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Solids Control
نویسنده : رضا سپهوند - ساعت ۱٢:٤٩ ‎ب.ظ روز ۱۳٩٤/٧/٥
 

Solids Control
Solids Control 8.1 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
The types and quantities of solids present
in drilling mud systems determine
the fluid’s density, viscosity, gel strengths,
filter-cake quality and filtration control,
and other chemical and mechanical
properties. Solids and their volumes also
influence mud and well costs, including
factors such as Rate of Penetration
(ROP), hydraulics, dilution rates, torque
and drag, surge and swab pressures, differential
sticking, lost circulation, hole
stability, and balling of the bit and the
bottom-hole assembly. These, in turn,
influence the service life of bits, pumps
and other mechanical equipment.
Chemicals, clays and weight materials
are added to drilling mud to achieve
various desirable properties. Drill solids,
consisting of rock and low-yielding
clays, are incorporated into the mud.
These solids affect many mud properties
adversely. Nevertheless, since it is
not possible to remove all drill solids —
either mechanically or by other means
— they must be considered a continual
contaminant of a mud system.
Solids removal is one of the most
important aspects of mud system control,
since it has a direct bearing on
drilling efficiency. Money spent for
solids control and for solving problems
related to drill solids represents a significant
portion of overall drilling costs.
Solids control is a constant problem —
every day, on every well.
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The types and
quantities of
solids present
in drilling
mud systems
determine
the fluid’s
density…
0 10 11 12 13 14 15 16 17 18
Mud weight (lb/gal)
Recommended range — field muds
Maximum solids — water and clay only
Minimum solids — water and barite only
50
45
40
35
30
25
20
15
10
5
0
Figure 1: Recommended range of solids in water-base muds.
Introduction
Solids volume (%)
Drilling mud solids may be separated
into two categories: Low-Gravity Solids
(LGS), with Specific Gravity (SG) in the
2.3 to 2.8 range, and High-Gravity Solids
(HGS), with SG of 4.2 or higher. Weight
materials such as barite or hematite
comprise the HGS category and are
used to achieve densities greater than
10.0 lb/gal (SG>1.2). Drill solids, clays
and most other mud additives fall into
the LGS category and often are the
only solids used to obtain densities up
to 10.0 lb/gal (SG <1.2). Figure 1 shows
the recommended range of total solids
content for water-base muds.
Fundamentals
Solids Control
CHAPTER
8
Solids Control 8.2 Revision No: A-0 / Revision Date: 03·31·98
Solids control is accomplished by
using one or more of the basic methods
of solids separation:
• Settling.
• Screening.
• Hydrocyclones.
• Rotating centrifuges.
Hydroclones and centrifuges use
centrifugal force to obtain higher rates
of separation than can be achieved by
gravitational settling. These methods
are similar to settling and are governed
by well-known laws of physics. If the
mud is kept moving so that the gel
strengths are broken, then the settling
of particles is governed by Stokes’ law,
which is:
gc Ds
2 V (rs – rL) s = 46.3 μ
Where: Vs = Slip or settling velocity
(ft/sec)
gc = Gravity constant (ft/sec2)
Ds = Diameter of the solid (ft)
rs = Density of solid (lb/ft3)
rL = Density of liquid (lb/ft3)
μ = Viscosity of liquid (cP)
This equation is a mathematical
expression of events commonly
observed; i.e., the larger the difference
between the density of the solid and
the density of the liquid (rs – rL), the
faster the solid will settle; the larger
a particle (Ds), the faster it settles; and
the lower the liquid’s viscosity (μ), the
faster the settling rate. Also, if force
acting on the particles (gc) can be
increased mechanically, the settling
rate is increased proportionally. For
centrifugal motion like that found in
hydroclones and centrifuges, the separating
force is proportional to the
diameter of circular motion times the
square of the rotating speed (RPM)
times the mass of the particle.
Field observations verify that low
mud viscosity, combined with a low
mud flow rate, promote the settling
of larger and heavier solids. Therefore,
the removal of sand and drill cuttings
by settling or centrifugal force is practical
and beneficial. If the mud contains
barite, however, then it may settle, too.
The only way that all drill solids could
be separated from all barite would be
for all drill solids to be of one size and
for all barite to be of a completely
different size and mass. Stokes’ law shows
that particles of different densities and
size, with the same mass (density times
volume), have exactly the same settling
rate. For example, a sand or shale particle
(SG 2.6) which is about 11⁄2 times
larger than a given particle of barite
(SG 4.2), will settle at about the same
rate (11⁄2 x 2.6 = 3.9), regardless of
where it is — settling pit, hydroclone
or centrifuge. From a solids-separation
point of view, it would be impossible
to separate a 60-micron shale particle
from a 40-micron barite particle, using
settling techniques.
Hydroclones and/or centrifuges are
not perfect in separating unwanted
solids from the mud. However, the
advantages presented by such equipment
far outweigh the limitations. Each
piece of solids-control equipment is
designed to remove a sufficient quantity
of target solids to keep drill solids at
a manageable level. All mechanical
solids-control equipment is designed to
separate a certain range of particle sizes.
It is important to use the right combination
of equipment for a particular
situation and to have it operating and
arranged in the correct manner.
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Solids Control
Solids Control 8.3 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
Figure 2: Classification of particle sizes.
Colloidal
0 2 74 2,000
Commercial barite
1 μ
15
37
45
75
150
180
250
300
420
595
841
2 3 4 5 6 7 8 9 2 3 4 5 6 7 8 9 2 3 4 5 6 7 8 9 2 3 4 5 6 7 8 9
10 μ 100 μ 1,000 μ (1mm) 10,000 μ
(1cm)
Sand
Shale shaker
Hydrocyclones
Decanting centrifuge
Silt Gravel
μ
Screen mesh
2,000
400
325
200
100
80
60
50
40
30
20
10
It is important
to
understand
how particle
sizes…are
classified…
It is important to understand how
particle sizes in drilling mud are classified
and the types of solids that fall
into each category. Particles in drilling
mud can range from very small clays,
(less than 1/25,400th of an inch), to
very large drill cuttings (larger than an
inch). Due to the extremely small particles,
sizes are expressed in micron
units. A micron is one-millionth of a
meter (1/1,000,000 or 1 x 10 -6 m). So,
1 in. equals 25,400 microns.
Drilling fluid solids are classified
according to size in the following
categories:
Table 1 and Figures 2 and 3 relate
particle sizes to familiar terms, typical
examples, screen mesh equivalents
and to the solids-control equipment
that will remove a given particle size.
Screen mesh is important because it
determines the separation size for shale
shakers. Figure 3 is a magnified drawing
to show screen sizes increasing from 20
to 325 mesh and the equivalent particle
size (in microns) that will pass through
each screen. A 200-mesh screen is used
for the API Sand Test, in which all particles
that do not pass through the screen
(>74 microns) are classified as sand.
Ninety-seven percent of good-quality
barite (<74 microns) will pass through
200-mesh screens and 95% will pass
through 325-mesh (<44 microns)
screens. Thus, most barite is in the
same size category as silt. Premium
clays, such as M-I GEL,T fall in the
colloidal range, i.e., 2 microns or less.
The grouping of solids according to
size does not take into account the
Classification of Particle Sizes
Table 1: Classification of solids by size.
