mud pump working principle free sample

This rig features a Mission 4-by-5 centrifugal pump. Courtesy of Higgins Rig Co.Returning to the water well industry when I joined Schramm Inc. last year, I knew that expanding my mud pump knowledge was necessary to represent the company"s mud rotary drill line properly. One item new to me was the centrifugal mud pump. What was this pump that a number of drillers were using? I had been trained that a piston pump was the only pump of any ability.

As I traveled and questioned drillers, I found that opinions of the centrifugal pumps varied. "Best pump ever built," "What a piece of junk" and "Can"t drill more than 200 feet with a centrifugal" were typical of varying responses. Because different opinions had confused the issue, I concluded my discussions and restarted my education with a call to a centrifugal pump manufacturer. After that conversation, I went back to the field to continue my investigation.

For the past eight months, I have held many discussions and conducted field visits to understand the centrifugal pump. As a result, my factual investigation has clearly proved that the centrifugal pump has a place in mud rotary drilling. The fact also is clear that many drilling contractors do not understand the correct operational use of the pump. Following are the results of my work in the field.

High up-hole velocity - High pump flow (gpm) moves cuttings fast. This works well with lower viscosity muds - reducing mud expense, mixing time and creating shorter settling times.

Able to run a desander - The centrifugal"s high volume enables a desander to be operated off the pump discharge while drilling without adding a dedicated desander pump.

6. Sticky clays will stall a centrifugal pump"s flow. Be prepared to reduce your bit load in these conditions and increase your rpm if conditions allow. Yes, clays can be drilled with a centrifugal pump.

7. Centrifugal pumps cannot pump muds over 9.5 lbs./gal. Centrifugal pumps work best with a 9.0 lbs./gal. mud weight or less. High flow rate move cuttings, not heavy mud.

The goal of this article has been to increase awareness of the value of the centrifugal pump and its growing use. Although the centrifugal pump is not flawless, once its different operating techniques are understood, drilling programs are being enhanced with the use of this pump.

If you wish to learn more, please talk directly to centrifugal pump users. Feel free to call me at 314-909-8077 for a centrifugal pump user list. These drillers will gladly share their centrifugal pump experiences.

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

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

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

What is a mud pump? A mud pump refers to a machine that transports mud or water and other flushing fluid into the borehole during drilling. Types of mud pumps are an important part of drilling equipment. In the commonly used positive circulation drilling, it is to send the surface flushing medium—clear water, mud, or polymer rinsing liquid to the bottom end of the drill bit through a high-pressure hose, faucet, and drill rod center hole under a certain pressure. Cool the drill bit, remove the cut debris and transport it to the surface.

The commonly used mud pump is a piston-type or a plunger type, and the crankshaft of the pump is driven by the power machine, and the crankshaft passes the crosshead to drive the piston or the plunger to reciprocate in the pump cylinder. Under the alternating action of the suction and discharge valves, the purpose of pumping and circulating the flushing liquid is achieved.

During operation, the power machine drives the main shaft and the crank that is fixed thereon by a transmission component such as a belt, a transmission shaft, and a gear. When the crank rotates counterclockwise from the horizontal position from left to right, the piston moves to the power end, the pressure in the liquid cylinder gradually decreases and a vacuum is formed, and the liquid in the suction pool is under the action of the liquid surface pressure, and the suction valve is opened to enter the liquid cylinder. Until the piston moves to the right stop. This working process is called the suction process of the pump.

After the crank completes the above suction process, it continues to rotate counterclockwise. At this time, the piston starts to move toward the hydraulic end (left side in the figure), and the liquid in the cylinder is squeezed. The pressure rises, the suction valve closes, and the discharge valve is closed. Top open, liquid enters the discharge pipe until the piston moves to the left stop. This process is called the pump discharge process. As the power machine continues to operate, the reciprocating pump continuously repeats the process of inhaling and discharging, and the liquid in the suction pool is continuously sent to the bottom of the well through the discharge pipe.

Created specifically for drilling equipment inspectors and others in the oil and gas industry, the Oil Rig Mud Pump Inspection app allows you to easily document the status and safety of your oil rigs using just a mobile device. Quickly resolve any damage or needed maintenance with photos and GPS locations and sync to the cloud for easy access. The app is completely customizable to fit your inspection needs and works even without an internet signal.Try Template

A mud pump (sometimes referred to as a mud drilling pump or drilling mud pump), is a reciprocating piston/plunger pump designed to circulate drilling fluid under high pressure (up to 7,500 psi or 52,000 kPa) down the drill string and back up the annulus. A mud pump is an important part of the equipment used for oil well drilling.

Mud pumps can be divided into single-acting pump and double-acting pump according to the completion times of the suction and drainage acting in one cycle of the piston"s reciprocating motion.

Mud pumps come in a variety of sizes and configurations but for the typical petroleum drilling rig, the triplex (three piston/plunger) mud pump is used. Duplex mud pumps (two piston/plungers) have generally been replaced by the triplex pump, but are still common in developing countries. Two later developments are the hex pump with six vertical pistons/plungers, and various quintuplexes with five horizontal piston/plungers. The advantages that these new pumps have over convention triplex pumps is a lower mud noise which assists with better measurement while drilling (MWD) and logging while drilling (LWD) decoding.

The fluid end produces the pumping process with valves, pistons, and liners. Because these components are high-wear items, modern pumps are designed to allow quick replacement of these parts.

To reduce severe vibration caused by the pumping process, these pumps incorporate both a suction and discharge pulsation dampener. These are connected to the inlet and outlet of the fluid end.

The pressure of the pump depends on the depth of the drilling hole, the resistance of flushing fluid (drilling fluid) through the channel, as well as the nature of the conveying drilling fluid. The deeper the drilling hole and the greater the pipeline resistance, the higher the pressure needed.

With the changes of drilling hole diameter and depth, the displacement of the pump can be adjusted accordingly. In the mud pump mechanism, the gearbox or hydraulic motor is equipped to adjust its speed and displacement. In order to accurately measure the changes in pressure and displacement, a flow meter and pressure gauge are installed in the mud pump.

