WBM & OBM Drilling Fluids.pptx

1. WBM & OBM
Drilling Fluids
Function , Classification , Properties , calculations
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2. Functions of Drilling Fluids
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You may not know that drilling fluid or mud has several important functions helping us
achieve goal to drill well. I would like to share about the functions of drilling fluid as
follows;
1. Transport cutting and dispose to surface – The drilling fluid brings the drilled
material to the ground surface either by mud rheology and velocity.
2.Clean drill bits – As drilling fluid exits the bit jets, fluid velocity removes cutting
from the bit teeth and bit body. This prevents bit ball up situation.
3.Provide hydrostatic pressure to control well while drilling – Hydrostatic pressure
provided from drilling fluid is the primary well control. Mud weight should be high
enough to control formation pressure while drilling.
4.Prevent excessive mud loss – While drilling, clay particle will form a thin layer over
porous zones called “mud cake” or “filter cake”. Mud cake acts as barrier to prevent
excessive drilling fluid loss into formation and provides wellbore stability.

3. Functions of Drilling Fluids
3
5.Prevent formation damage by using reservoir drill-in fluid – While drilling
long reach zone in horizontal wells, the special drilling fluid will be utilized in
order to prevent formation damage.
6.Provide hydraulic pressure to downhole assembly (BHA) as mud motor,
measuring while drilling (MWD), logging while drilling (LWD), etc – Without
enough hydraulic power, downhole tool will not be properly operated, hence,
drilling fluid plays essential role to provide power to sophisticated downhole
tool.
7. Facilitate downhole measurement as open hole logging, MWD, LWD, mud
logging, etc – Mud will assist tool to measure everything downhole.
8.Lubricate drill string and BHA and cool the bit. The drill bit and BHA become
hot due to friction during the drilling process. When the drilling fluid passes
through the bit and exits the jets/nozzles, some extra heat is removed via mud.

4. Drilling fluids classification
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5. Drilling Fluids properties WBM & OBM
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6. Mud Weight and Its Importance in Drilling WBM & OBM
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Mud weight or mud density is a weight of mud per unit volume. It
is one of the most important drilling fluid properties because it
controls formation pressure and it also helps wellbore stability.
Mud weight is measured and reported in pounds per gallon (PPG),
pounds per cubic feet (lb/ft3), or grams per milliliter (b/ml).
Mud weight is normally measured by a conventional mud balance;
however, if you have some air inside a fluid phase, reading from
the conventional mud balance will give you an inaccurate number.
Therefore, the most accurate method to measure the mud weight
is with a pressurized mud balance.
The pressurized mud balance looks like the convention one, but it
has a pressurized sample cup. When you press a mud sample into
the cup, any gas in a fluid phase is compressed to a very small
volume so the mud weight measurement is more accurate.

7. Pressurized Mud Balance Conventional Mud Balance
7

8. What will happen if there is insufficient drilling fluid density ?
8
Well control
The well will be in an underbalanced
condition so any formation of fluids – gas,
oil, and water- will enter into the wellbore.
Wellbore collapse (wellbore instability)
Mud weight will provide pressure to hole
back formation. If mud weight is too small,
wellbore may collapse.

9. What will happen if the mud weight is too high ?
9
Lost circulation
If the hydrostatic pressure from mud column exceeds formation strength, it will
cause a formation to break. Once the formation is broken, drilling fluids will be
lost into the induced formation fractures.
Decrease in rate of penetration
Heavier mud weight will result in slower ROP because of hold down effect.
Practically, while drilling, low mud weight is used at the beginning and mud
weight will be increased , as the well is drilled deeper in order to optimize ROP
and mitigate well control.
Deferentially Stuck Pipe
Since there are differences between formation pressure and hydrostatic pressure,
there will be a lot of chances that a drill string will get deferentially stuck across
permeable rocks.
Formation damage
The more mud weight that is in the well, the more mud filtration invades into
porous formations. The invaded mud will cause damage to formation rocks.

