Solid control for drilling fluid in oil gas well construction

1. Solid Control

2. WASTE
MANAGEMENT
The Fluid Process
Drilling Fluid Treatment
DRILLING
SOLIDS
CONTROL
MIXING
ADDITIVES
DRILLING FLUID
SOLIDS + FLUID
Solid Control: Maintains
desired fluid properties by
removal of drilled solids

3. Drilling Fluid Components
OIL
SOLUBLE
CHEMICALS
WATER
EMULSIFIERS AND
SOLUBLE CHEMICALS
LIQUID
ESTER/
ETHER
DIESEL
LOW
TOXIC
CRUDE
FRESH
WATER
BRINE
SOLIDS
REACTIVE
COMMERCIAL
CLAYS
AND POLYMERS
HYDRATABLE
DRILL SOLIDS
INERT
WEIGHTING
SOLIDS
INERT DRILL
SOLIDS

4. Mud Solids
PV, YP and gels are all affected by mud solids. These may be
divided into two types, high and low gravity.
High Gravity Solids (HGS)
This term refers to the weighting material added to a weighted
mud to increase mud density.
The ideal weighting agent should have the following properties:
a. High specific gravity to minimize volume required for a
given density.
b. Must be chemically inert.
c. Low abrasiveness.

5. Mud Solids (cont.)
The most commonly used weighting agent is barites or barium sulfate
(BaSO4), commonly referred to as barite. This was first used as a mud
additive in 1923 to control gas influx to a well in California.
The API specification for barite is:
Specific gravity - 4.2 minimum
Particle size - maximum 3% > 75 microns
maximum 30% < 6 microns
Other weighting agents commonly used include hematite (Fe203), specific
gravity 4.9 - 5.3 and dolomite (calcium / magnesium carbonate) specific
gravity 2.8 - 2.9. Hematite is used where mud weights in excess of 16 - 17
ppg are required, i.e., severely over pressured areas. Dolomite is used for a
low -weight weighted system where the reservoir must be stimulated by
acidizing.

6. Mud Solids (cont.)
Low Gravity Solids (LGS)
Low gravity solids comprises all other solids in the mud. The
average specific gravity of LGS is usually taken to be 2.6 or 2.65 in
solids analysis calculations. LGS can be further subdivided as
follows:
Desirable - commercial solids added to provide specific
mud properties, e.g., bentonite, and polymers
Undesirable - drilled solids

7. Mud Solids (cont.)
Desirable Solids
These include the following:
Bentonite or Gel
Bentonite is a high grade of fine grained, natural occurring
sodium montmorillonite clay used in drilling mud. It is primarily
used to increase viscosity and control fluid loss. Bentonite is
made up of a large number of flat, thin sheets. Because of its
plate-like structure and chemical make-up, it has the ability to
absorb water and swell (or hydrate) 10-15 times its original
volume when placed in fresh water.

8. Mud Solids (cont.)
Desirable Solids
Bentonite or Gel (cont.)
Some of the specific properties bentonite provides are:
1. Adequate viscosity to suspend weight material.
2. A thin, impervious filter cake and proper colloidal particle size
distribution for improved fluid loss control.
3. Proper viscosity to remove cuttings from the well bore.
4. Adequate gel strengths to suspend cuttings when mud
circulation is stopped.
5. Lubricity which reduces friction and equipment wear.
API specifications on bentonite for use in drilling muds are:
Maximum 4% > 74 microns (200 mesh API) in the ‘wet screen
analysis’.

9. Mud Solids (cont.)
Desirable Solids
Polymers
Various polymers may be added to water based mud for
viscosity control or to aid in prevention in the hydration,
swelling and dispersion of clay minerals.

10. Density of Various Materials
Used In Mud
Material Specific Gravity PPG PPB
Oil .84 7 294
Water 1.0 8.33 350
Low Gravity Solids 2.6 21.7 910
Bentonite 2.6 21.7 910
Calcium Carbonate 2.8 23.3 980
Barite 4.2 min. 35 1469
Illmenite 4.5 37.5 1574
Hematite 5.0 41.7 1749
Drill Solids 2.0 - 3.0 - -

11. Effect of Drilled Solids on Mud System
• Reduced ROP
• Increased Mud Costs
• Increased Risk of Differential Sticking
• Increased Drag and Torque
• Increased Erosion of Surface Equipment
• Increased Risk of Lost Circulation and Formation Damage
• Poor Cement Jobs
• Increased Environmental Impact

12. Amount of Drill Solids Generated
0
10
20
30
40
50
60
70
0
5
10
15
20
25
30
35
bbl/100ft m3/100 m
26 17½ 12¼ 8½ 26 17½ 12¼ 8½
Hole size (inch)

13. API Mud Solids Size Classification
Category Size Range (µm) Examples
Coarse >2000 Human hair 30 - 200
Intermediate 250 - 2000 Talcum powder 5 - 50
Medium 74 - 250 Cement dust 3 - 100
Fine 44 - 74 Cosmetic powder 35
Ultra-fine 2 - 24 Red blood corpuscles 7
Colloidal <2

14. A 20 micron drilled
solid surface area =
2400 sq. microns
The same solid cut
in half on each face
Another 1/4 cut on
each face.
The original 20 micron
solid reduced and sized
2 micron particles.
Surface area 24,000 sq.
microns.
DRILLED SOLIDS DEGRADION
An idealistic
representation of
the gradual
reduction in size
of a re-cycled
drilled solid by
mechanical
forces.

