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Water-Base Systems
نویسنده : رضا سپهوند - ساعت ۳:۱٥ ‎ب.ظ روز ۱۳٩٤/۸/۱۳
 
Water-Base Systems
Water-Base Systems 10.1 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
10
Many different types of water-base drilling
fluid systems (muds) are used in
drilling operations. Basic drilling fluid
systems are usually converted to more
complex systems as a well is deepened
and the wellbore temperature and/or
pressure increases. It is typical for several
types of drilling fluid systems to be used
in each well. Several key factors affect
the selection of drilling fluid system(s)
for a specific well. The most cost-effective
drilling fluid for a well or interval should
be based on the following criteria:
Application
• Surface interval.
• Intermediate interval.
• Production interval.
• Completion method.
• Production type.
Geology
• Shale type.
• Sand type.
• Permeability.
• Other formation types.
Makeup water
• Type of water.
• Chloride concentration.
• Hardness concentration.
Potential problems
• Shale problems.
• Bit/Bottom-Hole Assembly
(BHA) balling.
• Stuck pipe.
• Lost circulation.
• Depleted sands.
Rig/drilling equipment
• Remote location.
• Limited surface capacity.
• Mixing capabilities.
• Mud pumps.
• Solids-control equipment.
Contamination
• Solids.
• Cement.
• Salt.
• Anhydrite/gyp.
• Acid gases (CO2, H2S).
Drilling data
• Water depth.
• Hole size.
• Hole angle.
• Torque/drag.
• Drilling rate.
• Mud weight.
• Maximum temperature.
Water-base drilling fluids can usually
be placed into one of the following
classifications:
• Unweighted clay-water systems.
• Deflocculated, weighted clay-water
systems.
• Calcium-treated, weighted,
deflocculated clay-water systems.
• Saltwater systems.
• Inhibitive potassium systems.
• High-Temperature, High-Pressure
(HTHP) deflocculated systems.
• HTHP polymer systems.
• Encapsulating polymer systems.
• Cationic polymer systems.
• Extended or flocculated clay-based
systems.
• Polyglycol enhanced systems.
• Inhibitive silicate systems.
Introduction
It is typical
for several
types of
drilling fluid
systems to
be used in
each well.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.2 Revision No: A-0 / Revision Date: 03·31·98
This basic system is essentially
M-I GELT (Wyoming bentonite) and
water. Usually, this system is used to
spud a well. As drilling continues, formation
solids are incorporated into the
drilling fluid. Solids-removal equipment
is used to remove as much of the formation
solids (drill solids) as possible. Some
of the native formation solids may be
bentonitic in nature and increase the
viscosity of the drilling fluid. Therefore,
this system is often referred to as a
“native mud.” Advantages of this system
are low cost and high Rate of
Penetration (ROP). This system is
often extremely shear-thinning.
Unweighted, clay-water systems usually
are converted to another system
prior to reaching any critical part of
the well. Therefore, the solids content
should be maintained at low values to
facilitate this conversion.
Since this system is not weighted, it
has a low buoyancy effect on cuttings.
Therefore, hole-cleaning depends on viscosity
and flow rate. The plastic viscosity
should be low, if the solids content of
the system is low, so the carrying capacity
must be achieved with higher yield
points. Chemical deflocculants reduce
the yield point and viscosity dramatically.
This can result in inadequate hole
cleaning. Therefore, the use of chemical
deflocculants in this system should be
strictly limited. If a low fluid loss is
required, it should be controlled with
additions of M-I GEL (prehydrated if
used in seawater) and an appropriate
Fluid-Loss-Control Additive (FLCA).
The FLCA may be MY-LO-JELE, POLY-SALE,
THERMPACT UL, CMC or POLYPAC.T
Unweighted Clay-Water Systems
Typical Properties
Density (lb/gal) 8.5 - 10
Funnel viscosity (sec/qt) 36 - 55
Plastic viscosity (cP)* 5 - 9
Yield point (lb/100 ft2)* 12 - 25
Initial gel (lb/100 ft2) 5 - 10
10-min gel (lb/100 ft2) 10 - 20
pH 8.5 - 10.5
Pm (cm3 0.02N H2SO4) 0.1 - 1.5
Pf (cm3 0.02N H2SO4) 0.1- 1.0
Calcium (mg/l) 40 - 240
Chlorides (mg/l)
(freshwater) 0 - 5,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%) 3 - 10
MBT (lb/bbl) See Figure 1
*See Figure 1.
Typical Products Primary Function
M-I GEL Viscosity and
fluid-loss control
Caustic soda Increase pH and Pf
TANNATHINT Thinner
SAPP Thinner
POLYPAC Viscosity and
fluid-loss control
THERMPAC UL Fluid-loss control
MY-LO-JEL Fluid-loss control
POLY-SAL Fluid-loss control
POLY-PLUST Bentonite extender
CMC Viscosity and
fluid-loss control
Concentration
Material (lb/bbl)
M-I GEL 20 - 35
Caustic soda 0.1 - 0.5
FLCA As needed
SAPP 0.125 - 0.5
Usually,
this system
is used to
spud a well.
…the use
of chemical
deflocculants
in this system
should
be strictly
limited.
Water-Base Systems
Water-Base Systems 10.3 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
10
Figure 1: Plastic viscosity, yield point and Methylene Blue Test (MBT) ranges for water-base muds.
50
45
40
35
30
25
20
15
10
5
0
9 10 11 12 13 14 15 16 17 18 19 20
Mud weight (lb/gal)
PV (cP), YP (lb/100 ft2) and MBT (lb/bbl)
PV
MBT
YP
Figure 2: Solids range for barite water-base muds.
50
45
40
35
30
25
20
15
10
5
0
9 10 11 12 13 14 15 16 17 18 19
Mud weight (lb/gal)
Solids (% vol)
Maximum
9% LGS
6% LGS
3% LGS
Minimum
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.4 Revision No: A-0 / Revision Date: 03·31·98
The SPERSENEE deflocculated system
is one of the most common drilling
fluid systems used in the industry.
The primary thinner in the system is
SPERSENE (or SPERSENE CF) lignosulfonate.
Lignosulfonates are organic acids that
supply anions (negative ions) to the
fluid. These anions reduce the yield
point and gel strengths by neutralizing
the cations (positive ions) on the clay
particles, thus deflocculating the clay
slurry causing clay particles to repel one
another. SPERSENE is very versatile due to
its high degree of solubility in both
freshwater and saltwater environments.
Since it is acidic, SPERSENE requires an
alkaline environment in which to solubilize.
Therefore, hydroxyl ions are
added usually in the form of caustic
soda (sodium hydroxide) and lime (calcium
hydroxide) to increase the pH.
This system can be treated to have a
high degree of tolerance for both solids
and chemical contamination by simply
increasing the concentration of SPERSENE
and TANNATHIN (lignite) or XP-20T (causticized
chrome lignite). Lignite is an
organic acid that also supplies anions to
the fluid, thus causing clay particles to
repel one another. In most cases, a
ratio of two SPERSENE to one TANNATHIN,
or XP-20, is a very effective combination
for treatments, but the ratio can
be varied.
Materials like SPERSENE, TANNATHIN and
XP-20 are deflocculants, but are also
referred to as dispersants and thinners,
because they allow discrete clay particles
to disperse, and they reduce the
yield point, gel strength and “n” value
of the drilling fluid.
SPERSENE systems are usually converted
from unweighted, clay-water
suspensions or “spud muds.” A typical
treatment to convert to a lightly
treated SPERSENE system would be
SPERSENE System
The SPERSENE
deflocculated
system is one
of the most
common
drilling fluid
systems
used in the
industry.
Figure 3: Solids range for hematite water-base muds.
50
45
40
35
30
25
20
15
10
5
0
9 10 11 12 13 14 15 16 17 18 19 20 21 22
Mud weight (lb/gal)
Solids (% vol)
Maximum
Minimum
9% LGS
6% LGS
3% LGS
Water-Base Systems
Water-Base Systems 10.5 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
10
(SPERSENE SYSTEM CONTINUED)
about 4 lb/bbl M-I GEL, 2 lb/bbl
SPERSENE, 1 lb/bbl of either TANNATHIN
or XP-20 and 1 lb/bbl caustic soda.
Comparing the drilling fluid properties
at the flow line with those in the
pits indicates the degree to which wellbore
contaminants are affecting the
drilling fluid properties. This is also a
reflection of the stability of the system.
In most cases, a significant difference
in the properties between the flow line
and the pits indicates an unstable fluid.
The stability of a SPERSENE system can
be increased by increasing the concentration
of SPERSENE and TANNATHIN (or
XP-20). Lightly treated SPERSENE systems
contain 2 to 6 lb/bbl SPERSENE and 1 to
3 lb/bbl of TANNATHIN (or XP-20), while
a fully inhibitive SPERSENE system may
contain 8 to 12 lb/bbl SPERSENE and 4 to
6 lb/bbl of TANNATHIN or (XP-20).
Maintenance of a SPERSENE system
(and other drilling fluids systems) while
drilling means maintaining the properties
at predetermined, near-constant
values. These values are controlled by
the concentration of materials in the
drilling fluid. As water is added to the
drilling fluid to maintain an acceptable
drilled solids concentration, products
must be added to maintain the desired
concentration of additives. Therefore,
the volume of dilution water should be
measured or estimated to use as a basis
for product additions. The amount of
dilution required depends on the hole
size, rate of penetration, type of formation,
solids-control equipment and the
optimum concentration of drill solids
in the drilling fluid.