10. Hydrostatic and formation pressure
10

11. Sand Content Kit OBM & WBM
A sand content kit is used for measuring the sand
content in water based drilling mud or oil based drilling
mud, comprising a 200-mesh sieve, a plastic funnel and
a graduated glass tube that is calibrated to measure the
sand content as a percentage. The 200-mesh sieve is
designed to trap particles that are larger than 74
microns, which is much coarser than barite particles.
However, the sieve will also trap other coarse particles
(e.g. coarse Calcium Carbonate LCM particles), which
could distort results if ignored. Every effort must be
made to keep sand content as low as possible because it
is extremely abrasive and can damage mud pumps and
tubulars, as well as causing an undesirable increase in
mud density.
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12. Viscosity of Drilling Mud WBM & OBM
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Viscosity describes a substance’s resistance
to flow. High-viscosity drilling mud is
typically described as “thick,” while low-
viscosity mud is characterized as “thin”.
In the oilfield , the following terms are used
to describe drilling fluid viscosity and
rheological properties. Two viscosities that
will be described in this section are
Funnel Viscosity and Plastic Viscosity.

13. Funnel Viscosity WBM & OBM
The funnel viscosity is timed in seconds of
drilling mud flowing through the Marsh
Funnel Viscosity. The Marsh funnel is easy-
to-use equipment that is used to quickly
check viscosity of the mud.
The Marsh funnel is dimensioned so that
the outflow of time of one quart of
freshwater (946 cc) at a temperature of
70 F ± 5 F (21 C ± 3 C) in 26 ± 0.5 seconds.
13

14. why the viscosity measured from the Marsh Funnel
does not represent the true drilling mud viscosity.
For all drilling mud, especially oil-based mud, temperate has
an effect on the viscosity of a base fluid. The base fluid will
be less thick once the temperature increases. It means that
the funnel viscosity will decrease. The funnel viscosity
measures at only one rate of shear, but the temperature each
time of measurement is not constant. This is the reason why
the viscosity measured from the Marsh Funnel does not
represent the true drilling mud viscosity. On the drilling rig,
this measurement of the mud viscosity is still useful because
it is a quick and simple test for observing trends of drilling
mud. In order to use the funnel viscosity effectively,
personnel must record the values frequently. Then looking at
a trend of funnel viscosity, it will indicate if there is any issue
with drilling mud. Please remember that only a single point
of the funnel viscosity cannot tell you anything about a
condition of drilling mud. 15

15. Plastic Viscosity (PV) WBM & OBM
Plastic Viscosity (PV) is a resistance of fluid to flow. According to the
Bingham plastic model, the PV is the slope of shear stress and shear
rate. Typically, the viscometer is utilized to measure shear rates at 600,
300, 200, 100, 6, and 3 revolutions per minute (rpm).
In the field , the plastic viscosity can be calculated by a simple
calculation shown below.
Plastic Viscosity (PV) = Reading at 600 rpm – Reading at 300 rpm
The unit of PV is Centi Poise (CP).
For example
determine PV from these reading values from a viscometer.
Reading at 600 rpm = 56
Reading at 300 rpm = 35
Plastic Viscosity (PV) = 56 – 35 = 21 CP
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16. Plastic Viscosity (PV) WBM & OBM
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Any increase in solid content in drilling mud such as barite, drill solid, lost
circulation material, etc., will result in higher plastic viscosity. In order to
lower the plastic viscosity, solid content must be removed and it can be
achieved by using solid control equipment and/or diluting drilling mud with
base fluid. Fluid temperature will increase while drilling deeper therefore
plastic viscosity of drilling mud will decrease because the viscosity of the base
fluid decreases.
Normally, the higher the mud weight, the higher plastic viscosity will be.
However, if there is an increasing trend of plastic viscosity with constant mud
weight, it means that there is an increase in drill solid content in a mud
system. Moreover, if oil based mud is used, please keep in mind that water in
oil based drilling fluid will act like a solid, and it will increase the plastic
viscosity dramatically. It is very critical to ensure that amount of water in oil
based mud is within the designed limit.

