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Removal of the Drilling Fluid

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Removal of the Drilling Fluid
For cementing operations to be successful, all annular spaces must be filled with cement, and the cement properly bonded to the previous casing and formation. In order for this to occur, all the drilling fluid must be displaced by the cement slurry. This is not always an easy matter, because there are several factors which affect the removal of the drilling fluid:

• washouts in the open hole, making it difficult to remove drilling fluid and filter cake
• crooked holes, making casing centralization difficult and drilling fluid not being removed from the low side
• poorly treated drilling fluids having high fluid losses Good drilling practices will not assure a good cement job, but they may help prevent a failure. The ideal drilling fluid for cementing operations should have:

• a low gel strength, with low PV and low YP
• a low density
• a low fluid loss
• a chemical make-up similar to the cement

Since these conditions are very seldom met, fluid washes and spacers are usually pumped ahead of the cement to remove as much drilling fluid as possible.

Drilling Fluids- Pressure Loss in the Drillstring

Pressure Loss in the Drillstring

Once passed the surface equipment, the fluid will flow through the drillstring. In hydraulic calculations, these parts of the circulating system are considered circular pipes. In typical field operations, fluid velocities are in the order of 1000 ft/min (300 m/min). At such velocities, the fluid is in turbulent flow.

The pressure required to circulate fluid in turbulent flow varies by approximately 1.8 power of the flowrate. Doubling the flowrate would increase the pressure drop in the drillstring by approximately 3.5 times. Typically, the pressure losses in the drillstring are about 35 percent of the total pump pressure.

With this in mind, it will be necessary to know how much pressure will be required to pump the fluid through the drillstring, at a given rate.

Drilling fluid - Surface Pressure losses

Surface Pressure Losses

System pressure loss calculations begin with the determination of the type/ class of surface circulating equipment. These include the standpipe, rotary hose, swivel, and kelly (if present). Though hardly ever consistent, four types/classes have been recognized by the IADC as the most common.

They are:

When calculating surface pressure losses, choose the class which is closest to the present rig equipment; if necessary, extrapolate. Most modern rigs will have a surface pressure coefficient between 2 and 10. The coefficient is then used in the following formula:

Pls = 10^-5 x ks x MD x Q^1.86

where: Pls = Surface Pressure Loss (psi)

ks = Surface Pressure Coefficient

MD = Mud Density (lb/gal)

Q = Flow Rate (gal/min)

When extrapolating, bear in mind that increased lengths will increase the coefficient, while increased I.D.'s will decrease the coefficient.

Drilling fluid - Hydraulic Calculations

Hydraulic Calculations

In the “Advanced Logging Procedures Workbook” (P/N 80269H), an introduction to hydraulics illustrates the Bingham method for hydraulic optimization. The second, and more commonly used method is the Power Law Model.

This model fits the actual flow properties more closely, although at low shear rates, it will predict slightly low shear stresses. The model describes a fluid in which the shear stress increases as a function of shear rate, raised to some power. As mentioned earlier, the equation for the Power Law model is:

Shear Stress = k x Shear raten

“k” is known as the “consistency index”, and is indicative of the pumpability of the fluid. “n” is the power index, denoting the degree of how “non-Newtonian” the fluid is.

Both parameters can be determined from the Fann VG meter. “k” is defined as the viscosity of a fluid at a shear rate of 1 sec-1. When “n” equals 1, the fluid is Newtonian. As the fluid becomes more shear thinning, the “n” value decreases.

where: 300rpm = Fann VG meter dial reading at 300 rpm's

600rpm = Fann VG meter dial reading at 600 rpm's

If the Fann VG meter dial readings are not available, both “k” and “n” can be determined using the Plastic Viscosity and Yield Point.

where: PV = Plastic Viscosity (cps)

YP = Yield Point (lb/100ft2)

Once these values have been determined, they are used in calculating the pressure losses throughout the circulating system. This section will describe the pressure losses, using the Power Law Model, in the surface system, the drillstring, and the annulus.

