Drilling fluids & Maintenance equipment

Functions of drilling fluid

  • Cool and lubricate the bit and drill string.
  • Clean the bit and bottom-hole.
  • Suspend solids and transport cuttings and sloughing to the surface.
  • Stabilize wellbore and control subsurface pressure (Borehole instability is natural function of unequal mechanical stresses, physio-chemical interactions , pressure created when supporting material & surface exposed in the process of drilling a well. Drilling fluid must overcome both the tendency for the hole to collapse from mechanical failure o from chemical interaction of the formation with the drilling fluid).
  • Assist with gathering subsurface geological data and formation evaluation.

Last two mentioned function should be given priority in designing drilling fluid and controlling its properties. Once drilling fluid has been selected, the properties required to accomplish the first three functions then can be estimated by hydraulic optimization process.

Drilling fluid properties

Standards for testing:

API RP 13-B1 (Routine testing of water based drilling fluid)
API RP 13B-2 (Field testing of oil based drilling fluids)

Field determined properties:

Mud weight

The mud weight is density of fluid measured in terms of mass of a unit volume of the drilling fluid.

Usually low mud weights are desirable for achieving optimum penetration rates and minimizing the chances of loss circulation. However in practice, mud weights in excess of two and half-times the density of oil may be require to control the formation fluid influx and to control sloghing of troublesome formations.

Mud weight is measured by the conventional mud balance or pressurized mud balance. Pressurized mud balance can be useful to determine the density of the gas cut mud.

P(psi)=0.052×density of mud (ppg) × True vertical depth(ft)

Equivalent circulating density

Pressure exerted of mud in static condition is always less than the pressure applied in dynamic condition. This additional pressure is due to friction between mud and the system (annulus). This pressure acts in the opposite direction of the motion of the mud.

The pressure at the standpipe gauge is algebraic sum of frictional pressure losses that occurs in the circulating system. These pressure losses occur in;

  • Surface equipment
  • Inside string (drill string)
  • Drill collars
  • Bit nozzles and downhole tools
  • Annulus


Out of the total system friction pressure loss, only the loss in annulus contributes directly to the bottomhole pressure (causes increase in BHP)

ECD=Phydrostatic+Pannular loss

Or in terms of mud weight,



Viscosity is the property of fluid that causes resistance to flow.

Drilling fluid viscosity is measured by funnel viscosity or fan VG viscometer. Funnel viscosity of the given mud system is one point determination of mud consistency and cannot be correlated with measured rheological properties. Therefore, a mud system solely should not be treated on the basis of funnel viscosity.

‘The settling velocity of particle is directly proportional to the viscosity of the fluid’. In order to transport the solid vertically, the upward velocity of particle must be greater than the settling velocity of the particle.

By stoke’s law,     u=(D²) ∗ (ps−pf) ∗g/18∗µ∗108


  • u= velocity (cm/sec)
  • ds=density of solid (gm/cm3)
  • df= density of fluid (gm/cm3)
  • g=gravity
  • μ= viscosity (poise)
  • D= diameter of sphere (microns)

Viscous behavior of drilling fluid:
Relation between force required for fluid to flow (shear stress) and the rate at which force is applied (shear rate) is given by newton’s law. According to Nweton’s law,  shear stress∝shear rate

Shear rate (Υ): It is defined as the velocity gradient across adjacent fluid layers while in laminar flow.

Shear rate (τ): force per unit area to initiate a velocity gradient or to start the motion.

Newton’s law of viscous resistance

shear stress =µ∗shear rate

The proportionality constant is the true viscosity of Newtonian fluids.

Drilling fluid models

Bingham plastic model:

Bingham plastic is a viscoplastic material that behaves as rigid body at low stresses but flows as viscous fluid at high stresses.

To describe the viscous behavior of clay based drilling fluid.

ζ= ζΟ+μp∗γ

Y-intercept on graph is defined as dynamic yield point. Yield point is minimum value of stress required to initiate the flow of the fluid. The slope of the straight line is defined as plastic viscosity.

Determination of rheological properties for viscometer readings:\

Plastic viscosity: The difference between dial reading at ϴ600 and ϴ300.

pv= Θ600− Θ300

(Change in funnel viscosity such as increase in 1 0r 2 seconds per hour or per circulation, indicate that there may unacceptable solid build up or continuous chemical contamination. Abrupt increases in funnel viscosity would indicate a drastic change of basic flow properties possible due to large scale contamination).

