Basic Petroleum Geology and Log Analysis
Basic Petroleum Geology and Log Analysis
Basic Petroleum Geology and Log Analysis
Log Analysis
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Table of Contents
Introduction .............................................................................................................................................5
Objectives................................................................................................................................................6
Earth An Evolving Planet....................................................................................................................7
Geology Basics........................................................................................................................................8
Three Basic Rock Types ........................................................................................................................ 10
The Rock Cycle ..................................................................................................................................... 11
Geologic Time....................................................................................................................................... 12
Age Dating......................................................................................................................................... 12
Basic Age Dating Principles ............................................................................................................... 13
Geologic Time Scale .......................................................................................................................... 15
Basic Classification and Types of Sedimentary Rocks............................................................................ 17
The two main groups of sedimentary rocks are classified on the basis of their origin........................... 17
There are five types of sedimentary rocks that are important in the production of hydrocarbons:......... 18
Source Rock and Hydrocarbon Generation............................................................................................. 19
Migration of Hydrocarbons.................................................................................................................... 19
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Cross-Sections ................................................................................................................................ 52
Isopach Maps ................................................................................................................................. 53
Lithofacies Maps ............................................................................................................................ 54
Surface Geology .................................................................................................................................... 56
Subsurface Geology and Formation Evaluation ...................................................................................... 57
Well Cuttings ..................................................................................................................................... 59
Cores ................................................................................................................................................. 59
Logging While Drilling ...................................................................................................................... 60
Formation Testing .............................................................................................................................. 60
Wireline Well-Logging Techniques.................................................................................................... 61
Borehole Environment ........................................................................................................................... 63
The Basis of Log Analysis ..................................................................................................................... 65
Log Data............................................................................................................................................ 65
Porosity.............................................................................................................................................. 66
Remember ...................................................................................................................................... 66
Resistivity .......................................................................................................................................... 66
Example of changes in resistivity with changes in reservoir characteristics ......................................... 67
Water Saturation ................................................................................................................................ 68
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Introduction
Geology is the science that deals with the history and structure of the earth and its life
forms, especially as recorded in the rock record. A basic understanding of its concepts
and processes is essential in the petroleum industry, for it is used to predict where oil
accumulations might occur. It is the job of the petroleum geologist to use his/her
knowledge to reconstruct the geologic history of an area to determine whether the
formations are likely to contain petroleum reservoirs. It is also the job of the geologist to
determine whether the recovery and production of these hydrocarbons will be
commercially profitable.
The physical characteristics of a reservoir, how petroleum originated and in what type of
rock, what types of fluids exist in the reservoir, how hydrocarbons become trapped, and
basic well log analysis are some of the concepts vital to the production and recovery
efforts of any exploration or energy service company.
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Objectives
After completing this section, you should be able to:
•
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• Define porosity.
• Define permeability.
• Define a reservoir.
• List the two most common reservoir rock types and give some general characteristics
of each type.
Geology Basics
The earth is composed of three basic layers: the core, the mantle, and the crust. The crust
is the layer that is of most importance in petroleum geology. Geologists distinguish
between oceanic crust and continental crust. Oceanic crust lies under the oceans and is
thin about 5-7 miles (8-11 km) and is made up primarily of heavy rock that is
formed when molten rock (magma) cools. Continental crust is thick about 10-30
miles (16-48 km) and is composed of rock that is relatively light as compared to
oceanic crust.
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The crust is continuously changing and moving because of two major forces of nature—
Orogeny and weathering/erosion. Orogeny, or mountain building, is a process in
which the layers of the crust are folded and pushed upward by such processes as plate
tectonics and volcanism. Weathering and erosion are the opposing forces in which the
sediments are broken down and transported.
• Physical— occurs when solid rock is fragmented by physical processes that do not
change the rock’s chemical composition. These processes include wind (aeolian
forces), water (freezing, flowing, wave action, etc), heat, and even glacial movement.
Frost wedging is one example of physical weathering.
• Chemical— occurs when minerals in a rock are chemically altered or dissolved. The
weathering of potassium feldspar to form kaolinite, a clay, is an example of chemical
weathering.
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Figure 5
Sedimentary rocks are formed as sediments, either from eroded fragments of older rocks
or chemical precipitates. Sediments lithify by both compaction, as the grains are
squeezed together into a denser mass than the original, and by cementation, as minerals
precipitate around the grains after deposition and bind the particles together. Sediments
are compacted and cemented after burial under additional layers of sediment. Thus
sandstone forms by the lithification of sand particles and limestone by the lithification of
shells and other particles of calcium carbonate. These types of rocks are typically
deposited in horizontal layers, or strata, at the bottom of rivers, oceans, and deltas.
Limestone, sandstone, and clay are typical sedimentary rocks.
Petroleum-Bearing Rocks
Sedimentary rocks are the most important and interesting type of rock to the
petroleum industry because most oil and gas accumulations occur in them; igneous
and metamorphic rocks rarely contain oil and gas.
All petroleum source rocks are sedimentary.
Furthermore, most of the world’s oil lies in sedimentary rock formed from marine
sediments deposited on the edges of continents. For example, there are many large
deposits that lie along the Gulf of Mexico and the Persian Gulf.
Geologic Time
Geologic time and Earth’s geologic history are concepts that need to be clearly
understood and how they relate to the petroleum industry. It takes millions of years and
specific conditions for organic and sedimentary materials to be converted to recoverable
hydrocarbons.
The late eighteenth century is generally regarded as the beginning of modern geology.
During this time, James Hutton, a Scottish physician and gentleman farmer, published his
Theory of the Earth with Proof and Illustrations (1785) which put forth the principle of
uniformitarianism. This principle states that the geologic processes and forces now
operating to modify the earth’s crust have acted in much the same manner and with
essentially the same intensity throughout geologic time, and that past geologic events can
be explained by forces observable today. This is known as the classic concept “the
present is the key to the past.”
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Age Dating
Before radioactive materials were discovered, geologists used this and other principles
and an understanding of fossils to determine the relative ages of sedimentary rock layers;
that is, how old they are in relation to one another. Relative dating does not tell us how
long ago something took place, only that it followed one event and preceded another.
Once radioactivity was discovered, geologists used the physics of radioactive decay to
pinpoint a rock’s absolute age, that is, how many years ago it formed. Absolute dating
did not replace relative dating, but simply supplemented the relative dating technique.
The principle methods that have been used for direct radiochronology of sedimentary
rocks are as follows:
1. The Carbon-14 technique for organic materials.
2. The Potassium-Argon and Rubidium-Strontium techniques for glauconites,
hornblende, microclines, muscovites, biotites, etc.
