"

m m

ROTARY DRILLING SERIES

Unit I: The Rig and Its Maintenance
L esson. 1: The Rotary Rig and Its Components
Lesson 2: The'Bit
Lesson 3: The Drill Stem
Lesson 4: Rotary, Kelly, and Swivel
Lesson : The Blocks and Drilling Line
Lesson 6 : The Hoist
Lesson 7: Pow er and ?ow er Transmission
Lesson 8 : Cireulating Systems
Lesson 9: The Auxiliaries
Lesson 10: Safety on the Rig
Lesson 11: Diesel Engines and Electric Power
Lesson 12: Mud Pumps and Conditioning Equipment
Unit II: Normal Drilling Operations
Lesson
Lesson
Lesson
Lesson
Lesson

1:
2:
3:
4:
5:

Making Hole
Drilling Mud
Drilling a Straight Hole
Casing and Cementing
Testing and Completing

Unit III: Nonroutine Rig Operations

Lesson
Lesson
Lesson
Lesson

1:
2:
3:
4:

Controlled Directional Drilling

Open-Hole Fishing
Blowout Prevention
Subsea Blowout Preventers and Marine Riser Systems

Unit V: Offshore Technology

Lesson
Lesson
Lesson
Lesson
Lesson
Lesson
Lesson
Lesson
Lesson

1:
2:
3:
4:
5:
6:
7:
8:
9:

Wind', Waves, and W eather

Spread Mooring Systems
Buoyancy, stability, and Trim
Jacking Systems and Rig Moving Procedures
Diving and Equipment
Vessel M aintenance and Inspection
Helicopter Safety and Survival Procedures
Orientation for Offshore Crane Operation
Life Offshore

Unit IV, Man Management and Rig Management is published by Continuing

Engineering Education, University of Oklahoma, and is available from IADC,
P.O. Box 4287, Houston, Texas 7721.

ROTAR DRILLING

CIRCULATING
SYSTEMS
Unit / Lesson 8
Third Edition

Edited by Jodie Leecraft

Published by
S E i PETROLEUM EXTENSION SERVICE
Division of Continuing Education
The University of Texas a t Austin
Austin, Texas
in cooperation with

O p

INTERNATIONAL ASSOCIATION
OF DRILLING CONTRACTORS
Houston, Texas
1981

 1981 by The University of Texas at Austin

All r^ h ts reserved
First Edition published 1968. Second Edition published 1976
Third Edition 1981
Frinted in the United States of America
This bool or parts thereof may not be reproduced in any
form without permission of the Fetroleum Extension Service, The University of Texas at Austin.
Brand names, company names, trademarks, or other dentifying symbols appearing in illustrations and/or text are used
for educational purposes only and do not constitute an endorsement by the author or publisher.

CONTENTS
In tro d u c tio n ...................................................................................................................1
Historical B ackground..................................................................................................2
F u ^ tio n s of Drilling F lu id s ......................................................................................... 3
Transporting Cuttings to the S u r fa c e ....................................................................3
Cleaning the Bottom of the H o l e ............................................................................ 3
Cooling the Bit and Lubricating the Drill s te m ..................................................... 4
S p i r t i n g the Walls of the W e ll............................................................................ 5
Preventing E n try of Formation Fluids into the W e ll.......................................... 7
Composition of Drilling M u d ....................................................................................... 8
W ater-base M uds........................................................................................................ 8
Oil M u d s.......................................................................................................................9
Testing of Drilling Mud ............................................................................................... 9
Density or W eight T e s t........................................................................................... 10
Viscosity and Gel Strength T e s te .......................................................................... 10
Filtration and Wall-building T e s ts ........................................................................ 11
Sand Content D eterm ination.................................................................................11
Solid, Liquid, and Oil Content D eterm ination..................................................... 11
Determination of pH . . . . . . . . . . . . . . . .
Other Tests ...............................................
Treatm ent of Drilling Mud . . . . . . . . . . . . .
Breakover .................................................
Weight-up .................................................
W ater-back ...............................................
T hinning.....................................................
Adding O i l .................................................
Chemical T re a tin g ....................................
Safe Handling of Mud and Mud Chemicals
Mud Circulating S y ste m s...........................................................................................18
Route of C irculation................................................................................................. 18
Mud P i t s .....................................................................................................................19
Mud P u m p s .............................................................................................................. 23
Standpipe and Rotary H o s e ...................................................................................26
Mud Return L in e ......................................................................................................30
Storage and Mixing Facilities.................................................................................30
H ^ r u l i c ^ Mud C ircu latio n .............................................................................. 3-1

Air Circulating Systems . . . . . . . . . . . .

Rig Equipm ent....................................
Use of F o a m ........................................
Use of Aerated Mud . . . . . . . . . . . . .
W o ^ o v ^ i r c ^ a t i n g Systems . . . . . .
Circulating Fluid . . . . . . . . . . . . . . . .
Route of Circulation and Equipment

FOREWORD

The first edition of Circulating System s was printed in 1968, and a revised edition became available in 1975. Each edition has been directed to the new crew
member, aiming to enhance the quality of his knowledge about the equipment he
will operate.
The circulating system of a drilling rig rivals the drill stem and most of the
other collections of rig components in importance. The system takes on
significance partly because of the large variety of pieces in its total makeup, each
piece needing continued and careful attention. The new crew member who
studies this manual with some diligence and works under proper guidance of
seasoned crew members is sure to be rewarded. Not only will he have firsthand
knowledge gained from his work; he will also have a good understanding of the
basic concepts th at go into the design of the equipment and the arithm etic that
accompanies some of its functions.
Despite the best efforts of w riters, editors, typesetters, and proofreaders, it is
difficult to produce a publication without errors. The Petroleum Extension Service will be most grateful to those readers who will call attention to errors found
in this publication. Systematic and conscientious effort is made to correct errors
before each printing of a manual.
Bruce R. Whalen
Publications Coordinator

ACKNOWLEDGMENTS

Preparation of this manual was greatly aided by Dan Fox of Magcobar I)vsion, D resser Industries, Inc., who reviewed the m anuscript and offered helpful
suggestions for content improvement. Frank P. H errin provided information
concerning rotary hose construction, and Fann Instrum ent Operations, Dresser
Industries, Inc., provided photographs of mud-testing equipment. The American
Petroleum Institute graciously granted permission for use of m aterial from A P I
Specification fo r Rotary D rilling Equipment, Thirty-Second Edition, May 1979.
On the PETEX staff, Ron Baker provided helpful content
"
Charles Kirkley gathered new material, and Donna Hankey designed the cover.
Jodie Leecraft
Editor

Introduction
Rotary drilling has two im portant features:
(1) the drill stem is rotated to turn the bit, and
(2) some type of drilling fluid is c irc u la ted -th at
is, pumped down the drill stem, out through the
bit, and back up through the hole to the surface.
The drilling fluid may be either liquid or gaseous. A liquid, such as w ater, is a fluid th at cannot be compressed. A gas, such as air or natural
gas, is a fluid th a t can be compressed.
The main purposes of circulation are t o 1 . transport bit cuttings to the surface;
2 . clean the bottom of the hole;
3. cool and lubricate the bit and drill stem;
4. support the walls of the wellbore; and
5. prevent entry of formation fluids into the
well.
Other purposes of circulation are to make it
possible to detect gas, oil, or w ater th at may
enter the drilling fluid from a form ation being
drilled; to get information necessary for
evaluating producing zones (from cuttings,
cores, or electric logs); and to transm it hydraulic
power to the bit. In addition, drilling fluid is
sometimes used to drive a turbodrill or downhole motor th at has been placed a t the bottom of
the drill stem. In this case, the drilling fluid provides power to the m otor so th at the bit turns
without engaging the rotary table. Compressed
air, the circulating fluid for air drilling, can also
be used to power a hamm er drill, a downhole
device th a t combines rotary motion with a
pounding action.
The circulating fluid may be w ater, mud, oil,
air, gas, or a m ixture of these. W ater is the liquid most commonly used. While it may be either

fresh or salt w ater, fresh w ater is favored for

making water-base mud.
More than 98 percent of all wells drilled by the
rotary method employ w ater alone or waterbase mud as the circulating fluid, ^''ater-base
mud may contain from 5 to 10 percent oil,
dissolved chemicals, clay particles, and other
finely ground solids in addition to the w ater.O il
mud, usually containing from 2 to 15 percent
w ater as emulsified droplets, is a specialpurpose fluid th at is more expensive to prepare
than water-base mud and is less commonly used.
Air or gas is used in less than 1 percent of wells
drilled. Foam or aerated mud may be used in
remedial work or special situations.
A circulating system for drilling fluid includes
the following main equipment: ( 1) mud pumps,
(2) rotary hose, (3) swivel, (4) drill stem, (5) bit,
(6) mud return line, and (7) mud pits. In a circulating system using air or gas, compressors
m ust be added, and the gas lines m ust be connected to the regular equipment. Usually a well
is started with w ater or mud as the circulating
medium, and a string of casing is set before drilling begins with air or gas. The air or gas is injected a t the standpipe, going through the
swivel, drill stem, and bit and flowing back to
the surface. A t the surface it is turned to waste
through a line leading fi-o^n the wellhead.
Attending to the circulating fluid and the
equipment of a circulating system makes up a
large p art of the daily work on a drilling rig, and
the new crew member is expected to assist in
the tasks involved.

Historical Background
Spindletop, toe gusher brought in near Beaumont, Texas, in 1901, is sometimes considered
to be toe first well to use toe rotary drilling
method. Actually, it merely confirmed the value
of a method th at had been used extensively in
the area for five years.
The men who worked a t Spindletop had had
previous rotary experience and understood the
use of mud circulation for drilling toe type of
soft formations th at are prone to caving. The
Lucas well probably produced most of toe mud
needed to protect the h o le -th a t is, toe natural
clay form ations encountered in toe well provided a passable drilling fluid when mixed wth
water. One legend is th at mud was obtained by
driving cattle back and forth through a pit dug
out of toe ground and filled with w ater. It is
quite probable th at the mud used on toe well was
mixed in a pit nearby.
Circulating equipment for rotary drilling has
improved over toe years, but toe system of circulation rem ains essentially toe same. Mud
pumps have changed from small steam-powered
pumps for fluid pressures of 1,000 psi (pounds
per square inch) in 1916 (fig. 1) to present-day

F ig u re

2.

M o d e rn m ud pum ps

F ig u re

E a r l y m ud pum p

pumps powered by internal-combustion engines

or electric motors for fluid pressures of
1,500-3,500 psi (fg. 2). Drilling bits have
changed from early fishtail types to modern jet
bits requiring high-pressure circulation.
Circulating fluid has changed, too. Drilling
mud has received progressively more attention
since the 1920s until today when supplying mud
m aterials is a large industry. Mud companies
maintain warehouse stocks near toe principal oil
fie ld s a n d em p lo y tr a i n e d m e n - m u d
e n g in e e rs-to test toe mud on those jobs on
which their Material is used. Air drilling was
started in toe early 1950s and gave promise of
'
real improvement in penetration

rates, although problems with w ater seepage into the hole still make liquid circulation the usual
method of choice.
In some ways, things have not changed much
since Spindletop. The rig crew members are still
expected to do the hard work of mixing mud, the
derrickman m ust still know the basic mud tests
and general principles of treating mud, and
various people m ust still share in the responsibility of keeping pumps and other circulating
equipment in efficient working condition.

Functions of
Drilling Fluids
Fluid in the circulating system of a rotary rig
acts to transport bit cuttings to the surface,
clean the bottom of the hole, cool the bit and
lubricate the drill stem, support the walls of toe
wellbore, and prevent entry of form ation fluids
into toe well.

Transporting Cuttings
to the Surface
Liquid, air, or gas in circulation moves rock
chips, sand, or shale particles out of a well as it
moves up toe annulus. For a liquid, the annular
velocity, or speed, is usually from 100 to 200 feet
per minute (ft/mn) in order to keep toe hole
clean. Circulation of 3,000 ft/min is considered
ample velocity in toe annulus for cleaning with
gas or air. The solids in mud are separated a t toe
surface by screening, settling, centrifugal action, chemical flocculation, or a combination of
methods. Solids brought up by air or gas in air
drilling are blown as dust or fine chips to a
waste pit.
The viscosity of a drilling mud is its resistance
to flow. On the rig, a Marsh funnel (fig. 3) is
generally used to measure apparent viscosity.
The timed rate of flow obtained usually correlates with true viscosity. Funnel viscosity may
be from 30 to 40 seconds per quart (s/qt) for lowsolids muds, from 40 to 50 s/qt for high-solids

F ig u r e 3 . M
N EL

e a s u r in g

m u d v is c o s it y w it h a

arsh fu n-

muds, and above 50 s/qt for heavier-density

muds. Regardless of whether or not the mud is
weighted, very high viscosities are often needed
to clean the hole adequately.
Mud m ust have the proper viscosity and gel
strength to lift cuttings and to keep them in
suspension both during circulation and during
the time circulation is stopped. Gel strength is
the ability of a mud to keep cuttings from slowly
settling when the mud is not in motion. It can be
observed from the way the mud flows and stffens in ditches and pits. When circulation is
begun again after having been stopped, the mud
should again liquefy.

