Petroleum and Reservoirs

Origin, Migration, and Accumulation of Petroleum

This is one of the more problematical subjects in the discussion of petroleum

geology since there is only limited agreement about how petroleum forms, how it

migrates, and how it accumulates. Since there is oil structures that include

reservoirs far away from what appear to be potential source beds, the fact that oil

does form, migrate, and accumulate is indeed a reality.

Theories concerning oil and formation (cata genesis) involve organic and

inorganic considerations. Present evidence brings most weight to bear on the side

of the organic origin of petroleum because hydrocarbon compounds are present in

organic material derived from plant animal life. For us the origin of petroleum will

be considered to be from organic sources.

Source rock analysts and geochemists are not in complete agreement on the

types of organic material. Some suggest that only plant material involved. Others

conclude that animal and plant material contribute to petroleum generation.

Additional problems concern theories of how petroleum migrates, the

driving mechanisms of migration, and the distances that it migrates.

Accumulations of petroleum occur in places from which migrating fluids

cannot escape. How migrating petroleum responds to changes in reservoir and trap

considerations in the site of accumulation is difficult to assess. The time required

for accumulation is propably variable to perclude establishment of definite

parameters.

Origion of petroleum:

Organic origion of petroleum indicates petroleum is the product of altered

organic material derived from microscopic plant and animal life. Microscopic

plants and animals are carried in great volume 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 plants and animals, which are deposited with organic materials

introduced by the streams and rivers. As deposition of the organic material takes in

the marine, deltaic and lacustrine environments, burial and protection by clay and

silt accompany it. This prevents decomposition of the organic material and allows

it to accumulate.

The amount of burial is a function of how much sediment is discharged by

streams and rivers into lakes and the sea as well as the amount of time involved in

the depositional process. Thick accumulations of silt, clay, and organic material

can produce large volumes of petroleum if there is enough time for the alteration

process to occur. Some research indicates that terrestrial organic material generates

coal and gas, and marineorganic material forms oil.

Conversion of the organic material is called catagenesis. It is assisted by

pressure caused by burial, temperature and thermal alteration and degeradation,

these factors result from depth, some bacterial action in a closed non oxidizing

chemical system, radio activity and catalysis.

1- Normal heat flow within the earths crust produces an average geothermal

gradient of approximately 1.5 Fo for each 100 feet of depth. Maturation

studies on various crude oils types indicate that temperature required to

produce oil occur between the approximates of 5,000 and 20,000 feet.

Temperature below 20,000 feet are excessive for oil generation and produce

gas. Above 5000 feet is too cool to generate oil or gas.

2- Like temperature, pressure is a function of depth and increases 1 psi for one

feet of depth. Pressure caused by sedimentary overburden.

3- Bacterial action is important in conversion of organic material to petroleum

in shallow depths. Causes of breaking down the original material into

hydrocarbon compounds which become biogenic gas.

4- The best source rocks are considered to be organically rich, black-colored

shale deposited in a non oxidizing, marine environment.

5- Most petroleum is generated and occurs in sedimentary rocks. Some

petroleum occurances in iguous and metamorphic rocks may have inorganic

or altered organic origions.

Migration:

The concept of petroleum migration remains a reality not with standing limited

agreement about mechanism and distances. When petroleum moves from source

beds to reservoir rocks, it does so by primary migration. If it moves within the

reservoir after it has accumulated, it does so by secondary migration. How far

petroleum migrates is not kown. It is probable that some small amounts of

petroleum generate in reservoir rocks in which they accumulate. However, the bulk

of it comes from source beds external to the reservoir.

Accumulation:

Petroleum accumulates and is stratified according to its fluid phases and the

amounts of formation water. Gas is lightest and accumulates above oil, which

overlies water. The quality of gas dissolved in oil depends on pressure,

temperature, and hydrocarbon characteristics.

