2. WELL LOGGING AND INTERPRETATION TECHNIQUES
The Course For Home Study
I. Log Interpretation Fundamentals: Open Hole
II. Study Guide
III. Induction Logs
IV. Electrolog(st)
V. Laterolog and Dual Laterolog
VI. Flushed Zone Resistivity Devices
VII. Spontaneous Potential Log
VIII. Gamma Ray Log
IX. Compensated Densilog'"
x. Acoustic Logs
XI. Neutron Logs
3. FOREWORD
Lop, Interpretation Fundamentals: Open Hole is a home study course
which covers the important basic elements of open hole log interpretation.
The emphasis is on log interpretation, not on tool measurement theory. The
first few lessons introduce relevant rock and fluid characteristics. Subse-
quent lessons present progressively more complex log interpretation tech-
niques. The number of interpretation techniques is kept to a minimum.
This is a lesson-by-Iesson course. Participants should study each lesson
and then answer the related questions. (A study guide has been provided).
Supplementary reading is suggested throughout the text. The text, along
with the supplementary reading, should provide a sound basis for basic
open hole log interpretation.
Comments or questions, regarding any of the course material, should be
made to Dresser Atlas sales or log analysis personnel worldwide.
6. TABLE OF CONTENTS CONTINUED
LESSON 18
Overview of Shale Content Evaluation 136
LESSON 19
Porosity and Clay Content Determination (Sand-Shale Sequences) 141
LESSON 20
Rwa Method: Fast Formation Evaluation 146
LESSON 21
Conductivity Derived Porosity (COP) 152
LESSON 22
The Formation Factor-Movable Oil Plot 161
LESSON 23
Hingle Crossplot 165
LESSON 24
Pickett Crossplot 175
LESSON 25
Water Saturation Determination (Sand-Shale) 179
LESSON 26
Predict Water Cut from Well Logs 188
LESSON 27
Computer Processed Interpretation 197
LESSON 28
Computer Generated Log Data 207
iv
7. INTRODUCTION TO ROCK PROPERTIES 1
INTRODUCIlON THE NATURE OF SEDIMENTARY ROCKS
Throughout geologic time, global tectonic activity Sedimentary rocks may be classified as having been
altered and continues to alter the earth's crust. This formed primarily by mechanical weathering (e.g. sand-
process has distilled out the lighter lower melting stones, conglomerates) or by chemical weathering
point materials which have accumulated on the sur- and/ or precipitation from solution. These altered parti-
face forming the continents. Sedimentary rocks have cles may then be transported or dissolved in a fluid and
evolved as a result of mechanical and chemical altera- deposited mechanically or precipitated chemically or
tion of these rocks through exposure to the surface biogenetically under specific chemical and physical con-
environment. Today, a thin veneer of sediments ditions. Sedimentary rocks are composed primarily of
almost entirely covers the earth's surface. The those minerals which are stable under normal conditions
generation of petroleum within this sedimentary rock of stress, temperature and pressure. Minerals normally
has been occurring on the earth since life evolved. A associated with igneous and metamorphic rocks which
small percentage of the total organic remains has were formed under abnormal conditions of stress,
escaped oxidation by burial beneath the surface in temperature or pressure may also occur with the
sediments. These organic remains, when sufficiently sedimentary rock. Of the 2,900 naturally occurring
concentrated and subjected to moderate levels of minerals now known, less than 200 occur in sufficient
geothermal heat and overburden pressure in an ox- amounts to be classified among the common rock-
ygen free environment, have evolved to form forming minerals. Of these, only two dozen or so
petroleum. The movement of pore fluids from source characterize the majority of sedimentary rocks.
rocks into porous and permeable reservoir rocks Sedimentary rocks may be grouped conveniently
where they were accumulated and trapped has into mechanically derived rocks, or clastics and
resulted in the hydrocarbon bearing reservoirs found chemically precipitated rocks. Chemically precipi-
today. tated rocks may be further subdivided into car-
Most of the world's petroleum occurs in sedimen- bonates and evaporites. (Fig. 1.1)
tary rocks. The location of petroleum reserves re-
quires an understanding of the nature of the rocks in Source
Rock
which these reserves occur, and well logs are one of
the primary sources for such data. Well logs are par-
I
I I
ticularly useful in the description and characteriza- Chemical Mechanical
tion of sedimentary rocks and their pore fluids. Weathering Weathering
Well logs are a fundamental method of formation I
I
analysis since they measure the physical properties of
the rock matrix and pore fluids. They provide forma-
Plant
Extraction
I
Solution
I
New Minerals
tion data not directly accessible by means other than
coring. Well logs can be used to extend data obtained
from core analysis to wells from which only logs are
available. Utilizing log-derived measurements of
such petro-physical properties makes it practical to Precipitation
determine, for example, lithology, porosity, shale
Biologic Extraction
volume, water and hydrocarbon saturation and type, and Precipitation
when oil and/or gas are present and to estimate
permeability, to predict water cut, calculate residual
Peat Shale
oil saturation, and detect overpressured zones.
Coal
The primary purpose in the analysis of most well Evaporites Conglomerate
logs is to describe the lithology of the reservoir rock (Some Limestone) Sandstone
and fluid properties for the section cut by that par- Limestones Chert
ticular well. A set of logs representative of an area Diatomaceous Shales
Phosphates
can be used as an exploration tool to describe local
stratigraphy, structure, facies relationships and en- FIGURE 1.1
Simplified chart showing origins of sedimentary rocks.
vironments of depostion.
8. Sorting Grain Shape
C1
°8° ~o~
Angular: having sharp corners and edges
Very Well o Q and, therefore. showing little or no effects
000 of abrasion or wear.
C68'b 0
~D'{?
Subangular: having edges and corners
Well
slightly rounded. so that wear is evident.
000
OPeO Subround: having most of the corners and
Q~
l?~
Moderat~~y
00 °00 edges worn down to smooth curves, thus.
showing extensive abrasion.