Hydraulics - Deformation of a Fluid by Simple Shear - Power Law Model

Power Law Model

This model is defined by the relationship:

Shear Stress = Consistency Factor x Shear Rate flow behavior index

It describes the thickness or pumpability of the fluid, and is somewhat analogous to the apparent viscosity. The flow behavior index (n) indicates the degree of non-Newtonian characteristics of the fluid. As the fluid becomes more viscous, the consistency factors (k) increases; as a fluid becomes more shear thinning “n” decreases. When “n” is 1 the fluid is Newtonian. If “n” is greater than 1, the fluid is classed as Dilatant (the apparent viscosity increases as the shear rate increases). If “n” is between zero and 1 the fluid is classified as Pseudoplastic, exhibiting shear-thinning; (i.e., the apparent viscosity decreases as the shear rate increases). For drilling fluids, this is a desirable property and most drilling fluids are pseudoplastics.

While the Power Law Model is more accurate then the Bingham Model at low shear rates, it does not include a yield stress. This results in poor results at extremely low shear rates.

A modification to the Power Law Model, the OXY Model, was proposed for use in oil-based muds. The major difference is the viscometer readings used to determine the “k” and “n” values. Power Law uses the 300 and 600 rpm readings, the OXY Model uses the 6 and 100 rpm readings. In addition, other models have been proposed that tend to exhibit behavior between the Bingham and Power Law models at low shear rates.

Non-Newtonian fluids may show a degree of time-dependent behavior. (For example, the apparent viscosity for a fixed shear rate does not remain constant, but varies to some maximum or minimum with the duration of shear.) If the apparent viscosity decreases with flow time, the fluid is termed “Thixotropic”. Once flow has ceased, a thixotropic fluid will show an increase in apparent viscosity. When apparent viscosity increases with flow time, the fluid is “Rheopectic”. The shear stress developed in most drilling fluids is dependent upon the duration of shear. A time lag exists between an adjustment of shear rate and the stabilization of shear stress. This is due to the breaking up of clay

particles at high shear rates and the aggregation of clay particles when shear rate is decreased, both occurrences take a noticeable length of time.

“Gel strength” is used to measure this time dependent behavior. This gel strength measures the attractive forces of a fluid while under static conditions. If the gel strength increases steadily with time, the gel strength is classed strong or progressive. If it increases slowly with time, it is classed as weak or fragile.

When strong gels occur, excessive pressures may be required to break circulation.

Hydraulics - Deformation of a Fluid by Simple Shear - Bingham Plastic Model

Bingham Plastic Model

The Bingham model is defined by the relationship;

Shear Stress = Yield Stress + (Plastic Viscosity x Shear Rate)

The major difference between this and Newtonian fluids is the presence of a Yield Stress or “Yield Point” (which is a measure of the electronic attractive forces in the fluid under flowing conditions). No bulk movement of the fluid occurs until this yield stress is overcome. Once the yield stress is exceeded, equal increments of shear stress produce equal increments of shear rate.

Flow Curve for a Bingham Plastic Fluid

Note that the apparent viscosity decreases with increased shear rate. This phenomenon is known as “shear thinning”. As shear rates approach infinity, the apparent viscosity reaches a limit known as the Plastic Viscosity. This viscosity is the slope of the Bingham plastic line. The commonly used Fann V-G meter was specifically designed to measure viscosities for this model. As can be seen in the above illustration, this model does not accurately represent drilling fluids at low shear rates.

Hydraulics - Deformation of a Fluid by Simple Shear

Deformation of a Fluid by Simple Shear

The magnitude of shear between the layers is represented by the shear-rate, which is defined as the difference in the velocities between the layers, divided by the distance of separation. It is this relationship between the shear-stress and shear-rate that defines the behavior of the fluid.

For some fluids the relationship is linear (i.e., if the shear-stress is doubled then the shear-rate will also double, or if the circulation rate is doubled then the pressure required to pump the fluid will double). Fluids such as this are known as “Newtonian fluids”. Examples of Newtonian fluids are water, glycerine and diesel. The Newtonian fluid model is defined by the following relationship:

Shear-Stress = Absolute Viscosity x Shear-Rate

The slope of the flow curve in the diagram is given by the absolute viscosity, this is the shear stress divided by the shear rate. A typical flow profile for a Newtonian fluid in a cylindrical pipe is a parabola, with a maximum shear-rate at the wall and a minimum (0) at the center.

