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Inventory DCQJ250x2/100×10 Mud cleaner at a big discount

DCQJ250x2/100×10 Mud cleaner is one of the most hot sale model of mud cleaner equipment whose flow is about 240m3/h. At present DC Solid control has a finished mud cleaner at a big discount sale can meet your urgently requirements.


DC Mud Cleaner completes consist of everything you need to plumb up to and operate the equipment as it own stand alone unit. Just select the Mud Cleaner and Shaker combination you need based off of the flow rate you need to process and what micron level you need to cut to.

The unique manifold design minimizes the pressure drop across the hydrocyclones, thereby maximising solids removal and reducing the volume of mud discharged with the captured solids from the cone.

If you need to retain a larger capacity we are more than capable of constructing and fitting the equipment on any size mud cleaner you need.

Vertical cutting dryer working principle

Vertical cutting dryer is designed to reduce and recover base fluid from a variety of feed slurry. In drilling operations, typical solids control equipment discards 1-4 barrels of liquid for each barrel of solids removed.

Vertical Cutting Dryer uses centrifugal force to dry drilled solids in oil or synthetic base fluids. A stainless steel screen bowl traps “wet” solids and accelerates them up to 890RPM with G force up to 420. Liquid is forced through the screen bowl openings, while “dry” solids are extracted by the angled flights attached to the cone, which rotate slightly slower than the bowl.

vertical cutting dryer

Vertical cutting dryer improves overall cost-efficiency by recovering costly drilling fluids that is recovered from cuttings, as well as whole mud lost from shale shaker failure and rig motion. Further, the Vertical cuttings dryer produces lower waste volume by generating dryer solids in both oil and synthetic-based drilling mud system.

DCTLL-A915 vertical Cutting Dryer is the latest design from World top solids control manufacturer. This mechanism make vertical cutting dryer one of the industry’s best performing and most dependable cutting dryer. The Vertical Cutting Dryer gives operators a critical advantage in meeting increasingly stringent environmental rules for cuttings proposal.

Importance of use shear pump in solid control system

Shear Pump is new tape equipment which provides the fast configuration and treatment mud for the user, the user satisfy with configuration high performance mud. It can meet the requirements of customers with high-performance mud.

To improve the drill fluid properties, the polymers or clay should be highly sheared before adding them to the drill fluid system. The product can effectively mix and fully hydrate the material added into the drilling fluid, which can save the added polymer and shorten mud configuration time.

shear pumps

Structure features of drilling fluid shear pumps

1. Through special design, the impeller which is the main component of the mud shear pump has a wider flow path and smooth vanes.
2. The shaft of the product is designed with high strength to bear certain load.
3. With a hopper, mud gun and transfer line orifice plate available, the mud shear pump can be used as a belt driven or diesel driven package.
4. The pump is equipped with stainless steel turbine and a shear plate.
5. The turbine drilling mud shear pump installed in the special base ,and pulley, narrow V belt and 55KW/75kw explosion-proof motor drives

Function of shear pumps

1. Make the compounds dilute, shear and hydrate in a shorter time while saving over 30% of bentonites;.
2. Greatly enhance the hydration of the soil particles.
3. Shear pump can mix material effectively, fully hydrate material, save material using, shorten drilling fluid preparation time, supply good drilling fluid performance to drilling process.

How to improve shaker screen blinding

Screen blinding occurs when grains of solids being screened lodge in a screen hole. This often occurs when drilling fine sands, such as in the Gulf of Mexico. The following sequence is often observed during screen blinding:


1. When a new screen is installed, the circulation drilling fluid falls through the screen in a short distance.
2. After a time, the fluid endpoint travels to the end of the shaker.
3. Once this occurs, the screens are changed to eliminate the rapid discharge of drilling mud off the end of shaer.
4. After the screens have been washed, fine grains of sand that lodged in the screen surface can be observed. The surface of the screen will resemble fine sandpaper because of the sand particles lodged in the opening.


Most screens used in the oil field is blinded to some extent by the time it needs replacing. For this reason, when the same shaker screen size is reinstalled, the fluid falls through the screen closer to the feed.

One common solution to screen blinding is to change to a finer or coarser screen than the one being blinded. This tactic is successfully if the sand that is being drilled has a narrow size distribution. Another solution is to change to a rectangular screen, although rectangular screens can also blind with multiple grains of sand. Unfortunately, the process of finding a screen size that will not blind is expensive.

Why choose DC Desilters

Desilter is the third class solids control equipment to treat the drilling fluids. According to the size of the cone diameter, they are divided into Desander and Desilter. Desilters are designed to remove silt-sized (12-74 microns) solids from drilling fluids. DC desilters are simple to operate and easy to maintain.

The main parts of desilter is the hydrocyclone. The desilter is generally designed by with 10, 12, 16 or 20 cones, 4′ or 5″ in diameter. Each hydrocyclone is attached to a 6″ or 8″ manifold with a 2″ inlet and 2″ outlet. It has quick connect fittings on both inlet and outlet and the manifold ends.


