Drilling Fluids

Slayt No: 1/120Mustafa Münir ATAGÜN DRILLING FLUID ENGINEERING
Drilling Fluid Engineering MMA
1- DRILLING FLUID SELECTION …………………………………… 2
2- SOLID CONTROL IN DRILLING FLUIDS……………………… 9
3- SUBSURFACE PRESSURES……………………………………….32
4- HYDRAULIC OF DRILLING FLUIDS………………………. …..49
4- OIL BASE DRILLING FLUID………………………………………. 66
5-CLAYS AND CLAYS CHEMISTRY………………………………… 80
6- MUD PROGRAMS, RECAPS…………………………………….. 98

Drilling Fluid Engineering
DRILLING FLUID SELECTION:
Drilling fluid selection for a particular well starts with a full
consideration of all the factors mentioned below.. The study should
include examining well records from nearby wells, looking at the type
of drilling fluid used, and any fluid related problems which might have
been experienced. This could range from slow ROP’s to Hole Stability
issues, to Reservoir Damage.
It is not subject within the scope of this section go deeply into
the drilling fluid selection factors. The intention is to introduce to you
with the factors for selection the Drilling Fluids.
MMA

DRILLING FLUID SELECTION
1- ABNORMAL PRESSURES: To prevent the rock from failing mechanically at
the borehole (sloughing or caving), and to prevent fluids within permeable zones from
flowing into the borehole, a sufficient pressure must be maintained by the drilling fluid
to at least balance the fluid, or pore, pressure within the rock. Balancing the physical
stresses that effect wellbore stability then, are simply a matter of adjusting the Mud
Weight.
2- ACTIVE CLAYS: It is impossible to prevent hydration of shale formation
when using a water based drilling fluid. This is because, while Osmotic Forces may be
overcome by adding salt to the mud, there is no way to counter the Clay Mineral
Hydration force, when drilling with a water based fluid. Further, water may be sucked
into the formation from Invert Emulsion Oil and Synthetic base muds, if an inadequate
water phase salinity is run. As a general rule, deeper, hotter and older shale is less
chemically reactive than younger, shallower and cooler clay sediment. It should be
obvious that these factors need to be taken into consideration when planning a Drilling
Fluid Program, particularly if planning to use a water base mud.
3- HIGH TEMPERATURES: From the drilling fluid point of view high temperatures can
be considered as those above which conventional drilling fluid additives begin to thermally
degrade at an appreciable rate. The degradation leads to loss of product function, and system
maintenance becomes difficult and expensive.
MMA

4- DRILLING AND CLEANING THE HOLE: The choice of Drilling Fluid
will effect the potential Rate of Penetration. Drilling Fluid Properties are also
critical to Hole Cleaning. It is useful to have an understanding of the
mechanisms involved both in selecting and designing the Fluid for a specific
well, and in getting the most out of the Fluid being used.
5- RATE OF PENETRATION: The choice of Drilling Fluid will effect the
potential Rate of Penetration. Drilling Fluid Properties are also critical to Hole
Cleaning. It is useful to have an understanding of the mechanisms involved
both in selecting and designing the Fluid for a specific well, and in getting the
most out of the Fluid being used. This relationship varies considerably
between conventional roller cone bits, and the more modern PDC drag bits.
6- CUTTINGS TRANSPORT / HOLE CLEANING : The transportation of
the cuttings from bit to surface has always been one of the main functions of
drilling fluids. The relationship of mud rheology to cuttings transport in
vertical holes has been understood for a long time. In deviated holes
however, other factors aside from the “carrying capacity” of the mud come
into play. Cutting properties is also effect the hole cleaning and ROP related
with the mud selection.
MMA

7- CUTTINGS PROPERTIES: Researchers who experimented with
different density cuttings found that the greater the density, the greater
the tendency to settle out, and the harder to remove. The density and
other properties of the cuttings affect the cleaning of the well. While mud
selection it must be considered.
8- HYDRAULİC: Hydraulics is defined as “the physical science and
technology of the static and dynamic behavior of fluids”. In this section we
are concerned with pumping Drilling Fluids from the mud tanks, through
surface lines and hoses, down the drill string, and circulating it back up the
annulus. A certain increment of pressure is required to move the mud
through each section of the circulating system.
The pressure required to circulate a fluid through a particular
section of pipe or hose, depends on cross sectional area and length of the
tubular section, the physical properties of density and rheology of the
fluid, and the flow rate. In a Drilling Fluid, the Rheology defines the flow
properties of that fluid.
MMA

9- FORMATION DAMAGE:: As a drill bit cuts a permeable zone,
and fresh virgin rock is exposed to the drilling fluid, there is initially a
spurt of whole mud into the pores of the rock. If the particle size
distribution of the solids in the mud is good, mud solids will almost
instantly bridge the pore throats. Whole mud will not penetrate more
than a few millimeters at most into the rock, and a filter cake will
quickly be formed, restricting the flow of filtrate into the formation.
10- CORROSION: Acid conditions promote corrosion. CO2 gas
and the action of bacteria on some mud products produce acids, or
corrosive byproducts. Increasing pH reduces corrosion and bacterial
action, and reacts out CO2, but is not always viable when drilling
reactive formations. Techniques for minimizing corrosion include
raising pH, using oxygen scavengers, and adding amine type products
to the fluid to coat steel components and reduce reactivity.
MMA

11- LUBRICITY: Lubricity is generally not a problem with oil or
Synthetic base muds. High torque can be a problem in some water based
drilling fluids, mainly those with a low solids content. Solid particles within
drilling fluids are the main source of lubricating properties. Emulsified fluids
act as finely divided particles and have the same effect. Diesel oil added to
water base mud has an initial lubricating effect, not from the properties of the
oil, but as a particle within the fluid
12- GAS HYDRATE: Gas hydrates are solid mixtures of gas and water,
which react to form a rigid lattice type structure. They form, usually at the
seabed, due to a combination of high hydrostatic pressures, and low seabed
temperatures. High fluid velocities, and pressure pulses may also contribute
to hydrate formation. They may form above the freezing temperature of
water. Oil and Synthetic base muds, which have high CaCl2 water phase
salinities will not exhibit hydrate formation problems. Hydrates can however
form in these muds if the water phase salinity is too low. This should not be a
problem in any Unocal operation.
MMA