Category Size Example
Colloidal 2 μ or less Bentonite, clays and ultra-fine drill solids
Silt 2 – 74 μ Barite, silt and fine drill solids
(< 200 mesh)
Sand 74 – 2,000 μ Sand and drill solids
(200 – 10 mesh)
Gravel Larger than 2,000 μ Drill solids, gravel and cobble
(>10 mesh)
Solids Control
CHAPTER
8
Solids Control 8.4 Revision No: A-0 / Revision Date: 03·31·98
physical make-up of the material
being measured, even though the
terms “silt” and “sand” are used. For
instance, silt-size particles may include
shale, fine sand, fine carbonates and
barite. Sand-size particles may include
sand, shale, carbonates, drill cuttings
plus lost-circulation material, bridging
agents and coarse barite. Colloidal-size
solids include bentonite and other
clays; very fine drill solids (shale, sand
and carbonates); and fine barite.
Generally, the term “clay”, is used
to describe premium ground clay minerals,
such as Wyoming bentonite,
which are added to increase mud viscosity
and to improve the filter cake.
Drill cuttings, barite and other solids,
however, also will increase viscosity,
especially if the particle size degrades
into the colloidal range. Figure 4 illustrates
how particle size affects surface
area for a solid of a given volume. If
an original drill solid were a 40-micron
cube, it would have a surface area of
9,600 square microns. If this 40-micron
cube is allowed to degrade in size to
single 1-micron cubes, the number of
particles will now be 64,000 and the
surface area will increase to 384,000
square microns, 40 times the original.
During this particle size degradation, the
drill solid volume did not change. Keep
in mind that a single clay platelet is only
10 angstroms thick. One angstrom is
1/10,000 microns or 1 x 10 -10 m. If the
40-micron cube were allowed to break
down into clay platelet thickness pieces
40 microns square, the number of
particles would be only 40,000; however,
the surface area would increase
to 128,006,400 square microns, or
13,334 times the original surface area.
In a drilling mud, viscosity increases
proportionally with the surface area of
solids. The surface area of all solids
must be wetted. As the amount of liquid
is reduced due to increased surface
…the term
“clay”, is
used to
describe
premium
ground clay
minerals…
Figure 3: Screen mesh sizes vs. opening microns.
Screen size (mesh)
44 74 140 177 234 279 381 516 864
105 Equivalent opening size (μ)
864μ
516μ
381μ
279μ
234μ
177μ
140μ
105μ
74μ
44μ
20
30
40
50
60
80
100
150
200
325
Solids Control
Solids Control 8.5 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
area, fluid viscosity increases and performance
declines. Colloidal solids
produce most of the viscosity in drilling
muds due to this surface area
increase. For that reason, the volume
of colloidal-size solids contained in
drilling mud must be controlled for
the sake of economy and efficiency.
Methods of Solids Separation
Original drill solid
1, 40-μ cube
Surface area = 9,600 μ2
Broken in half on
each side
Broken in half again
on each side
8, 20-μ cubes
Surface area = 19,200 μ2
40μ 40μ
40μ
If allowed to degrade
into 1-μ cubes
64, 10-μ cubes
Surface area = 38,400 μ2
64,000, 1-μ cubes
Surface area = 384,000 μ2
(40 times original)
Figure 4: Effect of particle size on surface area.
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SETTLING PIT OR SAND TRAP
Settling pits are seldom used in modern
drilling operations; however, they
can be found from time to time. The
rate of solids settling in settling pits
or sand traps depends on (1) the size,
shape and specific gravity of the particles;
(2) the density of the drilling
fluid; (3) the viscosity of the drilling
fluid; (4) the type of fluid-flow regime;
and (5) the residence time in the pit.
According to Stokes’ law, effective
solids settling can be achieved only
when the fluid is in laminar flow.
Settling rates can be increased by
using low viscosities and low gel
strengths. Under plug flow or turbulent
flow conditions, minimal solids settling
occurs, with only the very large
particles tending to settle. On a drilling
rig with inferior shale shakers, a
sand trap or settling pit will remove
some of these large drill solids. Most
modern shale shakers will remove sandsize
and larger solids without the need
for sand traps and/or settling pits.
Solids-control equipment is rated by
the volume of mud it will process and
the amount and size of solids it will
remove. None of the solids-control
equipment used in drilling will remove
100% of the solids generated. To compare
the efficiency of solids-control
equipment, a cut point particle-size
rating is used. The cut point refers
Solids Control
CHAPTER
8
Solids Control 8.6 Revision No: A-0 / Revision Date: 03·31·98
to the combination of a micron size
and the percentage of that particle
size removed. Cut point designations
should include the percentage of the
stated size removed. Cut points should
always be denoted with the letter “D”
with a subscript indicating the percentage
removed. Without this percentage,
no two cut point sizes can be compared.
A D50 cut point of 40 microns means
that 50% of the 40-micron size particles
have been removed and 50% have
been retained in the mud system.
SHALE SHAKERS
The most important solids-control
devices are shale shakers, which are
vibrating screen separators used to
remove drill cuttings from the mud
(see Figure 5). As the first step in the
mud-cleaning/solids-removal chain,
they represent the first line of defense
against solids accumulation. Shale shakers
differ from other solids-removal
equipment in that they produce
nearly a 100% cut (D100) at the screen
opening size. As illustrated in Figure 3,
a 200-square-mesh shale shaker screen
will remove 100% of the solids greater
than 74 microns, thereby eliminating
the need for a desander. On the other
hand, today’s layered shaker screens,
hydroclones and centrifuges have variable
removal efficiencies for various
particle sizes and usually are given a
D rating (discussed later) for the target
particle size.
Many potential problems can be
avoided by observing and adjusting
the shale shakers to achieve maximum
removal efficiency for the handling
capacity. Using screens of the finest
mesh to remove as many drill solids as
possible on the first circulation from
the well is the most efficient method
of solids control. It prevents solids
from being re-circulated and degraded
in size until they cannot be removed.
As much as 90% of the generated
solids can be removed by the shale
Figure 5: Adjustable linear shaker.
Possum belly
Flow control gates
Mud and cuttings
Vibrating assembly
Mud return to pits Cuttings discharge
Mud and cuttings Flow line
Mud flows
through screen
to catch pan
The most
important
solids-control
devices are
shale
shakers…
Solids Control
Solids Control 8.7 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
shakers. Unless the shale shakers are
operating properly, and have screens of
the finest mesh possible, all other equipment
is subject to overloading and inefficient
operation (see Guidelines for
Proper Operation of Shale Shakers page
8.23). Shale shakers cannot remove silt
and colloidal-size solids, so dilution and
other equipment is required to control
ultra-fine drill solids.
Three basic types of shale shakers
are in use today. They are:
• The circular-motion shaker, which
is an older design on the market
and generally produces the lowest
centrifugal force, or G-force.
• The elliptical-motion shaker, which
is a modification of the circularmotion
type in which the center of
gravity is raised above the deck and
counter-weights are used to produce
an egg-shaped motion that varies in
both intensity and throw as solids
move down the deck.
• The linear-motion shaker, which
uses two circular-motion motors
mounted on the same deck. The
motors are set for opposite rotation
to produce a downward G-force and
an upward G-force when the rotations
are complementary, but no
G-force when the rotations are
opposed. The G-force on most
linear-motion shakers is variable
from about 3 to 6.
