Drilling fluids: functions and properties

Quick refresher

The mud must carry cuttings out and hold them in suspension when circulation stops. It must hold back the formations and support the walls of the well with its pressure, cool and lubricate the bit, and pass power to it. At the same time it must not harm the productive formation or the environment, and it must not cost too much.
The density sets the pressure on the formations: $p = 0.00981\,\rho h$ (MPa, g/cm³, m) or $p = 0.052\,\rho h$ (psi, ppg, ft). We raise it with a weighting material, most often barite (a heavy mineral) with a density of about 4.2 g/cm³.
Mud thins when it flows fast and thickens at rest, forming a gel. We describe its flow with three numbers: the plastic viscosity (how thick the mud is while it flows), the yield point (YP, the push needed to start it flowing) and the gel strength (how firm the gel is at rest).
Opposite permeable rocks (rocks that let fluid pass), the mud loses liquid into the rock and builds a cake on the wall. A good cake is thin and has low permeability.
Water-based muds are cheaper and safer for the environment, but water hydrates clays (the clays take up water and swell). Oil-based muds keep the hole stable and lubricate the string, but they cost more, need special disposal of cuttings and make it harder to detect gas kicks.

Key relationships

p = 0.00981\,\rho\,h

pressure of the mud column: MPa, g/cm³, m vertical

p = 0.052\,\rho\,h

the same in oilfield units: psi, ppg, ft

\dfrac{V_{\text{wm}}}{V_1} = \dfrac{\rho_2 - \rho_1}{\rho_{\text{wm}} - \rho_2}

volume of weighting material per unit volume of the original mud

\eta_p = \theta_{600} - \theta_{300},\quad \tau_0 = \theta_{300} - \eta_p

plastic viscosity (mPa·s) and yield point (lb/100 ft²) from the viscometer readings

Common pitfalls

Mixing up the units of density: 1 g/cm³ = 1000 kg/m³ = 8.345 ppg. The gradient of a column with a density of 1 g/cm³ is 9.81 kPa/m (0.433 psi/ft).
Judging the rheology of the mud from the funnel viscosity, which is the time the mud takes to run out of a funnel. It is only an indicator of changes.
Weighting up the mud without checking the margin to the fracture pressure of the rocks, with the equivalent circulating density (ECD) taken into account.
Taking the standard fluid loss figure as a forecast of how much filtrate will go into the formation.

Why we need a drilling fluid

The mud is prepared on the surface in tanks. The mud pumps send it through the standpipe (the vertical pipe on the rig) and the drill string to the bit. It leaves the nozzles of the bit as jets that hit the bottom of the hole, rises up the annulus, passes through the cleaning equipment and returns to the tanks (see How a well is drilled: the process and the people involved). During one cycle of circulation it does several jobs at once.

SchematicWhat the mud does near the bottom: it carries cuttings up the annulus, cleans the bottom of the hole and cools the bit with jets from the nozzles, supports the walls and holds back the formations with the pressure of its column, and builds a cake opposite permeable sandstone, while the filtrate goes into the rock. The sketch is not to scale.

Functions of the mud and the properties that serve them

Function: Carrying cuttings out of the well
Main properties: flow velocity in the annulus, rheology (yield point, viscosity), density
If the property is out of range: cuttings build up, torque and overpull (the extra pull needed to move the pipe) grow, and the string may get stuck

Function: Holding cuttings and weighting material in suspension when circulation stops
Main properties: gel strength (how firm the gel is at rest)
If the property is out of range: cuttings and weighting material settle to the bottom; in deviated holes cuttings beds form

Function: Holding back the formations
Main properties: density
If the property is out of range: if the density is too low, a kick; if it is too high, lost circulation and fracturing of the rock

Function: Stability of the wall of the well
Main properties: density, the inhibiting properties of the filtrate (how well it stops shales from swelling and breaking up), fluid loss
If the property is out of range: sloughing and caving of shales, washouts (enlarged parts of the hole), dissolving of salts

Function: Cooling and lubricating the bit and the string
Main properties: flow rate, lubricity, type of base fluid
If the property is out of range: overheating and wear of the bit, high torque and drag on the string

Function: Passing hydraulic power to the bit and the downhole motor
Main properties: flow rate, density, viscosity
If the property is out of range: poor cleaning of the bottom of the hole, low rate of penetration (how fast the bit drills)

Function: Sealing permeable rocks with a cake
Main properties: fluid loss, composition and size of the solid particles
If the property is out of range: a thick cake, differential sticking (the pipe is held against the wall by the pressure difference), deep invasion of filtrate, formation damage