The temperature limitation of this
system is approximately 320°F (160°C)
due to the increased rate of thermal
degradation of lignosulfonate above
this temperature. The temperature limit
of this system can be increased significantly
by increasing the concentration
of lignite and reducing the concentration
of lignosulfonate. Lignite has
a temperature limitation of about
450°F (232°C).
NOTE: SPERSENE and XP-20 contain
chrome and may not be allowed under
some environmental regulations. When
chrome is not permitted, SPERSENE CF and
TANNATHIN should be used.
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3.5 x mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 2 - 8
10-min gel (lb/100 ft2) 2 - 14
pH 9.5 - 11.5
Pm (cm3 0.02N H2SO4) 2.0 - 5.0
Pf (cm3 0.02N H2SO4) 0.5 - 1.5
Calcium (mg/l) 40 - 240
Chlorides (mg/l) 0 - 20,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 5 - 7
MBT (lb/bbl) See Figure 1
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL Viscosity and
fluid-loss control
Caustic soda Increase pH and Pf
Lime Increase Pm and
treat out CO3
Gyp Treat out CO3
SPERSENE (CF) Thinner
TANNATHIN Fluid loss and thinner
XP-20 HT thinner and
fluid-loss control
POLYPAC API fluid-loss control
and viscosity
RESINEXT HTHP fluid-loss control
DUO-VIST Increase low-shear
viscosity
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 5 - 30
Caustic soda 0.3 - 2
Lime 0 - 1
SPERSENE (CF) 2 - 12
XP-20 or TANNATHIN 1 - 12
POLYPAC 0.50 - 2
RESINEX 2 - 6
DUO-VIS 0.25 - 0.50
Lignite has a
temperature
limitation
of about
450°F…
The concentration
of
reactive
solids in
the drilling
fluid
determines
the viscosity
increase
encountered
when calcium
is added to
the system.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.6 Revision No: A-0 / Revision Date: 03·31·98
When calcium is added to a clay-water
slurry, a base exchange occurs as the calcium
(Ca2+) cation, which has higher
bonding energy, replaces the sodium
(Na+) cation on the clays, converting
them to calcium-base clays. Figure 4
shows the amount of calcium adsorbed
by Wyoming bentonite and native
clays. This cation exchange results in
partial dehydration of the hydrated clay
particles, reducing the size of the water
envelope around the clay particles (see
Figure 5). The reduction in the size
of the water envelope allows the clay
particles to come into contact with
one another, resulting in flocculation.
Flocculation causes an increase in the
yield point and gel strengths. If a deflocculant
is not used, the size of the flocs
of clay eventually will increase and may
precipitate out, resulting in a gradual
decrease in the plastic viscosity.
If a deflocculant is used, then the
clays will still have the reduced water
envelope, but the flocs of clay will
be dispersed.
This phenomenon occurs when calcium
contamination occurs while drilling
then is subsequently treated, or
when a fluid is converted (“broken
over”) to a calcium-base drilling fluid
such as a SPERSENE/gyp or a SPERSENE/
lime system.
The concentration of reactive solids in
the drilling fluid determines the viscosity
increase (viscosity hump) encountered
when calcium is added to the
system (see Figure 6). Therefore, prior to
converting to a calcium-base system, or
before drilling into formations that contain
calcium (such as anhydrite), the
reactive solids content of the drilling
fluid should be reduced by dilution
while the viscosity is maintained with
additions of polymers.
Calcium systems provide soluble
and reserve calcium in a drilling fluid.
Soluble calcium performs several functions.
It provides wellbore inhibition
by minimizing the hydration of drill
solids and exposed shales through
base exchange into calcium-based
clays. It makes a drilling fluid compatible
with formations that contain high
Calcium-Treated Drilling Fluids
Figure 4: Adsorption of calcium by clays.
16
14
12
10
8
6
4
2
0
0 500 1,000 1,500 2,000
Filtrate calcium (mg/l)
Calcium adsorbed (mg/g)
Wyoming
bentonite
Native clay
Figure 5: Reduction in water of hydration for sodium
clay during base exchange with calcium.
Na+
Na+
Na+
Ca2+
Water of hydration
(envelope of water)
+ Ca2+
Flocculation
causes an
increase in
the yield
point and gel
strengths.
Ca2+
Figure 6: Effect of solids concentration
on viscosity with calcium additions.
100
80
60
40
20
0
0 100 200 300 400 500 600 700 800
Filtrate calcium (mg/l)
Viscosity (cP)
High solids
Low solids
Water-Base Systems
Water-Base Systems 10.7 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
10
(CALCIUM-TREATED DRILLING
FLUIDS CONTINUED)
concentrations of calcium, such as
anhydrite. It precipitates carbonate
ions (CO3
2–) which result from carbon
dioxide (CO2) contamination.
The solubility of calcium is inversely
proportional to the pH of the drilling
fluid. It is nearly insoluble at a pH above
12.5, but is very soluble at a low pH.
This is illustrated in Figure 7 where, on
Line A (when only lime is added), the
pH does not increase above 12.5, but
on Line B (with added caustic), the pH
increases above 12.5 and the soluble
calcium decreases rapidly. Therefore,
calcium as lime (Ca(OH)2) helps to
buffer the pH when acid gases such
as CO2 or hydrogen sulfide (H2S)
are encountered.
Calcium solubility is also directly
related to salinity or chloride (Cl–) concentration.
The soluble calcium in seawater
is often around 1,200 mg/l and
will increase as the salinity is increased,
as shown in Figure 8. Figure 8 shows
the soluble calcium from gyp added
to increasing concentrations of salt.
SPERSENE/GYP SYSTEM
The SPERSENE/gyp (gypsum) system is
designed to drill anhydrite (CaSO4)
and/or provide inhibition while drilling
water-sensitive shales by using gypsum
(CaSO4•2H2O) as the source of calcium.
To maintain a sufficient amount of soluble
calcium, the pH of the SPERSENE/gyp
system should be kept low (9 to 10.5).
The normal concentration of soluble
calcium in this system is in the 600 to
1,200 mg/l range. Since the solubility
of calcium is affected by pH and salinity,
the actual level will depend on
these properties.
When converting an existing
untreated or lightly treated system
to a SPERSENE/gyp system, the MBT and
low-gravity solids content should be
reduced to minimize the “break-over
viscosity hump.” Then, about 8 lb/bbl
gyp, 8 lb/bbl SPERSENE and 2 lb/bbl caustic
soda should be added simultaneously
over one or two circulations. After the
initial conversion, properties such as
fluid loss, pH and alkalinity should be
refined by the additions of the proper
materials. Materials that have a low
hardness tolerance should not be used
in this system. Since soluble calcium
increases the hardness of the water
phase, treatments with about 2 lb/bbl
SURFAK-ME are beneficial for reducing
the surface tension of the water phase,
and improving the performance of the
chemical additives.
In addition to the maintenance
procedures previously described, the
“excess gyp” test should be used to
Figure 8: Solubility of calcium vs. chlorides.
2.0
1.6
1.2
0.8
0.4
0
0 50 100 150 200
Chlorides (mg/l x 1,000)
Soluble calcium (mg/l x 1,000)
Figure 7: Line A - soluble calcium vs. lime
concentration; Line B - Soluble calcium of 4 lb/bbl
of lime added to caustic solutions.
1,000
900
800
700
600
500
400
300
200
100
0
0 1 2 3 4 5 6
Caustic soda or lime concentration (lb/bbl)
Calcium (mg/l)
pH 12.4
Line A
pH 12.2
pH 12
pH 12.4
pH 12.9
pH 13.2
Line B
Materials
that have a
low hardness
tolerance
should not
be used in
this system.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.8 Revision No: A-0 / Revision Date: 03·31·98
(SPERSENE/GYP SYSTEM CONTINUED)
monitor the concentration of excess
gyp in the system. Mass-balance equations
cannot accurately monitor excess
gyp, because gyp is removed from the
system on drilled solids due to base
exchange.
Excess gyp procedure
The excess gyp content can be determined
by measuring the “whole mud
Versenate total hardness” (Vt) and the
total hardness of the filtrate (Vf) using
this procedure and the calculation
which follows:
Procedure to determine the gyp content
(see API RP13B-1, Appendix A.8):
1. Add 5 ml whole mud to 245 ml
distilled water.
2. Stir for 30 min at room temperature
or 15 min at 150°F.
3. Filter the solution with the API filter
press. Discard the first cloudy
portion of the filtrate. Collect the
clear filtrate.
4. Pipette 10 ml of the collected clear
filtrate into a titration dish and add
1 ml strong buffer and 4 to 6 drops
Calmagite Indicator.
5. Titrate with Standard Versenate to a
blue or blue-green end point, record
the number of ml of Standard
Versenate as Vt.
6. To 1 ml of mud filtrate from the
standard API filtrate test, add 1 ml
strong buffer and 4 to 6 drops
Calmagite Indicator, titrate with
Standard Versenate from wine-red
to blue, record the number of ml
of Standard Versenate as Vf.
