Basic Petroleum engineering

INTRODUCTION..............................................................................................................6
ORIGIN OF PETROLEUM...............................................................................................7
Inorganic Theories.........................................................................................................7
Deep seated terrestrial hypothesis................................................................................7
Extraterrestrial hypothesis...........................................................................................7
Problems with inorganic hypotheses............................................................................8
Generation of crude oil................................................................................................13
Generation of Natural Gas..........................................................................................14
CHEMISTRY OF PETROLEUM....................................................................................15
Introduction:................................................................................................................15
Hydrocarbons ..............................................................................................................15
Paraffin Series............................................................................................................16
Unsaturated Hydrocarbons.........................................................................................18
Naphthene Hydrocarbons...........................................................................................19
Aromatic Hydrocarbons ............................................................................................19
Types of Crude Oils.....................................................................................................20
Paraffin-based Crude Oils..........................................................................................20
Asphaltic Based Crude Oils.......................................................................................20
Mixed Base Crude Oils..............................................................................................21
Natural Gas ..................................................................................................................21
PETROLEUM GEOLOGY..............................................................................................22
The Rock Cycle............................................................................................................22
The 3 basic types of rocks............................................................................................25
Igneous Rocks...............................................................................................................25
Texture.......................................................................................................................26
Composition...............................................................................................................26
Sedimentary Rocks......................................................................................................27
Clastic sedimentary rocks: ........................................................................................28
Sandstone...................................................................................................................28
Conglomerate.............................................................................................................28
Shale...........................................................................................................................29
Clays..........................................................................................................................29
Bentonite....................................................................................................................30
Chemical sedimentary rocks: ....................................................................................30
Organic sedimentary rocks........................................................................................30
Metamorphic Rocks.....................................................................................................31
The Geological Time Scale .........................................................................................31
GEOLOGICAL FEATURES............................................................................................34
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Reservoir Rock ............................................................................................................34
Traps .............................................................................................................................34
Anticline Trap............................................................................................................35
Fault trap....................................................................................................................35
Thrust Fault................................................................................................................36
Salt Dome Trap .........................................................................................................38
Stratigraphic Trap.......................................................................................................38
PETROLEUM RESERVOIRS.........................................................................................40
Reservoir Properties ...................................................................................................40
Permeability..................................................................................................................40
Darcy’s Equation for linear incompressible fluid flow..............................................41
Porosity and hydraulic conductivity..........................................................................43
Sorting and porosity..........................................................................................................43
Types of porosity........................................................................................................43
Measuring Porosity....................................................................................................43
Water Saturation..........................................................................................................44
Determining Fluids in Place .......................................................................................45
PETROLEUM RESERVES DEFINITIONS..................................................................46
Proved Reserves...........................................................................................................47
Unproved Reserves......................................................................................................48
Probable Reserves......................................................................................................48
Possible Reserves.......................................................................................................49
Reserve Status Categories...........................................................................................49
Developed Reserves...................................................................................................49
Producing Reserves....................................................................................................50
Non-producing Reserves............................................................................................50
Undeveloped Reserves...............................................................................................50
SURFACE EXPLORATION METHODS.......................................................................51
Field Reconnaissance...................................................................................................51
Aerial surveys ..............................................................................................................51
Surface Geochemical Analysis ...................................................................................51
GEOPHYSICAL EXPLORATION..................................................................................52
Seismic Surveys............................................................................................................53
Seismic Section .........................................................................................................53
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Seismic data acquisition ............................................................................................54
Seismic data processing ............................................................................................55
Marine Seismic acquisition.........................................................................................56
Seismic records and the synthetic seismogram..........................................................57
Gravity Surveys............................................................................................................62
Magnetic Surveys.........................................................................................................63
STRUCTURE CONTOUR MAPPING............................................................................65
Rules for Construction...............................................................................................67
Example.....................................................................................................................67
Subsurface Exploration Methods....................................................................................69
Rock Cuttings...............................................................................................................69
Reservoir Fluid Samples..............................................................................................69
Mud Logs......................................................................................................................69
Cores..............................................................................................................................70
Well Logs...........................................................................................................................71
The Spontaneous Potential (SP) log...........................................................................71
TheResistivity log.........................................................................................................77
The "Porosity" logs......................................................................................................80
Drill Stem Testing.........................................................................................................86
Appraisal Wells............................................................................................................86
Reservoir Development Plan............................................................................................87
Development Wells.......................................................................................................87
Producing Wells.........................................................................................................87
Injection Wells...........................................................................................................88
Reservoir Pressure Control........................................................................................88
Observation Wells......................................................................................................89
The Drilling Process.........................................................................................................90
Rigging up.....................................................................................................................91
Blowout prevention....................................................................................................94
Drilling..........................................................................................................................94
Well Completion...........................................................................................................96
Casing String and Design Factors..............................................................................96
Conductor Pipe...........................................................................................................97
The Surface String.....................................................................................................98
Intermediate String ....................................................................................................98
The Production String................................................................................................98
Production Choke.......................................................................................................98
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Running the casing.......................................................................................................99
Primary Cementing ..................................................................................................100
Squeeze Cementing....................................................................................................101
Well Completion..............................................................................................................101
Conventional Single Zone Completion....................................................................102
Open Hole Completion............................................................................................102
Single Zone Cased Hole Completion.......................................................................102
Conventional Multiple Completion..........................................................................103
Tubingless Completion..............................................................................................103
Tubing.........................................................................................................................104
Packers........................................................................................................................104
Wellheads....................................................................................................................104
Casing Gun Perforating............................................................................................107
Through tubing perforating......................................................................................107
Tubing Conveyed Perforating..................................................................................108
Production EQUATIONS...............................................................................................109
Productivity Index.....................................................................................................109
Inflow Performance Relationship ............................................................................110
Formation Damage and skin factor..........................................................................110
Flow Efficiency...........................................................................................................110
Darcy Equation for Radial Flow...............................................................................112
Artificial Lift...................................................................................................................113
Gas Lift........................................................................................................................114
Continuous Gas lift..................................................................................................115
Intermittent Gas Lift.................................................................................................115
Plunger Lift..............................................................................................................116
Advantages of plunger lift..............................................................................................116
Beam Pumping...........................................................................................................117
Electric Submersible Pump.......................................................................................118
Progressive Cavity Pump .........................................................................................119
PCP System Applications.........................................................................................120
Reservoir Development Practices...................................................................................121
Hydrocarbon Recovery Mechanisms.............................................................................122
Primary Recovery .....................................................................................................122
Dissolved Gas Drive................................................................................................122
Gas-Cap Drive.........................................................................................................123
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Water Drive..............................................................................................................123
Secondary Recovery...................................................................................................123
Water Flood..............................................................................................................124
Gas –Cap Injection...................................................................................................125
Enhanced Recovery...................................................................................................125
Thermal Processes...................................................................................................125
Miscible Processes...................................................................................................127
Chemical Processes..................................................................................................128
Other EOR Processes...............................................................................................129
Recovery Efficiencies.................................................................................................130
REMEDIAL WELL WORK............................................................................................131
Gravel packing...........................................................................................................131
Acidising......................................................................................................................132
Acid Fracturing .........................................................................................................132
Hydraulic Fracturing.................................................................................................133
Processing of Produced Fluids......................................................................................133
Oil Wells......................................................................................................................134
Oil Well Surface Processing System ........................................................................135
Gas Wells.....................................................................................................................137
Gas Well Surface Processing System........................................................................137
5
INTRODUCTION
With the current oil prices in the $60US range, the cyclic interest in the petroleum
industry has heightened once again. Just a couple years ago, some companies sold oil
(heavy crude) at less than $10 US per barrel (bottled water may have fetched a higher
price). As a result some companies switched their focus to natural gas.
Crude oil remains a commodity in demand, with alternative sources of energy still
lagging way behind. Gasoline and fuel oil still remain prime fuels, resulting in high world
demand for crude oil. Petroleum is a non-renewable commodity and the next generation
may well experience shortages in supply, with increasing demand, resulting in
ridiculously high prices.
Through the process of generation, migration and trapping mechanisms, petroleum
accumulates in the sub strata, waiting to be discovered by some innovative explorationist.
This “oil of rock”, as the name indicates, is found and produced from formations as
shallow as a couple hundred feet to depths as deep at 3 miles beneath the earth’s surface.
Technololgies employed range from simple to very complex. Problems experienced in
“winning” the petroleum also lie in the same range.
The challenge to companies is how to find and produce crude oil and natural gas, in the
most cost effective way, in the timeliest fashion, capturing the markets at an opportune
time when the prices are attractive. The general trend is to be reactionary to commodity
prices. When the price of oil is down, companies react and scale down their drilling and
downsize their operations. When the price is up, they do the opposite. A company can
reap the benefits of proper planning by drilling when the price of crude oil is low, and
hence services such as rig rental are cheap, resulting in higher production rates when the
price rebounds.
This course seeks to trace the life petroleum from birth (generation) to the point of sales.
Processes include generation, migration, accumulation, exploration, development and
production phases. All of the above require experts who build careers in the various
fields. These processes are costly and high risk, but the reward of success can be great,
transforming companies, nations and individuals into multi-millionaires in a short space
of time. The petroleum industry continues to attract individuals and companies who
accept the challenge to take risk, hoping to reap the rewards.
At the end of this course, non-technical participants will be able to understand and
appreciate the various processes that are involved in the production of petroleum for sale
to the customer.
6
ORIGIN OF PETROLEUM
There are two basic schools of thought surrounding the formation of petroleum deep
within the earth’s strata. There is the more widely accepted organic theory and the not so
popular inorganic theory.
Inorganic Theories
Deep seated terrestrial hypothesis
From as early as 1877, Dmitri Mendele'ev, a Russian who developed the periodic table,
postulated an inorganic origin when it became apparent that there were widespread
deposits of petroleum throughout the world. He reasoned that metallic carbides deep
within Earth reacted with water at high temperatures to form acetylene (C2H2). This
acetylene condensed to form heavier hydrocarbons. This reaction can be easily performed
under laboratory conditions.
This theory was modified by Berthelot in 1860 and by Mendele'ev in 1902. Their theory
was that the mantle of the earth contained iron carbide which would react with
percolating water to form methane:
FeC2 + 2H2O = CH4 + FeO2
The problem with this theory is the lack of evidence for the existence of iron carbide in
the mantle. These theories are referred to as the deep-seated terrestrial hypothesis.
Extraterrestrial hypothesis.
In 1890, Sokoloff proposed a cosmic origin for petroleum. His theory was that
hydrocarbons precipitated as rain from original nebular matter from which the solar
system was formed. The hydrocarbons were then ejected from earth's interior onto
surface rocks.
Interest in this inorganic theory heightened in the 20th Century as a result of two
discoveries: The existence of carbonaceous chondrites (meteorites) and the discovery that
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atmospheres containing methane exists for some celestial bodies such as Saturn, Titan,
Jupiter. The only known source for methane would be through inorganic reactions.
It has been postulated that the original atmosphere of earth contained methane, ammonia,
hydrogen and water vapor which could result is the creation of an oily, waxy surface
layer that may have been host to a variety of developing prebiotic compounds including
the precursors of life as a result of photochemical reactions (due to UV radiation).
The discovery (Mueller, 1963) of a type of meteorite called carbonaceous chondrites, also
led to a renewed interest in an inorganic mechanism for creating organic compounds.
Chondritic meteorites contain greater than 6% organic matter (not graphite) and traces of
various hydrocarbons including amino acids.
The chief support of an inorganic origin is that the hydrocarbons methane, ethane,
acetylene, and benzene have repeatedly been made from inorganic sources. For example,
congealed magma has been found on the Kola Peninsula in Russia (Petersil'ye, 1962)
containing gaseous and liquid hydrocarbons (90% methane, traces of ethane, propane,
isobutane). Paraffinic hydrocarbons have also been found in other igneous rocks (Evans,
Morton, and Cooper, 1964).
Problems with inorganic hypotheses.
Firstly, there is no direct evidence that will show whether the source of the organic
material in the chondritic meteorites is the result of a truly inorganic origin or was in an
original parent material which was organically created. Similar reasoning applies to other
celestial bodies.
Secondly, there is no field evidence that inorganic processes have occurred in nature, yet
there is mounting evidence for an organic origin.
And thirdly, there should be large amounts of hydrocarbons emitted from volcanoes,
congealed magma, and other igneous rocks if an inorganic origin is the primary
methodology for the creation of hydrocarbons. Gaseous hydrocarbons have been
recorded (White and Waring, 1963) emanating from volcanoes, with methane (CH4) the
most common. Volumes are generally less than 1%, but as high as 15% have been
recorded. But the large pools are absent from igneous rocks. Where commercial
accumulations do occur, they are in igneous rocks that have intruded into or are overlain
by sedimentary materials; in other words, the hydrocarbons probably formed in the
sedimentary sequence and migrated into the igneous material (more on this later when we
discuss traps).
Conclusion: There are unquestioned instances of indigenous magmatic oil, but the
occurrences are rare and the volumes of accumulated oil (pools) are low. Other
problematic issues: Commercial accumulations are restricted to sedimentary basins,
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petroleum seeps and accumulations are absent from igneous and metamorphic rocks, and
gas chromatography can fingerprint the organic matter in shales to that found in the
adjacent pool. Thus current theory holds that most petroleum is formed by the thermal
maturation of organic matter - An Organic Origin generated the vast reserves (pools) of
oil and gas.
Organic Theory:
There are a number of compelling reasons that support an organic development
hypothesis.
First and foremost, is the carbon-hydrogen-organic matter connection. Carbon and
Hydrogen are the primary constituents of organic material, both plant and animal.
Moreover, carbon, hydrogen, and hydrocarbons are continually produced by the life
processes of plants and animals. A major breakthrough occurred when it was discovered
that hydrocarbons and related compounds occur in many living organisms and are
deposited in the sediments with little or no change.
Second were observations dealing with the chemical characteristics of petroleum
reservoirs. Nitrogen and porphyrins (chlorophyll derivatives in plants, blood derivatives
in animals) are found in all organic matter; they are also found in many petroleums.
Presence of porphyrins also mean that anaerobic conditions must have developed early in
the formation process because porphyrins are easily and rapidly oxidized and decompose
under aerobic conditions. Additionally, low Oxygen content also implies a reducing
environment. Thus there is a high probability that petroleum originates within an
anaerobic and reducing environment.
Third were observations dealing with the physical characteristics. Nearly all petroleum
occurs in sediments that are primarily of marine origin. Petroleum contained in nonmarine sediments probably migrated into these areas from marine source materials
located nearby. Furthermore, temperatures in the deeper petroleum reservoirs seldom
exceed 300oF (141 oC) . But temperatures never exceeded 392oF (200oC) where
porphyrins are present because they are destroyed above this temperature. Therefore the
origin of petroleum is most likely a low-temperature phenomenon.
Finally, time requirements may be less than 1MM years; this is based on more recent oil
discoveries in Pliocene sediments.
However, physical conditions on the Earth may have been different in the geologic past
and therefore it may have taken considerably more time to develop liquid petroleum.
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Figure 1A
Organic Hypothesis - Summary.
The organic theory became the accepted theory about the turn of the century as the oil
and gas industry began to fully develop and geologists were exploring for new deposits.
Simply stated, the organic theory holds that the carbon and hydrogen necessary for the
formation of oil and gas were derived from early marine life forms living on the Earth
during the geologic past -- primarily marine plankton. Although plankton are
microscopic, the ocean contains so many of them that over 95% of living matter in the
ocean is plankton. The Sun's energy provides energy for all living things including
plankton and other forms of marine life (Fig. 1 & 1A).
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As these early life forms died, their remains were captured by the processes of erosion
and sedimentation (Fig 2).
Successive layers of organic-rich mud and silt covered preceding layers of organic rich
sediments and over time created layers on the sea floor rich in the fossil remains of
previous life (Fig. 3).
Thermal maturation processes (decay, heat, pressure) slowly converted the organic matter
into oil and gas. Add additional geologic time (millions of years) and the organic rich
sediments were converted into layers of rocks. Add more geologic time and the layers
were deformed, buckled, broken, and uplifted; the liquid petroleum flowed upward
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through porous rock until it became trapped and could flow no further forming the oil and
gas reservoirs that we explore for at present (Fig. 4).
But the chemistry of the hydrocarbons found in the end product (oil, gas) differ
somewhat from those we find in living things. Thus changes, transformation, take place
between the deposition of the organic remains and the creation of the end product. The
basic formula for the creation of petroleum (oil, gas) is:
Petroleum End Product = ([Raw Material + Accumulation + Transformation + Migration]
+ Geologic Time)
Petroleum, according to the organic theory, is the product of altered organic material
derived from the microscopic plant and animal life, which are carried in great volumes by
streams and rivers to lakes or the sea, where they are deposited under deltaic, lacustrine
and marine conditions with finely divided clastic sediments.
These environments produce their own microscopic plant and animal life, which are
deposited with the organic materials introduced by the streams and rivers. As deposition
of the organic material takes place in these environments, burial and protection by clay
and silt accompany it. This prevents decomposition of the organic material and allows it
to accumulate.
Conversion of the organic material is called catagenesis. It is assisted by pressure caused
by burial, temperature and thermal alteration and degradation. These factors result from
depth, some bacterial action in a closed nonoxidising chemical system, radioactivity and
catalysis. Temperature, as thermogenic activity, appears to be the most important
criterion, with assistance other factors as applicable. Accumulation of organic and clastic
material on a sea or lake bottom is accompanied by bacterial action. If there is abundant
oxygen, aerobic bacteria act upon the organic matter and destroy it.
Plant and animal remains contain abundant carbon and hydrogen, which are fundamental
elements in petroleum. Shale and some carbonates contain organic material that bears
hydrocarbons of types similar to those in petroleum. These rocks are not reservoir rocks
and could be considered ultimately to be source beds. The hydrocarbons are of the same
type as those found in living plants and animals and consist of asphalt, kerogen and liquid
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forms. The best source rocks are considered to be organically rich, black-coloured shales,
deposited in a non-oxidising, quiet marine environment.
Generation of crude oil
Figure 5 – Organic composition in shales
Organic material in shale averages approximately one (1) percent of the shale rock
volume. Clay mineral constituents comprise the remaining 99 percent.
Kerogen is an insoluble, high molecular weight, polymeric compound which comprises
about 90 percent of the organic material in shale. The remaining 10 percent comprises
bitumens of varying composition, which, according to some researchers, is thermally
altered kerogen. As alteration occurs, kerogen is developed by the increasing temperature
in the closed system.
Temperature increases with depth. Normal heat flow within the earth’s crust produces an
average geothermal gradient of approximately 1.5 oF for each 100 feet of depth.
Maturation studies on various crude oil types indicate that temperatures required to
produce oil occur between the depth of approximately 5,000 feet and 20,000 feet under
average heat-flow conditions.
Pressure, like temperature, is a function of depth and increases 1 psi for each foot of
depth. Pressure is caused by the weight of the sedimentary overburden.
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Rock
Mineral material 99% Organic Material 1 %
Organic Material
Bitumens 1 0%
Kerogen 90%
Bacterial action is important in the conversion of organic material to petroleum at shallow
depths. It is involved in the process of breaking down the original material into
hydrocarbon compounds, which eventually become biogenic gas.
Kerogen is a primary factor in forming bitumens that increase and migrate to accumulate
as crude oil. Thermal conversion of kerogen to bitumen is the important process of crude
oil formation. Thermal alteration increases the carbon content of the migratable
hydrocarbons, which leaves the unmigratable kerogen components behind.
Maturation of kerogen is a function of increased burial and temperature and is
accompanied by chemical changes. As kerogen thermally matures and increases in carbon
content, it changes from an immature light greenish-yellow color to an overmature black,
which is representative of a higher coal rank.
Generation of Natural Gas
Natural gas comprises biogenic gas and thermogenic gas with differences contingent
upon conditions of origin.
Biogenic gas forms at low temperatures at overburden depths of less than 3,000 feet
under anaerobic or conditions associated with high rates of marine sediment
accumulation. Oxygen in the sediments is consumed or eliminated early. And before
reduction of sulfates in the system. Methane, the most common of natural gas
constituents, forms after the sulfates are eliminated by hydrogen reduction of carbon
dioxide. Anaerobic oxidation of carbon dioxide produces methane. Current estimates
suggest that approximately 20 percent of the world’s known natural gas is biogenic.
Thermogenic gas forms at significantly higher temperatures and overburden pressures. It
contains methane and significantly larger amounts of heavier hydrocarbons than biogenic
gas. As time and temperature increase, progressively lighter hydrocarbons form as wet
gas and condensate in the latter stages of thermogenesis.
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CHEMISTRY OF PETROLEUM
Introduction:
The smallest unit of a substance, which still retains the characteristics of that substance, is
called a molecule. Molecules can only be divided into atoms - which are different
elements. For example, all molecules of water are identical and have the characteristics
of water. Two atoms of hydrogen and an atom of oxygen (which made up the molecule)
on their own have none of the characteristics of water.
Crude oils are mixtures of many different substances, often difficult to separate, from
which various petroleum products are derived, such as: gasoline, kerosene propane, fuel
oil, lubricating oil, wax, and asphalt. These substances are mainly compounds of only
two elements: carbon (C) and hydrogen (H). They are called, therefore: hydrocarbons.
Refining crude oil involves two kinds of processes to produce the products so essential to
modern society. First, there are physical processes which simply refine the crude oil
(without altering its molecular structure) into useful products such as lubricating oil or
fuel oil. Second, there are chemical or other processes which alter the molecular structure
and produce a wide range of products, some of them known by the general term
petrochemicals.
Hydrocarbons
Hydrocarbons may be gaseous, liquid, or solid at normal temperature and pressure,
depending on the number and arrangement of the carbon atoms in their molecules. Those
with up to 4 carbon atoms are gaseous; those with 20 or more are solid; those in between
are liquid. Crude oils are liquid but may contain gaseous or solid compounds (or both) in
solution. The heavier a crude oil (i.e. the more carbon atoms its molecules contain) the
closer it is to being a solid and this may be especially noticeable as its temperature cools.
Light oils will remain liquid even at very low temperatures.
Although hydrocarbons consist of two elements only (carbon and hydrogen), they exist in
a wide variety of types and in large numbers. This arises from the ability of carbon atoms
to form long chains. The hydrocarbons may be classified according to their composition
(type and number of atoms) and the structure (arrangements of atoms in space) of the
molecule.
Hydrocarbons are usually classified in the paraffin, unsaturated, naphtene and aromatic
types.
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Paraffin Series
This series, also known as alkane series, is characterized by the fact that the carbon
atoms are arranged in open chains (not closed rings) and are joined by single bonds. The
hydrocarbons of the paraffin type are thus saturated (single bonds only between carbon
atoms) and have the general formula CnH2n+2.
The simplest hydrocarbon is methane, a gas consisting of one carbon atom and four
hydrogen atoms:
Figure 6 – Molecular structure of methane
A carbon atom has four bonds that can unite with either one or more other carbon atoms
(a property almost unique to carbon) or with atoms of other elements. A hydrogen atom
has only one bond and can never unite with more than one other atom. The larger
hydrocarbon molecules have two or more carbon atoms joined to one another as well as
to hydrogen atoms. The carbon atoms may link together in a straight chain, a branched
chain, or a ring.
The first three members of the paraffin series methane, propane and butane respectively
have a single structural formula.