Function	Main properties	If the property is out of range
Carrying cuttings out of the well	flow velocity in the annulus, rheology (yield point, viscosity), density	cuttings build up, torque and overpull (the extra pull needed to move the pipe) grow, and the string may get stuck
Holding cuttings and weighting material in suspension when circulation stops	gel strength (how firm the gel is at rest)	cuttings and weighting material settle to the bottom; in deviated holes cuttings beds form
Holding back the formations	density	if the density is too low, a kick; if it is too high, lost circulation and fracturing of the rock
Stability of the wall of the well	density, the inhibiting properties of the filtrate (how well it stops shales from swelling and breaking up), fluid loss	sloughing and caving of shales, washouts (enlarged parts of the hole), dissolving of salts
Cooling and lubricating the bit and the string	flow rate, lubricity, type of base fluid	overheating and wear of the bit, high torque and drag on the string
Passing hydraulic power to the bit and the downhole motor	flow rate, density, viscosity	poor cleaning of the bottom of the hole, low rate of penetration (how fast the bit drills)
Sealing permeable rocks with a cake	fluid loss, composition and size of the solid particles	a thick cake, differential sticking (the pipe is held against the wall by the pressure difference), deep invasion of filtrate, formation damage

There are also less obvious functions:

the mud supports part of the weight of the string: steel pipes in mud are lighter than in air by the fraction $\rho_m/\rho_s$ , where $\rho_m$ and $\rho_s$ are the densities of the mud and of steel (at 1.20 g/cm³ and 7.85 g/cm³ this is about 15%)
measurements made at the bottom of the hole (the path of the hole, and logging while drilling) travel to the surface through the mud column as pressure pulses (see Measurement while drilling)
the mud decides which logging tools can be used: tools that pass current through the mud need a conductive mud (see Borehole environment: invaded zone and mudcake)
the mud protects pipes and equipment from corrosion

A mud is also judged by things that have nothing to do with drilling itself: how much it costs, whether its filtrate and solid particles will reduce the permeability of the productive formation (see Formation damage and damage skin), and how safe it is for the environment: its toxicity and the disposal of the used mud and cuttings.

Density: pressure on the formations

Density is the most important property of the mud for safety. The pressure of the mud column at a depth depends only on its density and the vertical height of the column. The lesson Pore pressure and overburden pressure explains in detail where the constants of the calculation come from, and how to choose the density from the pore pressure (the pressure of the fluid in the pores of the rock) with a margin. Here it matters to move confidently between the units in which mud density appears in drilling programmes and reports.

Pressure of a column of drilling mud

p = 0.00981\,\rho\,h

where:

$p$ gauge pressure of the mud column at depth $h$ (the pressure above atmospheric pressure), MPa
$\rho$ density of the mud, g/cm³
$h$ vertical depth from the top of the column, usually from the rotary table, m

Units: metric units: MPa, g/cm³, m

Holds when

The mud is at rest. During circulation the pressure at the bottom is higher by the pressure loss in the annulus (ECD).
The density is the same all along the column, and the column reaches the wellhead.
$h$ is the vertical depth, not the length along the hole.

Every 0.01 g/cm³ of density at a depth of 3000 m gives about 0.3 MPa of pressure. A change in density that looks small changes the bottomhole pressure noticeably.

In other unit systems (2)

Oilfield units

p\,[\text{psi}] = 0.052\,\rho\,[\text{ppg}]\;h\,[\text{ft}]

$\rho$ in pounds per US gallon (ppg), $h$ in feet.

$0.052$ is a rounded $12/231 = 0.05195$ (the derivation is in the lesson on pore and overburden pressure). The rounding overstates the pressure by 0.1%.

SI

p = \rho\,g\,h

$\rho$ in kg/m³, $g = 9.80665$ m/s², $h$ in m, $p$ in Pa.

This gives the metric constant: $1000\cdot 9.80665\cdot 10^{-6} = 0.00981$ MPa per metre of a column with a density of 1 g/cm³.

Units of drilling mud density

Unit: kg/m³
Value for 1 g/cm³: 1000
Where it is used: SI, design documents

Unit: g/cm³ (relative density, SG)
Value for 1 g/cm³: 1
Where it is used: practice in Kazakhstan and Russia; SG in English-language practice

Unit: ppg: pounds per US gallon
Value for 1 g/cm³: 8.345
Where it is used: English-language drilling programmes and reports

Unit: lb/ft³ (pcf)
Value for 1 g/cm³: 62.43
Where it is used: less often, in English-language practice

Unit: gradient, kPa/m
Value for 1 g/cm³: 9.807
Where it is used: comparison with the gradients of pore pressure and fracture pressure

Unit: gradient, psi/ft
Value for 1 g/cm³: 0.4335
Where it is used: the same in oilfield units

Unit	Value for 1 g/cm³	Where it is used
kg/m³	1000	SI, design documents
g/cm³ (relative density, SG)	1	practice in Kazakhstan and Russia; SG in English-language practice
ppg: pounds per US gallon	8.345	English-language drilling programmes and reports
lb/ft³ (pcf)	62.43	less often, in English-language practice
gradient, kPa/m	9.807	comparison with the gradients of pore pressure and fracture pressure
gradient, psi/ft	0.4335	the same in oilfield units

The gradient is the pressure of the column per metre (foot) of depth: $0.00981\,\rho$ MPa/m for a density in g/cm³, or $0.052\,\rho$ psi/ft for a density in ppg. In old documents the mud density is called “specific weight” and is given in gf/cm³, which is numerically the same as g/cm³.