00°0
o 0 0 • 00 Round. having all edges and corners
0:)0
Poorly
1)
0°0
0 smoothed off to gentle curves by prolonged
wear. 080
FIGURE 1.2
Texture of clastic rocks.
Clastic rocks, principally sandstones and shales, comprise up to 40 alo or more of sands formed near
are those sediments composed of distinct grains granitic source areas in arid climates. A multitude of
which have been mechanically deposited. Their other minerals may occur in minor amounts (usually
character is dependent upon the composition of the less than one percent of the rock). Some, such as
grains, their relative abundance, grain size and hematite, dolomite and siderite serve as cementing
shape, orientation and packing of grains, cornposi- agents. Calcite is also quite common as a cement and
lion and distribution of cement and nature of the a rock forming mineral. Textures can vary from
fluid content of the pore system. Typical clastic rock poorly sorted conglomerates as found in the granite
nomenclature indicates the relative size of grains or wash to highly rounded, well sorted, fine blanket
texture. For example, a siltstone is composed of silt- sands. A marl is usually 40 to 60070 carbonate with
sized grains and a sandstone is composed of sand- the other 60 to 40 07 usually clay with silt or sand.
0
sized grains. Greater than 60070 carbonate is considered a shaly
The texture of clastic rocks is determined largely limestone or chalk. Less than 40 010 carbonate is often
by grain shape and sorting. (Fig. 1.2) Grain shape or considered as a calcareous or dolomitic shale.
sphericity is principally a function of the energy of Shale generally refers to a rock composed pri-
the environment of transport reworking and deposi- marily of clay minerals, minor quartz silt with some
tion. A grain which has been reworked through the feldspar, and from 0 to 20 070 organic matter. The car-
sedimentary cycle several times generally has a higher bonate equivalent of shales are often called marls.
sphericity. Younger grains near their source are They are composed primarily of calcite, clay, and
usually very angular. Sandstones deposited in minor silica, and are occasionally dolornitized. The
moderate to high energy environments tend to be extensive "oil shale" deposits in Utah, Colorado and
well-sorted while those formed in low energy en- Wyoming are marls.
vironments have poor sorting. Clay minerals are essentially hydrous aluminum
The composition of sandstone is highly dependent silicates in which magnesium and/or iron may
upon the source, climate and environment of substitute for aluminum, and aluminum may
transport and deposition. Sandstones are usually substitute for silica within the structure. Clay
composed of quartz. Numerous sandstones contain minerals are formed by the weathering of silicate
igneous or metamorphic rock fragments, some minerals from igneous and metamorphic rocks. In-
feldspar and a few carbonate grains. Feldspar is the dividual particle size is of the order of 10 microns.
most abundant mineral in igneous rock and may Shales comprise 50 to 60070 of the sedimentary
2
9. record. The great majority of all shales are deposited tant producing horizons have been explored in
in near shore marine environments along continental California.
margins. The remainder are deposited as deep marine
muds or in fluvial, and lacustrine environments. CHEMICAL ROCK CLASSIFICATION
The color of gray to black shales is due primarily
to organic content. Red or green shales have a high From the preceding brief discussion of the prin-
iron content and relatively low organic content. cipal features of sedimentary rocks, it is evident that
Yellow and brown shales have a low iron and low a simplified classification system for log interpreta-
organic carbon content. tion is needed. Logging tools respond primarily to
Shales have a low effective porosity and extremely the chemical nature of matrix and pore fluids. For
low permeabilities. They have usually been bypassed this reason, a chemical rock classification has been
I
..
by drillers even when good mud shows were en-
countered. The Woodford shale in Oklahoma is a
typical black organic-rich shale with beds of dark
pyritic chert, siliceous shale and some siltstone.
adopted. All rocks composed primarily of silica, in-
cluding cherts, are called sandstones. All calcium car-
bonate rocks are called limestones. All calcium
magnesium carbonate rocks are called dolomites.
Where relatively brittle zones have developed natural Rocks composed primarily of clay are called shale.
fracture systems, good gas production and some oil Silt or siltstone is sometimes used as the calculated
have been found. difference between shale volume and clay volume.
Anhydrite, gypsum, halite and coal all have suffi-
Carbonates comprise approximately 10010 of the
stratigraphic section. Their importance as reservoir ciently unique log responses which are easily iden-
rocks should not be underestimated. Approximately tified.
SOOfo of the world hydrocarbon reservoirs are in car- RESERVOIR ROCK PROPERTIES-POROSITY
bonate rocks. These consist primarily of calcite or
dolomite with mica amounts of aragonite, ankerite, A thorough understanding of basic reservoir
siderite, pyrite, chlorite. quartz and clays. parameters is a must for the analysis of any well log.
The ultimate storage capacity of any reservoir is
Evaporite sequences are deposited in marine basins defined as the percent of space not occupied by the
having restricted circulation. Halite or salt beds ex- rock matrix. Total porosity, 0, is defined as:
ceeding 3,000 ft thick are known in the geologic
record. Sylvite (KCl) and other salts occur in lower f2S = pore volume/total volume (1)
volumes, but are more important economically. Gyp-
sum and anhydrite are the common sulfates. Gypsum or
is altered to anhydrite by loss of water with increas-
ing depth of burial and these deposits are frequently
interlayered with shale, limestone, or dolomite.
I2l l I-matrix volume )
Anhydrite may also crystallize directly under certain ~ total volume
conditions.
Primary porosity is the porosity that is built into the
Phosphatic rocks also occur in complex mixed rock matrix during original deposition and includes
lithologies. They include carbonate as well as clastic its reduction by subsequent cementation and com-
mixtures. They frequently have high organic carbon paction. (Fig. 1.3)
content and are thought to be the source rock for
several major oil fields.