DRILLING FLUID SELECTION MMA

SOLID CONTROL IN DRILLING FLUIDS
Introduction
Laboratory tests and practical field experience show that closely monitoring
drilled solids in the mud and minimizing their concentration can result in large
savings of both money and time. These savings manifest in three ways:
Improved drilling rate
Increased bit life
Reduced wear on mud pumps.
MMA
Solids control methods are based on the average diameters of the particles being
handled:
Coarse Particles: Greater than 2000 microns
Intermediate Particles: From 250 and 2000 microns
Medium Particles: from 75 to 249 microns
Fine Particles: from 45 to 74 microns
Ultra-fine Particles: from 2 to 44 microns
Collodial Particles: less than 2 microns

SOLID CONTROL IN DRILLING FLUIDS MMA

SETTLING: Treatment of solids-related mud problems may involve
one or more of the following mechanisms: settling, dilution, mechanical
separation and chemical treatment.
Settling involves retaining mud in a nearly quiescent state long
enough to allow the undissolved solids, which are heavier than water, to "fall
out" of the fluid. The relative success of this method depends on several
factors, including the size and shape of the particles, the density of the
particles, the density of the fluid, and the overall retention (settling) time.
The settling time can be reduced by using a flocculant to increase the particle
size, or by inducing centrifugal force to increase the gravitational effect.
MMA

Dilution, unlike the other solids control methods, does not involve removing solid
particles from the mud; rather, it is a means of decreasing the solids concentration by
adding base fluid to the system. Dilution is most often used to correct mud properties that
have been altered by the accumulation of drilled solids. The drawback to this method is that
as drilling progresses, concentrations of drilled solids continue to increase, and undesirable
mud properties eventually reappear. Also, dilution is often expensive for the following
reasons:
The consumption of the products required to maintain desired mud properties is
continually increasing.
Lack of storage space for the increased mud volume often leads to the discarding of
hundreds of barrels of valuable drilling mud.
Extra cleanup and transportation costs are incurred in environmentally sensitive areas.
MMA

Mechanical separation devices are available in two basic types:
vibrating screening devices (shakers) and systems that use centrifugal force to
increase settling rate. Mechanical treatment of solids buildup is often the
most practical and cost effective of the four available methods—it does not
alter essential mud properties and it decreases the need for dilution.
Generally speaking, the greater the cost per barrel of a given mud, the greater
the savings in using mechanical equipment to rectify mud properties.
The equipment used to mechanically remove solids from the mud must be
designed to fit the requirements of a given drilling operation; not every piece
of equipment is appropriate in every situation. Furthermore, the equipment
specifically selected to aid in mechanical removal of solids must be rigged up
and maintained to ensure that the units operate at peak performance.
MMA

Shale Shakers: The
double-decker shale shaker has
two screens mounted on a flat-
bed construction. The screens
can range down to 100 mesh
with the mesh cross section
varying from square to an
exaggerated rectangle. Drilled
solids down to 177 microns are
removed by 80-mesh screens,
and 840-micron size particles by
20-mesh screens.
MMA

Desilters and Desanders: The desilters/desanders must be equipped with centrifugal
pumps capable of providing sufficient pressure to the hydrocyclones to allow them to operate in
the desired pressure range. When correctly installed and operating in the design range, desilters
and desanders are capable of removing up to 95% of solid particles larger than 15 microns.
MMA

Centrifuge: In weighted mud systems it is often desirable to reduce mud maintenance
costs by methods other than dilution. Since it is not practical to use desilting equipment in these
systems, a centrifuge is often used.
Mud centrifuges work on the decanting principle. The mud flow enters a chamber
rotating at a high speed, and centrifugal force separates the mud stream into three components:
fluid phase, low-specific-gravity solids, and high-specific-gravity solids. Following separation of the
low-gravity solids, the high-gravity solids are returned to the active mud system.
In unweighted mud systems, a high-volume decanting centrifuge removes low-specific-
gravity drilled solids most efficiently and economically. The centrifuge can be operated on
unweighted muds at speeds up to 2200 to 2400 rpm, creating centrifugal forces greater than 1500
G-force. The high-volume centrifuge can remove fine solids down to two microns (e.g., bentonite
and clays) .
The separation efficiency of hydrocyclones depends on four general factors:
1. Fluid properties;
2. Particle properties;
3. Flow parameters;
4. Hydrocyclone parameters.
MMA

Barium sulfate (barite) is the primary additive used to increase the density of
clay/water muds. Densities ranging from 9 – 19 lbm/gal can be obtained using mixtures of barium
sulfate, clay, and water. The specific gravity of pure barium fulfate is 4.5, but the commercial grade
used in drilling fluids (API barite) has an average specific gravity of about 4.2.
Recently, alternative density control agents such as hematite (Fe2O3) with specific
gravity ranging from 4.9 to 5.3 and ilmenite (FeO.TiO2), with specific gravity ranging from 4.5 to 5.1
have been introduced. Because of their hardness, there is a concern about the abrasive of these
materials in the circulating system.
Density control
MMA

The mixture density is given by
If the storage capacity is available, to increase the density of the drilling fluid, we simply add barite to the mud.
Therefore, the known and unknown variables in this case are:
Known: V1, r1, rB, r2 Unknown: V2, mB
MMA
r1, V1
r2, V2
rB, VB

For ideal mixing the volume of mud, V1 and
weight material, VB, must sum to the desired new volume, V2
Likewise, the total mass of mud and weight material must sum
to the desired density-volume product
Solving these equations simultaneously for unknowns V2 and
mB yields
MMA

The addition of large amounts of API barite to the drilling fluid can cause the
drilling fluid to become quite viscous. The finely divided API barite has an extremely large
surface area and can absorb a significant amount of free water in the drilling fluid. This
problem can be overcome by adding water with the weight material to make up for the
water adsorbed on the surface of the finely divided particles. It is often desirable to add only
the minimum water required to wet the surface of the weight material. The addition of
approximately 1 gallon of water per 100 lbm of API barite is usually sufficient to prevent an
unacceptable increase in fluid viscosity.
Mass balance
MMA

Solving these equations for unknowns V1 and mB gives
Note that VwB is the volume of water need to add with one pound of barite. VwB = 0.01
For mB pounds of barite, VwB = 0.01 mB.
MMA

Example-1: is desired to increase the density of 200 bbl of 11-lbm/gal mud to
11.5 lbm/gal using API barite. The final volume is not limited. Compute the weight of
API barite required.
Solution:
The final volume is given
The weight barite required
For a final volume of 800 bbl. V1 is given
Thus, 99.47 bbl of mud should be discarded before adding any API barite. The mass of
API barite needed is given by
The volume of water to be added with the barite
0.01mB = 1,083 gal or 25.79 bbl.