Each shaker has some design
advantages:
The circular-motion shaker has a
low G-force and produces a fast transport
(conveyance). This design works
well with sticky, clay-type solids by
reducing their impact into the screen
surface. This shaker has a low capacity
for drying cuttings, so wet cuttings are
commonly discharged.
The elliptical-motion shaker has
moderately high G-force and a slow
transport in comparison to the circular
or linear types. It produces the
greatest drying and, therefore, has
application in weighted mud or as a
mud cleaner to dry the underflow
from a desilter.
The linear-motion shaker is the most
versatile, producing fairly high G-force
and a potentially fast transport,
depending on the rotational speed,
deck angle and vibrator position.
Several different shaker types can be
combined in a “cascading arrangement”
to produce the greatest solids-removal
efficiency. Circular-motion shakers are
sometimes used as “scalping” shakers to
remove large, sticky solids. The fluid
then passes to an elliptical or linear
shaker with higher G-force to remove
the finer solids. This combination maximizes
removal by allowing finer-thannormal
mesh screens to be used on the
secondary shakers.
The mud flow should be spread over
as much of the screen surface as possible
by using feed-control gates located
between the possum belly (flow line-toshaker
transitional reservoir — see
Figure 5) and the screen surface. Ideally,
the mud should come to within 1 ft
of the end of the screens. Above all,
torn or damaged screens should be
replaced immediately. For shale shakers
designed with a negative slope, which
forms a mud pool in front of the possum
belly, beware of the potential for
backflow of mud behind the mud pool,
as well as the possibility that holes or
tears might exist in the screens covered
by the mud pool.
Occasionally, drill cuttings may be
of the same size as the screen openings
and will lodge in them. This is
known as blinding of the screen. It
will result in reduced screen capacity
and loss of whole mud. To correct this
problem, replace with a screen of finer
mesh. The finer screen should keep
the drill cuttings from plugging the
opening so that they will be transported
to the end of the shaker and
removed from the mud system.
Three basic
types of shale
shakers are
in use today.
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Solids Control 8.8 Revision No: A-0 / Revision Date: 03·31·98
SHAKER SCREENS
A shale shaker is only as good as the
mesh size and quality of its screen.
A number of screen types are available
today and performance varies.
For example, a 100-mesh “square”
screen removes 100% of the particles
greater than 140 microns, while a highflow-
rate, 100-mesh “layered” screen
removes 95% of the particles greater
than 208 microns. This layered-screen
performance is equal roughly to only
a 70-mesh “square” screen. Often, screen
selection is based on past experience,
which should be combined with knowledge
of the various screens and their
differences in design and capabilities.
Some general terms used when
describing shale shaker screens include:
Screen mesh: The number of openings
per linear inch. For example, a
30 x 30-mesh “square” screen has
30 openings along a 1-in. line in both
directions. A 70 x 30-mesh “oblong”
(rectangular opening) screen will have
70 openings along a 1-in. line one way
and 30 openings on a 1-in. line perpendicular.
Depending on the manufacturer,
wire size and weave, this 70 x
30-mesh screen may be described as: (1)
an “oblong” or “rectangular” 70-mesh
screen, (2) an “oblong 80” in an attempt
to rate the effective rectangular opening
in terms of a square equivalent or
possibly (3) a 100-mesh screen. Avoid
using mesh designations when comparing
screen types. In addition to mesh
count, various wire sizes and weave
patterns are used that affect the opening
size and flow-rate for a particular
mesh size. The 100-mesh square, layered,
oblong and bolted screens each
removes different particle sizes.
Separation efficiency or ‘cut
point’: It is no longer sufficient to
know a screen’s D50 cut point, because
many modern screen types do not
make a 100% cut. A D50 cut point represents
the particle size, where 50% of
the particles of that size are removed
by the solids-control device. The D subscript
refers to the percent removed, so
that in a D16 cut, 16% of the stated
micron size particles are removed and
D84 is the micron size where 84% of
the solids are removed. These D sizes
are determined from a particle size distribution
of the feed liquid and solids
discharge. The combination of the
screen D50 and the ratio of the D84
divided by the D16, gives a more complete
picture regarding separation efficiency.
The D84/D16 ratio indicates how
exact or “sharp” the cut point is —
where all of the solids down to a certain
size are removed but none of the
smaller particles are removed. A square
mesh market-grade screen makes a
sharp almost 100% cut point at the
opening size of the screen and the D50,
D84 and D16 values are all the same
micron size as the screen opening.
Therefore, the D84/D16 ratio is 1.0 for
square market-grade screens. It is most
desirable to have screens with a D84/D16
ratio near 1.0; values above 1.5 are undesirable.
The same D-type ratio applies
to hydroclones and centrifuges where
the ratio can be quite high, indicating
an inexact cut point (see Figure 8).
Open area: The area not taken up
by the wires themselves. An 80-mesh
screen with an open area of 46% will
handle a higher mud volume than an
80-mesh screen with an open area of
33%. The issue of open area must
include whether a screen is flat or threedimensional
(such as a corrugated
screen) and how much of that area
actually is processing fluid. Corrugated
or three-dimensional screens, on which
a significant portion of the screen area
always is exposed above the fluid, do
not actually help process fluid.
Conductance: The relative flow-rate
capacity or permeability per unit thickness
of a screen (as per API RP13E). This
is modeled on Darcy’s law. Various
manufacturers use different conductance
units, such as kilodarcy/cm
…D sizes are
determined
from a
particle size
distribution
of the feed
liquid and
solids
discharge.
A shale
shaker is
only as good
as the mesh
size and
quality of
its screen.
(kD/cm) or kD/mm, but it is helpful
to think of these values relative to
gallons per minute (gpm) per square
foot of screen. This number is particularly
useful in determining which
screen to use based on flow coverage
of the available screen area. For example,
if a particular mud system has
33% flow coverage for a 6.1 conductance-
rated, 50-mesh layered screen
and a 66% coverage is desired, then a
finer, 110-mesh, layered screen with a
conductance rating of 2.94 should be
used (66% ˜= 33% x (6.1/2.94)).
Although a screen of a certain mesh
may be preferred or specified by an
operator, keep in mind that the
different screen types and the difference
in manufacturers will cause different
levels of performance in screens designated
with the same mesh size. Screen
size selection depends on conditions
observed on location. If the volume of
fluid being circulated exceeds the capacity
of the screens (i.e., mud loss over
the screens), or if the flow coverage of
the screens is less than is desired, then
another mesh size should be used.
Tables 2 to 13 list shaker screen values
for U.S. standard sieve equivalents,
square mesh market screen and the three
most common screen series from several
different shale shaker manufacturers.
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Solids Control 8.9 Revision No: A-0 / Revision Date: 03·31·98
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Table 3: Square mesh market grade cloth.
Screen Equivalent U.S. Cut Point (μ) Open Area
Designation Sieve (mesh) D100 (%)
16 X 16 27 1,130 50.7
20 X 20 28 864 46.2
30 X 30 41 516 37.1
40 X 40 43 381 36.0
50 X 50 54 279 30.3
60 X 60 64 234 30.5
80 X 80 80 177 31.4
100 X 100 108 140 30.3
120 X 120 128 117 30.5
150 X 150 140 105 37.9
200 X 200 200 74 33.6
250 X 250 234 61 36.0
325 X 325 325 44 30.5
400 X 400 400 37 36.0
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U.S. Cut Point U.S. Cut Point
Sieve (μ) Sieve (μ)
(mesh) D100 (mesh) D100
3.5 5,660 40 420
4 4,760 45 350
5 4,000 50 297
6 3,360 60 250
7 2,830 70 210
8 2,380 80 177
10 2,000 100 149
12 1,680 120 125
14 1,410 140 105
16 1,190 170 88
18 1,000 200 74
20 840 230 62
25 710 270 53
30 590 325 44
35 500 400 37
Table 2: U.S. standard sieves.