Extensive deposits of chert have been formed in
deep marine basins from the remains of siliceous
micro-organisms. Chert also occurs as replacement
deposits in shales and limestones. Cherts are general-
ly not porous or permeable except where fractured.
Depth
An exception is the Mississippian "chert" zone in
South Central Kansas and Northern Oklahoma
which is a weathered chert with porosity of 30-40010
in places. The zone is also fractured which increases
1
the permeability.
Diatomites and diatomaceous shales are accumula-
tions of thin-walled unicellular siliceous micro-
organisms with varying amounts of shale. These FIGURE 1.3
deposits have very high porosities (25-60010), but their Porosity vs. well depth.
permeabilities are comparatively low. Several impor-
3
10. In clastics, grain shape, size, sorting and energy physically and chemically with drilling and comple-
level of the environment of deposition determine the tion fluids reducing permeability.
packing arrangement. In general, fine-grained sand- Carbonate rocks usually show little evidence of
stones with poorly sorted angular grains will have physical compaction. Carbonate rocks are cemented
lower porosity than sandstones composed of coarse, very quickly both during and soon after deposition.
well-sorted grains. Angular grains tend to fit together Porosity reduction is primarily due to continued
and develop more intimate grain-to-grain contacts. growth of cement in the pore space.
(Fig. t .4) In poorly sorted sediments, the smaller Secondary porosity is that porosity developed
subsequent to original deposition, compaction and
cementation. Secondary porosity includes fracture
Porosity porosity, solution porosity and porosity caused by
47.6% dolomitization.
47.6%
TRAPS
The occurrence of accumulations of petroleum in
nature requires the existence of an organically rich
source rock, a porous and permeable reservoir rock
25.9%
and a seal. Traps are classified as structural,
stratigraphic or a combination.
Structural traps include domes, faults and an-
ticlines. Stratigraphic traps may be formed by lateral
~ <25.9% variations in lithology. The presence of fractured
limestone stringers within impermeable shales is an
FIGURE 1.4 example of a stratigraphic trap. (Fig. 1.5) In some
Grain shape and size effects on porosity.
cases, inclined bodies of rock have been eroded at the
surface and overlain by impermeable bodies of rock
grains tend to fill the spaces in between the larger to form stratigraphic traps.
grains. Packing is independent of absolute grain size.
Rocks composed of grains of identical shape which
are equally well-sorted will theoretically have the PERMEABILITY
same porosity. However, sediment ranging from silt
to very fine-grained sandstone frequently exhibit The interconnective porosity in a rock is called its
lower porosities. Very small grains tend to have lower effective porosity. The degree to which this natural
sphericity and form smaller pores which are more plumbing system can conduct fluid is called
easily cemented. The degree of sorting and average permeability. It is the key parameter in determining
grain size are directly related to the duration of the the rate of production.
sedimentary process and the energy level present dur- Based on flow tests, Darcy determined that the
ing deposition. value of permeability, k, can be expressed by the
After deposition, compaction and cementation equation:
greatly reduce porosity. Shales exhibit the greatest
degree of compaction through the expulsion of in- k QJA/ A(AP/L) (2)
terlayer pore fluids. This expulsion of fluids by com-
paction at an increased temperature is the basic where:
mechanism for primary migration of petroleum from
source to reservoir rocks. Q flow per unit time
Compaction effects in sandstones are less signifi-
cant. The initial fabric of the grains is primarily JA = viscosity of flowing medium
determined at deposition. With increasing pressure, a
sand will compact no more than 10 to 15070 principal- A cross section of rock
ly due to grain rearrangement. At greatly increased
pressure and some increase in temperature, pressure L length of rock
solution occurs at stress points.
Porosity reduction is primarily due to cementation ~P pressure differential (drop)
and crystallization of certain minerals in the pore
space. Clean sandstones and carbonates are relatively The unit of permeability is the darcy (D), equal to
stable. Some clay minerals tend to react both 1,000 millidarcies (mD). By definition, a porous rock
4
11. X X'
L- _-J
b. Normal Fault
X'
Limestone
a.Dome
Shale
Sandstone
0 0 0 0 0 0
<0 CO 0 0
-- CO <0
X'
X
l
c
-- -
8 A
- --
B C
J
II Oil sand
I I I I
I
J. . . . . . ..- ---r - -
I
/' 1".--'1---1 . . . . . . . 1', :
---f
,--,I I
I
----------~~~~~------
-------------~---~--
d. Fractured limestone stringers within impermeable shales.
c. Anticlinal Trap
FIGURE 1.5
Structural traps.
5
12. exhibits a permeability of one darcy when a single Therefore, a fracture 0.01 in. wide has a permeability
phase fluid of one centipoise viscosity (viscosity of of 5,440 darcys.
water at 68 OF) which completely fills the entire pore In other words, solution channels, interconnected
'space will flow through it under viscous flow condi- vugs and fractures can significantly affect the pro-
tions at the rate of one cm 3/sec per square centimeter duction behavior of potential reservoir rocks.
of cross section area under a pressure gtadient of one Permeability can be determined from well resting
atmosphere per centimeter. Potential hydrocarbon.. operations, wireline or DST, measurements on
bearing rocks exhibit a wide range of perrneabilities. sidewall samples, core analysis using plug type or
(Fig. 1.6) Frequently, permeability increases with whole (full) core measurements, or estimated
through correlation to well log data. (Fig. 1.7)
ffi High Permeability
Area
Rock
~ Low Permeability 0-)) )_
Pl , . - - L ~I P2
Length
FIGURE 1.6
Range of permeability. Area of Core
Permeability
/ . - - Pressure Drop
porosity. However, even very low porosity rocks may "k x
Q =.
A--
be highly permeable. This is caused by natural frac.. L (P1 - P2)
tures and/or solution channels. On the other hand,
Flow
/ '
Fluid
-,
Core Length
high porosity rocks, such as chalk, may have very
Rate Viscosity
low matrix permeability.
