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Fourth Edition
P
ractical Well Control
By Ron Baker
published by
The University of Texas at austin
Division of Continuing & Innovative Education
PETROLEUM EXTENSION SERVICE
1998
Library of Congress Cataloging-in-Publication Data
Baker, Ron, 1940
Practical well control/by Ron Baker.—4th. ed.
p. cm.
ISBN 0-88698-183-2
1. Oil wells—blowouts. I. Baker, Ron. II. Title.
TN871.2.F547 1989 622'.3382—dc20 89-39589
CIP
© 1998 by The University of Texas at Austin
All rights reserved
First Edition published 1980. Fourth Edition 1998
Sixth Impression 2012
Printed in the United States of America
This book or parts thereof may not be reproduced in any form
without permission of Petroleum Extension Service, The University of Texas at Austin.
Brand names, company names, trademarks, or other identifying
symbols appearing in illustrations or text are used for educational
purposes only and do not constitute an endorsement by the
author or the publisher.
Catalog No. 2.80040
ISBN 0-88698-183-2
The University of Texas at Austin is an equal opportunity institution.
No state tax funds were used to publish this book.
C
ontents
Figures..................................................................................................................................................... v
Tables....................................................................................................................................................... vii
Foreword................................................................................................................................................. ix
1. Pressure Concepts......................................................................................................................... 1-1
2. Causes and Warning Signs of Kicks........................................................................................... 2-1
3. Shut-in Procedures and Shut-in Pressure.................................................................................. 3-1
4. Circulation and Well Control....................................................................................................... 4-1
5. Formation Fracture Gradient....................................................................................................... 5-1
6. Well-Control Methods.................................................................................................................. 6-1
7. Unusual Well-Control Operations.............................................................................................. 7-1
8. Well Control for Completion and Workover............................................................................. 8-1
9. Well Control and Floating Drilling Rigs.................................................................................... 9-1
10. Blowout Prevention Equipment.................................................................................................. 10-1
11. Organizing and Directing Well-Control Operations................................................................ 11-1
Appendix A. Hydrogen Sulfide Considerations............................................................................. A-1
H2S Guidelines for Offshore Operations.................................................................. A-2
H2S Guidelines for Land Operations........................................................................ A-5
Corrosion and H2S....................................................................................................... A-6
Appendix B. Reference Tables........................................................................................................... B-1
Appendix C. Equations....................................................................................................................... C-1
Appendix D. Cross-Reference Index and 30 CFR........................................................................... D-1
Appendix E. Cross-Reference Relating Elements in Practical Well Control to IADC WellCAP
Well-Control Accreditation Program................................................................................................... E-1
Glossary ................................................................................................................................................. G-1
Index........................................................................................................................................................ I-1
iii
Chapter
1
Pressure Concepts
practical well control
P
ressure Concepts
I
n well control, the two pressures of primary concern are formation pressure and hydrostatic
pressure. Formation pressure is the force exerted by fluids in a formation. It is measured at the
depth of the formation with the well shut in. It is also called reservoir pressure or, since it is
usually measured at the bottom of the hole with the well shut in, shut-in bottomhole pressure.
In drilling, hydrostatic pressure is the force exerted by
drilling fluid in the wellbore. When formation pressure is greater than hydrostatic pressure, formation
fluids may enter the wellbore. If formation fluids
enter the wellbore because formation pressure is
higher than hydrostatic pressure, a kick has occurred.
If prompt action is not taken to control the kick, or
kill the well, a blowout may occur. To control a well,
a proper balance between pressure in the formation
and pressure in the wellbore must be maintained;
hydrostatic pressure should be equal to or slightly
higher than formation pressure.
pressure, as it increases, compaction occurs, and the
porosity of the rock layer decreases.
As compaction occurs, any fluids in the formation
are squeezed into permeable layers, such as sandstone. If the permeable layer into which the fluids
are squeezed is continuous to the surface—that is,
if the layer eventually outcrops on the surface—
pressure higher than normal cannot form (fig. 1.1).
If, however, a layer’s fluid is trapped because of
faulting or some other anomaly, pressure higher
than normal can form; the formation can become
overpressured.
Origin of Formation Pressure
One generally accepted theory of how pressures
originate in subsurface formations relates to how
sedimentary basins are formed. As layer upon layer
of sediments are deposited, overburden pressure on
the layers increases, and compaction occurs. Overburden pressure is the pressure exerted at any given
depth by the weight of the sediments, or rocks, and
the weight of the fluids that fill pore spaces in the
rock. Overburden pressure is generally considered
to be 1 pound (lb) per square inch per foot (psi/
ft). Overburden pressure can vary in different areas
because the amount of pore space and the density of
rocks vary from place to place. In deepwater formations just below the seafloor, the overburden is almost
entirely seawater. Overburden pressure is therefore
about the same as the pressure caused by the weight
of seawater—about 0.45 psi/ft depending on its salinity. Regardless of the actual value of overburden
surface
outcrop
permeable
layer
Figure 1.1Pressure higher than normal cannot form if
the layer outcrops on the surface.