Cleaning the
Bottom of the Hole
A bit m ust have a clean surface on which to
work when making hole, w hether it is crushing
or shearing the formation. If chips or cuttings
are not swept away as they are formed, the bit
bogs down, and eventually the drill stem cannot
be turned. For the bit to regrind the chips

already broken off from the bottom of the hole is

effort wasted, reducing the power available for
making hole. The usual method for cleaning the
hole is by circulation of fluid through je t nozzles
in the bit. High-velocity stream s of fluid blast
the bottom of the hole, creating a turbulence
th at moves the chips from the face of the formation as fast as they are formed (fig. 4). In drilling with air or gas, the pressure and volume
applied to bring the cuttings to the surface are
normally more than enough to clean the bottom.
At the surface, the cuttings m ust be separated
and removed so th at the fluid pumped back to
the bit is clean. In addition, the system should be
so designed th a t a large volume of liquid under
high pressure can reach the bit. The proper combination of pump, drill stem, nozzles, and hole
diam eter makes it possible for 50 to 60 percent
of the fluid pressure generated by the pump to
reach the bit nozzles and clean the bottom of the
hole.

ig u r e

4 . C l e a n in g

the

bottom of th e

hole

Cooling the Bit and

Lubricating the Drill stem
The bit is forced against the bottoni of the hole
quite heavily. For example, weight on an
8 */2-inch bit sometimes exceeds 60,000 pounds,
about the weight of a railroad freight car; a
large-diam eter bit may require double th at
amount. The bit !^^ be rotated at a speed of 50
to 100 revolutions per minute (rpm). This combination of weight and speed creates heat due to
friction in the bit bearings and abrasion of the
formation against the teeth or blades. Unless a
bit is well cooled, it overheats and quickly wears
out. Fluid circulated around the parts of the bit
removes the heat (figs. 5 and 6). Oily substances
in the drilling fluid can reduce friction in the bit
bearings and act as a lubricant between the drill
stem and the walls of the hole. Oil-emulsion
muds and oil muds are especially helpful in this
way. Air or gas circulation is very efficient for
cooling because the air or gas expands as it
leaves the bit nozzles and produces a cooling effeet. For this reason, and because air contains

F i g u r e 5. W a t e r c o u r s e s i n a r o l l e r c o n e b i t

F ig u r e 7. H
OF TH E HOLE

ig u r e

6. J

et

IN A ROLLER CONE B IT

no significant foreign material, wear on the bit

bearings is much less with this method than with
mud circulation.

y d r o s t a t ic p r e s s u r e

on s id e s

Hydrostatic pressure is the force exerted on

adjacent bodies by a liquid th a t is standing still.
In a well, the hydrostatic pressure of the drilling
fluid (liquid) is determined by the unit weight or
density of the fluid and the height of the fluid
column. An increase in the hydrostatic pressure
a t any depth can be obtained by increasing the
density of the fluid, usually accomplished with
mud by adding barite. Barite is a mineral that is
4.2 times as dense as water.
The weight of drilling mud is m easured by
means of a mud balance (fig. 8). Mud weight is

Supporting the Walis of the Well

A drilling fluid with the proper characteristics
can support a form ation th a t might otherwise
cave into a well. This type of drilling fluid, or
mud, plasters the wall. of a well like m ortar.
Futherm ore, the hydrostatic pressure created
by the weight of the fluid column in the hole
pushes against the plastered wall to support unconsolidated or loose formations th at might fall
or slough into the well (fig. 7). H ard rock formations have little tendency to slough and can
therefore be drilled with air, gas, or w ater instead of mud.

AND BOTTOM

ig u r e

8. M

e a s u r in g

m u d w e ig h t

commonly expressed in term s of pounds per

gallon (ppg) or pounds per cubic foot (pcf or
lb/ft3). Table 1 compares the different ways of
reporting mud weight and hydrostatic head
TAKLE 1
C o m p a r is o n o p U n it s U s e d t o R e p o r t
M u d W e i g h t , S p e c if ic G r a v it y , a n d
F

ressu re

filtrate) into the permeable zones (sueh as sand),

and the solid m aterial is left behind as a filter
cake (fig. 9). This filtration slows to a very low

r a d ie n t

Lb/ft3

Specific
Gravity

Pressure Head
per 1,000 ft
of Depth (psi)

7.5
8.0

56.0
59.8

. 0
0.96

390
416

9.5
10.0
10.5

71.1
75.0
78.5

1.14
1.20
1.26

494
520
546

11.0

82.5

1.32

572

12.0
12.5

90.0
93.6

1.44
1.50

624
650

13.0
13.5
14.0
14.5

97.5
101.0
105.0
108.5

1.56
1.62
1.68
1.74

676
702
728
754

15.0
15.5
16.0

112.3
115.9
120.0

1.80
1.86
1.92

780
806
832

17.0
17.5
18.0

127.5
130.9
135.0

2.04
2.10
2.16

884
910
935

19.0
19.5
20.0

142.1
145.8
149.6

2.28
2.34
2.39

987
1,013
1,035

MUD.Fli.TRA
TH IC K MUD CAKE

ig u r e

9. F

il t e r c a k e

rate when a good filter cake has been formed on

the walls of a well. A good filter cake is thin,
slick, and impermeable. Finely ground clays or
other substances are added to drilling mud to
improve its wall-building quality, its ability to
form a filter cake. M easurement by means of a
filter press (fig. 10) of the amount of filtrate th at

COURTESY

OF DRESSER

IN D U S T R IE S

(pressure). A 10-ppg mud exerts about 0.5 psi

per foot of depth. Hydrostatic pressure can be
calculated by using one of the following equations:
1. h y d r o s ta tic p r e s s u r e (psi) = d e p th
(ft) X mud weight (ppg) X 0.052, or
2. h y d r o s ta tic p r e s s u r e (psi) = d e p th
(ft) X mud weight (pcf) X 0.00695.
F ilter cake, the plasterlike coating formed
from mud on the walls of a well, has the ability
to seal the wellbore and prevent the loss of
whole fluid. The force of the hydrostatic pressure squeezes the liquid p a rt of the mud (the

T H IN MUD CAKE

ig u r e

. F

il t e r p r e s s

passes through a filter paper a t 100 psi helps indicate the wall-building quality of th at mud.
Certain difficulties may arise if the fluid loss
of a mud becomes excessive. First, the filter
cake may become thick enough to reduce the
diam eter of the hole, causing tight places in the
hole th a t may stick the drill stem. Second, muds
with a high fluid loss may in some instances
cause sloughing and caving of shale formation.
Third, filtrate entering the productive zones
may reduce the rate of oil flow after completion.

...i

Preventing Entry of
Formation Fiuids into the Well
The pressures of gas, oil, or w ater in formations penetrated by the bit may exceed the
hydrostatic pressure of the fluid column in a
well. If this happens, form ation fluid will enter
the well (a kick). To kill a kick, the blowout
preventers (BOFs) are closed to hold backpressure on the column a t the surface. Then
heavier mud is circulated in order to obtain
enough pressure a t the bottom of the hole to
overcome the form ation pressure.
W ater or mud produces sufficient hydrostatic
head to overcome form ation pressures usually
encountered. The addition of weighting m aterial
to mud being circulated in a well can make a
mud dense enough to hold back almost any formation pressure. When form ation pressures are
expected to be high, a high mud weight is needed, so the pits and other equipment should be arranged to handle the heavy mud. A mud weight
of 16 to 18 ppg is considered heavy.
Special valves and fittings a t the wellhead,
called blowout prev en ters, are used for
emergency control when form ation fluids enter
the hole. They close in the well and allow mud of
a weight great enough to control the pressure to
be circulated. M aintaining the proper mud
weight and carefully controlling other mud
characteristics are toe best ways to prevent
blowouts. Crew members on a rig should know
toe first signs of an impending blowout: toe
volume of fluid returning from toe hole increases, and when toe pump is shut down, mud
continues to flow from toe well and mud pits

'

ig u r e

11. M

u d flo w

f i ' 1

in d ic a t o r

gain in volume. An increase in mud flow return

can be seen on a mud flow indicator (fig. 11),
and an increase in mud pit volume can be seen
on a pit volume indicator (fig. 12).

ig u r e

12. P

it v o l u m e

in d ic a t o r

Composition of
Drilling Mud
Although three types of fluids are used for
drillin g -w ater-b ase muds, oil muds, and
gaseous fluids, the g reatest share of attention
m ust be paid to the properties and conditioning
of water-base muds because they are used so extensively.

Water-base Muds
Fresh w ater muds. The composition of spud
mud, the fluid used to s ta rt a well, varies with
d rillin g p ra c tic e s a ro u n d th e c o u n try .
Sometimes w ater alone is used; a t other times a
fairly good quality of mud is needed. The w ater
is obtained from a nearby source such as a well,
stream , or lake. A t some locations surface formations may consist of loose sand and gravel. In
such cases, the spud mud should have the ability
to build up a filter cake on the wall of the hole to
prevent caving. It should also be viscous (thick)

F ig u r e . B e n to n ite r e a c t i n g w ith w a t e r

enough to carry out cuttings as the hole is

drilled. Sometimes the form ations near the surface contain enough clay to make up a good
mud; if not, bentonite or sacked clay m ust be
mixed before the well is started. Bentonite is a
clay th at reacts with fresh w ater to give it
viscosity, ability to build filter cake, and gel
s tre n g th -a ll properties necessary to make a
good mud (fig. 13).
N atural m ud is often used for surface drilling
and for making hole rapidly below the conductor
casing. When the shallow formations contain
gumbo and other low-grade clays, w ater plus
cuttings can make an acceptable natural mud.
When natural mud is used, a lot of w ater must
be used to keep the weight and viscosity of the
mud low. It is usually improved by chemical
treatm ent as the depth of the hole increases.
Wells have been drilled to 12,000 feet on the
Gulf Coast, using natural mud with a little commercial bentonite to thicken the mud and mp ro v e its w all-b u ild in g and filte r-lo s s
capabilities.

Chemically treated muds. Phosphate m ud is a

natural, water-base mud to which phosphate is
added as a thinning agent. When native days
are drilled with a natural mud, the viscosity of
the mud tends to get too high. Then the viscosity
is controlled by adding a little phosphate to the
mud; too much, however, can cause the viscosity
to increase.
Organic chemicals are widely used in many
parts of the world for treating mud. Brand
names of these chemicals vary according to the
mud company th at sells them. An old standby,
but now seldom used, is a combination of caustic
soda and quebracho (an extract obtained from a
South American tree of the same name). Addition of this m ixture changes the color of a drilling mud to red. The organic chemical in widest
use today for thinning and filtration control is
lignosulfonate. Chrome lignosulfonates are sold
under a number of trade names; they are very
effective but also expensive and should be used
only as ordered by a mud e n ^ n ee r. In fact, all
mud chemicals should be carefully mixed and
added to the mud system exactly as specified by
the mud man, for mud chemistry can be very
complicated.
C a lc iu m -tre a te d m uds. Lim e (calcium
hydroxide) was first used for calcium treatm ent
of mud. L ater, gypsum (calcium sulfate) and
calcium chloride were also found to be effective.
Calcium-treated muds are still in use, but
chrome lignosulfonate muds with very little lime
are much more widely used in the deep, hightem perature, high-pressure wells of today.
Oil-emulsion muds. An oil-emulsion mud is a
water-base mud into which oil has been mixed.
The oil is spread out, or dispersed, in the w ater
in the form of an oil-in-water emulsion. Diesel oil
is the kind usually used.
S altw ater muds. Offshore wells are often
drilled with seaw ater, which is an excellent
source of calcium and magnesium. These wells
are spudded with seaw ater and saltw ater clay
(attapulgite) and later improved with bentonite,
caustic soda, and chrome lignosulfonate, with

gypsum sometimes added for control and st abty. Saturated saltw ater mud is a special waterbase fluid used for drilling a bed of salt. If a
freshw ater mud is used to drill a salt bed, the
hole enlarges because the fresh w ater in the
mud dissolves the salt. Saturated saltw ater mud
overcomes this problem.

Oil Muds
Oil muds are sometimes employed when a well
is about to enter a producing zone or when
special drillin g problem s such as high
tem peratures, sloughing shale, or stuck pipe are
encountered. The two types of oil muds are oilbase and invert-oil muds. Both are expensive
and m ust be handled with special care on the
job
Oil-base muds. Basically, an oil-base mud
consists of diesel oil, emulsifiers, stabilizing
agents, salt, and less than 5 percent w ater. The
exact composition depends on the supplier.
Although oil-base mud has a small amount of
w ater, any additional w ater is a contam inant
th at m ust be avoided. Even a very small amount
may cause undesirable thickening of the fluid.
Invert-oil muds. Invert-oil mud may contain
from 10 to 50 percent w ater by volume. The
w ater is emulsified as small droplets in the oil.
Properly prepared, invert-oil muds are very
tight emulsions. They are used much less commonly today than they were in the early 1970s

Testing of
Drilling Mud
Drilling crews are usually made responsible
for m easuring mud weight, funnel viscosity, and
sometimes filtrate loss. They may also measure
sand and salt content and alkalinity. Deep, expensive wells require testingfor allphysical properties, as well as electrolytic properties, of the
mud. Such testing is done at regular intervals by
a mud engineer or technician. The reason for
such testing is to determine what properties the

mud has a t a given time so th at it can he treated

if necessary to give it the properties th at are
needed in the drilling situation being encountered.

Density or Weight Test

Density, or weight per unit of volume, can he
expressed as pounds per gallon (ppg), pounds
per cubic foot (lb/ft3), specific gravity, or pounds
per square inch per 1,000 feet of mud in the hole
(psi/1,000 ft). The last m easurem ent is toe most
convenient for calculating hydrostatic head of
toe mud column for any depth of hole because it
is in toe same units used for pump pressure and
form ation fluid pressure. A mud balance
(fig. 14) is used to m easure toe mud density. The
density is kept high enough to prevent kicks,
and low enough to prevent lost circulation and
to improve rate of penetration (ROP).
F

ig u r e

15. M

arsh fu n n ei

.<
F i g u r e 4 . M u d

balance

10

OF DRESSER
COURTESY

Viscosity and gel strength are related to toe

flow properties of mud. Routine m easurem ent
of viscosity is made with a Marsh funnel
(fig. 15), which gives a timed rate of flow. The
gel strength of mud is a m easurem ent of its
ability to thicken, or gel, when a t rest. Gel
strength m easurem ent is made by using a
direct-indicating viscometer (fig. 16) and following a given procedure. A mud m ust be thick
enough to carry cuttings up the hole, and thin
enough to flow freely through toe surface
system. In hard-rock country, it is necessary to
add bentonite, polymers, or the like to get a

IN D U S T R IE S

Viscosity and
Gel Strength Tests

viscosity th a t is high enough. In gumbo country,

it is necessary to add thinners to lower the
viscosity.

Filtration and
Wall-building Tests
Filtration rate is one of the most im portant
properties of drilling mud, for it is a m easure of
the relative amount of w ater in the mud lost to
permeable formations and therefore of the
relative amount of filter cake deposited on the
permeable walls of the hole. M easurements are
made with instrum ents called filter presses
(fig. 17), either a t low tem peratures or a t high
tem peratures th at simulate downhole conditions. Results give the volume of filtrate and the
thickness of the filter cake.

ig u r e

18.