A practical rule of thumb for classifying FIGURE 1.7
permeability is: poor to fair, k = < 1.0 to 15 mD; Determination of permeability.
moderate k = 15 to 50mD; good k = 50 to 250 mD;
very good k = 250 to 1,000 mD; and excellent k, in Reservoir permeability is a directional rock proper-
excess of one darcy. ty. Cross bedding, ripple marks, bioturbation, cut
Besides the typical matrix permeability, some and fill structures as well as variation in cementation,
potential reservoir rocks, particularly low-porosity grain size, sorting and packing contribute to varia-
carbonates, may have solution channels and vugs tion in permeability with a depositional unit.
and/or natural fracture systems, which g~eatly Permeability in the direction of elongation of the
enhance reservoir permeability. component grains is considerably greater than in any
Permeability of solution channels, which exhibit other direction. Horizontal permeability (k h ) ,
circular or near circular openings, can be directly measured parallel to bedding, is the major con-
related to and calculated from the size of the chan- tributor of fluid flow into the wellbore.
nels: Vertical permeability (k-) is frequently lower than
horizontal permeability. Bedding planes, the
k(darcy) (3) presence of muscovite or other platy minerals and
shale laminations act as barriers to vertical
where: permeability. The ratio of kh/k v generally ranges
from 1.5 to 3.0 and may exceed 10 for some reservoir
d = diameter of channels rocks.
Sometimes, however, unusually high vertical
For example, the permeability of a solution channel permeability occurs in unconsolidated clean and
having an opening of 0.001 in. is 20 darcys. coarse sandstones or due to fracturing or develop-
ment of vertical jointing. Joints may occasionally be
For typical fracture permeability, the above equa- filled with clay or other minerals which act as barriers
tion becomes: to horizontal permeability. This condition (kh/k v ~
1.0) greatly affects reservoir behavior due to bypass-
k{darcy) (0.544)( 10 8) (,2) ing and coning effects in producing wells.
where:
w fracture width, in.
6
13. ABSOLUTE, EFFECTIVE AND RELATIVE where:
PERMEABILITY
o and Swi are expressed in 010
Taking certain analytical precautions, a specific
rock sample is characterized by a unique permeability
value, regardless of whether gas or liquid has been
used in the measurement. (5)
Provided only a single medium such as water, oil
or gas flows through the rock (So or Sw or S = 1.0),
the term absolute permeability is used. g 250 for oil
However, since petroleum reservoirs contain gas C ={
and/or oil and water, the effective permeability (k , 80 for gas
ko ' k w ) for a given medium in the presence of othe:s
must be considered. Effective permeability is the where: 0, Swi are decimal fractions.
permeability of the rock to a medium when another
medium is present in the pore space. It is important For a graphical solution to the Timur equation and
to realize that the sum of effective permeabilities will Morris and Biggs equation, refer to Figures 1.8 and
always be less than the absolute permeability. This is 1.9.
due to mutual interference of simultaneous flows of
more than one liquid.
When dealing with flow of more than one fluid
through a permeable reservoir rock, it is necessary to
consider relative permeability (krg~ k ro, k rw).
Relative permeability is defined as the ratio of BIBLIOGRAPHY
relative permeability of one phase, during multiphase
fluid flow, to the absolute permeability of that fluid Blatt, H., Middleton, G., and Murray, R. Origin of
during single phase flow through the reservoir rock. Sedimentary Rocks, Second Edition. Prentice-Hall,
Inc., 1980.
Relative permeability = effective permeability/
absolute permeability. Fertl, W.H. Knowing Basic Reservoir Parameters
First Step in Log Analysis. Oil and Gas Journal,
Porosity and water saturation are commonly used 1979.
to predict production potential. It is apparent that
unless the relationship between porosity and Folk, R.L. Petrology of Sedimentary Rocks, Austin,
permeability is known, as well as the relative Texas: Hemphills, 1968. (A "syllabus" periodically
permeability, this practice entails considerable risk. revised, and used as a laboratory manual at the
The importance of the presence of clay minerals as University of Texas).
a determinant of permeability is often related not
only to their abundance, but also to their mineralogy Levorsen, A.I. Geology of Petroleum, Second Edi-
and the composition of the pore fluid, principally its tion. W.H. Freeman & ce., 1967.
salinity. In an undisturbed sandstone, the clay
minerals are attached to or coat the grain surfaces Potter, O.E., Maynard, J.B., and Pryor, W.A.
reducing the pore space. If the clays should be ex- Sedimentology of Shale. New York: Springer-Verlag,
panded due to changes in the chemistry of the pore 1980.
fluids, mud filtrate invasion or become dislodged to
float through the pore channels and block pore
throats, the permeability win be further reduced.
There are several methods of determining reservoir
permeability from log data. Two commonly used em-
pirical methods are the Timur equation and the Mor-
ris and Biggs equation.
Timur Equation:
0 4 .4
k (mD~ = 0.136 ~ (4)
WI
16. QUESTIONS 1
(1) Which of the following rock types arc usually clastics?
a) limestone
b) evaporites
c) sandstones
d) dolomites
(2) Calculate the permeability of a fracture whose width is 0.2 in.
a) 10 darcy
b) 11 x 106 darey
c) 2 x 106 darey
d) 544 darcy
(3) Sandstones are usually cornposed of:
a) feldspar
b) mica
c) quartz
d) calcite
(4) Shales have (high, low) effective porosity and very (high, 10') permeability.
(5) Relative permeability equals:
a) effective permeability/absolute permeability
b) absolute permeability/effective permeability
c) absolute permeability x primary porosity
d) primary porosity/effective permeability
(6) Determine the reservoir permeability for a gas-bearing formation with 0 15ctJo and Swi 20%
using both the Timur equation and Morris and Biggs equation.
k (Timur) = k (Morris & Biggs) =
10
17. BASIC RESISTIVITY CONCEPTS 2
INTRODUCTION ticular case may violate the rule. Figure 2.1 il-
lustrates the various symbols and terms used.