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Examples include: Propane (C3H8), a straight chain molecule, shown below.
Figure 7 – Molecular structure of propane
The remaining members may have two or more structural formulas for the same chemical
formula. The phenomenon, known as isomerism, has a strong impact on the
thermodynamic properties of the hydrocarbons. An example of a branched chain,
Isobutane (C4H10), is shown below:
Figure 7 – Molecular structure of Isobutane
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Isobutene has a boiling point of 109 oF while normal butane boils at 31.1 oF.
The members of the paraffin series are very important constituents of crude oil. Some
crude oils are largely composed of hydrocarbons of this series while others contain them
to a lesser extent. Natural gas consists mainly of the more volatile members of the
paraffin series containing from one to four carbon atoms per molecule.
The paraffin series are characterized by their chemical inertness. They will not react with
concentrated sulphuric or nitric acid at room temperature. However, when ignited on the
presence of air or oxygen, they give off large amounts of heat and under proper
conditions, this combustion is explosive. The reaction with oxygen occurs only at
elevated temperatures. The inertness of the paraffin hydrocarbons accounts for their
presence in petroleum since their existence for geological periods of time would require a
high degree of stability.
Unsaturated Hydrocarbons
The unsaturated hydrocarbons are characterized by the presence of double or triple bonds
between the carbon atoms. The multiple bonds allow the addition of hydrogen atoms,
under appropriate conditions, which explains the name unsaturated. The olefin series of
hydrocarbons is characterized by the presence of a double bond in the molecule and has
the general formula CnH2n.
The first three members (n=1…4) of this series, ethene, propene and butene are now
commonly referred to using their traditional names ethylene, propylene and butylene.
Isomerism occurs also with the olefins, not only due to the branching of the carbon
chains, but also to the position of the double bond in the molecule.
Another series of unsaturated hydrocarbons is known as diolefins. They are characterized
by the fact that there are two double bonds in the molecule. The general formula for the
series is CnH2n-2.
A third series of unsaturated hydrocarbons of considerable importance is the acetylene
series. The compounds have a triple bond and general formula CnH2n -2 . Hence they are
isomers with the diolefins. The first three members of this series (n=2…4) are ethine
(commonly called acetylene), propine and butine.
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Figure 8 – Molecular structure of Ethine
The unsaturated hydrocarbons are very reactive, in contrast with the members of the
paraffin series. They react rapidly with chlorine to form oily liquids ; hence the name
olefins (oil forming). Under the proper conditions they react rapidly with hydrogen,
which saturates the double bonds and forms the corresponding paraffin. Because of their
high reactivity, these unsaturated hydrocarbons are not found in crude oil to any great
extent. However, they are formed in large amounts in petroleum cracking processes and
have considerable industrial importance.
Naphthene Hydrocarbons
The naphthene hydrocarbons are also called cycloparaffins and, as ther name implies,
they are saturated hydrocarbons in which the carbon chains form closed rings. The
general formula for this series is CnH2n (n greater than 2) and consequently they are
isometric with the olefins. They are named by placing the prefix cyclo before the names
of the corresponding paraffin hydrocarbon. The first members of this series (n=3…6) are
cyclopropane, cyclobutane and cyclohexane, and so on. These compounds, being
saturated, are relatively stable and are important constituents of crude oil. In general, the
chemical properties of these hydrocarbons are very similar to those of the paraffins.
Aromatic Hydrocarbons
These hydrocarbons are also cyclic and may be considered to be derivatives of benzene
and have general formula CnH2n-6 (n greater than 5). Benzene has the formula C6H6, and
the structure consists of a six-fold ring, with alternate single and double bonds. This
structure is so common in organic compounds that chemists use a hexagon with a circle
in the middle as a special symbol to represent the benzene molecule. Some of the simpler
members of this series consist of benzene with one or more alkyl groups as side chains.
An example, methylbenzene, also known as toluene, is of sufficient importance to warrant
a common name.
The fact that the benzene ring contains three double bonds suggests that the members of
this series should be very reactive. However, this is not so and, although they are not as
stable as the paraffins, they do not show the high reactivity that is so characteristic of the
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olefins. Compounds of this series do occur in crude oil. Petroleum is one of the important
sources of these important hydrocarbons.
Figure 9 – Molecular structure of Aromatics
The aromatic hydrocarbons are either liquids or solids under standard conditions of
temperature and pressure. Benzene is a colorless liquid with as boiling point of 176oF.
Many of the members of this series are characterized by fragrant odors; hencr the name
aromatic given to this series.
Types of Crude Oils
Crude oils vary widely in appearance and viscosity from field to field. They range in
colour, odour, and in the properties they contain. While all crude oils are essentially
hydrocarbons, the differences in properties, especially the variations in molecular
structure, mean that a crude is more or less easy to produce, pipeline, and refine. The
variations may even influence its suitability for certain products and the quality of those
products.
Crudes are roughly classified into three groups, according to the nature of the
hydrocarbons they contain.
Paraffin-based Crude Oils
These contain higher molecular weight paraffins which are solid at room temperature, but
little or no asphaltic (bituminous) matter. They can produce high-grade lubricating oils.
Asphaltic Based Crude Oils
Contain large proportions of asphaltic matter, and little or no paraffin. Some are
predominantly naphthenes so yield a lubricating oil that is more sensitive to temperature
changes than the paraffin-base crudes.
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Mixed Base Crude Oils
The "gray area" between the two types above. Both paraffins and naphthenes are present,
as well as aromatic hydrocarbons. Most crudes fit this category.
Crude oils usually contain small amounts of combined oxygen, nitrogen and sulphur.
Crude oils obtained from various localities have widely different characteristics
indicating that the hydrocarbons have different properties. Nearly all crude oils will give
ultimate analyses within the limits shown below:
Element Content
(% in weight)
Carbon 84 - 87
Hydrogen 11 - 14
Sulphur 0.06 - 4.0
Nitrogen 0.1 - 2.0
Oxygen 0.1 - 2.0
Table 1 – Composition of typical Crude Oil
Classification of crude oils based on Gas Oil Ratio:
Black Oil ; solution GOR, (Rs) less than 2,000 scf/bbl
Volatile oil : solution GOR, (Rs) greater than 2,000 scf/bbl
Natural Gas
Natural gas can occur by itself or in conjunction with liquid crude oils . It consists mainly
of the more volatile members of the paraffin series containing from one to four carbon
atoms per molecule. In addition, natural gases may contain varying amounts of carbon
dioxide, nitrogen, hydrogen sulphide, helium and water vapour. Most natural gases
consist predominantly of methane, the percentage of which may be as high as 98 percent.
Natural gas can be classified as sweet and sour and as wet or dry. A sour gas is one that
contains appreciable amounts of hydrogen sulphide or carbon dioxide, and consequently
can be quite corrosive.
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The designation wet gas has nothing to do with the presence of water vapour but signifies
that the gas will yield appreciable quantities of liquid hydrocarbons with proper
treatment.
Water vapour is, however, often present in natural gas and sometimes causes stoppages in
high pressure gas lines during cold weather. This is due to the fact that hydrocarbons
form solid hydrates with water at high pressure and low temperature.
Typical Compositions of wet and dry natural gas:
Constituents Content (% in volume)
Wet Dry
Hydrocarbons
Methane 84.6 96
Ethane 6.4 2
Propane 5.3 0.6
Isobutane 1.2 0.1 8
n-Butane 1.4 0.1 2
Isopentane 0.4 0.1 4
n-Pentane 0.2 0.06
Hexanes 0.4 0.01
Heptanes 0.1 0.08
Non-hydrocarbons
Carbon Dioxide 0.5
Helium 0.05
Hydrogen Sulphide 0.5
Nitrogen 0.1
Argon 0.005
Radon, krypton, xenon Trace
Table 2 – Composition of typical Natural Gas
Classification of natural gas based on Condensate/Gas Ratio:
Gas/condensate : gas/condensate ratio greater than 5 stb/million scf
Dry gas: gas/condensate ratio less than 5 stb/million scf
PETROLEUM GEOLOGY
The Rock Cycle
22
There are four main layers that make up the earth:
1. Inner Core - A mass of iron with a temperature of about 7000 degrees F.
Although such temperatures would normally melt iron, immense pressure
on it keeps it in a solid form. The inner core is approximately 1,500 miles
in diameter.
2. Outer Core - A mass of molten iron about 1,425 miles deep that
surrounds the solid inner core. Electrical currents generated from this area
produce the earth's magnetic field.
3. Mantle - A rock layer about 1,750 miles thick that reaches about half the
distance to the center of the earth. parts of this layer become hot enough to
liquify and become slow moving molten rock or magma.
4. Crust - A layer from 4-25 miles thick consisting of sand and rock.
The core, mantle and crust of the earth can be envisioned as a giant rock recycling
machine. However, the elements that make up rocks are never created or destroyed
although they can be redistributed, transforming one rock type to another.
The recycling machine works something like this. Liquid (molten) rock material
solidifies either at or below the surface of the earth to form igneous rocks . Uplifting
occurs forming mountains made of rock. The exposure of rocks to weathering and
erosion at the earth's surface breaks them down into smaller grains producing soil. The
grains (soil) are transported by wind, water and gravity and eventually deposited as
sediments. This process is referred to as erosion.
The sediments are deposited in layers and become compacted and cemented (lithified)
forming sedimentary rocks. Variation in temperature, pressure, and/or the chemistry of
the rock can cause chemical and/or physical changes in igneous and sedimentary rocks to
form metamorphic rocks. When exposed to higher temperatures, metamorphic rocks (or
any other rock type for that matter) may be partially melted resulting in the creation once
again of igneous rocks starting the cycle all over again.
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Figure 10 – Rock Cycle
As you might expect - since most of the earth's surface is covered by water - molten
material from inside the earth often breaks through the floor of the ocean and flows from
fissures where it is cooled by the water resulting in the formation of igneous rocks. Some
low grade metamorphism often occurs during and after the formation of the rock due to
the intrusion of the material by the magma. As the molten material flows from the fissure,
it begins forming ridges adjacent to it.
If we examine the rock cycle in terms of plate tectonics, as depicted in figure 10 above,
we see that igneous rocks form on the sea floor as spreading ridges. As the rocks cool,
and more magma is introduced from below, the plate is forced away from the spreading
ridge, and acquires a sediment cover. As shown in the figure, in this case, the oceanic
plate eventually "dives" under the adjacent continental plate. As the oceanic plate travels
deeper, high temperature conditions cause partial melting of the crustal slab. When that
occurs, the surrounding "country rock" (existing adjacent rock) is metamorphosed at high
temperature conditions by the contact. The molten material is either driven to the surface
as volcanic eruptions, or crystallizes to form plutonic igneous rocks.
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The 3 basic types of rocks.
Just as any person can be put into one of two main categories of human being, all
rocks can be put into one of three fundamentally different types of rocks. They are
igneous, sedimentary and metamorphic rocks:
Figure 11 – Types of rocks
Igneous Rocks
Igneous rocks are crystalline solids, which form directly from the cooling of magma.
This is an exothermic process (it loses heat) and involves a phase change from the
liquid to the solid state.
Each mineral forms a characteristic type of crystal. For example, the well known igneous
rock, Granite, is composed of three main minerals, Quartz, Mica and Feldspar, all of
which look different and can be clearly seen in a sample.
Figure 12 - The three main minerals in granite
Black=Mica, White=Feldspar, Grey =Quartz
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The size of the crystals is usually determined by the speed at which the molten rock
material cools. Quick cooling produces small crystals, slow cooling produces larger
crystals.
The earth is made of igneous rock - at least at the surface where our planet is exposed
to the coldness of space. Igneous rocks are given names based upon two things:
composition (what they are made of) and texture (how big the crystals are).
Magmas occur at depth in the crust, and are said to exist in "magma chambers," a
rather loose term indicating an area where the temperature is great enough to melt the
rock, and the pressure is low enough to allow the material to expand and exist in the
liquid state. Many different types of igneous rocks can be produced. The key factors
to use in determining which rock you have are the rock's texture and composition.
Texture
Texture relates to how large the individual mineral grains are in the final, solid rock. In
most cases, the resulting grain size depends on how quickly the magma cooled. In
general, the slower the cooling, the larger the crystals in the final rock. Because of this,
we assume that coarse grained igneous rocks are "intrusive," in that they cooled at
depth in the crust where they were insulated by layers of rock and sediment. Fine
grained rocks are called "extrusive" and are generally produced through volcanic
eruptions.
Grain size can vary greatly, from extremely coarse grained rocks with crystals the size
of your fist, down to glassy material which cooled so quickly that there are no mineral
grains at all. Coarse grain varieties (with mineral grains large enough to see without a
magnifying glass) are called phaneritic. Granite and gabbro are examples of phaneritic
igneous rocks. Fine grained rocks, where the individual grains are too small to see, are
called aphanitic. Basalt is an example. The most common glassy rock is obsidian.
Obviously, there are innumerable intermediate stages to confuse the issue.
Composition
The other factor is composition: the elements in the magma directly affect which
minerals are formed when the magma cools. Again, we will describe the extremes, but
there are countless intermediate compositions.
The composition of igneous magmas is directly related to where the magma is
formed. Magmas associated with crustal spreading are generally mafic, and produce
basalt if the magma erupts at the surface, or gabbro if the magma never makes it out
of the magma chamber. It is important to remember that basalt and gabbro are two
different rocks based purely on textural differences - they are compositionally the
same. Intermediate and felsic magmas are associated with crustal compression and
subduction. In these areas, rock and sediment from the surface is subducted back into
the crust, where it re-melts. This allows the differentiation process to continue, and
26
the resulting magma is enriched in the lighter elements. Intermediate magmas
produce diorite (intrusive) and andesite (extrusive). Felsic magmas, the final purified
result of the differentiation process, lead to the formation of granite (intrusive) or
rhyolite (extrusive).
Sedimentary Rocks
Figure 13 – Sedimentary Rock
Sedimentary rocks are formed at the surface of the Earth, either in water or on land. They
are layered accumulations of sediments-fragments of rocks, minerals, or animal or plant
material. Temperatures and pressures are low at the Earth's surface, and sedimentary
rocks show this fact by their appearance and the minerals they contain.
Most sedimentary rocks become cemented together by minerals and chemicals or are held
together by electrical attraction; some, however, remain loose and unconsolidated. The
layers are normally parallel or nearly parallel to the Earth's surface; if they are at high
angles to the surface or are twisted or broken, some kind of Earth movement has occurred
since the rock was formed. Sedimentary rocks are forming around us all the time.
Sand and gravel on beaches or in river bars, look like the sandstone and conglomerate
they will become. Compacted and dried mud flats harden into shale. Scuba divers who
have seen mud and shells settling on the floors of lagoons find it easy to understand how
sedimentary rocks form. Sedimentary rocks are called secondary, because they are often
the result of the accumulation of small pieces broken off of pre-existing rocks.
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There are three main types of sedimentary rocks:
Clastic sedimentary rocks:
Clastic sedimentary rocks are accumulations of clasts: little pieces of broken up rock
which have piled up and been "lithified" by compaction and cementation.
Sandstone
Figure 14 – Sandstone rocks
Sandstone is composed of mineral grains (commonly quartz) cemented together by silica,
iron oxide, or calcium carbonate. Sandstones are typically white, gray, brown, or red. The
red and brown sandstone is colored by iron oxide impurities. Most sandstones feel gritty,
and some are easily crushed (friable) and break up to form sand. Sandstones have pore
spaces between each grain of sand; this property, called porosity, makes them good
reservoirs for oil and natural gas. Sandstones are very resistant to erosion and form bluffs,
cliffs, ridges, rapids, arches, and waterfalls.
Conglomerate
Conglomerate is a sedimentary rock usually composed of rounded quartz pebbles,
cobbles, and boulders surrounded by a matrix of sand and finer material, and cemented
with silica, iron oxide, or calcium carbonate. The rock fragments are rounded from being
rolled along a stream bed or a beach during transportation. If the fragments embedded in
the matrix are angular instead of rounded, the rock is called a breccia (pronounced
BRECH-i-a).
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Figure 15 -Conglomerate Rock
Shale
Figure 16 - Shales
Shale is the most abundant of all sedimentary rocks. It is composed primarily of soft clay
minerals, but may include variable amounts of organic matter, calcareous material, and
quartz grains. Shale may be any color, but is generally greenish gray to grayish black. It
is relatively soft and has a smooth, greasy feel when freshly exposed, but is hard and
brittle when dry. Most shales split into thin plates or sheets and are termed fissile, but
others are massive (nonfissile) and break into irregular blocks. Shales weather very easily
to form mud and clay.
Clays
The term "clay" is applied to various earthy materials composed dominantly of hydrous
aluminum magnesium silicate minerals. The most familiar characteristic of clay is
plasticity or the ability of moist clay to be fashioned into a desired shape. The physical
properties of a clay are plasticity, strength, and refractoriness. Plasticity enables the clay
29
to be molded; strength permits it to be handled during the forming, drying, and burning
processes; and refractoriness permits it to be burned into a hard body of permanent form
Bentonite
Bentonite is a soft, low-specific-gravity, expandable clay. It is altered volcanic ash and is
found in central Kentucky in beds up to 3 feet thick near the top of the Tyrone Limestone.
Drillers have labeled these bentonite beds the Mud Cave and Pencil Cave. Because of its
peculiar property of expanding when wet, bentonite is effective as a water sealer,
especially to prevent pond leakage, and is also used in rotary drilling muds to prevent
contaminating formations with drilling fluid.
Chemical sedimentary rocks:
Mny of these form when standing water evaporates, leaving dissolved minerals behind.
These are very common in arid lands, where seasonal "playa lakes" occur in closed
depressions. Thick deposits of salt and gypsum can form due to repeated flooding and
evaporation over long periods of time. Other chemical sedimentary rocks include
sedimentary iron ores, evaporites such as rock salt (Halite), and to some extent flint,
limestone and chert.
Organic sedimentary rocks
Any accumulation of sedimentary debris caused by organic processes. Many animals
use calcium for shells, bones, and teeth. These bits of calcium can pile up on the
seafloor and accumulate into a thick enough layer to form an "organic" sedimentary
rock. These include Limestone, Chalk and Coal.
Clues that may help you recognize a sedimentary rock are...
• It looks like bits of other rocks stuck together.
• It has a gritty feel and bits can be rubbed off it.
• It contains fossils, bits of shell or pebbles.
• There are no, or very few crystals in it.
• All the grains look rounded and worn.
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Metamorphic Rocks
The metamorphics get their name from "meta" (change) and "morph" (form). Any
rock can become a metamorphic rock. All that is required is for the rock to be moved
into an environment in which the minerals which make up the rock become unstable
and out of equilibrium with the new environmental conditions.
The process of metamorphism does not melt the rocks, but instead transforms them into
denser, more compact rocks. New minerals are created either by rearrangement of
mineral components or by reactions with fluids that enter the rocks. Some kinds of
metamorphic rocks--granite gneiss and biotite schist are two examples--are strongly
banded or foliated. (Foliated means the parallel arrangement of certain mineral grains that
gives the rock a striped appearance.) Pressure or temperature can even change previously
metamorphosed rocks into new types.
In most cases, this involves burial which leads to a rise in temperature and pressure.
The metamorphic changes in the minerals always move in a direction designed to
restore equilibrium. Common metamorphic rocks include slate, schist, gneiss, and
marble.
The Geological Time Scale
A sequence of divisions of geological
time comprising in order from oldest to
youngest: Precambrian, Cambrian,
Ordovician, Silurian, Devonian,
Carboniferous, Permian, Triassic,
Jurassic, Cretaceous, Tertiary and
Quaternary.
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Each of the geological periods is characterised by groups, or suites, of fossils. The picture
below shows a typical fossil embedded in a rock.
Figure 17 – Fossil embedded in a rock
The geological periods are grouped into three major divisions of Phanerozoic time. The
block of "ancient life" is dated from some 540 million years before present (the
Cambrian) to about 245 million years before present (the Permian). Fossils such as
trilobites, graptolites, early fish and ancestral plants belong to this "Era", known as the
Paleozoic. The Paleozoic Era is replaced by the time of "middle life" (the Mesozoic Era),
charcterised by dinosaurs and marine organisms such as the great marine reptiles and the
ammonites. The Mesozoic Era commenced with the Triassic Period (starting about 245
million years ago) and concluded with the Cretaceous Period (66.4 million years ago).
The last block of geological time is the Cenozoic Era with two geological periods, the
Tertiary and the Quaternary. This era is characterised by widespead evolution of the
mammals, and concludes with the appearance of modern Homo sapiens (our own
species), in late Quaternary time. We are living in the Quaternary Period.
EON ERA PERIOD
32
PhanerozoicEon
"Visible Life"
Organisms with skeletons or
hard shells.
540 mya through today
Cenozoic Era
"Age of
Mammals"
65 mya through
today
Quaternary Period
"The Age of Man"
1.8 mya to today
Tertiary Period
65 to 1.8 mya
Neogene
24-1.8 mya
Paleogene
65-24 mya
Mesozoic Era
"Age of Reptiles"
248 to 65 mya
Cretaceous Period
146 to 65 mya
Jurassic Period
208 to 146 mya
Triassic Period
248 to 208 mya
Paleozoic Era
540 to 248 mya
Permian Period
"Age of Amphibians"
280 to 248 mya
Carboniferous
360 to 280 mya
Pennsylvanian
Period
325 to 280 mya
Mississippian
Period
360 to 325 mya
Devonian Period,"The Age of
Fishes"
408 to 360 mya
Silurian Period, 438 to 408 mya
Ordovician Period, 505 to 438 mya
Cambrian Period, 540 to 500 mya
Proterozoic Eon
2.5 billion years ago to
540 mya
-
Vendian Period, 600 to 540 mya
-
Archeozoic Eon
(Archean)
3.9 to 2.5 billion years ago
- -
Hadean Eon
4.6 to 3.9 billion years ago - -
33
GEOLOGICAL FEATURES
There are three geological features that need to be present before oil may be present
underground: source rock, reservoir rock, and geological traps. The source rock is where
the oil was formed (if you accept the organic theory), but because it is relatively nonporous, it cannot hold oil in appreciable amounts. Instead, the oil migrates to more porous
rock like sandstone or limestone. These are examples of reservoir rock. It is possible for
the oil to move through the reservoir rock all the way to the surface of the earth.
However, this rarely happens because its progress is blocked by some impermeable rock
barrier. This causes the oil to accumulate to form a reservoir. The barrier and the resulting
reservoir form what is known as a trap.
Figure 18 – Typical Traps
Reservoir Rock
The oil that migrates through the reservoir rock is not pure oil. Rather it is a mixture of
oil, water, and natural gas. When the reservoir forms, the three components will separate,
with the gas at the top, the oil in the middle, and the water at the bottom. Depending on
the pressure in the reservoir, the gas may stay in solution. If the gas does form a separate
layer at the top, it is referred to as the gas cap. It is important to note that the
oil/water/gas mixture does not form a large pool of liquid as some people often envision;
it is actually dispersed throughout the reservoir rock.
Traps
There are two basic kinds of traps: structural and stratigraphic. Structural traps are the
result of deformations of the rock layer. Examples of structural traps are anticlines and
fault traps. The fault trap is associated with the shifting of fault layers along a fault line,
something that we are familiar with as the cause of earthquakes if the shifting motion is
strong enough. Stratigraphic traps form when reservoir rock is cut off by a horizontal
layer of impermeable rock. The figure above shows oil pooling in the two different types
of structural traps. The dome-like structure on the right is an anticline, while the structure
on the left is a trap formed along a fault.
