PETROLEUM DEVELOPMENT GEOLOGY RESERVOIR ENGINEERING

• Permeability is a property of the porous medium and is a measure of the capacity of the medium to transmit fluids• Absolute Perm: When the medium is completely saturated with one flui

THE RESERVOIR

PETROLEUM RESERVOIR

ROCK PROPERTIES

Rocks are described by three properties:

– Porosity - quantity of pore space

– Permeability - ability of a formation to flow

– Matrix - major constituent of the rock

note: porosity & permeability has been discussed partially in

“Chapter I Introduction”

• Permeability is a property of the porous medium and is a measure of the capacity of the medium to transmit fluids

• Absolute Perm: When the medium is completely

saturated with one fluid, then the permeability

measurement is often referred to as specific or absolute permeability

• Effective Perm: When the rock pore spaces contain

more than one fluid, then the permeability to a particular

fluid is called the effective permeability Effective

permeability is a measure of the fluid conductance

capacity of a porous medium to a particular fluid when the medium is saturated with more than one fluid

• Relative Perm: Defined as the ratio of the effective permeability to a fluid at a given saturation to the effective permeability to that fluid at 100% saturation.

PERMEABILITY

L A

r ln

) Pw P

(

kh q

• In a formation the minimum saturation induced by

displacement is where the wetting phase becomes

discontinuous.

• In normal water-wet rocks, this is the irreducible water saturation, Swirr.

• Large grained rocks have a low irreducible water

saturation compared to small-grained formations

because the

capillary

pressure is

smaller.

• The phenomenon of capillary pressure gives rise to the

transition zone in a reservoir between the water zone and the oil zone.

density difference between the two fluids.

• Take a core 100% water- saturated (A)

until irreducible water

saturation is attained

(Swirr) (A-> C -> D)

force water into the core until the residual

saturation is attained (B)

measure the relative

permeabilities to water and oil.

• Basic concepts of hydrocarbon accumulation

occupied by a given fluid

contains water equivalent to 15% of its volume.

• Amount of water per unit volume = φ Sw

• Lithostatic pressure is caused by the

pressure of rock, transmitted by grain-to- grain contact.

• Fluid pressure is caused by weight of

column of fluids in the pore spaces

Average = 0.465 psi/ft (saline water).

• Overburden pressure is the sum of the lithostatic and fluid pressures.

• Reservoir Pressures are normally controlled by the gradient in the aquifer.

The chart shows three possible temperature gradients The

temperature can be determined if the depth is known.

High temperatures exist in some places Local knowledge is important.

• A reservoir normally contains either water or hydrocarbon or a mixture.

• The hydrocarbon may be in the form of oil or gas.

• The specific hydrocarbon produced depends

on the reservoir pressure and temperature.

• The formation water may be fresh or salty.

• The amount and type of fluid produced

depends on the initial reservoir pressure,

rock properties and the drive mechanism.

• Typical hydrocarbons have the following composition in Mol Fraction

• The major

constituent of hydrocarbons is paraffin.

• Hydrocarbons are also defined by their weight and the Gas/Oil ratio The table gives some typical values:

• Natural gas is mostly (60-80%) methane,

CH4 Some heavier gases make up the rest.

• Gas can contain impurities such as

Hydrogen Sulphide, H2 S and Carbon

Dioxide, CO2 .

• Gases are classified by their specific

gravity which is defined as:

• "The ratio of the density of the gas to that

of air at the same temperature and

pressure".

• A fluid phase is a physically distinct state, e.g.: gas or oil.

• In a reservoir oil and gas exist together at equilibrium, depending on the pressure and temperature.

• The behaviour of a reservoir fluid is analyzed using the properties; Pressure, Temperature and Volume (PVT).

• There are two simple ways of showing this:

– Pressure against temperature keeping the volume constant.

– Pressure against volume keeping the temperature constant.

• The experiment is conducted at different temperatures.

• The final plot of Pressure against Temperature is made.

• The Vapour Pressure Curve represents the Bubble Point and Dew Point

• (For a single component they coincide.)

THE FIVE RESERVOIR

FLUIDS

Black Oil

Critical point

80

90

Critical point

B b

le p

in t li

Separator

1 5

D

w p

in t n

1 50

• Dry gas - gas at surface is same as gas in reservoir

• Wet gas - recombined surface gas and

condensate represents gas in reservoir

• Retrograde gas - recombined surface gas and condensate represents the gas in the reservoir but not the total reservoir fluid (retrograde condensate stays in reservoir)

FIELD IDENTIFICATION

Black Oil

Volatile Oil

Retrograde

Gas

Wet Gas

Dry Gas Initial

No Liquid

*For Engineering Purposes

LABORATORY ANALYSIS

Black Oil

Volatile Oil

Retrograde Gas

Wet Gas

Dry Gas Phase

Change in

Reservoir

Phase Change

No Phase Change Heptanes

PRIMARY PRODUCTION TRENDS

Time Time

Time

Time Time

No liquid

No liquid

Dry Gas

Wet Gas

Retrograde Gas

Volatile Oil

Sample : DRY GAS FLUID PROPERTIS

• Fluids at bottom hole conditions produce different fluids at

FLUID & FORMATION COMPRESSIBILITY

• A virgin reservoir has a pressure controlled by the local

gradient.

drive the fluids to the surface (otherwise they have to be

pumped).

Mechanism.

to fill the space vacated by the produced fluid.

• Water invading an oil zone, moves close to the grain surface, pushing the oil out of its way in a piston-

like fashion.

forces water to move ahead faster

in the smaller pore channels.

• The remaining thread of

oil becomes smaller.

• It finally breaks into smaller

pieces.

• As a result, some drops

of oil are left behind in

the channel.

Water Drive

vacated by the oil as it is produced.

Oil producing well

Cross Section

Bottom Water Drive

vacated by the oil as it is produced.

Oil producing well

Cross Section

Water

Water Drive 2

constant.

amount of produced water increases as the volume of oil in the reservoir decreases

Gas Invasion

• Gas is more mobile than oil and takes the path of least resistance along the centre of the larger channels.

• As a result, oil is left behind in the smaller, less permeable, channels.

Gas Cap Drive

Gas from the gas cap expands to fill the space vacated by the produced oil.

Gas Cap Drive 2

Solution Gas Drive

After some time the oil in the reservoir is below the bubble point.

Solution Gas Drive 2

permeability to gas

Drives General

• A water drive can recover up to 60% of the oil in place.

• A gas cap drive can recover only 40% with a greater reduction in pressure.

• A solution gas drive has a low recovery.

Average Oil Recovery

Drive Problems

Water Drive:

• Water can cone upwards and be

produced through the lower

perforations.

Gas Cap Drive:

• Gas can cone downwards and be

produced through the upper

perforations.

• Pressure is rapidly lost as the gas

expands.

Gas Solution Drive:

• Gas production can occur in the

reservoir, skin damage.

• Very short-lived.

Secondary Recovery

augment the natural drive of a reservoir or boost production at

a later stage in the life of a reservoir.

maximise its production.

– Water injection.

– Gas injection.

advanced recovery methods are used:

– Steam flood.

– Polymer injection .

– CO2 injection.

– In-situ combustion.

Secondary Recovery 2

water injection

gas injection