Resistivity Concepts in Well Logging
Resistance is the property of a substance that of-
fers opposition to the electrical current flow. Ohm's As
law describes the behavior of electrical current flow Mut1.----.......- - -
Cake
through a material.
hmLI
E (1)
r = Flushed Zone
s;: Undisturbed
Formation
Invaded Zone
.--Ri---t-.... • 8, ~
r resistance, ohm
E electromotive force, volts
current, amperes
R - ResistiVity xo - Flushed zone
Resistivity is a measure of the resistance of a given S - Saturation me - Mud cake
s - Shoulder bed h - Thickness
volume of material. me - Mud cake w • Formation water
A i-Invaded zone d - Diameter
R = r -
L
(2)
t - Non-invaded zone
FIGURE 2.1
R resistivity, ohms m 2/m Formation parameters.
r resistance, ohms
The flushed zone, next to the borehole, is created
A cross-sectional area, meters/ by the mud filtrate passing through it during the pro-
cess of invasion. The hydrocarbon saturation in the
L = length of material, meters flushed zones is at a minimum, and all the virgin for-
mation water is replaced by mud filtrate. The invaded
In practice, the resistance of a certain volume of zone is that portion of the formation which has been
the formation is measured. The volume of formation penetrated by drilling fluids. (Fig. 2.2)
measured is a function of the configuration of the in- Moving through the flushed zone next to the well
strument, which is a constant, therefore, the bore, deeper into the transition zone, water satura-
measurement is expressed in terms of resistivity. tion can vary. In a water zone there is no change in
The resistivity of any formation is a function of the water saturation, only a change in water resistivity or
amount of water in that formation and the resistivity salinity. In a hydrocarbon bearing lone, the
of the water itself. Ion-bearing water is conductive; hydrocarbon saturation is reduced in the flushed
the rock grains and hydrocarbons are normally in- zone and increases in the transition zone until the
sulators. original saturation in the undisturbed formation is
FORMATION FLUIDS reached. These changes in water saturation" combin-
ed with changes in the resistivity of the fluids filling
Changes in resistivity that occur in porous and the pores, create resist ivity pro files.
permeable beds between the wen bore and the virgin In fresh drilling muds, the mud resistivity is nor-
zone influence most resistivity logs. The following mally higher than the formation water, In a water-
discussion assumes that some invasion occurs during bearing zone, the formation resistivity is higher in the
the drilling process. The depth of invasion is a func- flushed zone due to R lll f > R w and decreases with
tion of the mud and formation properties. In general, movement out into the undisturbed formation. In a
low porosity formations invade more deeply than hydrocarbon-bearing zone . drilled with fresh mud,
high porosity formations. Explanations as to why the resistivity behind the flushed zone may be higher
are, at best, rationalizations. In general, any par- or lower depending on the water saturation and the
11
18. resistivity of the formation water. In Figure 2.3 the
invasion profiles are indicated with the relative posi-
tion of the deep, medium and shallow resistivity
curves. This assumes the shallow resistivity curve
reads mostly the flushed lone, the medium reads
some of the transition lone and the deep reads mostly
the undisturbed formation.
With a salt water based mud, the flushed zone nor-
mally has a lower resistivity. With the undisturbed
zone, resistivity is either the same or higher, if the
formation contains equivalent or higher resistivity
water . The virgin zone will have a higher resistivity, if
there are hydrocarbons. Notice that the resistivity
curve positions arc reversed because of the reversal of
the resistivity profile.
STEP PROFIL.:
The step profile of invasion assumes the simplest
geometry between the invading mud filtrate and undis-
turbed formation. This invasion profile consists of a
cylindrical interface moving laterally into a porous and
QOAl _ - ' - [
...... .,
...
permeable homogeneous formation. The diameter of
Distance from Borehole this cylindrical interface is d i- The formation within the
FIGURE 2.2
interface is the flushed zone, with resistivity R xo •
All resistivity/saturation profiles relate to this model. Beyond the interface lies the undisturbed zone, with a
resistivity of Rt • Figure 2.4 shows a schematic diagram
for this invasion profile.
a:
• Fresh Mud
} cf....-. _
Fresh Mud v Invaded
System rl Formation
A
Undisturbed
rf Formation
1
rl ~adius 9f _I
Invaslo,;-J
--Distance - -......
Salt Mud
System
A FIGURE 2.4
Step profile of invasion.
FIGURE 2.3
• Schematic resistivity log response. The transition profile of invasion assumes that a
D - Deep transition zone exists in a porous and permeable
M-Medium
homogeneous formation between the portion of the
S -Shallow
formation flushed by mud filtrate and the uncon-
12
19. taminated formation. The conductivity in the transi- profile exists. This invasion pattern is usually refer-
tion zone is assumed to vary linearly between the con- red to as a low resistivity zone or annulus profile, and
ductivity of the flushed zone and the undisturbed for- its existence is an indication of moveable hydrocar-
mation. (Figure 2.5) bons.
The width of this transition zone is dependent Due to the current patterns of the logging devices,
upon the type of formation, rate of invasion by mud the induction devices are affected to a greater degree
filtrate and the length of time the formation has been by the low resistivity zone. The low resistivity zone
exposed to the invading fluid. has a more severe effect upon the medium induction
device. Computations show that in the case of a
severe annulus, existing in a shallow to moderately
cS invaded formation, the medium induction may
A record lower resistivity than the deep induction
J Undistrubed device when the ratio of Rxo/R t is less than five.
Formation When ratios of Rxo/R t are greater than five, or
deeper invasion exists, the effect decreases and the
0 1 - Inner Boundary of medium curve will record resistivity approximately
Transition Zone
equal to or greater than the deep induction curve.