Poor Boy Degasser
MMA

Vacum Type Degasser
MMA

Three Phase Degasser
MMA

Subsurface Pressures
Pressure
MMA
Stress/pressure What is the difference?
•Pressure - Scalar quantity •Stress - Tensor quantity
•Pressure – in fluids •Stress – in solid bodies

Hydrostatic Pressure
MMA

Hydrostatic Pressure In Drilling Wells
MMA

Subsurface Pressures MMA
Drilling a hole through a rock formation interrupts the pattern of stresses
present within the rock. These stresses have both horizontal and vertical components,
and are generally present due to the vertical loading, or overburden load, upon a given
point within the rock.
During a period of erosion and sedimentation, grains of sediment are
continuously building up on top of each other, generally in a water filled environment.
As the thickness of the layer of sediment increases, the grains of the sediment are
packed closer together, and some of the water is expelled from the pore spaces.
However, if the pore throats through the sediment are interconnecting all the way to
surface the pressure of the fluid at any depth in the sediment will be same as that
which would be found in a simple colom of fluid. This pressure is called NORMAL
PRESSURE and only dependents on the density of the fluid in the pore space and the
depth of the pressure measurement (equal to the height of the colom of liquid). it will
be independent of the pore size or pore throat geometry.
Normal Pressure

The vertical pressure at any point in the earth is known as the overburden
pressure or geostatic pressure. The overburden pressure at any point is a function of
the mass of rock and fluid above the point of interest. In order to calculate the
overburden pressure at any point, the average density of the material (rock and
fluids) above the point of interest must be determined. The average density of the
rock and fluid in the pore space is known as the bulk density of the rock
Overburden Pressure

Normal Pressure
MMA
The altitude which is generally used during drilling operations is the drill
floor elevation but a more general altitude, used almost universally, is Mean Sea
Level, MSL. When the pore throats through the sediment are interconnecting, the
pressure of the fluid at any depth in the sediment will be same as that which would
be found in a simple column of fluid and therefore the pore pressure gradient is a
straight line. The gradient of the line is a representation of the density of the fluid.
Hence the density of the fluid in the pore space is often expressed in units of psi/ft.

Normal Pressure – Overburden Pressure

Pore pressures which are found to lie above or below the “normal”
pore pressure gradient line are called abnormal pore pressures. These
formation pressures may be either Subnormal (i.e. less than 0.465 psi/ft) or
Overpressured (i.e. greater than 0.465 psi/ft).
Compaction is a slow process of increasing load from above, re-
alignment of clay particles, and gradual expulsion of fluid from the rock, with
resulting decrease in porosity and increase in density. In this process if excess
fluid is trapped in the rock, the formation water may take up more than its
share of the overburden load, and by definition, be abnormally pressured.
The mechanisms which generate these abnormal pore pressures can
be quite complex and vary from region to region. However, the most common
mechanism for generating overpressures is called Undercompaction and can
be best described by the undercompaction model.
MMA
Abnormal Pressure

Abnormal Pressure
MMA
The weight material barite required

(a) Formation Foreshortening
During a compression process there is some bending of strata. The upper beds can
bend upwards, while the lower beds can bend downwards. The intermediate beds must
expand to fill the void and so create a subnormally pressured zone. This is thought to
apply to some subnormal zones in Indonesia and the US. Notice that this may also
cause overpressures in the top and bottom beds.
Subnormal Formation Pressure
Causes of Subnormal Pressure

(b) Thermal Expansion: As sediments and pore fluids are buried the temperature
rises. If the fluid is allowed to expand the density will decrease, and the pressure will
reduce.
(c) Depletion: When hydrocarbons or water are produced from a competent
formation in which no subsidence occurs a subnormally pressured zone may result.
This will be important when drilling development wells through a reservoir which has
already been producing for some time. Some pressure gradients in Texas aquifers
have been as low as 0.36 psi/ft
Subnormal Formation Pressure

(d) Potentiometric Surface: This mechanism refers to the structural relief of a
formation and can result in both subnormal and overpressured zones. The potentiometric surface is
defined by the eight to which confined water will rise in wells drilled into the same aquifer. The
potentiometric surface can therefore be thousands of feet above or below ground level
MMASubsurface Pressures

(a) Incomplete sediment compaction or undercompaction:
is the most common mechanism causing overpressures. In the rapid burial of low permeability
clays or shales there is little time for fluids to escape. The formation pressure will build up and
becomes overpressured formtion. In other words, If the burial is rapid and the sand is enclosed
by impermeable barriers, there is no time for this process to take place, and the trapped fluid
will help to support the overburden.
(b) Faulting
Faults may redistribute sediments, and place permeable zones opposite impermeable zones,
thus creating barriers to fluid movement. This may prevent water being expelled from a shale,
which will cause high porosity and pressure within that shale under compaction.
(c) Massive Rock Salt Deposition
Deposition of salt can occur over wide areas. Since salt is impermeable to fluids, the underlying
formations become overpressured. Abnormal pressures are frequently found in zones directly
below a salt layer.
Causes of Abnormal Pressure

(d) Phase Changes during Compaction: Minerals may change phase under increasing
pressure, e.g. gypsum (CaSO4.H2O) converts to anhydrite plus free water. It has been
estimated that a phase change in gypsum will result in the release of water. The volume of
water released is approximately 40% of the volume of the gypsum. If the water cannot
escape then overpressures will be generated. Conversely, when anhydrite is hydrated at
depth it will yield gypsum and result in a 40% increase in rock volume. The transformation
of montmorillonite to illite also releases large amounts of water.
(e) Repressuring from Deeper Levels: This is caused by the migration of fluid from a
high to a low presssure zone at shallower depth. This may be due to faulting or from a
poor casing/cement job. The unexpectedly high pressure could cause a kick, since no
lithology change would be apparent. High pressures can occur in shallow sands if they are
charged by gas from lower formations.
(f) Generation of Hydrocarbons: Shales which are deposited with a large content of
organic material will produce gas as the organic material degrades under compaction. If it
is not allowed to escape the gas will cause overpressures to develop. The organic by-
products will also form salts which will be precipitated in the pore space, thus helping to
reduce porosity and create a seal.