Plastic viscosity

The plastic viscosity is resistance to fluid flow caused by mechanical friction within the fluid. This mechanical friction is due to the interaction of solid particles in mud, the interaction of solid and liquid particles and deformation of liquid particles under shear stress.

Plastic viscosity should be taken as quantitative indicator of the total solid content.

Yield point

Yield value is interpreted as the component of the resistance to shear due to build up of structure in a fluid caused by electrochemical forces within the mud under initial flowing conditions. The electrochemical forces arise from the charges on the surface of reactive particles, the charges on the sub micron sized particles and presence of electrolytes in the water phase.

Yield value is mud property that must be controlled within a specified range according to hole conditions and mud system in use. In addition to solid control, maintaining yield value within specified limits require proper chemical treatments.

In well dispersed clay based mud system, yield value can be lowered by chemical deflocculation and mechanical removal of solid. Addition of chemical dispersant (lignite and lignosulphate) treat the effects of solid build up by altering the surface charges of the reactive particles. To increase yield value, additions of bentonite or a viscosifying polymer such as xanthan gum or polysaccharides.

In non-dispersed clay base system, the key to maintaining a stable yield value is to avoid over treatment of the mud system with bentonite and viscosifying polymers & to avoid an accumulation of drilled solids.

Types of fluid

Newtonian fluid Water , glycerin, diesel oil
Non-Newtonian fluid (Time independent)
Bingham plastic Grease, ketchup
Pseudoplastic Polymer solutions, water-based fluid
Dilatants Starch, mica fish solutions
Non-Newtonian (Time dependant)
 Thixotropic Drilling muds
Rheopectic Grease, gypsum
Viscoelastic Drilling fluids, long chain polymers

Viscoelastic fluids

Viscoelastic fluids are those with viscous properties but also exhibits a certain degree of elasticity of the shape. Viscoelastic polymers used in drilling fluids tend to straighten and elongate when subjected to extremely high shear stress but revert back to their coiled chain links when shear rate has decreased to nominal levels. Viscoelastic mud behavior causes thinning of the mud while going through the bit and reduces the friction losses. In annulus, under low shear rates, the polymers revert back to their characteristics shape, thickening the mud and provide better cuttings capacity.

Power law model

Power law model parameters can be calculated between any two shear rates representative of the annular region, it will provide much greater accuracy in predicting drilling fluid’s performance.



  • τ= shear stress
  • K= consistency index
  • Υ= shear rate
  • n = power law index

Herschel-bulkley model

ζ=ζo +k∗ (γn)

Optimum drilling fluid viscosity

Desired viscous properties of drilling fluid;

  • It should be shear thinning to impart optimum hydraulic horsepower at bit.
  • It should have sufficient viscosity in annulus for sufficient hole cleaning. It should have sufficient gellation characteristics to suspend cuttings and weight material when motionless.

Gel strength

Gel strength are measure of the attractive forces within the drilling fluid under static conditions and by convention are measured after 10 sec and 10 minutes. These attractive forces differ from yield value in that they are time dependant and disrupted after flow initiated.

In most unweighted water-base system 10 sec/10 min gel strength of 2/4 ln /100 ft2 are sufficient to suspend cuttings. In weighted system, a 10 sec gel strength of at least 2lb/100 ft2 will be required to suspend most of the barite. In such systems, it would be preferable to have 10 sec gel strength in range of 3-5lb/ 100 ft2 and 10 minute gel strength of 5-10 lb/100 ft2.

Filtrate loss

Spurt loss- loss of fluid to the formation before building of mud cake (filter medium).

Filtrate loss- loss fluid to the formation after building of mud cake.

Filtrate loss- loss fluid to the formation after building of mud cake.

Parameters Effect on filtrate loss Remarks
Temperature Increase With temperature filtrate loss increases, as viscosity is reduced. Fluid is easily movable at elevated temperatures.
Particle type and size Can’t define High permeable mud cakes cause more filtrate loss than low permeable mud cakes.
Permeability of mud cakes depend on particle size and it’s distribution.
 Time  Increases  =c√+
Spurt loss-volume of filtrate at zero time
Volume of filtrate depends on square root of time. Filrate will be doubles if time is quadrupled.
 Pressure  Can’t define  Highly compressible filter cake gets compacted as differential pressure increases. Ultimate reduction in permeability reduces filtrate losses.
 Flow profile  Depends on type of profile  Turbulent flow cause higher fluid loss due to scouring effect of filter cake and turbulence is associated with high pressure which with reduced filter cake forces more filtrate into formation

Method of obtaining spurt loss and ultimate loss

  • Classic loss= 2 * (30 min- 7.5 min)
  • Spurt loss = 30 min- classic loss
  • ultimate loss = {(classic loss)*(Total time/30)^1/2 }+spurt loss

Controlling filtrate loss

Controlling filtrate loss is very important. Too low filtrate loss is detrimental to penetration rates or too high filtrate loss could be harmful to borehole stability and water sensitive formations. The most desirable properties are high spurt loss and low ultimate filtrate loss.