S creen

set

(fig. 18), which gives the sand content of the

mud in percent by volume. Anything caught on a
200-mesh screen is called sand.

Solid, Liquid, and Oil

Content Determination
F i g u r e ?. H i g h - t e m ? e r a t u r e ,
TIO N T E ST E R

h ig h -p re s s u re

filtra -

Sand Content Determination

M easurement of the sand content of mud is
made with a simple apparatus called a screen set

Many properties of drilling m ud-density,

viscosity, gel strength, and filtration ra te -d e pend in large p art upon the solid content of the
mud. The calculated specific gravity of the solid
p a rt gives an indication of the relative amounts
of drill solids and weight m aterial present,
which are of special importance for heavy muds.

Because the mud viscosity is affected by the

relative volume of solids, it is im portant to know
this volume so th at a decision can be made about
the treatm ent needed. For example, if the solid
content is too large, w ater instead of chemicals
should be used for thinning. Gel strength and
filtration rate are related to the attracting and
repelling forces between solid particles in the
mud, and thus to the types of solids and their
volume
For research purposes, solid content can be
determined by evaporating a weighed portion of
the mud and weighing the residue, then
calculating the volume. For saltw ater muds, a
correction for salt content m ust be applied. For
oil-emulsion muds, the mud is distilled and the
liquid is condensed and measured. Stills are
available for determ ining the content of solids
and liquids in mud (fig. 19). At a given mud

weight or density, if the viscosity is higher than

the recommended range and the solids content
is also higher than the recommended range, the
mud clearly needs dilution.

Determination of pH
The pH of a drilling fluid indicates its relative
acidity or alkalinity. A perfectly neutral liquid
has a pH of 7. An acid solution has a pH less
than 7; an alkaline solution has a pH more than
7. The m easurem ent of pH employs either the
colorimetric method, using chemically treated
paper strips, or the electrom etric method, using
glass electrode pH m eters. Bentonite-extended
muds usually have a pH within the range of
8.5-9.5; most thinners must have a pH above 9
to become activated; the corrosion rate is
minimum a t a pH of 1 0 - 2 ; lime systems have a
pH around 12.

Other Tests
Mud tests such as filtrate analysis, cation exchange, resistivity, and electrical stability of
emulsions may be carried out by a mud engineer
for the purpose of dealing with special drilling
problems.

Treatment of
Drilling Mud
In many drilling operations, it becomes
necessary to change the chemistry of the mud
from one type to another. Such a change is
referred to as a conversion or breakover.
Reasons for making a conversion may be (1) to
m aintain a stable wellbore, (2) to provide a mud
th at will tolerate higher weight, (3) to drill salt
formations, and (4) to reduce the plugging of
producing zones.

Breakover
F i g u r e . S t i l l t o D E T E R M IN E SOLID AND LIQ U ID GONTENT
OF MUD

Chemicals added to mud cause an increase in

viscosity followed by a decrease in viscosity. The

term breakover refers to this thin-thick-thin sequence of events. Even though lignosulfonate
muds do not experience this sequence, the conversion of a lignosulfonate mud is still referred
to as a breakover. Lime muds, gyp muds,
calcium chloride muds, saturated saltw ater
muds, and potassium chloride muds all experience a breakover. In the conversion of
freshw ater muds, mud viscosity increases as
lime, gyp, and other chemicals are added; but
when a certain poi^t is reached, the viscosity
decreases as additional chemicals are added.

To calculate the amount o f barite needed 1. for mud weighing less than 12.0 ppg, add
60 sacks of barite to increase each 100 barrels (bhl) of mud 1 ppg; or
2. for mud weighing more than 12.0 ppg,
divide the desired weight by 0.2 to find the
number of sacks of barite needed to increase each 100 bbl of mud 1 ppg. For example, to raise the mud weight from 18.0
to 19.0 ppg, the calculation would b e -

When a mud is to be converted, certain procedures should precede the breakover, as

follows:

Since it is desirable to add barite a t such a rate

th a t the mud will make a t least one complete circulating cycle ^ pump suction to the bottom
of the hole and back to pump suction while the
barite is being added, the cycle time m ust also be
calculated.

- W ater should be added to the mud to lower

the percentage of solids.
2. All chemicals should be conveniently positioned so th at they can be added to obtain
even distribution.
3. Rig personnel should be given instructions
concerning the rate a t which m aterials are
to be added (number of minutes per sack).

Weight-up
Increasing mud weight is a fairly simple procedure. The im portant thing is to add the weight
m aterial a t a rate th at will keep the mud weight
constant in the suction pit while circulating.
Careful weighing of the mud in the suction pit
will tell w hether the weight m aterial is being
added too slow, too fast, or a t the right rate.
Calculating how many sacks of barite are
needed to increase the mud weight of a circulating system and how fast these sacks should
be added can be done by close approximation for
field use, using rule-of-thumb methods. It can
also be done very accurately by mud engineers,
using specific methods and tables.
Approxim ate calculation for field use.
Calculations m ust be made for two quantities:
(1) the amount of barite th a t m ust be added to
the mud in the system to produce the weight of
mud desired and (2) the time during which the
barite m ust be added.

19 - 9

= 0.2 - sacks of barite/100 bbl mud.

To calculate the cycle tim e cycle time =

bbl mud in hole + bbl mud in pit
bbl/min pump output
where
bbl mud in hole/1,000 ft of hole = (diameter in
inches)^;
bbl mud in pit =
pit length (ft) X width (ft) X depth (ft)
bbl/min pump output = pump output in
gal/min X 0.024, or
bbl/min pump output = bbMstroke X
strokes/min.
In an example of a weight-up operation in
which the mud weight m ust be raised from 18.0
to 19.0 lb/gal, it has been calculated th at 95
sacks of barite m ust be added to each 100 bbl of
mud. Total volume of mud in the system ineludes the hole volume plus the pit volume.
Calculate the approximate hole volume by
squaring the diam eter of the hole, in inches, for
1,000 ft of hole depth. If the hole is 978 inches in
diam eter, round the number off and call it 10.
There will be 102 = 100 bbl mud per 0,0) ft of
hole. If the hole is 10,000 ft deep, then multiply

13

weight in ppg) to a desired weight (in ppg). As

an example, the chart is m arked to indicate raising 13.0-ppg mud to 15.0-ppg weight. 147 sacks
of weighting m aterial having a specific gravity
of 4.2 are needed to obtain 15.0-ppg fluid. If the
mud system contains 1,500 ( , then 2,205 sacks
(or 220,500 lb of barite) m ust be added to obtain
the desired weight of 15.0 ppg. Major mud companies sell API-grade barite, which has a
guaranteed specific gravity of 4.2. Assuming a
circulation rate of 10 bbl/min, the time to circulate the system i s -

by 10 to calculate th at the hole contains 100

bbl X 10 = 1,000 bbl mud. Then calculate the
pit volume. Suppose there are two pits, each
with a mud volume of 7 ft by 8 ft by 20 ft
( 7 x 8 x 20). (Depth of the mud is 7 feet,
regardless of how deep the pit is.) The cubic
volume of each pit is 1,120 ft3 or 2,240 ft3 for
both. Since there are approximately 5.6 ft3/bbl,
the total pit volume is 2,240 400 = 5.6 bbl.
The total volume of mud in the system is
therefore 400 + 1,000 = 1,400 bbl. It will be
necessary to add 95 X 14(1,400 1,330 = (100
sacks of barite. If the pump output is 10 bbl/min,
then the cycle time for adding toe barite will be
140 minutes (1,400 10 ).

1,500 bbl 10 bbl/min = 150 minutes.

M ixing and adding. The mixing system in
the foregoing example, in order to raise the mud
weight 2.0 ppg during the time required for one
circulation, has to handle barite as follows:

Accurate calculation. Mud engineers have

more accurate means of making toe calculation
for weight-up. Table 2 shows toe number of
100-lb sacks of barite required to raise toe
weight of 100 bbl of mud (of a given initial

2,205 sacks 150 minutes = 15 sacks per

minute.

TABLE 2
M

Initial
Mud
Weight
(lb/gal)

u d -W e ig h t

d ju s t m e n t w it h

a k it e o r

ater

Desired Mud W e^ht (lb/gal)

9.5

10.0

10.5

11.0

11.5

12.0

12.5

13.0

13.5

14.0

14.5

15.0

15.5

16.0

16.5

17.0

17.5

18.0

9
29
59
90 123 156 192 229 268 308 350 395 442 490 542 596 653 714 778
9.5
29
60
92 125 160 196 234 273 315 359 405 452 503 557 612 672 735
10
43
30
61
93 128 164 201 239 280 323 368 414 464 516 571 630 691
10.5
85
30
31
62
96 131 167 205 245 287 331 376 426 479 531 588 648
11
128
60
23
31
64
98 134 171 210 251 294 339 387 437 490 546 605
11.5
171
90
46
19
32
66 101 137 175 215 258 301 348 397 449 504 562
12
214 120
69
37
16
33
67 103 140 179 221 263 310 357 408 462 518
12.5
256 150
92
56
32
14
34
68 105 144 184 226 271 318 367 420 475
13
299 180 115
75
48
27
12
34
70 108 147 188 232 278 327 378 432
13.5
342 210 138
94
63
41
24
11
35
72 111 150 194 238 286 336 389
14
385 240 161 112
76
54
36
21
10
36
74 113 155 199 245 294 345
14.5
427 270 185 131
95
68
48
32
19
9
37
75 116 159 204 252 303
15
470 300 208 150 110
82
60
43
29
18
8
37
77 119 163 210 259
15.5
513 330 231 169 126
95
72
54
39
26
16
8
39
79 122 168 216
16
556 360 254 187 142 109
84
64
48
35
24
15
7
40
81 126 172
16.5
598 390 277 206 158 123
96
75
58
44
32
23
14
7
41
84 129
17
641 420 300 225 174 136 108
86
68
53
40
30
21
13
6
42
86
17.5
684 450 323 244 189 150 120
96
77
62
49
38
28
20
12
6
43
18
726 480 346 262 205 163 132 107
87
71
57
45
35
26
18
12
5
The lower left half of this table shows the number of barrels of water which must be added to 100 bbl of mud to produce desired
weight reductions. To use this portion of the table, locate the initial mud weight in the vertical column at the left, then locate the
desired mud weight in the upper horizontal row. The number of barrels of water to be added per 100 bbl of mud is read directly
across from the initial weight and directly below the desired mud weight. For example, to reduce an 11 lb/gal mud to a 9.5 lb/gal
mud, 128 bbl water must be added for every 100 bbl of mud in the system.
The upper right half of this table shows the number of sacks of barite which must be added to 100 bbl of mud to produce desired
weight increases. To use this portion of the table, locate the initial mud weight in the vertical column to the left, then locate the
desired mud weight in the upper horizontal row. The number of sacks of barite to be added per 100 bbl of mud is read directly
across from the initial weight and directly below the desired mud weight. For example, to raise an 11 lb/gal mud to 14.5 lb/gal,
251 sacks of barite must be added per 100 bbl of mud in the system.

14

To add barite this fast requires good hoppers

and bulk barite tanks. Two or three rig tanks on
the line usually mix the required amount of
barite in the time required. Most rig-tank hoppers mix 5 to 10 sacks per minute without too
much difficulty. It should be rem embered that
the addition of weighting m aterial results in a
liquid volume gain of 6.7 bbl for each 100 sacks
of barite, or about 163 bbl for the example. Four
600-sack tanks have to be emptied to raise the
assumed 1,500 bbl of mud from 13.0- te 15.0-ppg
weight. That is a lot of material, and no prudent
toolpusher likes to have empty tanks for long. If
less storage is available on the job, mud mixing
m ust proceed a t a slower rate. The usual procedure is to order more barite, circulate a t a
slower rate, and raise the mud weight over two
or more circulations.

Water-back
Occasionally it becomes necessary to reduce a
higher mud weight to a lower mud weight. For
example, a heavier mud may be needed to drill a
high-pressured formation. Then, after casing is
set and the high-pressured formation is behind
the casing, it is sealed off. The formations below
the casing may be normally pressured, and a
decrease in mud weight is possible.
In water-base muds, reduction in mud weight
is usually done with water. The following formula can be used to approximate the volume of
w a te r n e e d e d to re d u c e th e w e ig h t:
V(W i - w 2)
w 2 - 8.34
where
X
V
W'l
w2

X = l,000(l)/2.66 = 376 bbl

This formula does not consider the effect of
solids settling from decreased viscosity. When
large amounts of w ater are to be added,
m aterials to increase the viscosity m ust be
added to prevent the settling of weighting
material from the mud. Various m aterials can be
used for this purpose (starch, polyacrylates, carboxymethyl cellulose), m aterials th at are also
used to lower fluid loss. These m aterials are
added through the hopper a t a slow rate to avoid
plugging the hopper.

Thinning
To thin the mud means to lower the viscosity.
In the case of water-base muds, thinning can be
done by adding w ater or chemicals. W ater
decreases mud weight, whereas chemicals
do not. Therefore, when using weighted muds, a
careful choice m ust be made about whether to
add w ater, chemicals, or both to obtain
minimum treating costs. When the percentage
of solids is in the correct range, chemicals are
added. If the percentage of solids is high, w ater
is usually added.
The chemicals most widely used to thin waterbase muds are the lignosulfonates. They can be
used in all water-base mud systems. The lignites
receive the next widest application; phosphates
and tannates are now rarely used. When large
am ounts of thinners are added, they are usually
put through the hopper. Small amounts of thinners are usually added from the chemical barrel.

Adding 0
=
=
=
=

bbl of w ater required

original volume of mud in bbl
initial mud weight in lb/gal
desired mud weight in lb/gal

For example, if the total volume of the system is

1,000 bbl, and if it is desired to lower the mud
weight from 12.0 lb/gal to 11.0 lb/gal, then toe
required am ount of w ater would b e 1,000(12 - 11)

When oil is added to mud, an emulsifying

agent m ust also be added. Lignosulfonates are
good emulsifying agents. A mud gun should be
used to break the oil into small droplets so that
they can be carried in suspension easily (fig. 20).
The oil and the emulsifing agent are usually
added through the mud hopper and should be
added a t a uniform rate, timed so th at the entire
system is treated in one or more complete circulations.

