lyons (1996) standard handbook of petroleum and natural gas engineering v 2

STANDARD
WILLIAM
C.
LYONS
EDITOR
MEB
X
D
21
F=
STANDARD
HANDBOOK
OF
Engineering

STANDARD
HANDBOOK
OF
Engineering
WILLIAM
C.
LYONS,
PH.D.,
P.E.
EDITOR
Gulf Professional Publishing
an imprint
of
Butternorth-Heinemann
STANDARD
HANDBOOK

OF
ROLEUM
GAS
Engineering
Copyright
0
1996
by Butterworth-Heinemann. All rights reserved.
Printed in the United States of America. This book,
or
parts thereof,
may not be reproduced in any form without permission of the
publisher.
Originally published by Gulf Publishing Company,
Houston, TX.
10 9 8 7
6
5
4
3
2
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Manager of Special Sales
Butterworth-Heinemann
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Library
of
Congress Cataloging-in-Publication Data
Wobu, MA
01801-2041
Standard handbook of petroleum and natural gas engineering
/
[edited by William Lyons].
p. cm.
Includes bibliographical references and index.
ISBN
0-88415-642-7 (Vol.
l),
ISBN
0-88415-643-5
cV01.2)
1.
Petroleum engineering. 2. Natural gas.
I.
Lyons, William
(William C.)
TN870.S6233 1996
665.5-dc20 96- 13965

CIP
ISBN
0-88415-643-5
Printed on Acid-Free Paper
(-)
iV
Contributing Authors

vii
Preface
ix
5-Reservoir Engineering

1
Basic Principles, Definitions, and Data,
3
Formation Evaluation,
86
Pressure Transient Testing of Oil and Gas Wells,
214
Mechanisms and Recovery of Hydrocarbons
by Natural Means,
225
Material Balance and Volumetric Analysis,
228
Decline-Curve Analysis,
244
Reserve Estimates,
249
Secondary Recovery,

259
Fluid Movement in Waterflooded Reservoirs,
269
Estimating Waterflood Residual Oil Saturation,
30
1
Enhanced Oil Recovery Methods,
319
References,
344
6-Production Engineering

363
Properties of Hydrocarbon Mixtures,
365
Flow of Fluids,
426
Natural Flow Performance,
533
Artificial Lift Methods,
594
Stimulation and Remedial Operations,
664
Surface Oil Production Systems,
702
Gas Production Engineering,
754
Corrosion and Scaling, 889
Environmental Considerations, 939
Offshore Operations, 964

References, 971
7-Petroleum Economics

,

,

,

985
Estimating Oil and Gas Reserves, 987
Classification
of
Petroleum Products, 989
Methods for Estimating Reserves, 990
Non-Associated Gas Reservoirs, 99’7
Production Stimulation,
1004
Determining the Value of Future Production,
1010
The Market for Petroleum,
1010
Economics and the Petroleum Engineer,
1012
Preparation
of
a Cash Flow,
1012
Valuation
of

Oil and Gas Properties,
1023
Risk Analysis,
1025
References,
1030
Appendix: Units and Conversions (SI)

1035
Index

1049
Contributing Authors
Robert
4.
Col
it@
P.G.
Consultant in
Ecology
and Geophysics
Socorro, New Mexico
Micheal
J.
Economides, Ph.D.
Texas
A
&
M
University

College Station, Texas
Kazimierz Glowacki, Ph.D.
Consultant in Energy and Environmental Engineering
Krakow, Poland
Reza
G.
Kashmiri
International Lubrication and Fuel, Incorporated
Rio Rancho, New Mexico
Joseph
V.
LaBlanc
Consultant in Petroleum Engineering
Conroe, Texas
Julius P. Langlinais, Ph.D.
Louisiana State University
Baton Rouge, Louisiana
F.
David Martin
New Mexico
Institute
of
Mining and Technology
Socorro,
New Mexico
Richard J. Miller
Richard
J.
Miller and Associates, Incorporated
Huntington Beach, Calqornia