There are three basic forms of a structural trap in petroleum geology:
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• Anticline trap
• Fault Trap
• Salt Dome Trap
The common link between these three is simple: some part of the earth has moved in the
past, creating an impedence to oil flow.
Anticline Trap
An anticline is an example of rocks which were previously flat, but have been bent into
an arch. Oil that finds its way into a reservoir rock that has been bent into an arch will
flow to the crest of the arch, and get stuck (provided, of course, that there is an
impermeable trap rock above the arch to seal the oil in place).
Figure 19
A cross section of the Earth showing typical Anticline Traps.
Reseroir rock that isn't completely filled with oil also contains
large amounts of salt water.
Figure 20 – Outcrop Anticline
Fault trap
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Fault traps are formed by movement of rock along a fault line. In some cases, the
reservoir rock has moved opposite a layer of impermeable rock. The impermeable rock
thus prevents the oil from escaping. In other cases, the fault itself can be a very effective
trap. Clays within the fault zone are smeared as the layers of rock slip past one another.
This is known as fault gouge.
Figure 21
A cross section of rock showing a fault trap - in this case, an example of gouge.This is because the reservoir
rock on both sides of the fault would be connected, if not for the fault seperating the two. In this example, it
is the fault itself that is trapping the oil.
Thrust Fault
Thrust faulting occurs when one section of the Earth is pushed up and over another
section, and they most often occur in areas where two continental plates are running into
one another. However, the photos below show sediments that were deposited by glaciers
only 10,000 years ago, and these sediments were then run over by a glacial readvance.
When the glacier moved back over the sediments, faulting occured. The faults below can
be clearly seen.
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Figure 22 – Outcrop Thrust Faults
Below you can see the faults and rock horizons drawn in If the conditions were right, oil
might become trapped in this rock.
Figure 23 – Interpretation of Figure 22
Also drawn in is the possibility of oil being trapped by the shale above it, as well as by
the fault and the shale to the left of it. Of course, this outcrop is only a couple of meters
wide, there really is no oil here, and the layers that we've assigned to the rock are mostly
37
imaginary in this case. But the point is, this is exactly how many structural traps are set
up below the Earth's surface.
Salt Dome Trap
Salt is a peculiar substance. If you put enough heat and pressure on it, the salt will slowly
flow, much like a glacier that slowly but continually moves downhill. Unlike glaciers, salt
which is buried kilometers below the surface of the Earth can move upward until it
breaks through to the Earth's surface, where it is then dissolved by ground- and rainwater. To get all the way to the Earth's surface, salt has to push aside and break through
many layers of rock in its path. This is what ultimately will create the oil trap.
Figure 24
Here we see salt that has moved up through the Earth, punching through and bending rock along the way.
Oil can come to rest right up against the salt, which makes salt an effective trap. However, many times, the
salt chemically changes the rocks next to it in such a way that oil will no longer seep into them. In a sense,
it destroys the porosity of a reservoir rock.
Stratigraphic Trap
A stratigraphic trap accumulates oil due to changes of rock character rather than faulting
or folding of the rock. The term "stratigraphy" basically means "the study of the rocks
and their variations". One thing stratigraphy has shown us is that many layers of rock
change, sometimes over short distances, even within the same rock layer.
As an example, it is possible that a layer of rock which is a sandstone at one location is a
siltstone or a shale at another location. In between, the rock grades between the two rock
types. From the section on reservoir rocks, we learned that sandstones make good
reservoirs because of the many pore spaces contained within. On the other hand, shales,
made up of clay particles, do not make good reservoirs, because they do not contain large
pore spaces. Therefore, if oil migrates into a sandstone, it will flow along this rock layer
until it hits the low-porosity shale, thus forming a stratigraphic trap.
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Figure 25- An example of a stratigraphic trap
The above series of diagrams is an attempt to illustrate a type of stratigraphic trap. In the
diagram at the upper left, we see a river that is meandering. As it does so, it deposits sand
along its bank. Further away from the river is the floodplain, where broad layers of mud
are deposited during a flood. Though they seem fairly constant, rivers actually change
course frequently, eventually moving to new locations. Sometimes these new locations
are miles away from their former path.
In the diagram at the upper right, we show what happens when a river changes its course.
The sand bars that were deposited earlier are now covered by the mud of the new
floodplain. These lenses of sand, when looked at from the side many years later (the
bottom diagram), become cut off from each other, and are surrounded by the mud of the
river's floodplain - which will eventually turn to shale. This makes for a perfect
stratigraphic trap.
39
PETROLEUM RESERVOIRS
The term reservoir implies storage. Reservoir rock, therefore, is that rock in which the
hydrocarbon can be stored and from which it can be produced. The fluids of the
subsurface migrate according to density with the dominant fluids in hydrocarbon regions
being hydrocarbon gas, hydrocarbon liquids and salt water. Since the hydrocarbons are
the less dense of these fluids, they will tend to migrate upward, displacing the heavier salt
water down elevation. Hydrocarbons may be forced from their source rock during
lithification, and migrate into the reservoir rock in which they are stored. The fluids
present will separate according to density as migration occurs.
Reservoir Properties
The key properties for describing a petroleum reservoir are porosity, pore saturation, and
permeability. Definitions of these terms are as follows.
Porosity refers to the capacity of the reservoir to hold fluids. It is basically the interstices,
or pores, present within the reservoir rock. Typical porosities of oil reservoirs are of the
order of 20%.
While porosity represents the maximum capacity of a reservoir to hold fluids, pore
saturation quantifies how much of this available capacity actually does contain fluids. For
example, if a reservoir is 50% saturated with oil, this means that half of the available pore
space in the reservoir actually contains oil.
Permeability
Permeability is a factor that quantifies how hard or how easy it is for the fluid to flow
through the reservoir to the oil producing well; the greater the permeability, the easier the
fluid flows.
Permeability of a rock is a measure of the ability of the rock to transmit fluids through it.
It is of great importance in determining the flow characteristics of hydrocarbons in oil
and gas reservoirs, and of groundwater in aquifers. The usual unit for permeability is the
darcy, or more commonly the milli-darcy or md (1 darcy = 1 x 10−12m²).
Permeability is part of the proportionality constant in Darcy’s Law which relates
discharge (flow rate) and fluid physical properties (e.g viscosity), to a pressure gradient
applied to the porous media. The proportionallity constant specifically for the flow of
water through a porous media is the hydraulic conductivity. Permeability is a portion of
this, and is a property of the porous media only, not the fluid. In naturally occurring
materials, it ranges over many orders of magnitude .
For a rock to be considered as an exploitable hydrocarbon reservoir, its permeability must
be greater than approximately 100 md (depending on the nature of the hydrocarbon - gas
reservoirs with lower permeabilities are still exploitable because of the lower viscosity of
40
gas with respect to oil). Rocks with permeabilities significantly lower than 100 md can
form efficient seals . Unconsolidated sands may have permeabilities of 5000+ md.
Darcy’s Equation for linear incompressible fluid flow
Darcy is a unit of permeability. It is not an SI unit, but it is widely used in petroleum
engineering and geology. The darcy has units of area.
Definition
Permeability measures the ability of fluids to flow through rock (or other porous media).
The darcy is defined using Darcy’s Law which can be written as:
where:
κ is the permeability of a medium
v is the superficial (or bulk) fluid flow rate through the medium
μ is the dynamic viscosity of the fluid
ΔP is the applied pressure difference
Δx is the thickness of the medium
This is the basic form of the equation. It assumes laminar, steady state, incompressible
fluid flowing through the system. We will assume that the reservoir is above the bubble
point , so that fluid flowing from the reservoir into the wellbore will be liquid.
The darcy is referenced to a mixture of unit systems. A medium with a permeability of 1
darcy permits a flow of 1 cm/s of a fluid of 1 cP viscosity under a 1 atm/cm pressure
gradient.
Absolute permeability is the permeability of a rock which has only a single fluid flowing
through it.
The effective permeability to a fluid is the permeability of the rock to that particular fluid
when there are more than one fluids flowing in the reservoir.
e.g. ko is the permeability to the flow of oil when ther is, say, oil and water flowing
throught the rock.
41
Relative permeability is the ratio of the effective permeability of a rock to the absolute
permeability of the rock, at a particular water saturation.
Relative Permeability Curve
Porosity
The porosity of a rock is the proportion of the non-solid volume to the total volume of
material, and is defined by the ratio:
where V
p is the non-solid volume (pores and liquid) and Vm is the total volume of
material, including the solid and non-solid parts. Both φ and n are used to denote
porosity.
Porosity is a fraction between 0 and 1, typically ranging from less than 0.01 for solid
granite to more than 0.5 for peat and clay, although it may also be represented in percent
terms by multiplying the fraction by 100%.
The porosity of a rock, or sedimentary layer, is an important consideration when
attempting to evaluate the potential volume of hydrocarbons it may contain. Sedimentary
porosities are a complex function of many factors, including but not limited to: rate of
burial, depth of burial, the nature of the connate fluids, the nature of overlying sediments
(which may impede fluid expulsion).
42
Relative Permeability curve
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9
Water Saturation %
Relative permeability%
Kro
Krw
Porosity and hydraulic conductivity
Porosity is indirectly related to hydraulic conductivity. For two similar sandy aquifers,
the one with a higher porosity will typically have a higher hydraulic conductivity (more
open area for the flow of water), but there are many complications to this relationship.
Clays, which typically have very low hydraulic conductivity also have very high
porosities (due to the structured nature of clay minerals), which means clays can hold a
large volume of water per volume of bulk material, but they do not release water very
quickly.
Sorting and porosity
Well sorted (grains of approximately all one size) materials have higher porosity than
similarly sized poorly sorted materials (where smaller particles fill the gaps between
larger particles). The graphic illustrates how some smaller grains can effectively fill the
pores (where all water flow takes place), drastically reducing porosity and hydraulic
conductivity, while only being a small fraction of the total volume of the material.
Types of porosity
• Primary porosity is the main or original porosity system in a rock
• Secondary porosity is a subsequent or separate porosity system in a rock, often
enhancing overall porosity of a rock. This can be a result of chemical leeching of
minerals or the generation of a fracture system. This can replace the primary
porosity or coexist with it (see dual porosity below).
• Fracture porosity is porosity associated with a fracture system or faulting. This
can create secondary porosity in rocks that otherwise would not be reservoirs for
hydrocarbons due to their primary porosity being destroyed (for example due to
depth of burial) or of a rock type not normally considered a reservoir (for example
igneous intrusions or metasediments).
• Vuggy porosity is secondary porosity generated by dissolution of large features
(such as macrofossils) in carbonate rocks leaving large holes, vigs, or even caves.
• Effective porosity (also called open porosity) refers to the fraction of the total
volume in which fluid flow is effectively taking place (this excludes dead-end
pores or non-connected cavities). This is very important in solute transport.
• Dual porosity refers to the conceptual idea that there are two overlapping
reservoirs which interact. In fractured rock aquifers, the rock mass and fractures
are often simulated as being two overlapping but distinct bodies. Delayed yield,
and leaky aquifer flow solutions are both mathematically similar solutions to that
obtained for dual porosity; in all three cases water comes from two
mathematically different reservoirs (whether or not they are physically different).
Measuring Porosity
43
There are several ways to estimate the porosity of a given material or mixture of
materials, which is called your material matrix.
• The Volume/Density method is fast and suprisingly accurate (normally within 2%
of the actual porosity). To do this method you pour your material into a beaker,
cylinder or some other container of a known volume. Weigh your container so
you know its empty weight, then pour your material into the container.
Tap the side of the container until it has finished settling and measure the volume
in the container. Then weigh your container full of this material, so you can
subtract the weight of the container to know just the weight of just your material.
So now you have both the volume and the weight of the material.
The weight of your material divided by the density of your material gives you the
volume that your material takes up, minus the pore volume. (The assumed density
of most rocks, sand, glass, ect. is assumed to be 2.65g/cc. If you have a different
material, you may look up its density) So, the pore volume is simply equal to the
total volume minus the mateial volume, or more directly (pore volume) = (total
volume) - (material volume).
• Water Saturation Method is slightly harder to do, but is more accurate and more
direct. Again, take a known volume of your material and also a known volume of
water. (Make sure the beaker or container is large enough to hold your material as
well.) Slowly dump your material into the water and let it saturate as you pour it
in. Then seal the beaker (with a piece of parafilm tape or if you don't have
parafilm tape a plastic bag tied around the beaker will do.) and let it sit for a few
hours to insure the material is fully saturated. Then remove the unsaturated water
from the top of the beaker and measure its volume. The total volume of the water
originally in the beaker minus the amount of water not saturated is the volume of
the pore space, or again more directly (pore volume) = (total volume of water) -
(unsaturated water).
• Water Evaporation Method is the hardest to do, but is also the most accurate. Take
a fully saturated, known volume of your material with no excess water on top.
Weigh your container with the material and water and then place your container
into a heater to dry it out. Drying out your sample may take several days
depending on the heat applied and the volume of your sample. Then weigh your
dried sample. Since the density of water is 1 g/cc, the difference of the weights of
the saturated versus the dried sample is eqaul to the volume of the water removed
from the sample (assuming you are measuring in grams), which is exactly the
pore volume. So once again, (pore volume in cubic centemeters) = (weight of
saturated sample in grams) - (weight of dried sample in grams).
Water Saturation
44
The fraction of water in a given pore space. It is expressed in volume/volume, percent or
saturation units. Unless otherwise stated, water saturation is the fraction of formation
water in the undisturbed zone. The saturation is known as the total water saturation if the
pore space is the total porosity, and the effective water saturation if the pore space is the
effective porosity. If used without qualification, the term usually refers to the effective
water saturation.
Determining Fluids in Place
To calculate the volume of oil, water and gas in place in a reservoir, we need to know the
acre-feet of the reservoir (the area of the reservoir times its thickness in feet), the porosity
of the reservoir in percent, and the percent saturation of the oil, water and gas. Note that
the sum of the percent saturation of the three fluids must equal 100%.
The acre-foot was originally an irrigation term and refers to the corresponding volume of
an acre of fluid that is one foot deep. An acre is equivalent to 43, 560 ft2, so an acre-foot
is 43, 560 ft3. One barrel is equivalent to 5.617 ft3, so there are 7, 758 barrels in one acrefoot. In order to calculate the barrels of oil in place in a reservoir, we multiply 7, 758 by
the acre-feet of the reservoir, by the porosity of the reservoir, and by the percent
saturation of oil. To determine the barrels of water and gas in place, we simply replace
the percent saturation of oil with the water and gas saturation, respectively. In conclusion,
it should be said that it is not possible to recover all of the oil in place. The amount that
can be recovered depends on the reservoir pressure and permeability, as well as the oil
viscosity.
OOIP = 7758*A*h*∅*(1-Sw)
Where OOIP is the original oil in place in barrels
A is the Area in acre-feet h is the thickness of the oilsand ∅ is the porosity, fraction Sw is the water saturation, fraction
OGIP = 43,560*A*h*∅*(1-Sw)
Where OGIP is the original Gas in place in cubic feet
A is the Area in acre-feet h is the thickness of the gas sand ∅ is the porosity, fraction Sw is the water saturation, fraction
45
PETROLEUM RESERVES DEFINITIONS
Reserves derived under these definitions rely on the integrity, skill, and judgment of the
evaluator and are affected by the geological complexity, stage of development, degree of
depletion of the reservoirs, and amount of available data. Use of these definitions should
sharpen the distinction between the various classifications and provide more consistent
reserves reporting.
Reserves are those quantities of petroleum which are anticipated to be commercially
recovered from known accumulations from a given date forward. All reserve estimates
involve some degree of uncertainty. The uncertainty depends chiefly on the amount of
reliable geologic and engineering data available at the time of the estimate and the
interpretation of these data. The relative degree of uncertainty may be conveyed by
placing reserves into one of two principal classifications, either proved or unproved.
Unproved reserves are less certain to be recovered than proved reserves and may be
further sub-classified as probable and possible reserves to denote progressively increasing
uncertainty in their recoverability.
The intent of the Society of Petroleum Engineers (SPE) and World Petroleum Council
(WPC, formerly World Petroleum Congresses) in approving additional classifications
beyond proved reserves is to facilitate consistency among professionals using such terms.
In presenting these definitions, neither organization is recommending public disclosure of
reserves classified as unproved. Public disclosure of the quantities classified as unproved
reserves is left to the discretion of the countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of estimation
is called deterministic if a single best estimate of reserves is made based on known
geological, engineering, and economic data. The method of estimation is called
probabilistic when the known geological, engineering, and economic data are used to
generate a range of estimates and their associated probabilities. Identifying reserves as
proved, probable, and possible has been the most frequent classification method and
gives an indication of the probability of recovery. Because of potential differences in
uncertainty, caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or engineering data
becomes available or as economic conditions change. Reserves do not include quantities
of petroleum being held in inventory, and may be reduced for usage or processing losses
if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery methods.
Improved recovery methods include all methods for supplementing natural energy or
altering natural forces in the reservoir to increase ultimate recovery. Examples of such
methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical
flooding, and the use of miscible and immiscible displacement fluids. Other improved
46
recovery methods may be developed in the future as petroleum technology continues to
evolve.
Proved Reserves
Proved reserves are those quantities of petroleum which, by analysis of geological and
engineering data, can be estimated with reasonable certainty to be commercially
recoverable, from a given date forward, from known reservoirs and under current
economic conditions, operating methods, and government regulations. Proved reserves
can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to express a
high degree of confidence that the quantities will be recovered. If probabilistic methods
are used, there should be at least a 90% probability that the quantities actually recovered
will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that is
consistent with the purpose of the reserve estimate, appropriate contract obligations,
corporate procedures, and government regulations involved in reporting these reserves.
In general, reserves are considered proved if the commercial producibility of the reservoir
is supported by actual production or formation tests. In this context, the term proved
refers to the actual quantities of petroleum reserves and not just the productivity of the
well or reservoir. In certain cases, proved reserves may be assigned on the basis of well
logs and/or core analysis that indicate the subject reservoir is hydrocarbon bearing and is
analogous to reservoirs in the same area that are producing or have demonstrated the
ability to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated by drilling
and defined by fluid contacts, if any, and (2) the undrilled portions of the reservoir that
can reasonably be judged as commercially productive on the basis of available geological
and engineering data. In the absence of data on fluid contacts, the lowest known
occurrence of hydrocarbons controls the proved limit unless otherwise indicated by
definitive geological, engineering or performance data.
Reserves may be classified as proved if facilities to process and transport those reserves
to market are operational at the time of the estimate or there is a reasonable expectation
that such facilities will be installed. Reserves in undeveloped locations may be classified
as proved undeveloped provided (1) the locations are direct offsets to wells that have
indicated commercial production in the objective formation, (2) it is reasonably certain
that such locations are within the known proved productive limits of the objective
formation, (3) the locations conform to existing well spacing regulations where
applicable, and (4) it is reasonably certain the locations will be developed. Reserves from
other locations are categorized as proved undeveloped only where interpretations of
47
geological and engineering data from wells indicate with reasonable certainty that the
objective formation is laterally continuous and contains commercially recoverable
petroleum at locations beyond direct offsets.
Reserves which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful testing by
a pilot project or favorable response of an installed program in the same or an analogous
reservoir with similar rock and fluid properties provides support for the analysis on which
the project was based, and, (2) it is reasonably certain that the project will proceed.
Reserves to be recovered by improved recovery methods that have yet to be established
through commercially successful applications are included in the proved classification
only (1) after a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides support for
the analysis on which the project is based and (2) it is reasonably certain the project will
proceed.
Unproved Reserves
Unproved reserves are based on geologic and/or engineering data similar to that used in
estimates of proved reserves; but technical, contractual, economic, or regulatory
uncertainties preclude such reserves being classified as proved. Unproved reserves may
be further classified as probable reserves and possible reserves.
Unproved reserves may be estimated assuming future economic conditions different from
those prevailing at the time of the estimate. The effect of possible future improvements in
economic conditions and technological developments can be expressed by allocating
appropriate quantities of reserves to the probable and possible classifications.
Probable Reserves
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this context,
when probabilistic methods are used, there should be at least a 50% probability that the
quantities actually recovered will equal or exceed the sum of estimated proved plus
probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved by normal
step-out drilling where sub-surface control is inadequate to classify these reserves as
proved, (2) reserves in formations that appear to be productive based on well log
characteristics but lack core data or definitive tests and which are not analogous to
producing or proved reservoirs in the area, (3) incremental reserves attributable to infill
drilling that could have been classified as proved if closer statutory spacing had been
approved at the time of the estimate, (4) reserves attributable to improved recovery
48
methods that have been established by repeated commercially successful applications
when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5) reserves in an
area of the formation that appears to be separated from the proved area by faulting and
the geologic interpretation indicates the subject area is structurally higher than the proved
area, (6) reserves attributable to a future workover, treatment, re-treatment, change of
equipment, or other mechanical procedures, where such procedure has not been proved
successful in wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as proved.
Possible Reserves
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable reserves. In this
context, when probabilistic methods are used, there should be at least a 10% probability
that the quantities actually recovered will equal or exceed the sum of estimated proved
plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on geological
interpretations, could possibly exist beyond areas classified as probable, (2) reserves in
formations that appear to be petroleum bearing based on log and core analysis but may
not be productive at commercial rates, (3) incremental reserves attributed to infill drilling
that are subject to technical uncertainty, (4) reserves attributed to improved recovery
methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics are such that a reasonable doubt exists that the project will be
commercial, and (5) reserves in an area of the formation that appears to be separated from
the proved area by faulting and geological interpretation indicates the subject area is
structurally lower than the proved area.
Reserve Status Categories
Reserve status categories define the development and producing status of wells and
reservoirs.
Developed Reserves
Developed reserves are expected to be recovered from existing wells including reserves
behind pipe. Improved recovery reserves are considered developed only after the
necessary equipment has been installed, or when the costs to do so are relatively minor.
Developed reserves may be sub-categorized as producing or non-producing.
49
Producing Reserves
Reserves subcategorized as producing are expected to be recovered from completion
intervals which are open and producing at the time of the estimate. Improved recovery
reserves are considered producing only after the improved recovery project is in
operation.
Non-producing Reserves
Reserves subcategorized as non-producing include shut-in and behind-pipe reserves.
Shut-in reserves are expected to be recovered from (1) completion intervals which are
open at the time of the estimate but which have not started producing, (2) wells which
were shut-in for market conditions or pipeline connections, or (3) wells not capable of
production for mechanical reasons. Behind-pipe reserves are expected to be recovered
from zones in existing wells, which will require additional completion work or future
recompletion prior to the start of production.
Undeveloped Reserves
Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled
acreage, (2) from deepening existing wells to a different reservoir, or (3) where a
relatively large expenditure is required to (a) recomplete an existing well or (b) install
production or transportation facilities for primary or improved recovery projects.