The construction department should have a special maintenance worker that is responsible for the maintenance and repair of the machine. Mud pumps and other mechanical equipment should be inspected and maintained on a scheduled and timely basis to find and address problems ahead of time, in order to avoid unscheduled shutdown. The worker should attend to the size of the sediment particles; if large particles are found, the mud pump parts should be checked frequently for wear, to see if they need to be repaired or replaced. The wearing parts for mud pumps include pump casing, bearings, impeller, piston, liner, etc. Advanced anti-wear measures should be adopted to increase the service life of the wearing parts, which can reduce the investment cost of the project, and improve production efficiency. At the same time, wearing parts and other mud pump parts should be repaired rather than replaced when possible.

Positive displacements pumps are generally used on drilling rigs to pump high pressure and high volume of drilling fluids throughout a drilling system. There are several reasons why the positive displacement mud pumps are used on the rigs.

The duplex pumps (Figure 1) have two cylinders with double acting. It means that pistons move back and take in drilling mud through open intake valve and other sides of the same pistons, the pistons push mud out through the discharge valves.

When the piston rod is moved forward, one of intake valves is lift to allow fluid to come in and one of the discharge valve is pushed up therefore the drilling mud is pumped out of the pump (Figure 2).

On the other hand, when the piston rod is moved backward drilling fluid is still pumped. The other intake and discharge valve will be opened (Figure 3).

The triplex pumps have three cylinders with single acting. The pistons are moved back and pull in drilling mud through open intake valves. When the pistons are moved forward and the drilling fluid is pushed out through open discharge valves.

On the contrary when the piston rods are moved backward, the intake valve are opened allowing drilling fluid coming into the pump (Figure 6). This video below shows how a triplex mud pump works.

Because each pump has power rating limit as 1600 hp, this will limit capability of pump. It means that you cannot pump at high rate and high pressure over what the pump can do. Use of a small liner will increase discharge pressure however the flow rate is reduces. Conversely, if a bigger liner is used to deliver more flow rate, maximum pump pressure will decrease.

As you can see, you can have 7500 psi with 4.5” liner but the maximum flow rate is only 297 GPM. If the biggest size of liner (7.25”) is used, the pump pressure is only 3200 psi.

Finally, we hope that this article would give you more understanding about the general idea of drilling mud pumps. Please feel free to add more comments.

The need to move liquids from one point to the other is as old as the history of humankind. Such liquids serve such needs as irrigation, domestic purposes, and locomotion among others. Primitive ways of moving liquids from one point to the other existed before the invention of the pump, which has made it easier to move such liquids. This essay seeks to look at the history of pumps, different types of pumps, and their uses.

The imbibing and suppuration nozzles in a single stage horizontal split centrifugal are integrally built in the lower half of the chamber and on the same horizontal centreline. The aperture configuration is side by side (Ruhrpumpen, 2013).

Single stage horizontal split centrifugal has several advantages. It is easier to set up, examine, maintain and service since its rotor and internals are easier to access. The single stage horizontal split centrifugal works well with several drivers like electric motors and engines (Centrifugal-Pump.org, 2013).

These are pumps with an axially split casing, which allows the removal of the whole rotor leaving the piping and motor intact (Thinking Buildings Universe, 2013). They have shut impellers with double curved vanes with two bearings on both sides of the pump, which have grease lubricated profound groove circular ball bearings (Thinking Buildings Universe, 2013).

The advantages of a horizontal split double suction centrifugal include the fact that it does not occupy a lot of space, unlike most other pumps. An inspector can open the lower chamber with interfering with the motor or the pipe system and this enables the technician to detect any problem without necessarily disassembling the pump. The horizontal split double suction centrifugal needs only one individual to repair it as opposed to a team of technicians.

The six types of positive displacement pumps include the rotary type, which moves liquid using the tenets of rotation (Pump, n.d.). The second type, reciprocating type, works by allowing fluid to flow into it as the cavity on the imbibing side expands and the fluid moves out of the outlet as the cavity caves in (Pump, n.d.). The third type, the gear pump, utilizes two meshed levers rotating in a compact chamber and pumps out fluids by capturing it in the tooth gaps (Pump, n.d.). The fourth type, progressing cavity pump, has a piston that enters a heavy rubber channel and as the piston rotates, the liquid rises up the rubber channel (Pump, n.d.).

The fifth type, roots pumps, produce a non-interrupted flow of liquid by imbibing at the outlet (Pump, n.d.). The sixth type, peristaltic pump, has a flexible cylinder in it. As the rotor moves, it pressures the liquid to move through the cylinder (Pump, n.d.).

Rishel, J. B. (2007). Horizontal Split-Case Centrifugal Pumps: Five advantages help achieve efficiency, quality, and low first costs. Applications and Resources , 2-3. Web.

Centrifugal pumps basically consist of a stationary pump casing and an impeller mounted on a rotating shaft. The pump casing provides a pressure boundary for the pump and contains channels to properly direct the suction and discharge flow. The pump casing has suction and discharge penetrations for the main flow path of the pump and normally has small drain and vent fittings to remove gases trapped in the pump casing or to drain the pump casing for maintenance.

Some centrifugal pumps contain diffusers. A diffuser is a set of stationary vanes that surround the impeller. The purpose of the diffuser is to increase the efficiency of the centrifugal pump by allowing a more gradual expansion and less turbulent area for the liquid to reduce in velocity. The diffuser vanes are designed in a manner that the liquid exiting the impeller will encounter an everincreasing flow area as it passes through the diffuser. This increase in flow area causes a reduction in flow velocity, converting kinetic energy into flow pressure.

Impellers of pumps are classified based on the number of points that the liquid can enter the impeller and also on the amount of webbing between the impeller blades.

Centrifugal pumps can be classified based on the manner in which fluid flows through the pump. The manner in which fluid flows through the pump is determined by the design of the pump casing and the impeller. The three types of flow through a centrifugal pump are radial flow, axial flow, and mixed flow.