15. Surface Area Increase
Due to Particle Degradation
10000
5000
2500
1250
625
313
156
78
39
20
10
5
2
Size (µm) Total Surface
Area
6
12
24
48
96
192
384
786
1536
3072
6144
12288
24576

16. Differential Sticking
Fs = PAF
Where: Fs = Sticking force (lbs)
P = Differential Pressure (PST)
A = Area of Contact (Sq. In.)
F = Sticking Coefficient
CASE A:
Low Solids,
Thin Wall Cake
P = 520 (PSI)
F = 0.2
A = 240 Sq. In. (1” width of drill pipe
against 20’ length of filter cake
Fs = 520 x 0.2 x 1 x 20 x 12 = 24,960 lbs.
CASE B:
High Solids,
Thick Wall Cake
P = 520 (PSI)
F = 0.2
A = 960 Sq. In. (4” width of
drill pipe against 20’ length of
filter cake
Fs = 520 x 0.2 x 4 x 20 x 12 = 99,840 lbs.

17. Suggested Operating Range for Plastic
Viscosity and Yield Point (Field Muds)
9 10 11 12 13 14 15 16 17 18
MUD WEIGHT LB/GAL
Plastic
Viscosity,
CPS
Yield
Point
LB
100
Sq.
Ft.

18. Barite Particle Size Distribution

19. Effect of Barite Particle Size
on Mud Flow Properties
PV
=
Plastic
Viscosity,
cp
YP
=
Yield
Point
lb./100
sq.
ft
0 20 40 60 80 100 120 140 160 180 200
Barites in Each Barrel, lb.

20. Effect of Drilled Solids on Rheology
Extra clays give
small increase
in viscosity
Extra clays give
large increase in
viscosity
5% 10%
% Clay in Mud
Viscosity

21. Solid Range in WBM

22. LGS Controls
• Experience has shown that the low gravity solids
concentration should be controlled and maintained at
specific levels for optimum fluid performance.
• Experience with the economics of solids control has
indicated that the specific level for low gravity solids
concentration falls between 4 and 6 percent.
• Since bentonite concentration can be approximately 2
volume %, this leaves room for only 2 - 4 volume % drill
solids.

23. Solids Control - The Key to Economy
Drilling rate
 Control of density and flow properties
 Life of bits and surface equipment
 Accuracy of downhole information
Fluid costs
 Disposal volumes and costs
 Cementing problems
 Risk of differential sticking

24. Methods for Solids Control
Three ways to obtain desired fluid properties
DILUTION
Addition of new fluid
DISPLACEMENT
Partial Replacement of Fluid
MECHANICAL SEPARATION
Removal of Drill Solids
(by particle size and density difference)

25. Dilution
Drill
Solids
Drilling Mud
(0% Drill Solids)
Fluid to
replace
volume
of solids
discharged
and fluid
lost
Solids
Discharge
Fluid
from
Hole
Fluid
to
Hole
Solids
Control
Equipment

26. VR = VS (LS - LD)
LD - LA
Where: VR = Dilution volume required LS = Volume % LGS in system
VS = Volume of mud in LD = Volume % LGS desired
circulating system
LA = Volume % LGS in dilution fluid
Example
a) System volume = 1000 bbl
LGS in system = 8%
LGS desired = 6%
Dilution with water i.e. zero % LGS
VR = 1000 (8-6) = 2000 = 333 bbl
6 6
b) If the dilution fluid contained 2% bentonite, this would be:
VR = 1000 (8-6) = 2000 = 500 bbl
6 - 2 4
Dilution Equation

27. Solids Removal with Displacement
(Dump) / Dilution
Drill
Solids
Drilling Mud
(0% Drill Solids)
Solids
Control
Equipment
Dilution
Mud
Mud to
Replace
Volume of
Solids
Discharged
and Mud Lost
with Solids
Solids
Discharge
Mud
from
Hole
Mud / Solids
Discarded
(Dumped)
Mud
to
Hole

28. Displacement Equation
VR = VS (LS - LD)
LS - LA
Example (Using same figures as dilution examples)
a) VR = 1000 (8-6) = 2000 = 250 bbl
8 8
b) VR = 1000 (8-6) = 2000 = 333 bbl
8 - 2 6
VR = Dilution volume required LS = Volume % LGS in system
VS = Volume of mud in LD = Volume % LGS desired
circulating system
LA = Volume % LGS in dilution fluid

29. Summary Water Vol. 2% Bentonite
Required (bbl) Slurry Required (bbl)
W S W S
Dilution 333 500 Displacement 250 333
The major disadvantages of dilution are:
a) Cannot continue indefinitely since limits imposed by tank
capacity would be exceeded.
b) High cost due to large volumes needed.
c) Increased maintenance costs for larger system.
Displacement maintains a constant system volume, but has three
disadvantages compared to mechanical methods:
a) Environmental impact of displaced mud.
b) High cost due to large volumes needed.
c) High disposal costs.
Displacement Equation (cont.)

30. + +
=
2 BARRELS
DILUTION TO REDUCE SOLIDS BY 50%
DISPLACEMENT
+
1 BARREL
=
10%
Drill
Solids
0%
Drill
Solids
5%
Drill
Solids
5%
Drill
Solids
10%
Drill
Solids
0%
Drill
Solids
5%
Drill
Solids
Discards

31. Comparison Between Dilution, Dilution
with Displacement and Solids Removal
Equipment With 50%, 75%, 90% Efficiency
Maintaining Max 5% Low Gravity Solids
BBLS Drill
Solids Removed
BBLS of
Fluid Lost
BBLS of
Dilution
Dilution 0 0 39480
Displacement* /
Dilution 50%
987 8883 19740
Solids Control
50% Efficient
987 987 19740
Solids Control
75% Efficient
1480 1480 9880
Solids Control
90% Efficient
1776 1776 3960
Figures Reflect A 13200 ft Well, 1974 BBLS of Cuttings, 50% V/V Discard Conc.
* Diiscard 10% solide