At the rig, density is measured with a mud balance. A cup of known volume is filled with mud and balanced with a weight on a lever arm. Gas bubbles in the sample make the result too low. So for gas-cut mud (mud with gas mixed into it) we use a balance with a sealed cup under pressure. The density of the mud going into the well and coming out of it is compared all the time (see Well control: primary barrier and kick indicators).

Worked exampleA programme in ppg, a calculation in MPa

Given (assumed data)

Mud density in an English-language programme: 10.8 ppg
True vertical depth of the sandstone: 3150 m
Pore pressure of the sandstone: 37.8 MPa

Solution

Density in metric units: $\rho = 10.8/8.345 = 1.294$ g/cm³, or 1294 kg/m³.
Pressure of the column: $p = 0.00981\cdot 1.294\cdot 3150 = 39.99$ MPa.
Check in oilfield units: $h = 3150/0.3048 = 10{,}335$ ft; $p = 0.052\cdot 10.8\cdot 10{,}335 = 5804$ psi, or $5804/145.04 = 40.02$ MPa. The difference is less than 0.1%. It comes from the rounding of the constants.
Overbalance on the sandstone (the excess of the mud pressure over the pore pressure): $39.99 - 37.8 = 2.19$ MPa. Equivalent mud weight of the pore pressure (the mud density that would just balance it): $37.8/(0.00981\cdot 3150) = 1.223$ g/cm³ (10.21 ppg).
Pressure gradient of the mud: $9.81\cdot 1.294 = 12.7$ kPa/m, or $0.052\cdot 10.8 = 0.5616$ psi/ft.

Answer: A mud of 10.8 ppg is 1.294 g/cm³. At a depth of 3150 m it produces about 39.99 MPa (5804 psi), and the overbalance on the sandstone is 2.19 MPa.

What it means. The same pressure, calculated in different systems of units, must agree to within the rounding of the constants. This is a simple check of the conversion. The mud density (1.294 g/cm³) exceeds the equivalent mud weight of the pore pressure (1.223 g/cm³) by only 0.071 g/cm³, and at this depth that already means more than 2 MPa of overbalance. The data in this example are assumed for illustration.

How the density is raised. The density of water is 1.0 g/cm³, and that of a saturated brine of table salt (salt water that cannot dissolve any more salt) is about 1.2 g/cm³. To make a heavier mud, we add a finely ground heavy mineral, the weighting material. Its particles do not dissolve. They stay in suspension because of the structure of the mud. The denser the weighting material, the smaller the volume of it that we need. Every extra share of solids makes the mud thicker, makes the cake thicker and speeds up the wear of the equipment.

Weighting materials and heavy brines

Material: Barite, $\mathrm{BaSO_4}$
Density, g/cm³: about 4.2 (the pure mineral up to 4.5)
Features: the main weighting material: heavy, chemically inert, fairly soft, and it wears the equipment little

Material: Hematite, $\mathrm{Fe_2O_3}$
Density, g/cm³: about 5
Features: for very heavy muds; it wears the equipment more

Material: Calcium carbonate (ground marble, chalk), $\mathrm{CaCO_3}$
Density, g/cm³: 2.7
Features: dissolves in acid, so the cake can be removed later; it is used when drilling into productive formations; it gives only a moderate density

Material: Brines: $\mathrm{NaCl}$ ; $\mathrm{CaCl_2}$ ; calcium and zinc bromides
Density, g/cm³: up to ~1.2; up to ~1.4; up to ~2.3
Features: fluids with no solids, for drilling into the productive formation and for completing the well; they are expensive, especially the bromides

Material	Density, g/cm³	Features
Barite, $\mathrm{BaSO_4}$	about 4.2 (the pure mineral up to 4.5)	the main weighting material: heavy, chemically inert, fairly soft, and it wears the equipment little
Hematite, $\mathrm{Fe_2O_3}$	about 5	for very heavy muds; it wears the equipment more
Calcium carbonate (ground marble, chalk), $\mathrm{CaCO_3}$	2.7	dissolves in acid, so the cake can be removed later; it is used when drilling into productive formations; it gives only a moderate density
Brines: $\mathrm{NaCl}$ ; $\mathrm{CaCl_2}$ ; calcium and zinc bromides	up to ~1.2; up to ~1.4; up to ~2.3	fluids with no solids, for drilling into the productive formation and for completing the well; they are expensive, especially the bromides

Drilled rock (sand, clay, limestone) also makes the mud heavier. Its density is about 2.6 g/cm³. But it is an unwanted solid phase, and it is removed by the cleaning equipment.

How much weighting material is needed to raise the density

V_{\text{wm}} = V_1\,\frac{\rho_2 - \rho_1}{\rho_{\text{wm}} - \rho_2}, \qquad m_{\text{wm}} = \rho_{\text{wm}}\,V_{\text{wm}}

where:

$V_1$ volume of the original mud, m³
$\rho_1,\ \rho_2$ density of the original mud and of the mud we need, g/cm³ (= t/m³)
$\rho_{\text{wm}}$ density of the weighting material, g/cm³
$V_{\text{wm}}$ volume of the weighting material to add, m³
$m_{\text{wm}}$ mass of the weighting material, t

Units: any consistent units: densities in g/cm³ (t/m³), volumes in m³, mass in tonnes

Holds when

The volumes of the mixed materials add up: $\rho_2 (V_1 + V_{\text{wm}}) = \rho_1 V_1 + \rho_{\text{wm}} V_{\text{wm}}$ . This is where the formula comes from.
The weighting material is dry and does not dissolve. In practice a little water is often added with it to wet the particles, and then slightly more weighting material is needed.
No mud is lost and none is diluted during weighting up.

