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Drilling Fluid Properties - Imposed Pressure, Pressure Imposed By The Formation

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Imposed pressures can also originate from a formation. If formation pressure exceeds hydrostatic pressure, and the well is shut-in, the pressure differential between the hydrostatic of the drilling fluid and the formation pressure, will be imposed throughout the system. This pressure can be read at the surface. At the surface, two different readings will be noted. These will be the drillpipe (pump) pressure and the casing (choke) pressure.

• If no influx of formation fluid occurs, then the hydrostatic pressure in the drill string, and in the annulus, will be the same; resulting in equal drillpipe and casing pressures.

• Usually, any formation fluid influx will have a density less than the drilling fluid, and will only go into the annulus. In this case, the total hydrostatic pressure in the annulus will be less than the hydrostatic pressure in the drill string. Since the formation pressure is constant for the bottom of the hole (both under the drill string and the annulus) the resulting pressures on the drill pipe and casing will differ. The surface drillpipe pressure will be less than the annular pressure since its hydrostatic is greater.

Depending on the situation, one or more of these types of pressures may exist in the well at any given time. If a type of pressure exists in the well bore, it exists everywhere in the system. However, it’s magnitude may vary throughout the system.

Pascal's Law

“The pressure at any point in a static fluid is the same in all directions. Any pressure applied to a fluid is transmitted undiminished throughout the fluid.”

The consequences of this law when applied to drilling practices are important. When a well is shut in during a kick, the pressure is exerted throughout the fluid column. Which means formations uphole experience the same pressures as those downhole.

Drilling Fluid Properties - Imposed Pressure, Pressure Imposed By The Pump

Assume that the well is shut in (annular preventer & choke are closed) and a small amount of mud is pumped into the well using the cementing unit. The pressure will begin to increase immediately. This pressure is an imposed pressure, and is felt uniformly throughout the well bore.

As an example: Pumping is stopped and 900 psi is held on the pump. This pressure (900 psi) is felt inside the BOP stack, inside the drill string, at the bottom of the hole, at the casing shoe, and everywhere else in the circulating system.

Such procedures are usually done after each casing string. It is referred to as testing the casing shoe and is done in order to determine the amount of pressure the formation at the shoe can withstand. Under normal conditions,the formation fracture pressure will increase with depth. This means that formations normally get stronger, and therefore harder to fracture, as depth increases.

Note: Under normal conditions, the weakest point in the annulus will be at the casing shoe.
It is possible to conduct three different types of casing shoe tests:

• Leak-Off Test: Pumping into the shut-in well continues until mud is lost to the formation. It is noted by a non-linear relationship between volume pumped and pressure increase.

• Pressure Integrity Test: Pumping proceeds until a predetermined imposed (pump) pressure is obtained ¾ without any loss of mud into the formation.

• Fracture Test: Pumping proceeds until the formation is fractured. Although this type of test is occasionally done, it is not a normal way of conducting a shoe test.

Drilling Fluid Properties - Imposed Pressure

These are external pressures which are “imposed” into the well. Since the well is open to the atmosphere, the well must be “shut-in” for there to be an imposed pressure. This type of pressure will always be felt uniformly throughout the shut-in well. Imposed pressures originate from:

1. the pumps (i.e. when testing a casing shoe)

2. the formation (i.e. when the well kicks)

Drilling Fluid Properties - Hydraulic Pressure

This is the pressure created (or needed) to move drilling fluid through pipe. In oil field terms, it is the pressure generated by the mud pump in order to move the drilling fluid from the mud pump around the system and back to the flowline. In this section, the terms Pump Pressure and Hydraulic
Pressure will be used interchangeably. This type of pressure can be calculated at any point in the circulating system.
Pressure drop or pressure loss is the amount of pressure needed to move the fluid over a given distance, for example,

the hydraulic pressure (pump pressure) remaining at point B in the figure is 600 psi. However, the system pressure loss at point B is 300 psi. That is, 300 psi is needed to pump the mud from point A to point B.

The hydraulic pressure (pump pressure) remaining at point E in the figure is 225 psi. However, the system pressure loss at point E is 675 psi. That is, 675 psi is required to move the mud from point A to point E. (300 psi from A to B and 375 psi from B to E.)