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Solids Control 8.10 Revision No: A-0 / Revision Date: 03·31·98
Table 6: Advanced DX screens for Swaco ALS shakers.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
DX 50 47 324 234 390 6.77
DX 70 64 234 171 274 4.73
DX 84 79 181 131 223 3.65
DX 110 99 151 107 185 3.00
DX 140 127 118 86 143 2.33
DX 175 158 95 66 113 1.87
DX 210 185 81 57 100 1.67
DX 250 205 72 51 85 1.49
Table 7: Derrick PWP DX screens.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
PWP DX 50 48 318 231 389 6.10
PWP DX 70 58 220 158 269 4.18
PWP DX 84 78 181 127 218 3.53
PWP DX 110 100 149 105 184 2.93
PWP DX 140 125 120 86 143 2.29
PWP DX 175 156 96 70 118 1.77
PWP DX 210 174 86 60 104 1.59
PWP DX 250 213 69 49 84 1.39
Table 5: XL (Southwestern) screens for Swaco ALS shakers.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
XL 50 48 320 234 380 6.17
XL 70 73 200 150 241 3.76
XL 84 86 169 119 200 3.44
XL 110 97 153 107 182 2.75
XL 140 118 127 91 153 2.14
XL 175 152 98 70 117 1.78
XL 210 174 86 60 106 1.63
XL 250 215 68 48 82 1.21
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Table 4: Swaco screens for ALS shakers.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
ALS 50 48 320 234 380 6.17
ALS 70 73 200 150 241 3.76
ALS 84 86 169 119 200 3.44
ALS 110 97 153 107 182 2.75
ALS 140 118 127 91 153 2.14
ALS 175 152 98 70 117 1.78
ALS 210 174 86 60 106 1.63
ALS 250 215 68 48 82 1.21
Solids Control
Solids Control 8.11 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
Table 8: Derrick PWP HP screens.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
PWP HP 45 44 362 283 388 9.51
PWP HP 50 50 299 234 313 8.20
PWP HP 60 57 263 207 278 6.78
PWP HP 70 71 208 158 221 4.81
PWP HP 80 77 186 145 192 3.93
PWP HP 100 105 143 113 154 3.20
PWP HP 125 121 124 100 133 2.59
PWP HP 140 147 101 79 113 2.24
PWP HP 180 168 89 57 94 1.82
PWP HP 200 203 76 60 82 1.59
PWP HP 230 230 62 52 72 1.31
PWP HP 265 261 55 44 59 0.97
PWP HP 310 300 48 38 53 0.85
PWP HP 460 357 41 31 47 0.60
Table 9: Derrick PMD DX screens.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
PMD DX 50 48 318 231 389 6.10
PMD DX 70 58 220 158 269 4.18
PMD DX 84 78 181 127 218 3.53
PMD DX 110 100 149 105 184 2.93
PMD DX 140 125 120 86 143 2.29
PMD DX 175 156 96 70 118 1.77
PMD DX 210 174 86 60 104 1.59
PMD DX 250 213 69 49 84 1.39
Table 10: Derrick PMD HP screens.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
PWP HP 45 44 362 283 388 9.51
PWP HP 50 50 299 234 313 8.20
PWP HP 60 57 263 207 278 6.78
PWP HP 70 71 208 158 221 4.81
PWP HP 80 77 186 145 192 3.93
PWP HP 100 105 143 113 154 3.20
PWP HP 125 121 124 100 133 2.59
PWP HP 140 147 101 79 113 2.24
PWP HP 180 168 89 57 94 1.82
PWP HP 200 203 76 60 82 1.59
PWP HP 230 230 62 52 72 1.31
PWP HP 265 261 55 44 59 0.97
PWP HP 310 300 48 38 53 0.85
PWP HP 460 357 41 31 47 0.60
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Solids Control
CHAPTER
8
Solids Control 8.12 Revision No: A-0 / Revision Date: 03·31·98
Table 12: Southwestern (TBC replacement) screens for Thule VSM 100.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
52 49 311 222 344 4.65
84 70 212 N/A N/A 3.25
105 95 156 130 161 2.48
120 106 142 118 146 2.26
140 122 123 118 126 1.87
165 133 112 108 115 1.72
200 168 89 86 92 1.41
230 193 75 73 77 1.23
Table 13: BHX (blue hex) screens for Brandt ATL linear shakers.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
BHX 24 20 884 872 898 15.40
BHX 38 31 579 567 588 14.70
BHX 50 44 360 255 410 12.20
BHX 70 69 215 141 280 5.30
BHX 84 81 176 123 230 4.50
BHX 110 100 149 103 190 3.40
BHX 140 104 144 102 170 3.80
BHX 175 144 103 71 133 1.90
BHX 210 170 88 63 106 1.70
BHX 250 228 63 43 80 1.40
BHX 275 252 57 42 68 1.20
BHX 325 319 45 35 51 0.98
BHX 370 336 43 32 49 0.50
BHX 425 368 40 33 42 0.61
BHX 4750 N/A 28 21 32 0.15
Table 11: Thule TBC screens for VSM 100 shakers.
Screen Equivalent U.S. Cut Point (μ) Conductance
Designation Sieve (mesh) D50 D16 D84 (kD/mm)
TBC 52 49 311 222 344 3.99
TBC 84 70 212 N/A N/A 3.08
TBC 105 95 156 130 161 2.38
TBC 120 106 142 118 146 2.18
TBC 140 122 123 118 126 1.81
TBC 165 133 112 108 115 1.67
TBC 200 168 89 86 92 1.37
TBC 230 193 75 73 77 1.20
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Solids Control
Solids Control 8.13 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
WET CLASSIFICATION
Wet classification is the separation of
solids from a slurry according to particle
mass (size and density) by means
other than screening. All wet classifiers
separate solids based on the variables
described in Stokes’ law. Several
factors govern wet classification:
1. Coarser particles have a faster settling
rate than fine particles of the
same specific gravity.
2. High-gravity solids have a faster settling
rate than low-gravity solids of
the same size.
3. Settling rate becomes progressively
slower as the viscosity and/or density
of the mud increases.
Note: Frequently, centrifuges use
liquid dilution to reduce viscosity so
that smaller-size particles can be
removed. However, two points
should be considered:
a) There is a “critical dilution” point
where lowering the viscosity or density
with dilution no longer benefits
efficient separation.
b) Conversely, if insufficient dilution
is used, then the desired cut point
and efficient separation cannot be
achieved.
The wet-solids classifiers most commonly
used for solids removal from
drilling muds are hydroclones and
centrifuges. As mentioned earlier,
these devices perform according to
Stokes’ law with regard to density,
viscosity and G-force. They increase
the settling and processing rates by
increasing the G-force acting on the
solid particles. The G-force acting on a
solid is proportional to the (diameter
of circular motion) x (the square of
the rotating speed [RPM]) x (the mass
of the particle).