The denominator $\rho_{\text{wm}} - \rho_2$ explains why a heavy weighting material is needed. The closer the required density is to the density of the weighting material, the faster the required volume grows. After weighting up there is $V_1 + V_{\text{wm}}$ of mud, so the tanks must hold the increase. The same formula with water in place of the weighting material solves the reverse problem: lowering the density by dilution.

In other unit systems (1)

Oilfield units (barite)

m\,[\text{lb/bbl}] = \frac{1470\,(W_2 - W_1)}{35 - W_2}

$W_1$ , $W_2$ are the densities of the original and the required mud in ppg; $m$ is pounds of barite per barrel of the original mud.

35 ppg is the density of barite (about 4.2 g/cm³). $1470 = 35\cdot 42$ , because there are 42 gallons in a barrel. 1 lb/bbl ≈ 2.853 kg/m³.

CalculatedThe share of the weighting material in the volume of the finished mud, against the required density, when an original mud of 1.05 g/cm³ is weighted up. It is calculated with the weighting-up formula. The lighter the weighting material, the more solids we must add.

Worked exampleWeighting up: barite or calcium carbonate

Given (assumed data)

Volume of mud in circulation $V_1$: 120 m³
Density now and required: 1.10 and 1.30 g/cm³
Density of barite and of calcium carbonate: 4.2 and 2.7 g/cm³

Solution

Barite per 1 m³ of original mud: $V_{\text{wm}} = \dfrac{1.30 - 1.10}{4.2 - 1.30} = 0.0690$ m³, and the mass is $4.2\cdot 0.0690 = 0.290$ t. For the whole volume we need 34.8 t of barite, and there will be 128.3 m³ of mud.
Calcium carbonate: $V_{\text{wm}} = \dfrac{0.20}{2.7 - 1.30} = 0.1429$ m³ per 1 m³, mass 0.386 t. For the whole volume we need 46.3 t, and there will be 137.1 m³ of mud.
The share of the weighting material in the volume of the finished mud, $V_{\text{wm}}/(V_1 + V_{\text{wm}})$ , is 6.5% for barite and 12.5% for carbonate.
Check with the oilfield formula: $W_1 = 1.10\cdot 8.345 = 9.18$ ppg, $W_2 = 1.30\cdot 8.345 = 10.85$ ppg. The barite is $1470\cdot(10.85 - 9.18)/(35 - 10.85) = 102$ lb/bbl, which is 290 kg/m³, the same as in the first step.

Answer: We need about 34.8 t of barite or 46.3 t of calcium carbonate. The volume of mud will grow to 128.3 m³ with barite and to 137.1 m³ with carbonate.

What it means. We need a third more carbonate by mass and twice as much by volume, and its share of the volume of the finished mud is also almost twice as high. So the mud will be thicker and the cake thicker. At still higher densities the difference grows quickly (see the graph). So we weight up with calcium carbonate only to a moderate density, and only where its solubility in acid matters. The tanks must hold the increase of volume: 8.3 m³ when weighting up with barite. The data in this example are assumed for illustration.

Rheology: how the mud flows and holds cuttings

Viscosity is the resistance of a fluid to flow. For water and oil it does not depend on the speed of flow. Such fluids are called Newtonian. Drilling muds behave differently. Clay particles and polymer molecules form a loose structure in them. At rest this structure gets stronger, and the mud turns into a weak gel. When the mud flows, the structure breaks down, and the faster the flow, the “thinner” the mud. This is a useful combination. In the pipe and in the bit nozzles, where the speed is high, the mud flows easily. In the annulus it is thicker and carries cuttings better. When the pumps stop, the gel holds the cuttings and the weighting material in suspension.

The flow of the mud is measured with a rotational viscometer. The mud fills the gap between a rotating sleeve and a cylinder hung on a spring. The angle through which the spring twists is the reading $\theta$ of the instrument, in degrees of the scale. It is proportional to the shear stress in the mud (the drag force per unit area), and the rotation speed of the sleeve is proportional to the shear rate (how fast the layers of mud slide past each other). The standard speeds are 600, 300, 200, 100, 6 and 3 rpm. The readings are most often processed with the Bingham plastic model: to make the mud flow, a certain starting stress must be exceeded, and after that the stress grows linearly with the shear rate.