Drilling fluids are generally Non-Newtonian in behavior, and are defined by more complex relationships between shear-stress and shear-rate. When fluids contains colloidal particles (or clays), these particles tend to increase the shear-stress or force necessary to maintain a given flow rate. This is due to electrical attraction between particles and to them physically “bumping” into each other. Long particles, randomly oriented in a flow stream, will display high interparticle interference. However, as shear-rate is increased, the particles will tend to develop an orderly orientation and this interaction will decrease.

In the center of a pipe, the shear-rate will be low and hence particle interaction high, giving it a flattened flow profile. This profile has an improved sweep efficiency and an increased carrying capacity for larger particles.

As can be seen from the previous examples, the ratio of shear-stress to shear-rate is not constant but will vary with each shear-rate. Various “oilfield” models have been proposed to describe this non-

Newtonian shear-rate/shear-stress curve. In order to arrived at “standard” variables, these models require the measurement of shear-stress at two or more shear-rates to define the curve.

The two most common models used at the wellsite are the Bingham Plastic Model and the Power Law Model.

Hydraulics

The concept that a fluid cannot maintain a rigid shape is a basic, but important characteristic, which means that fluids cannot sustain a shearstress (a tangential force applied to the surface). Any tangential force will cause the fluid to deform and continuous deformation is known as “flow”.

Fluid flow is always considered to take place within a conductor. A conductor may be the annulus created by casing for drilling fluid or a volcano’s slope and the atmosphere, in the case of a lava flow. Generally, fluid flow can be considered the result of parallel fluid layers sliding past one another. The layers adjacent to the conductor adhere to the surface and each successive layer slides past its neighbor with increasing velocity. This orderly flow pattern is known as laminar flow. At higher velocities, these layers lose their order and crash randomly into one another with an orderly flow occurring only adjacent to the conductor. This flow pattern is known as turbulent flow.

Laminar Flow is usually found in the annulus during drilling operations. This type of flow is generally desired in the annulus since it does not lead to hole erosion and does not produce excessive pressure drops. These pressure drop calculations can be mathematically derived according to the

type of flow behavior.

Turbulent Flow is the type of flow regime found inside the drill string during drilling operations. Since high mud velocities are required to achieve turbulent flow, this results in high pressure drops. This type of flow is generally not desired in the annulus due to its tendency to cause excessive hole erosion and high “equivalent circulating densities”.

However, turbulent flow can move the mud like a plug, causing the mud to move at approximately the same rate. This provides for better hole cleaning and is sometimes required on high angle holes. Pressure drop calculations for turbulent flow are empirical rather than mathematically derived. When a force is applied to a static fluid, the layers slide past one another and the frictional drag that occurs between the layers (which offers resistance to flow) is known as “shear-stress”.

Drilling Fluid Report - Funnel Viscosity

Funnel Viscosity sec/qt

The Marsh Funnel is the field instrument used to measure viscosity. It is graduated so that one quart (946 cc) of water will flow through the funnel in 26 seconds. To run a test, the bottom orifice is covered and drilling fluid is poured over a screen until the funnel is full. When the bottom is uncovered, the time required to fill one quart is recorded (in seconds) along with the temperature.

Funnel viscosity is a rapid, simple test, but because it is a one point measurement it does not provide information as to why the viscosity has changed, only that it has changed.

Drilling Fluid Report - Solids Content , Water Content , Oil Content

Solids Content % vol

Water Content % vol

Oil Content % vol

A retort is used to determine the quantity of liquids and solids in a drilling fluid. A measured sample of fluid is heated until the liquid portion is vaporized. The vapors are passed through a condenser and measured as a percentage by volume. The solids are then calculated by subtracting the total from 100.

Drilling Fluid Report - Sand Content

Sand Content % vol

This is measured by use of a 200 mesh sand screen set. A measuring tube is filled with mud and water and shaken vigorously. The mixture is then poured over the 200 mesh sieve and washed clean with water. The sand is then washed into the measuring tube and measured in percent. This will give an indication as to the effectiveness of the mechanical solids control equipment.

Drilling Fluid Report - Calcium

Calcium ppm

If water contains a lot of calcium or magnesium salts, it is referred to as “hard water”. The harder the water, the more difficult it is to get bentonite to yield, thus requiring more bentonite to make a good gel. Excess calcium contamination may cause abnormally high water loss and fast gel rates.