The total system pressure loss in the drawing (A to F) is 900 psi.

Note: The pressure at any given point in the circulating system is the sum of the hydrostatic, hydraulic, and imposed pressures which exist at that point.

Typically, hydraulic pressures will be calculated in order to:
• Determine the total pressure being exerted at the casing shoe (generally the weakest point in the circulating system); the bottom of the hole; or any other point (such as a lost circulation zone). After
this pressure is determined, it is often converted into a mud density equivalent and reported as the E.C.D. (Equivalent Circulating Density) for that depth.

• Determine the anticipated pump pressure, using:

- mud properties
- drill string configuration
- bit size
- total flow area for the bit
- flow rate

• Determine the nozzle size for a bit, using:

- maximum pump pressure allowed
- mud properties
- drill string configuration
- bit size
- flow rate

Drilling Fluid Properties -Hydrostatic Pressure

Hydrostatic Pressure

As mentioned earlier, this is the pressure created by a column of fluid due to its density and vertical height. This type of pressure always exists and may be calculated whether the fluid is static or flowing. It can be calculated using:

Hp(psi)= MW ´ 0.0519 ´ TVD(ft)

Drilling Fluid Properties- Pressure

Pressure is defined as the force acting on a unit area. In the oil field, pressure is commonly measured in pounds per square inch (psi).

At the wellsite, we are typically concerned with the pressures throughout the circulating system. We may need to know the pressure at a particular point in the wellbore (such as the casing shoe or a lost circulation zone) or we may want to know the total pressure required to pump a certain mud volume at a given rate. Various types of pressures exist due to different mechanisms, and are classified as either hydrostatic, hydraulic, or imposed. All of these pressures result in a force acting on a unit area, even though their origins may differ.

Note: The pressure at any given point in the circulating system is the sum of the hydrostatic, hydraulic, and imposed pressures which exist at that point.

Drilling Fluid Properties

For those working at wellsites, a basic knowledge of “fluid” properties is required, especially those properties that distinguish fluids from solids. Fluids can be either a gas or a liquid, where gases are highly compressible and its volume being dependent upon pressure and temperature. Liquids,
on the other hand, are only slightly compressible, and their volume being only slightly dependent upon temperature.

We shall be dealing with only liquids in this text. Since drilling muds are commonly referred to as drilling fluids, the term “fluid” will be used throughout the text. The effects of temperature and pressure on a volume of drilling fluid will be ignored.

A cube of water measuring 1 foot along each edge weighs 62.4 lbs. The density or “specific weight” is then 62.4 lb/ft3. Specific weight divided by the gravitational constant is known as “mass density” or just density. This same cube of water exerts a hydrostatic pressure of 62.4 lbs distributed evenly over its bottom surface of 1 ft2 or 0.433 psi (62.4lbs ¸ 144 in2).

Hydrostatic pressure of a column of fluid is thus determined by:

Hp = (Dv - Fl) x MD x g
where: Hp = hydrostatic pressure.
Dv = vertical depth.
Fl = flowline depth.
MD = fluid density.
g = gravitational constant.

Note that this is dependent upon vertical depth and fluid density. In oilfield units the fluid density will be the “mud density”, with a conversion factor 0.0519. The conversion factor is derived from:

There are 7.48 gallons in 1 cu/ft and 144 sq inches in 1 sq/ft
because: lb/gal x 7.48 gal/ft3 x 1/144 ft2/in2 = psi/ft
and: 7.48/144 = psi/ft/lb/gal
therefore: 0.0519 = psi/ft/lb/gal

A drilling fluid of 8.34 lb/gal exerts a pressure of;
8.34 x 0.0519 = 0.4328 psi/ft
In SI units the conversion factor is 0.0098, therefore:
Hp (kPa) = MD (kg/m3) x Dv(m) x 0.0098

Oil-Based Drilling Fluids

These fluids, because of their special nature of being a mixture of two immiscible liquids (oil and water), require special treatments and testing procedures.

Dispersed Phase: The liquid present in the form of finely divided droplets.

