amt mud pump free sample

The AMT line of Diaphragm pumps features a 2-stage, heavy duty forged gear driven transmission. Often referred to as Mud or Sludge Pumps, diaphragm pumps are designed to pump mud, slurry, sewage and thick liquids that have the ability to flow. AMT Diaphragm pumps are available with a choice of drivers to meet your application requirements: gasoline, diesel or single or three phase electric motor. Built-in check valve assures self-priming to 20 feet after initial prime. Heavy  duty forged gear driven transmission is designed to operate pump at 40 strokes per minute for electric motor models and 60 strokes per minute for engine driven models. Each unit includes a 2” or 3” NPT steel suction strainer, two NPT nipples and a wheel kit for portability. Models 338E K6, 338G-K6, 337H-K6 and 337E-K6 are kits provided less motor or engine. Suction and discharge port sizes cannot be reduced.

15 Models below. Made in USA. Gas, Diesel or Electric diaphragm pump, or mud / sludge pump. Easily maneuverable, the gas diaphragm pump is built for performance; Ideal for seepage dewatering, high suction lift, cleaning septic tanks, pumping industrial waste and marine tanks, small wellpoint systems and dewatering in sandy, muddy waters. Honda or Briggs gasoline engine or Electric diaphragm pump with motor.

Diaphragm Mud pump Suction & discharge port size cannot be reduced. Cast aluminum construction with thermoplastic rubber diaphragm. Also called a mudhog. 90 degree rotatable base on all models to fit through narrow gates. As a alternate in a centrifugal pump dredge pump design see 316F-95 2" mud pumps. Trash pumps, centrifugal Dredge Pump. Hoses and accessories.

Features 2-stage, 44 to 1 gear reduction with a large diameter output gear and heavy duty ball bearing construction. Often referred to as Mud pumps or Sludge pumps, diaphragm pumps are designed to pump mud, slurry, sewage, and thick liquids that have the ability to flow. AMT Diaphragm pump Honda GX120 OHV gasoline engines. Built-in molded polyurethane flapper / check valve assures self-priming to 20 feet after initial prime. Each unit includes a 3" NPT steel suction strainer, two 3" NPT nipples, and wheel kit with 10" semi-pneumatic transport wheels for portability. Pumps are designed for use with non-flammable liquids which are compatible with pump component materials. Was 3357-96. Suction and discharge port size cannot be reduced. Due to positive pumping action of diaphragm pumps, by all mfr"s, the discharge is recommended to only be 25FT long unless oversized. Discharge can not be restricted. There is no relief valve. OBS, see other model

The AMT line of diaphragm pumps features a 2-stage, heavy duty forged gear driven transmission. Often referred to as mud or sludge Pumps, diaphragm pumps are designed to pump mud, slurry, sewage and thick liquids that have the ability to flow. AMT Diaphragm pumps are available with a choice of drivers to meet your application requirements: gasoline, diesel or single or three phase electric motor. Built-in check valve assures self-priming to 20 feet after initial prime. Heavy duty forged gear driven transmission is designed to operate pump at 40 strokes per minute for electric motor models and 60 strokes per minute for engine driven models. Each unit includes a 2 or 3 inch NPT steel suction strainer, two NPT nipples and a wheel kit for portability.

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.

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

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

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

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

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

You’ll find many of the AMT pumps and parts that you’re looking for. From centrifugal, drum, trash, and diaphragm types to self-priming, gas, or electric powered, we have them. Some are available in Stainless-Steel, Cast Iron, or Bronze constructions.

During drilling operations, a fluid known as drilling mud or drilling fluid is normally pumped down bore of the drill pipe, and circulated up the annular space which is formed between the external surface of said drill pipe and the internal surface of the wellbore. The basic functions of drilling mud are: (1) to cool and lubricate the drill bit and downhole equipment during drilling operations; (2) to transport pieces of drilled-up rock and other debris from the bottom of the hole to the surface; (3) to suspend such rock and debris during periods when circulation is stopped; (4) to provide hydrostatic pressure to control encountered subsurface pressures; and (5) to seal the porous rock in the well with an impermeable filter cake.