API low temp. filtrate loss test, the low ultimate filtrate loss as measured by 30 min API low temp. test should be rarely less than 10 cm3. In HPHT conditions, 20 cm3 filtrate in full 30 min test at 300F and 500 psi is generally sufficient to avoid most of the hole problems.

Bentonite is most basic loss control agent. Polymers used as filtrate loss control agent mainly by tying up clay particles and bridging the gaps between the platelets.

Solid content

All main mud properties such density, viscosity and filtrate loss are depends on type and amount of solid in suspension. The essential solid are added to the drilling systems at the surface in controlled amounts. While undesirable solids are get added to system. Those solids are generated by the bit and retained mud. These solids adversely affect the primary mud properties.
Results of solid content can be useful to identify dissolved & undissolved solid, active and inert solids and low & high gravity solids. Fields measurement of solid includes total solid contents, sand content and bentonite content.
Sand content is defined as volume percent of particles that are retained on 200 mesh size screen. Sand content sample is taken at the flowline. Sand content in pit sample indicates the efficiency of solid removal system. It is expected that sand content in pit sample should be negligible.
If sand particles are being carried into suction pit, first step should be taken to check the shaker screen for holes, to dump or jet sand trap and bottoms of settling pits and check other solid control equipment for any malfunction.

Methylene blue test

MBT is use to determine amount of reactive bentonitic type solid in drilling fluid and it’s based on cation exchange capacity of solid particles. Organic material present in the sample is oxidized with hydrogen peroxide, a measured quantity of methylene blue dye is added and stirred vigorously. The gets absorbed on active particles. When these particles gets saturated with adsorbed dye, the unabsorbed dye appears and denotes the end point.
Possible errors in measurement includes presence of air bubble in mud sample, making sure after each incremental addition of dye is contacting all particles in flask (obtained by vigorous shaking of the flask) and end point is overshot by carelessness.
MBT values can be utilized in two ways. It gives direct measure of equivalent bentonite content and to evaluate each type of solid present in drilling fluid in conjunction with retort data, mud weight and filtrate analysis.
MBT gives total bentonite content (added at surface and added while drilling) in ppb bentonite equivalent.

Calculating types and amount of solid

Total low gravity solids

The amount of accumulate drilled solid can be obtained by subtracting MBT value from total low density solid content.

( )=(−)/(1−(MBC/100))

MBC= activity of formation in lbs (derived from methylene blue analysis of drill cuttings)
S=total low gravity solid content (ppb)
MBT= methylene blue test results in mud (ppb)
D=total drilled solid in mud (ppb)


For optimum performance and in order to maintain stable properties and avoid hole problems (D*S/B) should be less than 3 to1 in unweighted systems and preferable no more than 2 to 1. In weighted solids systems, the ratio should not exceed 2 to 1.

Chemical analysis of drilling mud

 Property  Additives Method  Remarks
 pH  Acid materials- salts calcium chloride, calcium sulfate, SAPP sodium bisuphite
Alkaline additives- salts sodium carbonate & sodium bicarbonate
 pHydration paper
ColorpHast sticks
Glass electrode pH meters
pH indicator solutions
 Drilling fluid should be maintained at 7 and above
Drilling fluid must be basic due to corrosive effects of acid and chemistry of clays
 Alkalinity  If filtrate sample has Pf or Pm value greater than zer, then pH of sample cannot be less than 8.3. These values are use to estoimate concentrations of hydroxyl, carbonate, bicarbonate and carbonate ion sin filtrate  Pf Pm Mf  Phenolphthalein is pink at pH>8.3 and is colorless at < 8.3
End point of methyl orange titration is 4.3 Methyl orange develops a yellow color above a pH of 4.3


 Relation b/n Pf and Mf  Conclusion
 P=0  Alkalinity due to bicarbonate ion
 P=M  Alkalinity due to hydroxyl ion
 2P>M  Alkalinity due to mixture of carbonate and hydroxyl
 2P=M  Alkalinity is all carbonate ions