Petroleum accumulates in the highest permeable portions of the reservoir

because of hydrodynamics, this is why the highest area of an anticline is usually

the best place to drill an exploratory well. Petroleum accumulations probably

require long period of time to form, particularly in reservoirs of low permeability.

Mobility of fluids within a reservoir is enhanced by increasing permeability.

(1)The Nature of petroleum

There is probably no other technical field in which so many major questions

remain unanswered and yet which functions as efficiently as the oil industry. For

example, geologists have yet to agree completely on the origion and accumulation

of petroleum, geophysicists have no tool which searchs directly for oil, petroleum

engineers are still leaving unrecoverable oil in the ground, and chemists and

chemical engineers must still evaluate crude oil on the basis of empirical tests

rather than by precise analyses. In short, we don’t know what it is, how it

origionates and accumulates, how to find it, or how to get it all out of the ground.

1.1. Chemical composition

Petroleum may be defined as a naturally occurring, complex mixture of

hydrocarbons which may be either gas, liquid, or solid, depending upon it is own

unique composition and the pressure and temperature at which it is confined. The

principal hydrocarbon series found in petroleum are

1. Paraffins(also called saturated hydrocarbons or alkanes) which have the

general formula CnH2n+2.These compounds are chemically stable and have

either straight or branched chains. The branched chain members are called

isomersand exibit somewhat different properties than their straight chain

counterparts, all crude oils contain some paraffins particularly as the more

volatile (low boiling point) constituents. The first few members of this series

are:

Abbreviation Formula Chemical structure Name

C1 CH4

Methane

C

H

H

H

H

C2 C2H6

Ethane

C3 C3H8

Propane

C4 C4H10

Normal Butan

iC4 C4H10

Iso-Butan

Note that iso-butan differs from normal by the manner in which the carbon atoms

are arranged. This is the only isomer possible with C4; the possible atomic

C C H

H H

H

H H

C C C H

H H

H H

H

H

H

C C C H

H H

H H

H

H

H C

H

H

C C C H

H

H

H H

H

H

H

C H H

combinations increase, however, with the length of the chain, as illustrated in table

below

POSSIBLE ISOMERS OF VARIOUS PARAFFINS

Carbon content Number of isomers

C8 18

C10 75

C20 366,319

C40 62,491,178,805,831

etc.

2. Cycloparaffins (naphthenes) having the general formula CnH2n. These

compounds have a ring structure, the simplest member being cyclopropane.

Typical members of this group are:

C3H6Cyclopropane

C4H8Cyclobutane

C C

C

H

H

H

H

H H

C C

C

H

H

H

H

H H

C H H

3. Aromatics (benzene series) having the general formula CnH2n-6. These

compounds are chemically active and contain the benzene ring. The simplest

member is

C6H6 Benzene

In addition to hydrocarbons, petroleum may contain numerous impurities such as

carbon dioxide (CO2), hydrogen sulfide (H2S) and other complex of nitrogen,

sulfur and oxygen. Any particular crude oil may contain a portion of each of the

listed hydrocarbon series plus numerous impurities, therefore is unique, precise

chemical analysis is impossible. Petroleum is often classified by a base

designation- as either a paraffin base, asphalt base, or mixed base crude.

A paraffin base crude is an oil whose chief components are paraffins, when

completely distilled leaves a solid residue of wax. An asphalt base crude is an oil

composed of cyclic compounds (mostly naphtheness), when distilled leaves a solid

residue of asphalt. Oils fall in the middle of these categories classified as mixed

base.

Crude petroleum yields a large number of products the simplest refining

process is fractional distillation whereby the constituents in the oil are separated by

utilizing their differences in boiling points. A few of these products are shown in

figure below.

C

C C

C C

C

H

H H

H H

H

1.2. Properties of liquid petroleum:

The most widely used indicator of a crude oil's worth to the producer is its API

(American petroleum institute) gravity. This value is actually a measure of an oil's

density, and related to specific gravity by the following formula.