As circulated drilling mud returns to the earth"s surface and is pumped out of a well, the mud contains pieces of broken, drilled-up rock and other solid debris known as “cuttings” or “drill cuttings”. In most cases, an effluent mud stream flowing out of a well, together with associated drill cuttings, is directed to one or more devices which are designed to separate such drill cuttings from the mud. Such devices include, but are not limited to, shale shakers, desanders, desilters, hydrocyclones and centrifuges.

Shale shakers are essentially screens that are used to separate drill cuttings from the drilling mud. In many cases, shale shakers utilize a series of screens arranged in a tiered manner relative to each other and are often made to vibrate in order to increase the quality of such separation. The bulk drilling mud passes through the screens by gravity, while the predominantly solid cuttings are inhibited from passing through and instead pass over the end of the screens. Certain shale shakers are designed to filter coarse material while other shale shakers are designed to remove finer particles from the drilling mud. Shale shakers and other similar devices are frequently necessary to efficiently separate drill cuttings from drilling mud.

Once drill cuttings and other debris have been separated from the bulk mud stream flowing out of a well, it is necessary to dispose of such cuttings. Unfortunately, the disposal of drill cuttings can present a number of different problems. Often, the most economical way to dispose of drill cuttings would simply be to discharge said cuttings directly into the surrounding environment, such as in a mud pit or discharged from an offshore platform or drill ship into the water. Even though drill cuttings leaving a shale shaker or other separation device may have been separated from a well"s effluent mud stream, such cuttings nonetheless can include entrained mud and other fluids which could be damaging to the environment.

In order for drilling mud to accomplish its intended objectives, it is often necessary to control certain characteristics of such drilling mud. Chemicals and/or other additives are often mixed into such drilling muds for control of a certain parameter. Common drilling mud additives include gelling agents (e.g., colloidal solids and/or emulsified liquids), weighting materials, and other chemicals which are used to maintain mud properties within desired parameters. Although drilling mud has historically been water-based, improved results have been obtained using oil-based or synthetic-based muds, especially in severe drilling environments. Many of these additives, oil-based muds and synthetic-based muds can be environmentally harmful. Thus, it is often undesirable and a violation of environmental regulations to release such fluid-laden cuttings directly into the surrounding environment.

Attempts have been made to clean drill cuttings in order to remove surface contaminants prior to discharge of such cuttings into the environment. For example, certain cuttings recovery and treatment devices utilize separate cells having low speed agitators to stir a mixture of cuttings and cleansing surfactants. The cuttings are transferred from one cell to the next where additional agitation and cleansing takes place. Thereafter, a slurry of cleansed drill cuttings and surfactant is pumped from the cells to a vibrating screen operation in which most of the surfactant is removed and recovered for later use. In some cases, a portion of the surfactant solution, which is rich in fine drill cuttings and adherent drilling fluids, is run through one or more hydrocyclone separators which discharge the fine drill cuttings in solution separated from the larger, cleansed drill cuttings.

FIG. 1 is a diagram illustrating an example of a wellbore drilling mud system that may be used in accordance with certain embodiments of the present disclosure.

Referring to the drawings, FIG. 1 depicts a schematic representation of the mud system of a typical drilling rig. The flow of drilling mud within this mud system in FIG. 1 is generally in the direction of the arrows.

The bulk of the drilling mud for the depicted mud system is in mud pit 12. Mud from the mud pit 12 is circulated through the overall mud system depicted schematically in FIG. 1 via mud pump 14. During typical drilling operations, mud is pumped into tubular work string 6 through flow line 8 a, circulated out the bottom end 6 aof work string 6, up the annulus 10 of wellbore 4, and out of the wellbore annulus 10 via flow line 8 b.