Total calcium sulfate (lb/bbl) =
2.38 x Vt
Excess calcium sulfate (lb/bbl) =
2.38 x Vt - (0.48 x Vf x Fw)
Where:
Fw = Water fraction from retort
NOTE: A simplified field method
titrates 1 ml of whole mud in 150 to
350 ml distilled water in a quart jar,
using 2 to 3 ml strong buffer and 1 to
2 ml Calmagite Indicator. Record the ml
of Standard Versenate as the Vm. The
color change may be hard to see due to
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3.5 x mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 1 - 10
pH 9.0 - 10.5
Pm (cm3 0.02N H2SO4) 0.5 - 2.5
Pf (cm3 0.02N H2SO4) 0.2 - 1.6
Calcium (mg/l) 600 - 1,200
Chlorides (mg/l) 0 - 20,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 4.5 - 7
MBT (lb/bbl) See Figure 1
Excess gyp (lb/bbl) 3 - 12
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL (prehydrated) Viscosity and
fluid-loss control
Caustic soda Increase pH and Pf
Gyp Calcium source
SPERSENE Thinner
TANNATHIN Fluid-loss control
POLYPAC API fluid-loss control
RESINEX HTHP fluid-loss control
SURFAK-ME Surface-acting agent
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 7.5 - 25
Caustic soda 0.2 - 1.5
Gyp 8 - 12
SPERSENE 5 - 15
TANNATHIN 2.5 - 10
POLYPAC 0 - 2
RESINEX 3 - 6
SURFAK-M 0 - 2
Water-Base Systems
Water-Base Systems 10.9 Revision No: A-0 / Revision Date: 03·31·98
CHAPTER
10
the dark brown color of the lignosulfonate
and lignite. This color change may appear
to be from the original color of the solution
with a red tint to only a slight green or bluegreen
tint. The rule-of-thumb calculation for
this procedure is:
Excess gyp (lb/bbl) = (Vm+Vf) ÷ 2
SPERSENE/LIME SYSTEM
Generally, SPERSENE/lime systems are
used to reduce the effects of acid
gases such as CO2 or H2S and/or to
reduce the hydration of formation
clays. SPERSENE/lime systems use lime
(Ca(OH)2) as their source of calcium.
Since lime has a high pH (12.4), the
pH of the system will be high. The
pH of the system depends on the concentration
of lime and caustic soda
(NaOH). Lime muds maintain a concentration
of excess lime which is not
in solution, since the solubility of
lime is an inverse function of pH.
Therefore, this excess (reserve) lime
goes into solution only as the pH of
the system is reduced by reactions
with acidic contaminants incorporated
into the system during drilling
operations. This results in the excess
lime having a buffering effect on the
pH, which provides greater stability to
the system.
Lime muds are subdivided into low-,
medium- and high-lime categories
according to the amount of excess
lime that they contain. This level of
excess lime is chosen based on the anticipated
severity of contamination and
on local practice. Typical alkalinities
and excess lime concentrations for
the low-, medium- and high-lime categories
are shown below. These systems
are more stable if the Pf is kept roughly
equal to the excess lime content
(lb/bbl). Lime muds generally are
not used when mud densities are
below 10 lb/gal because it is difficult to
maintain rheological properties sufficient
to clean the wellbore. Temperatures in
excess of 300°F (149°C) may cause
severe gelation or cementation of
medium- and high-lime drilling fluids.
This severe gelation, or cementation,
is caused by high alkalinity, high concentrations
of reactive solids and high
temperature which combine to form
alumino-silica cement.
When converting an existing
untreated or lightly treated system
to a SPERSENE/lime system, the MBT
and low-gravity solids content should
be reduced to minimize the “break-over
viscosity hump.” Then a treatment of 1
to 10 lb/bbl lime, 2 to 12 lb/bbl SPERSENE
and 2 lb/bbl caustic soda should be
added simultaneously during one or
two circulations. After the initial conversion,
properties such as fluid loss, pH
and alkalinity should be refined by the
additions of the proper materials.
In addition to the maintenance procedures
previously described, the “excess
lime” should be calculated as often as
required to monitor the concentration
of excess lime in the system. Massbalance
equations cannot accurately
monitor excess lime, because lime is
removed from the system on drilled
clays as the result of base exchange.
The equation for calculating excess
lime is:
Excess lime (lb/bbl) = 0.26 (Pm - PfFw)
Generally,
SPERSENE/lime
systems are
used to
reduce the
effects of
acid gases…
Alkalinities
Low-lime Pf (cm3 0.02N H2SO4) 0.5 - 1
Pm (cm3 0.02N H2SO4) 2.4 - 4.8
Excess lime (lb/bbl) 0.5 - 1
Medium-lime Pf (cm3 0.02N H2SO4) 1 - 4
Pm (cm3 0.02N H2SO4) 4.8 - 19
Excess lime (lb/bbl) 1 - 4
High-lime Pf (cm3 0.02N H2SO4) 4 - 10
Pm (cm3 0.02N H2SO4) 19 - 46
Excess lime (lb/bbl) 4 - 9.4
_______________________
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Water-Base Systems
CHAPTER
10
Water-Base Systems 10.10 Revision No: A-0 / Revision Date: 03·31·98
Typical Properties
Density (lb/gal) 10 - 16
Funnel viscosity (sec/qt) ± (3.5 mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 1 - 10
pH 11.5 - 13.5
Calcium (mg/l) 40 - 200
Chlorides (mg/l)
(freshwater) 0 - 5,000
Chlorides (mg/l)
(seawater) 20,000
Low-gravity solids (%)* 4.5 - 7
MBT (lb/bbl) See Figure 1
Excess lime (lb/bbl) 1 - 10
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL (prehydrated) Viscosity and
fluid-loss control
Caustic soda Increase Pf
Lime Excess lime and
increase Pm
SPERSENE Fluid loss and thinner
TANNATHIN Fluid-loss control
XP-20 HTHP thinner and
fluid-loss control
POLYPAC Viscosity and
API fluid-loss control
MY-LO-JEL Fluid-loss control
POLY-SAL Fluid-loss control
RESINEX HTHP fluid-loss control
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 15 - 30
Caustic soda 0.5 - 1.5
Lime 0.5 - 10
SPERSENE 2 - 15
XP-20 or TANNATHIN 3 - 8
RESINEX 0 - 6
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
_______________________
(SPERSENE/LIME SYSTEM CONTINUED)
Water-Base Systems
Water-Base Systems 10.11 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
Seawater and brackish-water systems
are used in offshore and coastal drilling
operations due to the endless supply of
that type of water at the drillsite. Other
benefits derived from using sea or
brackish water in drilling fluids include
a lesser degree of hydration of drilled
clays than when using freshwater.
An understanding of seawater drilling
fluids requires an understanding of seawater,
and how mud components react
in it. The pH of seawater is buffered
against changes by a solubility equilibrium
with atmospheric CO2 and sedimentary
calcium carbonate. This means
that as the pH of seawater is increased
through the addition of alkaline materials,
atmospheric CO2 will be absorbed
into the seawater in an effort to buffer
the pH. Since the buildup of these carbonates
is detrimental to drilling fluid
properties, an excess concentration of
lime (which is not in solution) is maintained
in the system. The lime prevents
the build-up of carbonates and buffers
the pH in the desired range. So, a seawater
mud should be run as a “low-lime
system” (see lime muds).
The cost-effectiveness of XP-20 and
TANNATHIN in seawater is minimized
due to their reduced solubility; therefore,
in environments where chlorides
exceed 15,000 mg/l, the use of lignites
should be minimized and the use of
SPERSENE increased.
The temperature limitation of this system
is approximately 320°F (160°C). If
bottom-hole temperatures greater than
320°F (160°C) are anticipated, freshwater
should be added to reduce the chlorides
to less than 15,000 mg/l so that XP-20
will be more soluble. Or, displace with a
synthetic- or oil-base system.
Since this system is similar to a
SPERSENE/low-lime system, conversion
and maintenance are the same as with
a SPERSENE/low-lime system.
SPERSENE/XP-20 Seawater System
…a seawater
mud should
be run as a
“low-lime
system”.
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3.5 x mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 1 - 10
pH 10.5 - 11.5
Pm (cm3 0.02N H2SO4) 3.0 - 6.0
Pf (cm3 0.02N H2SO4) 1.0 - 1.5
Calcium (mg/l) 40 - 200
Chlorides (mg/l) 20,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 5 - 7
MBT (lb/bbl) See Figure 1
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL (prehydrated) Viscosity and
fluid-loss control
Caustic soda pH and Pf
Lime Treat out carbonates
SPERSENE Thinner and
fluid-loss control
XP-20 HTHP thinner and
fluid-loss control
TANNATHIN Fluid-loss control,
thinner
POLYPAC Stability,
fluid-loss control
THERMPAC UL Fluid-loss control
THERMEX HTHP fluid-loss control
RESINEX HTHP fluid-loss control
DUO-VIS Low-shear viscosity
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 10 - 30
Caustic soda 0.2 - 1.5
Lime 0.2 - 1.5
SPERSENE 5 - 15
XP-20 or TANNATHIN 3 - 8
POLYPAC 0.5 - 2.0
THERMEX 5 - 10
RESINEX 0 - 6
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.12 Revision No: A-1 / Revision Date: 07·17·98
Saturated saltwater systems are designed
to prevent the enlargement of the wellbore
while drilling salt sections. This
enlargement results from the salt in
the wellbore dissolving into the “unsaturated
salt” water phase of the drilling
fluid. Saturation is achieved by adding
salt (sodium chloride) to the mud system
until the saturation point is reached.
Saturation is about 190,000 mg/l chlorides,
depending on temperature. See
the Drilling Salt chapter.
To convert an existing freshwater,
brackish water or seawater system to a
saturated saltwater system, the following
procedure should be followed. On
the initial break-over, add as quickly
as possible: 2 to 3 lb/bbl caustic soda,
1 to 2 lb/bbl soda ash, 4 to 6 lb/bbl
SPERSENE and 110 to 125 lb/bbl salt.
The salt will flocculate the reactive
solids in the system, increasing the
viscosity. Therefore, the MBT and
low-gravity solids content should be
reduced to minimize the viscosity
increase during conversion. This viscosity
hump is shown in Figure 9.