When two aqueous fluids as shown below having different salinities are
exposed to each other, there is a tendency for the less salty fluid to dilute the
more salty fluid, due to Osmotic Force. When a hole is drilled through a shale, if
the Drilling Fluid contains less salt than the shale, there will be a tendency for
water to migrate into the shale. This will cause swelling and failure of the rock.
Osmotic Pressure

Fracture pressure is the pressure in the wellbore at which a formation will crack
The stress within a rock can be resolved into three principal stresses. A formation will fracture when
the pressure in the borehole exceeds the least of the stresses within the rock structure. Normally, these fractures
will propagate in a direction perpendicular to the leastss.
At sufficient depths (usually below 1000 m or 3000 ft) the minimum principal stress is horizontal;
therefore, the fracture faces will be vertical. For shallow formations, where the minimum principal stress is
vertical, horizontal (pancake) fractures will be created.
Fracture Pressure

Hydraulics of Drilling Fluids MMA
Mud-Weight Equivalent, also known as Equivalent Mud Weight
(EMW) is the total amount of pressure exerted at a true vertical depth which is
denoted in the mud density. The formation during circulation can hold a specific
mud weight and pressure. This amount of mud weight is referred to as Mud-
Weight Equivalent.
Hydrostatic Pressure of in fluid column
if Po = 0
Hydrostatic Pressure in Fluid Column
0052.0 pDp  r
Dp 052.0 r
D
p
052.0
rThe fluid density
Example: Calculate the static mud density required to prevent flow from a permeable
stratum at 12,200ft if the pore pressure of the formation fluid is 8500psig.
Solution:
The mud density must be at least 13.4 lbm/gal
gallbm
D
p
/4.13
200,12052.0
8500
052.0


r

Hydrostatic Pressure in Gas Column
Hydrostatic pressure of the column
İdeal gas equation
Finally
dDdp r052.0
TR
M
m
ZTRnZpV 
TZ3.80
pM
ZRT
pM
V
m
r
dD
Mp
dp
TZ80.3
052.0
  
D
D
dD
M
00 TZ1544p
dpp
p
TZ1544
)(
0
0DDM
epp


P0
P0 +
dP

A well contains tubing filled with methane gas (MW = 16) to a vertical depth of
10000ft. The annular space is filled with a 9.0 lbm/gal brine. Assuming ideal gas behavior,
compute the amount by which the exterior pressure on the tubing exceeds the interior
tubing pressure at 10,000ft if the surface tubing pressure is 1000 psia and the mean gas
temperature is 140F. If the collapse resistance of the tubing is 8330 psi, will the tubing
collapse due to the high external pressure?
The pressure in the annulus (external pressure) at D = 10,000 ft is
P2 = 0.052 * 9.0 * 10,000 + 14.7 = 4,695 psia
The pressure in the tubing (internal pressure) at D = 10,000ft
Pressure difference = p2 – p = 4695 – 1188 = 3507 < 8330 psia
The tubing will withstand the high external pressure
Hydrostatic Pressure in Gas Column
psiae
DDM
epp 11881000
TZ1544
)0(
0
)140460(*1544
10000*16





The effective density exerted by a circulating fluid against the formation that
takes into account the pressure drop in the annulus above the point being considered.
The ECD is calculated as:
r – mud density, ppg
P – Sum of the hydrostatic pressure and the frictional pressure drop in the annulus between
the depth D and surface, Psig
D – the true vertical depth, ft
Example: A 9.5-PPG drilling fluid is circulated through the drill pipe and the
annulus. The frictional pressure losses gradient in the annulus is 0.15. Calculate the
equivalent circulating density in PPG.
Solution:
r = 9.5 + P/0.052 = 9.5 + 0.15 / 0.052 = 12.4 PPG
Equivalent Circulating Density (ECD)

Flow Rate
WHERE
v = average velocity, ft/s
q = flow rate, gal/min
d = internal diameter of pipe, in.
d2 = internal diameter of outer pipe or
borehole, in.
d1 =external diameter of inner pipe, in.
2
448.2 d
q
v 
 2
1
2
2448.2 dd
q
v


Annular Flow
Pipe Flow
Flow rate is one of the main factors affecting hole cleaning. More flow rate is not always the way to
improve hole cleaning because might cause erosion or hole washout, therefore enlarging the hole causing
less annular velocity and decreasing cuttings transport.
Below a useful table showing the recommended flow rate for highly deviated and horizontal wells:

Buoyancy
The behavior of an object submerged in a fluid is governed by Archimedes'
Principle. Archimedes determined that a body which is completely or partially submerged
in a fluid experiences an upward force called the Buoyant Force, B , which is equal in
magnitude to the weight of the fluid displaced by the object. This principle can be used to
explain why ships, loaded with millions of kilograms of cargo, are able to float.







o
l
oe WW
r
r
1
We ,: effective weight,
W: weight of the object in air,
Wbo: Buoyant force.
rl , ro: densities of liquid and the object

10,000 ft of 19.5-lbm/ft drillpipe and 600 ft of 147 lbm/ft drill collars are
suspended off bottom in a 15-lbm/gal mud. Calculate the effective hook load that
must be supported by the derrick. Density of steel is 65.5 lbm/gal
Solution:
W = 19.5 * 10000 + 147 * 600 = 283200 lbm
We = W(1 - rf/rs) = 283200*(1 - 15/65.5)= 218300 lbm
(density of steel = 65.5 lbm/gal = 490lbm/cu ft) W
Fb
PT
Pb
H
+

Hydraulics of Drilling Fluids
1.48
MMA
Efficient cuttings transport and hole cleaning is a very important factor that must be
considered during drilling operations. In inclined and horizontal drilling, hole cleaning is a
common issue since there is high tendency for formation of cuttings bed in the hole
which can lead to several complex problems. The optimization of cuttings transport
depends on so many factors like hole angle, cutting size, drill string rotation, drill pipe
eccentricity, bit hydraulics ( flow rate, anulus velocity, slip velocity, nozzle velocity, jet
impact force, bit hydraulic horse power) etc.
Here is a rule of thumb for optimization and cleanin the hole for roller cone bits.
Jet Velocity- Jet Impact Force

Pressure drop across the bit
factorcorrectionC
p
Cv
d
b
dn
10074.8 4



 
r
22
d
2-5
C
10*8.311
t
bit
A
q
Δp
r

ti
i
n
n
n
A
q
A
q
A
q
A
q
A
q
A
q
v 

....
3
3
2
2
1
1
Assuming a constant Pb velocity through all the nozzles
pqcF dj  r01823.0Hydraulic İmpact Force