Plastic viscosity and yield point from the viscometer readings

\eta_p = \theta_{600} - \theta_{300}, \qquad \tau_0 = \theta_{300} - \eta_p

where:

$\eta_p$ plastic viscosity (PV), the slope of the Bingham line, mPa·s (cP)
$\tau_0$ yield point (YP), the intercept of the Bingham line on the stress axis; 1 lb/100 ft² ≈ 0.479 Pa ≈ 4.8 dPa (in Russian-language reports the yield point and the gel strength are often given in dPa). By tradition the field value θ₃₀₀ − PV is written in lb/100 ft², although one division of the viscometer scale corresponds to ≈ 1.067 lb/100 ft² (0.511 Pa). So converting directly from scale divisions gives about 7% more in pascals. More on this in Drilling fluid rheology and flow regimes, lb/100 ft²
$\theta_{600},\ \theta_{300}$ viscometer readings at 600 and 300 rpm, scale degrees

Units: oilfield: $\eta_p$ in mPa·s, $\tau_0$ in lb/100 ft²; the formulas are valid for the standard geometry of the instrument

Holds when

The flow is described by the Bingham model from the two highest rotation speeds. At low shear rates real muds usually deviate from this line.
The measurement is made at a stated temperature, for water-based muds usually about 50 °C (120 °F). Viscosity depends strongly on temperature.
The formulas are a convention accepted in field practice. They leave out small constants of the instrument, so we compare values obtained in the same way.

PV reflects the friction of particles and liquid against each other. It grows first of all with the amount of solids and the viscosity of the base fluid. YP reflects the attractive forces between particles. It grows when clays flocculate (clump together), for example when the mud is contaminated with cement, salt or anhydrite. The apparent viscosity $\theta_{600}/2$ (mPa·s) is the viscosity of a Newtonian fluid that would give the same reading at 600 rpm.

The gel strength shows how strong the gel is. We leave the mud at rest for 10 s and for 10 min, and each time we note the highest reading at slow rotation, 3 rpm. Two numbers are written, for example 4 / 9 lb/100 ft². A gel is needed to hold the cuttings. But a gel that is too strong needs a high pressure to restart circulation, and it makes the pressure swings stronger when pipe is run in or pulled out (see Well control: primary barrier and kick indicators).

For a quick check at the rig, we measure the funnel viscosity: the time that the mud takes to run out of a funnel of standard size. For the Marsh funnel it is the time for 946 cm³ (one quart) to flow out. For fresh water it is about 26 s. Funnel viscosity is handy for noticing sudden changes, but it is not a physical quantity, because the shear rate keeps changing while the mud runs out. In Russian-language practice funnels of another standard were also used, so seconds from different funnels cannot be compared.

Worked exampleWhat the viscometer readings tell us

Given (assumed data)

Readings at 600 and 300 rpm: $\theta_{600} = 58$ , $\theta_{300} = 36$
Gel strength after 10 s and 10 min: 5 and 12 lb/100 ft²

Solution

Plastic viscosity: $\eta_p = 58 - 36 = 22$ mPa·s.
Yield point: $\tau_0 = 36 - 22 = 14$ lb/100 ft², that is $14\cdot 0.479 \approx 6.7$ Pa.
Apparent viscosity: $58/2 = 29$ mPa·s. The ratio of YP to PV is 0.64.

Answer: PV is 22 mPa·s, YP is 14 lb/100 ft² (6.7 Pa), and the gel strength is 5 / 12 lb/100 ft².

What it means. The numbers mean little by themselves. We compare them with the limits that the programme sets for this interval and density, and with the previous measurements. If PV rises while the density does not change, fine drilled solids are building up in the mud. It needs more careful cleaning or dilution. If YP and the gel rise, and the 10-minute gel strength gets further and further ahead of the 10-second one, the particles are flocculating, for example after drilling out cement or salt. Then the mud is treated with chemicals. The data in this example are assumed for illustration.

Filtration and the mudcake

Opposite a permeable formation, the pressure of the mud is higher than the pore pressure, and liquid from the mud goes into the rock. The solid particles (clay, weighting material, fine drilled rock) are held back on the wall and form a mudcake (a filter cake), while the filtrate passes into the formation. The cake is orders of magnitude less permeable than the rock. So as soon as it has formed, filtration slows down sharply. The volume of filtrate grows roughly in proportion to the square root of time (the derivation is in the lesson Borehole environment: invaded zone and mudcake).

Do not confuse filtration with lost circulation. In lost circulation the whole mud, with its solids, goes into fractures, caverns or very permeable rock, and less mud comes back out of the well than is pumped in. Filtration is a slow and unavoidable loss of the liquid phase. Lost circulation is a problem that calls for action.

We measure the filtration properties with a filter press. The mud is forced under pressure through filter paper, and we measure the volume of filtrate in 30 min and the thickness of the cake. In the standard test the pressure is about 0.7 MPa (100 psi) at room temperature. For deep, hot wells the test is repeated at high pressure and high temperature, with a pressure difference of 3.5 MPa (500 psi) and heating to 150 °C and above. The result is called the fluid loss (water loss). It is written in cm³ per 30 min, and the cake thickness in millimetres.