Pilot tests should be made prior to
conversion to determine the dilution
rate and quantities of products required
for a trouble-free conversion. After
all the salt has been added, 2 lb/bbl
SURFAK-M also should be added. Initially,
the salt may cause an increase in viscosity,
but this will diminish after several
circulations through the hole. This
should be followed by 0.5 to 1.0 lb/bbl
of POLYPAC UL, which should reduce the
viscosity to the desired range. If not,
further dilution with saturated saltwater
and additions of SPERSENE should be
made. Treatments of SPERSENE are more
effective when mixed with caustic in
drill water then added to the system.
To mix a saturated saltwater system,
20 to 25 lb/bbl M-I GEL should be prehydrated
in freshwater and added to
the saltwater. Then, other materials can
be added as described above. SALT GELT
can be used instead of M-I GEL if the
rig mixing system develops good shear.
SALT GEL requires shear to develop viscosity
and does not assist with fluid
loss or filter-cake quality.
When saturated saltwater is added
to the drilling fluid to maintain an
acceptable drilled solids concentration,
products must be added to maintain
the desired concentration of
additives. Therefore, the volume of
dilution water should be measured or
estimated to use as a basis for product
additions. Materials must be based
on the added saltwater. The amount
of dilution depends on the hole size,
ROP, type of formation, solids-control
equipment and the optimum concentration
of drilled solids in the drilling
fluid. Frequent chloride checks should
be made to monitor the salt content
for saturation.
Saturated Saltwater System
Figure 9: Effect of solids content on
viscosity with salt additions.
45
40
35
30
25
20
15
10
5
0
0 35 70 105 104
Salt (lb/bbl)
Viscosity (cP)
Salt added to
high-solids field mud
Saturated
saltwater
systems are
designed to
prevent the
enlargement
of the
wellbore
while
drilling salt
sections.
Salt added to prehydrated
bentonite slurry
Dry bentonite added
to salt solution
Frequent
chloride
checks
should be
made to
monitor
the salt
content for
saturation.
Water-Base Systems
Water-Base Systems 10.13 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(SATURATED SALTWATER
SYSTEM CONTINUED)
Provisions should be made to ensure
that all dilution water is saturated prior
to being added to the active system.
In areas where humidity is high, salt
absorbs water, becomes lumpy and is
almost impossible to mix through mud
hoppers fast enough to keep the drilling
fluid saturated. If salt is mixed
directly into the mud, about half the
salt may become coated by the mud
and settle to the bottom of the pits. It
is far more cost-effective to mix the salt
into the water.
When considering the use of a saturated
salt drilling fluid in low-density
environments, it is important to be
aware that the natural weight of saturated
sodium chloride is 10 lb/gal. The
minimum density of a saturated
sodium chloride drilling fluid is
about 10.5 lb/gal.
The temperature limitation of this
system is less than 300°F (149°C). If
bottom-hole temperatures greater than
300°F (149°C) are anticipated, alternative
high-temperature water-base
products must be used or the system
should be displaced with a syntheticor
oil-base drilling fluid.
Typical Properties
Density (lb/gal) 10 - 16
Funnel viscosity (sec/qt) ± (3.5 x mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 1 - 10
pH 10.5 - 12
Pm (cm3 0.02N H2SO4) 3 - 5
Pf (cm3 0.02N H2SO4) 1 - 2
Calcium (mg/l) <200
Chlorides (mg/l) 190,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 4 - 6, adjust for salt
MBT (lb/bbl) See Figure 1
*See Figure 2.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL (prehydrated) Viscosity and
fluid-loss control
Caustic soda pH and Pf
Salt Increase chloride
Soda ash Control calcium
<200 mg/l
SPERSENE Thinner and
fluid-loss control
MY-LO-JEL Fluid-loss control
POLY-SAL Fluid-loss control
POLYPAC UL Stability and
fluid-loss control
SP-101 HTHP fluid-loss control
DUO-VIS Low-shear-rate viscosity
SURFAK-M Surface-acting agent
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 10 - 30
Caustic soda 0.2 - 2.5
Soda ash 0.2 - 1
Salt 110 - 125
SPERSENE 5 - 15
POLYPAC UL 0.5 - 2
SURFAK-M 0 - 2
DUO-VIS 0.25 - 1
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.14 Revision No: A-1 / Revision Date: 07·17·98
Potassium is one of the most effective
ions available to minimize (inhibit)
shale hydration. The inhibitive nature
of potassium is achieved by the ionic
base exchange of potassium for sodium
and/or calcium ions between clay layers,
and by fixation of the potassium
ion in the crystalline lattice of swelling
clay minerals.
Many swelling clays are selective to
potassium and will adsorb potassium
ions in preference to sodium ions. In
other clays, the “mass action” effect
applies, which means that ion exchange
from sodium to potassium occurs most
readily when the potassium-to-sodium
ratio in the drilling fluid exceeds 3:1.
The low hydration energy of the potassium
ions contributes to the inhibition
of clay hydration in potassium-based,
exchanged clays.
Fixation of the potassium ions occurs
in clay platelets with a higher-thanaverage
negative charge. This ion fixation
occurs because the 2.66 Å diameter
of the potassium ion fits snugly into the
2.80 Å lattice space of the clay structure.
This provides an ideal condition for
crystalline compaction. The low hydration
energy of the potassium ion also
contributes to inter-layer dehydration,
resulting in the formation of a compact,
tightly held structure. This structure
resists hydration and cation exchange.
When ion fixation occurs, the clay
platelet contains less water in the interlayer
space, and is very stable. See Clay
Chemistry chapter.
POTASSIUM CHLORIDE POLYMER SYSTEM
The potassium chloride polymer system
was developed to stabilize watersensitive
shales by means of potassium
ion inhibition. The inhibitive nature
of this system minimizes the hydration
of shales, which minimizes hole
enlargement, bit and stabilizer balling,
sloughing shale, and reduction of permeability
in productive zones. The
potassium chloride system uses potassium
chloride salt (KCl) as the primary
source of potassium ions for ionic inhibition.
This system works best when
polymers are used for encapsulation.
Either Polyanionic Cellulose (PAC)
(POLYPAC) or Partially Hydrolized Poly
Acrylamide (PHPA) (POLY-PLUS) polymers
can be used for encapsulation.
These polymers coat cuttings and
exposed shales, limiting interaction
with water.
Since some shales are more watersensitive
than others, the concentration
of KCl required to inhibit these
shales varies. During drilling operations,
shale cuttings should be monitored
continuously for inhibition. If
the concentration of KCl in the system
is insufficient, shale cuttings will be
soft and mushy. If the concentration
of KCl is sufficient, they will retain
their integrity. Older shales usually
require about 10 to 15 lb/bbl KCl (3.5
to 5.0%) while younger shales may
require 30 to 50 lb/bbl (8.5 to 15%).
KCl and other chemicals should be
premixed prior to adding them to the
system for optimum cost effectiveness.
Inhibitive Potassium Systems
Potassium is
one of the
most effective
ions available
to minimize
shale
hydration.
The
potassium
chloride
polymer
system was
developed
to stabilize
watersensitive
shales…
Water-Base Systems
Water-Base Systems 10.15 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(POTASSIUM CHLORIDE POLYMER
SYSTEM CONTINUED)
When using hard makeup water,
the hardness should be treated to less
than 300 mg/l with soda ash prior to
adding polymers that are hardnesssensitive.
Since potassium chloride
systems are very solids-sensitive, it is
best to mix the system from scratch
instead of converting an existing drilling
fluid (containing drill solids) to a
potassium chloride system. The first
step in mixing a potassium chloride
system is to treat the hardness with
soda ash, then prehydrate the M-I GEL
in freshwater. Then, add the KCl,
KOH, POLY-PLUS, POLYPAC, DUO-VIS and
M-I BAR.
Rheological properties and filtration
rates in this system are controlled by
polymeric materials, which are not
temperature-stable above 300°F. The
temperature limitation of the system is
about 300°F. This system is very sensitive
to solids and calcium contamination
and generally is more expensive
than other water-base systems.
In addition to potassium chloride, a
variety of other non-chloride potassium
sources are available. These include
potassium carbonate, potassium sulfate,
K-52E (potassium acetate), caustic potash
(KOH) and more. All of these nonchloride
potassium chemicals have
been used to formulate inhibitive
potassium mud systems.
Typical Properties Old Formations Young Formations
Density (lb/gal) 10 - 16 10 - 16
Plastic viscosity (cP) See Figure 1 See Figure 1
Yield point (lb/100 ft2) 20 - 30 20 - 30
Initial gel (lb/100 ft2) 5 -10 10 - 15
10-min gel (lb/100 ft2) 15 - 20 15 - 20
Fluid loss (cm3/30 min) 10 -15 5 - 10
Potassium (mg/l) 15,000 - 25,000 55,000 - 100,000
Calcium (mg/l) <200 <200
pH 9.5 - 10 10 - 11
Low-gravity solids (%)* 2 - 4 3 - 5
MBT (lb/bbl) <25 <20
Typical Products
(lb/bbl) Old Formations Young Formations Primary Function
Potassium chloride 10 - 15 35 - 70 Potassium source
POLY-PLUS 0.5 - 1 0.5 - 2 Encapsulation
M-I GEL 8 - 10 (prehydrated) 2 - 5 Viscosity and filter cake
DUO-VIS 0.5 - 1 0.5 - 1.5 Low-shear viscosity
POLYPAC 0.5 - 2 0.5 - 3 Fluid-loss control
and encapsulation
Caustic potash (KOH) 0.5 - 1 0.75 - 1.5 pH and potassium
Soda ash 0.5 0.5 Control calcium
M-I BAR As required As required Density
*See Figure 2.