1-1
11-1
1-1
Pressure Concepts
Higher-than-normal formation pressure can result
from several geological conditions. In some cases,
the same conditions that trap hydrocarbons can
also cause higher-than-normal pressure. Examples
of such geological conditions are faults, large structures, massive shale beds, massive salt beds, and
charged sands.
Faults
Formation pressure normally increases with depth,
but deep rocks that have been faulted may have
higher-than-normal pressures. The fault may trap
fluids in the formation and allow abnormally high
pressure to develop. Since a fault is a sudden break
in a formation, when a faulted formation is drilled,
the bit may encounter abnormally high pressure
within a short interval; that is, it is possible to go
from normal pressure to abnormally high pressure
within a short time. Therefore, when faulted zones
are being drilled, the crew must be alert to the possibility of encountering abnormally high pressures
with very little warning. The high pressures that
appear at different depths in the Lake Arthur field
in South Louisiana are the result of a highly faulted
structure. High pressures encountered in drilling
next to salt domes are often the result of local faulting
around the dome. High pressures related to faulting
can also be found in mountainous country.
Large Structures
Any structure such as an anticline or dome may
have abnormally high pressures above the oil-water
or gas-water contact in the oil or gas zone because
hydrocarbons are less dense than water. If the anticline
or dome is large, abnormal pressures may be quite
high. Since anticlines and domes sometimes serve
as traps for hydrocarbons, drilling often takes place
on such structures. Thus, drilling crews should be
alert to the possibility of abnormally high pressures
in such situations.
High pressures may be expected when drilling into
the reservoir beds—usually sandstone, limestone,
or dolomite—of any structure. The high pressures
that were experienced in the early days of the East
Texas field came from an anticlinal structure. Since
large structures are often first drilled by the crew on
a wildcat well, the crew should be aware of the possibility of high pressure.
1-2
practical well control
Massive Shale Beds
Transition zones—formations in which pressures begin
to depart from normal—and abnormally high pressure
may develop within massive shale beds because thick,
impermeable shale restricts the movement of fluid. As
sediments are laid down on the surface and then sink
deeper, they support the considerable weight of the
overburden. Fluids trapped within the shale cannot
escape fast enough, and they also support the weight
of the overburden. Confined liquids supporting such
massive weight are under higher-than-normal pressure for the depth.
When thick shales are encountered, therefore, pressure should be expected to increase abnormally with
depth. Shale-related pressures can occur at any depth,
from near the surface to very deep. High pressures in
the U.S. Gulf Coast, the North Sea, the South China
Sea, and in other deep basins of the world are often
related to massive shale beds.
Massive Salt Beds
Since salt beds are plastic, they transmit all overburden
weight to the rock below. Therefore, high pressures
should be expected in and below thick salt beds. High
pressures usually are not found in thin and erratic
salt beds, however. Thick, plastic salt beds cause high
pressures in the Middle East in formations below the
Farrs salt, and in the United States in beds below the
Louann salt. Pressures in the Zechstein salt in the
North Sea and in northern Germany are also related
to the fact that salt transmits the rock weight above
it to the formation below it. Drilling mud with densities from 16 pounds per gallon (ppg) to 19 ppg may
be necessary to control the pressures within and just
below massive salt beds.
Charged Sands
Abnormally high formation pressure can be found in
relatively shallow sands that have become charged
from an underground blowout. A shallow sand can
become charged when a well is shut in on a kick
originating in a zone deeper than the sand. Pressure
from the lower zone then enters the wellbore and
escapes to the upper sand. As a result, the upper
sand becomes overpressured by the fluids from the
lower zone. Later, when another well is drilled into
the charged sand, the drilling crew may be caught
off guard when the charged sand kicks.
Pressure Concepts
practical well control
depth
(tvd)
Figure 1.2 Hole geometry has no effect on hydrostatic pressure. Pressure exerted at bottom is the static pressure.
Pressure exerted at bottom is the same for all containers because fluid density and depth are the same.
Hydrostatic Pressure
The term “hydrostatic” is derived from hydro, meaning water or liquid, and static, meaning at rest. Both
fluid in the formation and fluid in the wellbore are
under hydrostatic pressure, but in most well-control
discussions, formation pressure refers to fluid pressure in the formation; hydrostatic pressure refers to
the pressure of drilling fluid in the wellbore. Hydrostatic pressure increases directly with the density and
depth of the fluid in the wellbore. Hole geometry—the
diameter and shape of the fluid column—has no effect on hydrostatic pressure (fig. 1.2). In the wellbore,
hydrostatic pressure is the result of the weight, or
density, of the drilling fluid and the true vertical
depth of the column of fluid.