A centrifugal pump with a single impeller that can develop a differential pressure of more than 150 psid between the suction and the discharge is difficult and costly to design and construct. A more economical approach to developing high pressures with a single centrifugal pump is to include multiple impellers on a common shaft within the same pump casing. Internal channels in the pump casing route the discharge of one impeller to the suction of another impeller. Figure 9 shows a diagram of the arrangement of the impellers of a four-stage pump. The water enters the pump from the top left and passes through each of the four impellers in series, going from left to right. The water goes from the volute surrounding the discharge of one impeller to the suction of the next impeller.

Centrifugal pumps vary in design and construction from simple pumps with relatively few parts to extremely complicated pumps with hundreds of individual parts. Some of the most common components found in centrifugal pumps are wearing rings, stuffing boxes, packing, and lantern rings. These components are shown in Figure 10 and described on the following pages.

Some wear or erosion will occur at the point where the impeller and the pump casing nearly come into contact. This wear is due to the erosion caused by liquid leaking through this tight clearance and other causes. As wear occurs, the clearances become larger and the rate of leakage increases. Eventually, the leakage could become unacceptably large and maintenance would be required on the pump.

To minimize the cost of pump maintenance, many centrifugal pumps are designed with wearing rings. Wearing rings are replaceable rings that are attached to the impeller and/or the pump casing to allow a small running clearance between the impeller and the pump casing without causing wear of the actual impeller or pump casing material. These wearing rings are designed to be replaced periodically during the life of a pump and prevent the more costly replacement of the impeller or the casing.

In almost all centrifugal pumps, the rotating shaft that drives the impeller penetrates the pressure boundary of the pump casing. It is important that the pump is designed properly to control the amount of liquid that leaks along the shaft at the point that the shaft penetrates the pump casing. There are many different methods of sealing the shaft penetration of the pump casing. Factors considered when choosing a method include the pressure and temperature of the fluid being pumped, the size of the pump, and the chemical and physical characteristics of the fluid being pumped.

One of the simplest types of shaft seal is the stuffing box. The stuffing box is a cylindrical space in the pump casing surrounding the shaft. Rings of packing material are placed in this space. Packing is material in the form of rings or strands that is placed in the stuffing box to form a seal to control the rate of leakage along the shaft. The packing rings are held in place by a gland. The gland is, in turn, held in place by studs with adjusting nuts. As the adjusting nuts are tightened, they move the gland in and compress the packing. This axial compression causes the packing to expand radially, forming a tight seal between the rotating shaft and the inside wall of the stuffing box.

The high speed rotation of the shaft generates a significant amount of heat as it rubs against the packing rings. If no lubrication and cooling are provided to the packing, the temperature of the packing increases to the point where damage occurs to the packing, the pump shaft, and possibly nearby pump bearings. Stuffing boxes are normally designed to allow a small amount of controlled leakage along the shaft to provide lubrication and cooling to the packing. The leakage rate can be adjusted by tightening and loosening the packing gland.

It is not always possible to use a standard stuffing box to seal the shaft of a centrifugal pump. The pump suction may be under a vacuum so that outward leakage is impossible or the fluid may be too hot to provide adequate cooling of the packing. These conditions require a modification to the standard stuffing box.

One method of adequately cooling the packing under these conditions is to include a lantern ring. A lantern ring is a perforated hollow ring located near the center of the packing box that receives relatively cool, clean liquid from either the discharge of the pump or from an external source and distributes the liquid uniformly around the shaft to provide lubrication and cooling. The fluid entering the lantern ring can cool the shaft and packing, lubricate the packing, or seal the joint between the shaft and packing against leakage of air into the pump in the event the pump suction pressure is less than that of the atmosphere.

In some situations, packing material is not adequate for sealing the shaft. One common alternative method for sealing the shaft is with mechanical seals. Mechanical seals consist of two basic parts, a rotating element attached to the pump shaft and a stationary element attached to the pump casing. Each of these elements has a highly polished sealing surface. The polished faces of the rotating and stationary elements come into contact with each other to form a seal that prevents leakage along the shaft.

A diffuser increases the efficiency of a centrifugal pump by allowing a more gradual expansion and less turbulent area for the liquid to slow as the flow area expands.

Wearing rings are replaceable rings that are attached to the impeller and/or the pump casing to allow a small running clearance between the impeller and pump casing without causing wear of the actual impeller or pump casing material.

Many centrifugal pumps are designed in a manner that allows the pump to operate continuously for months or even years. These centrifugal pumps often rely on the liquid that they are pumping to provide cooling and lubrication to the pump bearings and other internal components of the pump. If flow through the pump is stopped while the pump is still operating, the pump will no longer be adequately cooled and the pump can quickly become damaged. Pump damage can also result from pumping a liquid whose temperature is close to saturated conditions.

The flow area at the eye of the pump impeller is usually smaller than either the flow area of the pump suction piping or the flow area through the impeller vanes. When the liquid being pumped enters the eye of a centrifugal pump, the decrease in flow area results in an increase in flow velocity accompanied by a decrease in pressure. The greater the pump flow rate, the greater the pressure drop between the pump suction and the eye of the impeller. If the pressure drop is large enough, or if the temperature is high enough, the pressure drop may be sufficient to cause the liquid to flash to vapor when the local pressure falls below the saturation pressure for the fluid being pumped. Any vapor bubbles formed by the pressure drop at the eye of the impeller are swept along the impeller vanes by the flow of the fluid. When the bubbles enter a region where local pressure is greater than saturation pressure farther out the impeller vane, the vapor bubbles abruptly collapse. This process of the formation and subsequent collapse of vapor bubbles in a pump is called cavitation.

Cavitation in a centrifugal pump has a significant effect on pump performance. Cavitation degrades the performance of a pump, resulting in a fluctuating flow rate and discharge pressure. Cavitation can also be destructive to pumps internal components. When a pump cavitates, vapor bubbles form in the low pressure region directly behind the rotating impeller vanes. These vapor bubbles then move toward the oncoming impeller vane, where they collapse and cause a physical shock to the leading edge of the impeller vane. This physical shock creates small pits on the leading edge of the impeller vane. Each individual pit is microscopic in size, but the cumulative effect of millions of these pits formed over a period of hours or days can literally destroy a pump impeller. Cavitation can also cause excessive pump vibration, which could damage pump bearings, wearing rings, and seals.