17. Several impacts of plastic viscosity on drilling operation are as follows;
Equivalent Circulating Density (ECD)
The more PV you have, the higher the ECD will be.
Surge and Swab Pressure
The PV has the same effect as ECD. If the PV increases, surge and
swab pressure will also increase.
Differential Sticking
A chance for differential sticking will increase, especially in water
based mud, when the plastic viscosity increases because of
increases in solid content.
Rate of Penetration (ROP)
The ROP will be directly affected by the plastic viscosity. Thicker
mud will have bigger hold down effect than thinner mud. Therefore,
it causes in reduction in ROP.
17

18. Yield point WBM & OBM
Yield Point (YP) is resistance of initial flow of fluid or the stress
required in order to move the fluid. It can be simply stated that
the Yield Point (YP) is the attractive force among colloidal particles
in drilling fluid. As per Bingham plastic model, YP is the shear
stress extrapolated to a shear rate of zero.
Yield point can be calculated by the following formula.
Yield Point (YP) = Reading at 300 rpm – Plastic Viscosity (PV)
A unit of YP is lb/100 ft2.
You can determine the Plastic Viscosity (PV) by this formula.
Plastic Viscosity (PV) = Reading at 600 rpm – Reading at 300 rpm
18

19. Example
19
you have these values from the viscometer.
Reading at 600 rpm = 56
Reading at 300 rpm = 35
Plastic Viscosity (PV) = 56 – 35 = 21 CP
Yield Point (YP) = 35 – 21 = 14 lb/100 ft2
The YP indicates the ability of the drilling mud to carry
cuttings to the surface.
Moreover, frictional pressure loss is directly related to
the YP.
Higher YP will result in larger frictional pressure loss.

20. For water base mud , the YP will be increased with
the following items
20
High temperature
the high temperature environment tends to
increase the YP in the water based mud.
Contaminants
such as carbon dioxide, salt, and anhydrite
in the drilling fluids
Over treatment
of the drilling mud with lime or caustic soda

21. For oil based mud, the causes of increasing in YP are listed
below;
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Drill solid
the more drill solid you have, the more the YP will
be.
Treatment CO2 in the mud with lime (CaO)
The lime (CaO) will chemically react with CO2 to
form Calcium Carbonate (CaCO3) which will increase
the YP.
Low temperature
in the oil based system, the low temperate will
increase the viscosity and the YP. Please keep in mind
that this is opposite to the water based system.

22. Operational impacts of the YP are as follows;
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Equivalent Circulating Density (ECD)
The ECD typically increases when the YP
increases.
Hole Cleaning
Usually the larger diameter hole to be
drilled, the higher the YP must be to
support efficient hole cleaning.

23. Gel Strength and Operational Impact WBM & OBM
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The gel strength is the shear stress of drilling
mud that is measured at a low shear rate
after the drilling mud has been static for a
certain period of time.
The gel strength is one of the most important
drilling fluid properties because it
demonstrates the ability of the drilling mud
to suspend drill solid and weighting material
when circulation is ceased.

24. How can gel strength is measured?
24
Gel strength measurement is made on
viscometer using the 3-rpm reading, which
will be recorded after stirring the drilling
fluid at 600 rpm to break gel. The first
reading is noted after the mud is in a static
condition for 10 seconds. The second
reading and the third reading will be 10
minutes and 30 minutes, respectively.

25. Why do we need to record the 3-rpm
reading after 30 minutes?
25
The reason is that the 30 minute-reading will tell
us whether the mud will significantly form the gel
during extensive static periods like tripping out
BHA or not.
If the mud has high gel strength, it will create a
high pump pressure in order to break circulation
after the mud is static for a long time.
Furthermore, increasing in a trend of 30-minute
gel strength indicates a buildup of an ultra-fine
solid. Therefore, the mud must be treated by
adding chemicals or diluting it with fresh base
fluid.