15

w ater and added to the liquid mud as a solution.

Generally the mixing and feeding is done by
means of a ehemical tank th at will regulate the
rate of flow (fig. 21).

Safe Handling of
Mud and Mud Chemicals

'
F

ig u r e

2 . U

s in g

a mud gun

Chemical Treating
Mud is often treated with chemicals to control
such properties as weight, viscosity, gel
strength, filtration, pH, and contamination.
Numerous chemicals are available. They are
generally obtained in tee form of dry powders,
flakes, or liquids, and are usually dissolved in

Mud control frequently involves the use of

chemicals th at are hazardous to those who handie them. Everyone on the job m ust be folly
aware of the hazards and know the best first-aid
treatm ent in the event of an accident. When
new chemicals are used, the drilling crews
should be instructed in precautions to be taken
in their handling and storing.
Barrels containing chemicals for treatm ent
are usually elevated above the mud ditch. An
adequate installation requires a sturdy stairway
and working platform. The top of the barrel
should be no more than waist high for a man on
the platform so th at his face and upper body are
always in the clear.
Mixing dry chemicals through the mud hopper
is generally not hazardous. However, if several

- . .

'1

storage

FACILITIES

ig u r e

16

21. E

q u ip m e n t f o r c h e m ic a l t r e a t m e n t o f m u d

men are adding chemicals a t the same time, they

m ust use team work and be concerned about
mutual protection. They should be careful not to
clog the mud hopper, for a clogged hopper can
cause splashing of liquid mud.
Caustic soda (sodium hydroxide) is furnished
as a dry chemical in paper bags. It is extremely
dangerous to handle, especially for toe eyes. It
is a strong alkali th at burns toe skin, especially
if toe skin is wet. Muds th at are heavily treated
with alkalis also burn the skin, either on direct
contact or after soaking through clothing. With
skin burns, toe first rule is to wash the burn with
a flood of w ater (fig. 22). Afterwards, a wash

F ig u r e 22. F i r s t a id f o r

c h e m ic a l

b u rn s

op

th e s k in

with vinegar is helpful. Crew members should be

careful about muddy clothing. Burns may not
occur immediately, but toe mud should be
washed off to prevent them. Eye burns need
prom pt washing with a lot of w ater (flg. 23),
followed by application of boric acid ointm ent or
caster oil. Eye burns should receive a p, hysicians
attention as quickly possible.
If caustic soda is properly handled, it can be
mixed safely in a chemical barrel, but caustic in
w ater generates heat th at can cause a barrel to
boil over. If caustic is added through a hopper in

a small, steady stream , the mud usually takes it

readily. On the other hand, the sudden addition
of a large batch of caustic may thicken the mud,
plug the outlet, and cause the mixture to run
over the hopper or squirt up into a workers
face. Crew members should wear goggles when
handling caustic, and possibly rubber gloves as
well.
Starch preservatives in treated mud have a
formaldehyde base and often other bactericides
as well. These are poisons when taken internally, and the fumes and dust can seriously affect
the lungs and eyes. Handling them requires
judgm ent and caution.
The use of oil-base or invert-oil mud calls for
certain safeguards. Losses of fluid should be
kept to a minimum because these muds are expensive. Contamination with w ater must be
strictly avoided. The oil muds m ust be kept off
the rig to prevent a slippery, oily mess th at can
be hazardous. Oil muds can also damage rubber
hoses, gaskets, and the like; so synthetic, oilresistant rubber parts should be used with oil
muds.
The oil in oil-base and invert-oil muds is flammable. Even though the oil used has a high flash
point to reduce fire hazard and even though oil
muds contain from 5 to 50 percent w ater to further reduce the fire hazard, oil muds may not be

17

Mud Circulating Systems

fireproof. Although most oil muds contain

enough solids and w ater to keep them from
burning, they m ust be treated as if they could be
readily ignited. No Smoking signs should be
placed around the rig and strictly observed,
e th e r precautions should also be taken to avoid
fires in case overheating, crude-oil contamination, or gas-cutting of the mud occurs.

Route of Circulation
Circulation of drilling mud begins from the
mud pits, with suction lines leading to the mud
pumps (fig. 24). Mud pumps send the mud
through the rotary hose into the swivel, down

SWIVEL
STANDPIPE

HOUSE
ROTARY HOSE

MUD
PUMP

KE LLY
DISCHARGE

SECTION LINE
D R ILLP IP E
MUD M IXING HOPPER
PIT

MUD RETURN LINE

CHEMICAL TAN K
ANNULUS

DITCH

SHALE
SHAKER

MUD PIT
D R ItL COLLAR

RESERVE PIT I
SHALE SLIDE

BOREHOLE

ig u r e

18

24. R o u te

o f c ir c u l a t in g f l u id

through the drill stem, and out through the bit.

The mud returns to the surface through the annulus of the borehole, then through the mud
return line back into the mud pits. The mud is
made up and conditioned in the surface system,
using various m aterials and auxiliary equipment.
The mud pump is the prim ary component of
any system using a liquid as the circulating fluid.
It furnishes the pressure for sending the fluid
through the system.. The swivel perm its the drill
stem to be raised or lowered while circulating
and rotating. The drill stem, made up of kelly,
drill pipe, and drill collars, rotates the bit, furnishes weight for drilling, and provides the conduit through which fluid flows to the bit. Drilling
fluid passes through the bit, out the nozzles, and
up through the annulus, which is the space between the drill stem and the wall of the well
Fluid returning to the surface through the annulus carries with it the cuttings made by the
bit. When the fluid reaches the surface, it flows
into the mud pits through a mud return line,
after having rock cuttings, sand, and shale
separated from it by devices such as shale
shakers, desanders, desilters, and centrifuges.

to contain the cuttings of sand and shale th at

have been removed from the hole during the
course of drilling. The second pit is large enough
to contain enough mud to fill the hole when the
entire drill stem is out of the hole, with a
reasonable margin to spare. A shale shaker at
the outlet of the mud retu rn line screens the
larger cuttings out of the mud stream before the
stream reaches the settling pit, thus allowing
the settling pit to be smaller than would otherwise be possible. Where it can be employed, circulating through the reserve pit provides nearly
solids-free fluid for drilling. Such an arrangem ent is used extensively in surface drilling with
a flocculated clear w ater system.
EARTHEN RETAINING W ALLS

Mud Pits
The main functions of mud pits a r e 1. to accumulate mud circulated from the
well;
2. to supply fluid to the pump for circulation;
and
3. to store mud so as to provide enough fluid
to fill the hole when pipe is removed.
A drilling rig for medium-depth holes can
usually operate quite satisfactorily with earthen
pits for circulation. Although most rigs are
equipped with steel pits, a look a t a system with
earthen pits is useful to understand the basic
functions of mud pits (fig. 25). When earthen
pits are being used, a short trench between the
pits ensures th at the mud stream travels tee
full length of each pit before reaching tee pump.
The slow movement of tee mud allows the cuttings to settle out before the mud is pumped
back into the well. The first pit is large enough

ig u r e

25. E

a r t h f .n

p it s

fo r

f l u id

c ir c u l a t io n

and

W ASTE D IS?O S A L

19

Steel mud pits form a better arrangem ent for

fluid circulation than do earthen pits; usually
two, three, four, or even more steel pits are used
for a circulating system. Steel pits have many
advantages over earthen ones. They have a
known volume, can be easily cleaned, and allow
a positive pressure to be maintained to aid in
pump suction. Chemical treatm ent of the mud is
easier with steel tanks than with earthen pits
because the volume of mud in the tanks can be
accurately figured. Steel troughs, or ditches,
can be perm anently installed with steel pits and
are easier to clean than earthen trenches. Incidentally, steel ditches should be arranged so
th at the mud stream can be diverted around any

pit. In this way, mud can be diverted directly to

a settling tank, reserve tank, or suction tank.
Equipm ent such as shale shakers, agitators,
desanders, desilters, degassers, or centrifuges
is easily installed on steel mud pits (fig. 26).
A nother advantage steel tanks offer is th at flexible lines between the mud pump and tanks and
between the tanks themselves enable fast rigging up on new locations (fig. 27).
Often rigs with steel pits also have large,
earthen pits bulldozed out of the ground nearby.
These are called reserve pits. Reserve pits are
used to receive waste fluid, cuttings, and even
trash th at accumulates as a well is drilled
(fig. 28). Sometimes a small area of a large

MUD GAS SEPARATOR

DEGASSER

DESANDER
DES -TER

^ RETURN LINE

S H ^ E SHAKER

w
F

ig u r e

20

2 6 . A

u x il ia r y e q u ip m e n t in s t a l l e d

s t e e l m u d p it s

REVIEW QUESTIONS
LESSONS IN ROTARY DRILLING
Unit /, Lesson 8: Circulating System s

W hat are the five prin :pa purposes of fluid circulation in rotary drilling ?
)(

______________________________________________________________

)2( _________________________________________________________
)3(

______________________________________________________________

)4(

______________________________________________________________

(5)

______________________________________________________________

Name the types of circulating fluids possible to use.

) _______________________________________ (

)4( _______________________________________

)2( ----------------------

)5( _____________________________________

(3)

(6) _______________________________________

...

Name the main components of circulating equipment.

)_______________________________________ (

)5( _______________________________________

)2( ____________________________ _

)6( _____________________________________

)3( _______________________________________

)7( _______________________________________

(4)

(8) _______________________________________

Mud m ust have the p ro p e r_____________________ a n d _______________________________ to lift

cuttings and to keep them in suspension both during circulation and during the time circulation is
stopped.
The usual method for cleaning the hole is by circulation of fluid through _ _ _ _ _
_ _ _ _ _ _ _ _ _ _ in the bit. High-velocity stream s of fluid blast the bottom of the hole, creating a
_______________________ th a t moves the chips from the face of the form ation as fast as they are
formed.
W hat is hydrostatic pressure, and how can it be increased in a well?

(1)
(2)

7. W hat are the first two signs of an impending well blowout?

) (-----------------------------

- ------------------------------------------------ )2 (

8. W hat type of fluid is most commonly used for drilling?

9. W hat three im portant properties does bentonite give to w ater or water-base mud?

(1) --------------------------------------------------------------------------------------------------------------------------
(2)

.. .

(3)
10. The organic chemical in widest use today for thinning and filtration control of drilling mud is

W hat is the difference in w ater content between oil-base muds and invert-oil muds?

12. Match the properties of drilling mud (listed on the left) with the equipment used to test for each
(listed on the right).
) (

Density, or weight

(2)

Viscosity and gel strength

(3)

Filtration rate and wall-building ability

(4)

Sand content

(5)

Solid, liquid, and oil content

c. Mud balance
D. ? a p e r strips or glass
electrode m eter
F. Marsh funnel and
directiindicatingviscom eter

(6)

pH

F. Still

List the reasons for making a chemical conversion of mud.

(1)
(2)

(3)
(4)

A. Screen set
B. Filter press

14. List the procedures th a t should he carried out before drilling mud is converted.
)
(

_____________________________ -_________________________________________________

)2( ________________________________________________________________
)3( ___________________________________________________________________
)4(

___________________________________________________________________

15. Increasing mud weight requires two calculations, either approximate or accurate. W hat factors
must be calculated?

(1)
(2) _______________________________________________________________________________
16. To what procedure does the term water-back refer?

17. W hat is the difference between the effects of adding w ater to mud and adding chemical thinners to
mud?

18. When oil is added to mud, an

m ust also be added.

19. W hat is the first-aid treatm ent for both chemical burns of the skin and chemical burns of the eye?

20. Trace the route of circulation of drilling mud by naming (in order) the main items of equipment
through which it travels, beginning with the mud pumps.
)_______________________________________ (

)5(

)2( _____________________________________

)6( _____________________________________

)_______________________________________ (

)7( _______________________________________

)4( _______________________________________

21. Name the three main functions of the mud pits.

)_____________________________________ (

)2( ___________________________________
(3)

22. Name six items auxiliary mud-handling equipment th at are usually placed on or adjacent to the
mud pits.
)_______________________________________ (

)4( _______________________________________

)2( _______________________________________

)5( _______________________________________

)3( _______________________________________

)6( _______________________________________

23. W hat are the two general types of mud pumps used for rotary drilling?
)

---------------------------------------------------------------------------------------------------------------------------------------

(2)
24. W hat are the four circulation components in which pressure losses take place while drilling?
) ) _________________________________________ (3 ( -----------------------------------------------------)2( ------------------------------------------------------------ )4( -----------------------------------------------------25. State the two im portant disadvantages of drilling with air or
1 ) ___________________________________________________
2)

....

26. How does foam help in moving w ater out of the hole when drilling with air?

27. W hat circulating fluid is most commonly used for workover drilling?

M U D PITS
SHEAR RELIEF VALVE
(POP-OFF VALVE)

PULSATION
D A M ENER

HIGH-PRESSURE
RELIEF LI^ES
TO PITS

IN TA K E LINES
TO PUM PS

CENTRlPtyGAIi
:TION C H A RGE

ig u r e

27. L

in e s fr o m m u d p u m p s t o s t e e l p it s

-:,-
;

ig u r e

2 8 . f tE S E R E

p it s

21

ig u r e

29. L

a y o u t o f m u d t a n k s a n d r e l a t e d f a c il it ie s

reserve pit is partitioned off for storage of

surplus good mud not in use a t the moment.
Auxiliary equipment becomes essential when
heavy mud is being circulated. The savings in rig
time, mud m aterials, and chemicals made possible by these devices more than justify their cost.
Shale shakers remove large particles from the
returning mud, thus lessening the need for settling time and making it possible to use smaller
pits than would otherwise be needed. Mud
agitators enable weighting m aterial to be kept
in suspension in the mud. They prevent channeling through the pits and ensure th at the mud is
homogeneous. Degassers remove entrained gas
from the mud much more quickly than does
allowing the mud to lie quietly in a pit. Desilters,
desanders, and mud centrifuges are useful in
separating sand or shale particles from liquid
mud and in salvaging weighting m aterial (usually barite, which is very expensive).