3. The Thorium-230 technique for deep ocean sediments and aragonite corals.
4. The Protactinium-231 technique for ocean sediments and aragonite corals.
5. The Uranium-238 technique for apatite, volcanic glass, zircon, etc.
Figure 7 Layered rock sequence illustrating relative age and deposition of strata in
horizontal layers
To establish a relative time scale, a few simple principle or rules had to be discovered and
applied. Although they may seem rather obvious to us today, their discovery was a very
important scientific achievement.
Stratigraphy is the study of the origin, composition, distribution, and sequence of layers
of sedimentary rock, or strata. Stratification is the characteristic layering or bedding of
sedimentary rocks. This characteristic is basic to two of the principles used to interpret
geologic events from the sedimentary rock record. First is the principle of original
horizontality, which states that most layers of sediment are deposited in a nearly
horizontal layer. If a sequence of sedimentary rock layers are folded or tilted, then
generally it is understood that these layers were deformed by tectonic events after their
initial deposition. Second is the principle of superposition which states that each layer
of sedimentary rock in a sequence that has not been tectonically disturbed is younger
than the layer beneath it and older than the layer above it. Therefore, a series of
sedimentary layers can be viewed as a vertical time line. This produces either a partial or
complete record of the time elapsed from the deposition of the lowermost bed to the
deposition of the uppermost bed. This rule also applies to other surface deposited
materials such as lava flows or beds of ash from volcanic events. If igneous intrusions or
faults cut through strata, they are assumed to be younger than the structures they cut and
is known as the principle of cross-cutting relationships.
Paleontology, the study of life in past geologic time, based on fossil plants and animals,
is an important consideration in the stratigraphic record and is significant in assigning
ages to rock units. In early geologic endeavors, index fossils ( fossils with narrow
vertical stratigraphic ranges) represented the only means for realistic correlation and age
assignment of rock sequences. Correlation is the process of relating rocks at one site with
those at another site.
In 1793, William Smith, a surveyor working in southern England, recognized that fossils
could be used to date the relative ages of sedimentary rocks. He learned that he could
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map rock units from coal quarry to coal quarry over a large distance if he characterized
the layers by their lithology and fossil content. While mapping the vertical rock
sequences he established a general order of fossils and strata from the oldest at the
bottom to the youngest at the top. This stratigraphic ordering of fossils eventually
became known as the principle of faunal succession and states that fossil faunas and
floras in stratigraphic sequence succeed one another in a definite, recognizable order.
Smith was also the first person to define formations within a rock unit. A formation is a
rock unit that is mappable over a laterally extensive area and has the same physical
properties and contains the same fossil assemblages. Some formations consist of one
rock type, like limestone. Others may be interbedded, for example, alternating layers of
sandstone and shale, but can be mapped as one unit.
By combining faunal succession and stratigraphic sequences, geologists can correlate
formations in a local area or around the world. The petroleum industry relies on the
application of these principles for exploration and production.
During the nineteenth and twentieth centuries, geologists built on the knowledge of their
predecessors and started to build a worldwide rock column. Although it will never be
continuous from the beginning of time, the above principles have allowed geologists to
compile a composite worldwide relative time scale.
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Table 1 Illustrates the distribution of discovered oil and gas fields based on geologic age
Cretaceous 27
Jurassic 21
Permo-Triassic 6
Carboniferous 5
Devonian 1
Cambrian-Silurian 1
Total 100
processes. Primary carbonate deposition results from the precipitation and deposits
formed by plants and animals that utilize carbonates in their life processes. The most
abundant mineral chemically or biochemically precipitated in the oceans is calcite, most
of it the shelly remains of organisms and the main constituent of limestone. Many
limestones also contain dolomite, a calcium-magnesium carbonate precipitated during
lithification. Gypsum and halite are formed by the chemical precipitation during the
evaporation of seawater.
Sandstones
Sandstones are clastic sedimentary rocks composed of mainly sand size particles or
grains set in a matrix of silt or clay and more or less firmly united by a cementing
material (commonly silica, iron oxide, or calcium carbonate). The sand particles usually
consist of quartz, and the term “sandstone”, when used without qualification, indicates a
rock containing about 85-90% quartz.
(calcium carbonate, CaCO3), with or without magnesium carbonate. Limestones are the
most important and widely distributed of the carbonate rocks. Dolomite is a common
rock forming mineral with the formula CaMg(CO3)2. A sedimentary rock will be named
dolomite if that rock is composed of more than 90% mineral dolomite and less than 10%
mineral calcite.
Shales
Shale is a type of detrital sedimentary rock formed by the consolidation of fine-grained
material including clay, mud, and silt and have a layered or stratified structure parallel to
bedding. Shales are typically porous and contain hydrocarbons but generally exhibit no
permeability. Therefore, they typically do not form reservoirs but do make excellent cap
rocks. If a shale is fractured, it would have the potential to be a reservoir.
Evaporites
Evaporites do not form reservoirs like limestone and sandstone, but are very important to
petroleum exploration because they make excellent cap rocks and generate traps. The
term “evaporite” is used for all deposits, such as salt deposits, that are composed of
minerals that precipitated from saline solutions concentrated by evaporation. On
evaporation the general sequence of precipitation is: calcite, gypsum or anhydrite, halite,
and finally bittern salts.
Evaporites make excellent cap rocks because they are impermeable and, unlike lithified
shales, they deform plastically, not by fracturing.
The formation of salt structures can produce several different types of traps. One type is
created by the folding and faulting associated with the lateral and upward movement of
salt through overlying sediments. Salt overhangs create another type of trapping
mechanism.
Migration of Hydrocarbons
Primary migration is the process by which petroleum moves from source beds to
reservoir rocks. Secondary migration is the concentration and accumulation of oil and
gas in reservoir rock. Evidence that petroleum does migrate is suggested by the very
common occurrence of active seeps where oil and gas come to the surface either directly
from the source rock or from reservoir rocks. In either case, the petroleum had to migrate
through rocks with enough permeability and porosity to allow the fluids to flow to the
surface. Therefore, migration involves rock properties and fluid properties, including the
petroleum, moving through the rocks. Some of the rock and fluid properties include
porosity, permeability, capillary pressure, temperature and pressure gradients, and
viscosity. These and other properties will be discussed in detail in the sections to follow.
Temperature affects the chemical structure of hydrocarbons and can break heavier long-
chain molecules into smaller and lighter molecules. For a more detailed explanation of
the chemical properties of hydrocarbons, refer to Appendix A.
Kerogen/Bitumens
Crude Oil
Crude oil is a mixture of many hydrocarbons that are liquid at surface temperatures and
pressures, and are soluble in normal petroleum solvents. It can vary in type and amount
of hydrocarbons as well as which impurities it may contain.