Continuous Phase: The liquid present in the form of the matrix in which the droplets are suspended.
To keep these liquids stabilized (i.e. to keep the dispersed phase from coalescing and settling out of the mixture), an emulsifier is added to form an interfacial film around the dispersed phase which causes them to repel each other, so they remain dispersed.
The effectiveness of an emulsifier depends on the alkalinity and electrolytes (chloride content) of the water phase, and the temperature of the drilling fluid.

Electrical Stability

The electrical stability (E.S.) of an oil-based drilling fluid is the stability of the emulsions of water in oil, or the amount of current required to break the emulsifier down and allow the saline water to coalesce.

1. An electrical probe is inserted into the drilling fluid and the voltage increased until the emulsion breaks down

a. the measure of emulsion breakdown is indicated by current flow
b. relative stability is recorded as the amount of voltage at the breakdown point

2. E.S. is recorded as the voltage reading and temperature of the drilling fluid sample

a. adding emulsifier will raise the E.S. readings
b. normal “fresh” mud is about 300 or higher
c. during drilling, the E.S. can increase to 800 or higher

Oil: Water Ratio

The Oil: Water Ratio is defined as the percent oil in the liquid phase and the percent water in the liquid phase. The percentages can be determined from a retort analysis of the drilling fluid.

Aniline Point

Another common term used when dealing with oil-based drilling fluids is the aniline point of that fluid. The aniline point is the temperature below which an oil containing 50% by volume aniline (C6H5-NH2) becomes cloudy. The solvent powers for rubber are related to the solvent power for aniline. Oils having an aniline point above 140oF are considered acceptable to use.

Material Balance Equations

Material balance equations are used for calculating volumes and densities when two or more insoluble materials are mixed together.

The Material Balance Equation is:

V1W1 + V2W2 ..... = VFWF where: V1 + V2 ..... = VF

where: V1 = Volume of first material to be mixed together

W1 = Density of first material
V2 = Volume of second material to be mixed together
W2 = Density of second material
VF = Total or sum of all volumes mixed together
WF = Density of total mixture. Proportional average of all volumes mixed together
The most commonly used variables in material balance equations are:

Barite

1. Weight of a barrel of barite (BaSO4) s.g. = 4.2 g/cc
42 gal/bbl x 8.33 lb/gal x 4.2 = 1470 lb/bbl

* since barite comes in 100 lb sacks, one barrel contains 14.70

sacks

2. Weight of a gallon of barite
8.33 lb/gal x 4.2 = 34.9 lb/gal

Hematite

1. Weight of a barrel of hematite (Fe2O3) s.g. = 5.0 g/cc
42 gal/bbl x 8.33 lb/gal x 5.0 = 1749 lb/bbl
2. Weight of a gallon of hematite
8.33 lb/gal x 5.0 = 41.65 lb/gal

Light Oil

1. Example - (41° API Gravity) s.g. = 0.82 g/cc
2. Weight of a gallon of oil
8.33 lb/gal x 0.82 = 6.8 lb/gal

Example Problem #1-1:

Calculate how many sacks of barite are required to increase the density of an 800 barrel mud system from 12.7 lb/gal to 14.5 lb/gal.

Using: V1W1 + V2W2 = VFWF

where: V1 = 800 bbls
W1 = 12.7 lb/gal
V2 = unknown volume of barite
W2 = 34.9 lb/gal (density of barite)
VF = V1 + V2 (or 800 + V2 )
WF = 14.5 lb/gal

therefore: 800(12.7) + V2(34.9) = (800 + V2) x 14.5

10,160 + 34.9V2 = 11,600 + 14.5V2
20.4V2 = 1440
V2 = 70.6 bbls of barite
70.6 bbls x 14.7 sk/bbl = 1038 sacks of barite

Example Problem #1-2:

Calculate how much water and barite are required to make 800 barrels of a 10.5 lb/gal water-based drilling mud.