26. Causes of Increasing in Gel Strength of Water Based Mud
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The following causes will lead to high gel
strength in the water based mud.
• Bacteria
• Ultra fine solid
• Salt
• Chemical contamination such as lime,
gypsum, cement, and anhydrite
• Acid gases such as Carbon Dioxide (CO2),
and Hydrogen Sulphide (H2S)

27. Causes of Increasing in Gel Strength of Oil Based Mud
27
For an oil based drilling fluid, there are
several points that will cause high gel
strength in the mud system as follows.
• Over treatment with organic gelling
material
• Build up of fine solid particles in the mud

28. Operational Impact of Excessive Gel Strength
28
Circulating Pressure
Excessive gel strength will lead to high pump initiation pressure to
break circulation after mud is in a static condition for a period of
time. High pump pressure may result in formation fracture and lost
circulation.
Cutting Suspension
Low gel strength indicates inability to suspend cuttings. It can lead
to pipe stuck and hole pack off due to insufficient cutting
suspension.
Barite Sag
Barite sag is a situation where barite cannot be suspended by
drilling mud because of low gel strength. It can be seen that when
large fluctuation of mud density coming out of hole.

29. Apparent viscosity WBM & OBM
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The viscosity of a fluid measured at the shear rate
specified by API.
In the Bingham plastic rheology model, apparent
viscosity (AV) is one-half of the dial reading at 600
rpm (1,022 sec–1 shear rate) using a direct-
indicating, rotational viscometer. For example,
a 600-rpm dial reading is 50 and the AV is 50/2,
or 25 cP.

30. API Fluid Loss Test WBM
API Fluid Loss Test (low-pressure, low-temperature filtration test) is a
test used to measure a filtration of mud with ambient temperature
and 100 psi differential pressure. The API fluid loss testing equipment
is shown Figure
How will the drilling mud be tested?
Place a filter
Add the sample into the testing chamber
Place the chamber in the testing kit
Apply 100 psi pressure
Record volume for 30 minutes; at the end of the test the volume of
filtrate will be recorded.
Record thickness of filter cake
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31. Filtration
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If drilling fluid has good fluid loss property, it will show a thin and
impermeable mud cake. Please keep in mind that this test is based on
the surface condition, and it may be in error because it does not
simulate down hole conditions. The API fluid loss test can lead you to
the wrong conclusion, because at the surface condition the test
demonstrates very good fluid loss and a very thin filter cake.
When the drilling mud is in a downhole condition, wellbore
temperature and pressure can dramatically change drilling fluid
properties . The best way to test the fluid loss is to simulate wellbore
condition at high pressure high temperature in order to see what the
fluid loss property will be. The procedure is called” HTHP Fluid Loss.”

32. 32

33. HTHP Fluid Loss Test WBM & OBM
The HTHP fluid loss test is similar to the API test because it indicates
information on drilling mud filtration into the formation under a
static condition over a certain period of time . For the HTHP fluid test,
both temperature and pressure can be varied to represent an
expected downhole condition. The HTHP testing equipment has a
heating jacket so you can heat up the drilling fluid sample to the
expected wellbore temperature. Typically, the recommended
temperature in the heating jacket should be above the estimated
temperate of about 25 F to 50 F. The test pressure is normally at 500
psi differential pressure. Normal test conditions are 150 F and 500
psi differential pressure and the maximum allowable test
temperature is 300 F with the standard equipment.
Mud filter cake thickness must be maintained below 2 mm. The
HTHP test is performed for 30 minutes, just like the API fluid lost test.
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34. Drilling Operational Impacts of Fluid Loss
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Formation damage
If the drilling mud does not have good fluid loss property, fluid with small
particles in the drilling mud can be invaded into formations and it will
cause formation damage. This will directly affect the production rate of
the well once it starts producing.
Differential sticking
The drilling fluid that has bad fluid loss will form a very soft and thick mud
cake across permeable formations. This can lead to differential sticking
because of an increase in the contact area between formation and drill
string.
Torque and drag
A thick mud cake across porous zones can be easily formed because the
drilling mud has high fluid loss values. The thicker the mud cake is, the
more torque and drag are experienced while performing the drilling and
tripping operations.