Crude oil may be classified chemically (e.g. paraffinic, naphthenic) or by its density.
This is expressed as specific gravity or as API (American Petroleum Institute) gravity
according to the formula:
141.5
API o = - 131.5
sp. grav. @ 60 o F
Specific gravity is the ratio of the density of a substance to the density of water.
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API gravity is a standard adopted by the American Petroleum Institute for expressing the
specific weight of oils.
The lower the specific gravity, the higher the API gravity, for example, a fluid with a
specific gravity of 1.0 g cm –3 has an API value of 10 degrees. Heavy oils are those with
API gravities of less than 20 (sp. gr. >0.93). These oils have frequently suffered
chemical alteration as a result of microbial attack (biodegradation) and other effects. Not
only are heavy oils less valuable commercially, but they are considerably more difficult
to extract. API gravities of 20 to 40 degrees (sp. gr. 0.83 to 0.93) indicate normal oils.
Oils of API gravity greater than 40 degrees (sp. gr. < 0.83) are light.
Asphalt
Asphalt is a dark colored solid to semi-solid form of petroleum (at surface temperatures
and pressures) that consists of heavy hydrocarbons and bitumens. It can occur naturally
or as a residue in the refining of some petroleums. It generally contains appreciable
amounts of sulphur, oxygen, and nitrogen and unlike kerogen, asphalt is soluble in
normal petroleum solvents. It is produced by the partial maturation of kerogen or by the
degradation of mature crude oil. Asphalt is particularly suitable for making high-quality
gasoline and roofing and paving materials.
Natural Gas
There are two basic types of natural gas, biogenic gas and thermogenic gas. The
difference between the two is contingent upon conditions of origin. Biogenic gas is a
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natural gas formed solely as a result of bacterial activity in the early stages of diagenesis,
meaning it forms at low temperatures, at overburden depths of less than 3000 feet, and
under anaerobic conditions often associated with high rates of marine sediment
accumulation. Because of these factors, biogenic gas occurs in a variety of environments,
including contemporary deltas of the Nile, Mississippi and Amazon rivers. Currently it is
estimated that approximately 20% of the worlds known natural gas is biogenic.
Thermogenic gas is a natural gas resulting from the thermal alteration of kerogen due to
an increase in overburden pressure and temperature.
The major hydocarbon gases are: methane (CH4 ), ethane (C2H6), propane (C3H8), and
butane (C4H10).
The terms sweet and sour gas are used in the field to designate gases that are low or high,
respectively, in hydrogen sulfide.
Natural gas, as it comes from the well, is also classified as dry gas or wet gas, according
to the amount of natural gas liquid vapors it contains. A dry gas contains less than 0.1
gallon natural gas liquid vapors per 1,000 cubic feet, and a wet gas 0.3 or more liquid
vapors per 1,000 cubic feet.
Condensates
Condensates are hydrocarbons transitional between gas and crude oil (gaseous in the
subsurface but condensing to liquid at surface temperatures and pressures). Chemically,
condensates consist largely of paraffins, such as pentane, octane, and hexane.
Temperature Gradient
Temperature is generally a function of depth because of the earth’s natural geothermal
gradient. Normal heat flow within the earth’s crust produces a gradient of approximately
1.5°F for each 100 feet of depth below the surface. The temperatures required to
produce crude oil occur between 5,000 and 20,000 feet of depth. Temperatures below
20,000 feet are generally too high and only generate gas. Temperatures above 5,000 feet
are not usually sufficient enough to transform the material into crude oil. There are, of
course, exceptions to the rules. Geologic conditions such as volcanism and tectonics
(folding and faulting) can change or effect the temperature gradient.
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Pressure Gradient
Most pressure that effects
rocks is due to the weight
of overlying rocks and is
called overburden
pressure. Overburden
pressure is a function of
depth and increases one
pound per square inch for
each foot of depth. At
3000 feet, for example, the
overburden pressure would
be 3,000 pounds per square
inch. Hydrocarbons evolve
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Figure 14
35% Sandstone
45%
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Carbonate
Shale
20%
Chart 1
60%
50%
Sandstone
40%
Carbonate
30%
20% Other
10%
0%
Chart 2
It is important to note that carbonate reservoirs produce almost twice the amount of
hydrocarbons than sandstone reservoirs. This occurs because of substantial
production from carbonate reservoirs in the Middle East and Mexico
Depth
The physical characteristics of a reservoir are greatly affected by the depth at which they
occur.
Shallow reservoir— Created by the folding of relatively thick, moderately compacted
reservoir rock with accumulation under an anticline or some trap. The hydrocarbons
would generally be better separated as a result of lower internal reservoir pressures, less
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gas in solution and oil of increased viscosity, resulting from lower temperatures.
Deep reservoir— Typically created by severe faulting. The hydrocarbons would be less
separated with more gas in solution and oil of reduced viscosity because of higher
temperatures. There is often a reduction in porosity and permeability due to increased
compaction.
The total area of a reservoir and its thickness are of considerable importance in
determining if a reservoir is a commercial one or not. The greater the area and thickness
of the reservoir, the greater the potential for large accumulations of oil and gas. However,
there are reservoirs that produce substantial amounts of hydrocarbons that are not of
considerable size.
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Figure 15
Porosity
Porosity is the ratio of void space in a rock to the total volume of rock, and reflects the
fluid storage capacity of the reservoir.
• Primary Porosity— Amount of pore space present in the sediment at the time of
deposition, or formed during sedimentation. It is usually a function of the amount of
space between rock-forming grains.
• Fracture porosity
results from the
presence of openings
produced by the
breaking or shattering of
a rock. All rock types
are affected by
fracturing and a rocks
composition will
determine how brittle
the rock is and how
much fracturing will
occur. The two basic
types of fractures
include natural Figure 18 Fractures in rock material
tectonically related
fractures and hydraulically induced fractures. Hydraulic fracturing is a method of
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• Vug
gy
poro
sity
is a
form
of
seco
ndar
y
poro
sity
resul
ting Figure 19 Vuggy porosity in carbonates
from
the dissolution of the more soluble portions of rock or solution
enlargement of pores or fractures.
• Maximum Porosity vs. Realistic Porosity— Porosity can approach, in a very well
sorted uncompacted sand, a theoretical maximum of 47.6%. In a sandstone, this value
Controls on Porosity
Packing strongly affects the bulk density of the rocks as well as their porosity and
permeability. The effects of packing on porosity can be illustrated by considering the
change in porosity that takes place when even-size spheres are rearranged from open
packing (cubic packing) to tightest or closed packing (rhombohedral packing).