This system
is very
sensitive to
solids and
calcium
contamination
and generally
is more
expensive
than other
water-base
systems.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.16 Revision No: A-1 / Revision Date: 07·17·98
K-MAG SYSTEM
The K-MAGE system is designed to provide
inhibition, wellbore stability and
improved production by means of
potassium inhibition in areas where
potassium chloride systems are not environmentally
acceptable. The sources of
potassium are K-17T (potassium lignite),
XP-20 (KOH chrome lignite), K-52
(potassium acetate) and caustic potash
(KOH). The system limits the amount of
added sodium. The system is designed
to perform in a freshwater or seawater
alkaline environment. Since the primary
deflocculant in this system is lignite,
the system is not as cost-effective in
environments where the chlorides are
above 15,000 mg/l since the solubility
of lignite decreases as the chlorides
increase. Benefits of the system are
non-dispersed cuttings, improved
solids removal and better wellbore stability.
A reduction in sloughing shale,
bridges and fill on trips, and expensive
cement jobs due to hole enlargement
are added benefits.
The K-MAG system can be mixed from
scratch or converted from an existing
system. To convert an existing system
to a K-MAG system, add approximately
3 to 5 lb/bbl prehydrated M-I GEL,
4 lb/bbl of either K-17 or XP-20, and 1
to 2 lb/bbl caustic potash in one circulation.
Adjust the potassium ion concentration
with additions of K-52 or
additional K-17. Add 4 to 6 lb/bbl
SHALE CHEKE on a later circulation for
additional shale stabilization and to
minimize bit and stabilizer balling.
Low-gravity solids should be maintained
at less than 5% and the MBT
at less than 25 lb/bbl. Dilution rates
should be monitored to assure that
proper material concentrations are
maintained. The potassium ion concentration
should be monitored separately
because the potassium reacts with, and
is depleted by, drill solids. The potassium
ion concentration usually is controlled
between 1,000 to 10,000 mg/l.
Typical Properties
Density (lb/gal) 10.0
Funnel viscosity (sec/qt) ± (3.5 x mud weight)
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 1 - 10
pH 9.5 - 10.5
Pm (cm3 0.02N H2SO4) 0.5 - 1
Pf (cm3 0.02N H2SO4) 1.0 - 1.8
Calcium (mg/l) 0 - 300
Potassium (mg/l) 1,000 - 10,000
Chlorides (mg/l) 0 - 20,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 4 - 5
MBT (lb/bbl) <25
*See Figures 2 and 3.
The K-MAG
system is
designed
to provide
inhibition,
wellbore
stability and
improved
production…
Typical Products Primary Function
M-I BAR or FER-OX Increase density
M-I GEL (prehydrated) Viscosity and
fluid-loss control
K-17 or XP-20 Thinner and
potassium source
KOH pH, Pf and
potassium source
K-52 Potassium source
POLYPAC Fluid-loss
and encapsulation
RESINEX HTHP fluid-loss control
DUO-VIS Low-shear-rate viscosity
SHALE CHEK Shale stabilization
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 550
M-I GEL 5 - 15
KOH 0.5 - 2.0
K-17 or XP-20 8 - 10
SHALE CHEK 4 - 6
K-52 0 - 3
POLYPAC 0.5 - 1.5
DUO-VIS 0.5 - 1.5
RESINEX 0 - 6
Water-Base Systems
Water-Base Systems 10.17 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
The DURATHERME system is a water-base
system designed for drilling in HTHP
environments. The system is stable in
the presence of contamination from
soluble calcium, salts and acid gases,
and can be used at temperatures in
excess of 500°F (260°C). The stability of
the system is due to its low colloidalsolids
content and chemicals that are
stable at high temperatures. This system
also is used as a high-temperature
packer fluid.
The low reactive-solids content of
the DURATHERM system is achieved by
reducing bentonite and the drill-solids
content as fluid density and wellbore
temperatures increase. Polymeric
materials are used in place of bentonite
to provide viscosity and gel strengths.
This minimizes problems caused by flocculation
of reactive clay solids at high
temperatures and viscosity increases
resulting from chemical contamination.
Most deflocculated water-base systems
can be converted to the DURATHERM system
by substituting XP-20 for SPERSENE;
reducing the reactive-solids content and
using POLYPAC or DUO-VIS for viscosity
and solids suspension; and using
THERMEX or RESINEX for HTHP filtration
control. Proper solids control is
an absolute necessity for this system.
This drilling fluid should be monitored
carefully for temperature stability.
One good way to accomplish this is to
heat-age the fluid frequently at 25°F
(15°C) above the estimated bottomhole
temperature. The reactive-solids
content of the fluid should be monitored
closely and controlled within recommended
ranges. If a closed-loop,
solids-control unit is used, the solids
particle size and plastic viscosity should
be monitored closely and controlled
within the proper range. Monitor dilution
rates to assure that proper chemical
concentrations are maintained (see
HTHP chapter).
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3 x mud weight)
Plastic viscosity (cP) ;Barite/water line
(see Figure 1)
Yield point (lb/100 ft2) 6 - 10
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 2 - 10
pH 10.5 - 11.5
Pm (cm3 0.02N H2SO4) 2.0 - 5.0
Pf (cm3 0.02N H2SO4) 0.5 - 1.5
Chlorides (mg/l) 0 - 10,000
Calcium (mg/l) 0 - 200
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 0.5 - 2.5
MBT (lb/bbl) 2.5 - 12.5
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
M-I GEL Filter cake and
fluid-loss control
Caustic soda Increase pH and Pf
XP-20 Thinner and
fluid-loss control
Lime Treat out CO3 and pH
Gyp Treat out CO3
POLYPAC Viscosity/gel strengths
THERMEX HT fluid loss
and stabilizer
RESINEX HT fluid-loss control
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 600
M-I GEL 1 - 10
Caustic soda 0.5 - 1.5
Lime or gyp 0 - 2
XP-20 15 - 20
POLYPAC 0.5 - 1.5
THERMEX 0 - 12
RESINEX 0 - 6
DURATHERM System
The
DURATHERM
system is a
water-base
system
designed
for drilling
in HTHP
environments.
Proper solids
control is
an absolute
necessity for
this system.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.18 Revision No: A-1 / Revision Date: 07·17·98
The ENVIROTHERME system is a chromefree,
environmentally acceptable waterbase
system designed to drill in HTHP
environments, making it similar to the
DURATHERM system. The system is stable
in the presence of contamination from
soluble calcium, salts and acid gases,
and can be used at temperatures in
excess of 400°F (204°C). The stability
of the system is due to its low reactivesolids
content and temperature-stable,
chrome-free materials. The low reactivesolids
content is achieved by reducing
bentonite and drill solids as fluid density
and wellbore temperatures increase.
Polymeric materials like POLYPAC and
CMC are used to replace the bentonite
to provide viscosity and gel strengths.
This minimizes problems caused by flocculation
of reactive clay solids at high
temperatures and viscosity increases
resulting from chemical contamination.
SPERSENE CFT (chrome-free lignosulfonate)
promotes overall fluid stability
by preventing high-temperature gelation
and flocculation while providing
supplemental API and HTHP fluid-loss
control. TANNATHIN (lignite) is the primary
fluid-loss-control additive and
serves as a secondary deflocculant
in this system. Thermal stability is
achieved through the addition of
THERMEX (a polymeric resin). The resin
appears to function synergistically with
SPERSENE CF to provide stable viscosity
and fluid-loss control.
Most chrome-free, water-base systems
can be converted to the ENVIROTHERM
system by reducing the reactive-solids
content to an MBT <10 lb/bbl and then
adding 4 to 12 lb/bbl SPERSENE CF, 4
to 6 lb/bbl TANNATHIN, 4 to 12 lb/bbl
THERMEX, 0.5 to 2 lb/bbl POLYPAC and
about 2 lb/bbl caustic soda. THERMEX
and SPERSENE CF work synergistically to
provide stable properties. Proper solids
control is a necessity for this system.
ENVIROTHERM System
The
ENVIROTHERM
system is a
chrome-free…
system
designed
to drill in
HTHP environments…
Proper solids
control is
a necessity
for this
system.
Water-Base Systems
Water-Base Systems 10.19 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(ENVIROTHERM SYSTEM CONTINUED)
This drilling fluid should be monitored
carefully for temperature stability.
One good way to accomplish this is to
heat-age the fluid at 25°F (15°C) above
estimated bottom-hole temperature. The
drill-solids content of the fluid should
be monitored and maintained within
recommended ranges. If a closed-loop,
solids-control unit is used, the solids
particle size and plastic viscosity should
be monitored and maintained within
the proper range. Monitor dilution
rates to ensure that proper chemical
concentrations are maintained (see
the HTHP chapter).
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3 x mud weight)
Plastic viscosity (cP) ; Barite/water line
(see Figure 1)
Yield point (lb/100 ft2) 6 - 10
Initial gel (lb/100 ft2) 1 - 5
10-min gel (lb/100 ft2) 2 - 10
pH 9.0 - 11.0
Pm (cm3 0.02N H2SO4) 2.0 - 5.0
Pf (cm3 0.02N H2SO4) 0.5 - 1.5
Chlorides (mg/l) 200 - 20,000
Calcium (mg/l) 40 - 600
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 0.5 - 2.5
MBT (lb/bbl) 2.5 - 12.5
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR Increase density
Caustic soda Increase pH and Pf
Lime Treat out CO3 and pH
SPERSENE CF Thinner and
fluid-loss control
TANNATHIN Fluid-loss control
THERMEX HT stabilizer and
fluid-loss control
POLYPAC Viscosity/gel strengths
M-I GEL Filter cake and
fluid-loss control
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 600
M-I GEL 1 - 10
Caustic soda 0.5 - 1.5
Lime or gyp 0 - 2
POLYPAC 0.5 - 2.0
THERMEX 4 - 12
SPERSENE CF 4 - 12
TANNATHIN 4 - 6
The POLYSTARE 450 system is M-I’s polymer
system for HTHP applications. Its
thermal stability is provided by new
synthetic polymers developed specifically
for deflocculating clays and controlling
fluid loss at high temperatures.