Example: A 12.0 lbm/gal drilling fluid is flowing through a bit containing three
13/32 in nozzles at a rate of 400 gal/min. Calculate the pressure drop across the bit
and the impact force developed by the bit.
Solution: Assume Cd = 0.95
Total Nozzle Area
Pressure Drop
Hydraulic impact force:
2
2
3889.0
32
13
4
3 inAt 







psi
A
q
Δp
t
bit 1169
3889.0*95.0
400*12*10*311.8
C
10*8.311
22
25
22
d
2-5

r
lbfpqcF dj 820169,1*1240095.001823.001823.0  r

Pseudoplastic
(Time-independent shear thinning fluids) If the
apparent viscosity decreases with increasing shear
rate.
Dilatant
(Time-independent shear thickening fluids) If the
apparent viscosity increases with increasing shear
rate
Thixotropic
(Time-dependent shear thinning fluids): If the
apparent viscosity decreases with time after the
shear rate is increased to a new constant value
Rheopectic
(Time-dependent shear thickening fluids): If the
apparent viscosity increases with time after the shear
rate is increased to a new constant value
Drilling fluids and cement slurries are generally
thixotropic
or time-dependent thinning
or time-dependent thickening
Fluid Type

• Newtonian fluids:
• Power law fluids:
• Bingham fluids:
• Herschel-Bulkley
(Yield power law fluids)
Flow curves of time-independent fluids
n
y K 
 py 
n
K 
 
Rheological Model
MMA

Type Of Flow
Laminar Flow
Flow pattern is linear (no radial flow)
 Velocity at wall is ZERO
 Produces minimal hole erosion
*Mud properties strongly affect pressure losses
*Preferred flow type for annulus(in vertical wells)
*Laminar flow is sometimes referred to as sheet
flow, or layered flow.
* As the flow velocity increases, the flow type
changes from laminar to turbulent.
Turbulent flow criteria is Reynold number:
Turbulent Flow
 Flow pattern is random (flow in all directions)
 Tends to produce hole erosion
 Results in higher pressure losses takes more energy
 Provides excellent hole cleaning…but
Mud properties have little effect on pressure losses
Is the usual flow type inside the drill pipe and collars
Thin laminar boundary layer at the wall
μ
dvρ928
N
_
Re 
cp.fluid,ofviscosityμ
inI.D.,piped
ft/svelocity,fluidavg.v
lbm/galdensity,fluidρwhere
_




MMA

When an operator felt that the hole was not being cleared of cuttings at a satisfactory rate, he
would:
Increase the circulation rate
Thicken the mud (increase YP/PV)
Turbulent flow cleans the hole better.
 Pipe rotation aids cuttings removal.
 With water as drilling fluid, annular velocities of 100-125 ft/min are generally adequate
(vertical wells)
A relatively “flat” velocity, profile is better than a highly pointed one.
 Mud properties can be modified to obtain a flatter profile in laminar flow decrease n
Drilled cuttings typically have a density of about 21 lb/gal.
Since the fluid density is less than 21 lb/gal the cuttings will tend to settle, or ‘slip’ relative to
the drilling mud.
Slip velocity of the d diameter cuttings: (ft/s)
Lifting Capacity- slip Velocity

rr

2
sfs
s
d)(138
v
MMA

Drilling Fluid Circulation System
MMA

OIL BASE DRILLING FLUID
Definitions
MMA

OIL BASE DRILLING FLUID MMA
The most common base oils used have been diesel and kerosene. They
have an acceptable viscosity, low flammability, and a low solvency for any rubber
in the drilling system. Diesel, however, is relatively toxic, making the
environmental impact of diesel-base muds generally higher than those of water-
base muds.
Mineral oils have replaced diesel oil and kerosene in environmentally
sensitive areas of the world. Mineral oils contain a much smaller percentage of
aromatics than diesel or kerosene, and thus are less toxic to marine life. There is
a wide range in aromatic content in mineral oils marketed today.
Crude oil can be used in oil muds; however, it has some drawbacks. For
example, crude oil usually has a significant fraction of light ends, and thus
exhibits low flash and fire points. Crude oil may need to be weathered prior to
use. Also, crudes often contain significant amounts of asphaltenes that may
present problems during drilling or completion operations, and may affect the
performance of invert emulsion additives.
Continuous Phase

Emulsifiers
MMA
1.60
Water present in an oil mud is in the form of an emulsion. A chemical emulsifier must
be added to prevent the water droplets from coalescing and settling out of the emulsion.
The emulsifier also permits water originally present in the rock destroyed by the bit to
emulsify easily. A chemical wettability reversal agent is added to make the solids in the
mud preferentially wet by oil rather than water. Otherwise, the solids will by absorbed by
the water droplets and cause high viscosities and eventually settling of barite.
The emulsified water of an oil mud tends to increase the viscosity of the mud in the
same manner as inert solids. It also causes a slight increase in fluid density. Since the water
is much less expensive than oil, it also decreases the total cost of an oil mud.
The calcium or magnesium fatty acid soap frequently is used as an emulsifier for oil
muds. Fatty acids are organic asids present in naturally occurring fats and oils that have a
structure:
CH3 – CH2 – (CH2)n –COOH
While the fatty acid soaps are the most common type of emulsifier used in oil muds,
almost any type of oil soluble soap can be used. Calcium naphthenic acid soaps and soaps
made from rosin (pipe tree sap) also are common organic acid type soaps.

Wettability
MMA
1.63
When a drop of liquid is placed on the surface of a solid, it may spread to cover the solid surface or
it may remain as a stable drop. The shape that the drop assumes depends upon the strength of the
adhesive forces between molecules of the liquid and solid phases. The wettability of a given solid
surface to a given liquid is defined in terms of the contact angle q. A liquid that exhibits a small contact
angle has a strong wetting tendency. If q = 1800, the liquid is said to be completely nonwetting
Most natural minerals are preferentially wet by water. When water-wet solids are introduced to a
water-in-oil emulsion, the solids tend to agglomerate with the water, causing high viscosities and
settling. To overcome this problem, wettability control agents are added to the oil phase of the mud.
The wetting agents are surfactants similar to the emulsifiers. This effectively changes the solids from
being preferentially wet by water to preferentially wet by oil.
The soaps added to serve as emulsifiers also function to some extent as wetting agents. However,
they usually do not act fast enough to handle a large influx of water-wet solids during fast drilling or
mud weighting operations.