API Gravity (degrees) =

Note that an API gravity of is equivalent to a specific gravity of 1.

The price which a producer receives for his oil depends on its gravity, the less

dense oils (higher API gravity) being the most valuable. The price schedule is

based on the premise that the lighter oils contain higher percentage of the more

valuable products such as gasoline. It is possible that a particular oil may be

more valuable than some oil, due to high yield of desirable products. The

refiners feel that these differences average out, probably that crude oil will always

be sold on a gravity basis.

The surface or tank oil as by a producer is not the same liquid which existed

underground. The differences between tank oil and reservoir oil are very important.

A reservoir oil always contains in solution components which would be gases at

standard temperature and pressure. Their solubility is due to elevated pressure and

temperature existing underground.

As oil is produced (brought form underground to the surface), the pressure is

decreased until it reaches atmospheric conditions in stock tanks. This pressure

reduction causer changes in reservoir fluid properties:

a) some of the volatile fraction vaporize, causing

b) the liquid volume shrink, and

c) the liquid viscosity to increase.

These effects are shown in figures 1.2 and 1.3 also a number of fundamental ideas

must defined

1- Bubble point pressure: The pressure shown as Pb is the bubble point or

saturation pressure. It is the pressure at which the first gas is liberated from

the reservoir oil upon isothermal pressure reduction at reservoir temperature.

2- Formation volume factor: This the quantity denoted by Bo the reservoir

volume occupied per volume of tank oil (oil reduced to standard conditions

– 14.7 psia and F) and its dissolved gas. This quantity is always greater

than 1.0 because of (a) thermal expansion [shown as ∆VTin figure 1.2 (D)

and (b) swelling asgas is dissolved at higher pressures [ shown by increasing

values of Vro in figure 1.2 (A),(B),(C),(D).

Note that Bo increases as the pressure is decreased from Pi to Pb due to liquids

expansion.

3- The solution gas-oil ratio. Denoted Rs, is the number of standard cubic feet

of gas dissolved per barrel of tank oil.

4- The oil viscosity ( µo ) behavior shown in figure 1.3(C) is typical and is

found by step wise determination in a high pressure viscosimeter. This

behavior explained as follows.

(a) Viscosity decreases as pressure is reduce from Pi to Pb due to liquids

expansion; greater intermolecular freedom of motion is possible, and

internal friction is reduced.

(b) Viscosity increases with pressure reduction below Pb because the low

viscosity fractions are lost.

The process explained in figure 1.2 is defined as flash vaporization, since the

composition of the system remained. If the cell pressure had been reduced by

removing liberated gas while holding volume constant, the process is differential

vaporization. The actual process taking place in underground petroleum reservoir

nearly fits the differential vaporization. It is commonly used in laboratory analyses.

The above fluid properties are called PVT (pressure - volume - temperature) and

are very important in solution of many petroleum engineering problems. These

values are normally obtained from analyses of subsurface or recombined surface

fluid samples. There are correlations in literature enable to obtain these factors

from available field data.

1.3. Gaseous petroleum (Natural Gas):

Recently natural gas has come into its own as a highly valuable product. Gas

produced with oil was sold primarily on a local scale and any excess was flared. As

the natural gasoline and liquefied petroleum gas (butane and propane) industry

developed, the use of the residue gas (dry gas remaining after liquid removed) also

increased. Today natural gas and its associated liquid products are virtually as

much in demand as oil. Natural gas is produced from three classes of wells:

(1) From wells where the dominate products oil (oil wells).

(2) From wells where the gas itself is the principal product (gas wells).

(3) As gas from condensate wells. Condensate wells produce from reservoir

in which the hydrocarbons (gas and liquid) originally existed as a single

fluid (or phase), the reservoir temperature and pressure being above the

critical point of the hydrocarbon mixture.