A small number of centrifugal pumps are designed to operate under conditions where cavitation is unavoidable. These pumps must be specially designed and maintained to withstand the small amount of cavitation that occurs during their operation. Most centrifugal pumps are not designed to withstand sustained cavitation.

Noise is one of the indications that a centrifugal pump is cavitating. A cavitating pump can sound like a can of marbles being shaken. Other indications that can be observed from a remote operating station are fluctuating discharge pressure, flow rate, and pump motor current. Methods to stop or prevent cavitation are presented in the following paragraphs.

To avoid cavitation in centrifugal pumps, the pressure of the fluid at all points within the pump must remain above saturation pressure. The quantity used to determine if the pressure of the liquid being pumped is adequate to avoid cavitation is the net positive suction head (NPSH). The net positive suction head available (NPSHA) is the difference between the pressure at the suction of the pump and the saturation pressure for the liquid being pumped. The net positive suction head required (NPSHR) is the minimum net positive suction head necessary to avoid cavitation.

When a centrifugal pump is taking suction from a tank or other reservoir, the pressure at the suction of the pump is the sum of the absolute pressure at the surface of the liquid in the tank plus the pressure due to the elevation difference between the surface of liquid in the tank and the pump suction less the head losses due to friction in the suction line from the tank to the pump.

If a centrifugal pump is cavitating, several changes in the system design or operation may be necessary to increase the NPSHA above the NPSHR and stop the cavitation. One method for increasing the NPSHA is to increase the pressure at the suction of the pump. For example, if a pump is taking suction from an enclosed tank, either raising the level of the liquid in the tank or increasing the pressure in the space above the liquid increases suction pressure.

It is also possible to increase the NPSHA by decreasing the temperature of the liquid being pumped. Decreasing the temperature of the liquid decreases the saturation pressure, causing NPSHA to increase. Recall from the previous module on heat exchangers that large steam condensers usually subcool the condensate to less than the saturation temperature, called condensate depression, to prevent cavitation in the condensate pumps.

If the head losses in the pump suction piping can be reduced, the NPSHA will be increased. Various methods for reducing head losses include increasing the pipe diameter, reducing the number of elbows, valves, and fittings in the pipe, and decreasing the length of the pipe.

It may also be possible to stop cavitation by reducing the NPSHR for the pump. The NPSHR is not a constant for a given pump under all conditions, but depends on certain factors. Typically, the NPSHR of a pump increases significantly as flow rate through the pump increases. Therefore, reducing the flow rate through a pump by throttling a discharge valve decreases NPSHR. NPSHR is also dependent upon pump speed. The faster the impeller of a pump rotates, the greater the NPSHR. Therefore, if the speed of a variable speed centrifugal pump is reduced, the NPSHR of the pump decreases. However, since a pump’s flow rate is most often dictated by the needs of the system on which it is connected, only limited adjustments can be made without starting additional parallel pumps, if available.

The net positive suction head required to prevent cavitation is determined through testing by the pump manufacturer and depends upon factors including type of impeller inlet, impeller design, pump flow rate, impeller rotational speed, and the type of liquid being pumped. The manufacturer typically supplies curves of NPSHR as a function of pump flow rate for a particular liquid (usually water) in the vendor manual for the pump.

For a given centrifugal pump operating at a constant speed, the flow rate through the pump is Figure 11 Centrifugal Pump Characteristic Curve dependent upon the differential pressure or head developed by the pump. The lower the pump head, the higher the flow rate. A vendor manual for a specific pump usually contains a curve of pump flow rate versus pump head called a pump characteristic curve. After a pump is installed in a system, it is usually tested to ensure that the flow rate and head of the pump are within the required specifications. A typical centrifugal pump characteristic curve is shown in Figure 11.

A centrifugal pump is dead-headed when it is operated with no flow through it, for example, with a closed discharge valve or against a seated check valve. If the discharge valve is closed and there is no other flow path available to the pump, the impeller will churn the same volume of water as it rotates in the pump casing. This will increase the temperature of the liquid (due to friction) in the pump casing to the point that it will flash to vapor. The vapor can interrupt the cooling flow to the pump’s packing and bearings, causing excessive wear and heat. If the pump is run in this condition for a significant amount of time, it will become damaged.

When a centrifugal pump is installed in a system such that it may be subjected to periodic shutoff head conditions, it is necessary to provide some means of pump protection. One method for protecting the pump from running dead-headed is to provide a recirculation line from the pump discharge line upstream of the discharge valve, back to the pump’s supply source. The recirculation line should be sized to allow enough flow through the pump to prevent overheating and damage to the pump. Protection may also be accomplished by use of an automatic flow control device.

Centrifugal pumps must also be protected from runout. Runout can lead to cavitation and can also cause overheating of the pump’s motor due to excessive currents. One method for ensuring that there is always adequate flow resistance at the pump discharge to prevent excessive flow through the pump is to place an orifice or a throttle valve immediately downstream of the pump discharge. Properly designed piping systems are very important to protect from runout.

Gas binding of a centrifugal pump is a condition where the pump casing is filled with gases or vapors to the point where the impeller is no longer able to contact enough fluid to function correctly. The impeller spins in the gas bubble, but is unable to force liquid through the pump. This can lead to cooling problems for the pump’s packing and bearings.

Centrifugal pumps are designed so that their pump casings are completely filled with liquid during pump operation. Most centrifugal pumps can still operate when a small amount of gas accumulates in the pump casing, but pumps in systems containing dissolved gases that are not designed to be self-venting should be periodically vented manually to ensure that gases do not build up in the pump casing.

Most centrifugal pumps are not self-priming. In other words, the pump casing must be filled with liquid before the pump is started, or the pump will not be able to function. If the pump casing becomes filled with vapors or gases, the pump impeller becomes gas-bound and incapable of pumping. To ensure that a centrifugal pump remains primed and does not become gas-bound, most centrifugal pumps are located below the level of the source from which the pump is to take its suction. The same effect can be gained by supplying liquid to the pump suction under pressure supplied by another pump placed in the suction line.