50
SURFACE EXPLORATION METHODS
In regions where rocks are exposed at he surface, geological studies based on these
surface outcrops can be of value in predicting sub-surface geology. Analysis of this
information can provided can sometimes be extrapolated to anticipate geology in other
locations not accessible for observation and analysis. The major sources of surface
geological information are:
i) Field Reconnaissance
ii) Aerial Surveys
iii) Satellite Surveys
iv) Surface Geochemical Analysis
Field Reconnaissance
This involves observation and sample collection of surface geological exposures. In some
regions, surface geological outcrops imply sub-surface geological characteristics. This
surface observation might provide an indication of the sequence of geological events,
which led to this surface geology. Geological properties such as strike and dip of
sedimentary beds, faults unconformities or other geologic exposures may be of major
importance in anticipating subsurface geology. The strike is the compass direction of a
horizontal line drawn in the plane under consideration. The dip is the angle between a
horizontal plane and a line drawn in the plane under consideration, perpendicular to the
intersection of the horizontal plane and the plane under consideration.
Aerial surveys
More recently, satellite surveys might provide the same type of information as that by
field reconnaissance, except over large regions. Extensive geologic information of
importance in defining sub-surface geology has been gathered by such surveys as landsat
survey, infra-red photography, radar photography and other sophisticated technologies.
Surface Geochemical Analysis
This can provide indicates of the presence of sub-surface hydrocarbon reservoirs. Many
scientists speculate that all sub-surface hydrocarbon reservoirs give surface chemical
indications of their presence. The simplest example is the surface seep, where
hydrocarbon is actually escaping or seeping to the surface and being dissipated, in
geologic time, into the environment. The conclusion can therefore be drawn that this
surface hydrocarbon must be originating from sub-surface reservoirs.
51
GEOPHYSICAL EXPLORATION
After identifying sedimentary basins thought to contain hydrocarbons, an oil company
acquires the mineral rights from the individual or government holding them. The oil
company will then contract with a seismic acquisition company to map the area's
underground rock formations through seismic surveying.
Figure 26 – Seismic Acquisition
52
Seismic Surveys
Seismic surveys use low frequency acoustical energy generated by explosives or
mechanical means. These waves travel downward, and as they cross the boundaries
between rock layers, energy is reflected back to the surface and detected by sensors called
geophones. The resulting data, combined with assumptions about the velocity of the
waves through the rocks and the density of the rocks, are interpreted to generate maps of
the formations.
Seismic surveys are usually performed using multiple geophones set at known distances
from the energy source. Early seismic surveys used mechanical plotters to record the
received signals, and were restricted to a few geophones. These surveys placed the source
and geophones in a straight line, with the interpretation of the resulting data producing a
2-D cross section of the formation under that line. The interpretations were subject to
error, which increased the difficulty, and cost, of accurately locating hydrocarbon-bearing
formations.
Today, the development of digital recording systems allow the recording of data from
more that 10,000 geophones simultaneously, greatly speeding data collection.
Sophisticated computer programs develop highly accurate 3-D models of rock structures.
These models are more accurate than past 2-D maps, and increase the likelihood of
accurately identifying hydrocarbon-bearing formations.
Seismic Section
The seismic reflection method works by bouncing sound waves off boundaries between
different types of rock. The reflections recorded are plotted as dark lines on a seismic
section. A seismic section resembles a geological cross-section, but it still needs to be
interpreted.
One major difference between a geological cross-section and a seismic section is that the
vertical axis is in time, rather than depth. In the earth's crust, seismic waves travel
typically at about 6000 m/s so that 1 second of two-way travel time corresponds to about
3 km of depth. All the seismic sections presented in this atlas are plotted at 1:1 (no
vertical exaggeration) assuming an average crustal velocity of 6000 m/s.
Another difference is that the reflections are plotted halfway between the source and the
receiver. These are referred to as unmigrated data. The process that moves the reflections
in their correct spatial position is referred to as migration, and the resulting seismic
section is referred to as a migrated section.
The science of LITHOPROBE is spearheaded by the seismic reflection method because it
is the geophysical technique which produces the best images of the subsurface. These
data resolve mappable features such as faults, folds and lithologic boundaries measured
53
in the 10's of meters, and image them laterally for 100's of kilometers and to depths of 50
km or more (Varsek, 1992).
Seismic reflection profiling is the principal method by which the petroleum industry
explores for hydrocarbon-trapping structures in sedimentary basins. Its extension to deep
crustal studies began in the 1960s, and since the late 1970s reflection technology has
become the principal procedure for detailed studies of the deep crust.
Seismic data acquisition
The method works by bouncing sound waves off boundaries between different types of
rock (Figure 1). As opposed to earthquake seismology, where the location and time of the
source is an unknown that needs to be solved for, seismic reflection profiling uses a
controlled source to generate seismic waves. On land, LITHOPROBE has been using
large truck-mounted vibrators as a source (the "Vibroseis" method), and occasionally
dynamite is used. At sea, large arrays of airguns, which rapidly eject compressed air, are
deployed. The reflected signals are recorded by geophones, or hydrophones at sea, which
resemble ordinary microphones.
Figure 26 – Seismic data Acquisition
54
During a seismic survey, a cable with receivers attached to it at regular intervals is laid
out along a road or towed behind a ship. The source moves along the seismic line and
generates seismic waves at regular intervals such that points in the subsurface, such as
point P in Figure 1, are sampled more than once by rays impinging on that point at
different angles. As a shot goes off, signals are recorded from each geophone along the
cable for a certain amount of time, producing a series of seismic traces. The seismic
traces for each shot (called a shot gather) are saved on magnetic tape in the recording
truck.
Seismic data processing
Digital data processing is applied to raw seismic data to produce a seismic section (Figure
27). The following is an example of typical processing sequence.
Figure 27. Seismic data processing.
The data are read from tape and the shot records (i.e. all traces recorded for a given shot)
are displayed (1). Bad seismic traces, due to noise or a short circuit in the recording
equipment, are edited out (2). The traces are then reordered (3) so that each gather of
traces belongs to a common reflection point, such as point P in Figure 26.
55
Non-reflected arrivals, such as surface waves and direct arrivals, are removed by digital
filtering and/or muting (zeroing of the data) (4). A correction is made for the time the
reflected ray spends travelling laterally, so that the reflected arrivals now line up (5).
These traces are then added to produce a single output trace (6). This process, referred to
as stacking, cancels out random noise and reinforces the reflected signals. The waveform
is then shrunk by frequency filtering or deconvolution to improve the resolution (7).
Steps (4) to (7) are repeated for each common reflection point, and the resulting seismic
traces are displayed as a seismic section (8) which is then interpreted (9).
Marine Seismic acquisition
Figure 28 – Marine Seismic Acquisition
In marine seismic surveys, a shock wave is created by the following:
• Compressed-air gun - shoots pulses of air into the water (for exploration over
water)
The reflections of the shock waves are detected by sensitive microphones or vibration
detectors (hydrophones) over water.
Although modern oil-exploration methods are better than previous ones, they still may
have only a 10-percent success rate for finding new oil fields. Once a prospective oil
strike is found, the location is marked by marker buoys on water.
56
Seismic records and the synthetic seismogram
Seismic energy sources used by the energy industry are required to generate reflections
from rock units several thousand feet below the surface, and so typically have frequencies
of the order of 30 Hz. A simulation of a field record of this type is shown in Figure 1.
This synthetic seismogram was computed using a sonic log recorded in a Dakota Aquifer
program observation well in Ellis County.
Notice that the depth scale is not measured in feet but in units of two-way travel time in
seconds that record the time that elapsed between the triggering of the energy source and
the arrival of the reflection at the geophone. Because the sound velocity changes
continuously with depth the time record is not a simple transformation of depth. The
reflection peaks (black) pick up rock boundaries where the acoustic velocity increased
downwards going from a "slow" shale to a "faster" limestone or sandstone, while the
reflection troughs (white) match the reverse situation.
The 30 Hz frequency of the energy source results in a fairly coarse resolution, so that
only fairly thick rock units with strong impedance contrasts can be distinguished. This
characteristic can be seen in Figure 1, where the stratigraphic units are resolved easily,
but reflections generated by the sandstones within the Dakota Aquifer tend to overlap and
merge.
57
Figure 29. Synthetic seismogram for the Dakota aquifer and adjacent stratigraphic units,
calculated from geophysical logs in the observation well KGS Braun #1 (NENENE 30-
12S-18W), Ellis County, Kansas.
Better precision can be obtained by high-frequency seismic shooting of Dakota Aquifer
sections where they are fairly close to the surface. Coyle (1990) made several field
studies in the vicinity of Dakota Aquifer program observation wells to evaluate the
feasibility of seismic methods in the location of channel sandstones. Sonic logs at the
wells could be used to create synthetic seismograms, so that interpretations of field
records could be correlated with geology.
Gamma-ray and sonic logs are shown from a second observation well in Ellis County
(Figure 30). The sonic log was converted to a two-way reflection time record of velocity,
58
which was then transformed to a train of reflection coefficients and convolved with a 100
Hz Ricker wavelet (Figure 31). By superimposing the synthetic seismogram at the
observation well location on the East-West seismic line (Figure 32), the field reflections
can be related to specific geological features. The Stone Corral provides a strong reflector
that is easily recognized on seismic records from the entire region
Figure 30. Gamma-ray and sonic logs from observation well KGS Brungardt #1
(SESESE 25-12S-17W), Ellis Co., Kansas.
59
The contact between the Dakota Formation and the underlying Kiowa Shale can be seen ,
and is caused by the sharp change in velocity at the contact (see Figure 30). Reflections
from the Greenhorn Limestone, Graneros Shale, and the top of the Dakota Formation can
also be identified on the field record from their signatures on the synthetic seismogram.
The distinctive and laterally continuous reflection at 0.26 seconds was interpreted to
coincide with the top of the Permian.
Figure 31. Comparison between the synthetic seismogram computed from the Brungardt
well sonic log (see Figure 3) and a field seismic line shot at the well site (from Coyle,
1990)
Coyle concluded that while thin sandstone lenses within the Dakota would not be
detectable at this frequency (100 Hz), modeling suggested that sandstones thicker than 30
feet would be resolvable. A field seismic line shot over a Dakota channel sandstone at
another site gave some support to his conclusion (Figure 5). Thinner sandstones could be
identified where reflections were recorded with frequencies higher than 180 Hz. The
resolution and quality of seismic records were also found to be site dependent. The best
sites were located on fresh exposures of Graneros Shale, where reflections of 200 Hz and
60
higher were recorded. The worst sites occurred on the Greenhorn Limestone outcrop,
while low frequencies were recorded at levels higher than the Greenhorn.
Figure 32. CDP seismic section tied to Dakota Aquifer program observation well KGS
Haberer #1 (NESENE 14-12S-15W), Russell County, Kansas. Note channel sandstone.
From Coyle, 1990.
61
Figure 33 – Seismic Section
Gravity Surveys
All materials in the earth influence gravity but because of the inverse-square law of
behaviour, rocks that lie close to the point of observation will have a much greater effect
than those farther away. The bulk of the gravitational pull of the earth (g) has little to do
with the rocks of the earth’s crust but rather is caused by the enormous mass of the
mantle and core. Only about 0.3% of g is due to materials contained within the crust and
of this small amount roughly 15% (0.05g) is accounted for by the uppermost 5 kilometres
of rock. Changes in the densities of rocks within this region will produce variations in g
which generally do not exceed 0.01% of its’ value anywhere. Fluctuations in the value of
g which may be associated with bodies that have a commercial mineral value are unlikely
to exceed even a small fraction of this minute amount, perhaps 10-5 g altogether. Thus
geological structures contribute very little to the earth’s gravity but the importance of that
small contribution lies in the fact that it has a point-to-point variation that can be mapped.
The gravitational field of the earth has a world-wide average of ~980 gals with a total
range of variation from equator to pole of about 5 gals, or 0.5%. Mineral ore bodies and
62
geological structures of interest seldom produce fluctuations in g exceeding a few
milligals and for practical purposes of exploration, a reading sensitivity of 0.01 milligals
is required. This represents about 1 part in 108 of the gravitational field of the earth. No
instrumentation is available that can measure g absolutely to this accuracy. Modern day
gravimeters respond to variations in g by measuring minute changes in the weight of a
small object as it is moved from place to place and can achieve reading sensitivities of
0.001 mgals.
Surface gravity measurements are affected by several factors, including such things as the
tidal forces generated by the moon, local topography and the ellipticity of the earth.
These factors can generate changes in the measured gravity that are several orders of
magnitude greater than those generated by the density variations in the underlying rocks.
Compensation for these factors requires precise geographical survey precision. For a
typical survey, the distance from the equator must be measured to within ~3 metres and
the absolute elevation to within 2-3 cm. For small, localized surveys, topographic
features within several hundred metres of the measurement location are considered. For
more regional surveys, major topographic features (mountains, lakes, oceans) within a
radius of 150 kilometres must be included in the data reduction procedures.
In the past, topographic surveys of this accuracy often accounted for the bulk of survey
costs. Recent advances in global positioning (GPS) technology have reduced these costs
considerably.
Gravity exploration typically involves taking measurements of the earth’s gravimetric
field across a surface grid. These data are processed to compensate for the various effects
described above to produce a map showing the relative strength of the earth’s gravity
across the area of interest. The presence of an anomalous mass beneath the surface will
be superimposed on the background field. By estimating this regional field and
subtracting it from the observed data, one obtains the field due to this anomalous mass.
Characteristics of this field can be used to estimate the properties of the anomalous body.
Magnetic Surveys
Magnetic intensity measurements are taken along survey traverses (normally on a regular
grid) and are used to identify metallic mineralization that is related to magnetic materials
(normally magnetite and/or pyrrhotite). Magnetic data are also used as a mapping tool to
distinguish rock types, identify faults, bedding, structure and alteration zones. Line and
station intervals are usually determined by the size and depth of the exploration targets.
The magnetic field has both an amplitude and a direction and instrumentation is available
to measure both components. The most common technique used in mineral exploration is
to measure just the amplitude component using a proton precession magnetometer. The
instrument digitally records the survey line, station, total magnetic field and time of day
63
at each station. This information is typically downloaded to a computer at the end of each
day for archiving and further processing.
The earth’s magnetic field is continually changing (diurnal variations) and field
measurements must be adjusted for these variations. The most accurate technique is to
establish a stationary base station magnetometer that continually monitors and records the
magnetic field for the duration of the survey. The base station and field magnetometers
are synchronized on the basis of time and computer software is used to correct the field
data for the diurnal variations.
64
STRUCTURE CONTOUR MAPPING
Contour lines help geologists (as well as hikers) understand the slope of the land. Each
line represents the elevation at that line. If you were to walk across a line, you are
changing elevation. The steeper the slope, the more lines you will cross in a short
distance
This concept of contour lines also works
under ground. Just like rocks above ground
can be seen to be bent, forming anticlines
(domes) or synclines (saddles), these
structures extend beneath ground. Therefore,
if the geologist understands what the
structure of the layers of rock underground
look like (either by well data or geophysical
evidence such as seismic reflections), he or
she can draw a contour map which represents
this structure
Figure 34 – Contour Mapping
Above ground, contour lines represent elevations, or heights. Below ground, the numbers
represent depths BELOW the surface. Therefore, a 1,000 meter contour line equals a
depth of 1000 meters (or NEGATIVE 1,000 meters), and would actually be higher than
the 2,000 meter contour.
(To be more accurate, generally, subsurface contours are mapped relative to a SEA
LEVEL datum, so even below the ground's surface you can have positive contour values,
and only get negative values when the contour depth is below sea level.)
Contour maps
 Maps that represent surfaces in terms of a series of curves. An individual curve
represents a part of the surface along which the surface "value" is constant. Topographic
contour  map: contour lines represent points of equal elevation of the ground surface.
Structure  contour  map: contour lines represent points of equal elevation along a geologic
surface (e.g., the top of a geologic unit) that commonly is buried. If the values of a
structure  contour  map are subtracted from the values on a corresponding topographic
65
map, the difference gives the depth from the ground surface to the top of the geologic
unit.
Isopach  contour  map:  contour lines represent points of equal thickness of the geologic
unit
Given a data set (x, y, z), one can prepare a contour  map of z (e.g., concentration of
contamination in ground water) vs. (x, y).
Geologic maps show the intersection (trace) of geologic features with the ground surface,
a surface that is generally sub horizontal but irregular (i.e., with some limited 3­D relief).
Geologic maps are not top views of subsurface features as projected into a horizontal
plane.
The strike of a geologic surface is obtained by determining the azimuth between two
points on the geologic surface that have the same elevation (i.e., that lie along the
intersection of the geologic surface and a horizontal plane).
A strike view cross section is taken perpendicular to the strike of a geologic body. It
shows the true dip and true thickness of the body.
The contacts of horizontal layers parallel elevations contours.
The contacts of vertical geologic surfaces appear as straight lines on geologic maps with a
topographic base.
Most geologic structures are not ideal planes, and structure contours on these structures
are often neither straight nor equally-spaced. In fact, structure contours can violate many
of the rules we are familiar with on topographic maps.
• Geologic structures often have overhangs; hence structure contours can cross.
Actually the contours themselves do not cross, only their projections on the map.
• Geologic structures often have discontinuities in the form of faults. Structure
contours can terminate and not close.
In the example we consider here, we will be concerned only with data that is fairly wellbehaved: smooth, with no overhangs or discontinuities. The problem is very similar to
contouring topographic data.
66
Rules for Construction
• Structure contours must still be parallel to the strike of a structure at every point.
• Keep the contours as simple as possible consistent with the data.
• Keep the contours smooth. Do not show abrupt changes in curvature or spacing
unless you have sound geologic reasons to do so.
• Interpolate only between nearby points
• If the structure is only gently curved, you may find it useful to approximate the
structure as a series of plane segments at first. For each group of three data points,
construct structure contours using the three-point method. Make sure the triangles
are as nearly equilateral as possible. Once the contours are constructed, draw the
final contours as smoothly as possible using the construction as a guide.
• You will often have surface or near-surface data and little or no data at great
depth. In such cases, your contours will be little more than guesses to suggest the
three-dimensional form of the structure. Such contours are called form lines. In
cases like this, you have no choice but to extrapolate surface data to deep levels
and use your knowledge of geologic structures as a guide.
Example
1. Contour the data shown
2. Interpolate between
nearby points. Avoid
extremely long-distance
interpolations.
3. Sometimes it pays to
treat the data as a series of
three-point problems.
4. Once you have a clear
mental picture of the
structure, construct smooth
contours to fit the data.
Figure 35 – Example of structure contouring
67
• Note that some of the data are negative. It is perfectly possible to have data points
below sea level when analyzing data from deep wells or when drawing form lines
on large, deep structures.
• If you treat the data as a series of three-point problems, contours within each
triangle must join the corresponding contours in neighboring triangles.
• When drawing the smoothed contours, the contours must be consistent with the
data points but need not be perfectly consistent with points estimated by
interpolation. A data point at 210 meters elevation must be located on the uphill
side of the 200 meter contour. But interpolated points are only estimates of the
elevation of the structure. Trying to fit all the interpolated points exactly may
result in contours that are overly erratic. Worse yet, it may create the impression
of spurious detail - a user of the contour map may be misled into thinking the
undulations in the contour are real features of the structure. It's better to draw
smooth contours that are as consistent as possible with both the interpolations and
with other contours.
• Note that the 0 and -100 contours are extended into areas of no data, based on the
overall shape of known contours. We can be fairly sure the -100 contour passes
just outside the -97 data point, but elsewhere, there is little control on the exact
locations of these contours. These are examples of form lines. We expect them to
be roughly correct, but do not expect high precision from them.
68
SUBSURFACE EXPLORATION METHODS
The wildcat well is defined as the first well to be drilled in a geographic region. The
drilling of the wildcat well is the beginning of the final stages of exploration. This is the
first opportunity to actually bring back to the surface for analysis samples of the
subsurface rocks and fluids. It is important to obtain as much information as possible
relative to subsurface conditions including rock properties, fluid properties and any other
significant data, which might be obtained.
There are many potential sources of important information from a wildcat well. Some of
these information sources may provide data not otherwise available from other sources, or
confirm data obtained from one or more of the potential sources of information. These
include rock cuttings, reservoir fluid samples, mud logs, cores, well logs and Drill Stem
Tests.
Rock Cuttings
During the drilling operation, rock removed from the subsurface formations by the drill
bit, are being returned to the surface on a continuous basis.  These samples are analysed
in order to describe the subsurface geology and for indications of hydrocarbon presence
within the cuttings. A cuttings analysis with well depth is used to complete a stratigraphic
column as a summary of subsurface geology. 
Reservoir Fluid Samples
Reservoir fluid samples are collected from any reservoir rocks that are of potential
interest. Various collection techniques are available, such as the pressure bomb. These
fluid samples are sent to the laboratory for a P-V-T analysis. This provides important
reservoir fluid data such as chemical composition, fluid formation volume factors, bubble
point pressure, solution gas oil ratio, viscosity and density.
Mud Logs
69
The drilling fluid, pumped through the inside of the drill string and exiting the drill bit
while drilling, carries rock samples back to the surface in the drilling mud. When drilling
into a rock formation containing hydrocarbons, traces of reservoir fluids encountered will
be returned to the surface in the drilling mud. Surface samples of the mud are collected
and analysed for hydrocarbon presence. This is known as a mud log. The mid log
contains description of the rock type based on inspection under a microscope, plot of
penetration rate, gas composition based on gas chromatography, oil cut based on washing
the cuttings in toluene and ultraviolet fluorescence to determine presence of oil.
Cores
When a formation of interest is encountered while drilling, one of the most important
sources of downhole information is the core of the reservoir rock. A typical core is a rock
cylinder, normally 4” to 6” in diameter, of the reservoir rock retrieved from the wellbore
to the surface in a core barrel.
The core is sent to the laboratory for analysis. Potential information obtained includes
rock type, rock characteristics, source of the sediments, depositional environments,
porosity, permeability, radioactive properties and estimates of fluid saturations in the
rock. Sidewall cores, which are less than 1” in diameter and less than 3” in length can be
taken instead of the full hole cores which can be 30 – 60 feet in length.
70
WELL LOGS
A log of a well is a determination of downhole properties relative to depth. Many types of
logs are run in a borehole, depending upon the information desired and equipment
available. Typical logs run are electric logs, magnetic logs, sonic logs, radioactive logs
and physical logs of various types. Properties measured by these logs may include
pressure, temperature, rock density, porosity, permeability, fluid saturations, magnetic
properties, radioactive properties and sonic velocity. In most instances more than one log
is run simultaneously during a logging run.
The Spontaneous Potential (SP) log
The spontaneous potential tool measures natural electrical potentials that occur in
boreholes and generally distinguishes porous, permeable sandstones from intervening
shales. The "natural battery" is caused when the use of drilling mud with a different
salinity from the formation waters, causes two solutions to be in contact that have
different ion concentrations. Ions diffuse from the more concentrated solution (typically
formation water) to the more dilute. The ion flow constitutes electrical current, which
generates a small natural potential measured by the SP tool in millivolts.
When the salinities of mud filtrate and formation water are the same, the potential is zero
and the SP log should be a featureless line. With a fresher mud filtrate and so, more saline
formation water, a sandstone will show a deflection in a negative potential direction (to
the left) from a "shale base line" (Figure 8). The amount of the deflection is controlled by
the salinity contrast between the mud filtrate and the formation water. Clean (shale-free)
sandstone units with the same water salinity should show a common value, the "sand
line". In practice, there will be drift with depth because of the changing salinity of
formation waters. The displacement on the log between the shale and sand lines is the
"static self-potential" SSP.