~ - Outer Boundary
Calculations show that the deep induction curve is
only slightly affected by an annulus, and the record-
"Co Translnon ed resistivity is only about lOC1Jo low for Rxo/R t ratios
~~ Zone
,~ ~ E of three to five and S% low for Rxo/R. ratios greater
v LL 0
than five. Figure 2.6 shows a low resistivity annulus
V u..
01 profile. Induction devices are covered in detail in
J Chapter 6.
D i s t a n c e - - - - - - - -..
01 - Inner Boundary of
cf Invaded
V
Transition Zone Formation
02 - Outer Boundary
r! Rxo
Undisturbed
-05 Formation
~;
U)«S
~
s 2E Low Resistivity Zone
:; LLO
LL
'iii
Q)
a:
Transition Undisturbed
Zone 0 1 O2
rf Formation
O2 ~ 1.4 0,
1
rl 0, - - Distance - - - - - - - - .
'II---Distance----.. FIGURE 2.6
Low resistivity annulus profile of invasion.
FIGURE 2.5
Transition profile of invasion,
ANNULUS PROFIL.:
Since it is possible for mud filtrate invasion 0 f a
hydrocarbon-bearing formation to create a zone of
formation water which is displaced ahead of the inva-
sion front by a process of miscible drive, considera-
tion must be given to the response of the logging
devices in the event this particular type of invasion
13
20. QUESTIONS 2
(1) The resistivity of the formation is a function only of the resistivity of the formation water.
a) True
b) False
(2) A step profile of invasion assumes --
a) invading fluids are intermixed with the formation fluids,
b) invading fluids are never mixed with the formation fluids.
c) invasion seldom occurs and, as such, need not be considered in regard to resistivity devices
(3) In a transitional profile the width of the transition Lone is assumed to vary only with the type of
formation.
a) True
b) False
(4) When an Annulus invasion profile exists and RXll/R. ratios are greater than five,
a) deeper invasion exists
b) the medium curve will record a resistivity approximately equal to or less than the deep induc-
tion curve
c) the medium curve will record a resistivity approximately equal to the deep induction curve
d) the deep curve will record a resistivity approximately equal to the medium induction curve or
less than the medium induction curve
14
21. FORMATION FLUID PROPERTIES 3
FORMATION WATERS the same water in a reservoir at a higher temperature.
Subsurface waters represent a diversity of sources. Likewise, water-base drilling mud changes resistivitv
They are mixtures of newly formed waters, at- with depth, due to the change in temperature. Figur~
mospheric waters, ocean waters and waters produced 3.1 shows how to correct the resistivity of mud, for..
from diagenetic reactions. The history of any specific marion water, etc. for the effects of temperature.
sample is exceedingly complex. Throughout geologic When the temperature of a solution is increased it is
time, formation waters have undergone continuous assumed that the salinity stays constant, making
modification by filtrations through clays, by ion ex- resistivity t he only other variable.
change, by precipitation of minerals and by reaction
with rock matrix and other fluids. Example: Draw a straight line on Figure 3.1 from
139 0 and a resistivity at 0.06 Q-lll; the salinit v of this
The initial fluid in most sedimentary rock was sea
mixture is 62,000 ppm as shown on the center string
water. Although it cannot be assumed that the com-
of the nomograph. An increase in temperature to
position of sea water has remained constant
throughout geologic time, most data suggest that its 179 0 (the salinity stays constant so the line still goes
composition has not undergone significant change through 62,000 ppm) changes the resistivitv to 0.046
over the past few billion years. Q-m. All aqueous solutions are handled in the same
manner. The salinities shown are for sodium chloride
The salinity of subsurface waters generally in-
solutions, but the nomograph works well for most
creases with depth. Reversals, however, are not un-
practical well Jogging applications.
common. Considerable variation within the same
In many cases. brines are encountered with total
formation may occur within a basin. Studies of
cementation in sandstones indicate that significant solid concentrations composed of ions other than Na
salinity variation can occur over very short distances, and Ct. To accurately correct the Rw' R In or Rmf"
• •
,U~-
both horizontally and vertically. Filtration through tng FIgure 3.1. the total ionic concentration must be
clay membranes appears to be one of the key expressed as equivalent NaCl concentration. Fiaure
mechanisms capable of producing the gradients 3.2 is used to correct ionic concentrations to
observed. equivalent NaCI concentrations.
The density of water depends upon its salt content, Example: If a brine with 50,000 ppm total solids
temperature and pressure. The specific gravity of a which includes 10,000 ppm Nat J6,000 ppm Cit 7,000
ppm Mg, 5~O(){) ppm Ca and 12,000 ppm S04 is en-
substance is the ratio of its density to that of water at
countered, Chart 3.2 can be used to determine a
specified temperatures. The density of water
value for equivalent NaCI concentration to enter in
decreases with increasing temperature, but increases
Chart 3.1. From the chart read K -= 0.92 for Mg , at
with higher total solid concentration and pressure.
50,000 ppm, K ::: 0.18 for Ca at 50,000 ppm, and
All porous rocks contain some water. Bv virtue of
K = 0.36 for S04 at 50.000 ppm, noting that
ionized salts contained in solution, these -fonnation
K = ).0 for the Na and C } at 50,000 ppm. Then add
..
waters are electrically conductive, exhibiting
(10,000 xl) + (16,000 xl) ,. (7,000 x 0.92) +
resistivities ranging from 0.02 Q-m to several ohm-
(5,000 x 0.78) + (12.000 x 0.36) -= 40,660 ppm
meters at formation temperature. The predominant
equivalent NaCI. This value is used at the ppm NaCI
salt in these solutions is sodium chloride. Resistivity
entry in Chart 3.1 when correcting R w' R In or R mt. for
of such an electrolyte normally decreases with in-
the temperature.
creasing salt concentration due to the higher amounts
of ions which carry electric charges and higher
temperature which affects the mobility of the ions.