Damage to pump impeller, bearings, wearing rings, and sealsTo avoid pump cavitation, the net positive suction head available must be greater than the net positive suction head required.

Gas binding of a centrifugal pump is a condition where the pump casing is filled with gases or vapors to the point where the impeller is no longer able to contact enough fluid to function correctly.

Centrifugal pumps are protected from runout by placing an orifice or throttle valve immediately downstream of the pump discharge and through proper piping system design.

A positive displacement pump is one in which a definite volume of liquid is delivered for each cycle of pump operation. This volume is constant regardless of the resistance to flow offered by the system the pump is in, provided the capacity of the power unit driving the pump or pump component strength limits are not exceeded. The positive displacement pump delivers liquid in separate volumes with no delivery in between, although a pump having several chambers may have an overlapping delivery among individual chambers, which minimizes this effect. The positive displacement pump differs from centrifugal pumps, which deliver a continuous flow for any given pump speed and discharge resistance.

Positive displacement pumps can be grouped into three basic categories based on their design and operation. The three groups are reciprocating pumps, rotary pumps, and diaphragm pumps.

During the suction stroke, the piston moves to the left, causing the check valve in the suction Figure 12 Reciprocating Positive Displacement Pump Operation line between the reservoir and the pump cylinder to open and admit water from the reservoir. During the discharge stroke, the piston moves to the right, seating the check valve in the suction line and opening the check valve in the discharge line. The volume of liquid moved by the pump in one cycle (one suction stroke and one discharge stroke) is equal to the change in the liquid volume of the cylinder as the piston moves from its farthest left position to its farthest right position.

Reciprocating positive displacement pumps are generally categorized in four ways: direct-acting or indirect-acting; simplex or duplex; single-acting or double-acting; and power pumps.

Some reciprocating pumps are powered by prime movers that also have reciprocating motion, such as a reciprocating pump powered by a reciprocating steam piston. The piston rod of the steam piston may be directly connected to the liquid piston of the pump or it may be indirectly connected with a beam or linkage. Direct-acting pumps have a plunger on the liquid (pump) end that is directly driven by the pump rod (also the piston rod or extension thereof) and carries the piston of the power end. Indirect-acting pumps are driven by means of a beam or linkage connected to and actuated by the power piston rod of a separate reciprocating engine.

A simplex pump, sometimes referred to as a single pump, is a pump having a single liquid (pump) cylinder. A duplex pump is the equivalent of two simplex pumps placed side by side on the same foundation.

The driving of the pistons of a duplex pump is arranged in such a manner that when one piston is on its upstroke the other piston is on its downstroke, and vice versa. This arrangement doubles the capacity of the duplex pump compared to a simplex pump of comparable design.

A single-acting pump is one that takes a suction, filling the pump cylinder on the stroke in only one direction, called the suction stroke, and then forces the liquid out of the cylinder on the return stroke, called the discharge stroke. A double-acting pump is one that, as it fills one end of the liquid cylinder, is discharging liquid from the other end of the cylinder. On the return stroke, the end of the cylinder just emptied is filled, and the end just filled is emptied. One possible arrangement for single-acting and double-acting pumps is shown in Figure 13.

Power pumps typically have high efficiency and are capable of developing very high pressures. Figure 13 Single-Acting and Double-Acting Pumps They can be driven by either electric motors or turbines. They are relatively expensive pumps and can rarely be justified on the basis of efficiency over centrifugal pumps. However, they are frequently justified over steam reciprocating pumps where continuous duty service is needed due to the high steam requirements of direct-acting steam pumps.

In general, the effective flow rate of reciprocating pumps decreases as the viscosity of the fluid being pumped increases because the speed of the pump must be reduced. In contrast to centrifugal pumps, the differential pressure generated by reciprocating pumps is independent of fluid density. It is dependent entirely on the amount of force exerted on the piston. For more information on viscosity, density, and positive displacement pump theory, refer to the handbook on Thermodynamics, Heat Transfer, and Fluid Flow.

Rotary pumps operate on the principle that a rotating vane, screw, or gear traps the liquid in the suction side of the pump casing and forces it to the discharge side of the casing. These pumps are essentially self-priming due to their capability of removing air from suction lines and producing a high suction lift. In pumps designed for systems requiring high suction lift and selfpriming features, it is essential that all clearances between rotating parts, and between rotating and stationary parts, be kept to a minimum in order to reduce slippage. Slippage is leakage of fluid from the discharge of the pump back to its suction.

Due to the close clearances in rotary pumps, it is necessary to operate these pumps at relatively low speed in order to secure reliable operation and maintain pump capacity over an extended period of time. Otherwise, the erosive action due to the high velocities of the liquid passing through the narrow clearance spaces would soon cause excessive wear and increased clearances, resulting in slippage.

There are many types of positive displacement rotary pumps, and they are normally grouped into three basic categories that include gear pumps, screw pumps, and moving vane pumps.

There are several variations of gear pumps. The simple gear pump shown in Figure 14 consists of two spur gears meshing together and revolving in opposite directions within a casing. Only a few thousandths of an inch clearance exists between the case and the gear faces and teeth extremities. Any liquid that fills the space bounded by two successive gear teeth and the case must follow along with the teeth as they revolve. When the gear teeth mesh with the teeth of the other gear, the space between the teeth is reduced, and the entrapped liquid is forced out the pump discharge pipe. As the gears revolve and the teeth disengage, the space again opens on the suction side of the pump, trapping new quantities of liquid and carrying it around the pump case to the discharge. As liquid is carried away from the suction side, a lower pressure is created, which draws liquid in through the suction line.

With the large number of teeth usually employed on the gears, the discharge is relatively smooth and continuous, with small quantities of liquid being delivered to the discharge line in rapid succession. If designed with fewer teeth, the space between the teeth is greater and the capacity increases for a given speed; however, the tendency toward a pulsating discharge increases. In all simple gear pumps, power is applied to the shaft of one of the gears, which transmits power to the driven gear through their meshing teeth.