32. Solid Control
PIT

33. Solids Control System Design Criteria
1. Removal of drilled solids at the first available
opportunity with the minimum of mechanical handling.
Solids Removal Efficiency:
Mass flow rate of solids removed x 100
Mass flow rate of solids in feed

34. Solids Control System Design Criteria
2. Removal of drilled solids in as concentrated
form as possible.
Decanting Efficiency:
(% Solids Discharge - % Solids Feed) x 100
100 - % Solids Feed

35. Particle Size of Solid Controls

36. Shale Shakers, Hydrocyclones
and Mud Cleaners
Shale Shakers
 Handles 100% of circulating volume
 Removes solids larger than 74 µm
 Separation by straining through screen
Optimization:
 Linear / elliptical motions
 Mesh size and type
 Deck angle

37. Shale Shakers, Hydrocyclones
and Mud Cleaners
Hydrocyclones
 Separation by density difference
Desanders
 Diameter: 6 - 12”
 Handles 125% of circulating volume
 D50 cut point 40-45 µm
Desilters
 Diameter: 4”
 Handles 125% of circulating volume
 D50 cut point 20-25 µm

38. Shale Shakers, Hydrocyclones
and Mud Cleaners
Mud Cleaners
 Desilter mounted over fine mesh shale shaker
 For use in weighted and / or expensive fluid systems
 Discards drilled solids while retaining expensive
barite, chemicals and liquids in the fluid system

39. General Solid Control Arrangements
Unweighted Mud
• Shale shaker
• Degasser
• Desander
• Desilter
• Centrifuge
Weighted Mud
• Shale shaker
• Degasser
• Mud cleaner
• Centrifuge

40. Solid Control Configurations
• The overflow for each piece of solids control equipment
should discharge to the compartment downstream from
the suction compartment for that piece of equipment.
• Two different pieces of solids equipment should not
simultaneously operate out of the same suction
compartment.
• Two different pieces of solids control equipment should not
simultaneously discharge into the same compartment.
• The degassers, desanders, desilters, and mud cleaners
should process 100 percent of the mud entering their
individual suction compartments. In a properly designed
system the processing rate should be at least lo-25 percent
more than the rig circulating rate.

41. Shale Shaker
Liquid and Fine Solids
Basket
____ Isolation Members
(Shock Mount)
Course Mount
Discharge
Mud Box
(Back Tank Possum Belly)
 No. of Decks
 Motion
 Screen Type
 Screen Mesh
 Deck Angle
 Basket Angle
 Stroke
 Thrust

42. Shale Shaker Nomenclature
Liquid and Fine Solids
Basket
Isolation
Members
(Shock
Mount)
Coarse Solids
Discharge
Header Tank
(Possum Belly)
• No. of Decks
• Motion
• Screen Type
• Screen Mesh
• Deck Angle
• Basket Angle
Screen Deck
Variables
Vibrators

43. Shale Shaker Motion
V
V
Vibrator
Direction of Rotation
(A) (B)
Vibrator
Circular Motion
Mechanical
or
Pneumatic
Vibrator
V Elliptical & Circular
Straight Line

44. Linear Motion
Solids Bed
Solids Direction
Counter Eccentric
Rotating Eccentric

46. Screen Cloth Weaves
1. Plain Square Weave
Providing a straight through
flow path with the same
diameter warp and shut wires
in and over the under pattern.
This is the most common
weave producing the same
mesh count vertically and
horizontally.
2. Rectangular Opening
Provides maximum open area
and tends to prevent binding
or clogging of material. Does
not build up on the loner
openings and smaller
dimension controls the sizing
of material.

47. 4. Twilled Square Weave
With the pattern of over two
wires and under two wires
this weave produces a
diagonal effect. To provide
greater strength and
corrosion resistance a larger
diameter wire can be woven.
Screen Cloth Weaves (cont.)
3. Plain Dutch Weave
Produces a tapered opening
reducing flow rate. Warp
wire are heavier in a plain
weave and threshold wires
are driven close and crimped
at each pass.

48. MARKET GRADE SCREEN LAYERED SCREEN
Screening
Cloth
Backing
Cloth
Screening
Cloth
Backing
Cloth

49. Screen Cloth Grades
Extra heavy Market grade
Heavy Tensile bolting cloth
Medium Mill
OPEN AREA
OA = (1 - nd)2 x 100
Where:
OA = % open area
n = mesh count
d = wire diameter

50. API Separation Potential Curve
(‘Cutt’ Points)
100
90
80
70
60
50
40
30
20
10
0
Separation Potential Curve Market Grade 150 x 150
70 80 92 100 102 107 110 112 114 120 130
Equivalent Spherical Diameter Micrometer

51. Ideal classifier
Layered 110
D90 = 195 µm
D50 = 136 µm
D10 = 58 µm
D50 = 136 µm
for both screens
Market grade
100 x 100
D90 = 136 µm
D50 = 136 µm
D10 = 105 µm
30 40 50 60 80 100 200 300 400 500 600 800
100
80
60
40
20
Separation
efficiency
%
Particle size, microns
Separation Efficiency Curves

52. API Specification RP13E
All screens should be labeled with:
 Manufacturers designation
 Separation potential
(d50, d16, d84 ‘Cutt’ points)
 Flow capacity
(conductance and non-blanked area)

53. Operational Considerations
Listed below are general guidelines for the operation
of shale shakers in the field.
Shaker Condition
Shale shakers should be regularly maintained according
to manufacturers maintenance schedules.
• Bed rubbers, shock mounts, tension bolt assemblies,
pneumatic bladders, hydraulic lines, etc. should be regularly
inspected and replaced when worn or damaged.
• Failure to do this will impair performance and probably result
in having to run coarser screens for a given flow rate and ROP.