Each natural gas, like each crude oil, is a unique mixture of hydrocarbons. All

gases composed mostly of light members of the paraffin series and mostly

methane. Numerous impurities found in petroleum gases, mostly carbon dioxide

(Co2), hydrogen sulfide (H2S), water vapor, nitrogen, and helium. These impurities

decrease the value of natural gas by raising the costs of processing it to pipe line

and consumer standards.

There are a number of basic definitions which presented here below.

1- Wet gas: A natural gas is said to be wet if it contains an appreciable natural

gasoline content.

2- GPM: The natural gasoline content of a gas expressed in gallons per

thousand standard cubic feet (MCF). Gases having a GPM of 1 to 2 are wet,

while gas with a GPM of 0.2 is considered somewhat dry.

3- Sour gas: Natural gas containing hydrogen sulfide.

4- Sweet gas: Natural gas containing no hydrogen sulfide.

5- Gas gravity: The ratio of the density of a gas to the density of air at standard

conditions (a specific gravity scale based on air).

6- Standard conditions: 14.7 psia and F.

1.4. The gas law:

The gas law as applied to the behavior of natural gas is most commonly stated as

PV = z n R T

Where P = pressure, absolute

V = volume

N = number of moles

R = gas constant

T = absolute temperature

Z = deviation (or compressibility) factor to account for the difference

between actual and ideal gas volumes.

The value of R is dependent on the system of units used as given in table below:

Table

Values of the gas constant R for different values of P,V, and T

P V T R

Atmospheres c-c 82.1

Atmospheres Liters 0.0821

mm mercury cc 62369

gm per sq. cm cc 8.315

Ib per sq. in cuft 10.7

Ib per sq. f cuft 1545

Atmospheres cuft 0.73

Equation (1.1) may be rewritten:

…………………… (1.2)

Where W/M = n

W = total wt. of gas

M = molecular wt. of gas

Hence

…………………… (1.3)

Or

………………………. (1.3a)

Where

= specific volume of the gas

Also,

………………….. (1.4)

Where = gas density

Another useful expression relating the PVT behavior of a constant number of mols

of gas is

…………… (1.5)

Determination of Z:

The values of Z for natural gas mixture have been experimentally correlated as

functions of pressure, temperature, and composition. The ratio of the volume of a

particular substance to its volume at its critical point is the same for all substances

at the same ratio of absolute pressure to critical pressure, and absolute temperature

to critical temperature. This theorem may be applied to compounds of similar

molecular structure such as the light paraffins and natural gases.

In preparing a correlation for hydrocarbon mixtures, the ratios of actual

pressure and temperature to the molal average critical or pseudo-critical pressure

and temperature used. These ratios called reduced pressure and reduced

temperature. Figure 1.4 is a correlation of z as a function of these quantities. For

determination of the pseudo-critical properties a correlation of as function of gas

gravity have been found accurate.Figure 1.5 shows this correlation.

(2) Concepts of petroleum Geology and Basic rock properties

2.1. Requirements for commercial oil accumulations:

Certain requirements must be fulfilled for a commercial petroleum deposit to

be present. These are

1. A source: material from which oil is formed.

2. Porous and permeable beds (reservoir rocks) in which the petroleum may

migrate and accumulate after being formed.

3. A trap: subsurface condition restricting further movement of oil such that it

may accumulate in commercial quantities.

2.1.1. Source of petroleum:

Many theories on the origion of petroleum have been proposed and

classified into two groups:

1. Inorganic theories. These are of historical interest only.

2. Organic theories. At present most authorities favor organic approach,

principle reasons follows below:

1) No inorganic theory can account for necessary quantities of carbon and

hydrogen needed to form large petroleum deposits.

2) Many crude oils contains porphyrins and contain nitrogen. Presence of

these materials suggests organic origion and these are present in all

organic matter.

3) Petroleum rotates the plane of polarized light. This property restricted to

organic materials known as optical isomers this conclude organic source

of petroleum.