There are no valves in the gear pump to cause friction losses as in the reciprocating pump. The high impeller velocities, with resultant friction losses, are not required as in the centrifugal pump. Therefore, the gear pump is well suited for handling viscous fluids such as fuel and lubricating oils.

There are two types of gears used in gear pumps  in addition to the simple spur gear. One type is the helical gear. A helix is the curve produced when a straight line moves up or down the surface of a cylinder. The other type is the herringbone gear. A herringbone gear is composed of two helixes spiraling in different directions from the center of the gear. Spur, helical, and herringbone gears are shown in Figure 15.

The helical gear pump has advantages over the simple spur gear. In a spur gear, the entire length of the gear tooth engages at the same time. In a helical gear, the point of engagement moves along the length of the gear tooth as the gear rotates. This makes the helical gear operate with a steadier discharge pressure and fewer pulsations than a spur gear pump.

The herringbone gear pump is also a modification of the simple gear pump. Its principal difference in operation from the simple spur gear pump is that the pointed center section of the space between two teeth begins discharging before the divergent outer ends of the preceding space complete discharging. This overlapping tends to provide a steadier discharge pressure. The power transmission from the driving to the driven gear is also smoother and quieter.

The lobe type pump shown in Figure 16 is another variation of the simple gear pump. It is considered as a simple gear pump having only two or three teeth per rotor; otherwise, its operation or the explanation of the function of its parts is no different. Some designs of lobe pumps are fitted with replaceable gibs, that is, thin plates carried in grooves at the extremity of each lobe where they make contact with the casing. The gib promotes tightness and absorbs radial wear.

There are many variations in the design of the screw type positive displacement, rotary pump. The primary differences consist of the number of intermeshing screws involved, the pitch of the screws, and the general direction of fluid flow. Two common designs are the two-screw, low-pitch, double-flow pump and the three-screw, high-pitch, double-flow pump.

The complete assembly and the usual flow  Figure 18 Three-Screw, High-Pitch, Screw Pump path are shown in Figure 17. Liquid is trapped at the outer end of each pair of screws. As the first space between the screw threads rotates away from the opposite screw, a one-turn, spiral-shaped quantity of liquid is enclosed when the end of the screw again meshes with the opposite screw. As the screw continues to rotate, the entrapped spiral turns of liquid slide along the cylinder toward the center discharge space while the next slug is being entrapped. Each screw functions similarly, and each pair of screws discharges an equal quantity of liquid in opposed streams toward the center, thus eliminating hydraulic thrust. The removal of liquid from the suction end by the screws produces a reduction in pressure, which draws liquid through the suction line.

The three-screw, high-pitch, screw pump, shown in Figure 18, has many of the same elements as the two-screw, low-pitch, screw pump, and their operations are similar. Three screws, oppositely threaded on each end, are employed. They rotate in a triple cylinder, the two outer bores of which overlap the center bore. The pitch of the screws is much higher than in the low pitch screw pump; therefore, the center screw, or power rotor, is used to drive the two outer idler rotors directly without external timing gears. Pedestal bearings at the base support the weight of the rotors and maintain their axial position. The liquid being pumped enters the suction opening, flows through passages around the rotor housing, and through the screws from each end, in opposed streams, toward the center discharge. This eliminates unbalanced hydraulic thrust. The screw pump is used for pumping viscous fluids, usually lubricating, hydraulic, or fuel oil.

Positive displacement pumps deliver a definite volume of  Positive Displacement Pump Characteristic Curve liquid for each cycle of pump operation. Therefore, the only factor that effects flow rate in an ideal positive displacement pump is the speed at which it operates. The flow resistance of the system in which the pump is operating will not effect the flow rate through the pump. Figure 21 shows the characteristic curve for a positive displacement pump.

The dashed line in Figure 21 shows actual positive displacement pump performance. This line reflects the fact that as the discharge pressure of the pump increases, some amount of liquid will leak from the discharge of the pump back to the pump suction, reducing the effective flow rate of the pump. The rate at which liquid leaks from the pump discharge to its suction is called slippage.

Positive displacement pumps are normally fitted with relief valves on the upstream side of their discharge valves to protect the pump and its discharge piping from overpressurization. Positive displacement pumps will discharge at the pressure required by the system they are supplying. The relief valve prevents system and pump damage if the pump discharge valve is shut during pump operation or if any other occurrence such as a clogged strainer blocks system flow.

The important information in this chapter is summarized below.The flow delivered by a centrifugal pump during one revolution of the impeller depends upon the head against which the pump is operating. The positive displacement pump delivers a definite volume of fluid for each cycle of pump operation regardless of the head against which the pump is operating.

Moving vane pump Diaphragm pumpAs the viscosity of a liquid increases, the maximum speed at which a reciprocating positive displacement pump can properly operate decreases. Therefore, as viscosity increases, the maximum flow rate through the pump decreases.

The present invention relates to filter screen assemblies used to filter drilling mud of the type used in downhole drilling technologies in the oil and gas industries and to a method for installing such a filter screen assembly in a well bore drilling operation.

The “mud” circulating system is used to circulate drilling fluid down through the drill string and up the annulus, carrying the drilled cuttings from the face of the bit to surface and will be familiar to those skilled in the relevant arts. Among the main functions of the circulating drilling fluid are to clean the borehole of cuttings made by the drill bit, to cool the drill bit head, and to exert a hydrostatic pressure sufficient to prevent formation fluids from entering the borehole.

Drilling fluid (mud) is usually a mixture of water, clay, weighting material, such as barite, and chemicals. The mud is mixed and conditioned in mud pits or tanks located at the well surface and is then circulated downhole by large pumps. These pumps are typically present at the ground level, for example, adjacent the rig floor or at subfloor or substructure of the rig. These are typically reciprocating positive displacement pumps, for example Triplex Pumps™. These types of pumps are well known in the industry and are often used because they can operate over a wide range of pressure and pump fluids containing high solids content and tend to be relatively reliable and easy to operate and maintain.