54. Screen Tension and Condition
• Screens should be correctly stored and handles, and
should always be tensioned in accordance with
manufacturers recommendations.
• Incorrectly tensioned screens have impaired separation
efficiency and vastly reduced working life.
Operational Considerations (cont.)

55. Selection of Screen Size
• The finest available mesh should be fitted which can be run
without loss of whole mud from the front of the screens.
As a general rule, the back two thirds to three quarters of the
screen should be covered with mud. This allows for surges
and rig heave when offshore.
Angled single deck units of the Derrick Flo-Line type are
designed to operate with a horseshoe shaped pond of mud,
concave towards the front edge.
Ramped screens, e.g., Thule VSM 100 or Alfa Laval Eagle,
operate with a mud pond on the horizontal rear lower screens,
and a dry beach on the front lower screens.
Operational Considerations (cont.)

56. Blinding
Screen blinding is caused by a reduction in the fluid
transmission capability of the screens which leads to whole mud
overscreen losses. There are two main reasons for this:
a) Coating
The coating of screen wires by dried or sticky solids. This
reduces aperture size and can drastically reduce the
screen’s conductance.
Screens should always be thoroughly washed down with a
pressure wash gun if the shakers are to be turned off for a
period of time. If coating is occurring due to sticky solids
during drilling then a pressure gun should be constantly
available at the shakers.
Operational Considerations (cont.)

57. Blinding (cont.)
a) Coating (cont.)
This should have a base oil feed for oil based mud and water
for water based mud. The best way to deal with this
problem is to have a set of clean screens standing by ready
to change at connection time.
Operational Considerations (cont.)

58. Blinding
a) Coating (cont.)
The screens removed should be thoroughly cleaned
ready for changing at the next connection.
If it is necessary to use the pressure gun while the
screens are fitted, it should not be blasted down
perpendicular to the screen since this breaks down
the solids and forces them through the screen.
If this problem is very severe, it may be necessary to
change to coarser screens until the problem
formation has been drilled.
Operational Considerations (cont.)

59. Blinding
a) Coating (cont.)
Rectangular mesh screens may also alleviate this
problem.
In general, spray bars should not be used since they
cause break down of the solids.
Operational Considerations (cont.)

60. Blinding
b) Plugging
As the name suggests, this problem occurs due to plugging
of the screen apertures by particles of about the same size,
often referred to as near sized particles.
The problem is most likely to occur with plain square weave
screen cloths in unconsolidated sand formations.
Rectangular or layered screens will not suffer so severely
from this problem for reasons already outlined.
When screens blind, many people have a tendency to fit a
coarser mesh. This does alleviate the problem, but is very
poor solids control practice since the sand is then allowed
through the screens.
Operational Considerations (cont.)

61. Blinding
b) Plugging (Cont.)
The best solution is to reduce flow rate if at all possible
and to fit finer mesh screens for which the particles will
no longer be near sized.
Operational Considerations (cont.)

62. Bypassing
Most header boxes (possum bellies) have a bypass valve
or valves. As the name suggests, this permits circulation
to bypass the shakers and may serve as a dump valve to
dump cuttings from the header box.
Shakers should never be bypassed when drilling. This
rapidly fills the sand trap with cuttings and leads to
overload or a blockage at hydrocyclones by coarse solids.
Dumping of the header box can be avoided by installing
jetting lines to agitate the tank and circulate cuttings over
the shakers. Jetting should be done during connections
in order to avoid flooding of the screens and whole mud
loss.
Operational Considerations (cont.)

63. Shaker Hand
Shakers should always be attended when drilling in order
that any malfunction or screen damage can be quickly
rectified.
A member of the rig crew should be assigned to the job of
“shaker hand” and should be fully trained on the actions
to be taken if problems occur.
Operational Considerations (cont.)

64. Degasser
The degasser is used whenever there is entrained gas in the
return mud flow.
Removal of this gas is important for three reasons:
a. Centrifugal pumps will not perform efficiently with ‘gas-cut’
mud and hydrocyclones need a constant head pressure to
operate efficiently.
b. Re-circulation of gas cut mud is dangerous since it reduces
the hydrostatic head of mud and can result in influx of
formation of fluid to the well-bore.
c. Mud density is important in solids content calculations. If
a pressurized mud balance is not available incorrect solids
content and solids analysis figures will result.

65. Degasser
Operating Principles
There are two main modes of operation for degassers.
Vacuum
Vacuum degassers operate by separating gas-cut mud into thin
layers followed by drawing off the gas with a vacuum pump. The
thin layers are achieved by flowing the mud over a series of
baffles.
Cyclonic
The cyclonic degasser operates by utilizing centrifugal force to
separate the gas. Gas cut mud is sucked into a cylindrical or
cono-cylindrical chamber at high velocity. Centrifugal force
throws the mud to the outside of the chamber while gas is
concentrated in the center and exits to be vented via a vortex
finder.

66. Degasser
Installation and Operation
Degassers should always take suction from the tank adjacent to
the sand trap and discharge to the adjacent downstream tank.
The feed rate should be greater than total circulating rate to
ensure that all of the return mud flow is being processed.
The back flow must be by high weir. If the back flow is beneath
the mud level the gas cut mud from the sand trap may sit on top
of the heavier degassed mud and may result in the suction tank
overflowing.