35. Mud Filter Cake WBM & OBM
Mud filter cake is a layer formed by solid particles in
drilling mud against porous zones due to differential
pressure between hydrostatic pressure and formation
pressure. For the drilling operation, it is preferred to have
a filter cake that is impermeable and thin. Practically, the
filter cake from API or HTHP fluid loss test should be less
than or equal to 1/16 inch.
If drilling fluid is not in a good shape, which results in a
thick filter cake in the wellbore, it will lead to a stuck pipe
situation and high torque/drag.
35

36. How will the filter cake impact on a drilling operation?
36
Differential sticking
If mud filter cake is thick, a contact area between drilling string or
any kind of tubular will be increased. When drilling into
permeable zones that are severely overbalanced, the drill stem
will have high chance to get differentially stuck across these
zones.
Moreover, not only can the drilling string get stuck, the logging
tool could be stuck across the permeable sands as well.
Torque and drag
Under dynamic conditions such as drilling, working pipe, etc.,
if drilling mud has a thick filter cake across the wall of the
wellbore, torque will increase. Furthermore, a thick wall filter
cake will result in high drag while tripping out of the hole or
logging.

37. 37

38. Solid Content in Drill Mud WBM & OBM
Solid content is a fraction of the total solid in
drilling mud, and it always increases while drilling
ahead because of drilling solid (cuttings), mud
chemical additives and weighting material. Solid
content refers to soluble and insoluble solid
content in the drilling fluid system.
There are three types of solid contents as listed
below;
Soluble material such as salt
Insoluble high gravity solid (HGS)
such as weighting agents (barite, calcium
carbonate, hematite, etc.)
Insoluble low gravity solid (LGS) or drilled solid
such as solids particles from‫ل‬
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39. Solid content
39
The drill solids are the worst solid content in the drilling fluid because it gradually
deteriorates mud properties. Moreover, if its particle size is less than 5 microns, these
drill solids cannot be removed by mechanical methods, and they will stay in the mud
forever. Generally, the drill solids will take up 6-7 percent of the total mud volume. Since
the drilled solid content is very important, it must be checked daily. For good drilling
practices, the drilled solid should be tested twice a day by retorting. The upper limit of
the drill solid faction should be 6-7 % by volume or approximately 55 – 60 lb/bbl.
Another critical value besides low gravity solid (LGS) and high gravity solid (HGS) is the
average density of weighting materials in drilling fluid. The weighting materials such as
Barite, Calcium Carbonate, Hematite, etc., have a specific gravity above 2.7. Table
1 demonstrates some important specific gravity of weighting materials.
However, the drilled solids usually have a specific gravity about 2.6. Hence, drill solids
will reduce average solid density when mixed in the drilling fluid. Normally, the
acceptable value of the average solid density is about 3.8 or higher. If this value is below
3.8, it indicates that there may be too much low gravity solid in the mud.

40. Retort
Retort 50 ml Retort 10 ml
40

41. The operational impacts of solid content
Equivalent Circulating Density (ECD)
ECD will be higher if the solid content increases. Excessive ECD will
lead to formation fracture and a loss circulation issue.
Differential Sticking
The filter cake will be thick and sticky, if there are a lot of low gravity
solids in the drilling mud. Due to this reason, the potential of getting
deferentially stuck across permeable formations is increased.
Rate of penetration
High concentration of the solid content will reduce the overall rate of
penetration. There are three solid contents added into the system.
The first two contents are weighting material and chemicals which are
needed to maintain good mud properties. The last one is the drill solid
which can be controlled by mechanical methods. If the drill solid
content is not controlled properly, drilling performance will decrease.
Surge/swab pressure
The excessive surge and swab pressures result from the high amount
of solid contents in the fluid system.
41

42. What is the difference between drill solids and barite?
42
Drill Solid: It is solid particles from formation generated while drilling. Its specific
gravity is about 2.6 which is normally defined as Low Gravity Solid (LGS).
Drill solid can increase mud weight; however, it will degrade mud properties such as
Yield Point, viscosity, gel strength, etc. If mud excessively gets drill solid, drilling fluid
properties especially rheology (Yield Point, viscosity) will be higher and mud cake with a
lot of drill solid will be poor quality. Higher rheology will lead to more required energy
in order to make circulation. In addition, poor mud cake can also lead to pipe struck
situation.
In order to control drill solid content in mud, solid control equipment as shale shakers,
desanders, desilters and centrifuges must be operated properly and effectively.
Barite: It is the weighting agent with specific gravity about 4.2 normally called High
Gravity Solid HGS . Both Drill solid and Barite are able to be weighting agent; however,
Barite does not degrade other mud properties such as PV, YP, gel strength, etc.