During standard drilling operations, mud exiting the wellbore annulus 10 through flow line 8 boften includes drill cuttings and other debris encountered in wellbore 4. Such drill cuttings are generated downhole as a result of the drilling process. Such drill cuttings and other debris would typically contaminate the overall quality of the mud system if allowed to remain in the active mud system. Accordingly, the mud and drill cuttings mixture leaving the well is directed to a separation device, such as shale shakers 16. It is to be understood that any number of separation devices could be used for this purpose; however, for purposes of illustration in FIG. 1, the separation device is depicted as being shale shakers 16. As the combined mixture of drilling mud and drill cuttings are directed over shale shakers 16, much of the “free” liquid mud passes through the screens of the shale shakers 16 and is directed into mud pit 12. Although such “free” liquids are separated at the shale shakers, the drill cuttings still frequently contain entrained and/or adherent fluids. These drill cuttings pass over shale shakers 16 and can then be discharged from the shale shakers 16 to an optional separation apparatus 17 and can then be discharged and contained in a collection box 18. The optional separation apparatus 18 can include, or work in conjunction with, a vacuum 19. Drilling fluid that is separated from the separation apparatus 17 and vacuum 19 can then be sent back to the mud pit 12 for further use.

For reasons described above, drill cuttings discharged from shale shakers 16 generally cannot simply be re-introduced into the active mud system and pumped back into a well. Accordingly, such drill cuttings must be treated and/or disposed of properly. In many cases, it is possible to collect such drill cuttings for transportation and eventual disposal. However, it is frequently beneficial to dispose or use the cuttings at the drilling rig location and avoid the transportation and offsite disposal of said cuttings.

The exemplary methods and compositions disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed compositions. For example, and with reference to FIG. 2, the disclosed methods and compositions may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary fracturing system 20, according to one or more embodiments. In certain instances, the system 20 includes a fracturing fluid producing apparatus 25, a fluid source 30, a proppant source 40, and a pump and blender system 50 and resides at the surface at a well site where a well 60 is located. In certain instances, the fracturing fluid producing apparatus 25 combines a gel pre-cursor with fluid (e.g., liquid or substantially liquid) from fluid source 30, to produce a hydrated fracturing fluid that is used to fracture the formation. The hydrated fracturing fluid can be a fluid for ready use in a fracture stimulation treatment of the well 60 or a concentrate to which additional fluid is added prior to use in a fracture stimulation of the well 60. In other instances, the fracturing fluid producing apparatus 25 can be omitted and the fracturing fluid sourced directly from the fluid source 30. In certain instances, the fracturing fluid may comprise water, a hydrocarbon fluid, a polymer gel, foam, air, wet gases and/or other fluids.

The proppant source 40 can include a proppant for combination with the fracturing fluid. In an embodiment the proppant source 40 can include ground drilling cuttings. The system may also include additive source 70 that provides one or more additives (e.g., gelling agents, weighting agents, and/or other optional additives) to alter the properties of the fracturing fluid. For example, the other additives 70 can be included to reduce pumping friction, to reduce or eliminate the fluid"s reaction to the geological formation in which the well is formed, to operate as surfactants, and/or to serve other functions.

The pump and blender system 50 receives the fracturing fluid and combines it with other components, including proppant from the proppant source 40 and/or additional fluid from the additives 70. The resulting mixture may be pumped down the well 60 under a pressure sufficient to create or enhance one or more fractures in a subterranean zone, for example, to stimulate production of fluids from the zone. Notably, in certain instances, the fracturing fluid producing apparatus 20, fluid source 30, and/or proppant source 40 may be equipped with one or more metering devices (not shown) to control the flow of fluids, proppants, and/or other compositions to the pumping and blender system 50. Such metering devices may permit the pumping and blender system 50 can source from one, some or all of the different sources at a given time, and may facilitate the preparation of fracturing fluids in accordance with the present disclosure using continuous mixing or “on-the-fly” methods. Thus, for example, the pumping and blender system 50 can provide just fracturing fluid into the well at some times, just proppants at other times, and combinations of those components at yet other times.