vii
Charles Nathan, Ph.D., P.E.
Consultant in Corrosion Engineering
Houston, Texas
Pudji Permadi, Ph.D.
Institut Teknologi Bandung
Bandung, Indonesia
Floyd
W.
Preston, Ph.D.
University
of
Kansas
Lawrence, Kansas
Chris
S.
Russell, P.E.
Consultant in Environmental Engineering
Grand Junction, Colorado
Oleg Salzberg
Consultant in Corrosion Engineering
Houston, Texas
Ardeshir
K.
Shahraki, Ph.D.
Dwight's Energy Data, Inc.
Richardson, Texas
Viii
Preface
This petroleum and natural

gas
engineering two-volume handbook
is written in the spirit of the classic handbooks of other engineering
disciplines. The two volumes reflect the importance of the industry
its engineers serve (i.e.,
Standard
and Poor’s
shows that the fuels sector
is the largest single entity in the gross domestic product) and the
profession’s status as a mature engineering discipline.
The project to write these volumes began with an attempt to
revise the old
Practical Petroleum Engineer’s Handbook
that Gulf
Publishing had published since the
1940’s.
Once the project was
initiated, it became clear that any revision of the old handbook
would be inadequate. Thus, the decision was made to write an
entirely new handbook and to write this handbook in the classic
style of the handbooks
of
the other major engineering disciplines.
This meant giving the handbook initial chapters on mathematics
and computer applications, the sciences, general engineering, and
auxiliary equipment. These initial chapters set the tone of the
handbook by using engineering language and notation common
to all engineering disciplines. This common language and notation
is used throughout the handbook (language and notation in nearly
all cases is consistent with Society of Petroleum Engineers publication

practices). The authors, of which there are
2’7,
have tried (and we
hope succeeded) in avoiding the jargon that had crept
into
petroleum
engineering literature over the past few decades. Our objective was
to create a handbook for the petroleum engineering discipline that
could be read and understood by any up-to-date engineer.
The specific petroleum engineering discipline chapters cover
drilling and well completions, reservoir engineering, production, and
economics and valuation. These chapters contain information, data,
and example calculations related
to
practical situations that petroleum
engineers often encounter. Also, these chapters reflect the growing
role of natural gas in industrial operations by integrating natural
gas topics and related subjects throughout both volumes.
This
has been a very long and often frustrating project. Through-
out the entire project the authors have been steadfastly cooperative
and supportive of their editor. In the preparation of the handbook
the authors have used published information from both the American
Petroleum Institute and the Society of Petroleum Engineers. The
authors thank these two institutions for their cooperation in the
preparation
of
the final manuscript. The authors would also like
to thank the many petroleum production and service companies
that have assisted in this project.

In the detailed preparation of this work, the authors would like
to thank Jerry Hayes, Danette DeCristofaro, and the staff of
ExecuStaff Composition Services for their very competent prepara-
tion of the final pages. In addition, the authors would like to thank
Bill Lowe of Gulf Publishing Company for
his
vision and perseverance
regarding this project; all those many individuals that assisted in
the typing and other duties that are
so
necessary for the prepara-
tion
of
original manuscripts; and all the families of the authors that
had to put up with weekends and weeknights of writing. The
editor would especially like to thank the group of individuals that
assisted through the years in the overall organization and preparation
of the original written manuscripts and the accompanying graphics,
namely; Ann Gardner, Britta Larrson, Linda Sperling, Ann Irby,
Anne Cate, Rita Case, and Georgia Eaton.
All the authors and their editor know that this work is not
perfect. But we also know that this handbook had to be written.
Our greatest hope is that we have given those that will follow us, in
future editions of this handbook, sound basic material
to
work with.
William
C.
Lyons, Ph.D.,
P.E.