Cubic packing can yield a porosity of 47.6%. Rhombohedral packing yields
approximately 26.0%.
• Compaction
— Over a
long period
of time
sediments
can
accumulate
and create
formations
that are
thousands of
feet thick.
The weight Figure 23I Sedimentation process: Layer A is compacted
of the by layer B
overlying
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• Cementati
on —
Cementatio
n is the
crystallizati
on or
precipitatio
n of soluble
minerals in
the pore
spaces
between
clastic
Figure 24 Effect of cementation on porosity
particles.
The
process of lithification (the conversion of unconsolidated deposits
into solid rock) is completed by cementation. Common cementing
agents include calcite (CaCO3), silica (SiO2), and iron oxide
(Fe2O3). Minerals in solution crystallize out of solution to coat
grains and may eventually fill the pore spaces completely. Porosity
and permeability can be reduced significantly due to cementation.
Permeability
Permeability is usually measured parallel to the bedding planes of the reservoir rock and
is commonly referred to as horizontal permeability. This is generally the main path of the
flowing fluids into the borehole. Vertical permeability is measured across the bedding
planes and is usually less than horizontal permeability. The reason why horizontal
permeability is generally higher than vertical permeability lies largely in the arrangement
and packing of the rock grains during deposition and subsequent compaction. For
example, flat grains may align and overlap parallel to the depositional surface, thereby
increasing the horizontal permeability, see Figure 25. High vertical permeabilities are
generally the result of fractures and of solution along the fractures that cut across the
bedding planes. They are commonly found in carbonate rocks or other rock types with a
brittle fabric and also in clastic rocks with a high content of soluble material. As seen in
Figure 25, high vertical permeability may also be characteristic of uncemented or loosely
packed sandstones.
• Shales and clays which contain very fine-grained particles often exhibit very
high porosities. However, because the pores and pore throats within these formations
are so small, most shales and clays exhibit virtually no permeability.
• Some limestones may contain very little porosity, or isolated vuggy porosity that is
not interconnected. These types of formations will exhibit very little permeability.
However, if the formation is naturally fractured (or even hydraulically fractured),
permeability will be higher because the isolated pores are interconnected by the
fractures.
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Since the 1960’s, most developments in the logging industry have centered around the
improvement of existing tools and new evaluation techniques. With the advent of
Magnetic Resonance Imaging Logging (MRIL), the industry has been presented with an
exciting method of evaluating hydrocarbon reservoirs. MRI logging had its beginnings in
the late 1950’s and soon after was offered as a commercial service. With continued
improvements in technology and analysis methods, MRIL is quickly becoming a high-
demand service. In 1997 Halliburton Energy Services acquired Numar Corporation,
positioning itself as the industry leader in MRI logging.
With time-honored logging tools such as the induction, resistivity, and neutron-density,
there have always been limitations because of the effects of the formation upon log
response. These measurements depend upon petrophysical characteristics of the
formation, whereas the main purpose of the logging industry is to investigate the fluids
A B
Figure 27 The principle of surface tension
rubber, squeezing against the water below and keeping the air-water interface straight. In
a droplet of water, this same surface membrane keeps the droplet round, as if a balloon
filled with liquid.
Where one liquid is in contact with another liquid or is in contact with a solid, there exists
an attractive force on both sides of their interface called adhesion. This attractive force
is not balanced across the interface because the molecules on one side of the interface are
completely different from those on the other. The tension resulting from such unbalanced
attractive forces between two liquids or between a liquid and a solid is called interfacial
tension. Interfacial tension accounts for whether a fluid will be adhered to the surface of
a solid or repelled from that surface. Water, for example, will spread out and adhere to
glass because its interfacial tension is low in comparison to that of glass. Mercury, on the
other hand, has an interfacial tension that is high compared to that of glass and therefore
will not adhere to the glass, but rather contract into a droplet. This principle is extremely
important in reservoir fluid mechanics because these same forces operate between rock
material (matrix) and the fluids filling the porosity. The force of adhesion between water
and most matrix material is greater than that of most oils. Therefore, if a rock contains
both water and oil, typically the water will occur as a film adhering to the rock grains
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with the oil occupying the space between, see Figure 28. Such a reservoir is said to be
water-wet, because water is the fluid phase that is “wetting” the grains of the rock. In
some instances, although rarer, the chemistry of the oil may be such that it is the fluid
that is in contact with the grains of the rock. This type of reservoir is said to be oil-wet.
Capillary Pressure
Reservoir rocks are
composed of varying sizes
of grains, pores, and
capillaries (channels
between grains which
connect pores together,
sometimes called pore
throats). As the size of the
pores and channels
decrease, the surface
tension of fluids in the rock
increases. When there are
several fluids in the rock, Figure 30 Capillary pressure effects in reservoirs
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As previously stated, all sedimentary rocks have porosity that is fluid saturated. The fluid
is sometimes oil and/or gas, but water is always present. Water saturation is defined as
the fraction of that porosity that is occupied by water. If the pore space is not occupied
by water, then it must be occupied by hydrocarbons. Therefore, by determining a value
of water saturation from porosity and resistivity measurements, it is possible to determine
the fraction of pore space that is occupied by hydrocarbons (hydrocarbon saturation).
Water saturation simply refers to the amount of water that is present in the reservoir, and
says nothing about its ability to be produced. In a reservoir containing a small amount of
water, it might be possible to produce this water if capillary pressures are low and the
water is not adsorbed (adhered) onto the surfaces of rock grains. However, if this water
is adhered to the surfaces of rock grains and there is a high capillary pressure, then it is
possible to produce water-free hydrocarbons from a reservoir that does contain some
water.
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For any reservoir, there is a certain value of water saturation at which all of the contained
water will be trapped by capillary pressure and/or by adsorption of water on the surface
of rock grains (surface tension). This is referred to as irreducible water saturation
(Swirr). At irreducible water saturation, all of the water within the reservoir will be
immovable, and hydrocarbon production will be water-free.
Geologic processes such as faulting, folding, piercement, and deposition and erosion
create irregularities in the subsurface strata which may cause oil and gas to be retained in
a porous formation, thereby creating a petroleum reservoir. The rocks that form the
barrier, or trap, are referred to as caprocks.
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Structural Traps
Structural traps are created by the deformation of rock strata within the earth’s crust.
This deformation can be caused by horizontal compression or tension, vertical movement
and differential compaction, which results in the folding, tilting and faulting within
sedimentary rock formations.
Figure 35 Faulting
Figure 36 Folding
Stratigraphic Traps
• Pinch-out or
lateral graded
trap— A trap
created by lateral
differential
deposition when
the environmental
deposition changes
up-dip.