Drilling Fluid Report - Salt/Chlorides

Salt/Chlorides ppm or gpg

The salt or chlorides concentration of the mud is monitored as an indicator of contamination. The salt contamination may come from water used to make mud, salt beds or from saline formation waters. The test is conducted on mud filtrate.

One or more milliliters of filtrate is added to a titration dish and 2 or 3 drops of phenolphthalein solution is added. Drops of 0.02 nitric or sulfuric acid solution are then added while stirring to remove the pinkish color. One gram of pure calcium carbonate is then added and stirred. Next, 25 - 50 ml of distilled water and 5 - 10 drops of potassium chromate solution are added. This mixture is stirred continuously while drops of silver nitrate solution are added until the color changes from yellow to orange red and persists for 30 seconds. The number of milliliters of silver nitrate used to reach the end-point are recorded. This is then used in the equation:

Chlorides(ppm) = (ml of silver nitrate x 1000) / ml filtrate
This can be converted to salt (NaCl) ppm by multiplying the chlorides by 1.65, or to grains per gallon by multiplying the salt ppm by 0.0583.

Drilling Fluid Report - Alkalinity, Mud : Alkalinity, Filtrate

Alkalinity, Mud Pm
Alkalinity, Filtrate Pf/Mf

Alkalinity or acidity of a mud is indicated by the pH. The pH scale is logarithmic and hence a high pH mud may vary considerably without a noticeable change in pH. The filtrate and mud can both be measured to show the phenolphthalein alkalinity.

The test for filtrate is carried out by putting 1 or more milliliters of filtrate into a titration dish and adding 2 or 3 drops of phenolphthalein indicator solution. Drops of 0.02 normal nitric or sulfuric acid solution are then added until the pink coloration just disappears. The alkalinity is measured as the number of milliliters of acid per milliliter of filtrate. The test for mud is similar except that to one milliliter of mud, 25 to 50 milliliters of water are added for dilution and 4 or 5 drops of phenolphthalein are added. The result is measured the same as for the filtrate.

Drilling Fluid Report - Filtrate/Water Loss , Filter Cake Thickness

Filtrate/Water Loss ml/30 min

Filter Cake Thickness 1/32 inch

These two properties shall be dealt with together, as it is the filtration of mud that causes the build up of filter cake. Loss of fluid (usually water and soluble chemicals) from the mud to the formation occurs when the permeability is such that it allows fluid to pass through the pore spaces. As fluid is lost, a build up of mud solids occurs on the face of the wellbore.

This is the filter cake.

Two types of filtration occur; dynamic, while circulating and static, while the mud is at rest. Dynamic filtration reaches a constant rate when the rate of erosion of the filter cake due to circulating matches the rate of deposition of the filter cake. Static filtration will cause the cake to grow thicker with time, which results in a decrease in loss of fluids with time.

Mud measurements are confined to the static filtration. Filtration characteristics of a mud are determined by means of a filter press. The test consists of monitoring the rate at which fluid is forced from a filter press under specific conditions of time, temperature and pressure, then measuring the thickness of the residue deposited upon the filter paper.

Excessive filtration and thick filter cake build up are likely to cause the following problems:

1. Tight hole, causing excessive drag.

2. Increased pressure surges, due to reduced hole diameter.

3. Differential sticking, due to an increased pipe contact in filter cake.

4. Excessive formation damage and evaluation problems with wireline logs.

Most of these problems are caused by the filter cake and not the amount of filtration because the aim is to deposit a thin, impermeable filter cake. A low water loss may not do this, as the cake is also dependent upon solids size and distribution.

The standard fluid loss test is conducted over 30 minutes. The amount of filtrate increases with direct proportion to the square root of the time. This can be expressed by the following;

Q2 = (Q1 x T2)/T1

Where: Q2 is the unknown filtrate volume at time T2

Q1 is the known filtrate volume at time T1

Pressure also affects filtration by compressing the filter cake, reducing its permeability and therefore reducing the filtrate. Small plate-like particles act as the best filter cake builders and bentonite meets these requirements.