Socorro, New Mexico
X
STANDARD
HANDBOOK
OF
Engineering

5
Reservoir Engineering
F.
David
Martin
New Mexico Institute of Mining and Technology
Socorro, New Mexico
Robert
M.
Colpitts,
P.G.
Consultant, Geology and Geophysics
Socorro, New Mexico
Basic Principles, Definitions, and Data

3
Reservoir Fluids
3.
Fluid Viscosities
7.
Formation Volume Factors
12.
Fluid Compressibilities

20.
Estimating Fluid Properties Using Computers
27.
Properties of Fluid-Containing Rocks
35.
Porosity
33.
Pore Volume
35.
Permeability
36.
Capacity
38.
Transmissibility
38.
Resistivity and
Electrical Conductivity
38.
Rock Compressibility
49.
Properties of Rocks Containing Multiple
Fluids
32.
Total Reservoir Compressibility
52.
Resistivity Index
53.
Surface and Interfacial
Tension
58.

Wettability and Contact Angle
61.
Capillary Pressure
68.
Effective Permeabilities
72.
Relative Permeabilities
76.
Effect of Wettability on Fluid
Rock
Properties
79.
Formation Evaluation

86
Coring and Core Analysis
86.
Drill Stem Tests
108.
Logging
109.
Influences on Logs
118.
Openhole Logs and Interpretation
122.
Determination of Initial Oil and Gas in Place
208.
Productivity Index
210.
Pressure Transient Testing of Oil and Gas Wells

214
Mechanisms and Recovery of Hydrocarbons by Natural
Means

225
Definitions and Concepts
214.
Important Pressure Transient Analysis Equations
222.
Petroleum Reservoir Definitions
225.
Natural Gas Reservoirs
225.
Primary Recovery of Crude
Oil
225.
Primary Recovery Factors in Solution-Gas-Drive Reservoirs
228.
Material Balance and Volumetric Analysis

228
Material Balance for Gas Reservoirs
231.
Material Balance Equations in Oil
or
Combination
Reservoirs
233.
Generalized Material Balance Equation

234.
Material Balance for Solution-
Gas-Drive Reservoirs
237.
Predicting Primary Recovery in Solution-Gas-Drive Reservoirs
238.
Predicting Primary Recovery in Water-Drive Reservoirs
240.
Volumetric Calculations for Recovery
of Gas and Oil
241.
Decline-Curve Analysis

244
Exponential Decline
246.
Hyperbolic Decline
247.
Harmonic Decline
248.
Production Type
Curves
248.
Reserve Estimates

249
Definition and Classification of Reserves
249.
Methods of Estimating Reserves
254.

Quality
of Reserve Estimates
258.
Secondary Recovery

259
Fluid
Movement in Waterflooded Reservoirs

269
Definitions
259.
Gas Injection
260.
Water Injection
262.
Spacing of Wells and Well Patterns
262.
Displacement Mechanisms
269.
Viscous Fingering
275.
Mobility and Mobility Ratio
276.
Recovery
Efficiency
277.
Displacement Sweep Efficiency
279.
Volumetric Sweep Efficiency

279.
Permeability
Variation
284.
Estimation of Waterflood Recovery by Material Balance
292.
Prediction Methods
293.
Performance Evaluation
293.
1
4
Reservoir Engineering
Estimating Waterflood Residual Oil Saturation

301
Material Balance
301.
Well Test Analyses
302.
Coring and
Core
Testing
304.
Tracer Tests for
Determining Residual Oil
309.
Geophysical Well Logging Techniques
312.
Summary of Methods

for
Estimating Residual Oils
317.
Recommended Methods for Assessing Residual Oil
318.
Enhanced
Oil
Recovery
Methods
319
Definition
319.
Chemical Flooding
320.
Gas Injection Methods
323.
Thermal Recovery
326.
Technical Screening Guides
327.
Hydrocarbon Miscible Flooding
329.
Nitrogen and Flue
Gas
Flooding
330.
Carbon Dioxide Flooding
331.
Surfactant/Polymer Flooding
332.