Subsurface Mapping
Geologic maps are a representation of the distribution of rocks and other geologic
materials of different lithologies and ages over the Earth’s surface or below it. The
geologist measures and describes the rock sections and plots the different formations on a
map, which shows their distribution. Just as a surface relief map shows the presence of
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mountains and valleys, subsurface mapping is a valuable tool for locating underground
features that may form traps or outline the boundaries of a possible reservoir. Once a
reservoir has been discovered, it is also the job of the geologist to present enough
evidence to support the development and production of that reservoir.
Subsurface mapping is used to work out the geology of petroleum deposits. Three-
dimensional subsurface mapping is made possible by the use of well data and helps to
decipher the underground geology of a large area where there are no outcrops at the
surface.
Some of the commonly prepared subsurface geological maps used for exploration and
production include; (1) geophysical surveys, (2) structural maps and sections, (3)
isopach maps, and (4) lithofacies maps.
Geophysical Surveys
Seismic Surveys
The geophysical method that provides the most detailed picture of subsurface geology is
the seismic survey. This involves the natural or artificial generation and propagation of
seismic (elastic) waves down into Earth until they encounter a discontinuity (any
interruption in sedimentation) and are reflected back to the surface. On-land, seismic
“shooting” produces acoustic waves at or near the surface by energy sources such as
Electronic detectors called geophones then pick up the reflected acoustic waves. The
signal from the detector is then amplified, filtered to remove excess “noise”, digitized,
and then transmitted to a nearby truck to be recorded on magnetic tape or disk.
In the early days of offshore exploration, explosive charges suspended from floats were
used to generate the necessary sound waves. This method is now banned in many parts
of the world because of environmental considerations. One of the most common ways to
generate acoustic waves today is an air gun. Air guns contain chambers of compressed
gas. When the gas is released under water, it makes a loud “pop” and the seismic waves
travel through the rock layers until they are reflected back to the surface where they are
picked up by hydrophones, the marine version of geophones, which trail behind the boat.
The data recorded on magnetic tape or disk can be displayed in a number of forms for
interpretation and research purposes; including visual display forms (photographic and
dry-paper), a display of the amplitude of arriving seismic waves versus their arrival time,
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Magnetic Surveys
Magnetic surveys are methods that provide the quickest and least expensive way to study
gross subsurface geology over a broad area. A magnetometer is used to measure local
variations in the strength of the earth’s magnetic field and, indirectly, the thickness of
sedimentary rock layers where oil and gas might be found. Igneous and metamorphic
rocks usually contain some amount of magnetically susceptible iron-bearing minerals and
are frequently found as basement rock that lies beneath sedimentary rock layers.
Basement rock seldom contains hydrocarbons, but it sometimes intrudes into the
overlying sedimentary rock, creating structures such as folds and arches or anticlines that
could serve as hydrocarbon traps. Geophysicists can get a fairly good picture of the
configuration of the geological formations by studying the anomalies, or irregularities, in
the structures.
The earth’s magnetic field, although more complex, can be thought of as a bar magnet,
around which the lines of magnetic force form smooth, evenly spaced curves. If a small
piece of iron or titanium is placed within the bar magnet’s field it becomes weakly
magnetized, creating an anomaly or distortion of the field. The degree to which igneous
rocks concentrate this field is not only dependent upon the amount of iron or titanium
present but also upon the depth of the rock. An igneous rock formation 1,000 feet below
the surface will affect a magnetometer more strongly than a similar mass 10,000 feet
down. Thus, a relatively low magnetic field strength would indicate an area with the
thickest sequence of nonmagnetic sedimentary rock. Once the magnetic readings have
been plotted on a map, points of equal field strength are connected by contour lines, thus
creating a map that is the rough equivalent to a topographic map of the basement rock.
This can be useful in locating basic geologic structures, although it will not reveal details
of the structures or stratigraphy.
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Gravity Surveys
The gravity survey method makes use of the earth’s gravitational field to determine the
presence of gravity anomalies (abnormally high or low gravity values) which can be
related to the presence of dense igneous or metamorphic rock or light sedimentary rock in
the subsurface. Dense igneous or metamorphic basement rocks close to the surface will
read much higher on a gravimeter because the gravitational force they exert is more
powerful than the lighter sedimentary rocks. The difference in mass for equal volumes of
rock is due to variations in specific gravity.
Although mechanically simple, a gravimeter can measure gravity anomalies as small as
one billionth of the earth’s surface gravity. Data collected from gravity surveys can be
used to construct contour maps showing large-scale structures and, like magnetic survey
contour maps, smaller details will not be revealed.
Geophysicists applied this knowledge, particularly in the early days of prospecting off the
Gulf of Mexico. Often, they could locate salt domes using data from a gravity survey
because ordinary domal and anticlinal structures are associated with maximum gravity,
whereas salt domes are usually associated with minimum gravity.
Contour maps show a series of lines drawn at regular intervals. The points on each line
represent equal values, such as depth or thickness. One type of contour map is the
structural map, which depicts the depth of a specific formation from the surface. The
principle is the same as that used in a topographic map, but instead shows the highs and
lows of the buried layers.
Contour maps for exploration may depict geologic structure as well as thickness of
formations. They can show the angle of a fault and where it intersects with formations
and other faults, as well as where formations taper off or stop abruptly. The subsurface
structural contour map is almost or fully dependent on well data for basic control
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Figure 43 Structural map and longitudinal profile section showing top of salt, which is datum for structure
contours
Cross-Sections
Isopach Maps
Isopach maps are similar in appearance to contour maps but show variations in the
thickness of the bed. These maps may be either surface or subsurface depending on data
used during construction. Isopach maps are frequently color coded to assist visualization
and are very useful in following pinchouts or the courses of ancient stream beds.
Porosity or permeability variations may also be followed by such means. Geologists use
isopach maps to aid in exploration work, to calculate how much petroleum remains in a
formation, and to plan ways to recover it.
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Lithofacies Maps
Lithofacies maps show, by one means or another, changes in lithologic character and how
it varies horizontally within the formation. This type of map has contours representing
the variations in the proportion of sandstone, shale, and other kinds of rocks in the
formation.
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Identification of source and reservoir rocks, their distribution, and their thickness’ are
essential in an exploration program, therefore, exploration, particularly over large areas,
requires correlation of geologic sections. Correlations produce cross-sections that give
visual information about structure, stratigraphy, porosity, lithology and thickness of
important formations. This is one of the fundamental uses of well logs for geologists.
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Wells that have information collected by driller’s logs, sample logs, and wireline logs
enable the geologists to predict more precisely where similar rock formations will occur
in other subsurface locations.
