Selection of shale shakers

Most drilling rigs are equipped with at least one shale shaker. The purpose of a shale shaker, as with all drilled-solids removal equipment, is to reduce drilling cost. Most drilling conditions require limiting the quantity and size of drilled solids in the drilling fluid. Shale shakers remove the largest drilled solids that reach the surface. These solids are the ones that can create many well-bore problems if they remain in the drilling fluid.


WARNING: Electrical Hazard—follow ALL national electric codes, local electric codes, and manufacturer’s safety and installation instructions. Always conform to regulatory codes, as apply regionally and internationally

1. Selection of Shaker Screens
Some proprietary computer programs are available that reportedly allow predictions of screen sizes used on some shale shakers. Most of these computer programs have been verified with data taken from laboratory-prepared drilling fluid with limited property variation. Different drilling-fluid ingredients can reduce the capacity of a shaker system. For example, a drilling fluid containing starch is difficult to screen because starch, acting as a good filtration control additive, tends to plug small openings in screens. Drilling fluids with high gel strengths are also difficult to screen through fine screens. No charts will be presented here that purport to predict screen sizes that will handle certain flow rates. Screen selection for various shale shakers is primarily a trial-and-error evaluation. The best advice is to contact the manufacturer for recommendations for various geographical areas.
2. Cost of Removing Drilled Solids
Few wells can be drilled without removing drilled solids. However, even for 3000- to 4000-ft wells, one problem created by drilled solids, such as lost circulation, stuck pipe, or a well-control problem, will more than nullify the modest savings resulting from the decision not to properly process the drilling fluid. In expensive operations, the proper use of solids-removal equipment will significantly reduce drilling costs.
Although drilled solids can be maintained by simply diluting the drilling fluid to control the acceptable level or concentration of drilled solids, the expense and impracticality of this approach are evident using the following example. A 12(1/4)-inch-diameter hole 1000 feet deep will contain about 144 barrels of solids. If these solids are to be reduced to a 6% volume target concentration, they must be blended into a 2400-barrel slurry. To create the 2400 barrels, the 144 barrels of drilled solids must be added to 2256 barrels of clean drilling fluid:
(144 bb/2256 + 144 bbl)= 6% volume
Not only would the cost of the clean drilling fluid be prohibitive, but most drilling rigs do not have the surface volume to build 2256 barrels of clean drilling fluid for every 1000 feet of hole drilled. (See Chapter 15 for a complete discussion of dilution calculations.)
Remove as many drilled solids as possible with the shale shaker. Shakers are a very important component of this process, but they are still only one component of a complete drilled-solids removal system. All of the system must be operated with careful attention to details to develop the most efficient drilled-solids removal. Complete processing will decrease the cost of building excess drilling fluid. Proper drilledsolids control is directed primarily at reducing the cost of drilling.
3. Specific Factors
Some specific factors that should be considered when designing the shale shaker system are flow rate, fluid type, rig space, configuration/power, elevation available, discharge dryness (restrictions).
Most programs extrapolate laboratory-generated performance curves to predict field performance. Unfortunately, laboratory-manufactured drilling fluid does not duplicate properties of a drilling fluid that has been used in a well. High shear rates through drill-bit nozzles at elevated temperatures produce colloidal-size particles that are not duplicated in surface-processed drilling fluid.
Flow Rate
The flow rate that a particular shaker/screen combination can handle depends greatly on the flow properties of the drilling fluid. The lower the values of PV, YP, gel strength, and mud weight, the finer the screen opening sizes that can be used on a shale shaker. The conductance of the shaker screen provides a guide for the fluid capacity but does not reveal how the screen will actually perform. Screens with the same conductance may not be able to handle the same flow rate if used on different shale shakers.
Shaker screen selection programs have been developed by several companies to predict the quantity of solids that can be removed from a drilling fluid by various shaker screens on specific commercial shakers. Most programs start by assuming that the flow rate of drilled solids reaching the surface is identical to the generation rate of the drilled solids. Unfortunately, many drilled solids are stored in the well bore and do not reach the surface in the order in which they are drilled. Frequently, in long intervals of open hole, as many drilled solids enter the drilling fluid from the sides of the well bore as are generated by a drill bit.
One proposed relationship shows that the maximum flow rate (Q) that can be handled by a shaker is inversely proportional to the product of the PV and mud weight and proportional to the screen conductance (K). This relationship would answer the question, If a linear motion shale shaker is handling 1250 gpm of a 10.3-ppg drilling fluid with a PV of 10 cP on a 120 square MG mesh screen, what flow rate could be handled on a 200 square MG mesh screen if the mud weight were increased to 14.0 ppg and the PV becomes 26 cP
Q2=[(1.24 kd/mm)(10 cP)(10.3 ppg)/(0.68 kd/mm)(26 cp)(14.0 ppg)]*1250 gpm
The problem with this equation is that it fails to account for other rheological variables. For example, if the gel strength of the 10.3-ppgdrilling fluid were increased significantly, the shaker could no longer handle the fluid. Some shakers might handle 750 gpm of an 11.0-ppg drilling fluid with a certain PV. If PHPA or a high concentration of starch is added to this fluid, the shaker capacity might be only 350 gpm. In both cases, the PV would change very little but would have a significant effect on the screening capability. If there are no other property changes in a drilling fluid except mud weight and PV, the preceding equation can help predict what flow rate can be handled.
Rig Configuration
On some drilling rigs, the derrick rig floor is not high enough to allow some shale shakers to be used because the flow line is not high enough. Small land rigs frequently have difficulty positioning larger shale shakers so that the flowline has sufficient slope to prevent fluid from overflowing the bell nipple. Whichever shaker or shakers are used, consideration must be given to providing sufficient safe power to the shaker motors. Check with the manufacturer about electrical service needed for the
shaker used.
Discharge Dryness
In some areas, drilled solids and drilling fluid cannot be discarded at the rig location. This applies to both land and offshore rigs. In some areas, the cost of handling discarded material may require drying the discard. The fine screens discharge much wetter solids than do very coarse screens. Hence, fine-screen discharge may require additional processing with dryers or dewatering techniques.