67. Feed
Inlet
A
Underflow Opening
Overflow Opening (Vortex finder
may be same size or smaller)
A
Top View
Not (Operating)
Feed
Inlet
Vortex Finder
Hydrocyclone Terminology
Top
Liquid Discharge Opening
(Overflow)
Feed Chamber Working (Inside)
Diameter
Cone
Zone of
Maximum Wear
Solids Discharge
Opening (Underflow
Air
Entry

68. Feed
Chamber
Diameter
(inch)
Capacity
(gpm)
Capacity
(m3/hr)
Cut Point
For Solids
of 2.6sg
(micron)
4 50 11.35 20 - 25
6 100 22.71 40 - 45
8 150 34.06 70 - 75
10 - 12 500 113.55 70 - 75

69. Cone Capacities
Cone Size (inch) gpm
3 50
4 50
6 100
8 150
10 500
12 500
Number of Cones
Number of cones = Max. circ. Rate (gpm) x
1.25
cone capacity (gpm)
Sizing of Hydrocyclone Installations

70. Sizing of Hydrocyclone Installations
Feedhead
Most manufacturers specify 75 feet of head at feed manifold.
The pressure gauge reading should therefore be:
p = 0.052 x feet of head x ppg
= 0.052 x 75 x ppg
= 4 x ppg

71. Hydrocyclones
Operating Pressure Sizing
Pressure Gauge Reading (PSI) No. of cones = circ. rate x 1.25
cone capacity
= 0.052 x feet of head x ppg e.g. for 4” desilter cones
= 0.052 x 75 x ppg gpm m3/hour cones
200 45.4 5
= 3.9 x ppg 400 90.8 10
600 136.3 15
= 4 x ppg 800 181.7 20
1000 227.1 25

72. Mud Conditioner

73. OPERATION
Installation
The desander should take suction from the degasser overflow tank
and overflow to the adjacent downstream tank. Desilter suction
should be from the desander overflow and again, overflow to the
adjacent downstream tank. Low level equalizers between the
overflow and suction tanks ensure a backflow of mud as described
above.
Where the bottom of the cones lies several feet above the mud level
in the tanks, the overflow line may create a vacuum which sucks
solids through the overflows, thereby reducing separation efficiency.
This can be overcome by installation of a vacuum break. Installing
the overflow line at 450 may also help to alleviate this.
Appearance of Underflow

74. OPERATION
Balancing
Once the installation is completed, the cones are set up as follows:
1. Start pump with water feed to all cones.
2. Open all cone underflow openings to maximum extent. this should
give a fine water spray from each cone.
3. Close down the opening until only a slow drip of water is escaping.
4. Start processing mud. Only slight further adjustment should be
needed to produce spray discharge.
Appearance of Underflow

75. Spray Discharge
When operating at maximum efficiency, the underflow
should exit from the apex of the cone as a spray discharge.
Larger particles are thrown to the outside of the cone and
travel downwards in a spiral. When solids reach the apex,
they are more concentrated than in the feed mud due to the
smaller area available. They exit the apex as an annular ring
which forms a conical spray.
Appearance of Underflow

76. Spray Discharge (Cont.)
As solids and fluid are discharged air is sucked upwards
through the center of the apex due to the creation of a low
pressure zone formed by the liquid and smaller particles
spiraling upwards in the center of the cone.
The percentage of solids in the underflow varies from
around 50% for coarse sand down to around 10% for fine
silt. The underflow will weigh more than the feed mud.
The solids in the overflow will be less and fall in the ultra
fine category. The overflow will weigh less than the feed
mud.
Appearance of Underflow

77. Rope Discharge
In a rope discharge, the liquid forms 50% or sometimes less of the total
underflow. The solids concentration can increase due to faster drilling
or the sand trap being full of solids. There is insufficient room for all of
the downwards moving solids to exit from the cone apex.
The solids tend to accumulate in a dead area above the apex and the
rate of solids removal is much reduced. The solids that cannot exit
from the apex of a roping underflow cone will be swept up the center
and exit from the overflow. This includes many of the solids that would
have been removed by a spray discharge.
Appearance of Underflow

78. Rope Discharge (Cont.)
Since only the coarsest solids are discharged the surface area to
weight ratio is reduced and therefore less liquid is discharged. The
rope underflow will therefore have a higher density than the spray
underflow for the same mud.
Appearance of Underflow

79. Solids
Reporting
to
Overflow
No
Air
Entry
Underflow
Discharge
Opening Slow “Falling” Discharge
“Dead” Area - No Rotation - No Wear
Rapid Cone Wear
Rope Discharge
A typical balanced design
hydrocyclone operating inefficiently
with rope type underflow
Side view diagram - half section
Rope Discharge

80. Partial Feed Plugging
This is a potentially serious situation for mud loss and results
from partial plugging of the feed inlet. the result is a reduction
in the inlet velocity and a loss of separation.
• The cyclone action is lost and the mud entering spirals out of
the underflow opening in a cone shape.
• Clean mud processed by other cones on the manifold may
flow backwards into the cone and may also be lost.
• The underflow density will be less than or equal to the feed
density.
Appearance of Underflow

81. Partial Feed Plugging (Cont.)
• Very high rates of mud loss can occur so the problem must
be rectified at the first opportunity, usually by replacing the
cone with a spare or removing it and blanking off the feed
from the manifold at the inlet pipe connection.
Appearance of Underflow

82. Total Feed Plugging
This is usually due to soft object completely plugging the
outlet from the feed manifold. The mud lost is cleaned mud
from other cone overflow, and floods downwards without
rotation. Therefore it does not exit the apex as a cone, but as
a parallel jet of mud.
Mud loss rates are extremely high and the problem must be
rectified by stopping the pump, removing the cone and
blanking off the feed stub.
The pump should then be restarted. The blockage can be
dealt with during the next trip out of hole.
The mud lost in this case is always lighter than the feed.
Appearance of Underflow

83. Straight Down
Flow Indicates
All Mud Entering
Backwards Through
Overflow
The Smooth Shape
Indicates Rotation
Due to Mud Entering
the Feed Inlet
a. Coning due to Partial
Plugging of Inlet
b. Flooding Due to Complete
Plugging of Inlet
Balanced Design Cyclones
Figure 21 & 22
Balanced Design
Cyclones with the
Feed Partly
Plugged
(left) End
Completely
Plugged (right)
Side views - Half Section Diagrammatic

84. Appearance of Underflow
Underflow Plugging
The underflow may become plugged for one of two reasons.
Firstly, rope discharge may have gone unchecked for so long that
plugging has resulted.
Secondly, the opening may be too small (see set up) which results in a
dry plug.
Both cases should be rectified since they reduce total capacity and
also increase the total feed concentration of solids to the other cones.
There are other serious implications of plugged underflow.