Polymer
Flooding
332.
Alkaline Flooding
333.
In-Situ Combustion
334.
Steamflooding
335.
Laboratory
Design for Enhanced Recovery
342.
References

344
5
Reservoir Engineering
Reservoir engineering covers a broad range of subjects including the occurrence
of fluids in a gas or oil-bearing reservoir, movement of those
or
injected fluids,
and evaluation of the factors governing the recovery of oil or gas. The objectives
of a reservoir engineer are to maximize producing rates and to ultimately recover
oil and gas from reservoirs in the most economical manner possible.
This chapter presents the basic fundamentals useful to practical petroleum
engineers. Topics are introduced at a level that can be understood by engineers
and geologists who are not expert in this field. Various correlations are provided
where useful. Newer techniques for improving recovery are discussed.
The advent
of

programmable calculators and personal computers
has
dramatically
changed the approach of solving problems used by reservoir engineers. Many
repetitious and tedious calculations can be performed more consistently and
quickly than was possible in the past. The use of charts and graphs is being
replaced by mathematical expressions of the data that can be handled with
portable calculators or personal computers. Programs relating to many aspects
of petroleum engineering are now available. In this chapter, many of the charts
and graphs that have been historically used are presented for completeness and
for illustrative purposes. In addition, separate sections will be devoted to the
use
of
equations in some of the more common programs suitable for program-
mable calculators and personal computers.
BASIC PRINCIPLES, DEFINITIONS, AND DATA
Reservoir
Fluids
Oil
and
Gas
Reservoir oil may be saturated with gas, the degree of saturation being a
function, among others, of reservoir pressure and temperature. If the reservoir
oil has dissolved in it all the gas it is capable of holding under given conditions,
it is referred to as saturated oil. The excess gas is then present in the form of
a free gas cap. If there is less gas present in the reservoir than the amount that
may be dissolved in oil under conditions of reservoir pressure and temperature,
the oil is then termed undersaturated. The pressure at which the gas begins to
come out
of

solution is called the saturation pressure or the bubble-point
pressure. In the case of saturated oil, the saturation pressure equals the reservoir
pressure and the gas begins coming out
of
solution as
soon
as the reservoir
pressure begins to decrease. In the case
of
undersaturated oil, the gas does not
start coming out of solution until the reservoir pressure drops to the level of
saturation pressure.
Apart from its function as one of the propulsive forces, causing the flow of
oil through the reservoir, the dissolved gas has other important effects on
recovery of oil. As the gas comes out of solution the viscosity of oil increases
and its gravity decreases. This makes more difficult the flow of oil through the
reservoir toward the wellbore. Thus the need is quite apparent for production
a
4
Reservoir Engineering
practices tending to conserve the reservoir pressure and retard the evolution
of the dissolved gas. Figure
5-1
shows the effect of the dissolved gas on viscosity
and gravity of a typical crude oil.
The dissolved gas also has
an
important effect on the volume of the produced
oil.
As

the gas comes out of solution the oil shrinks
so
that the liquid oil at
surface conditions
will
occupy less volume than the gas-saturated oil occupied
in the reservoir. The number of barrels of reservoir oil at reservoir pressure
and temperature which will yield one barrel
of
stock tank oil at
60°F
and
atmospheric pressure is referred to as the formation volume factor or reservoir
volume factor. Formation volume factors are described in a subsequent section.
The solution gas-oil ratio is the number of standard cubic feet of gas per barrel
of stock tank oil.
Physical properties of reservoir fluids
are
determined in the laboratory, either
from bottomhole samples
or
from recombined surface separator samples.
Frequently, however, this information
is
not available. In such cases, charts such
as those developed by
M.B.
Standing and reproduced as Figures
5-2,
5-3,