The diagram of a layout of tanks, piping,

pumps, and related facilities shows the flow of
mud through a typical system (fig. 29). The
hookup includes centrifugal pumps th at are used
for mixing, transferring fluids from one tank to
another, and operating the mud guns. Jet
siphons are also operated by fluid from the centrifugal pumps to move sand or cuttings from
the active tanks to waste (fig. 30).

ig u r e

30. J

e t s if h o n

The essential features of mud-handling equipm ent for very deep drilling include1. a capacity of 800 barrels in the working
pits, plus 00 barrels of ready reserve;
2. paddle agitators and mud guns for stirring;
3. high-capacity centrifugal pumps for mixing and transferring mud;
4. a je t hopper for rapid mixing of dry mud;
5. bulk-bin storage for barite;
6. covered storage for sacked material;
7. convenient storage for mixing chemicals
and mud additives;
8. ample w ater storage and supply;
9. a mud-gas separator; and
10. built-in piping and ditches.

Mud Pumps
A rig usually has two mud pumps, which are
the very heart of a fluid-circulating system for
rotary drilling. Their function is to give power
to the fluid in the form of pressure and volume,
thus moving the fluid from the pit, through the
drill stem, to the bit (where hydraulic power is
expended for jetting), back up the annulus, and
back to the pit. Mud pumps are either duplex or
triplex.
Duplex, double-acting pum ps. The duplex,
double-acting pump is widely used for rotary
drilling (fig. 31). Each of the two cylinders of
this pump is filled on one side of the piston a t the
same time th at fluid is being discharged on the

PULSATION
DAMPENER

DISCHARGE

,.

'

VALVE
POTS

t
CYLINDER
HEAD COVERS

SUCTION
LINE
F

ig u r e

31. D

u plex m ud pu m p

'

DISCHARGE VALVES

'ALVE COVERS

CYLINDER HEA

COVERS

F ig u r e 3 2 . O
PUM P

p e r a t io n o f

'

PULSATION
(AMPENER

PISTO N AND VALVES OF A D UPLEX

S U C ^O N LINE

other side of the piston (fig. 32). Each complete

cycle of a piston results in the discharge of a
mud volume th at is twice the volume of the
cylinder, minus the volume of the piston rod.
The total volume for a duplex pump in one complete cycle is twice this amount because there
are two pistons. The volume of fluid pumped per
minute is determined by multiplying the volume
per complete cycle times the number of strokecycles per minute. Strokes per minute (spm) actually means cycles per minute, although a
duplex pump makes four strokes during each cycle. Fluid pumping rates are usually expressed
as gallons per minute for a given pump and, for
a given pump, vary according to the speed and
the diam eter of the liner installed. Duplex
pumps may be powered either by electric motors
through chain drives or by several engines from
a chain transmission, with the final drive accomplished by means of multiple V-belts or
m ultistrand chains.
T riplex, sin g le-a ctin g p u m p s. Triplex,
single-acting pumps (fig. 33) have been used for
drilling mud service since 1962, although multicylinder pumps were used for acidizing, cementing, and workover service long before that.
Single-acting pumps put pressure on only one
face of the pistons rather than on both sides, as
double-acting pumps do. Triplex pumps have
three pistons and are much lighter than duplex,

24

iS H
F ig u re 33. T r ip le x

pu m p

double-acting pumps for specific power ratings.

The reason th at more power can be obtained
from a relatively small triplex pump is th at
triplex pumps operate a t higher speeds. Triplex
pumps can m aintain a smooth discharge flow a t
higher pressures than duplex units, because
equal volumes of fluid are delivered a t each 120
degrees of crankshaft rotation (fig. 34).

Intake

F ig u r e 3 4 . O
PUM P

p e r a t io n o f p is t o n a n d v a l v e s o f a

CENTRIFUGAL
PUMP ,

= =

ELECTRIC
PUMP MOTOR

'

-
F

ig u r e

'

3 5 . C e n t r if u g a l

rip u m p f o r s u c t io n c h a r g in g o f a t r ip l e x

Liners, rods, and pistons for a triplex unit are

much lighter and cost less than comparable
parts for a duplex pump of similar size. There
are no stuffing boxes or rod packings in a singleacting pump. And because of their high-speed
operation, triplex pumps can pump high (umes of fluid with liners th at are relatively

pu m p

small. Because the triplex pump operates at

high speed, it usually has a centrifugal pump to
charge the suction (fig. 35).
M ud m anifold. A manifold assembly is used
for connecting two pumps (fig. 36). Long-radius
els and tees are employed, and union couplings
th at are tightened and loosened with a hammer

VIBRATOR HOSE

ig u r e

36. H

i g h -p r e s s u r e m u d m a n if o l d

are placed at critical points. Special valves are

used in the hookup to perm it isolation of any
p art of the manifold in case of a leak during a
critical operation or to perm it repairs on one
p art of the system while the other p a rt is
operating under pressure. Short lengths of hose
from the pumps to the manifold assembly are
flexible and have connectors for quick rigging
up. Because the hoses are flexible, many of the
vibrating pulsations th at originate in the pump
are absorbed. The hoses are called vibrator
hoses because of this action.
M aintenance o f pum ps. W orn valves,
pistons, rods, and liners are expendable parts of
mud pumps th at m ust be replaced routinely.
These parts are subject to severe loads and wear
out quickly if not correctly fitted and properly
installed, particularly when operated under high
pressure. The new crew member on the rig is
often called on by the derrickm an to help open
up (work on) a pump after the decision about
what needs attention has been made (fig. 37).

F i g u r e 3 7 . S e r v i c i n g a m u d

pum p

The valve caps may need to he removed so th at

the valves may he looked at, or perhaps the
cylinder heads m ust he pulled so th at pistons
and liners may be examined. Valve seats, if
worn excessively, may have to he pulled, or a
piston and rod (or liner) may have to be changed
because of wear. Sometimes the liner may have
to he removed and replaced with a liner of
smaller size in order to increase the pump
pressure as a well is drilled deeper. Servicing a
pump is merely a routine job when the proper
tools are available, but it can be difficult and
dangerous when makeshift methods are used.
The tools are large, the parts are heavy, and a
lot of force is sometimes needed. Crew members
m ust work safely to avoid injury.

Standpipe and Rotary Hose

The extension of piping from ground level up
into the derrick is called the standpipe (fig. 38).
It anchors the upper end of the rotary hose and

gooseneck on the swivel. The ends of the hose

are tied to the derrick and the swivel with safety
chains fastened to clamps on the hose.
The standpipe and hose form a flexible link for
drilling fluid in the circulating system. The hose
can be raised or lowered as required. A 48-foot
standpipe with a 55-foot hose perm its about 80
feet of vertical travel by the swivel and kelly
(fig.39). This distance is needed to make
mousehole connections with a 45-foot kelly and
30-foot singles, with a reasonable margin to prevent bending the hose too sharply a t the standpipe. A higher standpipe and a 75-foot hose are
needed when range 3 drill pipe (45 feet long) is
being used.

ig u r e

3 8 . S t a n d p ip e

and h o se a rra n g em en t

keeps the hose clear of the rig floor when the

kelly has been drilled down and the swivel is
near the rotary table. The standpipe is firmly
clamped to the derrick and is topped with a
gooseneck fitting. One end of the rotary hose is
attached to the gooseneck on the standpipe, and
the other end of the hose is attached to a

ig u r e

3 9 . S t a n d p ip e

h e ig h t fo r a

5 5 -fo o t

h o se

The rotary hose, also called the mud hose or

the kelly hose, is an im portant p art of the circulating system (fig. 40). It m ust be flexible as
well as leakproof under high pressure, give long
service under severe conditions, and handle
various types of fluids th at may contain a high
percentage of abrasive solids (fig. 41). Rotary
hoses generally receive fairly good treatm ent
when in the derrick but are frequently subjected

to poor handling when laid down for rig moves.

The hose should be wrapped on a reel when
taken down, and g reat care should be taken in
attaching a cable or sling to prevent damage to
the rubber cover. API offers specifications for
both rotary hoses and vibrator hoses (fig. 42).
TUBE
BREAKER
FABRIC

PRIMARY
CARCASS
T R A V E L IN
BLOCK
W IR F

REINFCRCEMENT

HOOK
SECONDARY
CARCASS

CABLE
REINFORCEMENT
(MAY BE OF
MULTIPLE tAYERS)
SWIVEL
GOOSENECK
OPEN-WEAVE
FABRIC

SW IVEL

COVER

ROTARY

^OSE j

F ig u re

. R o ta ry

GOOSENECK

hose

a tta c h e d

to

th e

" "

THREADE
COUPLING

s w iv e l
F ig u re

41.

C o n s tru c tio n o f r o ta r y h o se

ROTARY VIBRATOR AND D R !LLIN G H O SE

D IM E N SIO N S AND PR E S S U R E S
1

Size, S ta n d a rd
In sid e
L e n g th .
D ia,
ft.

'

35
40

2
2 /

G rad e

A B
A B, C
A
A
A
A
A
A
A

B
B
B
u
B
B
B

D E
C E
> E
) ( E
C (E
('. E
c (E

no
12

4
4

4
4
4

Q
c
c
c
c
c
c
c

lb

lb
20

2%

30
bo
bb

20
30

bb
60

70
7 b

10
12
lb
20
30

3%

55
60

70
7 b

10
12

20
30
55
60

70
75

4
4
4
4
4
4

4
4
4
4

4
4
4
5
5
5
5
5
5
5
5

10

W orking P ressure, psi

3
3
3
3
3

10
12

3
T h re a d s
(L in e
? ip e

I) E
1) K

D E
I) E
D
D E
l> E

c I)

G rade
D

G rade
A

G rade

G rade

1500
1500

2000
2000

4000

1500
1500
1500
1500
1500
1500
1500

2000
2000
2000
2000
2000
2000
2000

4000
4000
4000
4000
4000
4000
4000

5000
5000
5000
5000
5000
5000
5000

7500
7500
7500
7500
7500
7500
7500

4000
4000
4000
4000
4000
4000
4000
4000
4000

5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000
5000

c
c
c
c
c
c
c

D E
(K
E
<E
(E
E
E
(E

4000
4000
4000
4000
4000
4000
4000
4000
4000

5000
5000
5000

c
c
c
c
c
c
c

D
D
(
D
D

4000
4000
4000
4000
4000
4000
4000
4000
4000

5000
5000
5000
5000
5000
5000
5000
5000
5000

<

COURTESY OF A PI S P E C 7

5000

11

12

13

14

T e st P ressu re, psi

G rade

G rade

G rade

G rad

G rade
D

G r^de

3000
3000

4000
4000

8000

3000
3000
3000
3000
3000
3000
3000

4000
4000
4000
4000
4000
4000
4000

8000
8000
8000
8000
8000
8000
8000

10,000
10,000
10,000
10,000
10,000
10,000
10,000

15,000
15,000
15,000
15,000
15,000
15,000
15,000

7500
7500
7500
7500
7500
7500
7500
7500
7500

8000
8000
8000
8000
8000
8000
8000
8000
8000

10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000

15,000
15,000
15,000
15,000
15,000
15,000
15,000
15,000
15,000

7500
7500
7500
7500
7500
7500
7500
7500
7500

8000
8000
8000
8000
8000
8000
8000
8000
8000

10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000

15,000
15,000
15,000
15,000
15,000
15,000
15,000
15,000
15,000

8000
8000
8000
8000
8000
8000
8000
8000
8000

10,000
10,000
10,000
10,000
10,000
10,000
10.000
10,000
10,000

ROTARY HOSE
17 D efinitions. R otary drilling hose is used as
the flexible connector betw een the top of th e standpipe and the swivel which allows fo r vertical trav el.
I t is usually used in lengths of 45 feet and over.
R otary v ib ra to r hoses a re used as flexible connect rs betw een th e mud pum p m anifold and the
standpipe m anifold to accom m odate alig n m en t and
isolate v ib ra ti n. They are usually used in lengths
17.2 SizesanR otarSy drillin g hose and ro ta ry vibrato r hose s^all be fu rnished in th e sizes and lengths
given in able 17.1 as specified on the purchase
or^er. A dditional lengths of v ib ra to r hose m ay be
ordered, and lengths of drilling hose m ay be ordered
in five foot increm ents. They m ay be m arked w ith
th e A P I m onogram if they m eet the o th e r r e uirem ents of th is specification.
17.3 D imensions. D im ensions of ro ta ry hose shall
conform to th e r e t i r e m e n t s of Table 17.1 and
Fig. 17.1, except as noted in P ar. 17.2.
17.4 Connections. R o ta ry hose assem blies shall
be fu rnished w ith ex tern al connections thread ed
w ith li e-pi e th re ad s a s specified in A P I Spec. 5B:
A P I S p e c ific a tio n f o r Thread ing, G aging, and
Thread Inspection / Casing, T ub in g , and. L in e
Pipe Threads. The A P I m onogram m a^ be retain ed

on th e hose assem blies when o th er connections are

applied, upon ag reem en t of the u ser and th e ^ fa c tu er, if th e assem bly is p ressu re te sted in
accordance w ith Table 11.1 w ith o th e r connections
17.5 T est P ressu re. Each hose assem bly shall
be individually te sted a t the applicable p ressu re
specified in Table 17.1 and held fo r a m inim um
period o f one ( )m inute.
17.6 W orking P ressu re. The m axim um w orking
p ressu re of th e hose assem bly shall be th a t shown
in Table 17.1. The su rg e pressu res encountered in
the system shall be included in the w orking pressure. The hose shall be designed to have a m inim um
b u rst p ressu re of a t le a st 2 tim es th e w orking
pressure.
17.7 M a k in g . The hose assem bly conform ing to
th is specification shall be m arked w ith th e A P I
m onogram , th e w orking p ressu re and th e m anufa c tu re r's id entification. Each len g th of hose shall
have a longitudinal lay line of a d iffe re n t color
th an the hose cover. M arkings, w hether embossed
o r p rin ted in distinctive colors, shall be vulcanized
o r sim ilarly affix ed into th e hose cover.
N O T E: See A ppendix E : Recommended P ractice f o r Care and Use / R o ta ry Hose.