Although they record different physical properties, the two logs are comparable because
of their sensitivities to shale and so both can be used to differentiate between sandstones
and shales. The stronger sandstone differentiation at greater depths on the SP log is
caused by greater salinities in the deeper sandstones.
71
Figure 35. Spontaneous potential (SP) and gamma-ray log from KGS Jones #1.
The SP log in Figure 35 is an example taken from a shallow section of the Dakota. Notice
how the shale baseline shows a distinctive drift with depth. This characteristic is
commonly observed in shallow sections and has been suggested to be caused by increases
in relative oxidation of the rocks that are close to the land surface. The highest sandstone
in the well has a muted deflection on the SP log as compared with the lower sandstones.
This contrast is an immediate indication that water in the upper sandstone may be
significantly fresher than waters of the lower sandstone. In other wells it is not
uncommon to see sandstone units where the SP deflection goes to the right of the shale
baseline. In these instances, the drilling mud filtrate is saltier than the formation water. A
good example of this phenomenon is shown in Figure 9 from a well in north-west
72
Kansas. In the upper sandstone, "U", the SP log shows a deflection to the right, indicating
formation water to be fresher than the drilling mud, while in the lower sandstone, "L", the
deflection is to the left, showing the formation water to be more saline.
Figure 36. Spontaneous potential (SP) and gamma-ray logs of the Dakota Aquifer in
Cities Service Montgomery #2 CNENW 7-8S-23W, Graham County, Kansas.
Note that the SP log deflects to the right in the upper sandstone, "U," but to the left in the
lower sandstone "L." This "reversal" occurs because the formation water in the upper
sandstone is fresher than the drilling mud, but saltier than the drilling mud in the lower
sandstone.
73
The conductivity of the drilling mud filtrate is measured by the engineers at the well-site
and recorded on the "header" of the log. This information combined with the SSP "battery
effect" shown on the log can be used to estimate the conductivity of the formation water.
The calculation is made very commonly by petroleum log analysts as an important
variable in the search for potential oil or gas zones (see Figure 10). When used to
evaluate the quality of aquifer waters, care must be taken to ensure realistic conclusions.
Although formation water compositions at greater depths tend to be mostly sodium
chloride, the ions of calcium, magnesium, bicarbonate and sulfate become more
important in shallow, aquifer waters. As a result, the equations used by petroleum log
analysts are only approximate and must be adjusted to honor the ionic mix of the local
aquifer water. In general, the divalent ions of shallow waters tend to make them appear
slightly more saline than they actually are when computed from the SP log.
74
Figure 37. Flow chart from oil-industry log analysis to estimate formation water
resistivity, Rw, in deep formations from the SP log (Bateman and Konen, 1977).
RMF is mud filtrate resistivity measured at temperature Tmf and recorded on the log
header; Tf is the temperature of the formation, generally estimated by interpolating
between the bottom-hole temperature (BHT) at total depth (TD) and mean annual
temperature at the surface; SSP is the static self-potential measured on the log between
the "clean line" and "shale line" in millivolts (mv) AND with associated sign (positive or
negative).
An empirical chart was developed as part of the research in the Dakota to correct
apparent water resistivities calculated from standard equations to estimates of real
resistivities measured in Dakota Aquifer water samples (Figure 38). The corrected
resistivities were then transformed to estimates of total dissolved solids. The method is
particularly useful in Dakota Aquifer studies because it allows water quality studies to be
extended beyond wells from which Dakota water samples were taken to wells that were
unsampled but logged with an SP device.
75
Figure 38. Custom-designed chart and function to convert apparent water resistivity
(Rwe) calculated from oil-industry algorithms to actual resistivity (Rw) of Dakota
Aquifer waters.
The correction is necessary because Rwe is calculated with the assumption that the
dissolved solids in the water are from a single salt; actual Rw values will be controlled by
the ionic mix of natural waters, and discrepencies with Rwe will be particularly noticable
in the relatively fresher waters of shallow formations. From Boeken (1995).
76
TheResistivity log
Resistivity logs measure the ability of rocks to conduct electrical current and are scaled in
units of ohm-meters. There is a wide variety of resistivity tool designs, but a major
difference between them lies in their "depth of investigation" (how far does the
measurement extend beyond the borehole wall?) and their "vertical resolution" (what is
the thinnest bed that can be seen?). These characteristics become important because of
the process of formation "invasion" that occurs at the time of drilling. In addition to its
other functions, drilling mud forms a mudcake seal on the borehole wall of permeable
formations.
77
Figure 39. Spontaneous potential (SP) spherically focussed (SFL) medium- (ILM) and
deep- (ILD) induction resistivity logs from KGS Jones #1.
However, in doing this, some mud filtrate penetrates into the formation, displacing
formation water and this is called "invasion". The replacement of formation water by
mud filtrate involves a change of pore water resistivity.
The difference between the resistivity log measurements and the invasion process can be
seen on Figure 12, where separation between the curves can be seen in the more porous
and permeable sandstones, but minimal separation in the shales which are effectively
impermeable. From a hydrologic perspective, the multiple resistivity curves are therefore
excellent discriminators of aquifer and aquitard units. The mud used in the example well
was less saline than formation waters in the deeper units, as is common in many drilling
operations. The shallowest reading resistivity device (in this case, the spherically focused
log) therefore records the highest resistivity because it responds mostly to formation
invaded by the higher resistivity mud filtrate.
The two induction logs draw their responses from deeper in the formation, so that the
deep induction log (ILD) probably records a reading close to the true resistivity of the
undisturbed formation. Notice that the resistivities in the uppermost sandstone (depth,
100 feet) are contrasted with those in the lower sandstones by showing a much reduced
separation. As observed already, the dampened deflection of this sandstone on the SP log
shows that its contained water is only slightly more saline than the drilling mud, and
much less saline than the lower sandstones. Therefore, invading mud filtrate is only
slightly fresher than the connate water, so that invasion effects on the resistivity logs are
masked.
The sensitivity of resistivity logs to water salinity can be used in an alternative method to
SP log estimates of water quality. In a sandstone-shale sequence, resistivity variation is
controlled by a variety of phenomena, including cation-exchange mechanisms by clay
minerals within the shalier zones, conduction by metallic minerals, and the dissolved ions
within the pore water of the sandstones.
However, formation water resistivity may be calculated in shale-free sandstone zones that
are logged by resistivity and porosity tools. The water resistivity (Rw) is calculated from
the resistivity and porosity log readings by the Archie equation (Archie, 1942) that
incorporates a "cementation factor" (m) expressing the tortuosity of the pore network as a
modifier to the fractional volume of pore space (F):
Rw = Ro x F**m
where Ro is the resistivity reading of the zone when it is completely saturated with water
whose resistivity is Rw. The method is widely used by log analysts in the oil industry and
generally gives good estimates of water resistivity in deeper (more saline) formation
waters. Results are less reliable in aquifers because of clay mineral effects as well as
surface conduction on quartz grain surfaces.
78
A water resistivity/specific conductance curve was computed for the Dakota Aquifer in
the Jones well using the Archie equation with a cementation exponent (m) of 1.6 (an
appropriate value for a slightly cemented sandstone). The water resistivity curve is shown
in Figure 40 and is indexed with two water sample measurements and a reference value
from Rattlesnake Creek.
Figure 40 - Spontaneous potential (SP) log and profile of specific conductance of
formation water estimated from resistivity and porosity logs in KGS Jones #1.
79
The curve is shown only for zones of sandstone that are relative low in clay content as
indicated by the gamma-ray log. The estimated specific conductance trace is a highly
acceptable match with sample measurements and appears to show a transition zone
between the fresher water of the upper sandstone and the more saline waters of the lower
sandstones.
Note match between profile and conductances measured from well water samples.
Again, it must be emphasized that log estimates of water quality should only be used (and
then with caution) where no samples are available for direct analysis. In each case, the
log property is an indirect measure, because it records a physically dependent property,
rather than water salinity itself. In addition, rock properties other than water salinity may
contribute to overall conductivity effects. The accuracy of the estimates degrades as water
salinity decreases, with a general rule of a bias to pessimism in overpredicting salinity in
fresher waters. However, when used judiciously with water chemical measurements, log
data estimates are valuable in extending knowledge of Dakota Aquifer water quality over
larger geographic areas and greater depth ranges.
The "Porosity" logs
There are three types of logging tools that are used to estimate the amount of pore space
in a rock: the neutron, density, and acoustic velocity (or sonic) tool. Although either one
or several of these types of logs are commonly run in oil exploration holes that penetrate
the Dakota, they are not always recorded in the Dakota interval. Commonly, a full suite
of logs is recorded in the deeper section, where there is a potential for oil and gas up to
the level of the Permian Stone Corral. Above the Stone Corral, a more restricted suite
may be run to be used for correlation purposes, and typically consists of the gamma-ray,
SP, and resistivity logs.
The neutron log records counts of the collisions between neutrons that radiate from a tool
source and hydrogen atoms within the rock of the borehole wall. So, the log is mainly a
measure of hydrogen concentration (mostly contained by the pore fluids of the
formation). Older neutron logs are recorded in counts that require conversion to porosity
units either by calibration to units of known porosity within the logged section or by
reconciliation with cored samples from the same well. Newer neutron logs are scaled
directly in units of porosity (Figure 41). Shales appear to have high porosities on the
neutron log, mostly because of bound water, rather than effective porosity. However,
porosities recorded in shale-free sandstones are a reasonable estimate of pore spaces that
contain water that can be produced in a well.
A "limestone scale" is normally, because oil exploration targets below the Dakota are
usually limestone. Actual prosoities in the sandstones will be about 3% higher. The
porosity reflects "free" water in the sandstones, but bound water in the shales.
80
Figure 41. Neutron porosity log from KGS Jones #1. Note that porosity increases from
right to left.
The density log is a measure of apparent density of the rock and is computed from the
absorption of gamma rays emitted from a tool radioactive source by the formation. An
example of a density log run in the Dakota is shown in Figure 42. The density of quartz is
about 2.65 grams per cubic centimeter, and that of water is approximately 1.0. These two
values correspond to the density of a sandstone with zero porosity and a hypothetical
sandstone with a porosity of 100%. The two limits can be used to convert the density
scale to values of equivalent porosity units. On more recent density logs, a supplementary
81
curve of the photoelectric factor is also recorded, and is a useful measure of formation
mineralogy.
Newer density logs commonly have a photoelectric factor curve which is a useful
lithology discriminator.
Figure 42. Density log from KGS Jones #1 recorded in grams per cc (upper scale) and an
equivalent sandstone scale (lower scale).
82
It is common to see both the neutron and density logs recorded on the same logging run
and shown as an "overlay" on a common scale of equivalent limestone porosity units (see
Figure 6). The overlay allows shales, sandstones, and other lithologies to be distinguished
and a better estimate to be made of the true porosity of the formation at any depth. The
log overlay has sufficient information to be converted to a profile that graphically shows
shale content and volume of effective pore space (Figure 7). Notice that the overall shale
composition estimated from the density-neutron log combination is similar to shale
indicated by the gamma ray log. but there are also systematic differences. The reason is,
that while both measurements are sensitive to shale content, the gamma ray log responds
to the natural radioactivity of the shale, while the neutron-density logs are influenced by
the bound water and density of the shales.
83
Figure 43. Neutron and density logs from KGS Jones #1 overlaid on a common
equivalent limestone scale.
The overlay allows the log analyst to recognize lithologies and read values of true
porosity in zones of interest.
Figure 44. Volumetric summary of shale, quartz, and pore space indicated by gamma-ray
and lithodensity-neutron logs from KGS Jones #1.
84
Note that shale estimation by the gamma-ray log is based on natural radioactivity and
shows slight differences with shales from the lithodensity and neutron logs which are
based on shale bound water and density characteristics.
The third type of porosity estimate is computed from measurements of the speed of
ultrasonic sound through the formation. The sonic tool has a mechanical source of
compressional energy that radiates sound through the rock formation in the borehole wall.
The log records the acoustic velocity of the rocks as a trace which is shown as a
continuous function of depth. The log is measured as transit time in units of
microseconds per foot. Sound travels faster in rocks with low amounts of contained fluids
than those with higher contents of fluid. This physical relationship can be used to
compute the porosity of a sandstone at any depth, by interpolating the measured value at
any depth between the expected value of quartz (55.5 microseconds per foot) and that of
water (189 microseconds per foot) as extremes of a porosity scale of zero to 100%
porosity.
The sonic log is widely used by geophysicists to create synthetic seismograms for
comparison with field records of seismic reflections from lines shot close to the well.
Observations from drill-cuttings and logs at the well site allow the geology in the
borehole section to be established. Therefore, reflection events on the synthetic
seismogram can be tagged with specific rock formations and used as a key to identify
reflections on field records. Some exploratory seismic field studies were made by Coyle
(1990) to determine what units in the stratigraphic section that contains the Dakota
Aquifer could be resolved as distinct reflections and whether seismic shooting could be
used in exploration for thick Dakota sandstones.
85
Drill Stem Testing
After drilling a wildcat well, potential zones of interest in the subsurface may be tested
for hydrocarbon presence by running a DST (drillstem test). Drillstem Tests are run more
frequently in open hole than cased hole. A drill stem test will provide the first opportunity
to collect a major sample of reservoir and to evaluate reservoir flow potential.
After drilling and casing well, a DST assembly is attached to the drillstring and run in the
hole. A downhole shut in valve is installed in the DST Assembly so that the well can be
shut in downhole. The well is perforated with completion fluid I the hole of appropriate
density to achieve underbalance.
Underbalance is achieved when the hydrostatic pressure due to the column of completion
fluid is less than the reservoir pressure. A packer is set in the hole prior to perforating to
prevent reservoir fluids from contacting the casing. The well is flowed at pre-determined
rates and the flowing bottomhole pressure is recorded in a downhole memory guage.
More than one intervals can be tested in this manner.
After the flow test, a pressure build up test is conducted. The well is shut in and the
pressure is allowed to build back to the initial reservoir pressure. From the data collected,
reservoir permeability and skin factor can be obtained. Skin factor is a measure of the
damage done to the formation by drilling mud liquids and solids, which may plug the
pore throats of the reservoir rock, resulting in restriction to fluid flow in the reservoir.
Appraisal Wells
If sufficient hydrocarbon is encountered in a wildcat well, then appraisal wells will be
drilled. These appraisal wells are also known as delineation wells. He purpose of drilling
these wells is to define the hydrocarbon reservoir limits. This involves locating the
boundaries of the reservoir and determining it’s shape and size, determining rock
properties and reservoir fluid properties.
Appraisal wells are necessary to:
i) Gather sufficient information on which to base a decision as to whether there
is economic justification for proceeding with development of the hydrocarbon
reservoir.
ii) Provide additional data relative to the reservoir and it’s associated geologic
environment, so as to permit preparation of an effective reservoir development
plan, which can be used over the productive life of the reservoir.
86
RESERVOIR DEVELOPMENT PLAN
When the decision is made that sufficient information is available for acceptable
definition of the reservoir, and that reservoir development and production should proceed,
a development plan for the reservoir is prepared. This plan is designed to optimize
recovery of the hydrocarbon within anticipated economic and resource development
limits. This development plan will determine the reservoir production history and is
extremely elaborate and specific. A part of that plan will be the development well
spacing.
Development Wells
The function of development wells is to “effectively and efficiently recover maximum
hydrocarbon from the reservoir in a reasonable production lifetime, maximizing
economic return and resource recovery within necessary environmental limits.” These
development wells not only include producing oil and gas wells, but may also include gas
injection, water injections, and other types of service wells, to optimize the development
of the reservoir. Some wells which are to be used as producing wells for the first several
years may converted in injections wells later in the life of the reservoir, according to this
development plan.
Producing Wells
These are the wells specified in the development plans, for production of the hydrocarbon
to the surface. They may be oil production wells or gas production wells. The spacing of
these wells will be selected based on reservoir properties and economics. A common
spacing for oil reservoirs for onshore operations has been the 40 acre spacing. 1 mile =
5,280 ft. and 1 mile2 is equal to 640 acres of area. 1 acre = 43,560 ft2.
Consider the 1 mile2 area. If that 1 mile2 is divided into quarters, each quarter = 160
acres. If those quarters are further divided into quarters, the result will be 16 square area
of acres each (16 times 40 acres = 640 acres).
A 40 acre spacing for the drilling of development wells implies that one well will be
drilled in each 40 acres. The result will be 16 wells per 1 mile2. Each well, therefore, will
be ¼ mile or 1,320 ft from its offset wells and will have 4 offsets (north, south, east and
west). In the ideal production plan, over a reasonable lifetime of production, each well is
expected to drain a rock cylinder 660 ft in radius and of thickness equal to the
hydrocarbon reservoir rock thickness.
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Many other spacings are also used. For gas reservoirs, a common spacing has been a 160
acre spacing, or 4 producing gas wells per 1 mile2. It is desirable, if practical, that the
wildcat well and the appraisal wells be among the best producing wells.
Injection Wells
Injection wells are drilled to serve various functions, such as injection of external fluids
into the reservoir, including hydrocarbon (natural) gas, water, nitrogen, CO2, or others, to
enhance the recovery of the original hydrocarbons or to maintain reservoir fluid pressures
during the production life of the reservoir.
Injection wells may previously have been utilized as producing wells, but, in the
development plan for the reservoir, there was included the conversion of some producing
wells into injection wells at a particular time in the production life of the reservoir.
Injection wells may also be drilled to dispose of undesirable fluids, such as salt water,
that are produced to the surface along with the hydrocarbons. These would be considered
as salt water disposal wells, and the salt may be injected into reservoirs other than
hydrocarbon reservoirs. Excess solution gas, for which there is no market, may also be
injected into reservoirs other than those from which it was produced, to store that gas for
future production.
Reservoir Pressure Control
For those reservoirs which initially have reservoir fluid pressures greater than the bubble
point pressure of the hydrocarbons, it is usually desirable to maintain the flowing
bottomhole pressures of the producing wells above the bubble point pressure for a
considerable portion of the production life of the reservoir. It may be possible initially to
maintain this condition by proper selection of the choke size in the wellhead.
If the reservoir fluid pressure is sufficiently higher than the bubble point pressure of the
reservoir hydrocarbons for the well depth and hydrocarbon density, then, within fluid
property limits, the flowing bottomhole pressures can be maintained above the bubble
point pressure by manipulating the production choke size in the wellhead. This indicates,
therefore, that the reservoir pressures in the producing region surrounding the wellbore
will also be maintained above the bubble point pressure, that there will only be liquid
hydrocarbons in the reservoir and that only liquids will be produced into the wellbore at
flowing bottomhole conditions. This is normally desirable in the early production history
of a reservoir.
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As produced fluid returns to the surface, however, it may reach its bubble point pressure,
so that both gas and liquid may exist at the wellhead. As the natural reservoir fluid
pressure reduces as hydrocarbons are produced, it may be necessary to inject external
fluids into the reservoir to maintain reservoir pressure. Oil production is a volume
displacement process. Idealistically, basing volumes on reservoir conditions, if, for each
reservoir barrel of oil produced, a reservoir barrel of water is injected beneath the oil zone
into the water zone, reservoir fluid pressure should maintained.
As the reservoir nears the end of its productive life, however, it will finally be desirable
to lower the flowing bottomhole pressure, through a controlled procedure, to se low a
pressure value as is feasible, to recover the maximum volumes of remaining oil and gas
(including solution gas) from the reservoir before it is depleted, as determined by
economics, and therefore abandoned,
Gas injection into a natural gas cap, which might exist above the oil zone, could also be
used for pressure maintenance. If the initial reservoir fluid pressure is greater than the
bubble point pressure of the reservoir hydrocarbons, a gas cap might created by gas
injections, even though one did not exist under original natural conditions within the
reservoir. For example, for reservoir where increased water saturations have a significant
adverse effect on permeability to the flow of oil, this gas injection process for pressure
maintenance could be initiated very early, or at the beginning of the productive life of the
reservoir.
Observation Wells
Wells may also be drilled for the purpose of monitoring the reservoir development plan
during the productive life of the reservoir. The wells are equipped with pressure
monitoring systems, to determine the extent of propagation of the pressure transient from
the producing wells into the reservoir. The observation wells may also be used to monitor
encroachment of the gas-oil interface or the oil-water contact into the oil zone, as well as
progress of injected fluids such as the water front, during enhanced oil recovery by
waterflood. These wells may also be converted for functions other than observation, such
as production or injection later in the productive life of the reservoir.
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THE DRILLING PROCESS
After choosing a prospect location, based on the geophysical and geological mapping and
interpretation, the site is surveyed to determine its boundaries, and environmental impact
studies may be done. Lease agreements, titles and right-of way accesses for the land must
be obtained and evaluated legally. For offshore sites, legal jurisdiction must be
determined.
Figure 45 – Offshore Jack-up Rig
Once the legal issues have been settled, the crew goes about preparing the land:
1. The land is cleared and leveled, and access roads may be built.
2. Because water is used in drilling, there must be a source of water nearby. If there
is no natural source, they drill a water well.
3. They dig a reserve pit, which is used to dispose of rock cuttings and drilling mud
during the drilling process, and line it with plastic to protect the environment. If
the site is an ecologically sensitive area, such as a marsh or wilderness, then the
cuttings and mud must be disposed offsite -- trucked away instead of placed in a
pit.
Once the land has been prepared, several holes must be dug to make way for the rig and
the main hole. A rectangular pit, called a cellar, is dug around the location of the actual
drilling hole. The cellar provides a work space around the hole, for the workers and
drilling accessories. The crew then begins drilling the main hole, often with a small drill
truck rather than the main rig. The first part of the hole is larger and shallower than the
main portion, and is lined with a large-diameter conductor pipe. Additional holes are dug
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off to the side to temporarily store equipment -- when these holes are finished, the rig
equipment can be brought in and set up.