Oil Base and Synthetic Base Muds Testing
MMA
1.64
The field tests for rheology, mud density, and gel strength are accomplished in the
same manner as outlined for water-based muds. The main difference is that rheology
is tested at a specific temperature, usually 120°F or 150°F. Because oils tend to thin
with temperature, heating fluid is required and should be reported on the API Mud
Report.
Sand Content: Sand content measurement is the same as for water-base muds
except that the mud's base oil instead of water should be used for dilution. The sand
content of oil-base mud is not generally tested.
HPHT Filtration The API filtration test result for oil-base muds is usually zero. In
relaxed filtrate oil-based muds, the API filtrate should be all oil. The API test does not
indicate downhole filtration rates. The alternative high-temperature-high pressure
(HTHP) filtration test will generally give a better indication of the fluid loss
characteristics of a fluid under downhole conditions. See the figure below.

1.65
The instruments for the HTHP filtration test consists essentially of a controlled
pressure source, a cell designed to withstand a working pressure of at least 1,000 psi, a
system for heating the cell, and a suitable frame to hold the cell and the heating system.
For filtration tests at temperatures above 200°F, a pressurized collection cell is attached to
the delivery tube. The filter cell is equipped with a thermometer well, oil-resistant
gaskets, and a support for the filter paper (Whatman no. 50 or the equivalent). A valve on
the filtrate delivery tube controls flow from the cell.
A non-hazardous gas such as nitrogen or carbon dioxide
should be used as the pressure source. The test is usually
performed at a temperature of 220 -350°F and a pressure of 500
psi (differential) over a 30-minute period. When other
temperatures, pressures, or times are used, their values should
be reported together with test results. If the cake compressibility
is desired, the test should be repeated with pressures of 200 psi
on the filter cell and 100 psi back pressure on the collection cell.
The volume of oil collected at the end of the test should be
doubled to correct to a surface area of 7.1 inches.

Electrical Stability : The electrical stability test indicates the stability of emulsions of
water in oil mixtures. The emulsion tester consists of a reliable circuit using a source of
variable AC current (or DC current in portable units) connected to strip electrodes
(Figure 1.9). The voltage imposed across the electrodes can be increased until a
predetermined amount of current flows through the mud emulsion-breakdown point.
Relative stability is indicated as the voltage at the breakdown point and is reported as
the electric stability of the fluid on the daily API test report.
MMA
1.66

Liquids and Solids Content Oil, water, and solids volume percent is determined
by retort analysis as in a water-base mud. More time is required to get a complete
distillation of an oil mud than for a water mud. The corrected water phase volume,
the volume percent of low-gravity solids, and the oil-to-water ratio can be calculated.
The volume oil-to-water ratio can be found from the procedure below:
Oil fraction 100
% by volume oil or synthetic oil % by volume oil or synthetic oil - % by volume water
MMA

Chemical analysis procedures for nonaqueous fluids can be found in the API 13B
bulletin available from the American Petroleum Institute.
Alkalinity and Lime Content (NAF) The whole mud alkalinity test procedure is a
titration method that measures the volume of standard acid required to react with the
alkaline (basic) materials in an oil mud sample. The alkalinity value is used to calculate the
pounds per barrel of unreacted, "excess" lime in an oil mud. Excess alkaline materials,
such as lime, help to stabilize the emulsion and neutralize carbon dioxide or hydrogen
sulfide acidic gases.
Total Salinity (Water-Phase Salinity [WAF] for NAF) The salinity control of NAF fluids is
very important for stabilizing water-sensitive shales and clays. Depending on the ionic
concentration of the shale waters and of the mud water phase, an osmotic flow of pure
water from the weaker salt concentration (in shale) to the stronger salt concentration (in
mud) will occur. This may cause dehydration of the shale and, consequently, affect its
stabilization.
MMA

Anilin Point, is the lowest temperature at which oil is completely miscible with equal
volume of anilin (C6H5NH2) is called anilin point. . The aniline point (AP) correlates roughly
with the amount and type of aromatic hydrocarbons in an oil sample. A low AP is indicative
of higher aromatics, while a high AP is indicative of lower aromatics content. Diesel oil with
AP below 120°F [49°C] is probably risky to use in oil-base mud. The API has developed test
procedures that are the standard for the industry.
Test Procedure:
1. Clean and dry the apparatus. Measure 4 ml of aniline
and 4 ml of the oil to be tested into the test tube.
2. Place stopper into the test tube and insert
thermometer, making sure the bulb does not touch the
sides or bottom of the tube.
3. Heat the tube slowly while stirring the mixture (stir by
moving the thermometer up and down) until complete
miscibility (the mixture becomes clear) occurs.
4. Remove from heat source and continue stirring until
aniline-oil mixture becomes cloudy. Read thermometer
temperature at cloud point and report aniline point in °F.
MMA

Particle-Size Distribution (PSD) Test The PSD examines the volume and particle size
distribution of solids in a fluid. This test is valuable in determining the type and size of
solids control equipment that will be needed to properly clean a fluid of undesirable
solids.
Lubricity Testing Various lubricity
meters and devices are available
to the industry to determine how
lubricous a fluid is when exposed
to steel or shale. In high-angle
drilling applications, a highly
lubricious fluid is desirable to
allow proper transmission of
weight to the bit and reduce side
wall sticking tendencies.
MMA

Capillary Suction Time (CST) Inhibition testing looks at the inhibitive nature of a drilling
fluid filtrate when exposed to formation shale samples. The CST is one of many tests that
are run routinely on shale samples to optimize the mud chemistry of a water-base fluid.
Linear-Swell Meter (LSM) Another diagnostic test to determine the inhibitive nature
of a drilling fluid on field shale samples. The LSM looks at long-term exposure of a fluid
filtrate to a formation shale sample. Test times for LSM can run up to 14 days.
Shale Erosion Shale inhibition testing looks at the inhibitive nature of a drilling fluid and
examines the erodability of a shale when exposed to a drilling fluid. Various tests
procedures for this analytical tool.
Return Permeability Formation damage characterization of a fluid through an actual
or simulated core is accomplished with the return permeability test. This test is a must
when designing specialized reservoir drilling fluids to minimize formation impairment.
MMA

CLAYS AND CLAYS CHEMISTRY
• Clays and clay minerals are very important as
drilling Engineering point.
8-35 km crust
12500 km dia
O = 49.2
Si = 25.7
Al = 7.5
Fe = 4.7
Ca = 3.4
Na = 2.6
K = 2.4
Mg = 1.9
other = 2.6
% by weight in crust
82.4%
MMA