Pumps deliver mud to wet classifiers,
but centrifugal pumps are particularly
bad about causing solids to degrade in
size, thus aggravating the problem of
controlling colloidal solids. For this reason,
centrifugal pumps operating for
mixing hoppers and hydroclones
should be shut down when they are
not needed. Because centrifuges process
a smaller volume, it is possible to use
positive-displacement pumps, which
do not cause as much particle-size
degradation as centrifugal pumps.
A hydroclone is illustrated in Figure 6.
This device has no moving parts. As liquid
from a centrifugal pump enters on
the outside tangent of the funnelshaped
cone, the shape imparts a circular,
whirling motion to the fluid,
thereby increasing centrifugal force to
separate higher-mass particles at a high
processing rate. The hydroclone design
forces high-mass solids to be discharged
from the open bottom, while the majority
of the processed liquid flows back up
through the vortex finder at the top
to be retained. While it is difficult to
achieve a sharp cut point with hydroclones,
they are simple, rugged and
inexpensive to operate and have a
high-volume processing rate.
Centrifuges used in oilfield service are
usually decanting-type centrifuges, as
illustrated in Figure 11. These are highspeed,
rotating centrifuges that can
develop 600 to 800 or more “Gs” of separation
force. Their mechanical design
and ability to achieve centrifugal forces
well above 500 Gs enables them to give
a relatively sharp particle size cut. One
drawback of most decanting centrifuges
is their relatively low volumetric processing
rates (<40 gpm), since only a
small portion of the circulating volume
can be processed by a single unit.
By examining Figure 2, it is easy to
understand why it becomes impractical
to desand or desilt weighted muds
containing barite. Barite is a silt-size
material so that desilters or desanders
will discharge large volumes of this
valuable material. For desanders, the
median cut (depending on hydroclone
size) should be in the 45- to 74-micron
Wet
classification
is the
separation
of solids
from a
slurry…
…wet-solids
classifiers…
perform
according to
Stokes’ law
with regard
to density,
viscosity and
G-force.
Solids Control
CHAPTER
8
Solids Control 8.14 Revision No: A-0 / Revision Date: 03·31·98
range, while desilters may have a 15- to
35-micron cut. Since the median particle
size for barite often is in the 15- to
30-micron range, much of the barite
would be discarded along with the silt
or sand.
Note that barite recovery centrifuges
and microclones (small-diameter, highpressure
hydroclones) — cut at 7 to
9 microns D50 — will deliver efficient
barite recovery. However, unless they
are used in combination with other
properly selected and sized solidsremoval
equipment, undesirable
amounts of silt or sand may be
returned to the active system.
HYDROCLONES
Figure 6 is a cross-sectional diagram of
a hydroclone or “cyclone”-type centrifugal
separator. A centrifugal pump
feeds a high-volume mud through a tangential
opening into the large end of
the funnel-shaped hydroclone. When
the proper amount of head (pressure) is
used, this results in a whirling of the
fluid much like the motion of a water
spout, tornado or cyclone, expelling
wet, higher mass solids out the open
bottom while returning the liquid
through the top of the hydroclone.
Thus, all hydroclones operate in a similar
manner, whether they are used as
desanders, desilters or clay ejectors.
Head is related to pressure as follows:
Head (ft) = Pressure (psi)/[.052 x
mud weight (lb/gal)]
Many hydroclone devices (check with
the manufacturer) are designed for
about 75 ft of head at the inlet manifold.
Since mud weight is a factor in the
above equation, the pressure required
to produce the proper amount of head
will vary with mud weight. Head
should be measured at the manifold
inlet, since it will decrease between the
pump and the hydroclone manifold.
Inadequate head will result in smaller
volumes of mud being processed and a
larger-than-desired cut point. For example,
when the head is 45 ft instead of
75 ft, a 4-in. hydroclone will process
only 40 gpm instead of 50 gpm, and
the cut point will be 55 microns instead
of 15 microns. Excessive head also is
detrimental, with most solids carried
back into the mud system.
A short pipe called a “vortex finder”
extends into the hydroclone body from
the top. This forces the whirling stream
to start downward toward the small
end of the hydroclone body (“apex” or
“underflow”). Larger and/or heavier
particles are thrown outward toward
the wall of the hydroclone, while the
fluid with the finer, lighter particles
(which move outward more slowly)
all move toward the center within the
moving liquid. Since it is preferable to
retain most of the liquid and discharge
Figure 6: Hydroclone schematic.
Cleaned mud (overflow)
Mud inlet
Vortex finder
Apex
Wet cuttings discharge
…“vortex
finder”
extends into
the hydroclone
body from
the top.
Solids Control
Solids Control 8.15 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
only solids, the apex opening (bottom)
must be smaller than the vortex
opening. The larger particles and a
small amount of fluid will pass out of
the apex. The remainder of the fluid
and smaller particles will reverse direction
and pass upward inside the hydroclone
of fluid, leaving by way of the
vortex finder (overflow).
Figure 7 illustrates hydroclone applications.
When using hydroclones as
desanders or desilters, the underflow
from the apex containing coarse solids
is discarded and the overflow (effluent)
is returned to the active mud stream.
When used for barite recovery or to
eject clay, the hydroclones return the
underflow containing barite to the
active mud system and discard the
effluent containing clays and other
fine particles.
The size and number of hydroclones
required will vary, depending on the
application. Desanders usually are 6-in.
hydroclones or larger, with two 12-in.
hydroclones being common. Generally,
desilters use 4- to 6-in. hydroclones,
with 12 or more 4-in. hydroclones
being common. Clay ejectors or
microclones use 2-in. hydroclones,
with 20, 2-in. hydroclones being common.
Capacity is related to hydroclone
size, so more smaller hydroclones are
required for a given volume than larger
ones. An example of hydroclone removal
efficiency, showing the cut and D10 -
D50 - D90 values for typical 3-, 4- and
6-in. hydroclones, is depicted in
Figure 8.
Figure 7: Hydroclone applications.
0 10 20 30 40 50 60 70 80 90 100
Equivalent particle size diameter (μ)
D90 D90 D90 D90
D50
3" cone
4" cone
6" cone
4" cone
(rope discharge)
D10 D10 D10
D50 D50 D50
100
90
80
70
60
50
40
30
20
10
0
Figure 8: Typical hydroclone performance.
The size and
number of
hydroclones
required
will vary…
API 200 mesh
“ideal cut”
Save
Desander
12-in.
Save
Desilter
4-in.
Discard
Microclone
2-in.
Discard Discard Save
Feed
Percentage removed
Solids Control
CHAPTER
8
Solids Control 8.16 Revision No: A-0 / Revision Date: 03·31·98
The hydroclone discharge, or underflow,
must be evaluated to ensure that
the hydroclone is operating efficiently.
The discharge should be in the form of
a fine spray, with a slight suction felt
at its center. Conversely, a “rope-type”
discharge with no air suction is not
desirable, since the cut point and
slope will be increased (see Figures 8
and 9). However, when drilling a largediameter
hole at high ROP, the feed
may become overloaded with solids
and result in a rope-type discharge. At
times, this may have to be tolerated,
since shutting the unit down would be
worse. If a hydroclone begins to exhibit
a rope-type discharge and the feed is
not overloaded, the feed pressure may
be improper or the hydroclone may
be worn out or plugged. With some
hydroclone types, it may be possible to
adjust apex size to produce a spray discharge.