The hydrocyclone is designed with a cylindrical feed section, a conical section leading to the solids discharge opening and an inward extending overflow outlet. Hydrocyclones are very effective classification devices which, as a result of centrifugal forces in the spinning fluid, cause solids to be separated at the under flow. Hydrocyclones are simple and inexpensive devices relative to the amount of material they remove.


DC’s polyurethane hydrocyclone offers a high volume 4” cone, while providing contractors an economical replacement for less efficient older equipment. DC hydrocyclones are manufactured using a specially formulated EU polyurethane which has excellent resistance to heat and abrasion.

How to Best Maintain Drilling Fluid Centrifuge During Use

Decanter Centrifuge(VFD) DCLW360-1200N

In drilling operation, drilling fluid centrifuge is one of the core equipment that is often used, it is mainly used for separating fine solid particles whose diameters are 2-7 μm from the drilling fluid, the use of drilling fluid centrifuge can effectively protect the drill bit, and also has a very important role in improving drilling speed. With the oil drilling industry technology is getting mature, drilling fluid centrifuge manufacturing technology has been greatly improved. However, some inherent mechanical problems are still not solved and continue to haunt users.

So, what are these problems?
Mainly for the below:
1. Bowl fault.
2. Wearing parts (inlet pipe, shockproof strip) problem.
3. Excessive vibration.
4. Outlet blocking.
5. Explosion-proof plug damage.
6. Centrifuge scroll wear.
7. Bearings failure in the process of using.
8. Drilling fluid centrifuge hose damage.

So how should we maintain the drilling fluid centrifuge during using?

The first point: the use of staff must be regular maintenance on the centrifuge, regular cleaning the inlet and outlet, add grease to the bearing parts;

The second point: regular inspect easy damaged parts on the drilling fluid centrifuge, like hoses. In order to ensure the process in the use of these parts is not a problem which influences the production. Finally, electronic products and TV sets, reduce the on-off times, when drilling fluid centrifuge started, preferably every 8 hours rather than an hour on drilling fluid centrifuge to start. Do all of the above, then you’ll find out centrifuge failure rate will be greatly reduced in use.

Drilling Fluid Management During Horizontal Directional Drilling

Drilling Fluid Management

Horizontal Directional Drilling (HDD) is a trenchless construction solution to traditional open-cut methods used for utility conduit installation. Over the past four decades, advancements in HDD have made it an effective and common installation method, particularly in congested urban areas and environmentally sensitive areas, such as beneath rivers and wetlands, as it minimally impacts surroundings. The HDD process includes pilot boring, reaming, and product pullback.

Drilling fluid is used in all the three stages of HDD, functioning to: provide stability to the borehole, especially in collapsible soil and porous medium; decrease the frictional drag between the pipe and the borehole; cool the drill bit during excavation, and transport drill cuttings to the ground surface. Drilling fluid generally comprises an admixture of water and bentonite, and different types of additive can also be used to improve the fluid’s capacity to carry the cutting soils out of the borehole. Figure 1 shows the first stage of HDD in which the borehole is excavated with a mechanical cutting structure and the cutting soils are transported to the ground surface by means of hydraulic transmission (circulation of drilling fluid).

The drilling fluid pressure in the borehole must be high enough to provide borehole stability and adequate circulating pressure for cutting transport out of the borehole. However, excessively high drilling fluid pressure can also cause hydraulic fracture and release of drilling fluid to the ground surface, which is a critical issue encountered during HDD. This phenomenon occurs when drilling fluid pressure exceeds the shear strength of the surrounding soil, which causes cracks to propagate to the ground surface. Penetration of the drilling fluid into the cracks leads to operational (loss of drilling fluid, collapse of the borehole, bit balling, and circulating pressure loss) and negative environmental impacts. Figure 2 illustrates the growth of the crack around the borehole during pilot boring. Hydraulic fracture is the greatest concern in the first stage of the boring process, as it has lower annulus areas compared to the reaming stage. Therefore, higher interaction between drilling fluid particles in lower annulus areas causes an increase in annular pressure.

Drilling fluid management is a technique employed during HDD to maintain a proper drilling fluid pressure, which prevents mud loss failure and provides stability through the borehole. HDD contractors and engineers should consider applying a drilling fluid management system to achieve a targeted drilling fluid rheology and to predict the mechanical behavior of drilling fluid as it interacts with soil in the borehole. Effective drilling fluid management provides the necessary information to monitor and control risk events resulting from elevated annular pressures during HDD construction. To accomplish this, the circulating drilling fluid pressure (plan pressure) must be predicted, which can be done via the appropriate flow model and associated parameters.

Centrifugal Pump’s Impeller Designs and Casing Functions

centrifugal pumps

An oilfield solids control system needs many centrifugal pumps to sit on or in mud tanks. Hydraulic performance of a centrifugal pump determines its working efficiency. Two basic components of a centrifugal pump that are related to hydraulic performance are the impeller and casing.