The standard test is static: the mud does not move along the cake. In the well, circulation erodes the cake, and the temperature and the pressure difference are different. So the fluid loss is a comparison figure for the mud, not a forecast of the volume of filtrate in the formation. A good cake is thin, dense and of low permeability:

a thick cake narrows the hole and increases overpull and swabbing
the pressure difference between the well and the formation presses the string against a thick cake, and differential sticking occurs: the pipe is “sucked” to the wall opposite a permeable formation
the more filtrate and fine particles go into the formation, the more the permeability of the near-wellbore zone can fall (see Formation damage and damage skin) and the deeper the invaded zone (the part of the rock that the filtrate has entered) that logging sees
a loose, thick cake gets in the way of good cementing of the casing

We lower the fluid loss by adding to the mud a finely dispersed clay (bentonite), polymers (starch, carboxymethyl cellulose, polyanionic cellulose) and particles of a chosen size that plug the mouths of the pores. In oil-based muds we add emulsifiers and special fluid-loss reducers.

Solids and the chemistry of the mud

The solid particles in the mud are divided into active ones and inert ones. The active ones are clays, which interact with water and chemicals, swell and create structure. The inert ones are the weighting material, sand, carbonates and most of the drilled rock. Not all solids are useful. Bentonite and the weighting material are added on purpose, but fine drilled rock only thickens the mud, makes the cake thicker, wears the pumps and lowers the rate of penetration. It is economically impossible to remove it completely. So the cuttings are separated on shale shakers, hydrocyclones (cone-shaped cleaners) and centrifuges (fast-spinning separators; see Solids control in drilling fluids), and what is left is diluted with fresh mud.

The content of solids and liquids is found by boiling off a sample in a retort, which gives the volumes of water, oil and solid residue. The sand content is found by washing a sample on a sieve with a 74 µm mesh. The content of active clay is found from the absorption of the dye methylene blue.

Chemical properties of the mud

Property: pH and alkalinity
What it shows: most water-based muds are kept slightly alkaline (pH usually about 8.5–10.5). Chemicals work better and there is less corrosion

Property: Chlorides
What it shows: a rise is a sign of drilling through salt or of an inflow of formation water; in salt muds it is a check of the concentration

Property: Hardness (calcium, magnesium)
What it shows: contamination with cement, gypsum or anhydrite; calcium weakens the action of many chemicals

Property: Electrical stability (oil-based muds)
What it shows: the stability of the emulsion: the voltage at which current begins to pass through the sample

Property: Oil–water ratio and water-phase salinity (also in oil-based muds)
What it shows: the composition of the emulsion and its ability not to give water to clays

Property	What it shows
pH and alkalinity	most water-based muds are kept slightly alkaline (pH usually about 8.5–10.5). Chemicals work better and there is less corrosion
Chlorides	a rise is a sign of drilling through salt or of an inflow of formation water; in salt muds it is a check of the concentration
Hardness (calcium, magnesium)	contamination with cement, gypsum or anhydrite; calcium weakens the action of many chemicals
Electrical stability (oil-based muds)	the stability of the emulsion: the voltage at which current begins to pass through the sample
Oil–water ratio and water-phase salinity (also in oil-based muds)	the composition of the emulsion and its ability not to give water to clays

The instruments, the order of measurements and the calculations are covered in the lesson Field testing of drilling fluids.

Types of drilling mud

Muds are classified first of all by their base fluid, also called the continuous phase. This is the liquid or gas that forms the continuous part of the mud and touches the walls of the well: water, a hydrocarbon liquid or a gas.

Main types of drilling mud

Type: Water-based (WBM)
Base and composition: fresh or sea water, bentonite, polymers, chemicals, weighting material
Where it is used: most wells and intervals
Limitations: water hydrates clays and dissolves salt; many polymers lose their properties at high temperature

Type: Inhibitive water-based
Base and composition: water with potassium chloride, polymers, glycols, silicates and other inhibitors
Where it is used: active clays, when oil-based muds are undesirable
Limitations: more expensive than ordinary water-based muds; the inhibition is incomplete

Type: Salt-saturated
Base and composition: saturated $\mathrm{NaCl}$ brine with polymers
Where it is used: drilling rock salt
Limitations: bentonite does not swell in brine, so salt-resistant polymers and clays are needed; brine increases corrosion

Type: Oil-based (OBM)
Base and composition: diesel fuel or mineral oil with droplets of calcium chloride brine (an invert emulsion), organophilic clay (clay treated so that it mixes with oil), lime, emulsifiers (chemicals that keep the droplets from merging), weighting material
Where it is used: unstable shales, salts, high temperatures, deviated and horizontal wells
Limitations: cost; collection and disposal of cuttings; gas dissolves in the base fluid, which makes kicks harder to detect; special logging is needed

Type: Synthetic-based (SBM)
Base and composition: synthetic hydrocarbons or esters in place of a petroleum base
Where it is used: the same jobs as OBM, where the rules on toxicity and discharge are stricter
Limitations: the most expensive

Type: Gaseous fluids
Base and composition: air, mist, foam, aerated mud
Where it is used: very strong dry rocks, low-pressure formations, underbalanced drilling (drilling with the pressure in the hole below the pore pressure)
Limitations: the pressure in the hole is low: the walls are hardly supported, formations with normal pressure are not held back; an inflow of water upsets hole cleaning