The well is shown with a work string 112 extending from the surface 106 into the well bore 104. The pump and blender system 50 is coupled a work string 112 to pump the fracturing fluid 108 into the well bore 104. The working string 112 may include coiled tubing, jointed pipe, and/or other structures that allow fluid to flow into the well bore 104. The working string 112 can include flow control devices, bypass valves, ports, and or other tools or well devices that control a flow of fluid from the interior of the working string 112 into the subterranean zone 102. For example, the working string 112 may include ports adjacent the well bore wall to communicate the fracturing fluid 108 directly into the subterranean formation 102, and/or the working string 112 may include ports that are spaced apart from the well bore wall to communicate the fracturing fluid 108 into an annulus in the well bore between the working string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or more sets of packers 114 that seal the annulus between the working string 112 and well bore 104 to define an interval of the well bore 104 into which the fracturing fluid 108 will be pumped. FIG. 3 shows two packers 114, one defining an uphole boundary of the interval and one defining the downhole end of the interval. When the fracturing fluid 108 is introduced into well bore 104 (e.g., in FIG. 2, the area of the well bore 104 between packers 114) at a sufficient hydraulic pressure, one or more fractures 116 may be created in the subterranean zone 102. The proppant particulates in the fracturing fluid 108 may enter the fractures 116 where they may remain after the fracturing fluid flows out of the well bore. These proppant particulates may “prop” fractures 116 such that fluids may flow more freely through the fractures 116.

While not specifically illustrated herein, the disclosed methods and compositions may also directly or indirectly affect any transport or delivery equipment used to convey the compositions to the fracturing system 20 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the compositions from one location to another, any pumps, compressors, or motors used to drive the compositions into motion, any valves or related joints used to regulate the pressure or flow rate of the compositions, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.

In an alternate embodiment, the fluid compositions of the invention may be employed as a lost circulation management solution. The thixotropic rheological behavior of the fluid compositions containing ground drilling cuttings enable placement of the fluid compositions with significant build-up of gel strength in regions of low-shear, e.g. lost circulation zones. The fluid lost circulation management solution of the invention may be pumped through a drill bit more easily than fluids containing course fiber or granular lost circulation materials.

Suitable gases for use in conjunction with the present invention may include, but are not limited to, nitrogen, carbon dioxide, air, methane, helium, argon, and any combination thereof. One skilled in the art, with the benefit of this disclosure, should understand the benefit of each gas. By way of nonlimiting example, carbon dioxide foams may have deeper well capability than nitrogen foams because carbon dioxide emulsions have greater density than nitrogen gas foams so that the surface pumping pressure required to reach a corresponding depth is lower with carbon dioxide than with nitrogen. Moreover, the higher density may impart greater proppant transport capability, up to about 12 lb of proppant per gal of fracture fluid.

An embodiment of the present invention is a method that involves providing a treatment fluid that contains an aqueous base fluid along with ground drilling cuttings and placing the treatment fluid in a subterranean formation. The treatment fluid can be selected from drilling fluids, spacers, flushes, and efficiency fluids. In an embodiment the treatment fluid is a lost circulation management solution. The ground drilling cuttings can provide the treatment fluid a thixotropic rheological behavior which can provide significant build-up of gel strength in regions of the subterranean formation having low-shear or alternately regions of the subterranean formation having lost circulation zones. In optional embodiments the ground drill cuttings serve as a weighting agent, scouring agent or as a lost circulation control agent. The embodiment can include the mixing of the treatment fluid using mixing equipment and can also include introducing the treatment fluid into a subterranean formation using one or more pumps.

An embodiment of the present disclosure is a method that includes providing a treatment fluid selected from the group comprising drilling fluids, spacers, flushes, and efficiency fluids, the treatment fluid comprising an aqueous base fluid and ground drilling cuttings and placing the treatment fluid in a subterranean formation wherein the ground drilling cuttings provides the treatment fluid a thixotropic rheological behavior that provides significant build-up of gel strength in regions of the subterranean formation having low-shear. The embodiment can include the mixing of the treatment fluid using mixing equipment and can also include introducing the treatment fluid into a subterranean formation using one or more pumps.

And then the monsoon came, and mud was all over the bike while riding in and after rain. Bought Carbon Racing front mud guard extender and taped it using 3M high strength bonding tape. For the rear did a jugaad setup with the hard plastic cover of a classmates notebook. Both have held well to this date and doing duty just fine.