Shale shaker power system

The most common power source for shale shakers is the rig electrical power generator system. The rig power supply should provide constant voltage and frequency to all electrical components on the rig. Most drilling rigs generate 460 alternating-current-volt (VAC), 60 Hz, 3-phase power or 380 VAC, 50 Hz, 3-phase power. Other  common voltages are 230 VAC, 190 VAC, and 575 VAC. Through transformers and other controls, a single power source can supply a variety of electrical power to match the requirements of different rig components.
Shale shakers should be provided with motors and starters to match the rig generator output. Most motors are dual wound. These may be wired to use either of two voltages and starter configurations. For example, some use 230/460VAC motors and some use 190/380VAC motors. Dual-wound motors allow the shaker to be operated properly with either power supply after relatively simple rewiring. Care must be taken, however, to make certain that the proper voltage is used. Electric-motor armatures are designed to rotate at a specific speed. Typically the rotational speed is 1800 rpm for 60-Hz applications and 1500 rpm for 50-Hz applications.
Shale shakers use a vibrating screen surface to conserve the drilling fluid and reject drilled solids. The effects of this vibration are described in terms of the g factor, or the function of the angular displacement of a screen surface and the square of the rotational speed. (For a detailed discussion, see the preceding section on g factor.)
Angular displacement is achieved by rotating an eccentric mass. Most shale shakers are designed to be operated at a specific, fixed g factor by matching the stroke to a given machine’s rotational speed. It follows that any deviation in speed will affect the g factor and influence the shaker performance.
Deviations in speed may be caused by one or more factors but typically are caused by fluctuations in voltage or the frequency of the alternating current. If the voltage drops, the motor cannot produce the rated horsepower and may not be able to sustain the velocity needed to keep the eccentric mass moving correctly. Low voltage also  reduces the life of electrical components. Deviations in frequency result in the motor turning faster (frequencies higher than normal) or slower (frequencies lower than
normal). This directly influences rpm and shaker performance.
Slower rpm for a particular motor reduces the g factor and causes poor separation and poor conveyance. Faster rpm increases the g factor and may improve conveyance  and separation, but can destroy the machine and increases screen fatigue failures. In extreme cases, higher rpm may cause structural damage to the shale shaker. Thus, it is important to provide proper power to the shale shaker.
For example, a particular shale shaker is designed to operate at 4 g’s. The shaker has an angular displacement, or stroke, of 0.09 inches. This shaker must vibrate at 1750 rpm to produce 4.1 g’s. At 60 Hz, the motor turns at 1750 rpm, so the g factor is 4.1, just as designed. If the frequency drops to 55 Hz, the motor speed reduces to 1650 rpm, which results in a g factor of 3.5. Further reduction of frequency to 50 Hz results in 1500 rpm and a g factor of 2.9.
Most rigs provide 460 VAC, 60 Hz power, so most shale shakers are designed to operate with this power supply. However, many drilling rigs are designed for 380- VAC/50-Hz electrical systems. To provide proper g factors for 50-Hz operations, shale shaker manufacturers rely on one of two methods: increasing stroke length or  using voltage/ frequency inverters (transformers).
A motor designed for 50-Hz applications rotates at 1500 rpm. At 0.09-inch stroke, a shale shaker will produce 2.9 g’s. Increasing the stroke length to 0.13 inches provides 4.1 g’s, similar to the original 60-Hz design. However, the longer stroke length and slower speed will produce different solids-separation and conveyance  performance. At the longer stroke lengths, shakers will probably convey more solids and have a higher fluid capacity. Conversely, instead of increasing the stroke length, some manufacturers use voltage inverters to provide 460-VAC/60-Hz output power from a 380-VAC/50 Hz supply.
Constant electrical power is necessary for good, constant shale shaker performance. The tables below assist in designing a satisfactory electrical distribution system.
Alternating-current motors are common on most shale shakers. The motor rating indicates the amount of electrical current required to operate the motor. The values in Table 7.1 provide some guidelines for various motors. Be wary of all electrical hazards; follow all applicable regulatory codes, nationally, internationally, regionally, and locally, as well as manufacturer’s safety and installation instructions. The manufacturer’s recommendations should always take precedence over the generalized
values in these tables. The values in the tables are to be used as general guidelines only. Many factors, including insulating material and temperature, control the values.
The amount of electric current that a conductor (or wire) can carry increases as the diameter of the wire increases. Common approximate values for currents are presented with the corresponding wire size designation in Table 7.2. Conductors, even relatively large-diameter wire, still have some resistance to the flow of electric current. This resistance to flow results in a line voltage drop. When an electric motor is located in an area remote from the generator, the line voltage drop may decrease
the motor voltage to unacceptably low values. Some guidelines of wire diameter necessary to keep the voltage drop to 3% are presented in Table 7.3.