True vertical depth is the length of a straight vertical line from the surface to the bottom of the hole.
Measured, or total, depth is the length of the well as
measured along the actual course of the hole. Thus,
true vertical depth and measured depth can differ,
especially in directionally drilled holes (fig. 1.3). In
determining hydrostatic pressure, true vertical depth
is the measurement used.
measured
depth
10,500 ft
tvd
10,000 ft
Figure 1.3In this case, true vertical depth is different from
measured depth, because the hole is directionally drilled.
1-3
Pressure Concepts
practical well control
Mud weight can be expressed in ppg, pounds per
cubic foot (pcf), specific gravity, or other units. In the
United States, mud weight is usually expressed in ppg,
except on the Pacific Coast, where it is usually expressed
in pcf. If mud weight is measured in ppg, the value of
C in equation 1 is 0.052. If mud weight is measured
in pcf, the value of C in equation 1 is 0.00694. As an
example of using the equation, find the hydrostatic
pressure in a wellbore if the mud weight is 12 ppg and
the true vertical depth (TVD) is 11,325 ft.
HP = 0.052 × 12 × 11,325
= 7,066.8
HP = 7,067 psi.
Figure 1.4 Simple mud balance
Hydrostatic pressure can be calculated mathematically as—
HP = C × MW × TVD (Eq. 1)
where
HP = hydrostatic pressure, psi
C = a constant (value depends on unit used
to express mud weight)
MW = mud weight, ppg or other units
TVD = true vertical depth, ft.
To find hydrostatic pressure if the mud weight is
90 pcf and TVD is 11,325 ft, the calculation is—
HP = 0.00694 × 90 × 11,325
= 7,073.6
HP = 7,074 psi.
Measuring Mud Weight
Mud weight is usually measured with a simple mud
balance (fig. 1.4). It can also be measured, however,
with a special pressurized mud balance (fig. 1.5A
pressurization port
(check valve is under Port)
pressure
lid
Rider
balance arm
spirit level
cylinder
cup housing
(balance cup
inside)
knob
pump nose
pressurization pump
Figure 1.5A Pressurized mud balance (Courtesy Fann Instrument Company)
1-4
Pressure Concepts
practical well control
mud to be tested. Put the perforated cap on the cup
and rotate it until it is firmly seated. Be sure that some
of the mud comes out through the hole in the cap to
free any trapped air or gas. Hold the cap firmly on the
cup and, while keeping the hole covered, wash or wipe
the outside of the cup until it is clean and dry. Place
the balance arm (beam) on the fulcrum or base support
and balance it by sliding the weight along the beam’s
graduated scale. If the mud balance has a bubble, the
bubble will be directly under a center line etched on the
metal around the bubble when balance occurs. Read the
mud weight at the edge of the sliding weight.
Using a pressurized mud balance is very much
like using a regular mud balance except that the
mud sample is put under pressure to approximate
downhole conditions. Depending on the manufacturer of the balance, some type of pressure device is
secured to the sample cup to pressure up the sample.
A procedure from a manufacturer of a pressurized
mud balance follows. (Refer to Figure 1.5.)
PRESSURING
PUMP
SEALING
LID
CHECK
VALVE
lbs/gal
lbs/cu. ft.
7
50
SAMPLE CUP
ENTRAINED AIR
SLURRY
SAMPLE
Figure 1.5B Pressurized mud balance cutaway
and 1.5 B). Crewmembers may be instructed to use
a pressurized balance to obtain mud weight when
air or gas is entrained in the mud. Pressurizing the
balance’s sample cup decreases the volume of any
entrained air or gas in the mud to a negligible amount.
As a result, the mud density measurement will more
accurately reflect downhole conditions.
To use a regular mud balance, place the instrument
on a flat, level surface. Fill the clean, dry cup with the
1. Collect a fluid sample.
2. Place the balance’s stand or carrying case on a
flat, level surface.
3. Measure and record the temperature of the
sample, then transfer the sample to the balance
cup, filling to between ¼ and ⅛ in. of the top.
Tap the side of the cup several times to break
up any entrained air or gases.
4. Place the lid on the cup with the check valve
in the down or open position. (Some of the test
sample may be expelled through the valve.)
After fitting the lid onto the cup, pull the check
valve up into the closed position.
5. Rinse the pressurization port and balance with
water, base oil, or solvent; then dry it off.
6. Slide the cup housing over the balance cup from
the bottom, aligning the slot with the balance
arm. Screw the closure over the pressure lid and
tighten as tight as possible by hand to insure
that the pressure lid is completely seated.
7. Fill the pressurization pump with the test
sample.
8. Push the nose of the pump onto the pressure
port of the lid.
9. Pressure the sample cup by maintaining a downward force on the pump cylinder housing. At
the same time, force the pump knob down with
about 50 to 70 lb of force and release the cylinder
housing. Remove the pump. (The check valve
1-5