85. Appearance of Underflow
Underflow Plugging (cont)
The wear on the overflow is very severe since all solids in the feed
pass through and exit via the overflow.
Cuttings are left in the system causing erosion to pumps, etc., and
eventually are degraded to the point where they cannot be removed by
mechanical means.
It is essential that hydrocyclone installations are correctly designed
and sized, otherwise overloading will reduce efficiency through roping
or plugging. Sizing of installations and pumps is dealt within the next
section.

86. Coarse Solids Passing On To
Rig Pump, Filter Cake, Annulus.
Severe Wear Inside
Vortex Finder
Ring Of Severe Wear
Still Bed Of Very Coarse Material
Plugged Area
Feed
A Hydrocyclone
operating with the
underflow
discharge
opening plugged

87. Vacuum Break on
Hydrocyclone Overflow
Discard Unders
Hydrocyclone
Feed
Equalizer
Backflow
Motor
Pump
Pump
Suction
Desilter
Overs
12 to 18”
Vacuum Break

88. Appearance of Underflow
OPERATION
Troubleshooting
1. Low feed pressure.
a. Pump incorrectly sized.
b. Plugged pump suction - clean filter and settlement in pipe.
c. Ensure no other equipment being fed by same pump.
d. Air lock in suction.
2. No Underflow.
a. Plugged apex.
b. Aperture too small.
c. Solids all below cut point.
d. Vacuum on overflow.

89. OPERATION
Troubleshooting
3. Rope Discharge
a. Solids overload
b. Very high mud viscosity.
c. Undersized apex.
4. Cone Discharge - Feed partially plugged.
5. Flooded Liquid Jet Discharge - Feed completely plugged
Appearance of Underflow

90. Pump Sizing Procedure
1. Calculate friction head.
2. Calculate total dynamic head.
T.D.H. = Inlet head + Lift + Friction head
3. Determine pump size to be used from manufacturers tables.
4. Select pump curves and determine impeller size.
Up to 1750 rpm estimate to nearest 1/4“
5. Determine horsepower required for water:
6. Calculate horsepower required for maximum mud density.
7. Choose motor size as smallest standard size equal to or
greater than minimum calculated.

91. Friction Loss in Pipe Fittings in Terms of Equivalent Feet of Straight Pipe
Swing
Gate check Angle Globe
Actual valve valve valve valve
Nom. inside Friction Close Butter- 90 welding Mitre bend
pipe diam. factor full 90 45 thru branch return full full full fly elbow
size d f open elbow elbow flow flow band open open open valve r/d=1 r/d=2 45 90
1/2 0.622 0.027 0.41 1.55 0.83 1.04 3.11 2.59 5.18 7.78 17.6
3/4 0.824 0.025 0.55 2.06 1.1 1.37 4.12 3.43 8.86 10.3 23.3
1 1.049 0.023 0.7 2.62 1.4 1.75 5.25 4.07 8.74 13.1 29.7
1 1/4 1.38 0.022 0.92 3.45 1.84 2.3 6.9 5.75 11.5 17.3 39.1
1 1/2 1.61 0.021 1.07 4.03 2.15 2.68 8.05 6.71 13.4 20.1 45.6
2 2.067 0.019 1.38 5.17 2.76 3.45 10.3 8.61 17.2 25.8 58.6 7.75 3.45 2 2.58 10.3
2 1/2 2.469 0.018 1.65 6.17 3.29 4.12 12.3 10.3 20.6 30.9 70 9.26 4.12 2.47 3.08 12.3
3 3.068 0.018 2.04 7.67 4.09 5.11 15.3 12.8 25.5 38.4 86.9 11.5 5.11 3.07 3.84 15.3
4 4.026 0.017 2.68 10.1 5.37 5.71 20.1 16.8 33.6 50.3 114 15.1 6.71 4.03 5.03 20.1
5 5.047 0.016 3.36 12.6 6.73 8.41 25.2 21 42.1 63.1 143 18.9 8.41 5.05 6.31 25.2
6 6.065 0.015 4.04 15.2 8.09 10.1 30.3 25.3 50.5 75.8 172 22.7 10.1 6.07 7.58 30.3
8 7.981 0.014 5.32 20 10.6 13.3 39.9 33.3 33.3 99.8 226 29.9 13.3 7.98 9.98 39.9
10 10.02 0.014 6.68 25.1 13.4 16.7 50.1 41.8 41.8 125 284 29.2 16.7 10 12.5 50.1
12 11.938 0.013 7.96 29.8 15.9 19.9 59.7 49.7 49.7 149 338 34.8 19.9 11.9 14.9 59.7
14 13.124 0.013 8.75 32.8 17.5 21.8 65.6 54.7 54.7 164 372 38.3 21.8 13.1 16.4 65.6
16 15 0.013 10 37.5 20 25 75 62.5 62.5 188 425 31.3 25 15 18.8 75
18 16.876 0.012 16.9 42.2 22.5 28.1 84.4 70.3 70.3 210 478 35.2 28.1 16.9 21.1 84.4
20 18.814 0.012 12.5 47 25.1 31.4 94.1 78.4 78.4 235 533 39.2 31.4 18.8 23.5 94.1
24 22.628 0.012 15.1 56.6 30.2 37.7 113 94.3 94.3 283 641 47.1 37.7 22.6 28.3 113
30 28 0.011 18.7 70 37.3 46.7 140 117 46.7 28 35 140
36 34 0.011 22.7 85 45.3 56.7 170 142 56.7 34 43 170
42 40 0.01 26.7 100 53.3 66.7 200 167 56.7 40 50 200
48 46 0.01 30.7 115 51.3 76.7 230 192 76.7 46 58 230
1/2 TO 6
L/D 8 30 16 20 60 150 =100 150 340 20 12 15 60
24 TO 48
=50
Friction Loss in Pipe Fittings