Subsurface correlation is based primarily on stratigraphic continuity, or the premise that
formations maintain the same thickness from one well to another. A major change in
thickness, rock type, or faunal content can be a geologic indicator that conditions forming
the strata changed, or it may be a signal of an event that could have caused hydrocarbons
to accumulate.
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Figure 48 Stratigraphic cross-section constructed from correlated well logs showing the effect of pinchout
of sand 3
Surface Geology
There are several areas to look for oil. The first is the obvious, on the surface of the
ground. Oil and gas seeps are where the petroleum has migrated from its’ source
through either porous beds, faults or springs and appears at the surface. Locating seeps at
the surface was the primary method of exploration in the late 1800’s and before.
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Figure 49 Seeps are located either updip (A) or along fractures (B)
Seeps are abundant and well documented worldwide. Oil or gas on the surface, however,
does not give an indication of what lies in the subsurface. It is the combination of data
that gives the indication of what lies below the surface. Geologic mapping, geophysics,
geochemistry and aerial photography are all crucial aspects in the exploration for oil and
gas.
Log measurements, when properly calibrated, can give the majority of the parameters
required. Specifically, logs can provide a direct measurement or give a good indication
of:
These parameters can provide good estimates of the reservoir size and the hydrocarbons
in place.
Logging techniques in cased holes can provide much of the data needed to monitor
primary production and also to gauge the applicability of waterflooding and monitor its
progress when installed. In producing wells, logging can provide measurements of :
Flow rates
Fluid type
Pressure
Residual oil saturations
Logging can answer many questions on topics ranging from basic geology to economics;
however, logging by itself cannot answer all the formation evaluation problems. Coring,
core analysis, and formation testing are all integral parts of any formation evaluation
effort.
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Well Cuttings
Well samples are produced from drilling operations, by the drill bit penetrating the
formation encountered in the subsurface. Samples are taken at regular intervals. They
are used to establish a lithologic record of the well and are plotted on a strip sample log.
Cores
Cores are cut where specific lithologic and rock parameter data are
required. They are cut by a hollow core barrel, which goes down
around the rock core as drilling proceeds. When the core barrel is
full and the length of the core occupies the entire interior of the core
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barrel, it is brought to the surface, and the core is removed and laid
out in stratigraphic sequence. It is important to note that the sample
may undergo physical changes on its journey from the bottom of the
well, where it is cut, to the surface, where it is analyzed. Cores are
preferable to well cuttings because they produce coherent rock. They
are significantly more expensive to obtain, however. Sidewall cores
are small samples of rock obtained by shooting small metal cylinders
from a gun into the walls of a drill hole. Sidewall cores can be taken
from several levels and at different locations by using the versatile
sidewall coring gun tool. Sidewall cores may also be taken using a
wireline tool called the RSCT (Rotary Sidewall Coring Tool).
Figure 50
Conventional Sidewall
Core Gun
Formation properties can be measured at the time the formation is drilled by use of
special drill collars that house measuring devices. These logging-while-drilling (LWD)
tools are particularly valuable in deviated, offshore, or horizontally drilled wells.
Although not as complete as open-hole logs, the measurements obtained by MWD are
rapidly becoming just as accurate and usable in log analysis procedures.
Formation Testing
of the reservoir and its ability to produce in the long term, than any other method except
established production from a completed well.
Wireline formation testers complement drillstem tests by their ability to sample many
different horizons in the well and produce not only fluid samples but also detailed
formation pressure data that are almost impossible to obtain from a DST alone.
Figure 53 Perforation
Borehole Environment
Reservoir properties are measured by lowering a tool attached to a wireline or cable into
a borehole. The borehole may be filled with water-based drilling mud, oil-based mud, or
air. During the drilling process, the drilling mud invades the rock surrounding the
borehole, which affects logging measurements and the movement of fluids into and out of
the formation. All of these factors must be taken into account while logging and during
log analysis. It is important to understand the wellbore environment and the following
characteristics: hole diameter, drilling mud, mudcake, mud filtrate, flushed zone, invaded
zone and the univaded zone.
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• Hole diameter (dh)— The size of the borehole determined by the diameter of the
drill bit.
• Drilling Mud Resistivity (Rm)— Resistivity of the fluid used to drill a borehole and
which lubricates the bit, removes cuttings, maintains the walls of the borehole and
maintains borehole over formation pressure. Drilling mud consists of a variety of
clay and other materials in a fresh or saline aqueous solution and has a measurable
resistivity.
• Mud Filtrate (Rmf)— Resistivity of the liquid drilling mud components that infiltrate
the formation, leaving the mudcake on the walls of the borehole.
Resistivity values for the drilling mud, mudcake, and mud filtrate are determined
during a full mud press and are recorded on a log’s header.
• Invaded Zone— The zone which is invaded by mud filtrate. It consists of a flushed
zone (Rxo) and a transition or annulus zone (Ri). The flushed zone (Rxo) occurs close
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to the borehole where the mud filtrate has almost completely flushed out the
formation’s hydrocarbons and/or water. The transition or annulus zone (Ri), where a
formation’s fluids and mud filtrate are mixed, occurs between the flushed zone (Rxo)
and the univaded zone (Rt).
• Uninvaded Zone (Rt)— Pores in the univaded zone are uncontaminated by mud
filtrate; instead, they are saturated with formation fluids (water, oil and/or gas).
Well-site analysis generally concerns the evaluation of two types of logs: electrical or
resistivity logs, and porosity logs. Resistivity and porosity are the singlemost
important measurements made by conventional logging tools, and form the
foundation on which the entire industry is built. With the data presented on these logs
and others, analysts can determine not only the lithology and productive capabilities of
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the formation of interest, but also the relative proportion of water (water saturation), and
therefore hydrocarbons that the formation contains.
Log Data
Porosity
To calculate porosity (φ) we measure bulk density (ρb), hydrogen index (HI) and/or
interval transit time (∆t). A sonic tool measures internal transit time (∆t) and is used to
determine the effective porosity of a reservoir. The neutron-density combination is used
to calculate porosity two different ways, and provides us with a value of total porosity.
Remember
• Effective porosity is the interconnected pore volume available to free fluids. Total porosity is all void
space in a rock and matrix, whether effective or noneffective.
Resistivity
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Resistivity is, perhaps, the most fundamental of all measurements in logging. All
geological materials posses some amount of resistance, or the inherent ability to resist the
flow of an electrical current.
Resistivity (R) is the physical measurement of resistance, and is defined as the reciprocal
of electrical conductivity (C).