Studies of thousands oil fields has led most geologists to the following

conclusions:

1- Petroleum origin from organic material mostly vegetable altered by heat,

bacterial action, pressure, and other agents over long periods of time.

2- Conditions favoring petroleum formation found only in sedimentary rocks.

3- The principle sediments considered probable source rocks are shale's and

limestones that were originally muds under saline water.

2.12. Porous and permeable beds (Reservoir Rocks):

After petroleum formation it migrates from source rock into porous permeable

beds were it accumulates and continues its migration until finally trapped. Forces

causing this migration are:

1. Compaction of sediments as depth of burial increases.

2. Diastrophism: crustal movement causing pressure differentials and

subsurface fluid movements.

3. Capillary forces causing oil to be expelled from fine pores by

preferential entry of water.

4. Gravity causing fluid segregation due to density differences.

The term porous and permeable denote two distinct rock properties whose

measures and quantitative definitions have comprised most technical literature of

the oil industry.

Porosity:

Porosity is a measure of the void space within a rock expressed as a fraction (or

percentage) of the bulk volume of that rock.

Where = porosity

= bulk volume of the rock.

= net volume occupied by solids (grain volume).

= pore volume = the difference between bulk and solid volumes.

In actual rocks porosity is classified as

A) Absolute porosity: total porosity of a rock, regardless of whether or not

individual voids are connected, and

B) Effective porosity: only that porosity due to voids which are connected.

It is the effective porosity which is of interest in the oil industry.

Geologically, porosity is classified in two types, according to the time of

formation.

1- Primary porosity (inter granular): porosity formed at the time the sediment

was deposited. The voids contributing to this type are the spaces between

individual grains of sediment.

2- Secondary porosity: voids formed after the sediment was deposited.

Primary porosity:

The sedimentary rocks which exhibit primary porosity are the clastic

(fragmental or detrital) rocks which are composed of erosional fragments from

older beds. These are classified by grain size. Typical clastic rocks which are

common reservoir rocks are sandstones, conglomerates, and ooliticlimestones.

Secondary porosity:

Porosity of this type subdivided into three classes based on the mechanism

of formation.

(1) Solution porosity:

Voids formed by the solution of the more Soluble portions of the rock in

percolating surface and subsurface waters containing carbonic and other organic

acids. This is also called vagular porosity and individual holes are called vugs.

Voids of this origion ranges from small vags to cavernous – openings.

(2) Fractures, fissures and joints:

These voids are common in many sedimentary rocks and they are formed by

structural failure of rocks under loads caused by folding and faulting. This type of

porosity is very difficult to be quantitatively evaluated due to irregularity.

(3) Dolomitization:

This process is transformation of limestone (CaCo3) to dolomite CaMg(Co3)2

2CaCo3 + MgCl2 → CaMg(Co3)2 + CaCl2

It is should be noted that primary and secondary porosity can occur in the same

reservoir rock.

Quantitative use of porosity data:

As defined previously, is a measure of the void space within a rock, and may be

used to determine the quantity of fluidstored in that rock. Consider a bulk volume

of rock with a surface area of one acre and a thickness of one foot. This constitutes

the basic rock volume measurement used in oil field calculations, an acre – foot.

All liquid volume expressed in barrels.

1 acre = 34,560 ft2

1 acre – ft = 43,560 ft3

1 bb = 42 gal = 5.61 cuft

1 acre – ft =

= 7758 bb1

It is obvious that pore space of a rock is equal to 7758 x = (bb1/acre – ft)

where is rock porosity. See fig. 2.5 which shows that Volumetric Equation of oil

in place:

=

………… 2.2

Where N = tank oil in place, bbl / acre – ft

So = fraction of pore space occupied by oil (oil saturation)

Sw = the water saturation

Bo = the formation volume factor for oil at the reservoir pressure, barrels reservoir

space, barrel tank oil.