This chrome-free, environmentally
acceptable system is formulated with
DURASTARE and RHEOSTARE.
RHEOSTAR is a stand-alone rheological
stabilizer designed to deflocculate clays
at temperatures of up to 450°F (232°C).
It contains no chrome, lignosulfonates,
lignites or gilsonites. RHEOSTAR also
reduces high-shear-rate viscosity, which
results in a low plastic viscosity, and
higher solids tolerance. RHEOSTAR does
not require the use of other products to
be effective. It performs well in makeup
water that contains high concentrations
of hardness and/or high salinity.
POLYSTAR 450 System
This chromefree…
system
consists, is
formulated
with DURASTAR
and RHEOSTAR.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.20 Revision No: A-1 / Revision Date: 07·17·98
(POLYSTAR 450 SYSTEM CONTINUED)
DURASTAR provides filtration control
in water-base drilling fluids at temperatures
up to 450°F (232°C). It is a standalone,
fluid-loss-control stabilizer that
does not require the use of other products
to be effective. DURASTAR provides
some viscosity and resists shear degradation.
It does not require a high concentration
of bentonite to achieve a
low fluid loss. DURASTAR is a liquid product
in a low-toxicity, environmentally
acceptable carrier.
RHEOSTAR and DURASTAR, with a small
quantity of GEL SUPREMEE (non-treated
bentonite), are the effective components
of the POLYSTAR 450 system.
The POLYSTAR 450 system should be
mixed from scratch, since it is not
compatible with the chemicals in
other systems. The first step in mixing
this system is to prehydrate 4 to
10 lb/bbl GEL SUPREME (depending on
the mud density). Then, add about
10 lb/bb RHEOSTAR, 1.5 lb/bbl caustic
soda, 6 lb/bbl DURASTAR and the
weight material required to increase
the density.
The POLYSTAR 450 system should be
monitored carefully for temperature
stability. One good way to accomplish
this is to heat-age the fluid frequently
at 25°F (15°C) above estimated bottomhole
temperature. The clay/solids content
of the fluid should be monitored
and controlled at recommended concentrations.
If a closed-loop, solidscontrol
unit is used, the solids particle
size and plastic viscosity should be
monitored and maintained to within
the proper range. Monitor dilution
rates to assure that proper chemical
concentrations are maintained.
Typical Properties
Density (lb/gal) 10 - 18
Funnel viscosity (sec/qt) ± (3 x mud weight)
Plastic viscosity (cP) ; Barite/water line
(see Figure 1)
Yield point (lb/100 ft2) 5 - 20
Initial gel (lb/100 ft2) 3 - 10
10-min gel (lb/100 ft2) 5 - 20
pH 8.5 - 12.0
Pm (cm3 0.02N H2SO4) 0.5 - 2.0
Pf (cm3 0.02N H2SO4) 0.2 - 1.0
Chlorides (mg/l) 0 - 40,000
Calcium (mg/l) 0 - 600
API fluid loss
(cm3/30 min) 2 - 6
HTHP fluid loss <15 in freshwater
<20 in seawater
Low-gravity solids (%)* <4
MBT (lb/bbl) 2.5 - 12.5
*See Figures 2 and 3.
Typical Products Primary Function
M-I BAR or FER-OX Increase density
Caustic soda or KOH Increase pH and Pf
Lime or gyp Treat out CO3
2–
RHEOSTAR HTHP deflocculant
DURASTAR HTHP fluid-loss control
GEL SUPREME Filter cake and
fluid-loss control
Concentration
Material (lb/bbl)
M-I BAR or FER-OX 0 - 600
GEL SUPREME 3 - 10
NaOH or KOH 0.5 - 1.5
Lime or gyp 0 - 2
RHEOSTAR 2 - 8
DURASTAR 1 - 4
DURASTAR…is
a stand-alone,
fluid-losscontrol
stabilizer
that does
not require
the use
of other
products
to be
effective.
Water-Base Systems
Water-Base Systems 10.21 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
POLY-PLUS systems are designed to provide
shale stabilization (inhibition) and
viscosity control in water-base muds.
These systems use POLY-PLUS (a highmolecular-
weight PHPA polymer),
which has multiple applications and
benefits. POLY-PLUS is used in a variety
of systems and special applications for
encapsulation.
POLY-PLUS is used in the following
applications:
1. In clear-water drilling, POLY-PLUS acts
as a total flocculant in bentonitefree
systems by removing the drill
solids at the surface. Benefits from
this application include improved
ROP, improved efficiency of solidscontrol
equipment and improved
wellbore stability.
2. In low-solids, non-dispersed systems
where POLY-PLUS is used primarily
to extend M-I GEL. Benefits of this
application are lower solids content,
increased ROP, improved efficiency
of solids-removal equipment and
minimized hole enlargement.
Concentrations of 0.1 to 0.5 lb/bbl
POLY-PLUS are added to these systems,
which contain 8 to 12 lb/bbl bentonite,
to increase the yield point
and minimize the plastic viscosity.
Conventional systems that do not
contain POLY-PLUS usually contain
25 to 35 lb/bbl bentonite.
3. The true low-solids POLY-PLUS systems
are used primarily for shale
stabilization. This is achieved by
encapsulation, through viscosifying
the water phase, and by the free
water being absorbed by the polymer.
Encapsulation is the process
by which POLY-PLUS wraps around
the clay platelets, preventing water
from entering the interlayer structure
of the clays. POLY-PLUS also
increases the viscosity of the liquid
phase, which slows the movement
of the fluid into the interlayer structure
of the clays. POLY-PLUS also adsorbs
water from the liquid phase, reducing
the amount of water available
to enter the structure of the clays.
In this system, the concentration
of active polymer (POLY-PLUS) is
maintained at 1 to 2 lb/bbl. At this
concentration, the anionic sites on
the polymers exceed the available
cationic sites on the bentonite and
drilled clays, resulting in the encapsulation
of reactive clays in the mud
and on the wall of the wellbore. This
condition is often referred to as “controlling
the viscosity over the hump.”
The stability of this system depends
on keeping the polymer concentration
within the proper range and
controlling the clay-solids content
of the system at less than 6%. If the
polymer concentration gets too low
or the solids concentration gets too
high, anionic deflocculants (thinners)
will be required to stabilize
flow properties. If deflocculants are
used, shale stabilization and encapsulation
are both reduced as the strong
anionic sites of the deflocculants
compete with those of the POLY-PLUS
for the cationic sites on the clays.
Therefore, if deflocculants are
required, TACKLET should be used,
since it does not reduce the yield
point as much as lignosulfonate or
lignite. The maximum density of a
true POLY-PLUS system is 12 to 13 lb/gal
due to solids intolerance, unless
deflocculants are used to stabilize
the flow properties.
4. For shale stabilization. POLY-PLUS
may be added to any low-pH,
freshwater or KCl-treated system
to reduce sloughing and heaving
shale. POLY-PLUS also will reduce
torque and drag, and prevent
bit- and BHA-balling.
POLY-PLUS System
POLY-PLUS
systems are
designed to
provide shale
stabilization
and viscosity
control in
water-base
muds.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.22 Revision No: A-1 / Revision Date: 07·17·98
5. POLY-PLUS sometimes is added to a
part of the active system to increase
the viscosity and then sweep the
hole. This procedure is used in areas
of fast ROP, such as when drilling
gumbo and soft shale, and in the
riser assembly on offshore floaters.
POLY-PLUS may be added in concentrated
amounts directly to the suction
pit or can be added to the drill
pipe on connections.
Most existing drilling fluid systems
can be converted to POLY-PLUS systems,
but it is far more desirable to mix a
clean POLY-PLUS system from scratch.
To mix an unweighted POLY-PLUS system,
the following formulation can
be used as a guide:
To mix a weighted POLY-PLUS system,
the following formulation can be used
as a guide:
Typical Properties
Density (lb/gal) 9 - 13
Funnel viscosity (sec/qt) 32 - 45
Plastic viscosity (cP) 6 - 10
Yield point (lb/100 ft2) 10 - 20
Initial gel (lb/100 ft2) 3 - 6
10-min gel (lb/100 ft2) 5 - 10
pH 8.5 - 10
Pm (cm3 0.02N H2SO4) 0.2 - 1
Pf (cm3 0.02N H2SO4) 0.1 - 0.5
Calcium (mg/l) <300
Chlorides (mg/l) 0 - 190,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* 3 - 10
MBT (lb/bbl) 7.5 - 17.5
Typical Products Primary Function
M-I BAR Increase density
M-I GEL Viscosity and
fluid-loss control
POLY-PLUS Inhibition and
gel extender
Caustic soda and KOH pH and Pf
POLYPAC Fluid-loss control
SP-101 Fluid-loss control
POLY-SAL Fluid-loss control
Soda ash Control hardness
DUO-VIS Control low-shear-rate
viscosities
TACKLE Reduce gel strengths
KCl and NaCl Ionic inhibition
Concentration
Material (lb/bbl)
M-I BAR 300
M-I GEL 2.5 - 10
Caustic soda 0.5 - 1
POLY-PLUS 0.5 - 1.5
POLYPAC 0.5 - 2
SP-101 0.5 - 2.5
TACKLE 0.1 - 1
DUO-VIS 0.5 - 1
Amount
Chemical (lb/bbl)
Prehydrated M-I GEL 2.5 - 5
Caustic soda or KOH 0.25
POLY-PLUS 1 - 2.5
POLYPAC 0.5 - 2
Amount
Chemical (lb/bbl)
Prehydrated M-I GEL 1 - 5
Caustic soda or KOH 0.25
POLY-PLUS 1 - 2.5
DUO-VIS 0.2 - 1
POLYPAC 0.5 - 2
TANNATHIN or RESINEX 2 - 5
*See Figures 2 and 3.