1000
R=
C
Oil and gas are electrical insulators. They will not conduct the flow of an electrical
current, and therefore their resistivities are said to be infinite. Water, however, will
conduct electricity depending upon its salinity. Salt water, with high concentrations of
dissolved solids (e.g., NaCl, etc), will conduct electricity much more readily than will
fresh water. Therefore, salt water has a much lower resistivity than does fresh water. In
most instances, the water present in a formation will be saline, and will have a resistivity
much lower than or similar to the resistivity of the fluid used to drill a well penetrating
that formation.
A current and a voltage are measured using an induction or resistivity tool. From these
measurements, resistivity (R) can be calculated by Ohm’s Law.
V
R=
I
The amount of current flow that can be supported by a formation depends upon the
resistance of the formation matrix (i.e., rock) and the conductive properties of the fluids
that formation contains. Salt water, for instance, requires very little voltage to produce a
current flow. The resulting ratio of voltage to current (expressed as resistivity) is
therefore low. Oil, on the other hand, requires that extremely high voltages be applied in
order to generate an electrical current. It is because of this condition that the resistivity of
hydrocarbons is said to be infinite (hydrocarbons are insulators).
• Start with a dense quartz sandstone with no porosity. Rock is an electrical insulator→
R = ∞.
• Add porosity, but no fluid occupies the pores. Rock and air are electrical insulators
→ R = ∞.
• Add even more saline water. Even more current conducted → further decrease in R.
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Water Saturation
Water saturation (Sw) is calculated from porosity (φ) and resistivity (R) and some basic
assumptions.
Assumptions
• if porosity (φ) is measured 2-3 inches from the borehole wall, then you must assume
that to be representative of the entire formation
• deep resistivity is measured 5-7 feet from the borehole wall, then you must assume
that to be representative of the univaded zone
These assumptions are used in calculating the water saturation (Sw) of the uninvaded
zone.
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φ — Porosity
a — Tortuosity factor
m — Cementation exponent
Rt — True resistivity, of the univaded zone
Sw — Water saturation
Consider a formation with a given amount of porosity, and assume that the porosity is
completely filled with saline formation water of a given resistivity. Because saline water
is capable of conducting an electric current, the formation water resistivity (Rw) is quite
low. The measured resistivity of the formation itself (Ro, wet resistivity, where porosity
is 100% filled with water) will depend upon
Ro
Fr =
Rw
1
F=
Φ
This relationship between formation resistivity and porosity was first researched by G. E.
Archie, of the Humble Oil Company, while working on limestones in France. Archie had
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electric (resistivity) logs from several wells, and core porosity from productive zones
within these wells. He noticed that there was some relation between resistivity and
porosity, and thus was able to identify zones of interest through the use of electric logs
alone. What he wanted to know was if there was some relationship that made it possible
to determine whether a zone would be productive on the basis of measured resistivity and
core porosity.
Changes in the porosity of a formation may have effects other than simply increasing or
decreasing the amounts of fluids available to conduct electric current. With a change in
porosity, there may be concomitant changes in the complexity of the pore network that
affect the conductive nature of the fluids present, and formation resistivity factor (Fr) can
therefore vary with the type of reservoir. These changes are expressed by
a
and (m) cementation exponent Fr =
Φm
For the limestones of Archie’s experiments, the tortuosity factors and cementation
exponents were always constant (a = 1.0, m = 2.0). However, this may not be the case
for sandstone reservoirs. Although both parameters can be determined experimentally for
a specific reservoir, log analysts commonly use set values for tortuosity factor (a) and
cementation exponent (m), depending upon lithology and porosity, which are presented
below.
Table 2 Standard values for tortuosity factor (a) and cementation exponent (m).
Sandstones
Carbonates Porosity Φ > 16% Porosity Φ < 16%
(Humble) (Tixier)
Consider now that the porous formation discussed previously is filled with some
combination of conductive formation water of constant resistivity (Rw) , and oil. Oil is an
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insulator and will not conduct an electrical current. Furthermore, because the formation
is filled with both water and oil, the resistivity of the formation can no longer be referred
to as wet resistivity (Ro). The measure of formation resistivity in this instance—taking
into account the resistivity of the rock matrix and the fluids contained—is called true
resistivity (Rt). True resistivity of a formation will only be equal to wet resistivity (Rt =
Ro) when that formation is completely filled with conductive water. However, because
some of the available porosity may be filled with non-conductive oil, the theoretical wet
resistivity (Ro) of that formation is now related to the measured true resistivity (Rt) by
some additional factor, referred to as F′ .
R o = F′ × R t
The factor F′ can therefore be expressed as a ratio of the theoretical wet resistivity of that
formation (Ro) to the actual measured resistivity of the formation (Rt).
Ro
F′ =
Rt
In the example formation, because both porosity and formation water resistivity are
considered to be constant, the resulting theoretical wet resistivity (Ro) will be constant.
Therefore, changes in the factor F′ will occur with changes in measured resistivity (Rt).
Under the given conditions, the only way in which true measured resistivity (Rt) of the
formation can change is through the addition or subtraction of conductive fluid.
For example, the addition of oil to the reservoir would result in the increase of that
formation’s measured resistivity (Rt) because some amount of conductive formation
water would be displaced by the oil. Therefore, the factor F′ is dependent upon the
relative proportion of conductive fluids (water) and non-conductive fluids (hydrocarbons)
in the formation.
The factor F′ in the above equations represents water saturation (usually expressed Sw)
which is the percentage of pore space within a formation that is occupied by conductive
F× Rw a R
Sw = Sw = × w
n n
or
Rt Φ m
Rt
a R
Sw = n × w
Φ m
Rt
It is important to realize that while water saturation (Sw) represents the percentage of
water present in the pores of a formation, it does not represent the ratio of water to
hydrocarbons that will be produced from a reservoir. Shaly sandstone reservoirs with
clay minerals that trap a large amount of formation water may have high water
saturations, yet produce only hydrocarbons. Saturations simply reflect the relative
proportions of these fluids contained in the reservoir. Nonetheless, obtaining accurate
values for water saturation is the primary goal of open-hole log analysis. With the
knowledge of water saturation, it is possible to determine that percentage of porosity that
is filled with a fluid other than water (i.e., hydrocarbons), and therefore hydrocarbon
reserves.
Review of Permeability
As previously stated, permeability is the property that permits the passage of a fluid
through the interconnected pores of a rock.
Permeability is measured in darcies. A rock that has a permeability of 1 darcy permits 1
cc of fluid with a viscosity of 1 centipoise (viscosity of water at 68°F) to flow through
one square centimeter of its surface for a distance of 1 centimeter in 1 second with a
pressure drop of 14.7 pounds per square inch.
Few rocks have a permeability of 1 darcy, therefore permeability is usually expressed in
millidarcies or 1/1000 of a darcy.