Clay particles are like plates or needles. They are negatively charged.
Clays are plastic; Silts, sands and gravels are non-plastic
Clays exhibit high dry strength and slow dilatancy
There are three main groups of clay minerals:
1- Kaolinite - also includes dickite and nacrite; formed by the decomposition
of orthoclase feldspar (e.g. in granite); kaolin is the principal constituent in
china clay.
2- Illite - also includes glauconite (a green clay sand) and are the commonest
clay minerals; formed by the decomposition of some micas and feldspars;
predominant in marine clays and shales.
3- Smectites or montmorillonites - also includes bentonite and vermiculite;
formed by the alteration of mafic igneous rocks rich in Ca and Mg; weak
linkage by cations (e.g. Na+, Ca++) results in high swelling/shrinking potential
MMA

Clay minerals are made of two distinct structural units.
Basic structures of clay minerals
Tetrahedral Silica Sheet:
Formula of the tetrahedral sheet: Si4O6 (OH)4
negative charge: only exists in combination with cations
and additional oxygens
Octahedral AliminumSheet: Al2(OH)6
Formula of the octahedral sheet:
Brucite: Mg3(OH)6 􀃆 all octahedrals occupied 􀃆 trioctahedral
Gibbsite: Al2(OH)6 􀃆 2/3 of octahedrals occupied 􀃆 dioctahedral
MMA

SILICATE SHEET (T) ALUMINA SHEET (O)
+ + +
TO or 1:1KAOLINITE
MONTMORILLONITE
AND MICA (INCLUDE ILLITE)
+
+ + + TOT or 2:1
CHLORITE: TOT :0: TOT or 2:1:1
ATTAPULGITE/SEPIOLITE: TOT or 2:1
Clay Structures
MMA

Property Kaolin Mica Mont Attap Chlorite
Layer type 1 : 1 2 : 1 2 : 1 2 : 1 2 : 1 : 1
Crystal
Structure Sheet Sheet Sheet Sheet Sheet
Particle Hexagonal Extensive Flakes Needles Plates
Shape Plate Plates
Particle 0.5 - 5 0.5 - Large 0.1 - 2 0.1 - 1 0.1 - 5
Size (µ) Sheets
Surface Area
BET-N2-m2/g 15 - 20 50 - 110 30 - 80 200 140
BET-H2O-m2/g - - 200 - 800 - -
CEC-meq/100g 3 - 15 10 - 40 80 - 150 15 - 25 10 - 40
Viscosity
in Water Low Low High High Low
Effects of
Salts Flocculates Flocculates Flocculates Little or none Flocculates
Comparison of Structures
CLAYS AND CLAYS CHEMISTRY MMA

There are over 400 mineral and rock names to describe clay minerals. Only the following are common and
applicable to drilling fluids chemistry
• Kaolin often hydro-termal alternation of feldspars, of volcanic ash, and is found in shales and marine
– Composed of single tetrahedral sheet and single octahedral sheet
– Charges within structure are balanced with few substitutions
– Strong hydrogen bonding between layers limits swelling
– Edge charges are sensitive to pH
• Micas found in sedimentary shale sections is normally clsassed as illite
– 2:1 lattice with 2 silica sheets sandwiching an octahedral layer
– Ion replacement occurs in the TETRAHEDRAL layer
– Charge deficiency is balanced by potassium ions
– The Potassium fits neatly in the hexagonal holes made by the silica tetrahedral and securely binds the
separate layers together.
• Montmorillonite The most common mineral in the group of minerals called the smectites.
– A 2:1 lattice structure very similar to mica
– Ionic substitution occurs in the OCTAHEDRAL layer
– Cations are unable to approach close enough to completely loose their ionic character
– The residual ionic character provides attractive forces for adsorbing water.
• Sepiolite and Attapulgite
– Both consist of long needles.
– They cannot swell but have a large surface are and can bind water strongly. This means that they are
effective viscosifiers
• Chlorite 2:1:1 lattice type mineral

Atterberg observed that the consistency of fine-grained soils are greatly affected by the amount
of moisture content present in these soils, therefore, the moisture content at which the soil changes
from one state to another state is defined Consistency Limits or Atterberg Limits (Murthy, 2002).
Depends on water content, fine-grained soil can exist in any of four states. A) Solid State B) Semi Solid
State C) Plastic State D) Liquid State.
Liquid limit: The boundary between
the liquid and plastic states;
Plastic limit: The boundary between
the plastic and semi-solid states;
Shrinkage limit: The boundary between
the semi-solid and solid states.
Liquid, Plastic, Shrinkage limits

1.78

0
10
20
30
40
50
60
0 10 20 30 40 50 60 70 80 90 100
PlasticityIndex
Liquid Limit
A-line
U-line
montmorillonite
kaolinite
halloysite
chlorite
illite
Plastisity Index –Liquid Limit Chart
MMA
1.79

++
+ +
Na+ Na+ Na+
Na+ Na+
Na+ Na+ Na+ Na+
K+ K+
+ K+
K+ K+
Ion Exchange Properties of Clays
The negative charge generated by isomorphous is balanced by cations held near the clay surface ,
Common charge- balancing cations are Na, K, Ca, Mg, these cations are readly exchangeable in
montmorillenite.
e.G KCl solution
Different cations have different attractions for the exchange sites.
Assuming all the cations are the same, the order of increasing replacing power of cations is generally
Li+ < Na+ < K+ < Mg2+ < Ca2+ < H+
e.g. : At equal concentrations potassium will displace more sodium than sodium will displace potassium.
Increasing the concentration of any given cation will increase the probability that it will displace another
cation.
e.g. : It is possible for high concentrations of potassium to displace calcium cations.
Cation exchange capacity of clay can be measured by methylene blue test (MBT) or chemical analysis of
displaced.
MMA

*The properties of the exchange cations have an important influence on clay properties.
*Hydration of cations depends on their charge and size.
– High charge & small diameter cations are usually most highly hydrated
– Low charge & large diameter cations are usually least hydrated
*The important diameter is the hydrated ionic diameter
Atom Dehydrated Ion Hydrated Ion
Diameter A Diameter A
Na - Sodium 1.90 11.2
K - Potassium 2.66 7.6
Cs - Cesium 3.34 7.6
Mg - Magnesium 1.30 21.6
Ca - Calcium 1.90 19.0
Hydration of Cations (Clays)
MMA