92. Example
Desander at 1500gpm: Fittings on discharge:
Pipe Diameter; 6” – Discharge, 8” – Suction.
Qty
Inlet head required = 75 feet 90º elbows = 2
Lift = 10 feet 45º = 1
Pipe length = 30 feet Tee piece = 1
Pipe length = 10 feet Butt. valves = 2
Fittings on Feed:
Qty
Tee piece = 1
Butt. valve = 2
Maximum mud density = 1.6sg.

93. 1. Friction head
Discharge FH = 30 + 30.4 + 8.1 + 10.1 + 45.4
= 124.1 feet 6” pipe
= 124.1 x 0.015
= 1.9 feet
Suction FH = 10 + 13.3 + 59.8
= 83.1 feet 8” pipe
= 83.1 x 0.014
= 1.2 feet
Total FH = 3.1 feet
2. Total Dynamic Head
T.D.H. = 75 + 10 + 3.1
+ 88 feet

94. 3. Pump size = Mission 8 x 6 11 at 1750rpm.
4. Estimated impeller size = 10.75”
5. Horsepower for water = 47HP
6. Horsepower for maximum mud density.
a) HP = 47 x 1.6 = 75.2 HP
b) HP = gpm x feet head x 1.6
3960 x EFF
= 1500 x 88 x 1.6
3960 x 0.7
= 76.2 HP
7. Motor size = 75 HP.

95. Recommended Pump
Suction Submergence
Velocity, feet / second = GMP x 0.4
D2 (inches)
0
2
4
6
8
10
12
14
16
2 4 6 8 10 12 14 16
H Submergence
in feet (min)
Velocity in feet Per Second

96. Mudcleaner
Hydrocyclones
(Desilters
and/or
Desanders)
Fine Mesh
Screen
Reject or
Discard
Solids
Screen Underflow
Clean Mud
Mud Return
Mud In
##################

97. 0
10
20
30
40
50
60
70
80
90
100
After: 12% Greater than 100 Micrometers
Before: 22% Greater than 100 Micrometers
Effect of Centrifugal Pump
on Mud PSD
Particle Size
(Micrometers)
10 100 1000
Cumulative
Volume
%
Less
than

98. Decanter Centrifuges
An Introduction to the Working Principles

99. Decanting Centrifuge
A machine for the continuous sedimentation of suspended
solids from a liquid by the action of centrifugal force in an
elongated rotating bowl.
Continuous unloading of solids from the bowl is made
possible by a conveyor which rotates in the same direction
as the bowl but at a slightly different speed.
PRINCIPLE COMPONENTS
1. Bowl (or drum)
2. Conveyor (or scroll)
3. Gearbox
4. Frame and collecting vessel
5. Feed inlet and distribution

100. Decanter Centrifuge
Working principle and nomenclature

101. Feed Rate
Change RPM
Method of Adjustment
MOHNO NE80

102. Setting efficiency
Vc
=
d 2(p - 1)
18 L
rw2
Centrifugal Separation
Vc
Centrifugal
settling
velocity
(m/s)
p
Particle
density
(kg/m3)
Particle
diameter
(mm)
d 1
Liquid
density
(kg/m3)
L
Liquid
viscosity
(kg/ms)
rw2
Centripetal
acceleration
(m/s2)
Stokes’ Law
V
c
d
r
w

103. Process parameters
Vc
=
d 2(p - 1)
18 L
rw2
Centrifugal Separation
PARTICLE SIZE VISCOSITY FEED RATE
Separation
efficiency
Separation
efficiency
Separation
efficiency
Small Large Low High Low High

104. Regulating Possibilities
Degree
of solids
recovery
ROTOR SPEED DIFFERENTIAL SPEED POND DEPTH
% DS in
underflow
Low High Low High
Low High Low High
Shallow Deep
Shallow Deep
( - )
( + )
( - )
( + )

105. 13-3-2002 106 A.MUDOFIR
Well
King Cobra
fine screen
shaker Shaker
SR Desander
500 gpm/ cone
SE Desilter
60 gpm/cone
DG-5 Degasser
one per 500 gpm
Agitators
all active
compartment
s
Brandt SCE
HS-3400 low
Speed
Barite Recovery
UN WEIGHTED MUD SYSTEM
Gumbo Scalper
one per 1500 gpm

106. 13-3-2002 107 A.MUDOFIR
Well
King Cobra
fine screen
shaker
Shaker
Cuttings
collection
Mud Cleaner
60 gpm/cone
DG-5 Degasser
one per 500 gpm
King Cobra
Mud
Conditioner
includes Desander
and Desilter
HS-3400 high
speed
viscosity control Agitators
all active
compartment
s
Brandt SCE
HS-3400 low
Speed
Barite Recovery
WEIGHTED MUD SYSTEM

107. 13-3-2002 108 A.MUDOFIR
Well
LCM-2D CS
Cascade shaker
one per 500 gpm
Scalping Shaker
LCM-2D Mud
Conditioner
includes Desander
and Desilter
Dry Location System
Fine Screen Shaker
Gumbo Scalper
one per 1500 gpm
Cuttings
collection
SR Desander
500 gpm/ cone
SE Desilter
60 gpm/cone
DG-10 Degasser
one per 1000 gpm
SC-4 low speed
barite recovery
may need 2
HS-3400 high
speed
viscosity control
Agitators
all active
compartment
s
Vortex Dryer

108. End of Solids Control

109. Pump Sizing Procedure
1. Calculate friction head.
2. Calculate total dynamic head.
T.D.H. = Inlet head + Lift + Friction head
3. Determine pump size to be used from manufacturers tables.
4. Select pump curves and determine impeller size.
Up to 1750 rpm estimate to nearest 1/4“
5. Determine horsepower required for water:
6. Calculate horsepower required for maximum mud density.
7. Choose motor size as smallest standard size equal to or
greater than minimum calculated.