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(POLY-PLUS SYSTEM CONTINUED)
Water-Base Systems
Water-Base Systems 10.23 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(POLY-PLUS SYSTEM CONTINUED)
When displacing an existing system
with a POLY-PLUS system, the shaker
screen size should be increased to prevent
loss of mud. The mud will be flocculated
and the polymer unsheared for
the first circulation or two after displacement.
Fine shaker screens should
be replaced as soon as possible. A thick,
M-I GEL/POLY-PLUS spacer should be
pumped ahead of the POLY-PLUS system
to achieve a clean displacement.
Pumping at a high rate (in turbulent
flow) will also help remove old wall
cake and aid in a clean displacement.
If a POLY-PLUS system is used to displace
a current system at a casing point, drill
the cement and get a positive shoe test
on the formation before displacing with
the POLY-PLUS system. Cement and high
pH are very detrimental to the polymer.
If cement must be drilled with
the POLY-PLUS system, pretreatment
and disposal of contaminated mud
must be done to prevent depleting
the polymer content.
The primary concerns of maintaining
a POLY-PLUS system are to monitor and
maintain the proper polymer concentration
and control the solids to within the
proper ranges. The POLY-PLUS concentration
should be monitored through the
use of the Ammonia Extraction Test
(the procedure for this test is in the
Testing chapter of this manual). The
MBT value should be limited to
17.5 lb/bbl.
The MCATT polymer system is designed
to provide shale inhibition through the
use of two cationic polymers. MCAT-A, a
low-molecular-weight cationic polymer,
is used to suppress shale hydration,
while MCAT, a high-molecular-weight
polymer, is used for encapsulation.
Hydration of swelling clays can be
suppressed by using MCAT-A, which
penetrates the lattice space of the clay
structure. This results in the displacement
of exchangeable cations and water
molecules which reduces swelling. While
this polymer adsorption is similar to
the exchange reaction of common
cations, the adsorbed cationic polymers
cannot exchange with other common
cations because of their multisegment
attachment on clay surfaces. This multisegment
attachment provides a stronger
bonding between the layers, similar
to the potassium fixation, in that it
is irreversible.
MCAT has a large molecular size that
does not allow it to penetrate the clay
layers as effectively as low-molecular
polymers. As a result, adsorption occurs
primarily on the exterior surfaces and
forms a protective coating (encapsulation).
Although anionic polymers also
can encapsulate shales, cationic polymers
are more effective because of the
abundance of negatively charged surface
areas on the clay minerals. Therefore,
cationic polymers provide better shale
stabilization than anionic polymers.
Cationic polymers are not compatible
with anionic polymers in freshwater.
So, if freshwater is used, non-ionic
materials like starch must be used for
filtration control. However, with the
addition of salt (sodium chloride or
potassium chloride), certain anionic
polymers are compatible with the
cationic polymers.
MCAT Polymer System
The MCAT
polymer
system is
designed to
provide shale
inhibition
through the
use of two
cationic
polymers.
…cationic
polymers
provide
better shale
stabilization
than anionic
polymers.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.24 Revision No: A-1 / Revision Date: 07·17·98
(MCAT SYSTEM CONTINUED)
This system is sensitive to solids
and is more expensive than traditional
water-base systems. The temperature
limitation is about 275°F.
When displacing an existing system
with an MCAT polymer system, the
shaker screen size should be increased to
prevent loss of mud. The mud will be
flocculated and the polymer unsheared
for the first circulation or two after displacement.
Fine shaker screens should
be replaced as soon as possible. A thick,
M-I GEL/MCAT spacer should be pumped
ahead of the MCAT polymer system to
achieve a clean displacement. Pumping
at a high rate (in turbulent flow) also
will help remove old wall cake and aid
in achieving a clean displacement.
Typical Properties
Density (lb/gal) 8.8 - 16
Funnel viscosity (sec/qt) 36 - 85
Plastic viscosity (cP) 5 - 55
Yield point (lb/100 ft2) 5 - 40
Initial gel (lb/100 ft2) 2 - 15
10-min gel (lb/100 ft2) 5 - 35
pH 8.0 - 9.5
Pm (cm3 0.02N H2SO4) 0.2 - 1.0
Pf (cm3 0.02N H2SO4) 0.1 - 0.5
Fluid loss (cm3/30 min) As needed
Chlorides (mg/l) >30,000
Low-gravity solids (%)* <5
Typical Products Primary Function
M-I BAR Increase density
DUO-VIS Low-shear-rate viscosity
NaOH and KOH Increase pH and Pf
POLYPAC Fluid-loss control
POLY-SAL Fluid-loss control
MCAT Encapsulation
MCAT-A Swelling suppression
LUBE-167E Lubricity and bit balling
Concentration
Material (lb/bbl)
NaOH and KOH 0.5 - 2
NaCl and KCl >30,000 mg/l
MCAT 1 - 3
MCAT-A 3 - 6
POLY-SAL 3 - 6
POLYPAC 0.5 - 2
LUBE-167 1 - 2%
*See Figure 2.
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Water-Base Systems
Water-Base Systems 10.25 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
The Mixed Metal Hydroxide (MMH)
system is a low-solids, flocculated,
cationic drilling fluid system which
provides excellent hole-cleaning and
solids-suspension characteristics. The key
product in this system is the cationic
MMH (inorganic polymagnesium aluminum
hydroxyl). Two MMH-type
products are Polyvis IIE from SKW and
Drill-OutE from Drilling Specialties Co.
The viscosity and suspending capability
of an untreated gel slurry is increased
significantly by using MMH. The basic
MMH/gel slurry has a low plastic viscosity,
a high yield point, high fragile
gel strengths and a high fluid loss.
Viscosity and gel strengths in this
system are achieved by flocculating
fully hydrated bentonite with MMH.
This mechanism relies on the cationic
charges of the MMH to react with the
anionic charges on the bentonite to
form a flocculated slurry. For this reason,
anionic materials cannot be used
in this system without sacrificing its
unique rheological characteristics. Only
after pilot-testing should any materials
be used, including all starch additives.
Even small amounts of an anionic material
will drastically reduce the yield
point, low-shear-rate viscosity and gel
strengths. This leaves specialized starches
as the only filtration-control materials
that are compatible with the system.
Starch is subject to fermentation; therefore,
a pH of 11.0 to 11.5 and treatments
with a non-ionic biocide are
recommended to prevent fermentation.
The pH of MMH systems should be
maintained at 10.5 to 11.5. Rheology
is reduced a pH levels <10.
This system is very solids-sensitive,
so low-gravity solids must be controlled
at 5% or less by mechanical
removal and/or dilution. The maximum
mud weight for this system is
about 13 lb/gal.
Mixed Metal Hydroxide System
Typical Properties
Density (lb/gal) 8.8 - 13
Funnel viscosity (sec/qt) 36 - 55
Plastic viscosity (cP) Minimum value Figure 1
Yield point (lb/100 ft2) 15 - 60
Initial gel (lb/100 ft2) 10 - 60
10-min gel (lb/100 ft2) 10 - 60
pH 10.5 - 11.5
Pm (cm3 0.02N H2SO4) 0.7 - 1.8
Pf (cm3 0.02N H2SO4) 0.6 - 1.5
Calcium (mg/l) <80
Chlorides,
freshwater (mg/l) 100 - 15,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* <5
MBT (lb/bbl) 10 - 20
Typical Products Primary Function
M-I BAR Increase density
GEL SUPREME Viscosity
Caustic soda Increase pH and Pf
MMH Viscosity
Starch (non-ionic) Fluid-loss control
Concentration
Material (lb/bbl)
M-I BAR 0 - 350
GEL SUPREME 8 - 12
MMH 0.8 - 1.2
Starch (non-ionic) 3 - 8
*See Figure 2.
The MMH
system…
provides
excellent
hole-cleaning
and solidssuspension
characteristics.
Water-Base Systems
CHAPTER
10
Water-Base Systems 10.26 Revision No: A-1 / Revision Date: 07·17·98
The GLYDRILE system is an enhancedpolymer,
water-base system that uses
polyglycol technology to provide a high
degree of shale inhibition, wellbore stability,
HTHP fluid-loss control and
lubricity. This system also is ideal for
drilling depleted sands where differential
pressure-sticking is a major concern,
in deepwater operations, and drilling
high-angle wells in reactive formations
where wellbore stability and torque and
drag are major concerns. Other benefits
include enhanced cuttings integrity,
improved filter-cake quality, lower dilution
rates, less hole enlargement, greater
solids tolerance, better performance
of PDC bits, reduced bit-balling and
increased ROP. The GLYDRIL system also
is environmentally acceptable due to its
low toxicity and reduced disposal rates.
Although the GLYDRIL enhanced polymer
system achieves some inhibition by
chemical adsorption, the cloud-point
phenomenon is the primary mechanism
for inhibition and stabilization.
The cloud-point is the temperature at
which polyglycol changes from being
totally soluble to insoluble. At temperatures
above the cloud point, polyglycols
form colloidal droplets, or micelles,
which results in a microemulsion. This
phenomenon is often referred to as a
“Thermally Activated Mud Emulsion”
(TAME). This TAME effect provides
wellbore stability in three distinct ways:
• Through chemical adsorption.