If the feed pressure is in the
correct range and a rope-type discharge
cannot be corrected, the capacity of the
unit usually is too low for the drilling
conditions. A general guide to the
maintenance and trouble shooting of
desanders and desilters is included on
page 8.24.
DESANDERS
A desander is needed to prevent overload
on the desilters. Generally, a 6-in.
ID or larger hydroclone is used, with
a unit made up of two 12-in. hydroclones,
rated at 500 gpm per hydroclone,
being common. Large desander
hydroclones have the advantage of a
large volumetric capacity (flow rate)
per hydroclone, but have the disadvantage
of making wide particle-size
cuts in the 45- to 74-micron range.
To obtain efficient results, a desander
must be installed with the proper
“head” pressure.
DESILTERS
To achieve maximum efficiency and
prevent overloading the desilter, the
entire flow should be desanded before
being desilted. Generally, a 4-in. ID
hydroclone is used for desilting, with
a unit containing 12 or more 4-in.
hydroclones, rated at 75 gpm per
hydroclone, being common. The proper
volumetric capacity for desilters and
Figure 9a: Spray discharge and air suction.
Lowest wear
Highest efficiency
High wear
Low efficiency
Plugs easily
Clean
mud
out
Mud
and
solids
out
Mud in
Mud in
Open apex
Crowded apex
Air suction
Figure 9b: Rope discharge. No air suction.
Figure 9: Change from spray to rope underflow
with solids overloading.
A desander
is needed
to prevent
overload on
the desilters.
…the entire
flow should
be desanded
before being
desilted.
Solids Control
Solids Control 8.17 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
desanders should be equal to 125 to
150% of the circulation rate. Largediameter
wells with high circulation
rates require a greater number of
hydroclones. Desilter hydroclones
generally process a significant volume
of fluid and have a more-desirable narrow
cut-point, as depicted in Figure 8.
A well-designed and properly operated
4-in. hydroclone will have a D50 cut
point of 15 to 35 microns, with a D90
of around 40 microns. Since barite falls
into the same size range as silt, it also
will be separated from the mud system
by a desilter. For this reason, desilters
are rarely used on weighted muds above
12.5 lb/gal. Both desilters and desanders
are used primarily while drilling surface
hole and where unweighted,
low-density muds are used.
MUD CLEANERS
Basically, a mud cleaner is a desilter
mounted over a vibrating-screen shaker
— generally 12 or more 4-in. hydroclones
above a very fine-mesh screen,
high-energy shaker (see Figure 10).
A mud cleaner will remove sand-size
drill solids from the mud, yet retain
the barite. It first processes the mud
through the desilter, then screens the
discharge through a fine-mesh shaker.
The mud and solids that pass through
the screen (cut size depending on screen
mesh) are saved; the larger solids
retained on the screen are discarded.
By API specifications, 97% of barite
particles are less than 74 microns in
size; therefore, most of the barite will
be discharged by the hydroclones and
will pass through the screen and be
returned to the system. A mud cleaner,
in effect, desands a weighted mud and
is a backup to the shale shakers. Mud
cleaner screens vary in size from 120
to 325 mesh. For a mud cleaner to be
an effective solids-control device, the
screen size must be finer than the
screen size on the shale shakers.
Although drill solids removal and
barite recovery are the most common
uses for the mud cleaner, the salvage of
expensive liquid phases (synthetics, oils,
saturated salt, KCl, etc.) together with
barite, will reduce mud costs. Also, the
material discarded from the vibrating
screen is notably drier, so in many
cases, the decreased volume and dryness
of the waste material lowers disposal
costs. Unless the mud cleaner is
discharging a significant amount of
solids, the centrifugal pump feeding the
desilter will be causing detrimental particle-
size degradation. If fine-mesh shale
shaker screens of 200 mesh or less are
operating properly and no mud is
bypassing the shakers, a mud cleaner
may not be of any additional value.
CENTRIFUGES
As with hydroclones, decanting-type
centrifuges increase the forces causing
separation of the solids by increasing
centrifugal force. The decanting centrifuge
(see Figure 11) consists of a
conical, horizontal steel bowl rotating
at a high speed, with a screw-shaped
conveyor inside. This conveyor rotates
in the same direction as the outer
bowl, but at a slightly slower speed.
The high rotating speed forces the
solids to the inside wall of the bowl
and the conveyor pushes them to the
end for discharge.
Whole mud is pumped into the hollow
spindle of the conveyor, where it
is thrown outward into an annular
ring of mud called the “pond.” The
Figure 10: Schematic of a mud cleaner.
A mud
cleaner,
in effect,
desands a
weighted
mud.
…decantingtype
centrifuges
increase the
forces causing
separation of
the solids… Overflow
(cleaned mud)
Fine mesh screen
Desilting
hydrocyclone
Liquid, fines, most barite
Discard
(sand, some
silt
and
some
barite)
Feed
Return
to pits
level of this pond is determined by the
height of the liquid-discharge ports at
the large, flanged end of the bowl. The
slurry then flows toward the ports
through two channels formed by the
conveyor blades, since solids pack
against the inner wall of the bowl. As
these particles pack against the wall,
the conveyor blades push them along
toward the small end of the bowl.
They emerge from the pond across
the tapered dry area (the beach), where
they are stripped of all free liquid, then
conveyed out the discharge ports at
the small end of the centrifuge.
Centrifuges are capable of making a
sharp cut point. The ideal cut point is
the particle size at which all larger particles
are separated and all finer particles
are retained. This is, however, not possible,
so the actual stated percent of cutpoint
(D number) should be included
when comparing centrifuge performance
characteristics. A D95 indicates that
based on weight, 95% of all particles
larger than the D95 micron size are
removed. Manufacturers use various D
numbers, including D50, D84, D90 and
D95. Also, in a weighted drilling mud
with solids of mixed specific gravity, the
cut point may refer only to the particles
of higher specific gravity (barite, for
example). Therefore, the cut point for
low-SG solids (clays and shale) may be
1.5 times the rated number.
An important aspect of centrifuge
operation is the dilution of the slurry
being fed into the unit. The purpose of
this dilution is to reduce the feed viscosity
to maintain the device’s separation
efficiency. Generally, the higher
the base mud viscosity, the more dilution
needed (2 to 4 gpm of water is not
uncommon). For efficient centrifuge
operation, the effluent viscosity should
be 35 to 37 sec/qt. If the viscosity is
above 37 sec/qt, the slower settling rate
lowers efficiency. If the viscosity is much
below 35 sec/qt, too much water is
being added. This will cause turbulence
inside the bowl, reducing its efficiency.
Manufacturers’ recommendations
concerning mud feed rates and bowl
speed should be followed closely.
The accumulation of fine drill solids
will increase viscosity and gel strengths,
indicating the need for a centrifuge.
However, using a centrifuge will discard
some beneficial mud additives (solids)
like bentonite and lignite. If treatments
are not adjusted to account for this
loss, mud properties may be compromised,
increasing the potential for
drilling problems such as differential
Solids Control
CHAPTER
8
Solids Control 8.18 Revision No: A-0 / Revision Date: 03·31·98
Figure 11: Cross section of a decanting centrifuge.