shale shaker power system

hp=horsepower; v=volts.
WARNING: Electrical Hazard—follow ALL national electric codes, local electric codes, and
manufacturer’s safety and installation instructions. Always conform to regulatory codes, as
apply regionally and internationally.

shale shaker design

AWG=American Wire Gauge.
WARNING: Electrical Hazard—follow ALL national electric codes, local electric codes, and
manufacturer’s safety and installation instructions. Always conform to regulatory codes,
as apply regionally and internationally.

Shale shaker design -g factor

The g factor refers to a ratio of an acceleration to Earth’s gravitational acceleration. Jupiter has a mass of 418.6*10^25 lb and Earth has a mass of 1.317*10^25 lb. A person on Earth who weighs 200lb would weigh 320 times as much on Jupiter, or 64,000 lb. A person’s mass remains the same on Earth or Jupiter, but weight is a force  and depends on the acceleration of gravity. The gravitational acceleration on Jupiter is 320 times the gravitational acceleration on Earth. The g factor would be 320. (As a point of interest, Mars has a mass of 0.1415*10^25 lb, so the g factor would be 0.107; a 200-lb person would weigh only 21.4 lb on Mars.)

Continue reading “Shale shaker design -g factor”

Shale shaker design-vibrating system

The type of motion imparted to the shale shaker depends on the location, orientation, and number of vibrators used. In all cases, the correct direction of rotation must be verified.
Unbalanced elliptical motion shakers use a single vibrator mounted above the shale shaker’s center of gravity. Integral vibrators, enclosed vibrators, and belt-driven vibrators are used for this shale shaker design.
Circular motion shale shakers use a single vibrator mounted at the shale shaker’s center of gravity. Belt-driven vibrators and hydraulic-drive vibrators are used for this shale shaker design.
Most linear motion shakers use two vibrators rotating in opposite directions and mounted in parallel, but in such a manner that the direction and angle of motion is achieved. Integral vibrators, enclosed vibrators, belt-driven vibrators, and gear-driven vibrators are used for this shale shaker design.
Balanced elliptical motion shakers use two vibrators rotating in opposite directions but at a slight angle to each other so that they are not parallel. These vibrators must be oriented correctly to achieve the direction and angle of motion desired. The elliptical motion traces must all lean toward the discharge end and not backward toward the possum belly. If two vibrators of different masses are mounted in the same manner as the linear motion vibrators (i.e., parallel), a balanced elliptical motion is also achieved.
Various vibrating systems are used on shale shakers. These systems include:
1. Integral vibrator: The eccentrically weighted shaft is an integral part of the rotor assembly in that it is entirely enclosed within the electric motor housing.
2. Enclosed vibrator: This is a double-shafted electric motor that has eccentric weights attached to the shaft ends. These weights are enclosed by a housing cover attached to the electric motor case.
3. Belt-driven vibrator: The eccentrically weighted shaft is enclosed in a housing and a shaft is attached to one end. A sheaved electric motor is used to rotate the shaft with a belt drive. The electric motor may be mounted alongside, above, or behind the shaker, depending on the model. It may also be mounted on the shaker bed along with the vibrator assembly.
4. Dual-shafted, belt-driven vibrator: This system is similar to that of the belt-driven vibrator except that it has two vibrator shafts rotating in opposite directions and is driven by one electric motor with a drive belt.
5. Gear drive: A double-shafted electric motor drives a sealed gearbox, which in turn rotates two vibrator shafts in opposite directions.
6. Hydraulic drive: A hydraulic drive motor is attached directly to a vibrator shaft, which is enclosed in a housing. The hydraulic motor must have a hydraulic power unit that includes an electric motor and a hydraulic pump. The hydraulic-drive motor powers the vibrator shaft.