• Through microemulsion and
precipitate pore-plugging.
• By providing a thinner, less-porous
filter/wall cake.
These polyglycol polymer systems are
more effective when used with an inhibitive
salt, such as KCl, for ionic inhibition
and an encapsulating polymer such
as POLYPAC or POLY-PLUS. So, it is recommended
to maintain sodium chloride
or potassium chloride salt in the system.
Maximum benefits are obtained by
matching the cloud point of the polyglycols
with the bottom-hole temperature
or the temperature of the formation
being drilled. This results in the adsorption
of insoluble polyglycols onto the
wellbore and into the filter/wall cake.
This adsorption of insoluble polyglycols
onto the clay/shale formation forms a
protective barrier against water and its
damaging effects. Adsorption of insoluble
polyglycols into the filter/wall cake
on permeable formations reduces the
thickness of the filter/wall cake and the
filtration loss rates. Since the insoluble
polyglycol has an affinity to surfaces, it
can coat solids and exposed surfaces, it
provides lubrication and reduces balling.
Most polyglycol polymer systems are
designed for the polyglycol to become
totally soluble as it cools while being
pumped up the annulus to the surface.
However, some polyglycol polymer systems
are designed to keep the polyglycol
insoluble at all times. Several glycols are
available with a wide range of cloud
points to achieve the one desired.
However, polyglycol polymer systems
usually are designed prior to drilling
the well, so only the proper glycol is
sent to the wellsite. These polyglycols
are listed below.
GLYDRIL System
The GLYDRIL
system…uses
polyglycol
technology
to provide a
high degree
of shale
inhibition,
wellbore
stability,
HTHP fluidloss
control
and lubricity.
GLYDRIL GP Broad-range-clouding
PAG blend, low salinity
GLYDRIL LC Low-salinity-clouding
PAG, <30,000 mg/l Cl–
GLYDRIL MC Moderate-salinity-clouding
PAG, 30,000 to
90,000 mg/l Cl–
GLYDRIL HC High-salinity-to
saturated-clouding PAG,
>90,000 mg/l Cl–
Water-Base Systems
Water-Base Systems 10.27 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(GLYDRIL SYSTEM CONTINUED)
Polyglycol polymer systems, like other
polymer systems, should be mixed from
scratch. If a polyglycol polymer system
follows another mud system in a well,
the previous system should be displaced
by a pre-mixed polyglycol polymer system
rather than being converted from
the previous system.
The primary concerns involved in
maintaining a polyglycol polymer system
are to monitor and maintain the
proper polymer concentration; to control
the solids in the proper ranges; and
to maintain the proper concentration
and type of polyglycol in the system to
obtain the TAME effect. The POLY-PLUS
concentration should be monitored
through the use of the Ammonia
Extraction Test (the procedure for this
test is contained in the Testing chapter
of this manual). The polyglycol concentration
can be monitored by a two-stage
retort or by using a hand refractometer.
After distilling the water off at 300°F
(149°C), the sample is distilled at 950°F
(510°C) to distill and measure the glycol.
The MBT value of the mud should
be limited to 20 lb/bbl.
Typical Properties
Density (lb/gal) 9 - 15
Funnel viscosity (sec/qt) 36 - 55
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 2 - 25
10-min gel (lb/100 ft2) 5 - 50
pH 8 - 10
Pm (cm3 0.02N H2SO4) 0.2 - 2
Pf (cm3 0.02N H2SO4) 0.1 - 1
Calcium (mg/l) 100
Chlorides (mg/l) 0 - 190,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* <5
MBT (lb/bbl) <20
Typical Products Primary Function
M-I BAR Increase density
M-I GEL Viscosity and
fluid-loss control
Caustic soda or KOH Increase pH, Pf
POLY-PLUS Encapsulation
and inhibition
DUO-VIS Viscosity and suspension
POLYPAC Fluid-loss control
and encapsulation
GLYDRIL GP, LC, Inhibition
MC or HC and lubricity
NaCl or KCl brine Ionic inhibition
Concentration
Material (lb/bbl)
M-I BAR 0 - 350
M-I GEL 2.5 - 12.5
KOH or soda ash 0.25 - 1.5
POLY-PLUS 0 - 2
DUO-VIS 0.25 - 1.5
POLYPAC 1 - 5
GLYDRIL 2 - 5%
NaCl or KCl brine 0 - 20%
*See Figure 2.
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Water-Base Systems
CHAPTER
10
Water-Base Systems 10.28 Revision No: A-1 / Revision Date: 07·17·98
The SILDRILE system is a salt/polymer
system utilizing sodium silicate for
improved inhibition. The system was
developed to provide shale inhibition
and wellbore stability in problem areas
where oil- or synthetic-base fluids normally
would be used. Formations such
as microfractured shale, chalk or formations
with interbedded dispersive
clays are the applications where a
SILDRIL system should be considered.
Inhibition and wellbore stability are
achieved as the soluble silicates precipitate
to form an insoluble silicate film
which prevents water contact with the
wellbore shale (clay) or invasion into
permeable formations. As the soluble silicates
come in contact with the surface
of the low-pH shales (clays), a reduction
in the pH and a reaction with the divalent
cations (Ca2+, Mg2+) on/in the shale
occur to form a calcium and/or magnesium
silicate coating. Soluble silicates
are stable only at pH values above 10.4
and in the absence of divalent cations.
Silicates precipitate when pH values are
less than 10.4 or in the presence of
divalent cations. Therefore, the pH
should be controlled at 11.0 or greater
and multivalent cations should be precipitated
with soda ash. The optimum
concentration of 50% active silicate is
about 30 lb/bbl. It is very important to
monitor the silicate concentration in
the system because the depletion rates
of silicate can be high when drilling
reactive shales. For the SILDRIL system
to provide good inhibition, the silicate
concentration must be monitored and
maintained within the proper range.
The silica-to-sodium ratio also is
very important. It describes the ratio
of SiO2 to Na2O for a particular silicate.
Research has shown that the best
ratio between silica and sodium for
shale inhibition ranges from 2.0:1 to
2.65:1. Higher SiO2 to Na2O ratios do
not improve inhibition and can result
in unstable flow properties.
Dispersion tests show that the inhibition
of the SILDRIL system is comparable
to that of oil- or synthetic-base systems.
Shale inhibition can be further
enhanced by additions of GLYDRIL and
potassium or sodium salts. GLYDRIL is
glycol with a low-cloud-point temperature
that reduces the coefficient of
friction of the fluid and extends the
thermal stability of the system to 250°F.
Therefore, glycol should be added to
the system once the bottom-hole temperature
exceeds 190°F, or as required
to reduce excessive torque and drag.
Caution should be used when drilling
reservoirs where the formation water
contains high concentrations of Ca2+ or
Mg2+. If the formation water is high in
Mg2+ or Ca2+, or the pH of the invaded
filtrate is reduced over time, damage
could occur due to precipitation of calcium
silicate (cement) or solidification
of sodium silicate within the pore throat
of the rock matrix. However, if the
completion will include cemented casing
and perforations, this should not
present a problem.
When mixing a SILDRIL system, freshwater
— or water that has been treated
with soda ash and caustic to remove
any divalent ions (Ca2+ and Mg2+) —
SILDRIL System
The SILDRIL
system…was
developed to
provide shale
inhibition
and wellbore
stability in
problem
areas…
It is very
important
to monitor
the silicate
concentration
in the
system…
Water-Base Systems
Water-Base Systems 10.29 Revision No: A-1 / Revision Date: 07·17·98
CHAPTER
10
(SILDRIL SYSTEM CONTINUED)
should be used. If not, these ions will
precipitate the silicate out of solution
as it is added to the makeup water.
The SILDRIL system is not as solidstolerant
as most other inhibitive mud
systems and is not recommended for
applications where densities of more
than 13.5 lb/gal are required. Since
the SILDRIL system is solids-sensitive,
high dilution rates would be required
to provide stable flow properties in
high-density SILDRIL applications. Since
SILDRIL is an expensive, high-performance
system, it is recommended only
for difficult wells that contain watersensitive
shales. The temperature stability
of the SILDRIL system is about
275°F (135°C).
Typical Properties
Density (lb/gal) 8.8 - 13.5
Funnel viscosity (sec/qt) 36 - 55
Plastic viscosity (cP) See Figure 1
Yield point (lb/100 ft2) See Figure 1
Initial gel (lb/100 ft2) 2 - 25
10-min gel (lb/100 ft2) 5 - 50
pH 11.0 - 12.5
Pm (cm3 0.02N H2SO4) 1.0 - 3.0
Pf (cm3 0.02N H2SO4) 0.8 - 2.5
Calcium (mg/l) <100
Chlorides (mg/l) 60 - 120,000
Fluid loss (cm3/30 min) As needed
Low-gravity solids (%)* <5
MBT (lb/bbl) <15
Typical Products Primary Function
M-I BAR Increase density
SILDRIL Inhibition
Caustic soda or KOH Increase pH and Pf
Soda ash Precipitate hardness
DUO-VIS Viscosity and suspension
POLYPAC (UL) Fluid-loss control
GLYDRIL Inhibition and lubricity
NaCl or KCl brine Base fluid and activity
Concentration
Material (lb/bbl)
M-I BAR 0 - 300
SILDRIL 4 - 7%
Caustic soda or KOH 1 - 2
Soda ash 0.5 - 1.5
DUO-VIS 0.5 - 1.5
POLYPAC (UL) 1.0 - 3.0
NaCl or KCl brine 18 - 68/22 - 37
GLYDRIL 2 - 5%
*See Figure 2.