An important
aspect of
centrifuge
operation is
the dilution
of the slurry…
Liquid return to active Pool Beach Solids discharge
Whole
mud
feed
Liquid zone Drying zone
…using a
centrifuge
will discard
some
beneficial
mud
additives…
Solids Control
Solids Control 8.19 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
pipe sticking. Therefore, when a centrifuge
is being used, bentonite and
other treatments must be increased
to maintain good filter-cake quality.
Using a centrifuge does not eliminate
the need for periodic dilution as 100%
solids-control efficiency is impossible.
Dilution and treatments should be used
to maintain the desirable properties of
the mud system.
CENTRIFUGE APPLICATIONS
In weighted drilling fluids, a centrifuge
is normally used for barite recovery. The
centrifuge is arranged to separate mostly
barite, returning it to the system, while
discarding the liquid phase containing
the detrimental fine and colloidal solids.
The discarded liquid volume is replaced
with liquid dilution or new volume.
Due to the low capacity of most centrifuges,
only a small portion of the circulating
volume is processed, so dilution
and treatments can be adjusted to
maintain chemical concentrations
and satisfactory properties.
In unweighted drilling fluids, a centrifuge
is normally used for liquid
recovery. The centrifuge is arranged to
separate and discard silt-size solids and
return the liquid phase to the system.
The centrifuge solids discharge is basically
dry solids with little free water,
unlike the wet discharge from hydrocyclones.
The cleaned liquid phase
still contains some ultra-fine and
colloidal-size solids, but many situations
benefit from the additional
solids removal. The applications for
unweighted muds include: fluids with
an expensive liquid phase (oil-base,
synthetic, saturated salt, etc.) and
where drilling waste disposal is expensive,
such as at zero-discharge drill
sites, where wastes must be collected
and disposed of elsewhere.
Another application of a centrifuge
is processing underflow from hydroclone
units like desilters or clay ejectors.
Hydrocyclones are designed to
process the full flow of a mud system,
while a centrifuge can handle only
partial flow. By having the centrifuge
process the underflow of the hydrocyclones,
it is cleaning more of the system
volume than it could process
directly. In this application, the centrifuge
also dries out the normally wet
discharge from the hydroclones, discharging
basically dry solids while
retaining the liquid. This is beneficial
when the liquid phase of the mud is
very expensive or when waste discharge
needs to be kept at a minimum.
Dual centrifuges are incorporated
in closed-loop systems. The first centrifuge
is operated as a barite recovery
unit; the second, operated at higher
G-force (RPM), processes the effluent
from the barite recovery centrifuge,
returning the liquid to the mud system
and discarding the solids. Dual
centrifuges are used commonly with
oil-base mud systems. When used
with water-base muds, a flocculant is
sometimes added to the effluent of
the first centrifuge to improve solids
separation in the second centrifuge.
Centrifuges also are used for mud
“dewatering,” in which whole mud is
treated to form dry solids for disposal
and clear water for recycling. For this
application, the solids content of the
mud is brought to a very low level.
Then, chemicals are added to encourage
the particles to coagulate and flocculate.
Once the fluid is properly treated, it can
be processed through a centrifuge, with
mostly dry solids and water being
recovered. Normally, dewatering applications
require special metering pumps
and processing equipment, as well as
experienced personnel.
Reduction of mud costs, without
sacrificing control of essential mud
properties, is the main purpose of, and
justification for, using a decanting centrifuge.
Although it helps control undesirable
fine solids, the centrifuge’s
Dual
centrifuges are
incorporated
in closed-loop
systems.
Solids Control
CHAPTER
8
Solids Control 8.20 Revision No: A-0 / Revision Date: 03·31·98
principal function is to minimize dilution
and maintain acceptable properties
in the mud system (see Guidelines for
Proper Operation of Decanting
Centrifuges page 8.25).
Correct
rig-up is
essential
to getting
maximum
separation
efficiency…
…a sand trap
can catch
the larger
particles
that would
plug or
damage…
Correct rig-up is essential to getting
maximum separation efficiency from
solids-removal equipment. The mechanical
equipment usually is set up in a
descending order, based on the particle
size that it will remove. Although a
degasser, or mud-gas separator, is technically
not a solids-removal device, it
should always be located immediately
after the shale shakers, because centrifugal
pumps and solids-control equipment
do not operate efficiently with
gas-cut mud.
A “sand trap” is a settling pit that is
beneficial to a marginal mud-cleaning
system. Located under or directly after
the shale shaker, a sand trap can catch
the larger particles that would plug or
damage downstream equipment if a
screen develops a hole or if the shaker
is bypassed. Gravity is the force acting
on the particles, so this compartment
should never be stirred or used as a
suction or discharge for hydroclones.
This type of trap also is essential in
maintaining a minimum-solids mud
system.
Other guidelines also can help
improve solids-control efficiency.
Some of them are:
1. Never use the same feed pump for
different types of solids-control
equipment (desander, desilter, mud
cleaner, centrifuge). Doing so will
either bypass equipment with part
of the fluid or place too great a load
on specific parts of the equipment.
2. Never discharge into the same pit
where the feed is located. This will
allow a significant part of the flow
to bypass the solids-control equipment
without being treated.
3. Never take the feed from downstream
of the discharge. This also allows a
significant part of the flow to bypass
the solids-control equipment.
4. Size desanders and desilters so there
will be a “backflow” from the downstream
pit compartment to the feed
compartment. This will ensure 100%
processing of the total flow.
5. Never take a solids-control equipment
feed from the mixing pit. This will
remove the mud chemicals being
added. This happens most frequently
on rigs where the centrifugal pump
for the mud hopper is being used to
feed the solids-control equipment.
Figures 12 through 16 show typical
rig-ups of most solids-control equipment.
Each pit (with the exception
of the sand trap) is assumed to be
thoroughly mixed by blade-type
pit mixers.
Rig-Ups
Solids Control
Solids Control 8.21 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
Figure 12: Basic system unweighted mud.
Figure 13: Unweighted mud with degasser.
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Flow line Mud pump suction
Hopper
Pump
Pump Pump Pump
Pump Pump
Discard
Desander suction
Desander
Desilter
suction
Underflow Underflow
Overflow
Underflow
Hopper
suction
Desilter
Discard
Flow line Degasser Pump suction
Hopper
Sand trap
Desander
suction
Desander Desilter
Desilter
suction
Hopper
suction
Underflow Underflow
Overflow
Underflow
*Overflow when degassing, underflow when not degassing.
*
Degasser
suction
Sand trap
Shale
shakers
Shale
shakers
Discard
Discard
Discard Discard
Solids Control
CHAPTER
8
Solids Control 8.22 Revision No: A-0 / Revision Date: 03·31·98
Figure 14: Unweighted mud with centrifuge.
Figure 15: Weighted mud with mud cleaner and centrifuge.
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Flow line Degasser Pump suction
Hopper
Desander
suction
Desilter
suction
Centrifuge
suction
Centrifuge Liquid
returns
Desander Desilter
Underflow Underflow
Overflow
Pump
Pump
Pump
Pump Pump
Underflow
Underflow Underflow
Overflow
Underflow
Screen
*Overflow when degassing, underflow when not degassing.
Flow line Degasser Pump suction
Hopper
Sand trap
Mud
cleaner
suction
Centrifuge
suction
Degasser
suction
*Overflow when degassing, underflow when not degassing.