*The most common swelling clay mineral is montmorillonite.
* Montmorillonite (bentonite) is used in some drilling fluids to give viscosity and fluid loss control.
* Montmorillonite is found in many reactive shales.
* Montmorillonite is found in some sandstone (including reservoir sands).
* The amount of water taken up by a montmorillonite (& hence the degree of swelling) depends on :
– Layer charge of the clay / Ion exchange
– Nature of the exchangeable cation
– Nature of the external solution
* Swelling promoted by highly hydrated, low charge exchangeable cations
e.g.. Li+ , Na+
* Swelling reduced by high charge, less hydrated cations
e.g.. Al3+
K+ reduces swelling because poorly hydrated even though low charge.
Ca2+, Mg2+ reduces swelling because high charge, though highly hydrated.
Clays Swelling
MMA

relative distribution of particles
with a given spacing, %
relative distribution of particles
with a given spacing, %
High Salinity Solutions Reduce Clay Swelling
Effect of Low Salt Concentration on
space between sheets
Effect of High Salt Concentration on
space between sheets
MMA

Clay particles in a fluid can be :
– Deflocculated
– Flocculated
– Aggregated
– Dispersed
Degree of dispersion / deflocculation of clays will affect viscosity, fluid loss control and shale
inhibition.
There are four basic colloidal states of clay particles in a fluid :
– Deflocculated. There is an overall repulsive force between the particles. This is done by
ensuring all the particles have the same charge. (The particles may be aggregates)
– Flocculated. There are net attractive forces for the particles and they can associate with
each other to form a loose structure.
– Aggregated. The clay sheets are still attached to each other and hydration has not
occurred, or the hydration process has been reversed. The aggregate maybe disaggregated
by hydration and or mechanical shear.
– Dispersed. This is where the aggregates have all been broken down. The dispersed clays
may be flocculated or deflocculated.
Clay Dispersion / Deflocculation
MMA

Edge to edge
flocculated
and aggregated
Edge to face
flocculated
and aggregated
Edge to edge
flocculated
but dispersed
Edge to face
flocculated
but dispersed
Aggregated but
deflocculated
Dispersed and
deflocculated
FlocculatedDispersed
Effect of Clays in Mud:
Viscosity normal
Yield normal
Fluid loss normal
Viscosity High
Yield High
Fluid loss High
Effect of Clays in Mud :
Viscosity Normal
Yield Low
Fluid loss Low
Viscosity Low
Yield Low
Fluid loss High
Viscosity Low
Yield High
Fluid loss High
Viscosity Normal
Yield Normal
Fluid loss High
Viscosity Normal
Yield High
Fluid loss High
Viscosity High
Yield Normal
Fluid loss High
MMA

Deflocculation
MMA

Chemical name and formulas of the compounds releated with drilling fluids
MMA

In the normal deposition, compaction and diagenesis of sediments, a gradually increasing
overburden load, forces fluid (seawater) out of the compacting clastic material. Granular
sediments, such as sand and silt take up the weight of this overburden load by grain to grain
contact and the integral strength of the grains. Clay type rocks on the other hand are
composed of flat platelet and rod shaped materials, and the matrix tends to be
compressible.
Abnormal pressuring of a rock always refers to the pore pressure or the pressure of the
included fluids within the rock. In shallow formations it may be due to rapid burial. In
deeper shales. it is commonly caused through diagenesis of montmorillonites to Illite,
releasing bound water,
From the driller’s perspective, increasing pore pressure in a shale will be coincidental
with increasing porosity and decreasing density. The rock will therefore drill faster. It will
contain more fluid, and if some of the fluid is gas, more gas will be released from the drill
cuttings into the mud. Background gas will increase.
From the driller’s perspective, increasing pore pressure in a shale will be coincidental
with increasing porosity and decreasing density. The rock will therefore drill faster. It will
contain more fluid, and if some of the fluid is gas, more gas will be released from the drill
cuttings into the mud. Background gas will increase
High Pressures

MUD PROGRAMS, RECAPS
It is usual for a Mud Program to be submitted by the Mud Company supplying the
drilling fluid products and engineering service, for each well. The exception to this may
be where a standard mud formulation, such as SBM, is used for all wells. In that case a
general Mud Guideline document should be prepared to act as a mud program for all
wells.
Drilling Fluid selection should be based on a thorough evaluation of the functions that
will be required of the Fluid. This evaluation should include a look at any offset well
data, particularly any problems that might have been encountered, plus a look at any
Geological data that is available. This may include age, type, and potential reactivity of
formations to be drilled; as well as pore pressure and temperature
In the situation where the Mud Company is recommending a Fluid for a particular well
or series of wells, the Program should be fully detailed. It should justify the
recommendation of a particular Fluid system, and fully explain the components of the
system and their functions. It should give recommended mud properties and estimated
mud consumption for each interval. There should be a recommended make-up range for
the various products recommended, and an estimated total amount of each product to
be used. Finally an estimated total cost for each interval, and for the well should be
given. A good Mud Program may also include a discussion on solids control,
Mud Programs

• A good Mud Program has the following components:
A brief discussion of the well to be drilled covering any special considerations related
to the selection of the recommended Mud System.
A discussion of the Mud System, its functions and cost effectiveness, and why it is
particularly suitable for the well to be drilled.
A discussion of the mud products used to make up the recommended Mud System,
what each product is, and its function in the System.
A phase by phase breakdown, recommending mud properties and mud formulation
for each interval. This should include an estimate of the quantity of mud that will be
required to drill the interval, the amount of each product that will be required, and an
estimated cost for mud for the interval.
A summary of mud consumption, product requirements, and cost estimates.
A list of products and quantities to be sent to the rig for the well, including
contingency items such as lost circulation material.
There should be a discussion on solids control.
If there is a potential for lost circulation, a discussion on the type of lost circulation
expected, and recommended cure procedures. There should be a discussion of products
and should include recommended make up formulations for LCM pills, and
recommended spotting procedures.
A discussion on recommended contingency products, other than LCM.
In a water base mud program, corrosion control should be discussed, and if applicable,
a recommendation for corrosion control should be included – corrosion monitoring,
products for corrosion control, concentrations and procedures for using the products.

The Drilling Fluids Recap is the Mud Engineers end of well summary of
the use of mud on a particular well. A Recap should have the following
elements:
A recap should start with a brief well history, followed by a discussion of
any mud-related problems that occurred, and recommendations for their
remediation. This should include mud consumption, hole problems, lost
circulation, etc. These may be on a phase by phase basis.
The Recap should give tables showing mud and mud product usage by
phase, and mud cost for each phase, as well as a summary of total mud and
product consumption and cost.
The Recap should also have tables showing Mud Properties on a day to
day basis for the whole well.
Finally it is common to show graphs of Depth vs. Days, Depth vs. Mud
Cost, and Depth vs. Mud Weight.
Mud Recapss

Drilling Fluids

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