The resistivity of formation water may be determined
OIL & GAS PROPERTIES
by direct resistivity measurement on a sample,
Specific gravity of oil is related to its API gravity
chemical analysis, or an estimation of R or
by the relationship:
equivalent NaCI (in ppm) from well logs.
The resistivity of an aqueous solution, which is
water plus a salt such as sodium chloride. varies with 141.5
temperature . The resistivity of a water measured at p (1)
°API + 13].5
surface conditions is different from the resistivity of
15
23. +2.0 ...- ....- . . . - - - - -....----------------------------~- I - - - -..
- .....
Mg
.....- .
,
I
I
.- --._. - J.
I I I' /
.. I
.. -- :/
I
"'Mg
Ca •• -.......
__ • . _.·A~ . ,/r-
... ,/
.. .. .. . . . .
~
<, /
. . . .,........ _... ----------
.1 Na and CI
~ +1.0 ~---~ , - .... -......
..........~......~...----~~ ~..... -------..---------~-~...... - - - - - -......
'3
::E
-- ---- -- K --
~
.. ~~
.. - ............
-. "~ ........ Ca
'... ~ - ...".". "-"
.. . .
.---._----- .............. -'--"- '- .- ......
HCOa
'- .-- ....... - HC~ .' ~
. "
.-i..:.
O... ..._ ...._ .........__.....lI-A. . . . . . . . . . . ._ - . . . _. . . . . . . .--A............~ ....._ . . . ._ . a . _......................_..._j~ . . .
.
100 1000 10.000 100.000 200,1
Total Solids Concentration. ppm
FIGURE 3.2
Equivalent NaCI concentrations from Ionic concentrations.
where p is the specific gravity of oil at 60 OF. When 1.0
dissolved gas is present in oil, the specific gravity of
the mixture decreases as the gas/oil ratio increases. M
Figure 3.3 can be used for determining reservoir den- E 09
~
sity of oil in g/cm' for a known value of GOR. ~
Figure 3.4 shows the variation of specific gravity of <5
'0 0.8
oils with temperature. Dry gas density as a function ?:'
of reservoir pressure and temperature is illustrated in iii
c
Q)
Figure 3.5. C 0.7
~
The viscosity of gas-free crude oil also decreases '0
e
with temperature. (Fig. 3.6) From a knowledge of (J)
en 0.6
(1)
crude oil °API gravity and formation temperature, a:
the viscosity of gas-free crude oil can be determined.
The amount of gas dissolved in oil has an important 0.5
10 20 30 40 50 60
bearing on viscosity at reservoir conditons, figure Oil Gravity (OAPI)
3.7 shows how to correct the viscosity of dead oil, at
reservoir temperature and atmospheric pressure, to Example: °API qravitv » 39
the viscosity of gas-saturated oil for the known GOR GOR = 1000
at reservoir conditions.
Oil Density = 0.66 g/cm 3
FIGURE 3.3
Reservoir oil density as a function of oil gravity (OAPI)
and gas·oil ratio (GOA).
17
24. 400
100 200 300 400 500 600 700 800 900 1000
1 - Temperature In Degrees Fahrenheit
Example: The specific gravIty of an oil
at 60°F IS 0.85. The specific
gravity at 10QoF = 0.83.
--.
..... --
--
~H6 = Ethane
C:3Ha = Propane 20 30 40 50 60
C4 H 10 = Butane
Crude Oil Gravity (OAPI) at 60°F and Atmospheric
C4H 10 = Isobutane Pressure,
C4H 10 = Isopentare
To find the weight densrty of a petroleum oil Ibs/ff~ at its
FIGURE 3.6
flowing temperature when the specific gravity at 60°F is
ViSCOSity of gas-free (STO) crude oils.
known. multiply the specific gravity of the oil at flowing
temperature (see chart above) by 62.4 lbs/It:' the weight
density of water at 60° F.
FIGURE 3.4
Specific gravity-temperature relationship for petroleum oils
100 .......- - - - , , - - - - - - - - - . . . . . - - - - - - - - -
80
60
Q)
~ 40
tJ)
0 C/)
~£
-c:
20
2000 ==0
o ~ 1O~---I__------_lfA__.........__,... ~OO
g
(j)
4000 ~~ ~ .>..
~
;j
au
~ s 4
~~
,,~
C/)
C/)
Q)
6000 I ~
Ii: ~ ~ 2 ,.(o.... SOlution Gas/Oil
8000
C)Qi ,'0"'.1 Ratio CU ft/bbl
- a. -,,'fOOo
~~ 1 t-----~~~ ......,........I«-" 00°;-.---------4
10,000 :~ .... 0.8 ",,~'
0 0.1 0.2 0.3 8 '6 0.6 rz,r:fJ
Density of Dry Gas (g/cm 3 ) 5 ~ 0.4
C/)
,,~$
",~
C2 ~GOO
FIGURE 3.5
~O.2
Density of dry gas as a fu nction of reservoir pressure and
temperature.
Viscosity of Dead Oil (cP)
(at Reservoir Temperature and Atmospheric Pressure)
FIGURE 3.7
Viscosity of gas-saturated crude oils (J,l) at reservoir
temperature and pressure.