*
Degasser
suction
Shale
shakers
Discard
Shale
shakers
Discard
Sand trap
Discard Discard Dry solids discard
Centrifuge Liquid
returns
Mud cleaner
Pump Pump
Coarse solids discarded
Screened liquid
returned
Dry solids discard
*
Solids Control
Solids Control 8.23 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
8
11. Mount and operate the shaker in
a level condition. Both the solids
and volume capacities will be
reduced if a shaker is not level.
12. Provide the proper voltage and
frequency. Low voltage reduces
motor life. Low frequency reduces
the vibrating motion and capacity.
13. Be certain the vibrator is rotating
in the proper direction, for
proper solids discharge. The top
of the shaft should rotate toward
the solids discharge end.
14. Install the proper screen support
cushions in accordance with the
manufacturer’s directions. Screens
that rub against steel rapidly wear
out. The hardness of the rubber is
critical for properly seated screens.
15. Take special care to tension screens
properly in accordance with the
manufacturer’s recommendations.
If screens are improperly tensioned,
their life will be reduced.
16. Screens should be sized such
that mud will cover 75 to 80%
of the area. This permits using the
capacity of the shaker with some
provision for handling surges.
17. With multiple deck shakers, the
proper combination of screen
sizes should be used. On divided
multiple screen deck shakers, the
same screen size should be used
on all panels.
18. A water (or oil) hose should be
provided to wash down the
screens. All screens blind and plug
to a certain degree. Mud left on the
screens during trips will temporarily
plug the screen openings. When
circulation is stopped prior to a
trip, the screens should be washed.
19. A water (or oil) spray is occasionally
used on the shaker screens to
assist the removal of wet, gummy
particles (gumbo) off the screen.
It should never be used continually.
Guidelines for Proper Operation of Shale Shakers
Figure 16: Weighted mud centrifuging underflow from hydroclones.
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Flow line Degasser Pump suction
Hopper
Sand trap
Desilter
suction
Desilter Centrifuge
Underflow Underflow
Overflow
Underflow
*Overflow when degassing, underflow when not degassing.
*
Degasser
suction
Shale
shakers
Discard
Liquid
returns
Pump Pump
Pump
Holding
tank
Dry solids discard
Solids Control
CHAPTER
8
Solids Control 8.24 Revision No: A-0 / Revision Date: 03·31·98
The water spray dilutes the mud
and washes smaller particles
through the screen that would
have otherwise adhered (piggybacked)
to larger particles being
removed at the shaker.
10. Never bypass the screens, even during
a trip, unless lost-circulation
material is in the mud. A bypassed
shaker rapidly fills the sand trap and
removes the backup capacity for
large solids. Downstream solids
removal equipment will not properly
operate if large solids are circulated
past the shaker. Bypassing a shale
shaker will cause desander and desilter
plugging. Mud brought from
another location should only be
added to the active mud system
through the shale shaker.
11. Wash and monitor shaker screens
on connections. Screens with
holes or tears should be replaced
immediately when detected.
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Maintenance and Trouble Shooting of
Desanders and Desilters
(IMPROPER OPERATION AND
PROBABLE CAUSES)
1. No wet solids discharge at the
apex (bottom)
a) Bottom opening (apex) plugged.
Turn unit off. Loosen bottom
adjustment. Push a rod up through
the bottom opening to break up
dried or caked mud. If this is not
successful, remove top of hydroclone
and take out object plugging
apex. Make sure the shale shaker is
not bypassed. Re-adjust bottom
and replace top of hydroclone.
b) Feed pressure (head) too high.
Adjust to proper head pressure, or
75±5 ft, using accurate pressure
gauge.
c) Mud cleaned of all particles
hydroclones can remove. If drilling
is very slow or if the unit is
running during a trip, removal can
approach zero at the underflow
and unit should be shut down and
run only periodically.
d) Worn inlet nozzle, vortex finder
or hydroclone ID. Remove hydroclone
and inspect for excessive
wear. Replace hydroclone if there
is any question as to its condition.
e) Hydroclone improperly installed.
Remove and inspect hydroclone
and re-install according to manufacturers’
instructions.
2. Flooding liquid out of apex
(bottom)
a) Feed pressure (head) too low.
Check pump suction for restrictions,
inadequate liquid level for
pump suction or air entering suction.
Check pump impeller blades
for wear and proper size. Check
pump discharge for correct manifold
routing to only one hydroclone
solids-control unit. Check
condition of pump packing and
alignment-clearance of pump
impeller. Be sure the pump suction
compartment is bottom-equalized
to the overflow discharge compartment
downstream.
b) Hydroclone inlet plugged resulting
in inadequate feed pressure.
Remove hydroclone and inspect,
removing any objects plugging
inlet. If feed plugging occurs frequently,
carefully inspect shale
shaker for bypassing cuttings and
shaker screens for holes/tears.
Install a suction screen on the
Solids Control
Solids Control 8.25 Revision No: A-0 / Revision Date: 03·31·98
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8
b) centrifugal pump. Do not bypass
the shale shaker.
c) Vortex finder plugged, resulting
in back-pressure on hydroclone.
Remove hydroclone and inspect,
removing any objects plugging
vortex tube. If feed plugging occurs
frequently, carefully inspect shale
shaker for bypassing cuttings and
shaker screens for holes/tears.
Install a suction screen on the centrifugal
pump. Do not bypass the
shale shaker.
d) Worn inlet nozzle, vortex finder
or hydroclone ID. Remove hydroclone
and inspect for excessive
wear. Replace hydroclone if there
is any question as to hydroclone
condition.
e) Hydroclone improperly installed.
Remove and inspect hydroclone
and re-install according to manufacturers’
instructions.
3. Hydroclones plugging
a) Feed header (feeding hydroclone
inlets) plugged. Stop feed
pump, remove the blind victaulic
cap from the inlet header end
and remove obstruction. Replace
the blind cap and restart pump
after checking suction screen. Do
not bypass shale shaker.
b) Hydroclone overloaded (roping).
More solids-control capacity
needed. Solids removal system
cannot handle excessive drilling
rates and/or solids loading.
4. Inlet head fluctuating
a) Restricted pump suction. Check
for plugging, gas-cut mud or foam
at the pump suction. Inspect general
condition of pump and piping.
Guidelines for Proper Operation of Decanting Centrifuges
1. Do not operate the centrifuge without
the rotating assembly shroud
and belt guards fastened in place.
2. Rotate the bowl by hand first to
ensure “free” (no drag) movement.
3. Do not operate if unusual noise or
vibration develops; lube bearings per
supplier’s recommendation (typically
every 8 hours of operation).
4. Allow the unit to attain desired
rotational speed prior to starting
the feed pump.
5. Do not overfeed (“crowd”) the
centrifuge.
Symptoms:
• Safety torque coupling frequently
disengages.
• Unit packs off rapidly.
• “Excessive” amount of weight
material in the overflow.
• “Wet” solids discard from unit.
16. Heavily weighted and viscous fluids
require lower feed rates and
higher dilution rates.
17. Ensure proper agitation is available
at the centrifuge pump suction
and in the barite return tank.
18. Remember to turn off the dilution
liquid after the centrifuge has been
shut down.
19. Review start up and shut down
procedures; if inadequate, notify
supplier.
10. If a problem develops that is not
understood, call a centrifuge technician
before attempting to repair.