43. Alkalinity WBM
pH is a value representing the hydrogen ion concentration in liquid and it is used to
indicate acidity or alkalinity of drilling mud. The pH is presented in a numerical value
(0-14), which means an inverse measurement of hydrogen concentration in the fluid.
The pH formula is listed below;
pH = -log10[H]
Where: H is the hydrogen ion concentration in mol.
According to the pH formula, the more hydrogen atoms present, the more acidity of
substance is but the pH valve decreases. Generally speaking, a pH of 7 means neutral.
Fluids with a pH above 7 are considered as being alkaline. On the other hand , the
fluids with pH below 7 are defined as being acidic.
In the drilling mud, there are three main chemical components involved in Alkalinity of
drilling fluid, which are bicarbonate ions (HCO –) , hydroxyl ions (OH–)
3
and The Alkalinity means ions that will reduce the acidity.
In order to get accurate measurements for the pH, using a pH meter instead of using a
pH paper is recommended because it will give more accurate pH figures. Additionally,
pH meters must be calibrated fr
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44. pH in Drilling Mud
(Water Based Mud)
pH strips pH meter
44

45. Cause of a decrease in pH of drilling Mud
45
There are many factors that can cause reduction in pH of drilling
mud as listed below;
Water contamination The water contamination or water influx will
decrease pH in the drilling fluid because water is neutral.
Carbonate or Bicarbonate With these two chemical molecules, the
pH of drilling mud will be reduced.
Acid gases as Carbon dioxide (CO2) and Sulphur Dioxide (H2S)
If there are acid gases mixing in the system, the pH will
decrease. Additionally, acid gas has bad effect on mud properties.
The rheology of the mud as PV, YP, and gel strength will increase,
but Pm and Pf will decrease due to loss of pH.
Anhydrite Chemical components of Anhydrite will neutralize
hydrogen ions in the mud so pH of drilling mud will drop. It is
important to increase mud pH while drilling Anhydrite formation.

46. Pm = phenolphthalein of mud WBM
46
Pm stands for “phenolphthalein end point of the
mud” and it indicates quantities of Potassium
Hydroxide (KOH), caustic soda, cement, etc., in the
water base mud. The Pm refers to the amount of
acid required to reduce the pH of mud to 8.3. The
Pm test includes the effect of both dissolved and
non-dissolved bases and salts in drilling fluid.
Especially in lime mud, Pm is used to determine
the ratio of insoluble lime to soluble lime in the
filtrate.

47. Pf = phenolphthalein of filtrate WBM
47
Pf stands for the phenolphthalein
alkalinity of the mud filtrate. Pf is different
from the Pm because it tests the affect of
only dissolved bases and salts.
However, Pm includes the effect of both
dissolved and non-dissolved bases and
salts in drilling mud.

48. Mf = methyl orange of filtrate WBM
48
Mf stands for the methyl orange alkalinity end
point of mud filtrate and the definition of the
methyl orange alkalinity is the amount acid
used to reduce the pH to 4.3.
According to the API test, Pm, Pf and Mf are
shown in a daily mud report and all the figures
are reported in cubic centimeters of 0.02N
sulfuric acid per cubic centimeter of drilling
fluid sample.

49. Alkalinity cases
49
Pf and Mf are based on the mud filtrate tests that will
help people know about ions in the drilling mud.
There are three cases regarding Pf and Mf.
First case: Pf and Mf are similar in value to each other.
It indicates that the ions (hydroxyl ions) are the main
contributor to the mud alkalinity.
Second case: If Pf is low but the Mf is high,
it indicates that bicarbonate ions are in the mud.
Third case: if both figures (Pf and Mf) are high,
it means that carbonate ions are in the mud system.