18
25. SUBSURFACE PRESSURE REGIMES PFG = 0.433 x p (3)
Hydrostatic pressure is caused by the unit weight where p is the specific gravity of a representative col-
and venical height of a fluid column. The size and umn of water.
shape of this fluid column has no effect on the Overburden pressure originates from the combined
magnitude of this pressure. Hydrostatic pressure, weight of the formation matrix (rock) and (he fluids
(water, oil, gas) in the pore space overlying the for-
P H• ' equals the mathematical product of the average
y
fluid density and its vertical heights, such as: mation of interest. Mathematically, the overburden
pressure can be expressed as:
P Hy = P X g x D (2)
P = weight (rock matrix + fluid) (4)
o area
where: p average density
g gravity value
D height of the column Generally, it is assumed that overburden pressure
increases uniformly with depth. For example,
The hydrostatic pressure gradient is affected by the average Tertiary deposits on the U .5. Gulf Coast,
concentration of dissolved solids (i.e., salts) and and elsewhere, exert an overburden pressure gradient
gases in the fluid column and different or varying of 1.0 psi/ft of depth. This corresponds to a force ex-
temperature gradients. In other words, an increase in erted by a formation with an average bulk density of
dissolved solids (i.e., higher salt concentration) tends 2.31 g/crrr'. Experience also indicates that the pro-
to increase the normal pressure gradient, whereas in- bable maximum overburden gradient in clastic rocks
creasing amounts of gases in solution and higher may be as high as 1.35 psi/ft.
temperature would decrease the normal hydrostatic Worldwide observations over the last few years
pressure gradient. For example, a pressure gradient have resulted in the concept of a varying overburden
of 0.465 psi/ft assumes a water salinity of 80,000 gradient used for fracture pressure gradient predic-
ppm NaCI at a temperature of 77 of (25 O(~). tions in drilling and completion operations.
Typical average hydrostatic gradients which may Formation pressure (P f) is the pressure acting upon
be encountered during drilling for oil and gas are the fluids (formation water, oil, gas), in the pore
shown below: space of the formation. Normal formation pressures
in any geologic setting will equal the hydrostatic head
Equivalent Total
(i.e., hydrostatic pressure) of water from the surface
Hydrostatic Mud Wt. Chlorides Basin
to the subsurface formation. Abnormal formation
Gradient ppg ppm Location
pressures, by definition, are then characterized by
any departure from the normal trend line.
0.433 8.33 Fresh Rocky Formation pressures exceeding hydrostatic pres-
water Mountains sure (Pr > PH,,) in a specific geologic environment
0.442 8.5 20,000 Beaufort, are defined as abnormally high formation pressure
Brunei, (surpressures) whereas formation pressures less than
Malay, hydrostatic are called subnormal (subpressures).
Sverdrup, These subsurface pressures and stress concepts are
N. Slope in related.
Alaska In normal pressure environments (PI' = PH ) , the
(most of . ~
matrix stress supports the overburden load due to
world's grain-to-grain contacts. Any reduction in this direct
basins) grain-to-grain stress (0 -+ 0) will cause the pore fluid
0.452 8.7 40,000 North Sea, to support part of the overburden, the result being
Delaware abnormal formation pressures (P f > PH,,). In other
(older words, the overburden may effectively be "floated"
portion- by high formation pressures.
prePenn.) There are numerous factors that can cause abnor-
0.465 9.0 80,000 Gulf Coast mal formation pressures, such as surpressures and
0.478 9.2 95,000 Portions of subpressures, Frequently, a combination of several
Gulf Coast causes superimposed prevails in a given basin and as
such is related to the stratigraphic, tectonic and
In general, the hydrostatic pressure gradient (in geochemical history of the area.
psi/ft) can be defined as: In most cases, abnormal pressures are caused by
19
26. early formation of impermeable barriers prior to BIBLIOGRAPHY
compaction and consolidation or other geologic and
diagenetic processes. Figure 3.8 shows subsurface Beal, C. The Viscosity of Air, Water, Natural Gas,
pressure concepts. Crude Oil and Its Associated Gases at Oilfield
Temperature and Pressure. A/ME, Vol. 165, 1946.
Pressure (1000x psi)
2 4 6
O---.--......-----.-........- -.........----i---.---.----
Brown, K.E. The Technology of Artificial Lift
Methods. Tulsa, Oklahoma: The Petroleum
Publishing ce., 1977.
2
Dresser Atlas. Log Interpretation Charts. 1980.
Fertl, W.H. Abnormal forma/ion Pressures. New
£ 4 York-Amsterdam: Elsevier Scientific Publishing Co.,
o
8 1976.
s:
0.. 6
Q) Katz, D.L., Cornell, D., Kobayashi, R., Poetman,
c
F.H., Vary, J.A., Elenbaas, J.R., and Weinaug,
Surpressures C.F. Handbook of Natural Gas Engineering.
(Abnormally
8 McGraw-Hill Book Co., 1959.
High Pressure)
Schowalter, T.T. Mechanics of Secondary Hydrocar-
10 bon Migration and Entrapment. AAPF Bulletin,
May 1979.
FIGURE 3.8
Standing, M.B. Volumetric and Phase Behavior of
Subsurface pressure concepts. Oil Field Hydrocarbon Systems. New York:
Reinhold Publishing Corp., 1952.
FLUID SATURATION DISTRIBUTION
Fluid saturation is the percentage of the porosity
of a rock occupied by a specific fluid. For example, a
water saturation (Sw) of 50070 means that half the
pore space is filled with water. In a water-oil system
100070 - S" = So (oil saturation). The same logic
would apply to a water-gas system.
Water saturation, a key parameter determined
from well logs, controls the reservoir production
behavior and the amount of hydrocarbons in place.
An oil reservoir at irreducible (non-movable) water
saturation produces water free, but with increasing
water saturation the percent of water production will
increase. There is no unique, single water saturation
value to use as a cutoff for commercial or water-free
production. Each reservoir has its own unique
characteristics.
20
27. QUESTIONS 3
(1) What is the API gravity of an oil whose specific gravity is 0.85 g/cm 3?
a) 65
b) 35
c) 40
d) 50
(2) Viscosity of gas-free crude oil (increases, decreases) with increasing temperature.
(3) Higher salt concentrations tend to (increase, decrease) the normal pressure gradient, whereas in-
creasing amounts of gases in solution would (increase, decrease) the normal pressure gradient.
(4) If Sw = 720/0
So = ---
(5) If the total solid concentration of a Cae) water is 5,000 ppm, of which 2,500 ppm is Ca, and
2,500 ppm is CI, determine the R w at 160 OF.
a) 0.06
b) 0.4
c) 0.6
d) 0.03
21