Using: V1W1 + V2W2 = VFWF

where: V1 = unknown volume of water

W1 = 8.33 lb/gal
V2 = unknown volume of barite or (800 - V1)
W2 = 34.9 lb/gal
VF = 800 bbls
WF = 10.5 lb/gal

therefore: V1(8.33) + (800 - V1)34.9 = 800(10.5)

8.33V1 + 27920 - 34.9V1 = 8400
-26.57V1 = -19520
V1 = 735 bbls of water
V2 = 800 bbls - 735 bbls = 65 bbls of barite @ 14.7 sk/bbl or 956 sacks

Drilling Fluid Additives

Many substances, both reactive and inert, are added to drilling fluids to perform specialized functions. The most common functions are:

Alkalinity and pH Control

Designed to control the degree of acidity or alkalinity of the drilling fluid.
Most common are lime, caustic soda and bicarbonate of soda.

Bactericides

Used to reduce the bacteria count. Paraformaldehyde, caustic soda, lime and starch preservatives are the most common.

Calcium Reducers

These are used to prevent, reduce and overcome the contamination effects of calcium sulfates (anhydrite and gypsum). The most common are caustic soda, soda ash, bicarbonate of soda and certain polyphosphates.

Corrosion Inhibitors

Used to control the effects of oxygen and hydrogen sulfide corrosion. Hydrated lime and amine salts are often added to check this type of corrosion. Oil-based muds have excellent corrosion inhibition properties.

Defoamers

These are used to reduce the foaming action in salt and saturated saltwater mud systems, by reducing the surface tension.

Emulsifiers

Added to a mud system to create a homogeneous mixture of two liquids (oil and water). The most common are modified lignosulfonates, fatty acids and amine derivatives.

Filtrate Reducers

These are used to reduce the amount of water lost to the formations. The most common are bentonite clays, CMC (sodium carboxymethylcellulose) and pre-gelatinized starch.

Flocculants

These are used to cause the colloidal particles in suspension to form into bunches, causing solids to settle out. The most common are salt, hydrated lime, gypsum and sodium tetraphosphates.
Foaming Agents Most commonly used in air drilling operations. They act as surfactants, to foam in the presence of water.

Lost Circulation Materials

These inert solids are used to plug large openings in the formations, to prevent the loss of whole drilling fluid. Nut plug (nut shells), and mica flakes are commonly used.

Lubricants

These are used to reduce torque at the bit by reducing the coefficient of friction. Certain oils and soaps are commonly used.

Pipe-Freeing Agents

Used as spotting fluids in areas of stuck pipe to reduce friction, increase lubricity and inhibit formation hydration. Commonly used are oils, detergents, surfactants and soaps.

Shale-Control Inhibitors

These are used to control the hydration, caving and disintegration of clay shale formations. Commonly used are gypsum, sodium silicate and calcium lignosulfonates.

Surfactants

These are used to reduce the interfacial tension between contacting surfaces (oil/water, water/solids, water/air, etc.).

Weighting Agents

Used to provide a weighted fluid higher than the fluids specific gravity. Materials are barite, hematite, calcium carbonate and galena.

Drilling Fluid Classification Systems

Non-Dispersed System

This mud system consists of spud muds, “natural” muds, and other lightly treated systems. Generally used in the shallower portions of a well.

Dispersed Mud Systems

These mud systems are “dispersed” with deflocculants and filtrate reducers. Normally used on deeper wells or where problems with viscosity occur. The main dispersed mud is a “lignosulfonate” system, though other products are used. Lignite and other chemicals are added to maintain specific mud properties.

Calcium-Treated Mud Systems

This mud system uses calcium and magnesium to inhibit the hydration of formation clays/shales. Hydrated lime, gypsum and calcium chloride are the main components of this type of system.

Polymer Mud Systems

Polymers are long-chained, high molecular-weight compounds, which are used to increase the viscosity, flocculate clays, reduce filtrate and stabilize the borehole. Bio-polymers and cross-linked polymers, which have good shear-thinning properties, are also used.

Low Solids Mud System

This type of mud system controls the solids content and type. Total solids should not be higher than 6% to 10%. Clay content should not be greater than 3%. Drilled solids to bentonite ratio should be less than 2:1.

Saturated Salt Mud Systems

A saturated salt system will have a chloride content of 189,000 ppm. In saltwater systems, the chloride content can range from 6,000 to 189,000 ppm. Those at the lower end are normally called “seawater” systems.These muds can be prepared with fresh or salt water, then sodium chloride
or other salts (potassium, etc.) are added. Attapulgite clay, CMC or starch is added to maintain viscosity.