Type	Base and composition	Where it is used	Limitations
Water-based (WBM)	fresh or sea water, bentonite, polymers, chemicals, weighting material	most wells and intervals	water hydrates clays and dissolves salt; many polymers lose their properties at high temperature
Inhibitive water-based	water with potassium chloride, polymers, glycols, silicates and other inhibitors	active clays, when oil-based muds are undesirable	more expensive than ordinary water-based muds; the inhibition is incomplete
Salt-saturated	saturated $\mathrm{NaCl}$ brine with polymers	drilling rock salt	bentonite does not swell in brine, so salt-resistant polymers and clays are needed; brine increases corrosion
Oil-based (OBM)	diesel fuel or mineral oil with droplets of calcium chloride brine (an invert emulsion), organophilic clay (clay treated so that it mixes with oil), lime, emulsifiers (chemicals that keep the droplets from merging), weighting material	unstable shales, salts, high temperatures, deviated and horizontal wells	cost; collection and disposal of cuttings; gas dissolves in the base fluid, which makes kicks harder to detect; special logging is needed
Synthetic-based (SBM)	synthetic hydrocarbons or esters in place of a petroleum base	the same jobs as OBM, where the rules on toxicity and discharge are stricter	the most expensive
Gaseous fluids	air, mist, foam, aerated mud	very strong dry rocks, low-pressure formations, underbalanced drilling (drilling with the pressure in the hole below the pore pressure)	the pressure in the hole is low: the walls are hardly supported, formations with normal pressure are not held back; an inflow of water upsets hole cleaning

The names and compositions of systems differ between suppliers; the table gives the general classes. Abbreviations: WBM is water-based mud, OBM is oil-based mud, SBM is synthetic-based mud.

Water-based muds are the most common. They are cheaper, they are easier to dispose of, and all logging tools work in them. Their main weakness is shales: shales (clay-rich rocks) are the commonest rocks in the section, and a large share of the problems comes from them. Water from the mud enters the shale, the clay minerals hydrate and swell, the rock loses strength, the walls cave in and washouts form. There are two ways to fight this. One is to suppress (inhibit) hydration: potassium ions reduce the swelling of clays, and polymers coat the particles and the wall. The other is to remove the free water altogether by switching to an oil base (see Water-based muds and clay chemistry).

An oil-based mud contains water too, sometimes up to half of its volume. But the water is broken into tiny droplets surrounded by oil. This is an invert emulsion (“water in oil”). There is no free water that could touch the clays, and the calcium chloride in the droplets is chosen so that water does not pass from the mud into the clay by osmosis (the flow of water towards the saltier side). So the hole is more stable in such muds, the string rubs less against the walls and sticks less often, and the muds keep their properties at temperatures at which many polymers of water-based muds break down. The price of this is the cost, the collection and disposal of cuttings, the solubility of gas in the base fluid (see Well control: primary barrier and kick indicators), and limits on logging. Tools that pass current through the mud do not work in a non-conductive mud (see Oil-based muds).

The type of mud is chosen separately for each interval. We take into account the rocks to be drilled (active clays, salts, lost-circulation zones), the temperature and pressure, the profile of the well (lubrication and carrying out cuttings are especially important in deviated and horizontal holes), the protection of the productive formation, the logging requirements, the environmental limits, logistics and cost. Often several muds are used in one well. The upper intervals are drilled with a cheap water-based mud. Unstable shales and salts are drilled with an inhibitive water-based mud or an oil-based one. The productive formation is drilled into with a special mud that has a minimum of damaging solid particles, for example with calcium carbonate that dissolves in acid.

Terms and symbols

Mud density, $\rho$: The mass of a unit volume of mud. It sets the pressure on the formations. It is measured in g/cm³, kg/m³ or ppg.
Weighting material: A finely ground heavy mineral that raises the density: barite, hematite, calcium carbonate.
Plastic viscosity (PV): The slope of the Bingham line. It grows with the amount of solids.
Yield point (YP): The intercept of the Bingham line on the stress axis. It reflects the attractive forces between particles.
Gel strength: The strength of the gel after rest for 10 s and 10 min.
Fluid loss: The volume of filtrate in 30 min in the standard filter press test.
Mudcake: A layer of solid particles on the wall opposite permeable rocks. A good cake is thin and has low permeability.
WBM, OBM, SBM: Water-based, oil-based and synthetic-based muds.
Invert emulsion: An emulsion of brine droplets in a hydrocarbon liquid. It is the basis of most oil-based muds.
Inhibition: Suppressing the hydration and swelling of clays with chemical additives.

Common mistakes and misconceptions

Wrong

“The higher the viscosity, the better the mud carries cuttings.”

In fact

Carrying capacity depends on the flow velocity in the annulus and the yield point. Extra viscosity raises the ECD, the pump pressure and swabbing, and it makes cleaning the mud harder.

Wrong

“The funnel viscosity is the viscosity of the mud.”

In fact

It is a run-out time, handy for monitoring changes. The flow of the mud is described by PV, YP and gel strength from a rotational viscometer.

Wrong

“We have no barite, so we will weight up with calcium carbonate to any density.”