110. Example
Desander at 1500gpm: Fittings on discharge:
Qty
Inlet head required = 75 feet 90º elbows = 2
Lift = 10 feet 45º = 1
Pipe length = 30 feet Tee piece = 1
Pipe length = 10 feet Butt. valves = 2
Fittings on Feed:
Qty
Tee piece = 1
Butt. valve = 2
Maximum mud density = 1.6sg.

111. 1. Friction head
Discharge FH = 30 + 30.4 + 8.1 + 10.1 + 45.4
= 124.1 feet 6” pipe
= 124.1 x 0.015
= 1.9 feet
Suction FH = 10 + 13.3 + 59.8
= 83.1 feet 8” pipe
= 83.1 x 0.014
= 1.2 feet
Total FH = 3.1 feet
2. Total Dynamic Head
T.D.H. = 75 + 10 + 3.1
+ 88 feet

112. 3. Pump size = Mission 8 x 6 11 at 1750rpm.
4. Estimated impeller size = 10.75”
5. Horsepower for water = 47HP
6. Horsepower for maximum mud density.
a) HP = 47 x 1.6 = 75.2 HP
b) HP = gpm x feet head x 1.6
3960 x EFF
= 1500 x 88 x 1.6
3960 x 0.7
= 76.2 HP
7. Motor size = 75 HP.

113. API Standard for Evaluation of
System Efficiency
Water Added VW 1481 bbls.
Average Water fraction kw 0.9 percent
Interval Length L 1600 feet
Bit Diameter D 12.25 inches
Washout W 0.1 percent
Average Drill Solids Concentration ks 0.06 percent
1. Calculate volume of mud built:
Vm = Vw/Kw = 1645.56 bbls.
2. Calculate volume of drilled solids:
Vc=D^2*W/1029*L 256.45 bbls.
3. Calculate the dilution volume required if no solids were removed:
Vd = Vc/ks 4274.18 bbls.
4. Calculate the dilution factor:
DR - Vm/Vd 0.384999
5. Solids removal performance:
Et = (1-DF) 0.615001
61.50%

114. Cone Capacities
Cone Size (inch) gpm
4 50
6 100
8 150
10 450
12 500
Number of Cones
Number of cones = Max. circ. rate(gpm) x 1.25
cone capacity (gpm)
Sizing of Hydrocyclone Installations

115. Sizing of Hydrocyclone Installations
Feedhead
Most manufacturers specify 75 feet of head at feed manifold.
The pressure gauge reading should therefore be:
p = 0.052 x feet of head x ppg
= 0.052 x 75 x ppg
= 4 x ppg

116. Hydrocyclones
Operating Pressure Sizing
Pressure Gauge Reading (PSI) No. of cones = circ. rate x 1.25
cone capacity
= 0.052 x feet of head x ppg e.g. for 4” desilter cones
= 0.052 x 75 x ppg gpm m3/hour cones
200 45.4 5
= 3.9 x ppg 400 90.8 10
600 136.3 15
= 4 x ppg 800 181.7 20
1000 227.1 25

117. Calculation of Differential Speed
1. Sunwheel Speed
Sunwheel speed (rpm) = B.drive motor speed x motor pulley diameter
Sunwheel pulley diameter
e.g. 60 Hz
Motor speed = 1750/3500 rpm
Motor pulley = 125 mm
Sunwheel pulley = 175 mm
For high speed:
Sunwheel speed = 3500 x 125
175
= 2500 rpm

118. Calculation of Differential Speed
2. Differential Speed
Differential speed (rpm) = Bowl speed - Sunwheel speed
Gearbox ratio
Note: Sunwheel speed is negative for negative backdrive motor rotation
Negative rotation (left):
Differential speed (rpm) = Bowl speed + Sunwheel speed
57
Positive rotation (right):
Differential speed (rpm) = Bowl speed - Sunwheel speed
57

119. 2. Differential Speed (cont.)
Brake position:
Differential speed (rpm) = Bowl speed
57
e.g. 60Hz, 2 left, 2425 rpm bowl speed:
Differential speed = 2425-(-2500)
57
= 2425+2500
57
= 86 rpm
Calculation of Differential Speed

120. Principles of Centrifugal Separation
Conveying Capacity
All solids which are sedimented in the decanter have to be
scrolled out by the conveyor. If not, they will flow out with
the cleaned liquid contaminating it.
Theoretically the greatest amount of solids is conveyed
when the solids reach the body of the conveyor.
The smallest cross-sectional area, which the solids have to
pass, is just before the solids outlet ports in the bowl. If
this area is multiplied with the conveyor pitch the volume of
discharged solids per relative turn of the conveyor is found.
This figure has to be reduced with 5 - 15% (depending on
the pitch, because solids are moving along a spiral line and
not a straight line.)

121. Principles of Centrifugal Separation
Solids Conveying Capacity (cont.)
Steep cone decanters are used or soft sludge applications
only. The amount and thickness of the sludge is basically
determined by the level adjustment of the machine because
the sludge is more a thick liquid than a sludge.
Theoretically these applications could be run without
conveyor, but as a fact the feed always contains impurities
as fibers, sand etc. The conveyor is needed to remove this
minor amount.