In the case of a typical drilling rig, the mud is pumped through, for example, a standpipe, rotary hose, a swivel, and a Kelly and then down the drill string. At the bottom of the borehole, the mud passes through the bit and then up the annulus between the drill string and surrounding well bore, carrying cuttings up to surface. On surface the mud is directed from the annulus, through a mud return line back to the mud tanks and ultimately back to the mud pumps. However, before it re-enters the mud tanks, the drilled cuttings are removed from the drilling mud by some of solids removal equipment. The used mud may also be reconditioned in other ways.

Once the drilled cuttings have been removed from the mud it is re-circulated down the borehole. The mud is therefore in a continuous circulating system. The properties of the mud are checked continuously to ensure that the desired properties of the mud are maintained. If the properties of the mud change then chemicals will be added to the mud to bring the properties back to those that are required to fulfill the functions of the fluid. The chemicals may be added, for example, while the drilling fluid is being circulated through the mud tanks.

As has been mentioned, during drilling operations as the mud is being circulated, it begins to accumulate suspended drilled cuttings, as well as some gas or other possible contaminants. These must be removed before the mud is recycled. In a typical operation, the mud passes over a shale shaker, which is basically a vibrating screen. This will remove the larger particles, while allowing the residue (underflow) to pass into settling tanks. The finer material can be removed using other solids removal equipment. If the mud contains gas from the formation it will be passed through a degasser which separates the gas from the liquid mud. Having passed through all the mud processing equipment the mud is returned to the mud tanks for recycling.

The debris which the drilling mud picks up can affect the flow of the mud and the operation of the drill bit and other tools. In addition to the mud conditioning equipment previously described at the well surface, in the past, a filter screen subassembly was often installed in the drill string to help collect and filter debris. Downhole filter screens are run, for example, during directional drilling operations and are sometimes installed near the drill bit at the bottom of the drill string, and thus are not easily accessible during drilling. In some cases, to remove or clean out a downhole filter screen, the entire drill string must be pulled out of the wellbore.

The above described procedure is time consuming and somewhat complicated. Also, prior art downhole filter screens can be damaged during drilling operations. Filters in the drill string are subject to washing. Also, if a filter screen fills with debris and is not properly maintained or cleaned, then it can cause blockages in the fluid flow or other problems. In some extreme cases, the filter screen may shear off due to excess debris buildup or excess vibration during drilling operations. The broken filter screen can be pushed by the fluid flow of the drilling mud and may end up at the bottom of the borehole. Due to the inconveniences from factors such as installation, cleaning, and maintenance, filter screens are sometimes not used by drilling operators despite the benefits they provide in filtering drilling mud.

Because of these kinds of problems with downhole filter screens, surface pipe screens are also sometimes used to filter drilling mud. In the past, these pipe screens were typically installed in the drill string above the surface, typically at an elevated position on the drilling rig, and they are designed to catch finer particulates than downhole filter screens. They may be part of a top drive, for example, or in close proximity to the top drive, at an elevation located above the rig floor.

U.S. Pat. No. 6,976,546, issued Dec. 20, 2005, to Herst, is a typical prior art drilling mud filtration system using a filter screen which is disposed within a drilling mud fluid passageway that extends from the entry point of the drilling mud into the overhead drilling system on the top drive unit. Specifically, the overhead drilling system includes a washpipe assembly, having a gooseneck extending therefrom for receiving an S-pipe and the mud filter screen is disposed within the S-pipe. The S-pipe is located immediately adjacent the upper end of the top drive unit at an elevated position on the drilling rig.

The following invention presents a novel design for a filter screen assembly used in a variety of different conventional mud circulation systems of the type used on oil and gas well drilling rigs. The filter screen assembly is installed at the surface of a well on the discharge side of the mud pump typically at ground level, for example, as a part of the substructure of the rig. It does not need to be removed and reinstalled when additional segments are added to the drill string and is always easily accessible for routine maintenance or replacement. Since it is located at ground level, it does not present the safety hazards that some of the prior art arrangements presented where filtering devices were placed at elevated locations on the drill rig.

A method of drilling a well bore is shown which uses the improved filter screen assembly of the invention, where drill bit cuttings and other abrasive debris and contaminants are filtered from a drilling mud that is circulated from a surface mud tank through an oil or gas well drilling system. The filtering system is located on a well drilling rig having a rig floor and a rig derrick, the method comprising the steps of:providing a drill string;

providing a drilling system supported by the well derrick that rotatably drives the drill string for drilling a well bore, the drilling system including a stand pipe, a rotary hose, a swivel and a Kelly positioned at an elevated level above one end of the drill string, the drill string also having a drilling mud fluid passageway;

locating a mud pump at a well surface location for circulating the drilling mud from the mud tank to the drilling mud fluid passageway of the drill string, the mud pump having a pump inlet and a discharge outlet;

providing a mud filter screen assembly for filtering the drilling mud, the mud filter screen assembly being positioned in the interconnecting conduit adjacent the discharge outlet of the mud pump at a surface level which is prior to the interconnecting conduit rising to the elevated level of the rotary hose and swivel on the well derrick.

The drilling rig may be provided with a stand pipe that is located in the interconnecting conduit between the discharge outlet of the mud pump and the remainder of the drill string on the derrick, the stand pipe being positioned in a generally upright position in the derrick. In this case, the filter screen assembly used in the method of the invention will be positioned in the interconnecting conduit adjacent the discharge outlet of the mud pump at a surface level on the rig floor or floor substructure and prior to the stand pipe. In any case, the filter screen assembly will be located at ground level, for example, as a part of the substructure of the rig.

The mud filter screen assembly may assume various configurations, but will in any case be a porous structure, typically made of metal, having a plurality of openings along a length thereof which allows a flow of drilling mud through the filter screen portion of the assembly, while trapping drill bit cuttings, shavings and other abrasive debris. For example, the filter screen porous structure may be selected from the group consisting of metal mesh material, a plurality of welded metal bars, or a generally solid metal tube having a plurality of longitudinal opening formed therein. The filter screen porous structure could also be made from a variety of synthetic materials such as Nylon or various hard plastics.

FIG. 1 is a simplified, partly schematic view of a drilling mud system showing the principal components thereof and showing the location of the in-line mud filter screen assembly of the invention.