ROTARY V IBRATOR AND D R ILLIN G HOSE

D IM EN SIO N S

ig u r e

42. API

S PE C IF IC A T IO N S FOR H OSES

MUD R E ^R N
LINE

LMsnaasH

|

ig u r e

43. M

u d r e t u r n l in e

Mud Return I;ine

if the fluid has to move a long distance from the

wellhead to the pits.

The mud return line from the w ellhead-the

line th at allows the mud to return to the pit or
shale shaker by the action o fg ra v ity -is usually
6 to 8 inches in diam eter (fig. 43). However, if
the mud is viscous or if a large volume of mud is
being circulated, a return line of 10-inch
diam eter is required. A large line is also needed

Storage and Mixing Faciiities

A rrangem ents m ust be made on any rig for
storing, mixing, and treating mud. Usually
sacked bentonite and treating chemicals are
kept in a mud house, bulk barite in metal bins,
and w ater for drilling in storage tanks (fig. 44).

BULK BAR ITE

BINS

'ANKS

"SSSr
11

ig u r e

30

44. M

u d a n d c h e m ic a l s t o r a g e

Hoppers and pumps are used for mixing toe

mud ingredients efficiently.
M ud-m ixing hopper. J e t hoppers are used
universally for adding solid m aterials to liquid
mud (fig. 45). A low-pressure mud-mixing hopper is used with a centrifugal pump. The pump is
used to circulate mud from toe pit to toe hopper
and then back to toe pit. The high velocity of toe
fluid through toe je t lowers toe pressure in toe
base and sucks m aterials placed in the hopper into toe stream , where they become mixed with
toe fluid. M aterials such as clay, bentonite,
barite, and chemicals are fed into toe mud
through toe hopper.
M ud-m ixing pum p. A centrifugal pump for
mud service may develop a pressure of only 50
psi and yet move more than 1,000 gallons of liquid per minute (gal/min). Suction and discharge lines for this type of pump should

ig u r e

45. J

et

have minimum restrictions in order to perm it

high flow. Some rigs are arranged with highpressure piping and use one of the regular
piston pumps for the purpose of mixing and
transfer. However, a low-pressure system of
piping with a centrifugal pump is much less expensive to install, faster, and less troublesome
to operate than a high-pressure system.
Chemical tanks. Generally, the container
used to'feed chemicals into mud is placed on toe
mud pit near toe pump suctions and close to toe
chemical storage point. A large-capacity, opentop tank with a paddle stirrer offers a workable
arrangem ent.

Hydraulics of Mud Circulation

Fluid, or hydraulic, power a t the bit is very imp ortant to toe drilling process. Hydraulic power
m ust remove the cuttings from the bottom of

H O P P E R FOR MUD A D D ITIV ES

31

Table 3 dem onstrates w hat is m eant by

pressure losses. If it is assumed th at a mud
pump a t the surface is pumping mud a t the rate
of 400 gal/min a t 2,000 psi, then pressure losses
shown in table 3 will occur as the mud travels
through the components of the circulating
system.
TABLE 3
P r e s s u r e L o s se s w ith M u d P um p a t
P u m p i n g R a t e o p 4 0 0 g a l / m i n a t 2 , 0 0 0 PSI

C i t a t i o n

the hole so th at the bit can cut into the formation and not simply redrill cuttings. The mud
pump is the source of the hydraulic power for
the mud stream . Some of this power is lost as
the mud travels through the surface piping and
down the drill stem. It is lost because the inside
surfaces of the pipe are rough and produce t'riction and turbulence in the mud stream , both of
which reduce the power. At the bit, the mud
leaves the drill stem through je t nozzles, and the
hydraulic power th at is still left in the mud after
its trip through the drill stem leaves the bit at
high velocity and lifts the cuttings off the bottom of the hole. Then the rem aining hydraulic
power forces the mud up the annulus and back
to the surface. Once the mud reaches the surface, all of the hydraulic power is used up
(fig. 46). One term for this loss of hydraulic
power is pressure loss. Engineers often speak of
such losses as system pressure losses.

Pressure Loss

Percent of Loss

Surface equipment
Drill stem
Bit nozzles
Return annulus

50
650
1,200
100

psi
psi
psi
psi

2.5
32.5
60.0
5.0

Total loss

2,000 psi

100.0

It should be noted th at the g reatest loss of

pressure occurs as the mud is jetted out of the
bit nozzles. The high velocity is desirable for efficient removal of the bit cuttings. In the example
given, only 100 psi is required to move the mud
to the surface. It m ust be noted th a t only one set
of circumstances is covered. The depth of the
hole, weight of the mud, size of the bit nozzles,
and diam eters of the piping and the hole
through which the mud moves all have a bearing
on the amount of pressure lost in a circulating
system. Drilling engineers spend a great deal of
time in studying the factors th at affect hydraulic
power in order to make the most efficient use of
the mechanical power available.

Air Circulating Systems

When it is possible to circulate with air or gas,
the rate of drilling is faster than when a liquid
m ust be used. Penetration rates are higher,
footage per bit is greater, and bit cost is lower.
Air or gas cleans the bottom of the hole more effectively than mud; it does an excellent job of
cooling when it expands on leaving the bit; and
it transports cuttings to the surface quickly. In
addition, with air or gas circulation, it is easy to
identify the formation, even though cuttings are

small; and it is easy to detect indications of gas,

oil, or water.
These advantages of air or gas circulation are
usually overbalanced by two im portant disadvantages, however. First, if the walls of the well
tend to slough, or cave, into the hole, air or gas
cannot prevent them from doing so, and sticking
of the drill stem becomes likely. Second, it is impossible to prevent formation fluids from entering the wellbore because neither air nor gas can
exert enough pressure to keep them out. This
second disadvantage is especially im portant
because most wells encounter water-bearing
formations a t some time.
Two further disadvantages of drilling with air
or gas are (1) the ever-present hazard of fire,
and (2) the problem of corrosion. Chemicals to
combat corrosion are available now, but the
added cost and effort of using them m ust be considered.

Rig Equipment
In air drilling, the air does not make a complete circulation. It makes one trip through the
compressors, down the drill stem, and back to
the surface, where it is blown to waste. Skidmounted compressors furnish the high-pressure
air for a regular rotary rig arranged for air drilling (fig. 4?). Other equipment required to handie air for circulation includes chemical treatm ent equipment to use against corrosion and
specialized equipment such as (1) mist pumps for
injecting foamers and fluid when drilling with
foam or mist, (2) hamm er drills to increase
penetration rates, and (3) air bits, special bits
with extra-heavy shanks and ducts to allow air
to flow through the bit bearings.
In preparing to drill with air, the usual procedure is as follows. Rigging up for using mud
as the circulating medium is done first. Then the

F ig u re 47. A ir c o m p re sso rs f o r

air

--

PILOT LIGHT
BYPASS LINE
FLEXIBLE LINE

MUD TANKS

COMPRESSOR LINE

STANDPIPE

CHEMICAL PUMP

PUMPS

RIG

COMPRESSOR

PREVAILING A W IN D S
F ig u re 48. A rra n g e m e n t

ig u r e

49. B

low out

of

E U IFM E N T f r a i r c i r c u l a t i o n

FR EV EN TER S

f o r a ir d r il l in g

BLOOEY LI^E

ig u r e

51. B

looey

LIN E

OF NL IN D U S T R IE S
COURTESY

compressors or a connection to a supply of highpressure gas is installed (fig. 48). Next, the
blowout preventers (fig. 49) and a rotating head
are hooked up, and safety precautions are put
into effect to minimize the fire hazard. A
rotating head, or rotating blowout preventer
(fig. 50), makes a seal around the kelly to prevent the air or gas from leaking during drilling,
while still allowing the drill stem to rotate. An
exhaust line, or blooey line, equivalent to the
mud retu rn line for mud circulation, is connected below the rotating head to vent the air or
gas to a location a t a safe distance from the rig
(fig. 51). If gas is being used, a pilot light is set
up a t the end of-the exhaust line to ignite the gas
as it leaves.
C alculating the volum e o f a i r needed. Air or
gas usually returns up the annulus a t a rate of
about 3,000 ft/min, depending on several
variables. The most im portant of these variables
are the rate of penetration, well depth, and
amount of w ater entering the well. Other
variables are the diam eters of the hole and drill

F ig u r e 50. R o ta tin g

head

Use of Foam

pipe, type of formation being drilled, and size of

cuttings. Using gas instead of air requires more
volume to produce the same lifting capacity
under given conditions, since gas is lighter than
air.

In air-drilled wells in which water-producing

formations are encountered, it sometimes
becomes necessary to employ foaming agents to
reduce the am ount of pressure th at would otherwise be needed to lift the w ater out of the hole.
When w ater is encountered, it flows into the
wellbore and begins to fill it. As the hole fills up
with w ater, more and more air pressure is required to lift the w ater out of the hole. Enough
^ ^ eventually gets into the hole so th a t not
enough air pressure is available to overcome the
weight of the water. For example, a 5,000-foot
column of salt w ater exerts 2,340 psi on bottom,
and a t least th at much air pressure is required to
remove toe w ater. Because this much air
pressure is not readily available, chemicals
similar to soap are used to cause the w ater in toe
annulus to froth and foam into a large volume.
The foam reduces toe pressure needed to move
the w ater out of the hole. As much as 50 barrels
of w ater per hour entering toe hole can be
handled by adding a foaming agent. The
soaplike chemicals are mixed with w ater in a
small tank and pumped into toe air stream going
into toe well by means of a small pump (fig. 52).
C orrosion-inhibiting chemicals are injected into
toe air stream along with the foaming agent.
The foam is blown away a t the surface. If w ater

As one can see in table 4, 50 percent more air

is required a t 6,000 feet when toe rate of
penetration is 90 feet per hour (ft/h) than at
2,000 feet when toe rate is 30 ft/h. More gas
than air is required at all depths and penetration
rates.
Determ ining the size ofcom pressors needed.
A fter toe necessary volume of air or gas is
calculated, the necessary size of compressors
must be determined. In reality, compressors will
not be used unless air is toe circulating fluid.
Gas is used only if there is a high-pressure
source nearby, and in th at case no compression
is necessary.
Single-stage com pressors are used for
pressures up to 125 psi; two-stage or three-stage
units are used for pressures up to 300 psi. For
even higher pressures such as those often needed when w ater is encountered and foam or
aerated mud m ust be used, booster compressors
are necessary. Booster compressors take the
output of one or two units and raise toe pressure
to pressures ranging from 500 to 1,500 psi.

TABLE 4
A
4 / i n c h - 2 R ILL P

ip e

p p r o x im a t e

w it h

ate of

o l u m es to

ir c u l a t io n

roduce

if t in g

( f t 3/ m i n ) i n 8 % - i n c h H o l e w i t h
P o w e r E q u iv a l e n t t o a V e l o c it y

of

3 ,0 0 0

f t / m in

Drilling Rates
Well Depth

Compressed Air

Natural

30 ft/h

90 ft/h

2,000 ft

1,039 ft3/mln

1,113 ft3/min

1,326 ft3/min

1,426 ft3/min

4,000ft

1,174 ft3/min

1,323 ft3/min

1,486 ft3/min

, </<

ft 6,000

1,30

ft3/min 1,573

1,646 ?

ft3/min 1,946

30

90 ft/h

______________

.'

ig u r e

52.

Chem

i c a l t a n k a n d p u m p p r c i r c u l a t i n g

w it h fo a m

enters the well a t a rate of more than 50 barrels

per hour, it may be necessary to resort to drilling with aerated mud.

Workover
Circulating Systems

Use of Aerated Mud

Circulating Fiuid

A erated mud is employed when sizable

amounts of w a te r - th a t is, more w ater than can
be handled with foaming a g e n ts -e n te r a hole
being drilled with air, or when there is a problem
of lost circulation. A erated mud may also be
used when drilling through coral or cavernous
limestone formations in situations th at make
normal mud circulation impossible.

A rotary workover rig, which is actually a

light-duty drilling rig, often employs clear w ater
as the circulating medium. Even if this w ater is
dark colored or muddy looking, it is called clear
w ater around oil fields if it has few solids to settie out of suspension and does not gel, or stiffen,
when not flowing. Most workovers are performed with salt w ater because it is usually available

37

in toe field and because it does less damage to

reservoir formations than fresh w ater. Regular
drilling mud is employed if well pressure is expected to be high. If toe well must be deepened
and therefore a new form ation m ust be drilled,
drilling mud is used because cuttings m ust be
carried to toe surface and heavy fluid to control
form ation pressure may be required. In some
cases, foam or aerated mud m ust be used as toe
circulating fluid.

Route of Circulation and Equipment

Circulation for a workover is usually conventio n a l-th a t is, down toe drill stem and up toe
annulus (fig. 53). However, on many workover
jobs it is desirable to employ reverse circulation.
In such cases, toe blowout preventer is closed
around toe drill stem, and fluid flow is directed

F ig u r e 53. C ir c u la t io n s y s te m

f o r a w o rk o v e r rig

down the annulus, up the drill stem, through the

hose, and back to the tank.
Regardless of whether conventional or reverse circulation is used, fluid retu rn from the
wellhead to the tank is through a pipe th at is 2
or 3 inches in diam eter. The settling and suction
pits are usually combined in one tank. Mixing of
dry mud is kept to a minimum, and chemical
treatm ent is seldom required. A reserve pit is
seldom needed because shale or sand disposal is
not a major requirem ent and there is usually not
much w astew ater. Most heavy-duty workover
rigs are provided with a shale shaker, which is
usually mounted on the mud tank.
The addition of air to the mud being pumped
into the well lowers the hydrostatic pressure of
the fluid in the annulus to less
formation
pressure and speeds up the rate of penetration.
The hydrostatic pressure is lowered to the point
a t which circulation is still possible, but some
form ation fluid will enter the well. In some instances the amount of formation fluid removed
in this m anner has been more than 1,000 barrels
per hour.
Form ation fluid removed in this m anner may
not be salty, but the presence of air causes considerable corrosion unless inhibiting chemicals
are employed. The usual treatm ent is to add
lime to the w ater being pumped into the hole.
The mud is aerated by injecting high-pressure
air produced by compressors (usually a t about
1,000 psi) into the standpipe. The air-mud mixture goes down the drill stem and returns up the
annulus. Because the air expands on its way to
the surface, the column of mud is lightened and
flows out of the well. J e t collars placed in the
drill stem perm it some of toe compressed air to
return to toe surface before it reaches toe bit.
For aeration, a mud m ust be of good quality
and have low gel strength so th at air can easily
break out. The mud is recycled, so it m ust be
deaerated after each circulation for handling by
toe mud pumps.
In drilling with aerated mud, sufficient casing
m ust be set. Annular velocity is so g reat th at it
may destroy an open hole unless the formation
is hard rock.