There are three basic impeller designs:
. a closed impeller that has a shroud (rotating wall) on both the front and the back of the impeller,
. a semi-open impeller that has a shroud on one side and is closely fitted to the stationary wall of the casing on the other side, and
. an open impeller that may or may not have part of a shroud on one side and is closely fitted to the casing wall on the other side.

As fluid approaches the pump suction, it is assumed to have very little to no rotational velocity. When fluid enters rotating passages of the impeller, it begins to spin at the rotating velocity of the impeller. Fluid is forced outward from the center of the impeller, and its rotating velocity increases in direct proportion to the increasing impeller diameter. It should be noted that head produced by a centrifugal pump is a function of fluid velocity and is not dependent (normally) on the fluid being pumped. For example, a pump that will produce 100 feet of head on water (8.34 lb/gal) will also produce 100 feet of head on gasoline (6.33 lb/gal).

The function of the pump casing is to
1. direct fluid into the eye of the impeller through the suction inlet,
2. minimize fluid recirculation from impeller discharge to impeller suction, and
3. capture fluid discharge from the impeller in the case volute to most efficiently utilize work performed by the impeller and direct fluid away from the impeller.

The impeller performs useful work and increases the head of the fluid. The casing consumes part of the work imparted to the fluid and creates head losses due to friction, eddies, and other flow characteristics. A good casing design will minimize the losses, as opposed to a bad casing design. However, no casing design will increase pump head above what exists at the discharge of the impeller. Typically a centrifugal pump casing is designed so that the suction flange is one or two pipe sizes larger than the discharge flange. This is done to manage velocity of the fluid as it approaches the impeller inlet and also to minimize friction losses ahead of the pump. Excessive losses on the suction side of a pump can cause severe and rapid damage to the pump impeller and casing.

What is hydrocyclone and structure

Hydrocyclones use the centrifugal separation principle to remove or classify suspended solids in a slurry.

The hydrocyclone is a closed vessel designed to convert incoming liquid velocity into rotary motion. It does this by directing inflow tangentially near the top of a vertical cylinder. This spins the entire contents of the cylinder, creating centrifugal force in the liquid. Heavy components move outward toward the wall of the cylinder where they agglomerate and spiral down the wall to the outlet at the bottom of the vessel. Light components move toward the axis of the hydrocyclone where they move up toward the outlet at the top of the vessel.


The Volute feed inlet prevents the slurry from circulating back into the path of the incoming slurry, causing undesirable turbulence that reduces separation efficiency.

The Fluted Vortex Finder shape increases the momentum as the incoming slurry swirls around the increasing cross-sectional area, causing a more rapid separation of the suspended solids. This also prevents larger particles from “short circuiting” and reporting out the Vortex Finder with the liquid phase and smaller particles.


The Non-plugging discharge Apex has a non-circular orifice configuration with a central core and lobes surrounding the central core. As the solids report out the Apex discharge, the surrounding lobes will cause any central core plugging to wash through by producing a differential pressure region.

The inner liner of polymer hydraulic cyclone uses abrasion-resistant and ageing-resistant material polyurethane(PU). This kind of material can reduce the abrasion of equipment and makes this type of device much more durable in use.

How Are Wells Typically Drilled?

The conventional process of drilling oil and gas wells uses a rotary drill bit that is lubricated by drilling fluids or muds. As the drill bit grinds downward through the rock layers, it generates large amounts of ground-up rock known as drill cuttings. This section of the Drilling Waste Management Information System website discusses several alternative drilling practices that result in a lower volume of waste being generated.

Oil and gas wells are constructed with multiple layers of pipe known as casing. Traditional wells are not drilled from top to bottom at the same diameter but rather in a series of progressively smaller-diameter intervals. The top interval is drilled starting at the surface and has the largest diameter hole. Drill bits are available in many sizes to drill different diameter holes. The hole diameter can be 20″ or larger for the uppermost sections of the well, followed by different combinations of progressively smaller diameters. Some of the common hole diameters are: 17.5″, 14.75″, 12.25″, 8.5″, 7.875″, and 6.5″.

After a suitable depth has been reached, the hole is lined with casing that is slightly smaller than the diameter of the hole, and cement is pumped into the space between the wall of the drilled hole and the outside of the casing. This surface casing is cemented from the surface to a depth below the lowermost drinking water zone. Next, a smaller diameter hole is drilled to a lower depth, and another casing string is installed to that depth and cemented. This process may be repeated several more times. The final number of casing strings depends on the regulatory requirements in place at that location and reflects the total depth of the well and the strength and sensitivity of the formations through which the well passes.

Historically, wells were drilled to be relatively vertical and were completed at a depth to intersect a single formation. Thus, one full well was required for each completion. Modern technology allows modifications to several aspects of this procedure, thereby allowing more oil and gas production with less drilling and less waste generation. The following sections describe how drilling can be done to intersect multiple targets from the same main well bore, how wells can be drilled using smaller diameter piping in the wells, how drilling can be done using techniques that minimize the amount of drilling fluid, and drilling fluid systems that generate less waste. The U.S. Department of Energy describes these and other environmentally friendly oil field technologies in a 1999 report, “Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology” (DOE 1999).

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