Oil-Based Mud Systems

There are two types of systems: 1) invert emulsion, where water is the dispersed phase and oil the continuous phase (water-in-oil mud), and 2) emulsion muds, where oil is the dispersed phase and water is the continuous phase (oil-in-water mud). Emulsifiers are added to control the rheological properties (water increases viscosity, oil decreases viscosity).

Air, Mist, Foam-Based Mud Systems

These “lower than hydrostatic pressure” systems are of four types: 1) dry air or gas is injected into the borehole to remove cuttings and can be used until appreciable amounts of water are encountered, 2) mist drilling is then used, which involves injecting a foaming agent into the air stream, 3) foam drilling is used when large amounts of water is encountered, which uses chemical detergents and polymers to form the foam, and 4) aerated fluids is a mud system injected with air to reduce the hydrostatic pressure.

Workover Mud Systems

Also called completion fluids, these are specialized systems designed to 1) minimize formation damage, 2) be compatible with acidizing and fracturing fluids, and 3) reduce clay/shale hydration. They are usually highly treated brines and blended salt fluids.

Special Drilling Fluids

These drilling fluids are made to combat particular abnormal hole conditions or to accomplish specific objectives. These are:

1. Special Objectives

(a) faster penetration rates
(b) greater protection to producing zones

2. Abnormal Hole Conditions

(a) long salt sections
(b) high formation pressures

Lime Base Muds

1. Water base mud
2. Treated with large amounts of caustic soda, quebracho, and lime. Added in that order
3. Ratio of 2 lb caustic soda, 1.5 lb quebracho and 5 lb lime per 1 barrel of mud
4. Will go through a highly viscous stage, but will become stable at a low viscosity
5. Good points

(a) can tolerate large amounts of contaminating salts
(b) remains fluid when solids content gets high

6. Weakness - it has a tendency to solidify when subjected to high bottom-hole temperatures

Lime-Treated Muds

1. Similar to lime based mud - differ only in degree
2. A compromise attempt at overcoming the high temperature gelation problem

(a) use less lime than lime-base mud
(b) not nearly so resistant to salt contamination

Emulsion Muds - Oil in Water

1. Oil can be added to any of the normal or special muds with good results
2. No special properties necessary
3. Natural or special emulsifying agents hold oil in tight suspension after mixing
4. Oils used are:

(a) Crude oils
(b) Diesel
(c) any oil with an API gravity between 25 and 50

5. Oil content in mud may be 1% to 40%

6. Advantages are:

(a) very stable properties
(b) easily maintained
(c) low filtration and thin filter cake
(d) faster penetration rates
(e) reduces down-hole friction

7. Major objection is that the oil in the mud may mask any oil from the formations
Inhibited Muds

1. Muds with inhibited filtrates
2. Large amounts of dissolved salts added to the mud
3. High pH usually necessary for best results
4. Designed to reduce the amount of formation swelling caused by filtrate - inhibit clay hydration
5. Disadvantages

(a) need specialized electric logs
(b) requires much special attention
(c) low mud weights cannot be maintained without oil
(d) hard to increase viscosity
(e) salt destroys natural filter cake building properties of clays

Gypsum Base Muds

1. A specialized inhibited mud

(a) contained large amounts of calcium sulfate
(b) add 2 lb/bbl gypsum to mud system
(c) filtration controlled by organic colloids

2. Advantages

(a) mud is stable
(b) economical to maintain
(c) filtrate does not hydrate clays
(d) high gel strength

3. Disadvantages

(a) fine abrasives remain in mud
(b) retains gas in mud

Oil Based Muds

1. Oil instead of water used as the dispersant
2. Additives must be oil soluble
3. Generally pre-mixed and taken to the wellsite
4. To increase aniline value, blown asphalt and unslaked lime may be added
5. Advantages

(a) will not hydrate clays
(b) good lubricating properties
(c) normally higher drill rates

6. Disadvantages

(a) expensive
(b) dirty to work with
(c) requires special electric logs
(d) viscosity varies with temperature

Inverted Emulsions

1. Water in oil emulsion. Oil largest component, then water added. Order of addition is important
2. Have some of the advantages of oil muds, but cheaper. Somewhat less stable