Determining proper values of Sw in Equation 2.2 is more difficult than obtaining

. Some water will always exist in reservoir rock and its volume must be

subtracted from squce available for oil. This water is called connate water. Note

that the pore space is assumed to be occupied either oil or water, and that no free

gas is present. Equation above must be applied to the reservoir at or above bubble

point and used to compute the initial oil in place.

A similar expression may be derived for the amount of gas stored in a

particular sand. Gas volume will be expressed in terms of SCF or in MCF

(thousands of standard cubic feet). From gas law.

………………. (2.3)

Where subscript, s, denotes standard conditions, (not shown), then

……………………… (2.4)

Where G = standard gas volume contained in at conditions P,T,z.

But: = 3,560 (1 – Sw) cuft/ acre – ft

= = R

= 14.7 pasia

Substitution of these values in Eq.2.4 gives

G = 43,560 (1 – Sw) X

…………….. (2.5)

Or

G =

MCF/Acre – ft …………… (2.5a)

Permeability: Darcy's Equations

In addition to being porous, a reservoir rock must be permeable; that is, it

must allow fluids to flow through its pore network at practical rate under

reasonable pressure differentials. Permeability is defined as a measure of a rocks

ability to transmit fluid. Permeability was first given in an empirical relationship

developed by the French hydrologist Henry D'Arcy who studied the flow of water

through unconsolidated sounds.

This law in its differential form is:

……………….. (2.6)

Where v = apparent flaw velocity

M = viscosity of the flowing fluid

dp/dL = pressure gradient in the direction of flow

k = permeability of the porous media

Consider the liner system of figure above. The following assumptions are

necessary to the development of the basic flow equations:

1- Steady state flow conditions exist.

2- The pore space of the rock is 100% saturated with the flowing fluid. Under

this restriction k is absolute permeability.

A

dp P2

q2

dL

P1

q1

q1 = q2

3- The viscosity of the flowing fluid is constant. For all real fluids. However,

this effect is negligible if M at the average pressure is used, and if

conditions 4-6 hold.

4- Iso thermal conditions prevail.

5- Flow is horizontal and liner.

6- Flow is laminar.

With these conditions, let

………………….. (2-7)

Where q = volumetric rate of fluid flow

A = total cross – sectional area perpendicular to flow direction.

This is further assumption since only the pores, and not the full area, conduct fluid.

Hence, v = an apparent velocity. The actual velocity, assuming uniform medium =

⁄ .

Case 1: Liner Incompressible Fluid Flow

Substitution of (2.7) in (2.6) gives

…………….. (2.8)

Separation of variable and insertion of the limits shown in figure above

∫

∫

……………. (2-9)

By integration

……………………. (2.10)

Or

Note that the negative sign used to denote a negative pressure gradient in the

direction of integration was removed by reversing the pressure limits equation

(2.10) is basic and following units server to define the Darcy.

If q = 1 cc/sec

A = 1

M = 1 centipoise

Atmosphere/cm

Then

K = 1 Darcy which is much higher than that commonly found in reservoir rocks.

Therefore common unit is millidarcy, where

1 Darcy = 1000 millidarcy

Case II, Linear compressible fluid flow:

Consider the same linear system of figure above, except that flowing fluid is

compressible; then constant, but ois a f(p)

Assuming that Boyles law is valid (z=1)

= constant …………. (2-11)

Then

………………… (2-12)

∫

∫

………………. (2-13)

From which

…………………… (2-14)

Expressing Eq (2-14) in terms of the rate of gas flow at the average pressure in

the system is

…………….. (2-15)

But

Therefore

……………………. (2-16)

Which is the same as Eq. (2-10)

An expression for the standard flow rate, , is from charle's law:

……………. (2-17)

Where = (520 )

= 1 atm

= flowing temperature

Thus

=

……………. (2-18)

Note: for standard units, = 1 atm and is often omitted from eq (2-18). The use of

liner equations is limited to laboratory testing. Radial flow (linear) equations are

used in fields.