50. Total Hardness Content in WBM & OBM
“Total Hardness” or “Water Hardness” is
a measurement of calcium (Ca2+) and
magnesium (Mg 2+) ions in water base
mud and oil base mud
.The total of both soluble ions of calcium
(Ca2+) and magnesium (Mg 2+) is given
by titration with standard Versenate
solution.
50

51. What will be happening if you have a lot of total hardness in
your drilling mud?
• Bad mud cake (thick and mushy)
• High fluid loss
• Flocculation of clay content
• Less polymer effectiveness
• Ineffective chemical treatment
For most of the water base mud, the acceptable
value of total hardness must be below 300 mg/L. If
the lime drilling mud is used, it is acceptable to
have a higher value but is should be kept below
400 mg/L.
51

52. Chloride Content in WBM
52
The chloride comes from salt in the formation, and chloride concentration can be
determined by titration with a silver nitrate solution .The amount of chloride must be
checked frequently .
If there are any abnormal changes in the chloride content, it can be an indication of
drilling into a salt formation or taking water influx from drilled formations
Why is it so important to maintain the amount of chloride in the drilling fluids?
The chloride is used to prevent a shale swelling problem.
How can the chloride content be maintained?
The chloride content in the drilling fluid can be maintained by adding salts such as
potassium chloride (KCl) and sodium chloride (NaCl). If potassium chloride (KCl) is used,
it is imperative to have sufficient potassium ions to react with the clay content from the
formation. Generally, 3 – 4% KCL is recommended for normal drilling. However, it may
require increasing the concentration of KCl if you are drilling into formations which have
a lot of reactive clay content.

53. Potassium Ion & KCL In Drilling Fluid Test
It is important to monitor and control the Potassium ion
concentration for Water Based Mud systems that use
Potassium for Shale Inhibition because it will deplete as it
is adsorbed onto shales .
Depletion needs to be monitored and effective inhibition
levels need to be maintained in the mud system.
The Potassium ion concentration is determined by adding
excess Sodium Perchlorate to a measured volume of mud
filtrate to precipitate out Potassium Perchlorate.
The precipitate is then centrifuged and the volume of the
compacted precipitate is converted to Potassium ion
concentration by reference to a calibration curve, which
must be prepared using the test reagents at the rig site
(see overleaf).
53

54. Glycol Concentration Test in WBM
Glycol is generally used in KCl-Polymer fluid systems when
enhanced Shale Inhibition is required.
Glycol will be lost through adsorption on exposed shale
formations in the wellbore and on the cuttings, and the glycol
depletion rate will be a function of drilling Penetration Rate
(ROP) and Cuttings size.
The glycol concentration test in drilling mud ( Refractometer )
therefore needs to be monitored to ensure that levels are
maintained for effective shale inhibition.
54

55. Methylene Blue Test (MBT) WBM
Methylene Blue Test (MBT) or Cation Exchange
Capacity is used to determine the amount of reactive
clay (clay-like materials) in a water base mud.
A methylene blue dye (a cation dye) is utilized for this
test because it powerfully magnetizes the negative
ions in the clay . Typically, the test is reported in terms
of the reactive clay concentration in pounds per
barrel, bentonite equivalent.
Same as other mud properties, tracking the MBT and
observed for trend changes are required in order to
maintain good mud conditions.
If an increase in MBT is observed, it indicates that the
drill solid concentration in the drilling mud increases.
For a good drilling operation, the MBT should be kept
at 15 lb/barrel or less. 56

56. Water Phase Salinity of OBM
Water phase salinity WPS is a factor showing the
activity level of salt in oil based mud. In order to
control the water phase salinity, salt is added into the
drilling fluid. The salt added into the system will be
dissolved by water in the mud; therefore, the chloride
content will increase.
By increasing the chloride concentration (adding salt),
the activity level in the mud will decrease. Salt is
added in order to create an activity level which is
equal to or less than formation water. Therefore, the
water phase in the mud will not move into formation
and cause a clay swelling issue.
Practically, calcium chloride (CaCl2) or sodium chloride
(NaCl) is the chemical to be used.
56