Rigging up
Depending upon the remoteness of the drill site and its access, equipment may be
transported to the site by truck, helicopter or barge. Some rigs are built on ships or barges
for work on inland water where there is no foundation to support a rig (as in marshes or
lakes). Once the equipment is at the site, the rig is set up. Here are the major systems of a
land oil rig:
Figure 45 – Anatomy of an oil rig
• Power system
 large diesel engines burn diesel fuel to provide the main source of power
 electrical generators are powered by the diesel engines to provide
electrical power
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• Mechanical system - driven by electric motors
 hoisting system - used for lifting heavy loads; consists of a mechanical
winch (drawworks) with a large steel cable spool, a block and tach\kle
pulley and a receiving storage reel for the cable
 turntable - part of the drilling apparatus
• Rotating equipment - used for rotary drilling
 swivel - large handle that holds the weight of the drill string; allows the
string to rotate and makes a pressure-tight seal on the hole
 kelly - four- or six-sided pipe that transfers rotary motion to the turntable
and drill string
 turntable or rotary table - drives the rotating motion using power from
electric motors
 drill string - consists of drill pipe (connected sections of about 30 ft / 10
m) and drill collars (larger diameter, heavier pipe that fits around the drill
pipe and places weight on the drill bit)
 drill bit(s) - end of the drill that actually cuts up the rock; comes in many
shapes and materials (tungsten carbide
steel, diamond) that are specialized for
various drilling tasks and rock formations
• Casing - large-diameter concrete pipe that lines the
drill hole, prevents the hole from collapsing, and
allows drilling mud to circulate
• Mud Circulation system - pumps drilling mud
(mixture of water, clay, weighting material and
chemicals, used to lift rock cuttings from the drill
bit to the surface) under pressure through the kelly,
rotary table, drill pipes and drill collars
 pump - sucks mud from the mud pits and
pumps it to the drilling apparatus
 pipes and hoses - connects pump to drilling
apparatus
 mud-return line - returns mud from hole
 shale shaker - shaker/sieve that separates rock cuttings from the mud
 shale slide - conveys cuttings to the reserve pit
 reserve pit - collects rock cuttings separated from the mud
 mud pits - where drilling mud is mixed and recycled
 mud-mixing hopper - where new mud is mixed and then sent to the mud
pits
Figure 46
Mud circulation in the hole
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Figure 47 - Drill-mud circulation system
Drilling mud is used to:
• lift soil/rock cuttings from the bottom of the borehole and carry them to a settling
pit;
• allow cuttings to drop out in the mud pit so that they are not re-circulated
(influenced by mud thickness, flow rate in the settling pits and shape/size of the
pits);
• prevent cuttings from rapidly settling while another length of drill pipe is being
added (if cuttings drop too fast, they can build-up on top of the bit and seize it in
the hole);
• create a film of small particles on the borehole wall to prevent caving and to
ensure that the upward-flowing stream of drilling fluid does not erode the adjacent
formation;
• seal the borehole wall to reduce fluid loss (minimizing volumes of drilling fluid is
especially important in dry areas where water must be carried from far away);
• cool and clean the drill bit; and lubricate the bit, bearings, mud pump and drill
pipe
• Derrick - support structure that holds the drilling apparatus; tall enough to allow
new sections of drill pipe to be added to the drilling apparatus as drilling
progresses
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Blowout prevention
A blowout occurs when there is loss of control of downhole reservoir fluid pressures.,
when the hydrostatic pressure due to the column of mud in the hole is less than the
reservoir pressure. When a higher than normal reservoir pressure is drilled into, it may be
necessary to activate the blowout prevention system (BOP stack) to provide time to kill
the well. The BOP stack is usually a combination of different types of blowout
preventers.
• Blowout preventer - high-pressure valves (located under the land rig or on the sea
floor) that seal the high-pressure drill lines and relieve pressure when necessary to
prevent a blowout (uncontrolled gush of gas or oil to the surface, often associated
with fire)
The BOP stack is usually located below the rotary table. A typical BOP stack consists of
three (3) blowout preventers is shown below:
i) Annular Preventer (top)
ii) Blind Rams (middle)
iii) Pipe Rams (bottom)
Drilling
The crew sets up the rig and starts the drilling operations. First, from the starter hole, they
drill a surface hole down to a pre-set depth, which is somewhere above where they think
the oil trap is located. There are five basic steps to drilling the surface hole:
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Mud Return
Annular
Preventor
Blind
Rams
Pipe
Rams
1. Place the drill bit, collar and drill pipe in the hole.
2. Attach the kelly and turntable and begin drilling.
3. As drilling progresses, circulate mud through the
pipe and out of the bit to float the rock cuttings
out of the hole.
4. Add new sections (joints) of drill pipes as the
hole gets deeper.
5. Remove (trip out) the drill pipe, collar and bit
when the pre-set depth (anywhere from a few
hundred to a couple-thousand feet) is reached.
Once they reach the pre-set depth, they must run and
cement the casing -- place casing-pipe sections into the
hole to prevent it from collapsing in on itself. The casing
pipe has spacers around the outside to keep it centered in
the hole.
The casing crew puts the casing pipe in the hole. The
cement crew pumps cement down the casing pipe using a
bottom plug, a cement slurry, a top plug and drill mud. The pressure from the drill mud
causes the cement slurry to move through the casing and fill the space between the
outside of the casing and the hole. Finally, the cement is allowed to harden and then
tested for such properties as hardness, alignment and a proper seal.
Drilling continues in stages: They drill, then run and cement new casings, then drill again.
When the rock cuttings from the mud reveal the oil sand from the reservoir rock, they
may have reached the final depth. At this point, they remove the drilling apparatus from
the hole and perform several tests to confirm this finding:
• Well logging - lowering electrical and gas sensors into the hole to take
measurements of the rock formations there
• Drill-stem testing - lowering a device into the hole to measure the pressures,
which will reveal whether reservoir rock has been reached
• Core samples - taking samples of rock to look for characteristics of reservoir rock
Once they have reached the final depth, the crew completes the well to allow oil to flow
into the casing in a controlled manner. First, they lower a perforating gun into the well to
the production depth. The gun has explosive charges to create holes in the casing through
which oil can flow.
After the casing has been perforated, they run a small-diameter pipe (tubing) into the hole
as a conduit for oil and gas to flow up the well. A device called a packer is run down the
outside of the tubing. When the packer is set at the production level, it is expanded to
form a seal around the outside of the tubing.
Figure 48.
Drill Floor workers trip drill
pipe
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Finally, they connect a multi-valved structure called a Christmas tree to the top of the
tubing and cement it to the top of the casing. The Christmas tree allows them to control
the flow of oil from the well.
Once the well is completed, they must start the flow of oil into the well. For limestone
reservoir rock, acid is pumped down the well and out the perforations. The acid dissolves
channels in the limestone that lead oil into the well. For sandstone reservoir rock, a
specially blended fluid containing proppants (sand, walnut shells, aluminum pellets) is
pumped down the well and out the perforations. The pressure from this fluid makes small
fractures in the sandstone that allow oil to flow into the well, while the proppants hold
these fractures open. Once the oil is flowing, the oil rig is removed from the site and
production equipment is set up to extract the oil from the well.
Well Completion
If the evaluation of the well logs indicates a potential zone to be completed, ie potential
hydrocarbon bearing zone present, the well must be completed. This will enable the well
to produce hydrocarbons to the surface, until the reservoir is depleted. The first and
critical step is to run and cement casing in the hole.
The main reasons fore running and cementing casing in the open hole is to:
1. Prevent caving of the hole.
2. Confine production to the wellbore
3. Prevent contamination of fresh water sands, particularly in the surface
hole.
4. Facilitate installation of surface equipment
5. Facilitate installation of downhole equipment
6. Provide means of controlling pressure
7. Exclude water from producing formation
Casing String and Design Factors
The casing is the steel pipe which is run to different depths in the well. This depth at
which the casing is set is the casing point. A casing string is casing that is run from it’s
casing point back to the surface or to the seafloor in offshore wells. A casing liner is
casing that is run from it’s casing depth back to a casing liner hanger downhole inside a
previously run and cemented casing string or liner.
The following are considered when selecting a casing to be run:
i) Axial load in tension
ii) Axial load in compression
iii) Burst as a thin walled cylinder (due to internal pressure)
iv) Collapse as a thin walled cylinder (due to external pressure)
v) Corrosion
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vi) Abrasion
Figure 49 - Typical casing and hole sizes.
There are four typical types of casing that may be run in a well:
i) Conductor pipe
ii) Surface string
iii) Intermediate string or liner
iv) Production string or liner
Conductor Pipe
The conductor pipe may also be called drive pipe for offshore wells since it may be
driven in to the seafloor with a pile driver. One function of the conductor pipe is to
support the wellbore through the unconsolidated materials present in the surface ho,e
such as dirt, gravel, clay, sand, rock boulders, silt and sediment. It is therefore desirable
to set the conductor pipe either on solid rock or into solid rock. A second function of the
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17 1/2 " hole
1 3 3/8" casing
12 1/4" hole
casing liner hanger
9 5/8" casing
8 1/2" hole
7" casing liner
conductor is to protect the wellbore near the surface from washout, which may result
from circulation of the drilling mud from the lower section of the wellbore, and therefore
to restrict the well diameter at the surface to the ID of the conductor.
The Surface String
The surface string serves a primary function of protecting the surface environment from
contamination from downhole fluids such as hydrocarbons and drilling mud. This
environmental protection requirement makes the cementing of the surface casing to the
surface necessary. Once the surface string is run, a bolt flange connection is welded to the
top of the casing to which the BOP stack will be attached. The combination of the casing
head and BOP stack will protect against blowout during further drilling operations. It is
important that the surface string be set at sufficient depth within solid rock to provide
protection against downhole pressures.
Intermediate String
A primary function of intermediate strings or liners is to seal off zones of high fluid
pressures. The determining factor for this casing point will be to drill through an
impermeable rock formation below the high pressure reservoir, thereby permitting further
drilling with a less dense drilling mud. A second function of intermediate strings or liners
is to seal off zones of lost circulation, which can occur when drilling a low pressure
reservoir. Another function of intermediate strings or liners is to seal off zones of
wellbore washout in unconsolidated sandstones or mobile shales.
The Production String
The production string or liner is that casing through which the reservoir fluid will be
produced. This casing is run all the way through the reservoir and set some depth below
it. The casing depth is therefore dependent on the depth of the bottom of the reservoir and
the amount of rathole required for that particular well.
It is usually desirable to produce hydrocarbons through production tubing rather than
through the production casing in order to minimize exposure to possible corrosion from
the reservoir fluids. The production casing may also serve the functions of sealing off
high pressure zones, zones of lost circulation, and zones of potential wellbore washout.
Production Choke
The production choke can be used to control the production flow rate of the well and
hence the drawdown. The drawdown is the difference between the reservoir pressure and
the flowing bottomhole pressure. This is very important in preventing sand entry into the
wellbore. If the drawdown is too high, the cohesive forces due to the cementing material
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between the sand grains within the rock can be exceeded. This will result in sand grains
becoming loose and flowing into the wellbore. This can result in plugged tubing, washed
out choke and plugged flowline.
The choke could be either adjustable or fixed choke (with a bean inserted). Adjustment of
the choke and hence the flow rate can maintain a bottomhole pressure above the bubble
point, preventing the breakout of gas out of solution at the bottom of the well. This
guarantees only liquids flowing into the well.
Factors affecting Production:
i) Reservoir Fluid Pressure
ii) Reservoir Fluid Temperature
iii) Formation Volume Factor
iv) Bubble Point Pressure
v) Reservoir Fluid Saturations
vi) Solution Gas Oil ratio
vii) Reservoir Fluid Viscosity
viii) Reservoir Fluid Compressibility
ix) Porosity
x) Permeability
xi) Well Depth
xii) Flow area variations
xiii) Perforation size, penetration and density
xiv) Choke size
xv) Flowing Bottomhole Pressure
xvi) Production history of the reservoir
xvii) Skin Factor
Running the casing
A casing guide shoe is attached to one end of one joint of the casing. The joint of casing
is the brought to the rig floor and is suspended from the hoisting system in the derrick.,
with the guide shoe on the lower end. The guide shoe will allow the casing to be lowered
in unconsolidated formations where there will be ledges in the well. The guide shoe will
guide the casing past these ledges, to keep it from hanging up. The guide shoe also
protects the end of the casing from damage while it is being run into the wellbore.
The first joint of casing is now run into the wellbore and a float collar is attached to the
top of that joint. Within this float collar is a one-way check valve. This valve prevents
flow from occurring up through the inside of the casing, but permits flow down through
the casing.
Once the float collar has been connected, joints of the casing are addad as the casing is
lowered into the wellbore. The inside of the casing is filled with drilling mud to prevent
the casing from floating out of the well due to buoyancy. During the running of the
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casing, centralizes and scratchers are placed at pre-determined intervals along the outside
of the casing string. The functions of these centralizes are to centralize the casing in the
center of the wellbore. Scratchers have spring steel teeth, which scratch through the
bentonite the bentonite wall cake on the wall of the wellbore, to provide a better cement
bond with the rock formations.
Primary Cementing
A cementing head (plug container) is attached to the top of the casing string. Within this
cementing head will be the bottom plug and the top plug. The diameter of these plugs wil
be slightly less than the casing ID. The mud is conditioned prior to cementing, by
reciprocating the casing vertically with the hoisting system; ideally a distance at least
equal to the spacing between centralizes and scratchers, as mud is circulated down th
inside of the casing, thereby opening the check valve in the float collar and returning up
the annulus. This procedure will break the gel in the annulus. Any rock particles present
in the annulus will be carried to surface because of the reciprocation and circulation as
the well is prepared for cementing.
The bottom plug is now dropped on top of the mud column in the casing, and the
calculated volume of cement is pumped into the casing behind this plug. This bottom
plug separates the drilling mud from the cement, thereby minimizing contamination of
the cement by the mud as the wipers remove the mud from the wall of the casing in front
of the cement.
When the calculated volume of cement has been pumped into the casing, the top plug is
dropped on the cement column. Once the bottom plug reaches the internal shoulder at the
top of the float collar, flow will be stopped when that plug seats on the shoulder, since
flow is blocked by the plug. The result is a pressure increase , which will rupture a
diaphragm within the bottom plug. When the diaphragm ruptures, it will be known at the
surface, since the pressure will drop and flow will resume. Pumping will continue until
top plug seats on the remains of the bottom plug. When this occurs, flow again will stop
and pressure will rise, indicating that the top plug has reached a position on top of the
remains of the bottom plug.
The casing is reciprocated throughout the entire pumping process in order to break the gel
in the annulus and permit the cement to distribute itself around the casing. When the top
plug seats the system is shut down to provide the pre-determined time for the cement to
set. Once the cement has set, further drilling can now proceed.
The bit size for the next hole is attached to the bottom of the drill string and tripped into
the hole and drilling is resumed. The top and bottom drillable plugs are then drilled out
along with the float collar. The bottom joint of casing filled with set cement along with
the guide shoe are now drilled out. Drilling now proceeds to the next casing point.
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Squeeze Cementing
Squeeze cementing is selective cementing downhole, within the casing. This technique
might be used to seal off casing leaks caused by corrosion or to repair channels that occur
behind the casing during primary cementing. A drillable plug is placed in the casing
below the point where the squeeze cementing is to occur. Tubing with a packer is then
run into the wellbore, and the packer is set in the casing above the point at which the
squeeze cementing is to occur. Cement is the pumped under pressure through the pipe
and squeezed into intervals perforated for this purpose, or theough the leaks, to seal the
annulus and therefore the leak at that location. After the cement has set the packer is
released and the tubing is retrieved to the surface. It is then necessary to drill out the set
cement remaining in the casing, and the plug set in the casing below the cement.
WELL COMPLETION
There are three basic types of well completion:
1. Conventional Single zone Completion
2. Conventional Multiple zone Completion
3. Tubingless Completion
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Conventional Single Zone Completion
Open Hole Completion
This is the simplest of all completion types, where casing is run and cemented just above
the producing zone. The pay section is drilled with a non-damaging fluid.
Open hole completions can be barefoot, where tubing is run and a packer is set in the
casing above the open hole the well put on production. Another option is to run a gravel
pack liner or screen and gravel pack the open interval. This is known as an Open Hole
Gravel Pack completion. The open hole can also be widened using an under-reamer and
then gravel packed. Productivity of open hole gravel packs is higher than the cased hole
gravel packs because the hydrocarbon flows into a larger tube.
Some features of open hole gravel pack completions:
i) It is run in consolidated sandstone or carbonate reservoirs
ii) Perforating expense is eliminated
iii) It provides good sand control
iv) The entire pay section is produced
v) It can easily be converted to cased hole completion
vi) It is difficult to selectively stimulate using acid or fracturing
vii) The casing is set “in the dark” before the pay section is drilled
viii) It is difficult to eliminate water or gas production
Single Zone Cased Hole Completion
In this completion, casing is run and cemented to the bottom of the pay zone. In some
cases the well is drilled and cased beyond the pay zone, leaving a “rat hole” below the
perforated zone. The size of the casing is determined based on the expected rate of
production of the well. The thickness of the casing is determined based on both the
external and the internal pressures the casing must withstand. These are called collapse
and burst pressures. Single zone cased hole completions may be with gravel packed
screens or liners for sand control.
Some features of open hole gravel pack completions:
i) It is easier to selectively stimulate using acid or fracturing
ii) Different intervals can be stimulated selectively
iii) Multiple completion is possible
iv) The well can be easily deepened
v) Perforating cost can be high
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vi) Various sand control techniques can be utilized
Conventional Multiple Completion
Conventional Multiple Completion is utilized when there are two zones in a well that
contain significantly different reservoir pressures. If both are produced together and
allowed to mix, some production from the higher pressure zone will preferably flow into
the lower pressure zone, especially when the well is shut in. Thus it is necessary to isolate
production from both zones.
This is achieved by placing a dual packer between both zones and allowing flow up two
different tubing strings (see diagram).
Figure 50 – Dual Completion.
Tubingless Completion
In this type of completion the casing is small and no inner tubing is run in the hole.
Tubingless completions can be single zone or multiple zone. The zones are perforated
using “orienting guns” which utilize magnetism to orient the guns away from the other
casing strings in the hole, while perforating the selected zone.
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17 1/2 " hole
13 3/8" casing
12 1/4" hole
casing liner hanger
9 5/8" casing
high pressure zone high pressure zone
low pressure zone low pressure zone
7" casing liner
DUAL COMPLETION
Tubing
Tubing is set inside the casing to transmit fluids from downhole to surface, with minimal
pressure drop. Another factor is gas expansion in the tubing, which assists in the lifting of
the liquids to the surface. To achieve this, tubing is usually small in diameter e.g 2 3/8”,
2 7/8”, 3 ½”. In choosing the optimum size of tubing the following is considered:
i) The desired flow rate
ii) Gas and liquid ratio for liquid loading in the tubing
iii) Possible artificial lift method to be employed.
iv) Special requirements for completion e.g. sand control
Packers
Packers are set in the wellbore to provide a seal between the tubing and casing.They also
serve an anchors/hangers for the production tubing.A packer may be classified by the way
it is set: hydraulic or mechanical set, by the way it is run: wireline or tubing, or by
whether permanent or temporary.
Packers are run for:
i) Casing protection from pressure or fluid in the tubing
ii) Separation of zones
iii) Subsurface pressure and fluid control for safety
iv) Artificial lift support equipment
Wellheads
Wellheads are the connection points for the tubing and the surface flow lines as well as
being the surface control point in all wells. The selection of the wellhead is based on the
pressure, temperature and corrosivity of the produced fluids. Both the casing and tubing
strings are landed in the wellhead. The casing also acts as a conduit allowing for all types
of workover operations. Wellheads plays a major role in preventing oncontrolled flow
from downhole, through it’s configuration of valves.
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A SECTION
Casing head 13 5/8" 5M X l3 3/8" SOW w/2 1/16" 5M F.O. & 6" L.P. w/hold down
screws; Valve WKM 2 1/16" 5M RJ MM T-21; 2 Flanges threaded 2 1/16" 5M X 2"
LP; l-Bull Plug 2" LP plain; 1-Bull Plug 2" LP X 1/2" NPT.
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B SECTION
2. AP Flange Packoff TS-5 13 5/8" 5M X 11" 10M W/9 5/8" "P" Seals.
3. AP Casing Spool 11" 10M X 11" 15M "SF" w/1 13/16" 15H F.O. and
hold down screws for wear bushing and 2-9 5/8" 'P" seals RC-22
w/K-Monel Hd. Screws.
4. Valve WKH 1 13/16" 15M 6BX MM T-22 w/test flange 1 13/16" 15N X 1 1/8"
autoclave.
5. Valve WKM 1 13/16" 15M 6BX MM T-22 w/weld neck flange,
C SECTION
6. Tubing head 11" 15M X 7 1/16" 20M w/1 13/16' 20M outlets.
RC22 W/K-Monel hold down Screws,
7. Valve - WKM 1 13/16" 20M 6BX MN T-26 w/test flange 1 13/16" 20M X 1 1/8"
S.S.
8. Valve - WKM 1 13/16" 20M 6BX MN T-26 w/weld neck flange.
UPPER SECTION
9. AP Flange Adp. Spool 7 1/16r X 2 9/16" 20H w/"P'" seals to accept metal to metal
hanger S.S., and UEMM Tbg. Hanger w/metal to metal seals; Nom. 6" X 3 1/2" 15.80#
PH6 CB L X S 2 1/2" BPV 17.4 PH S.S.
10. Valve WKM 2 9/16" 20M 6BX MM T-26.
11. AP Cross Stud. 2 9/16" 20M Run X 1 13/16" 20M out. S.S,
12. AP Top Adapter 2 9/16" 20M S,S. w/2 7/8" Lift Threads. BP Tapped 1 1/8" 12 NF,
13. Valve WKM 1 13/16" 2OM 6OX MM T-25.
14. Valve WKM 1 13/16- 20M T-26 w/.s-600 actuator and bonnet kit,
15. Pos. Choke - T[[C 1 13/16" 20M FXF S.S, w/weld neck 1 13/16" 20M RC22 flange,
16. Adj. Choke - THC 1 13/16- 2OM FXF S.S. w/weld neck I 13/16" 20M RC22 flange.
106
Perforating
Perforations are hole through casing to permit entry of fluids. The perforations must be
placed opposite the productive zones and are designed to penetrate both the casing and
the cement placed behind it, thus allowing communication between the permeable part of
the reservoir and the borehole.
The “shaped charge” or “jet charge” is the most commonly used perforating technique
used today. This mechanism produces a hole in the casing by propagating a pressure
wave front from the surface of the metal liner in the charge, through the port or scalloped
wall of the gun and then through the casing and cement into the formation. The metal
liner of the charge deforms under high pressure and provides mass, which makes the
charge more efficient.
In order to achieve this, a chain reaction is triggered from an electrically-fired detonator,
which detonated the primacord, booster charge and the main charge. Usually four (4) one
half inch (1/ inch) diameter holes per foot are required, except in gravel packing
operations where 4 to 8 three-quarter inch (3/4 inch) holes are shot. The higher density
larger holes accommodate transport of gravel through the perforations with less pressure
drop across them.
The three (3) typical perforating guns used for perforating wells are: casing, through
tubing and tubing conveyed guns.
Casing Gun Perforating
The casing guns are hollow steel carrier guns run on wireline. This gun is run without the
tubing in the hole and requires a wireline lubricator connected on top of a shooting valve.
The tubing is run after the guns are fired and retrieved from the borehole. An electric
current, sent down the wireline to a detonator, fires the guns.
This type of gun is used for overbalance perforating. “Overbalance” occurs when the
hydrostatic head, due to the density and weight of the perforating fluid, is greater than the
reservoir pressure. Casing gun perforating is cheaper than the other two types and is used
for low pressure, low rate wells.
Through tubing perforating
The through tubing guns contain charges that are screwed into a thin metal strip that can
pass through the tubing. The tubing is run in the hole , packer set and well head installed.
A wireline lubricator is installed on top of the wellhead. A grease injector head is installed
on the lubricator since this type of perforating can withstand some pressure from the well.
The firing mechanism is the same as casing gun perforating.
Multiple runs have to be made since the length of the perforating gun, and hence the
number of charges per run, are restricted by the length of the lubricator. The advantage
107
of this type of perforating is that the well can be flowed as soon as the last run is
completed, and it is not as expensive as tubing conveyed perforating.
Tubing Conveyed Perforating
Tubing Conveyed Perforating or TCP as it is more popularly known is the most
expensive of the three and is used for high production rate wells. The perforating guns
are run on hollow steel and attached at the end of the tubing. The tubing is run in the
hole, packer set and wellhead installed. The guns are fired either by tubing pressure or by
dropping a steel bar in the tubing, which sets off the detonator on impact. Sometimes,
especially in deep wells, the drop bar method is utilized as a back-up mechanism.