In fact

For the same density we need about twice as much carbonate by volume, and at a high density the mud becomes too thick. Carbonate is used for a moderate density and when drilling into the productive formation.

Wrong

“An oil-based mud is always better than a water-based one.”

In fact

It solves the problems of shales and lubrication, but it costs more, needs collection and disposal of cuttings, makes gas kicks harder to detect and limits the choice of logging.

Wrong

“A fluid loss of 5 cm³ in 30 min means that 5 cm³ will go into the formation.”

In fact

It is a comparison figure for the mud in a standard static test. In the well, filtration depends on circulation, temperature, pressure difference and time.

Connections to other topics

Pore pressure and overburden pressure — where the hydrostatic constants come from and how the mud density is chosen from the pore pressure.
Well control: primary barrier and kick indicators — mud density as the primary barrier; gas-cut mud and the special features of oil-based muds.
Borehole environment: invaded zone and mudcake — the mudcake and the invaded zone as logging sees them.
How a well is drilled: the process and the people involved — where the mud works in the cycle of building a well.
Field testing of drilling fluids — how the properties of the mud are measured at the rig.
Drilling fluid rheology and flow regimes — flow models of muds and flow regimes.
Water-based muds and clay chemistry — bentonite, polymers and the chemistry of clays.
Oil-based muds — the composition and properties of oil-based muds.
Solids control in drilling fluids — cleaning the mud of drilled solids.
Formation damage and damage skin — how the mud can damage the productive formation.

Check yourself

1
Which property of the mud is first of all responsible for keeping formation fluid out of the well?
1. A.pH
2. B.Plastic viscosity
3. C.Fluid loss
4. D.Density
Show the answer
Correct answer: D. Density
The pressure on the formations is created by the mud column: $p = 0.00981\,\rho\,h$ . The other properties affect the pressure in the well only indirectly, through friction losses during circulation and pressure swings when pipe moves.
2
A mud with a density of 1.35 g/cm³ fills the well up to the wellhead. What is the pressure at a vertical depth of 2800 m, in MPa and in psi?
Show the answer
$p = 0.00981\cdot 1.35\cdot 2800 \approx 37.1$ MPa. In oilfield units: $1.35\cdot 8.345 \approx 11.27$ ppg, $2800/0.3048 \approx 9186$ ft, $p = 0.052\cdot 11.27\cdot 9186 \approx 5380$ psi, which is also about 37.1 MPa.
3
Why is barite the main weighting material, and not ground limestone or marble?
1. A.Barite improves the lubricating properties
2. B.For the same mud density we need much less barite by volume, so there are fewer solids in the mud
3. C.Barite dissolves in acid
4. D.Barite is cheaper
Show the answer
Correct answer: B. For the same mud density we need much less barite by volume, so there are fewer solids in the mud
The density of barite is about 4.2 g/cm³, against 2.7 for calcium carbonate. By the formula $V_{\text{wm}} = V_1(\rho_2 - \rho_1)/(\rho_{\text{wm}} - \rho_2)$ , the heavier the weighting material, the smaller its volume, and every extra share of solids thickens the mud. It is the carbonate that dissolves in acid, which is why it is chosen for drilling into the productive formation.
4
Viscometer readings: $\theta_{600} = 64$ , $\theta_{300} = 40$ . Find the plastic viscosity and the yield point.
Show the answer
$\eta_p = 64 - 40 = 24$ mPa·s; $\tau_0 = 40 - 24 = 16$ lb/100 ft², or about 7.7 Pa. We compare the values with the limits of the programme. A rise of PV at a constant density means that fine drilled solids are building up.
5
Why is a mud with a high fluid loss and a thick cake dangerous when drilling opposite a permeable formation?
Show the answer
A thick cake narrows the hole. The pipe is pressed against it by the pressure difference, and differential sticking occurs. The filtrate and fine particles penetrate deeper into the formation and reduce the permeability of the near-wellbore zone. Overpull and swabbing increase, and cementing gets worse. A good cake is thin and of low permeability.
6
Why is a gas kick harder to notice with an oil-based mud?
1. A.Such a mud is lighter than water, so the pressure at the bottom is lower
2. B.Gas dissolves in the hydrocarbon base fluid: the gain of volume in the tanks is small, and the gas comes out of solution only in the upper part of the hole
3. C.Volume sensors do not work with such a mud
4. D.Gas does not enter a well filled with such a mud
Show the answer
Correct answer: B. Gas dissolves in the hydrocarbon base fluid: the gain of volume in the tanks is small, and the gas comes out of solution only in the upper part of the hole
Gas dissolves well in a petroleum or synthetic base fluid. While the pressure is high, it stays in solution and hardly increases the volume of the mud. It comes out of solution only in the upper part of the hole, quickly and in large amounts. So with such muds the volumes are monitored especially carefully.

Drilling fluids: functions and properties

Quick refresher

After this lesson you can

Why we need a drilling fluid

Density: pressure on the formations

Rheology: how the mud flows and holds cuttings

Filtration and the mudcake

Solids and the chemistry of the mud

Types of drilling mud

Terms and symbols

Common mistakes and misconceptions

In depth: advanced detail

Connections to other topics

Check yourself