54,
and
5-5
have been used to determine the data needed
[1,2].
The correlations
on which the charts are based present bubble-point pressures, formation volume
factors of bubble-point liquids, formation volume factors of gas plus liquid
phases, and, density of a bubble-point liquid as empirical functions of gas-oil
ratio, gas gravity, oil gravity, pressure, and temperature. More recent correlations
will be presented subsequently.
Until recently, most estimates of PVT properties were obtained by using charts
and graphs of empirically derived data. With the development of programmable
calculators, graphical data are being replaced by mathematical expressions
57
54
51
48
E
04
45
-
42
3
s
I-
U
39
E
36

33
Figure
5-1.
Change
in
viscosity and gravity
of
crude
oil
due
to
dissolved gas.
Basic Principles, Definitions, and Data
5
Figure
5-2.
Properties of natural hydrocarbon mixtures of gas and liquid:
bubble point pressure
[1,2].
Figure
5-3.
Properties
of
natural hydrocarbon mixtures of gas and liquid:
formation volume of bubble point liquids
[1,2].
6
Reservoir Engineering
MMPLE
Figure

5-4.
Properties of natural hydrocarbon mixtures of gas and liquid:
formation volume
of
gas plus liquid phases
[1,2].
Figure
5-5.
Properties of natural hydrocarbon mixtures of
gas
and liquid:
density and specific gravity of mixtures
[1,2].
Basic Principles, Definitions, and Data
7
suitable for computer use. In a later section, the use of such programs for
estimating PVT properties will be presented. In the initial sections, the presenta-
tion of graphical data will be instructive to gaining a better understanding of
the effect of certain variables.
Water
Regardless of whether a reservoir yields pipeline oil, water in the form
commonly referred to as interstitial or connate is present in the reservoir
in
pores small enough to hold it by capillary forces.
The theory that this water was not displaced by the migration of oil into a
water-bearing horizon is generally accepted as explanation of its presence.
The amount of the interstitial water is usually inversely proportional to the
permeability of the reservoir. The interstitial water content of oil-producing
reservoirs often ranges from 10% to
40%

of saturation.
Consideration of interstitial water content is of particular importance in
reservoir studies, in estimates of crude oil reserves and in interpretation of
electrical logs.
Fluid
Viscosities
Gas
Viscosity.
Viscosities of natural gases are affected by pressure, temperature,
and composition. The viscosity of a specific natural gas can be measured in
the laboratory, but common practice is to use available empirical data such as
those shown in Figures 5-6 and 5-7. Additional data are given in the
Handbook
of
Natural
Gas
Engineering
[3].
Contrary to the case for liquids, the viscosity of
a gas at low pressures increases as the temperature is raised. At high pressures,
gas viscosity decreases as the temperature is raised. At intermediate pressures,
gas viscosity may decrease as temperature is raised and then increase with
further increase in temperature.
Oil
Viscosity.
The viscosity of crude oil is affected by pressure, temperature,
and most importantly, by the amount of gas in solution. Figure 5-8 shows the
effect of pressure on viscosities
of
several crude oils at their respective reservoir

temperatures
[4].
Below the bubble-point, viscosity decreases with increasing
pressure because of the thinning effect of gas going into solution. Above the
bubble-point, viscosity increases with increasing pressure because of compression
of the liquid. If a crude oil is undersaturated at the original reservoir pressure,
viscosity will decrease slightly as the reservoir pressure decreases.
A
minimum
viscosity will occur at the saturation pressure. At pressures below the bubble-
point, evolution of gas from solution will increase the density and viscosity of
the crude oil as the reservoir pressure is decreased further.
Viscosities of hydrocarbon liquids decrease with increasing temperature as
indicated in Figure 5-9 for gas-free reservoir crudes [5]. In cases where only the
API gravity of the stock tank oil and reservoir temperature are known, Figure
5-9 can be used to estimate dead oil viscosity at atmospheric pressure. However,
a more accurate answer can be obtained easily in the laboratory by simply
measuring viscosity of the dead oil with a viscometer at reservoir temperature.
With the dead oil viscosity at atmospheric pressure and reservoir temperature
(either measured
or
obtained from Figure 5-9), the effect of solution gas can
be estimated with the aid of Figure 5-10 [6]. The gas-free viscosity and solution
gas-oil ratio are entered to obtain viscosity of the gas-saturated crude at the
bubble-point pressure. This figure accounts for the decrease in viscosity caused
a
m
v)
E
E