GLOSSARY

acidize v: to treat oil-bearing limestone or other formations,

using a chemical reaction with acid, for the purpose of increasing production. Hydrochloric or other acid is injected
into the formation under pressure. The acid etches the rock,
enlarging the pore spaces and passages through which the
reservoir fluids flow. The acid is held under pressure for a
period of time and then pumped out, and the we'll is swabbed
and put back into production. Chemical inhibitors combined
with the acid prevent corrosion of the pipe.
aeration : the technique of injecting air or gas into a fluid.
For example, air is injected into drilling fluid to reduce the
density ol' th fluid.
annular space n: 1. the space surrounding a cylindrical ol) within a cylinder. 2. the space around a pipe in a
wellbore, the outer wall of which may be the wall of either
the borehole or the casing; sometimes termed the annulus.
annulus n: also called annular space. See annular space.

back-presssure n: 1. the pressure maintained on equipment

or systems through which a fluid flows. 2. in reference to
engines, a term used to describe the resistance to exhaust
gas flow through the exhaust pipe.
ball up v: to collect a mass of sticky consolidated material,
usually drill cuttings, on drill pipe, drill collars, tool joints,
and so forth. A b it w ith such m aterial a tta ch e d to it is term ed
a balled-up bit. The condition frequently is a result of inadequate pump pressure or !!Sufficient drilling fluid.
barite or baryte n: barium sulfate, BaS04, a mineral foequently used to increase the weight or density of drilling
mud. Its specific gravity is 4.2 (i.e., it is 4.2 times heavier
than water).
bearing 1 ;. an object, surface, or point that supports. 2. a
machine part in which another part (such as a journal or
pin) turns or slides.
bentonite n: a colloidal clay, composed primarily of montmorillonite, that swells when wet. Because of its gel-forming
properties, bentonite is a major component of drilling muds.
See gel and
bit n: the cutting or boring element used in drilling oil and
gas wells. The bit consists of a cutting element and a circulating element. The circulating element permits the
passage of drilling fluid and utilizes foe hydraulic force of foe
fluid stream to improve drilling rates. In rotary drilling,
several drill collars are joined to the bottom end of foe drill
pipe column. The bit is attached to foe end of the drill collar.
Most bits used in rotary drilling are roller cone bits.
blooey line n: foe discharge pipe from a well being drilled by
air drilling. The blooey line is used to conduct the air or gas
used for circulation away from the rig to reduce foe fire

hazard as well as to transport the cuttings a suitable distance

from the well.
blowout n: an uncontrolled flow of gas, oil, or other well
fluids into the atmosphere. A blowout, or gusher, occurs
when formation pressure exceeds the pressure applied to it
by the column of drilling fluid. A kick warns of an impending
blowout. See kick.
blowout preventer n: one of several valves installed at the
wellhead to prevent the escape of pressure either in the annular space between the casing and drill pipe or in open hole
(hole with no drill pipe) during drilling completion operations. Blowout preventers on land rigs are located beneath
the rig at the lands surface; on jackup platform rigs, they
are located at the waters surface; and on floating offshore
rigs, on the seafloor.
borehole n: the wellbore; the hole made by drilling or boring.
See wellbore.
breakover ;the change in the chemistry of a mud from one
type to another; also called a conversion.

casing n: steel pipe placed in an oil or gas well as drilling

progresses to prevent the wall of the hole from caving in during drilling and to provide a means of extracting petroleum if
the well is productive.
cementing n: the application of a liquid slurry of cement and
water to various points inside or outside the casing.
centrifugal force n: the force that tends to pull all matter
from the center of a rotating mass.
centrifugal pump n: a pump with an impeller or rotor, an
impeller shaft, and a casing, which discharges fluid by centrifugal force.
centrifuge n: a machine that uses c e n tr ifu g a l force to
separate substances of varying densities; also called the
shake-out or grind-out machine. A centrifuge is capable of
spinning substances at high speeds to obtain high centrifugal
forces.
chain drive n: a mechanical drive using a driving chain and
chain gears to transmit power. Power transmissions use a
roller chain, in which each link is made of side bars,
transverse pins, and rollers on the pins. A double roller chain
is made of two connected rows of links, a triple roller chain
of three, and so forth.
circulation n: the movement of drilling fluid out of the mud
pits, down the drill stem, up the annulus, and back to the
mud pits.
complete a well v: to finish work on a well and bring it to
productive status. See well completion.
compressor n: a device that raises the pressure of a compressible fluid such as air or gas. Compressors create a
pressure differential to move or compress a vapor or a gas.

39

consuming power in the process. They may be positivedisplacement compressors 0 nonpositive-displacement compressors.
condition v: to treat drilling mud with additives to give it
certein properties. Sometimes the term applies to water
used in boilers, drilling operations, and so on. To condition
and circulate mud is to ensure that additives are distributed
evenly throughout a system by circulating the mud while it is
being conditioned.
conversion n: the change in tee chemistry of a mud from
one type to another; also called a breakover. Reasons for
making a conversion may be (I) to maintain a stable
wellbore, (2) to provide a mud that will tolerate higher
weight 0 density, (3) to drill soluble formations, and (4) to
provide protection to producing zones.
core n: a cylindrical sample taken from a formation for
geolo^cal analysis. Usually a conventional core barrel is
substituted for tee bit and procures a sample as it penetrates
the formation, v: to obtain a formation sample for analysis.
corrosion n: a complex chemical or electrochemical process
by which metal is destroyed through reaction with its environment. For example, rust is corrosion.
cuttings n pi: the fragments of rock dislodged by the bit and
brought to the surface in tee drilling mud. Washed and dried
samples of the cuttings are analyzed by geologists to obtain
information about the formations drilled
cylinder n: 1. the unit of an internl-combuston engine in
which combustion and compression take place. 2. a chamber
in a pump from which the piston expels fluid.

degasser n: tee device used to remove unwanted gas from a

liquid, especially from drilling fluid.
density n: the mass or weight of a substance per unit
volume. For instance, the density of a drilling mud may be
10 pounds per gallon (ppg), 74.8 pounds per cubic foot
(lb/ft3), or 1 198.2 kilograms per cubic metre (kg/m3).
derrickman n: tee crew member who handles the upper end
of the drill string as it is being hoisted out of or lowered into
the hole. He is also responsible for tee circulating machinery
and the conditioning of the drilling fluid.
desander n: a centrifugal device for removing sand from
drilling fluid to prevent abrasion of the pumps. It may be
operated mechanically () by a fast-moving stream of fluid inside a special cone-shaped vessel, in which case it is
sometimes called a '
Compare desilter.
desilter n: a centrifugal device for removing very fine partides, or silt, from drilling fluid to keep tee amount of solids
in the fluid at the lowest possible point. Usually, the lower
the solids content of mud, the faster is the rate of penetration. A desilter works on the same principle as a desander.
downhole mud motor n: also called a turbodrill. See turbodrill.
drill collar n: a heavy, thick-walled tube, usually steel, used
between the drill pipe and the bit in tee drill stem to provide
a pendulum effect to the drill stem and weight to the bit.
drilling fluid n: circulating fluid, one function of which is to
force cuttings out of the wellbore and to the surface, ft also
serves to cool the bit and counteract downhole formation
pressure. While a mixture of clay, barite, water, and

40

chemical additives is the most common drilling fluid, wells

can also be drilled using air, gas, water, or oil-base mud as
the drilling fluid. Also called circulating fluid. See mud.
drill pipe : the heavy seamless tubing used to rotate the bit
and circulate the drilling fluid. Joints of pipe approximately
30 feet long are coupled together by means of tool joints.
drill stem n: all members in the assembly used for drilling by
the rotary method from tee swivel to the bit, including the
kelly, drill pipe and tool joints, drill collars, stabilizers, and
various specialty items. Compare drill string.
drill string n: the column, or string, of drill pipe with
attached tool joints that transmits fluid and rotational power
from the kelly to the drill collars and bit. Often, especially in
the oil patch, the term is loosely applied to both drill pipe and
drill collars. Compare drill stem.
duplex pump n: a reciprocating pump having two pistons or
plungers, used extensively as a mud pump on drilling rigs.

electric log n: also called an electric well log. See electric

well log.
electric well log n: a record of certain electrical
characteristics of formations traversed by tee borehole,
made to identify the formations, determine the nature and
amount of fluids they contain, and estimate tee' depth. Also
called an electric log or electric survey,
emulsifying agent n: material added to solid-in-liquid or
liquid-in-liquid suspensions to separate the individual
suspended particles. Also called disperse or emulsifier.
emulsion n: a mixture in which one liquid, termed tee
dispersed phase, is uniformly distributed (usually as minute
globules) in another liquid, called the continuous phase or
dispersion medium. In an oil-water emulsion, tee oil is the
dispersed phase and the water the dispersion medium; in a
water-oil emulsion, the reverse holds. A typical product of oil
wells, water-oil emulsion is also used as a drilling fluid.
electrolytic property n: tee ability of a substance, usually in
solution, to conduct an electric current.

filter cake n: 1. compacted solid or semisolid material remaining on a filter after pressure filtration of mud with tee
standard filter press. Thickness of the cake is reported in
thirty-seconds of an inch or in millimetres. 2. the layer of
concentrated solids from the drilling mud that forms on the
wells of the borehold opposite permeable formations; also
called wall cake or mud cake.
filter press n: a device used in the testing of filtration properties of drilling mud. See mud.
filtrate n: a fluid that has been passed through a filter.
fishtail bit n: a drilling bit with cutting edges of hard alloys;
also called a drag bit. First used when tee rotary system of
drilling was developed about 1000, it is still useful in drilling
very soft formations.
flash point n: the temperature at which a petroleum product
ignites momentarily but does not burn continuously.

flocculation n: the coagulation of solids in a drilling fluid

produced by special additives or by contaminants,
formation n: a bed or deposit composed throughout of
substantially the same kind of rock; a lithologic unit. Each
different formation is given a name, frequently as a result of
the study of the formation outcrop at the surface and
sometimes based on fossils found in the formation.
formation fluid n: fluid (such as gas, oil, or water) that exists in a subsurface rock formation.

I
internal-combustion engine n: a heat engine in which the
pressure necessary to produce motion of the mechanism
results from the ignition or burning of a fuel-air mixture
within the engine cylinder.

gas-cut mud n: a drilling mud that has entrained formation

gas, giving the mud a characteristically fluffy texture. When
entrained gas is not released before the fluid returns to the
well, the weight 0' density of the fluid column is reduced.
Because a large amount of gas in mud lowers its density,
gas-cut mud must be treated to lessen the chance of a
blowout.

jet n: 1. a hydraulic device operated by pump pressure to

clean mud pits and tanks in rotary drilling and to mix mud
components. 2. in a perforating gun using shaped charges, a
highly penetrating, fast-moving stream of exploded particles
that cuts a hole in the casing, cement, and formation.
jet bit n: a drilling bit having replaceable nozzles through
which the drilling fluid is directd in a high-velocity stream to
the bottom of the hole to improve the efficiency of the bit.

gel n: a semisolid, jellylike state assumed by some colloidal

dispersions at rest. When agitated, the gel converts to a fluid
state, v: to take the form of a gel; to set.
gel strength n: a measure of the ability of a colloidal dispersion to develop and retain a gel form, based on its

to shear. The gel strength, or shear strength, of a drilling
mud determines its ability to hold solids in
'
Sometimes bentonite and other colloidal clays are added to
drilling fluid to increase its gel strength.

hammer drill n: a drilling tool that, when placed in the drill

stem just above a roller cone bit, delivers
percussion blows to the rotating bit. Hammer drilling combines the basic features of rotary and cable-tool drilling (i.e.,
bit rotation and percussion), v: to use such a tool.
hopper n: a large funnel- or core-shaped device into which
dry components (such as powdered clay or cement) can be
poured in order to uniformly mix the
' with
water (or other liquids). The liquid is injected through a nozzle at the bottom of ^he hopper. The resulting mixture of dry
material and liquid may be drilling mud to be used as the circulating fluid in a rotary drilling operation or may be cement
slurry used to bond casing to the borehole.
hydraulic adj: 1. of or relating to water or other liquid in
motion. 2. operated, moved, or effected by water or liquid.
hydrostatic head n: the pressure exerted by a body of water
at rest. The hydrostatic head of fresh ^ ^ is 0.433 psi per
foot of height. Those of other liquids may be determined by
comparing their gravities with the gravity of water. See
pressure gradient.
hydrostatic pressure n: the force exerted by a body of fluid
at rest; hydrostatic pressure increases directly with the
weight and depth of the fluid. In drilling, the term refers to
the pressure exerted by the drilling fluid in the wellbore. See
hydrostatic head.

kelly n: the heavy steel member, three-, four-, or six-sided,

suspended from the swivel through the rotary table and connected to the topmost joint of drill pipe to turn the drill stem
as the rotary table turns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa.
kick n: an entry of water, gas, oil, or other formation fluid
into the wellbore. It occurs because the pressure exerted by
the column of drilling fluid is not great enough to overcome
the pressure exerted by the fluids in the formation drilled. If
prompt action is not taken to control the kick or kill the well,
a blowout will occur. See blowout.

liner n: 1. any string of casing whose top is located below the

surface. A liner may serve as the oil string, extending from
the producing interval up to the next string of casing. 2. in
jet-perforating guns, a conically shaped metallic piece that is
part of a shaped charge. It increases the efficiency of the
charge by increasing the penetrating ability of the jet. 3. a
replaceable tube that fits inside the cylinder of an engine or a
pump.
lost circulation n: the loss of quantities of whole mud to a
formation, usually in cavernous, fissured, or coarsely
permeable beds, evidenced by the complete or partial failure
of the mud to return to the surface as it is being circulated
the hole. Lost circulation can lead to a blowout and, in
general, reduce the efficiency of the drilling operation. It is
also called lost returns. See blowout.