Increased temperature has the effect of reducing the viscosity of the liquid phase and hence increasing filtration. With all other factors being constant, the amount of filtrate will vary with the square root of time. Proper dispersion of the colloidal clays in the mud gives a good overlap of particles, thus giving good filtration control. A flocculated mud, which has aggregates of particles, allows fluid to pass through easily. The addition of chemicals to act as dispersants will increase the efficiency of the filter cake.

The standard test is conducted at surface temperature at 100 psi and is recorded as the number of ml's of fluid lost in 30 minutes. An API high pressure/high temperature (Hp/Ht) test is conducted at 300° F and 500 psi.

The tests may be conducted using a portable filter press that uses CO2 cartridges or using a compressed air supply. The high pressure and high temperature test is conducted to simulate downhole conditions, since the degree of filtration may vary, depending upon the compressibility of the filter cake. A mud sample may be tested at standard temperatures and pressures, increased temperature and 100 psi, or at high temperatures and pressures. Increased pressure will indicate if the filter cake is compressible.

The primary fluid loss agent in most water based muds are the clays. These solids should have a size variation with a large percentage being under 1 micron. This will produce a filter cake with low porosity and permeability.

The use of centrifuges or cyclone solids removal equipment may cause filtration problems by removing the small size solids. Starch is also used as a fluid loss agent, the starch being treated is so that it will easily gelatinize and swell. Water soluble polymers are commonly used as viscosifiers, acting on the fluid phase which also reduces fluid loss.

Sodium Carboxyl-Methyl Cellulose (CMC) is an organic colloid with a long chain structure that can be polymerized into different lengths or grades. It is thought to act by either the long chains plugging narrow openings in the filter cake, curling into balls to act as plugs, or by coating the clay particles with a film. It will however, lose its effectiveness as salt concentrations rise above 50,000 ppm. A polyanoinic cellulose is used as the fluid loss agent in high salt concentration, low solids drilling fluids.

Drilling Fluid Report - pH

Drilling muds are always treated to be alkaline (i.e., a pH > 7). The pH will affect viscosity, bentonite is least affected if the pH is in the range of 7 to 9.5. Above this, the viscosity will increase and may give viscosities that are out of proportion for good drilling properties. For minimizing shale problems, a pH of 8.5 to 9.5 appears to give the best hole stability and control over mud properties. A high pH (10+) appears to cause shale problems.

The corrosion of metal is increased if it comes into contact with an acidic fluid. From this point of view, the higher pH would be desirable to protect pipe and casing.

Carbon Dioxide corrosion can cause severe pitting and cracks in fatigue areas. If moisture is present, CO2 dissolves and forms carbonic acid.

CO2 + H2O = H2CO3

This causes a reduction in the pH, which makes the water more corrosive to steel.

Fe + H2CO3 = FeCO3 (iron carbonate scale)

If a high pH is maintained, the water will tend to be less corrosive.

Standard treatments for CO2 are:

1. Kill the source of CO2 (if it is a kick, then circulate out the gas through the degasser).

2. Re-establish proper alkalinity and pH by additions of lime and/ or caustic soda.

While a high pH will combat corrosion, it may be necessary to add chemicals to remove the scale as well.

H2S as a gas is not particularly corrosive, however if moisture is present it will become corrosive and in the presence of CO2 or O2, it becomes extremely corrosive. Since H2S is soluble in drilling muds, as the pH increases, the total amount of sulfides existing as H2S is reduced. The pH should be maintained above 10 if known H2S bearing formations are to be drilled. A scavenger should also be added to remove sulfides. The most common scavengers are zinc carbonate, zinc chromate, zinc oxide, ironite sponge (Fe304) and copper carbonate. The pH will have to be treated as scavengers are added.

pH is commonly measured with pHydrion paper. This paper is impregnated with dyes that render a color which is pH dependent. The paper is placed on the surface of the mud which wets the paper. When the color has stabilized, it is compared with a color chart. An electronic pH meter may also be used.

Drilling Fluid Report - Gel Strength

Gel Strength lbs/100 ft2 (10 sec/10min)

This is a measurement that denotes the thixotropic properties of the mud and is a measurement of the attractive forces of the mud while at rest or under static conditions. As this and yield point are both measures of flocculation, they will tend to increase and decrease together, however a low yield point does not necessarily mean 0/0 gels!