As has been described in some detail in the Background discussion above, in the oil and gas industry, downhole drilling operations may drill boreholes that extend thousands of feet into the ground. Drilling muds are used to facilitate such drilling operations. FIG. 1 is a simplified schematic which shows how drilling mud circulates through a typical prior art drilling mud circulation system. The drilling rig shown in FIG. 1 is intended to be a simplified view of a generic mud circulation system, designated generally as 11. Mud pumps 13 pump the mud from mud tanks or mud pits 15 (“mud tanks” hereafter) through a suction line 17 located at the surface. The mud is then pumped through a stand pipe 19, through a rotary hose 21 and through a swivel 23 and Kelly 25 to the top of the stand of drill pipe (the “drill pipe string”) 27. The conventional well derrick is indicated in broken-away, schematic fashion as 26 in FIG. 1.

The mud is further pumped through a drilling mud fluid passageway (internal bore) of the drill pipe string 27 to a bottom hole assembly and drill bit 33. In the simplified view shown in FIG. 1, the drill pipe 27 is shown supporting a drill collar 29 which is located within the well annulus 31 at a selected downhole location. The bottom hole assembly may assume a variety of configurations and may contain, for example, electrical and microprocessor components embedded within tools such as measurement drilling assemblies. As it reaches the bottom of the borehole, the mud acts to cool and clean the drill bit 33. The mud also picks up rock formation cuttings and other debris and circulates them back up through the annulus 31 between the drill string 27 and casing, returning ultimately to the mud tanks 15. The mud may also be processed through a shale shaker 35, desander 37, desilter 39 and a degasser 41, or other conditioning equipment, before returning to mud tanks 15 to start the process of being pumped downhole again.

As has been mentioned, prior art drilling systems often employed a filter screen assembly in addition to the shale shakers, vibrating screen, etc., present at the well surface, to further filter the recirculating drilling mud. These filter screens were typically placed either in the drill string, or in an elevated position on the drilling rig, as for example, being incorporated into some part of a top drive assembly or adjacent to such an assembly. In any event, the filter screen assemblies were located above the rig floor or within a section of the drill pipe itself. The various disadvantages that result from such an arrangement have been discussed.

In the method of the present invention, a drilling system such as the system shown simplified fashion in FIG. 1, is used to drill a well bore. The simplified schematic shown in FIG. 1 is intended to be a generic view of a typical mud circulation system of the type used with a conventional rotary table. The rig could also just as easily be a “top drive” type rig, which will be well familiar to those skilled in the relevant arts. Again with reference to FIG. 1, the method of the invention utilizes the principal components of the mud circulation system previously described. As has been described, the drill string 27 includes a mud fluid passageway within the interior thereof. The mud pump 13 receives mud from the mud tanks 15 through the suction line 17. Mud is drawn through a pump inlet 43 and discharges from a pump discharge outlet 45 on its way to the stand pipe 19, rotary hose 21 and Kelly 25, as previously described. Note that the stand pipe 19 is positioned in a generally upright position in the derrick. All of this is conventional drilling technology. It should also be noted that the mud tanks and mud pumps of the mud circulating system are typically located at the well surface level, i.e., at ground level or as a part of the substructure of the rig. In FIG. 1, “ground level” is indicated schematically as 47.

Unlike the prior art systems, in the method used in the present invention, the filter screen assembly (49 in FIG. 1) is located in the fluid conduits which are located adjacent the discharge outlet 45 of the mud pump 13 at a surface level, generally prior to the stand pipe 19. Where the derrick and drilling system includes a rotary hose, swivel and Kelly connecting the drill string to the stand pipe 19, the mud filter screen assembly will be located upstream of these components. In any event, the filter screen assembly will be located at ground level, for example, as a part of the substructure of the rig.

FIGS. 2-3A show one preferred form of the filter screen assembly of the invention. The filter screen apparatus shown FIG. 2 is a porous structure, preferably made of metal, such as a suitable steel, having a plurality of openings along a length thereof which allows a flow of drilling mud through the filter screen while trapping drill bit cuttings and other abrasive debris and contaminants. The filter screen itself can assume various forms, for example, the filter screen can be selected from the group consisting of metal mesh material, a plurality of welded metal bars, or a generally solid metal tube having a plurality of longitudinal opening formed therein, as by machining or milling. As mentioned, the porous structure of the filter screen could also be made from a variety of synthetic materials, such as Nylon and various hard plastics.

The coupling members, such as member 83 can be traditional “hammer unions” of the type that will be familiar to those skilled in the relevant arts. As best shown in FIG. 4, the hammer union 83 is used to enclose the filter screen assembly within the outer steel tubular member (85 in FIG. 4). Other conventional hammer unions 87, 89, shown in FIG. 4, are used to position the filter assembly at a selected location in the fluid conduit system which connects the mud pump discharge with the drill string, as previously described.

During drilling operations, used mud returns to the mud tanks 15 through a return line (93 in FIG. 1). After treatment, the mud will flow into the filter screen assembly from the discharge outlet 45 of the mud pump 13. As debris collects at the bottom of the filter screen, mud flow may be diverted through the sides of the cylindrical tube region 51, through the spaced slotted regions 53, 55, 57, and into an annular passageway that exists between the filter screen section and the outer tubular member (85 in FIG. 4) within the filter screen assembly. The mud will then flow through the remainder of the filter screen assembly and into the fluid conduit (91 in FIG. 1) which connects the filter assembly with the drill string.

An invention has been provided with several advantages. The filter screen system of the invention has the ability to put the filter screen on the discharge side of the mud pump, thereby eliminating the need for other types of filter screens such as top drive screens, surface screens, downhole filters, and the like. Unlike the filter screens presently offered in the marketplace, the present system is not tied to a specific rotary connection size and would eliminate that need. The prior art systems typically require removal and reinsertion on every stand of pipe, and this need would be eliminated by the present system. The present system can be utilized with any of a number of drilling rigs with the screen assembly simply being placed in-line in the mud circulation system. It stays with the drilling fluid system which is specific to the drilling rig at hand.