P,
Gos
qrovity
(air
=1.01
IC1
Basic
Principles, Definitions, and Data
9
Temperature, deg
F
Temperature,
deg
F
Figure
5-7.
Viscosity
of
natural gases as a function
of
temperature at four
gravities
[3].
10
Reservoir Engineering
PRESSURE.
psig
Figure
5-8.
Effect

of
pressure
on
crude
oil
viscosities
[4].
by
gas
going into solution as pressure is increased form atmospheric to the
saturation pressure.
If the pressure is above the bubble-point pressure, crude oil viscosity in the
reservoir can be estimated with Figure
51
1
[5]. This figure shows the increase in
liquid viscosity due to compressioon of the liquid at pressures higher than the
saturation pressure. Viscosity of the crude can be estimated from the viscosity at the
bubble point pressure, and the difference between reservoir pressure and bubble-
point pressure.
Recent correlations [7] were presented in equation form for the estimation of
both dead oil and saturated oil viscosities. These correlations, which are presented
in the section on programs for hand-held calculators, neglect the dependence of oil
viscosity on composition of the crude. If compositional data are available, other
correlations [S-101
for
oil viscosity can be used.
Water
Viscosity.
In 1952, the National Bureau of Standards conducted tests

[
111
which determined that the absolute viscosity of pure water was 1.0019 cp as
compared with the value of 1.005 cp that had been accepted for many years.
Effective July
1,
1952, the value of
1.002
cp for the absolute viscosity of water was
recommended
as
the basis for the calibration of viscometers and standard oil
samples. Any literature values based on the old standard are in slight error. Water
viscosity decreases
as
temperature is increased as shown in Table
5-1.
Basic
Principles, Definitions,
and
Data
11
J
0
-
W
w
IJ.
u)
0

a
a
I
IO
4
IIII
II
I
II
Ij
\
:\
\
RESERVOIR
CRUDE
OIL
GRAVITY,
'APl AT
60'F
AND ATMOSPHERIC PRESSURE
Figure
5-9.
Crude oil viscosity as
a
function
of
API
gravity
[5].
0.1

0.5
I
5
IO
50
100
VISCOSITY
OF
DEAD
OIL.
cp
(at reservoir ternperoture
and
otmospheric pressure
1
Figure
5-10.
Viscosities
of
gas-saturated crude oils at reservoir temperature
and bubble-point pressure
[6].
12
Reservoir Engineering
"I
UNDERSATURATED PRESSURE
,
psi
(Pressure above bubble
point

less
pressure
ot
bubble
point)
PRESSURE,
psi
-
>
Figure 5-11.
Increase in oil viscosity
with
pressure above bubble-point
pressure
[5].
Although the predominate effect on water viscosity is temperature, viscosity
of water normally increases as salinity increases. Potassium chloride is an
exception to this generality. Since most oilfield waters have a high sodium
chloride content, the effect of
this
salt
on
viscosity of water is given in Table
5-2.
For temperatures of interest in oil reservoirs (>60°F), the viscosity of water
increases with pressure but the effect is slight. Dissolved gas at reservoir
conditions should reduce the viscosity of brines; however, the lack of data and
the slight solubility of gas in water suggest that this effect is usually ignored.
Figure
5-12

is the most widely cited data for the effect of sodium chloride and
reservoir temperature on water viscosity
[
131.
Formatlon Volume Factors
These factors are used for converting the volume
of
fluids at the prevailing
reservoir conditions of temperature and pressure to standard surface conditions
of
14.7
psia
and
6OOF.