57. When salt must be added into the mud system?
Typically, while drilling with oil based mud,
cuttings are generally dry, hard, and easy to
break into pieces.
However, if the cuttings come together in big
pieces and are wet, it may increase salt
content in the drilling fluid.
The reason is that water in the mud moves
into formations and swells the clay particles in
the formation.
Swelled clay causes wet and mushy cuttings.
57

58. Functions and Importance of Electrical
Stability of Oil Based Mud
The Electrical Stability (ES) is one of the vital properties for oil
based mud. It shows the voltage of the current flowing in the
mud. The ES number represents the mud emulsion stability.
The more ES is; the more the emulsion stability is.
Oil based fluid is a non-conductive material. Therefore, the
base fluid will not transfer any current. Only the water phase
in the mud will conduct the electricity. If the mud has good
emulsion, you will have high ES figures.
On the other hand, if the emulsion of the mud is bad, you
will have low ES value.
The Electrical Stability (ES) is obtained from an electrical
stability tester kit as in the figure
There are several factors that can weaken the emulsion, such
as oil/water ratio, solid content, pressure, temperature, some
types of weighting material, etc 59

59. What the Electrical Stability (ES) will tell us?
59
If ES is lower than a normal mud specification, it indicates that
there is something unusual in the mud such as water or salts,
which will make emulsion of the oil based mud in bad shape.
Moreover, the ES can be utilized to determine an interface
between water and oil based mud while displacing water with oil
based fluid.
For good drilling practices, it is required to frequently monitor
the ES level and watch for any unusual changes. Changes in the
ES can be seen while drilling into green cement or while adding
any conductive material as stated earlier. These known factors
affecting the ES must be noted in order to prevent any confusion
when interpreting the mud’s property.

60. Alkalinity Excess Lime (Oil
Based Mud Properties)
For most of oil based mud, lime (Ca(OH)2) is used in
the system in order to perform a chemical reaction
with fatty acid emulsifiers.
Typically, 3 to 5 lb/bbl of lime is added in the drilling
mud so that there is enough hydroxide (OH-1) ions
to keep the emulsion stability in good shape.
Moreover, lime (Ca(OH)2) will control acid gases
such as H2S and CO2.
The following chemical equations demonstrate how
lime reacts with H2S and CO2, respectively.
Ca(OH)2 + H2S -> CaS + 2(H2O)
Ca(OH)2 + CO2 -> CaCO3 + H2O
60

61. Calculate Oil-Water Ratio
from Retort Data
Oil Water Ratio (OWR) is a figure representing the fraction of oil
and water in oil based drilling mud. Generally speaking, it is a ratio
between the percent oil in liquid phase and the percent water in
liquid phase. In order to determine OWR, volume of oil/water/solid
in drilling mud comes from a retort analysis.
A sample of oil based mud is controlled burnt in a retort kit at
required temperature. When the mud is heated, water and oil will
be extracted out and solid is left in the retort kit. The retort analysis
report shows percentage of each component by volume so we use
data from the retort analysis to determine oil water ratio.
61

62. how to calculate oil water ratio from retort data.
62
a) % oil in liquid phase =
(% by volume oil x 100) / (% by volume oil + %
by volume water)
b) % water in liquid phase =
(% by volume water x 100) ÷ (% by volume oil +
% by volume water)
c)Result: The oil/water ratio equals to the
percent oil in liquid phase and the percent water
in liquid phase.

63. Example
63
Determine oil water ratio from following information
Data from a retort analysis:
% by volume oil = 56
% by volume water = 14
% by volume solids = 30
Solution:
a) % oil in liquid phase = (56 x 100) ÷ (56+14)
% oil in liquid phase = 80
b) % water in liquid phase = (14 x 100) ÷ (56+14)
% water in liquid phase = 20
c) According to this retort report, the oil/water ratio equals to
80/20.