This type of perforating is done underbalance (the hydrostatic head is less than the
reservoir pressure). This results in gun debris being flowed back immediately upon
perforating as the wellhead sees an immediate pressure and the well can be produced and
cleaned up immediately.
108
PRODUCTION EQUATIONS
The following is a simplification of procedures for predicting well performance. This
discussion assumes a flow efficiency of one. A damaged well or other factors will effect
the flow efficiency and could change the well's productivity.
Productivity Index
When the well flowing pressure (Pwf) is greater than bubble -point pressure (Pb), the fluid
flow is similar to single phase flow, and the inflow performance curve is a straight line
with slope J, as given by the productivity index, PI:
Where:
Q = the fluid test production rate. Pwf = the well flowing pressure @ test rate .
= the well static pressure.
Figure 57
109
Inflow Performance Relationship
If is less than , resulting in multi-phase flow, the IPR method should be used. The
relationship is given by the following equation:
This relationship was first used by W.E. Gilbert1 and further developed by J.V. Vogel2.
Vogel developed a dimensionless reference curve that can be used to determine the IPR
curve for a particular well.
Formation Damage and skin factor
Wellbore damage occurs when filtrate (liquid) or solids from drilling mud or completion
fluids interact or plug the formation near the wellbore. Water in the filtrate can swell the
clays or fines from the solids can plug the pore throats. Both result in a reduction in the
size of the flow channels and hence a reduction in the near wellbore permeability. This is
referred to as skin damage. The skin factor is a numerical representation of skin damage.
The additional pressure drop in the near wellbore due to skin is called Δpskin.
Flow Efficiency
The Vogel equation was modified by Standing, who represented the Vogel Equation as
the situation when the Skin Factor is zero. The flow efficiency can be estimated as:
Where s is the skin factor.
If the skin factor is positive (s>0), then the Flow Efficiency is less than 1 indicating that
the well is damaged. If the skin factor is negative (s<0), then the Flow Efficiency is
greater than 1 indicating that well is stimulated.
110
7
7 + s
F.E =
For the well represented in the graph above, the unstimulated well will produce at a rate
of approx. 1,750 bopd for a flowing bottomhole pressure of 1,000 psia, while the
production rate for the same flowing bottomhole pressure will be approx. 2,400 bopd, an
increase of 650 bopd.
Darcy Equation for Radial Flow
Previously we looked at the Darcy Equation for linear flow for incompressible fluids.
However, radial flow exists in a reservoir (flow from all directions in a radial pattern as
shown below).
Plan View of a wellbore, depicting radial flow
111
Wellbore
IPR Standing
0
500
1 000
1 500
2000
2500
3000
3500
4000
4500
0.0 500.0 1000.0 1500.0 2000.0 2500.0 3000.0
Q
Pwf
Stimulated well
IPR Curve
FE > 0
Darcy developed an equation for radial flow, which estimates the radial fluid flow
thropugh porous media:
7.08 x 10-3 k h (P - Pwf)
µoB o( ln(0.472 re/rw) + s )
where:
qo = Oil flow rate, (STD/day)
h = Reservoir Rock Thiockness, (ft)
P = Initial reservoir Pressure, (psia)
Pwf = Flowing Bottomhole Pressure, (psia) µo = Oil Dynamic Viscosity, (Centipoise)
Bo = Oil Formation Volume Factor, (RB/STB)
re = Radius of the boundary (limit of reservoir), (ft)
rw = Wellbore Radius, (ft)
s = Skin Factor
From the above equation, we can see that a positive skin factor (s>0) will result in a
reduction in the well’s oil rate, while a negative skin factor rill result in an increased flow
rate in the well. This forms the basis for well stimulation.
112
qo =
ARTIFICIAL LIFT
In most fields, the new wells flow under it’s natural pressure until such time that the
reservoir pressure is reduced to the point that the well can no longer flow under it’s
natural pressure. The well now becomes a prime candidate for artificial lift.
There are various artificial lift mechanisms such as: gas lift, plunger lift, downhole
electric or hydraulic pump, and rod pump. The selection of artificial lift depends on type
of hydrocarbons, flow rate and the reservoir pressure. The design of lift systems also
depends on the economics of the project.
Artificial lift is simply a method of adding energy to lift liquid to the surface of a well,
and can be accomplished by any of the following means:
1. Gas Lift
a) Continuous gas lift system
b) Intermittent gas lift system
c) Plunger lift system
2. Beam pumping or sucker rod pumping
3. Electric submersible pumping
4. Progressive cavity or screw type pumps particularly for heavy oil operations
5. Various special techniques e.g. hydraulic pumps, jet pumps etc.
Gas Lift
Gas lift systems can be used to effectively produce wells ranging
from low productivity to high productivity. Gas lift systems are
selected for artificial lift if a low cost, high pressure gas source is
readily available.
In flowing wells, gas is produced along with the liquids. The gas
comes out of solution and expands as the pressure is reduced as it
flows up the tubing. The expanding gas assists in lightening the
column of fluid, resulting in more inflow from the reservoir and also
helps push the fluids out of the well.
In gas lift operations, high pressure gas is injected down the casing
and enters the tubing at the bottom of the well through a pressurerated gas lift valve. As the gas rises the bubbles expand, increasing
the velocity of the fluid and decreasing it’s density just as in flowing
wells. Figure 51 – Gas Lifting
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The applications of gas lift are:
i) To enable wells that will not flow naturally to produce
ii) To increase production rate in flowing wells
iii) To unload a well that will later flow naturally
iv) To remove or unload fluids from gas wellsand keep the gas wells unloaded
(usually intermittent gas lift)
Continuous Gas lift
Under continuous gas lift, high pressure gas enters the tubing through gas lift valves
continuously, maintaining a constant flowing bottomhole pressure. This action reduces
the fluid gradient in the tubing and the well performs very similar to a natural flowing
well. The gas lift valves can be either loaded or pressure balance release valves. The two
different types of gas lift valves used in the industry are differential valves and bellows or
charged valves.
The differential valves are normally open and when the pressure in the annulus is high
enough, the valve closes. As the pressure in the tubing is less than the injected gas, the
valve will not reopen until the tubing pressure has risen due to liquid loading or the
injection pressure has decreased.
The bellows pressure in the pressure charged bellows valve closes the valve. The valve
opens when the annulus gas pressure acting on the area below the bellows plus the tubing
pressure is greater than the bellows pressure. The valves are arranged in a string down the
tubing with the bellows-pressure charge being less as the valve location is deeper,
allowing the deeper valve to stay open when the valve above is closed.
Intermittent Gas Lift
Intermittent gas lift is used on wells that have low volumes of produced fluids.
Intermitting is usually done using surface equipment. The gas lift supply is shut down for
a predetermined period of time, allowing fluid inflow from the reservoir. The injection
takes place again, removing fluids from the wellbore and then the next cycle begins.
Some features of gas lift
i) Simple operation
ii) Very flexible – one gas lift design can handle a variety of changing well
conditions
iii) Relatively low cost – both capital and operating
iv) Can be used in directional wells
114
v) Must have a high pressure gas supply
vi) Would not work on low API gravity crudes due to high specific gravity of the
oil
vii) Requires a compressor, to recompress the gas for further gas lift use
Plunger Lift
Plunger lifting is an economical artificial lift alternative, especially in high gas oil ratio
wells. A plunger is a “pipeline pig” that runs vertically in a well to remove liquids from a
wellbore after the well is unable to produce fluids on it’s own drive mechanism.
A plunger cycle consists of three stages:
Shut-in: A producing well is shut in to build casing pressure. This is needed to
build the pressure to lift the plunger with the liquid column on top of the plunger.
Unloading: The tubing is opened, and stored casing pressure lifts the liquid column
and plunger to the surface.
Afterflow: The well is allowed to flow while the plunger is at surface. During the
afterflow period, the well keeps producing gas and fluids until the next shut-in period. At
the end of the afterflow period, the well is shut in and the plunger falls.
Plunger lift is used mainly in:
- High producing GOR wells
- Wells where scale, paraffins, wax foul up the tubing
- Gas wells that require liquid unloading
- Reducing liquid fall back (used along with intermittent gas lift)
Advantages of plunger lift
i) Low maintenance cost
ii) Increases the well’s own lifting efficiency
iii) Easy installation
iv) Reduces paraffin or hot oil expense for cleaning the deposits in the tubing as
the moving plunger keeps the tubing clean
v) No external energy is required except for low gas oil ratio wells
vi) Slows well decline and extends well life
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Beam Pumping
Figure 52 – Rod Pump
Beam Pumping is the most widely accepted artificial lift method. It utilizes a mechanical
linkage to actuate a piston type bottomhole pump. The beam pump (or rod pump) is a
plunger with a two valve arrangement. The standing valve is a one way valve in the
bottom of the pump, which allows flow from the wellbore to the pump but stops reverse
flow. The traveling valve is another one way valve that is attached to the rod string.
As the plunger is lifted by the rod on the upstroke, the traveling valve is closed, forming a
low pressure area beneath the plunger and drawing in reservoir fluid through the standing
valve into the wellbore chamber.
At the end of the upstroke, the downstroke begins. When the bottom of the plunger
(which contains the traveling valve) hits the surface of the liquid that has flowed into the
pump, the traveling valve is forced open as the valve moves through the liquid and the
standing valve is closed. The downstroke of the plunger forces the liquid in the pump up
through the traveling valve, adding it to the tubing. The new fluid pushes all other fluid in
the tubing up by the volume of the liquid in the pump.
The most difficult task in beam pumping is keeping the rod string in operation without
high maintenance costs, frequent servicing and excessive downtime. Problems associated
with sucker rods result from:
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i) Corrosion
ii) Carelessness in handling
iii) High pumping speeds
iv) Wide range of loads
v) Crooked hole
vi) Poor selection and string design
Sucker rod pumping is controlled by variable frequency drive and timer mechanism at the
surface.
Electric Submersible Pump
A submersible pump is a pump which has a hermetically sealed motor close-coupled to
the pump body. The whole assembly is submerged in the fluid to be pumped. The
advantage of this type of pump is that it can provide a significant lifting force as it does
not rely on external air pressure to lift the fluid.
Figure 53 – ESP
ESP systems are effective for pumping produced fluids to surface. A system of
mechanical seals are used to prevent the fluid being pumped entering the motor and
causing a short circuit. The pump can either be connected to a pipe, flexible hose or
lowered down guide rails or wires so that the pump sits on a "ducks foot" coupling,
thereby connecting it to the delivery pipework.
Submersible pumps are found in many applications, single stage pumps are used for
drainage, sewage pumping, general industrial pumping and slurry pumping. Multiple
stage submersible pumps are typically lowered down a borehole and used for water
abstraction.
117
Submersible pumps are also used in oil wells. By increasing the pressure at the bottom of
the well significantly, more oil can be produced from the well compared to natural
production. This makes Electric Submersible Pumping (ESP) a form of "artificial lift" (as
opposed to natural flow). New varieties of ESP can include a water/oil separator which
permits the water to be reinjected into the reservoir without the need to lift it to the
surface.
The ESP system consists of a number of components that turn a staged series of
centrifugal pumps to increase the pressure of the well fluid and push it to the surface. The
energy to turn the pump comes from a high-voltage (3 to 5 kV) alternating-current source
to drive a special motor that can work at high temperatures of up to 300 °F (150 °C) and
high pressures of up to 5000 lb/in² (34 MPa), from deep wells of up to 12000 feet (3.7
km) deep with high energy requirements of up to about 1000 horsepower (750 kW). ESPs
have dramatically lower efficiencies with significant fractions of gas, greater than about
10% volume at the pump intake. Given their high rotational speed of up to 4000 rpm (67
Hz) and tight clearances, they are not very tolerant of solids such as sand.
Progressive Cavity Pump
Progressing Cavity Pumping (PCP) Systems typically consist of a
surface drive, drive string and downhole PC pump. The PC pump
is comprised of a single helical-shaped rotor that turns inside a
double helical elastomer-lined stator. The stator is attached to the
production tubing string and remains stationary during pumping. In
most cases the rotor is attached to a sucker rod string which is
suspended and rotated by the surface drive.
As the rotor turns eccentrically in the stator, a series of sealed
cavities form and progress from the inlet to the discharge end of
the pump. The result is a non-pulsating positive displacement flow
with a discharge rate proportional to the size of the cavity,
rotational speed of the rotor and the differential pressure across the
pump.
Figure 54 – PCP
118
PCP System Applications
• Sand-laden heavy crude oil and bitumen
• Medium crude oil with limits on H2S and CO2
• Light sweet crude oil with limits on aromatic content
• High water cuts
• Dewatering gas wells such as coalbed methane projects
• Mature waterfloods
• Visual and/or height sensitive areas
• All type wells, including horizontal, slant, directional and vertical
reservoirs
There are two basic elements that make up the downhole Progressing Cavity
(PC) Pump – a single helical alloy-steel rotor connected to a rod string and a
double helical elastomer-lined stator attached to the tubing string. Using the
latest manufacturing technology, rotors are kept to tight tolerances and
treated with chemical and abrasion-resistance coating, typically hard
chrome. Stators are comprised of a steel tube with an elastomer molded
inside to provide the internal geometry. Each combination of rotor/stator is
matched to downhole conditions to provide highly efficient operation and optimum production
enhancement. Figure 55 – Rotor
119
RESERVOIR DEVELOPMENT PRACTICES
All information gathered through drilling and completion of the wildcat and appraisal
wells and analysis of data obtained, is used to prepare a Reservoir Development Plan.
This plan includes not only spacing of development wells, as affected by surface and
subsurface conditions, but also the control procedures determined for manipulating the
reservoir fluid pressure changes and flow characteristics over the productive life of the
reservoir.
For flowing wells, this involves choke sizes and variations, in order to manipulate the
flowing bottomhole pressure of the wells within technical and economic limits. It also
involves fluid injection into the reservoir, to manipulate that pressure and therefore
control the production of hydrocarbons from the reservoir and encroachment of external
fluids such as water and gas into the reservoir.
The onshore development plan will be quite different than the offshore development plan.
One of the major decisions in preparing the offshore development plan is selection of
offshore platform locations and number of platforms, to optimize production within
economic limits from the reservoir in a reasonable lifetime.
If an offshore platform is placed in the wrong location, as determined by later drilling,
this will result in a major economic loss compared to drilling a single well in the wrong
onshore location. The decision, therefore, for offshore development may be far more
critical than decisions foe development of an onshore reservoir.
Economics, both at the time of development, and that anticipated over the productive life
of the reservoir, place limits on the extent to which the best technology can be applied.
For example, an offshore reservoir might be best developed on a 40-acre spacing (16
wells per square mile).
However, the cost of the platforms as related to hydrocarbon prices may justify the
drilling of only three wells per mile on an average basis, by directional drilling from
centralized platforms. It cannot be anticipated, therefore, that as high a percentage of the
original hydrocarbon in place will be recovered during the life of production of the
reservoir with three wells per mile as would have been recovered has the best available
technology been applied, requiring 16 wells per mile.
120
HYDROCARBON RECOVERY MECHANISMS
The recovery of hydrocarbons is basically a volume displacement process. When a
volume of hydrocarbon is removed from the reservoir by production, it will be replaced
by a volume of some fluid. Energy is expended in this process. Hydrocarbon recovery
mechanisms may be divided into two categories:
i) Primary Recovery
ii) Enhanced Recovery
Primary Recovery
Primary recovery is “utilization of the natural energy of the reservoir to cause the
hydrocarbon to flow into the wellbore.” Based on this definition, as long as the
hydrocarbon flows into the wellbore, this is primary recovery, even if the hydrocarbon
must be artificially lifted to the surface by pumps or some other process. There are many
sources of this primary recovery energy of which three are dominant:
a) Dissolved Gas Drive ( Solution Gas Drive )
b) Gas-Cap Drive
c) Water Drive
Dissolved Gas Drive
When the reservoir is produced so that gas is permitted to escape from the hydrocarbon
liquid in the reservoir, so that two-phase flow (gas and liquid ) occurs from the reservoir
into the wellbore, the expanding gas will force the oil ahead of the gas into the wellbore.
In order to maximize oil recovery, however, for most reservoirs it is desirable to prevent
dissolved gas drive, at least until late in the productive life of the reservoir.
As the reservoir approaches depletion, the flowing bottomhole pressures may be reduced
to as low a value as possible, in order to recover whatever percentage of remaining
hydrocarbons might flow into the wellbore, including solution gas from the oil which will
remain in the reservoir (residual oil) at the time the reservoir is abandoned.
Dissolved gas drive can be delayed by injecting water into the water zone beneath the oil,
or gas on top of the oil (there creating a gas cap, in order to maintain reservoir fluid
pressures above the bubble point pressure.
121
Gas-Cap Drive
If a gas cap exists above the oil zone, and wells are drilled and perforated in the oil zone
and the bottomhole pressures are sufficiently reduced, the expanding gas cap will force
the oil into the wells as the gas interface encroaches into the oil zone. In order for gas-cap
drive to exist as a primary recovery mechanism, however, the gas cap must exist
naturally.
Water Drive
Most hydrocarbon reservoirs will have a water zone beneath the hydrocarbon. This water
is tending to encroach into the oil zone. If wells are drilled and perforated in the oil zone,
when the wellbore pressure is reduced, oil flow will be initiated into the well as water
encroaches into the oil zone forcing the oil towards the producing wells. If this natural
encroachment tendency is to exist, natural energy must be present. There are several
possible sources of this natural energy. One source is the expansion of the water as a
compressible fluid, as reservoir pressures are reduced. As the reservoir pressure is
reduced, the expanding water will push the oil in front of it into the producing wells.
Water expansion as a compressed liquid produces more oil than oil as a compressed
liquid, not because the compressibility of water is much different to compressibility of
oil, but because the total volume of water in the water zone is usually very large when
compared to the total volume of oil in the oil zone.
Another source of energy for water drive occurs when the reservoir rock dips upward to
the surface where it outcrops. If permeability continuity exists through this rock, as oil is
produced from the reservoir, water flows down dip from the surface to replace the oil
volume removed. Surface water replenished that water, maintaining a constant
hydrostatic pressure on the reservoir fluids.
Secondary Recovery
Secondary recovery is proven technology; indeed, a recent study indicates that 50 percent
of all domestic crude oil in the US comes from secondary recovery operations. Water
flooding is inherently more efficient than gas displacement in pressure-maintenance
projects and is the preferred process where feasible.
Some reservoirs, principally those containing heavy oil that flows only with great
difficulty, not only provide poor primary recovery but often are not susceptible to
waterflooding. Enhanced oil recovery would be especially useful in some of
these reservoirs.
122
Water Flood
Of the historical techniques used for EOR, water flooding has been the most common.
This is not water drive. In water drive, water is encroaching into the oil zone from
beneath, but in a true water flood, water is injected down injection wells into the oil zone.
Ideally, this creates a vertical flood front, pushing the oil in front of the water toward the
producing wells. In a water flood, the water injection wells are placed relative to the oil
producing wells in some predetermined pattern based on reservoir characteristics and
production history. A common pattern for water flooding for large reservoirs which arc
basically horizontal reservoirs is the five spot pattern. This five spot pattern is repeated
over the reservoir,
Prior to the initiation of a water flood project for a reservoir, various studies will have
been made in designing the water flood. These might include model studies in the
laboratory, digital and analog computer simulations, and pilot floods may have been run
in a portion of the reservoir as a preliminary study, so that an analysis of the water flood
plan might be made.
It is desirable to conduct the water flood so as to maximize the sweep efficiency within
economic limits relative to production, so that when the water front from the injection
wells breaks into the producing wells, a maximum percent of the reservoir volume will
have been swept by the flood. Once this water front reaches the producing wells, further
hydrocarbon production will be negligible, in that the wells will now produce essentially
water. In order to recover further hydrocarbons, a different EOR technique must now be
applied as a tertiary (or third) method for recovery.
Whatever the technique used for enhanced recovery, it is desirable that the mobility ratio
of driving fluid be less than the mobility ratio for the driven fluid. The mobility ratio is
the ratio of the permeability to the flow of the liquid to the dynamic viscosity of that
liquid. The oil ratio mobility ratio will be
[ko/µo ] = Oil Mobility Ratio
And, in the case of the water flood, the water mobility ratio of the water will be
[kw/µw ] = Water Mobility Ratio
If the mobility ratio of the driving fluid is greater than the mobility ratio of the driven
fluid, the driving fluid will tend to channel or finger through the hydrocarbon, tending to
bypass the hydrocarbon in the smaller permeability channels, leaving it behind in the
reservoir.
123
Gas –Cap Injection
In the gas cap drive injection secondary recovery technique, gas is injected into the gas
cap above the oil zone, to pressurize the gas cap. In reservoirs where reservoir fluid
pressure is higher than the bubble point pressure, a gas cap may be created by gas
injection so that the expending gas cap with further gas injection will displace the oil into
the producing wells. As previously discussed, gas cap drive or gas cap drive enhancement
is often used as a reservoir pressure maintenance technique.
Enhanced Recovery
Processes that inject fluids other than natural gas and water to augment a reservoir’s
ability to produce oil have been designated “improved,” “tertiary,” and “enhanced” oil
recovery processes. The term used in this assessment is enhanced oil recovery (EOR).
According to American Petroleum Institute estimates of original oil in place and ultimate
recovery, approximately two-thirds of the oil discovered will remain in an average
reservoir after primary and secondary production. This inefficiency of oil recovery
processes has long been known and the knowledge has stimulated laboratory and field
testing of new processes for more than 50 years.
Early experiments with un-conventional fluids to improve oil recovery involved the use
of steam (1920’s) and air for combustion to create heat (1935). Current EOR processes
may be divided into four categories:
(a) thermal, (b) miscible, (c)chemical, and (d) other.
Most EOR processes represent essentially untried, high-risk technology. One thermal
process has achieved moderately widespread commercialization. The mechanisms of
miscible processes are reasonably well understood, but it is still difficult to predict
whether they will work and be profitable in any given reservoir. The chemical processes
are the most technically complex, but they also could produce the highest recovery
efficiencies.
The potential applicability of all EOR processes is limited not only by technological constraints, but by economic, material, and institutional constraints as well.
Thermal Processes
Viscosity, a measure of a liquid’s ability to flow, varies widely among crude oils. Some
crudes flow like road tar, others as readily as water. High viscosity makes oil difficult to
recover with primary or secondary production methods.
124
The viscosity of most oils dramatically decreases as temperature increases, and the purpose of all thermal oil-recovery processes is therefore to heat the oil to make it flow or
make it easier to drive with injected fluids. An injected fluid may be steam or hot water
(steam injection), or air (combustion processes).
Steam Injection.
Steam injection is the most advanced and most widely used EOR process. It has been
successfully used in some reservoirs in California since the mid-1960’s. There are two
versions of the process: cyclic steam and steam drive.
In the first, high-pressure steam or steam and hot water is injected into a well for
a period of days or weeks. The injection is stopped and the reservoir is allowed to “soak.”
After a few days or weeks, the well is allowed to backflow to the surface. Pressure in the
producing well is allowed to decrease and some of the water that condensed from steam
during injection or that was injected as hot water then vaporizes and drives heated oil
toward the producing well.
Figure 56
When oil production has declined appreciably, the process is repeated. Because of its
cyclic nature, this process is occasionally referred to as the “huff and puff” method.
