standpipe (or surface) pressure consists of the sum of two components, PSURF can be written as

(9.64)PSURF=ΔPCIRC+ΔPBIT

This can also be written

(9.65)HHPQ=ΔPCIRC+ΔPBIT

Solving this equation for ΔPBIT and expressing ΔPCIRC in terms of Q and u:

(9.66)ΔPBIT=HHPQKQu

The expression derived which related the hydraulic impact (force) to the pressure drop through the bit nozzles was

(9.67)JIF=K×Q×(ΔPBIT)0.5

This force may now be calculated in terms of flow rate from the calculation for the pressure drop through the bit nozzles:

(9.68)JIF=K×Q×(HHPQKQu)0.5

or rearranging terms:

(9.69)JIF=K×(Q×HHPK×Qu+2)0.5

This is the expression for the force of the fluid striking the bottom of the hole. To find the maximum value, differentiate with respect to flow rate and set the differential equal to zero.

(9.70)JIFQ=K×(HHPK×(u+2)×Qu+1)(Q×HHPK×Qu+2)0.5=0

For this to be true, the numerator must be equal to zero or

(9.71)K×(HHPK×(u+2)×Qu+1)=0

or

(9.72)K×HHP=K2×(u+2)×Qu+1=0

reducing

(9.73)HHP=K×(u+2)×QOPTu+1=0

Since HHP is the product of the standpipe pressure and the flow rate, this could be written as

(9.74)PSURF OPT×QOPT=K×(u+2)×QOPTu+1=0

Solving for the optimum surface (or standpipe) pressure, results in:

(9.75)PSURF OPT=K×(u+2)×QOPTu

Recall that the pressure loss through the circulating system was

(9.76)PCIRC=K×Qu

Substituting, the optimum surface (or standpipe) pressure would therefore be

(9.77)PSURF OPT=(u+2)×PCIRC OPT

The optimum pressure drop through the bit nozzles would be the difference between the optimum surface pressure and the optimum circulating pressure, or

(9.78)ΔPBIT OPT=PSURF OPTΔPCIRC OPT

Substituting

(9.79)ΔPBIT OPT=PSURF OPTPSURF OPTu+2

Reducing

(9.80a)ΔPBITOPT=PSURFOPT×(11u+2)
(9.80b)PBITOPT=(11u+2)PCIRCOPT

Understanding that for optimum conditions the PSURF OPT is the maximum possible surface pressure PMAX OPT, this may be simplified as

(9.81a)ΔPBITOPT=u+1u+2×PSURFOPT
(9.81b)PBITOPT=(u+1u+2)PCIRCOPT

If the (u+1/u+2) fraction of the standpipe pressure is applied across the jet nozzles, the hydraulic impact will be the maximum value possible for the hydraulic power limited case.

Note that there is a mathematical discontinuity between API Region 1 and Region 3.

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Pumping and Stimulation

Howard Crumpton, in Well Control for Completions and Interventions, 2018

8.1.3 Guidelines for the use of mud pumps and cement pumps

In most cases, dedicated high pressure pumps will be brought to a location specifically for an intervention operation. On offshore platforms and drilling rigs, there may be limitations on the space available for intervention pumps. As a consequence, the mud pump, or more usually the cement unit, will be used. Even where dedicated intervention pumps are used, the cement unit is often used to pressure test surface lines and as a back up to the intervention pump.

8.1.3.1 Mud pumps

Before pumping operations begin, the drilling, mud pumps, mud manifold, valves, and main discharge lines should be pressure tested with water to the circulating system working pressure.

For some critical operations a minimum of two pumps should be available to allow for redundancy.

Hydraulic output should be sufficient to circulate maximum anticipated weight of fluid at planned well profile and worst case geometry.

Functional stroke counters should be installed to enable displacement to be properly monitored.

8.1.3.2 Cement pump

The emergency high pressure kill pump (and/or the cement pump), manifolds, valves, and lines should be tested to the maximum rated working pressure of the lowest rated part of the system.

Cement pumps may be required as back up during well intervention operations where fluid is to be pumped, e.g., coil tubing clean out.

Ideally the cement pump will have an independent power source (diesel) in the event of total power loss at the host facility.

Functional stroke counters or flow/volume measuring devices must be installed prior to displacement.

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Oil and Natural Gas: Offshore Operations

Ron Baker, in Encyclopedia of Energy, 2004

6.3 Power System

Any drilling rig needs power—power to actuate the mud pumps, to hoist the drill string, and to run all the machinery on the rig. Several large diesel engines usually provide the power. A diesel engine is an internal-combustion engine, which means that it runs because a mixture of fuel and air burns inside the engine. Electricity transmits engine power—that is, the diesel engines put out mechanical power. The mechanical power turns electrical generators. The generators produce electricity, which heavy-duty cables carry to powerful electric motors on the equipment needing power. Drillers control the transfer of power with controls and switches from their position on the rig floor.

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Common Hidden Dangers and Remedies of Vacuum Degassers

Sun Xiaozhen, in Common Well Control Hazards, 2013

Hidden danger: The degasser is installed on the suction tank of the mud pump

Hazard

If the degasser is installed on the suction tank of the mud pump, there's not enough time for the gas-bearing mud circulated from the well to be degassed; it is sucked into the borehole by the mud pump. If the gas-bearing mud goes into the annulus, the hydraulic column pressure decreases further, and well invading will be sped up (Fig. 9-1-13).

Fig. 9-1-13. Degasser is near the suction tank of the mud pump.

Remedy

The installation position of the degasser should meet the gas-bearing mud returned from the borehole. First it is degassed by the degasser, and then it goes into the mud tank to be circulated. The degasser should be installed between the shale shaker and desander (Fig. 9-1-14).

Fig. 9-1-14. Degasser is between the shale shaker and desander.

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