Salt Water Muds

1. Can be used either completely or partly saturated
2. Weight can vary up to 10 lb/gal when saturated
3. No filter cake building properties, easily lost to porous formations

Silicate Muds

1. Composed of sodium silicate and saturated salt water
2. Has a pickling effect on shales which prevents heaving or sloughing
3. Will be 12 lb/gal or higher
4. Corrosive, expensive and gives poor electric log results

Low Solids Muds

1. Keeps amounts of clays in the mud at a minimum, which promotes faster and safer drilling
2. Three ways to remove solids from mud

(a) water dilution
(b) centrifuging
(c) circulate through large surface area pits

3. When clays are removed, a minimum of viscosity control chemicals are needed
4. When viscosity and gel strength become too low, clay solids are replaced by organic or suspended material - polymers

5. Other advantages

(a) good for drilling with large pumps and high mud volumes
(b) always give faster drilling

6. Problems

(a) excessive dilution a problem
(b) can become expensive

Normal Drilling Fluids

Though this type of drilling fluid is easy to describe, it is hard to define and even more difficult to find. In the field, a normal fluid generally means there is little effort expended to control the range of properties. As such, it is simple to make and control.
General rules include:

1. It is used where no unexpected conditions occur
2. The mud will stabilize, so its properties are in the range required to control hole conditions
3. The chief problem is viscosity control

Formations usually drilled with this type of mud are shales and sands. Since viscosity is the major problem, the amount and condition of the colloidal clay is important. To do this, two general types of treatment are used:

1. Water soluble polyphosphates

(a) they reduce viscosity
(b) can be used alone or with tannins
(c) if filter cake and filtration control is required

- add colloidal clay to system

2. Caustic Soda and Tannins

(a) they also reduce viscosity
(b) used under more severe conditions than phosphate treatment

The upper portions of most wells can use “normal” muds

1. Care must be taken not to add chemicals which may hinder the making of special muds later on

2. Native clays used to make the mud are usually adequate

Make-up of a Drilling Fluid

In its most basic form a drilling fluid is composed of a liquid (either water or oil) and some sort of viscosifying agent. If nothing else is added, whenever the hydrostatic pressure is greater than the formation pore pressure (and the formation is porous and permeable) a portion of the fluid will be flushed into the formation. Since excessive filtrate can cause borehole problems, some sort of filtration control additive is generally added. In order to provide enough hydrostatic pressure to balance abnormal pore pressures, the density of the drilling fluid is increased by adding a
weight material (generally barite).

In summary, a drilling fluid consists of:

The Base Liquid

• Water - fresh or saline
• Oil - diesel or crude
• Mineral Oil or other synthetic fluids

Dispersed Solids

• Colloidal particles, which are suspended particles of various sizes

Dissolved Solids

• Usually salts, and their effects on colloids most is important
All drilling fluids have essentially the same properties, only the magnitude varies. These properties include density, viscosity, gel strength, filter cake,water loss, and electrical resistance.

Drilling Fluids

A drilling fluid is any fluid which is circulated through a well in order to remove cuttings from a wellbore. This section will discuss fluids which have water or oil as their continuous phase. Air, mist and foam, which can be used as drilling fluids, will not be discussed at this time.
A drilling fluid must fulfill many functions in order for a well to be drilled successfully, safely, and economically. The most important functions are:

1. Remove drilled cuttings from under the bit
2. Carry those cuttings out of the hole
3. Suspend cuttings in the fluid when circulation is stopped
4. Release cuttings when processed by surface equipment
5. Allow cuttings to settle out at the surface
6. Provide enough hydrostatic pressure to balance formation pore pressures
7. Prevent the bore hole from collapsing or caving in
8. Protect producing formations from damage which could impair production
9. Clean, cool, and lubricate the drill bit

Occasionally, these functions require the drilling fluid to act in conflicting ways. It can be seen that items #1-3 are best served if the drilling fluid has a high viscosity, whereas items #4-5 are best accomplished with a low viscosity. Items #6 & 8 are often mutually exclusive because drilled solids will tend to pack into the pore spaces of a producing formation.

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