The second method, steam drive or steam flooding, involves continuous injection of
steam or steam and hot water in much the same way that water is injected in water
flooding. A reservoir or a portion thereof is developed with interlocking patterns of
injection and production wells. During this process, a series of zones develop as the fluids
125
move from injection well to producing well. Nearest the injection well is a steam zone,
ahead of this is a zone of steam condensate (water), and in front of the condensed water is
a band or region of oil being moved by the water. The steam and hot water zone together
remove the oil and force it ahead of the water.
Cyclic steam injection is usually attempted in a reservoir before a full-scale steam drive is
initiated, partially as a means of determining the technical feasibility of the process for a
particular reservoir and partly to improve the efficiency of the subsequent steam drive.
A steam drive, where applicable, will recover more oil than cyclic steam injection.
Combustion Processes.
Combustion projects are technologically complex, and difficult to predict and control.
Injection of hot air will cause ignition of oil within a reservoir. Although some oil is lost
by burning, the hot combustion product gases move ahead of the combustion zone to
distill oil and push it toward producing wells. Air is injected through one pattern of wells
and oil is produced from another interlocking pattern of wells in a manner similar to
waterflooding.
This process is referred to as fire flooding, in situ (in place) combustion, or forward
combustion. Although originally conceived to apply to very viscous crude oils not
susceptible to water flooding, the method is theoretically applicable to a relatively
wide range of crude oils.
An important modification of forward combustion is the wet combustion process. Much
of the heat generated in forward combustion is left behind the burning front. This heat
was used to raise the temperature of the rock to the temperature of the combustion. Some
of this heat may be recovered by injection of alternate slugs of water and air. The water is
vaporized when it touches the hot formation. The vapor moves through the combustion
zone heating the oil ahead of it and assists the production of oil.
Miscible Processes
Miscible processes are those in which an injected fluid dissolves in the oil it contacts,
forming a single oil-like liquid that can flow through the reservoir more easily then the
original crude.
A variety of such processes have been developed using different fluids that can mix with
oil, including alcohols, carbon dioxide, petroleum hydrocarbons such as propane or
propane-butane mixtures, and petroleum gases rich in ethane, propane, butane, and
pentane.
The fluid must be carefully selected for each reservoir and type of crude to ensure that the
oil and injected fluid will mix. The cost of the injected fluid is quite high in all known
processes, and therefore either the process must include a supplementary operation to
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recover expensive injected fluid, or the injected material must be used sparingly. In this
process, a “slug,” which varies from 5 to 50 percent of the reservoir volume, is pushed
through the reservoir by gas, water (brine), or chemically treated brine to contact and
displace the mixture of fluid and oil.
Miscible processes involve only moderately complex technology compared with other
EOR processes. Although many miscible fluids have been field tested, much remains to
be determined about the proper formulation of various chemical systems to effect
complete solubility and to maintain this solubility in the reservoir as the solvent slug is
pushed through it.
Because of the high value of hydrocarbons and chemicals derived from hydrocarbons, it
is generally felt that such materials would not make desirable injection fluids under
current or future economic conditions. For this reason, attention has turned to C02 as a
solvent. Conditions for complete mixing of C02 with crude oil depend on reservoir
temperature and pressure and on the chemical nature and density of the oil.
Chemical Processes
Three EOR processes involve the use of chemicals : surfactant/polymer, polymer, and
alkaline flooding.
Surfactant/Polymer Flooding.
Surfactant/poIymer flooding, also known as microemulsion flooding or micellar flooding,
is the newest and most complex of the EOR processes. While it has a potential for
superior oil recovery, few major field tests have been completed or evaluated.
Several major tests are now under way to determine its technical and economic
feasibility. Surfactant/polymer flooding can be any one of several processes in which
detergent-like materials are injected as a slug of fluid to modify the chemical interaction
of oil with its surroundings.
These processes emulsify or otherwise dissolve or partly dissolve the oil within the
formation. Because of the cost of such agents, the volume of a slug can represent only a
small percentage of the reservoir volume. To preserve the integrity of the slug as it moves
through the reservoir, it is pushed by water to which a polymer has been added.
The chemical composition of a slug and its size must be carefully selected for each reservoir/crude oil system. Not all parameters for this design process are well understood.
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Polymer Flooding.
Polymer flooding is a chemically augmented waterflood in which small concentrations of
chemicals, such as polyacrylamides or polysaccharides, are added to injected water to
increase the effectiveness of the water in displacing oil.
Alkaline Flooding.
Water solutions of certain chemicals such as sodium hydroxide, sodium silicate, and
sodium carbonate are strongly alkaline. These solutions will react with constituents
present in some crude oils or present at the rock/crude oil interface to form detergent-like
materials which reduce the ability of the formation to retain the oil.
The few tests which have been reported are technically encouraging, but the technology
is not nearly so well developed as those described previously.
Reservoirs not considered for alkaline flooding became candidates for other processes.
Other EOR Processes
Over the years, many processes for improving oil recovery have been developed, a large
number of patents have been issued, and a significant number of processes have been
field tested. In evaluating a conceptual process, it should be recognized that a single field
test or patent represents but a small step toward commercial use on a scale large enough
to influence the supply of crude oil.
Some known processes have very limited application, for example, if thin coalbeds lay
under an oil reservoir this coal could be ignited, the oil above it would be heated, its
viscosity would be reduced, and it would be easier to recover. This relationship between
oil and coal is rare, however, and the process is not important to total energy production.
Another example involves use of electrical energy to fracture an oil-bearing formation
and form a carbon track or band between wells. This band would then be used as a highresistance electrical pathway through which electric current would be applied, causing the
“resistor” to heat the formation, reduce oil viscosity, and increase oil recovery. The
process was conceived over 25 years ago and has been tested sporadically, but
does not appear to have significant potential.
A third process in this category is the use of bacteria for recovery of oil. Several
variations have been conceived. These include use of bacteria within a reservoir to
generate surface-active (detergent-like) materials that would perform much the same
function as a surfactant/polymer flood. Although some bacteria are able to with-stand
temperatures and pressure found in oil reservoirs, none have been found that will both
successfully generate useful modifying chemicals in sufficient amounts and also tolerate
the chemical and thermal environments in most reservoirs.It is uncertain whether
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nutrients to keep them alive could be provided. Further, any strain of bacteria developed
would need to be carefully screened for potential environmental hazards.
Recovery Efficiencies
Experience has determined expected ranges of efficiencies of recovery of hydrocarbons
by primary and enhanced techniques. These recovery efficiencies are normally expressed
in one of two ways:
i.) Percent of Original-Oil-in-Place recovered
ii.) Percent of remaining-Oil-in-Place recovered
The ranges of recovery efficiencies for primary recovery and enhanced may be
summarized as follows:
Primary Recovery Efficiencies
Oil (Percent of Original Oil- in- Place)
Dissolved Gas Drive 5% to 30%
Gas-Cap Drive 20% to 40%
Water Drive 35% to 75%
Gas (Percent of Original-Gas-In –Place)
Gas Expansion and Water Drive 90% +
Enhanced Recovery Efficiencies
Oil (Percent of Original- Oil- In- Place)
Water flood (Secondary Recovery) 30% to 40%
CO2 Miscible Flood (Tertiary Recovery) 5% to 10%
Steam Drive (Heavy Oil) 50% to 80%
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REMEDIAL WELL WORK
Gravel packing
Gravel packs can be performed in either open hole or cased hole completions, in well
deviations from 0° to 110° and in zone lengths up to a few thousand feet. Systems are
available for virtually any well temperature, pressure, and environment. Gravel packed
wells can be produced under high drawdown without concern of sand production.
Productivity of the open or cased hole gravel packed completion is determined in part by
the condition of the reservoir behind the filter cake, quality of the filter cake, and stability
of the wellbore.
Figure 58
Sand-free production, high productivity, and completion longevity are primary objectives
for gravel pack operations. To achieve these objectives, operators must be able to perform
gravel pack applications under various well conditions.
Several techniques are available for dealing with sand production from wells. These
range from simple changes in operating practices to completions such as Sand
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CASED HOLE GRAVEL PACK COMPLETION
1 7 1/2 " hole
13 3/8" casing
1 2 1/4" hole
casing liner hanger
9 5/8" casing
Gravel Pack Packer
Perforation Gravel
Gravel Pack Screen
Hydrocarbon
7" casing
Consolidation and Gravel Packing. The sand control method selected depends on site
specific conditions, operating practices, and economic consideration.
Acidising
The purpose of acidising is to stimulate or effectively increase the flow capacity of wells.
The increase in flow capacity is accomplished by the acid’s ability to dissolve rock,
certain scale, mud and other soluble material, which may be blocking the flow channels.
Acids that are commonly used for stimulation are:
i) Hydrochloric acid (HCl)
ii) Hydrofluoric acid (HF)
iii) Acetic Acid
iv) Formic Acid
v) Other Acid Additives
Of the four acids mentioned above, hydrochloric acid is the most widely used due to its
high carbonate dissolving ability and low cost. It reacts with limestone to form water,
carbon dioxide and calcium chloride.
HCI/HF, also known as mud acid, is used exclusively for sandstone reservoirs with little
calcium. A pre-flush of 10% HCl is used to dissolve any calcium which is in the pore
throats. Hydrofluoric acid is used on sandstone reservoirs since it reacts with siliceous
compounds:
SiO2 + 6HF = H2SiF6 + 2H2O
A mixture of 3% HF and 12% HCl, known as mud acid, is used to dissolve clays and and
remove mud cakes created during the drilling process.
Acetic and Formic acids are used in stimulations where their slower reaction time and
ease of inhibition is required. On the basis of cost, these acids are 3 to 5 times more
expensive than HCl.
Acid Fracturing
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In acid fracturing, the acid is injected at higher rates and pressures , which fractures the
reservoir. The acid then travels along the newly created flow path and etches sides of the
fracture as well as the matrix pores along the fracture. This method is useful where deep
penetration is required.
Hydraulic Fracturing
Hydraulic fracturing is a technique used to allow oil and natural gas to move more freely
from the rock pores where they are trapped to a producing well that can bring them to the
surface. The technology was developed in the late 1940s and has been continuously
improved and applied since that time.
Hydraulic fracturing is used to create small cracks in subsurface geologic formations to
allow oil or gas to move toward a producing well. A fracture acts much like a road,
speeding up the journey of oil or gas molecules on their way to the wellbore that will
produce them.
If only water was being pumped into the well, the fracture would gradually close when
the operator stopped pumping, and within minutes the formation would be back to its
original non-fractured condition. In a hydraulic fracturing job, the fluid pumped into the
well contains a proppant (usually sand) to keep the fracture open.
This proppant collects inside the created fracture, so when the fracture tries to close, it
cannot, because the proppant is holding it open. The operator has now “constructed a
road” that molecules of gas far out in the coal can use to travel to the well. Some of these
gas molecules might not have been able to make it to the well otherwise. Even though
this new fracture is full of proppant, it is still much more permeable and easier to travel
through than the coal itself.
The extent of the fracture is controlled by the characteristics of the geologic formation, its
depth, the fluid type, and pumping pressure. The fracture will grow if the operator
continues to pump fluid at higher rates, or if the operator pumps a more viscous fluid into
the formation (e.g., molasses = high viscosity, water = low viscosity).
Whether the fracture grows higher or longer is determined by the surrounding rock
properties. When the fracture reaches the shale above (or below) the geologic formation
being fractured, it will stop; shale does not fracture easily. In nature, fluids that are under
pressure (such as fracturing fluids) will follow the path of least resistance. A hydraulically
created fracture will always take the path of least resistance, which means staying within
the formation that fractures easiest.
PROCESSING OF PRODUCED FLUIDS
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For oil wells and gas wells, surface processing is intended to reduce the presence of
undesirable produced fluids and other materials to a sufficiently low level (percent by
volume or percent by weight) to make transportation of the desirable fluids
(hydrocarbons) economic to facilities at other locations for further processing and
conversion into marketable products.
In the case of crude oil it is normally desirable to reduce water present to a level no
greater than two percent of the total volume of the liquids to be transported. In some
instances, however, it is necessary to completely remove contaminants during the initial
processing. This would be the requirement if hydrogen sulfide (H2S) should be present,
in that not only does it create a corrosive environment in the presence of water, but it is
also toxic and potentially deadly.
The surface processing system is designed to perform its necessary functions at minimum
cost, without endangering personnel or environment, and to retain maximum value of the
hydrocarbons while still fulfilling the functions of the processing system. For example,
for crude oil in general, the higher the API gravity of oil, the greater its value. Removal of
the lighter weight hydrocarbon molecules, such as paraffin series hydrocarbons, reduces
the API gravity of the remaining liquids and increases the producing gas-oil ratio with a
net loss of hydrocarbon liquid volume. Since the hydrocarbon liquid (crude oil) is
normally of greater value than hydrocarbon gas, the processing system is designed to
maximize the volume of crude oil available for marketing at as high an API gravity as
possible.
The higher the processing temperature to which crude oil is subjected, the lower the API
gravity of the resultant crude oil and the lower the volume of crude oil available for
transport and sale. Therefore, it is desirable to design the surface processing system to
minimize the maximum temperature to which the crude oil is exposed, while still meeting
the necessary functions of the system. The design of this system is therefore an
optimization process.
Oil Wells
The most commonly produced fluids and materials from oil wells are oil, gas, water
(usually salt water), emulsions, and solids. Oil wells are generally classified as either high
pressure wells or low pressure wells. If both well classifications are producing
into a central gathering system, the high pressure wells will have their production
directed to a high pressure manifold, and the low pressure wells will have their
production directed to a low pressure manifold.
Fluids produced from high pressure wells normally have a high solution gas-oil ratio,
consequently resulting in a higher producing gas-oil ratio. There are several options for
this gas, and the option selected will affect specifications for the surface processing
equipment. The three most common options for the gas are:
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1. Market the gas (or use the gas as a fuel at the location)
2. Re-inject the gas into the hydrocarbon reservoir from which it was produced or
into some other reservoir.
3. Flare or vent the gas as waste.
If significant gas is being produced, the third option is not normally permitted be
government regulations, in that a natural resource would be destroyed, with adverse
effect on the environment. Either of the first two options is more likely to be selected.
Therefore, the surface system is designed so that gas produced at the surface is
maintained as nearly as possible at the pipeline pressure or the re-injection pressure to
minimize cost of recompression of the gas.
Oil Well Surface Processing System
The high pressure well production from the high pressure manifold will initially be
directed through stage separators, so that gas is permitted to escape from the oil in stages.
From each stage separator, gas, oil, salt water, emulsions and solids may be removed. The
solids would tend to settle out due to gravity, but the liquids would essentially flow
through each stage of separation, to the free water knockout essentially at atmospheric
pressure (or at least at a relatively low pressure as compared to the wellhead pressure)
The produced fluid from the low-pressure wells is taken through the same system, with
the exception of the multi-stage separation process. The production from the low-pressure
well is directed to a low-pressure manifold, from where it flows directly to the free water
knockout. From that point to the transportation system, the process system is the same for
high-pressure and low-pressure well production.
The free water knockout is essentially a gravity separator with baffles to enhance the
separation. The high velocity fluids flow into this separator and upon entry, the flow area
is significantly greater, thereby reducing the velocity of flow and enhancing the gravity
separation of fluids and other materials into their different densities. Solid particles
transported from the reservoir will fall to the bottom of the system, with the fluids
stratifying according to density (salt water on bottom, emulsion in the next layer, crude
oil in the next layer, with gas rising to the top of the system). The water will contain
droplets of oil, the oil droplets of water, and the gas both oil and water droplets, possibly
in the form of a mist. As the fluids flow through baffling within the free water knockout,
fluid droplets suspended within the other fluids will tend to coalesce, forming larger
droplets and enhancing their gravity separation.
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As the separated fluids exist from the free water knockout, the salt water is removed from
the bottom, oil and emulsions are removed from the top of the salt water, and gas is
removed from the top. The water likely contains sufficient oil to prevent its being
exhausted to the environment, and may require further processing to remove any
remaining oil or other contaminants to a sufficiently low level to permit its disposal
overboard, in the case of an offshore operation, into the surface environment, or reinjection into a subsurface formation through a salt water disposal system. The oil, and
certainly the emulsion, flows from the free water knockout to an emulsion treater to break
the emulsion and remove as much additional water as is practical.
Figure 59 - Oil Processing System
There are several different emulsion treating processes. Historically, one of the most
common has been the heater treater, in that increased temperature will break the
emulsion. The oil and the emulsion flows from the free water knockout into the heater
treater, where it flows down the “down-comer” to the bottom of the heater treater. There
it is exposed to the heater, thereby increasing its temperature.
The increased temperature tends to break the emulsion with the heavier water moving
downward and the lighter oil upward, through gravity separation. There may be baffling
in the system through which the oil passes, further breaking the emulsion. The oil is
skimmed from the top of the water and, if the processing system has serve its function, is
then transported for storage or to the transportation system (pipeline, offshore tanker, rail
cars etc.)
Since the heater treater has increased the temperature of the system, additional gas is
formed and is removed from the top of the heater treater, to be combined with the gas
obtained from the free water knockout. It is then recompressed for transport or reinjection
into the reservoir. The water from the emulsion treater must be transported for disposal.
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Water
Salt Water
Clean Oil
Storage
Emulsion
Treater
Free Water
Knockout
Oil Wells
Oil, Gas &
Water
Water
Oil &
Emulsion
Clean Oil
Vapor
Recovery
Gas sales
Gas
Gas
Disposal
If hydrogen sulfide (H2S) and/or carbon dioxide (CO2) are present in the produced fluid,
they are normally removed from the oil and gas after exiting from the free water
knockout, to minimize exposure of downstream processing systems to the corrosive
environment which exists when H2S and/or CO2 is present. Dependent upon the volumes
of H2S and/or CO2 produced, various removal systems are available. One of the most
common is the amine system.
Since the heater treater increases the temperature of the produced fluids, the API gravity
as well as oil volume are both reduced, thereby reducing the value of the produced
hydrocarbons. Therefore, other emulsion treater systems may be used. Others available
include electrostatic emulsion treaters, chemical treatment to break the emulsions, and
molecular sieves. The electrostatic treaters takes advantage of the fact that the H2O
molecule is an electric dipole so that, when exposed to an electrostatic field there is an
attraction for the water molecule, thereby enhancing separation from the hydrocarbon.
The gas is removed from the stage separators, the free water knockout, and the emulsion
treater will likely be directed to a dehydrator for further removal of H2O molecules. The
dehydration process is the same as that process which will be discussed relative to
production from gas wells. Both the crude oil and the hydrocarbon gas leaving the system
will be transported for processing into marketable products.
Gas Wells
Production from gas wells may include hydrocarbon gas, carbon dioxide (CO2),
hydrogen sulfide (H2S), hydrogen, helium, oxygen, nitrogen, other gases, hydrocarbon
liquids and water in the form of droplets or vapor, and suspended solid particles such as
sand particles. Solid particle suspension, however, should minimized at the reservoir to
reduce the “sand blasting” effect on the production casing and/or tubing, wellhead
components, and surface equipment. Surface processing of production from gas wells is
usually less complex than for oil wells. From the wellhead, production passes into a
gathering system delivering production to the central processing facilities or topside
facilities on an offshore gas production platform.
Gas Well Surface Processing System
In normal operations, gas well production flow into a gravity separator, which is basically
a large tank. The velocity of the flow from the gathering pipeline decreases significantly
upon entering the separator, so that gravity separation occurs. Solid particles and liquid
droplets fall to the bottom of the separator, and gases move to the top. If there is
sufficient liquid accumulation from gravity separation, the hydrocarbons, usually
condensate will float to the top of any water present.
136
Using a baffle system to separate the liquid hydrocarbons from the water, the
hydrocarbons will be removed by pipeline to a central gathering location. Water will be
removed from the bottom of the separator, and solids will accumulate. The gravity
separator tank must occasionally be flushed or backwashed to remove accumulated solids
from the bottom of the separator. Gas is taken from the top of the separator. If H2O
content and content of other gases is sufficiently low, the hydrocarbon gas is transported
to market by pipeline, used as an energy source at the location, or re-injected.
The hydrocarbon gas leaving the gravity separator may contain too much H2O for
transport, injection, or use as fuel. If this should be the case, it will pass to the dehydrator
for removal of H2O molecules to an acceptably low level. This will usually be a glycol
dehydrator, using components such as ethylene glycol, for removal of the H2O molecules
from the hydrocarbon gas. The glycol molecule has a greater affinity (attraction) for the
H2O molecule than does hydrocarbon. Glycol dehydration is therefore a relatively simple
operation.
Figure 60 - Gas Processing System
The hydrocarbon gas is passed into the base of a glycol dehydration tower, where it rises,
bubbling through trays containing glycol, exposing the hydrocarbon gas to as large a
surface area of liquid glycol as is practical. As the hydrocarbon gas bubbles through the
glycol, the H2O molecules are attracted to the glycol and are removed from the
hydrocarbon gas, with the” dry” gas being removed from the top of the glycol tower.
“Dry” glycol (glycol without the presence of H2O molecules) flows on a continuing basis
into the top tray of the layered trays in the tower, and flows downward through the tower
from one tray to the next, accumulating H2O molecules as the hydrocarbon gas bubbles
through the glycol. By the time the glycol reaches the base of the tower, it is now “wet”
glycol (glycol with a significant H2O molecular content).
137
Gravity
Separator
Gas Wells
Gas,
Condensate
& Water
Water Condensate
Gas
Dehydrator
Water
Gas Sales
This process of removing the H2O molecules from the hydrocarbon gas has not been a
chemical process, in that no chemical reactions have occurred. There have been no
molecular changes. This “wet” glycol is removed from the base of the dehydration tower.
The H2O molecules are then removed from the glycol as it is prepared for recirculation as
“dry” glycol, back into the dehydration tower.
Removal of the H2O molecules from the glycol is not complex,, since H2O boils at a
lower temperature than does glycol. The “wet” glycol is taken to a temperature higher
than the boiling point of H2O, yet lower than the boiling point of glycol, boiling the H2O
molecules from the liquid glycol, leaving it “dry”. The “dry” glycol is then re-circulated
back to the glycol dehydration tower.
If hydrogen sulfide H2S and/or carbon dioxide (CO2) should be present in the production
from the gas wells, the gas taken from the top of the gravity separator is taken through a
process to remove the H2S and/or CO2 before dehydration. Several types of processes are
available to remove the H2S and/or CO2, the most common being an amine system as
mentioned in the discussion for processing the fluids produced by oil wells. H2S and CO2
molecules have a greater affinity (attraction) for amine molecules than for hydrocarbon
molecules, so in a similar fashion to glycol removal of H2O molecules from hydrocarbon
gas, the amine removes H2S and CO2 molecules. H2S and CO2 are corrosive in the
presence of water; therefore it is desirable to remove them early in the processing system,
to minimize exposure of downstream equipment to this corrosive environment.
The hydrocarbon liquid, usually condensate, taken from the bottom of the gravity
separator, is transported for storage or used downstream. If production is on or near an
offshore platform with an oil pipeline, the condensate may be used to “spike” the crude
oil in the pipeline by mixing it with oil. This mixing of the condensate with the oil
increases the API Gravity of the crude oil. The hydrocarbon gas exiting from this surface
processing system normally requires no further processing.
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