Gel strength is measured with the viscometer by stirring the mud at high speeds for about 15 seconds and then turning the viscometer off or putting it into neutral (low gear if it's a lab model) and waiting the desired period, (i.e., 10 seconds or 10 minutes). If the viscometer is a simple field model, the “gel strength” knob is turned counter clockwise slowly and steadily. The maximum dial deflection before the gel breaks is then recorded in lb/ 100 ft2. With a lab model, the procedure is the same except a low speed is used. After a wait, the second gel can be taken in a similar manner. Gels are described as progressive/strong or fragile/weak. For a drilling fluid, the fragile gel is more desirable. In this case, the gel is initially quite high but builds up with time only slightly. This type of gel is usually easily broken and would require a lower pump pressure to break circulation.

Drilling Fluid Report - Yield Point

Yield Point lbs/100 sqft

This parameter is also obtained from the viscometer. The yield point (YP), as mentioned earlier, is a measure of the electro-chemical attractive forces within the mud under flowing conditions. These forces are the result of positive and negative charges located near or on the particle’s surfaces.

With this in mind, the yield point is then a function of the surface properties of the mud solids, the volume concentration of the solids, and the concentration and type of ions within the fluid phase.

The yield point is the shear stress at zero shear rate, and is measured in the field by either;

YP = 300 rpm reading - PV
or YP = (2 x 300 rpm reading) - 600 rpm reading

This gives a Bingham yield point, which is generally higher than the actual or true yield.
As stated earlier, at low shear rates, the Bingham model does not give particularly good readings.

High viscosity, resulting from a high yield point is caused by:

1. Introduction of soluble contaminants such as salt, cement, anhydrite, or gypsum, which neutralize negative charges of the clay particles, resulting in flocculation.

2. The breaking of clay particles by the grinding action of the bit and pipe, which creates “broken bond valences” on the edges of the particles, causing the particles to pull together.

3. Introduction of inert solids causes the particles to be closer together into disorganized form or flocks.

4. Drilling of hydratable clays introduces active solids into the system, increasing the attractive forces by increasing the number of charges and by bringing the particles closer together.

5. Both insufficient or over-treatment of the mud with chemicals will increase the attractive forces of the mud.

Treatment for increased yield point may be controlled by chemical action, but reduction of the yield point will also decrease the apparent viscosity.

Yield point may be lowered by the following:

1. Broken bond valences may be neutralized by adsorption of certain negative ions at the edge of the clay particles. These residual valences are almost totally satisfied by chemicals such as tannins, lignins, lignosulfonates and complex phosphates. The attractive forces are satisfied by chemicals, and the clay's natural negative charge remains, so that the particles repel each other.

2. If calcium or magnesium contamination occurs, the ion is removed as an insoluble precipitate, thus decreasing the attractive forces and hence the yield point.

3. Water can be used if the solid content is very high, but it is generally ineffective and may alter other properties drastically (i.e., mud density).

As mentioned earlier, the chemicals that are added to deflocculate the mud and act as “thinners” are commonly lignosulfonates and tannins. These also have a secondary function of acting as filtration agents.

Drilling Fluid Report - Plastic Viscosity

Plastic Viscosity centipoise (cps)

The plastic viscosity (PV) is calculated by measuring the shear rate and stress of the fluid. These values are derived by using a Fann viscometer, which is a rotating-sleeve viscometer, and may be a simple hand operated two speed model or a more complex variable speed electric model. The two speed model operates at 300 and 600 rpm.

The Fann viscometer consists of an outer rotating sleeve and an inner bob. When the outer sleeve is rotated at a known speed, torque is transmitted through the mud to the bob. The bob is connected to a spring and dial, where the torque is measured. The shear rate is the rotational speed of the sleeve and the shear stress is the stress (torque) applied to the bob, measured as deflection units on the instrument dial. These measurement values are not true units and need to be converted.

Shear rate is the rate of change as the fluid layers move past one another per unit distance, and is measured in reciprocal seconds (i.e. (ft/sec)/ft) and is usually written as seconds-1. To convert the dial reading to shear stress, the dial reading is multiplied by 1.067 to give a reading in lb/100ft2.