M
manifold : an accessory system of piping to a main piping
system (or another conductor) that serves to divide a flow

41

into several parts, to combine several flows into one, or to

reroute a flow to any one of several possible destinations.
mix mud v: to prepare drilling fluids from a mixture of water
or other liquids and one or more of the various dry mudmaking materials (such as clay, weighting materials,
chemicals, and so forth).
mousehole n: an opening through the rig floor, usually lined
with pipe, into which a length of drill pipe is placed temporarily for later connection to toe drill string.
mud n: toe liquid circulated through the wellbore during
rotary drilling and workover operations. In addition to its
function of bringing cuttings to toe surface, drilling mud
cools and lubricates the bit and drill stem, protects against
blowouts by holding back subsurface pressures, and deposits
a mud cake on toe wall of toe borehole to prevent loss of
fluids to toe formation. Although it originally was a suspension of earth solids (especially clays) in water, the mud used
in modern drilling operations is a more complex, three-phase
mixture of liquids, reactive solids, and inert solids. The liquid
phase may be fresh water, diesel oil, or crude oil and may
contain one or more conditioners. See drilling fluid.
mud additive n: any material added to drilling fluid to
change some of its characteristics or properties,
mud balance n: a beam balance consisting of a cup and a
graduated arm carrying a sliding weight and resting on a
fulcrum, used to determine toe density or weight of drilling
mud.
mud cake n: the sheath of mud solids that forms on toe wall
of the hole when toe liquid from toe mud filters into toe formation; also called wall cake or filter cake.
mud conditioning n: toe treatment and control of drilling
mud to ensure that it has toe correct properties. Conditioning may include toe use of additives, the removal of sand or
other solids, the removal of gas, the addition of water, and
other measures to prepare the mud for conditions encountered in a specific well.
mud engineer n: a person whose duty is to test and maintain
toe properties of the drilling mud that are specified by toe
operator.
mud flow indicator n: a device that continually measures
and sometimes records the flow rate of mud returning from
the annulus and flowing out of the mud return line. If toe
mud does not flow at a fairly constant rate, a kick or lost circulation may have occurred.
mud-gas separator n: a device that separates toe gas from
the mud coming out of a well when gas cutting occurs or
when a kick is being circulated out.
mud gun n: a pipe that shoots a jet of drilling mud under
high pressure into toe mud pit to mix additives with toe mud
or to agitate the mud.
mud logging n: toe recording of information derived from
examination and analysis of formation cuttings made by the
bit and mud circulated ut of toe hole. A portion of the mud
is diverted through a gas-detecting device. Cuttings brought
up by the mud are examined under ultraviolet light to detect
the presence of oil or gas. Mud logging is often carried out in
a portable laboratory set up at toe well.
mud pits n pi: a series of open tanks, usually made of steel
plate, through which the drilling mud is cycled to allow sand
and sediments to settle out. Additives are mixed with the
mud in the pits, and toe fluid is temporarily stored toere
before being pumped back into toe well. Modern rotary drilling rigs are generally provided with three or more pits,
usually fabricated steel tanks fitted with built-in piping,

valves, and mud agitators. Mud pits are also called shaker
pits, settling pits, and suction pits, depending on their main
purpose. Also called mud tanks.
mud pump n: a large reciprocating pump used to circulate
the mud on a drilling rig. A typical mud pump is a single- or
double-acting, or three-cylinder piston pump whose
pistons travel in replaceable liners and are driven by a
crankshaft actuated by an engine or motor. Also called a
slush pump.
mud return line n: a trough or pipe placed between the surface connections at the wellbore and the shale shaker,
through which drilling mud flows upon its return to the surfrom the hole.

oil-base mud n: an oil mud that contains from less than 2

percent up to 5 percent water. The water is spread out, or
dispersed, in the oil as small droplets.
ol-emulsion mud n: a water-base mud in which water is the
continuous phase and oil is the dispersed phase. The oil is
spread out, or dispersed, in the water in small droplets,
which are tightly emulsified so that they do not settle out.
Because of its lubricating abilities, the use of an "
mud increases the drilling rate and ensures better hole conditions than other muds. Compare oil mud.
oil mud n: a drilling mud in which oil is the continuous phase.
Oil-base mud and invert-oil mud are types of oil muds. They
are useful in drilling certain formations that may be difficult
or costly to drill with water-base mud. Compare oil-emulsion
mud.
operator n: the person or company, either proprietor or
lessee, actually operating an oilwell or lease. Generally, the
oil company by whom the contractor is engaged.

permeability n: 1. a measure of toe ease with which fluid can

flow through a porous rock. 2. toe fluid conductivity of a
porous medium. 3. the ability of a fluid to flow within the interconnected pore network of a porous medium.
pH value n: a unit of measure of toe acid or alkaline condition of a substance. A neutral solution (like pure water) has a
pH of 7; acid solutions are less than 7; basic, or alkaline, solutions are above 7. The pH scale is a logarithmic scale; a
substance with a pH of 4 is more than twice as acid as a
substance with a pH of 5. Similarly, a substance with a pH of
9 is much more than twice as alkaline as a substance with a
pH of 8.
pressure gradient n: a scale of pressure differences in which
toere is a uniform variation of pressure from point to point.
For example, toe pressure gradient of a column of water is
about 0.433 psi/ft of vertical elevation. The normal pressure
gradient in a formation is equivalent to the pressure exerted
at any given depth by a column of 10 percent salt water extending from that depth to the surface (0.465 ps/ft).

rate of penetration n: a measure of the speed at which the

bit drills into formations, usually expressed in feet per hour,
resistivity n: toe electrical resistance offered to toe passage
of current; the opposite of conductivity.
rig manager n: an employee of a drilling contractor who is in
charge of the entire drilling crew and toe drilling rig. Also
called a toolpusher, drilling foreman, rig supervisor, or rig
superintendent.
rig up ; to prepare the drilling rig for making hole; to install
tools and machinery before drilling is started,
rotary drilling n: a drilling method in which a hole is drilled
by a rotating bit to which a downward force is applied. The
bit is fastened to and rotated by toe drill stem, which also
provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as toe drillmg progresses.
rotary hose n: a reinforced, flexible tube on a rotary drilling
rig that conducts the drilling fluid from the mud pump and
standpipe to the swivel and kelly; also called the mud hose or
the kelly hose.
rotary table n: toe principal component of a rotary, or
rotary machine, used to turn the drill stem and support toe
drilling assembly, ft has a beveled gear arrangement to
create toe rotational motion and an opening into which
bushings are fitted to drive and support toe drilling
assembly.
rotating blowout preventer n: also called rotating head.
See rotating head.
rotating head : a sealing device used to close off toe annular space around the kelly when drilling with pressure at
toe surface, usually installed above toe main blowout
preventers. A rotating head makes it possible to drill ahead
even when there is pressure in the annulus that toe weight of
toe drilling fluid is not overcoming; toe head prevents toe
well ! blowing out. It is used mainly in the drilling of formations that have low permeability. The rate o ^ n e tr a tio n
through such formations is usually rapid.

s
shale n: a fine-grained sedimentary rock composed of consolidated silt and clay or mud. Shale is the most frequently
occurring sedimentary rock.
shale shaker n: a series of trays with sieves that vibrate to
remove cuttings from toe circulating fluid in rotary drilling
operations. The size of the openings in the sieve is carefully
selected to match toe size of the solids in the drilling fluid
and the anticipated size of cuttings. Also called a shaker.
shear n: action or stress that results from applied forces and
that causes or tends to cause two adjoining parts of a body to
slide relative to each other in a direction parallel to their
plane of contact.
single n: a joint of drill pipe.
specific gravity n: toe ratio of toe weight of a ^ ven volume
of a substance at a given temperature to the weight of an
equal volume of a standard substance at toe same
temperature. For example, if 1 cubic inch of water at 39F
weighs 1 unit and 1 cubic inch of another solid or liquid at
39F weighs 0.95 unit, then the specific gravity of toe

substance is 0.95. In determining the specific gravity of

gases, the comparison is made with the standard of air or
hydrogen.
spud in v: to begin drilling; to start the hole,
standpipe n: a vertical pipe rising along the side of the derrick or mast, which joins the discharge line leading from the
mud pump to the rotary hose and through which mud is
pumped going into the hole.
suction pit n: the mud pit from which mud is picked up by
the suction of the mud pumps; also called a sump pit or mud
suct^n pit.
swivel n: a rotary tool that is hung from the rotary hook and
traveling block to suspend and permit free rotation of the
drill stem. It also provides a connection for the rotary hose
and a passageway for the flow of drilling fluid into the drill
stem.

toolpusher n: an employee of a drilling contractor who is in

charge of the entire drilling crew and the drilling rig. Also
called a drilling foreman, rig manager, rig supervisor, or rig
superintendent.
transmission n: the gear or chain arrangement by which
power is transmitted from the prime mover to the
drawworks, mud pump, or rotary table of a drilling rig.
triplex pump n: a reciprocating pump with three pistons or
plungers.
turbodrill n: a drilling tool that rotates a bit attached to it by
the action of the drilling mud on the turbine blades built into
toe tool. When a turbodrill is used, rotary motion is imparted
only a t the bit; therefore, it is unnecessa ^to rotate toe drill
stem. Although straight holes can be drilled with the tool, it
is used most often in directional drilling.

V-belt n: belt with a trapezoidal cross section that is made to

run in sheaves, or pulleys, with grooves of corresponding
shape.
viscometer n: a device used to determine the viscosity of a
substance; also called a viscosimeter.
viscosity n: a measure of the resistance of a liquid to flow.
Resistance is brought about by toe internal friction resulting
from toe combined effects of cohesion and adhesion. The
viscosity of petroleum products is commonly expressed in
terms of the time required for a specific volume of the liquid
to flow through an orifice of a specific size.

w
wall cake n: also called filter cake or mud cake. See filter
cake.
water-back v: 1. to reduce the weight or density of a drilling
mud by adding water. 2. to reduce toe solids content of a
mud by adding water.

water-base mud n: a drilling mud in which continuous

phase is water. In water-base muds, any additives are
dispersed in the water. Compare oil-base mud.
weight up v: to increase the weight or density of the drilling
fluid by adding weighting material.
wellbore n: a borehole; the hole drilled by the bit. A wellbore
may have casing in it or may be open (uncased), or a portion
of it may be cased, and a portion of it may be open,
well completion n: the activities and methods necessary to
prepare a well for the production of oil and gas; the method
by which a flow line for hydrocarbons is established between
the reservoir and the surface. The method of well completion
used by the operator depends on the individual

44

characteristics of the producing formation or formations.

These techniques include open-hole comp)etions, sandexciusion completions, tubingless completions, multiple completions, and miniaturized completions.
wellhead n: the equipment installed at the surface of the
wellbore. A wellhead includes such equipment as the casinghead and tubing head, adj: pertaining to the wellhead
(e.g., wellhead pressure).
workover n: the performance of one or more of a variety of
remedial operations on a producing oilwell to try to increase
production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, squeeze cementing,
and so forth.

ANSWERS TO REVIEW QUESTIONS

LESSONS IN ROTAR DRILLING
Unit /, Lesson 8: Circulating System s

(1) Transporting cuttings to toe surface

(2) Cleaning the bottom of toe hole
(3) Cooling toe bit and lubricating toe drill stem
(4) Supporting toe walls of the well
(5) Preventing entry of formation fluids into the well
2. (1) Water
(2) Mud

I L ,,

14. (1) Mud pits should be cleaned thoroughly.

(2) W ater should be added to the mud to lower percentage of solids.
(3) Ail ehemicals should be positioned conveniently.
(4) Rig personnel should be given instructions concerning the rate at which materials are to added.
15. (1) How many sacks of barite are needed
(2) How fast these sacks should be added
16. Reducing mud weight by adding water

these fluids

3. (1) Mud pumps

(2) Rotary hose
(3) Swivel
(4) Drill stem
(5) Bit
(6) Mud return line
(7) Mud pits
(8) Compressors (for air drilling)
4. viscosity; gel strength
5. jet nozzles; turbulence
6. (1) Force exerted on adjacent bodies by a liquid standing
still
(2) By increasing the density of toe fluid
7. (1) Volume of fluid returning from toe hole increases.
(2) Mud continues to flow when toe pump is shut down.
8. Water-base mud
9. (1) Viscosity
(2) Ability to build filter cake
(3) Gel strength

17. Water decreases mud density, whereas chemicals do

not.
18. emulsifying agent
19. Flushing with water
26. (1) Mud pumps
(2) Rotary hose
(3) Swivel
(4) Drill stem
(5) Bit
(6) Annulus
(7) Mud pits
21. (1) To accumulate mud circulated from the well
(2) To supply fluid to the pump for circulation
(3) To store enough mud to fill the hole when pipe is
removed
22. (1) Shale shakers
(2) Mud agitators
(3) Degassers
(4) Desilters
(5) Desanders
(6) Mud centrifuges

10. lignosulfonate

23. (1) Duplex, double-acting

(2) Triplex, single-acting

11. Oil-base mud: less than 5 percent water

Invert-oil mud: from 10 to 50 percent water

24. (1) Surface equipment

(2) Drill stem
(3) Bit nozzles
(4) Return annulus

12. (1)C
(2)E

(3)B
(4)A
(5)F
(6)D
13. (1) To maintain a stable wellbore
(2) To provide a mud that will tolerate higher weight
(3) To drill soluble formations
(4) To provide protection to producing zones

25. (1) Air cannot prevent sloughing of the walls of the well,
and sticking of toe drill stem becomes likely.
(2) Air cannot exert enough pressure to prevent formation fluids from entering toe wellbore.
26. Foam causes the water to froth and foam into a large
volume and thus reduces toe pressure needed to move
the water out of the hole.
27. Salt water

 ,'