The permeabilities of average reservoir rocks generally range between 5 and 1000
millidarcys. A reservoir rock whose permeability is 5 md or less is called a tight sand or
a dense limestone, according to composition. A rough field appraisal of reservoir
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permeabilities is:
Fair 1-10 md
Good 10-100 md
Very good 100-1,000 md
• Absolute Permeability (Ka)— Permeability calculated with only one fluid present in
the pores of a formation.
• Effective Permeability (Ke)— The ability of a rock to conduct one fluid in the
presence of another, considering that both fluids are immiscible (e.g., oil and water).
Effective permeability depends not only on the permeability of the rock itself, but
also on the relative amounts of the different types of fluid present.
The following chart illustrates the relative permeabilities of oil and water in an example
formation. In a reservoir 100% saturated with oil, the relative permeability of oil (Kro) to
water is equal to 1. As water saturation increases, the relative permeability of oil to water
will begin to decrease. The value of water saturation where no water will flow is referred
to as irreducible water saturation (Swirr). At some value of water saturation, water will
begin to flow within the formation because it can no longer be contained by capillary
pressure. With increasing water saturation, the relative permeability of oil (Kro) to water
will continue to decrease. Meanwhile, the relative permeability of water (Krw) to oil will
increase. Eventually, a value of water saturation will be reached at which the relative
permeability of oil (Kro) to water is 0. At this point, oil will no longer flow within the
reservoir, and that value of water saturation is referred to as residual oil saturation
(ROS). At water saturations above the residual oil saturation, only water will flow within
the reservoir. In a reservoir 100% saturated with water, the relative permeability of water
(Krw) to oil is equal to 1.
Notice from Chart 3 that there is a point at which the relative permeability of oil (Kro) is
equal to the relative permeability of water (Krw). At this value of water saturation
(approximately 55% in this example), both oil and water will flow with equal ease. This
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1
Krw
Relative Permeability
0.8
0.6 Kro
0.4
0.2
Swirr ROS
0
0 10 20 30 40 50 60 70 80 90 100
Water Saturation %
Chart 3
does not mean that the same amounts of oil and water will be produced from the
reservoir. The amount of fluid flowing is not a direct effect of the relative permeability
of a fluid because different fluids have different viscosities. For example, if water and
gas were existing in a reservoir and had equal relative permeabilities (Krw = Krg), the
more gas would flow within the formation because the viscosity of gas is much lower
than that of water.
Reserve Estimation
Accurately estimating the reserves of hydrocarbons in the reservoir is extremely
important. This calculation not only relies on computations from log data but also on the
size and shape of a reservoir, and correlations of logs from many wells in the field.
Dipmeter data and seismic data also assist the analyst in making accurate calculations. In
summary, a log analyst can say with some reasonable degree of certainty that, for
example, 10% of the volume of the reservoir is full of oil. It is up to others to determine
the size of the reservoir and therefore deduce the actual volume of oil available.
trap or the OIP (oil-in-place). This is accomplished when some reservoir thickness (h) is
delineated to exist over an area (A) to produce a volume (V). If (h) is measured in feet
and (A) in acres, the reservoir volume (V) is expressed in acre-feet.
In actual reservoirs, both porosity and saturation vary laterally and vertically. A useful
quantity for oil-in-place measurements is therefore the hydrocarbon pore volume, or
HCPV, which is defined as:
HCPV = Φ(1-Sw)
OIP = Σ Φ(1-Sw)h ∗A
Second, we must convert the oil-in-place to reserves which requires two additional pieces
of data: the recovery factor (r) and the formation volume factor (B). Neither of these can
be estimated from logs. The recovery factor is a function of the type of reservoir and the
drive mechanism, and the formation volume factor is a function of the hydrocarbon
properties. The reserves (N), in terms of stock tank volumes, are thus expressed as
C ∗ Σ Φ (1 - Sw)h ∗ A ∗ r
N=
B
Reserves (N) are expressed in stock tank barrels at Standard Temperature and Pressure
(STP).
= 1.33 ± 0.16
Appendix
As previously stated, hydrocarbons are formed from the alteration of sediment and
organic materials. They are the simplest organic compounds, consisting of only carbon
and hydrogen. They are classified according to the ratio of carbon and hydrogen, their
molecular structure, and their molecular weight. Hydrocarbons have been divided into
various series, differing in chemical properties and relationships. The four that comprise
most of the naturally occurring petroleums are the normal paraffin (or alkane) series, the
isoparaffin (or branched-chain paraffin) series, the naphthene (or cycloparaffin) series,
and the aromatic (or benzene) series. A fifth group is the NSO compounds, which are
hydrocarbon compounds that sometimes contain substantial amounts of nitrogen, sulphur,
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and hydrogen with other elements, predominantly nitrogen (N), sulfur (S), and oxygen
(O), in complex molecules.
Nearly all crude oils contain small quantities of nitrogen. Nothing is known of the nature
of the nitrogen compounds in undistilled crude oil, but the nitrogen compounds in the
distillates are frequently of the general type known as pyridines (C5H5N) and quinolines
(C9H7N). Since nitrogen is a common, inert constituent of natural gas, it may be that the
nitrogen content of the crude oil is contained in the dissolved gases. Nitrogen is an
unwanted component of both crude oil and natural gas.
Sulfur occurs to some extent in practically all crude oils and in each of the fractions that
make up the oil. It may be in one of the following forms: free sulfur, hydrogen sulfide
(H2S), or organic sulfur compounds. The presence of sulfur and sulfur compounds in
gasoline causes corrosion, bad odor, and poor explosion. Before the development of
modern cracking processes by refineries, the presence of sulfur made petroleum less
desirable and consequently worth less per barrel. Since sulfur can now be removed from
oil, this price differential has been largely eliminated, and sulfur-bearing crude oils are
nearly equal to nonsulfur crudes.
Oxygen is found in crude oil and occurs in the following various forms: free oxygen,
phenols (C6H5OH), fatty acids and their derivatives, and naphthenic acids.
Glossary
AccretionThe process by which an object grows larger due to the addition of fresh
material to the outside.
References
Allen, P.A. and J.R. Allen, 1990, Basin Analysis – Principles and Applications: Blackwell
Science Ltd., Osney Mead, Oxford. 451.
Asquith, G.B., 1982, Basic Well Log Analysis for Geologists: The American Association of
Petroleum Geologists, Tulsa, OK. 216.
Boggs, S. Jr., 1995, Principles of Sedimentology and Stratigraphy, Second Edition: Prentice
Hall, Upper Saddle River, NJ. 774.
Hatcher, R.D. Jr., 1995, Structural Geology – Principles, Concepts, and Problems, Second
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