The units of viscosity are poise or centipoise (1/100 poise) and is derived as follows:

Viscosity (poise) = (F/A) / (V/H)
where: F = Force (dynes)
A = Area (cm2)
V = Velocity (cm/cc)
H = Distance (cm)

This produces viscosity as Dynes (sec/cm2) or poise.
The Fann viscometer reading is therefore multiplied by 1.067 to obtain shear stress in lb/100ft2; or multiplied by 478.8, and divided by the shear rate in second-1 to get Dynes/cm2.

Viscosity then becomes:

511 x dial reading / shear rate (sec-1)
since 511 sec-1 = 300 rpm
or (300 x dial reading) / Fann shear rpm

The viscometer is designed to give the viscosity of a Newtonian fluid when used at 300 rpm.

For Non-Newtonian fluids, the ratio of shear-stress to shear-rate is not constant and varies for each shear rate. With a Bingham plastic fluid, a finite force is required to initiate a constant rate of increase of shear-stress with shear-rate. To obtain a value for this constant rate of increase, readings are taken with a viscometer at 511 sec-1 and 1022 sec-1 (300 and 600 rpm). The 600 dial reading minus the 300 dial reading gives the slope of the shear-stress/shear-rate curve. This is the Plastic Viscosity. The “apparent viscosity” is given by the 600 reading divided by 2. This is a measure of that part of resistance to flow caused by mechanical friction between solids in the mud, solids and liquids and the shearing layers of the mud itself.

We can see that control of the solids will give us control over our PV! This leads to “Why are we controlling the solids?” Since the viscosity of the mud is one of the principal factors contributing to the carrying capacity of the mud, the suspension of weighting materials, and pressure surges applied to the formation through frictional pressures in the annulus, it is obvious that increased solids will increase these annular pressures (and may increase the mud density), so a balance must be found in which the correct mud density and carrying capacity are maintained without exerting unnecessary pressures on the annulus.

In the mud system, we have solids that are an integral part of the mud (bentonite, starch, CMC, etc.) and solids that are undesirable (sand, limestone, dolomite, etc.). As the mud density is increased, by the addition of barite or hematite (more solids), the PV will automatically increase. The PV is also a function of the viscosity of the fluid phase of the mud (as temperature rises, the viscosity of water decreases, and the PV will decrease).

Several methods of lowering the solids content of the mud are available, all of which will lower the plastic viscosity and apparent viscosity, as well.

1. Dilution; add water and lower the concentration of solids.
2. Shaker Screens; using the finest screens possible without “blinding” to remove solids. Avoid hosing water on the screens as this washes fine solids through the screens.
3. Centrifuge; these separate the solids by size and mass, reducing total solids concentration.
4. Desander/Desilter; these mechanically remove the sand/silt sized particles from the mud.

To increase the viscosity of a mud system, various “mud chemicals” can be added. These are mostly types of bentonite, but attapulgite clays, asbestos and gums (Guar or Xanthan) are also used.
The polymer viscosities such as XC polymer, consist of these gums. Most polymers provide a mud with a shear thinning effect. This is desirable as it allows viscosity to be maintained while circulating pressures are reduced.

Drilling Fluid Report - Density

One of the most important reports at the wellsite is the daily drilling fluid report, or “mud report”. In addition to containing basic well and rig information, chemical inventory and mud system costs, the mud report will contain a list of the fluid properties of the mud system. To maintain the required properties, certain tests are conducted on the drilling fluid. The most important are listed below.

Density

pounds/gallon (lb/gal)

The density of the drilling fluid is important to maintaining well control. As mentioned earlier, fresh water has a density of 8.34 lb/gal, with a corresponding gradient of 0.433 psi/ft. As long as the formations have the same gradient, fresh water will “balance” the formation pressures.

Since this is generally not the case, some weight material must be added to the fluid, the most common being barite and hematite. The drilling fluids density is measured using a “mud balance”. This balance contains a mud cup on one end of a beam with a fixed counter weight on the other end of the beam. The beam is inscribed with a graduated scale, contains a level bubble and a movable rider. When the cup is filled with fresh water, steel shot is added to the counter weight container until the beam is level, with the rider pointing at the 8.34 scribe line.

During wellsite operations, the mud’s density is checked by filling the cup with drilling fluid and moving the rider until the level bubble indicates the beam is balanced. The density is then read using the position of the rider.

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