THE RESERVOIRTHE RESERVOIR

PETROLEUM PETROLEUM RESERVOIRRESERVOIR

• ROCK PROPERTIES

• FLUID PROPERTIES

• PRESSURE

• RESERVOIR DRIVE

ROCK PROPERTIESROCK 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.

PERMEABILITYPERMEABILITY

DARCYDARCY’’S LAWS LAW

L = length q = flow ratep1 , p2 = pressuresA = area perpendicular to flowμ

= viscosity

q

Direction of flow A

p2 p1L

)( 21 ppL

Aqk

−•

μ=

k = permeability (measured in darcies)

k/μ

= kh/μ

=

DARCYDARCY’’S LAW:S LAW: RADIAL FLOWRADIAL FLOW

h = height of the cylinder (zone)P = pressure at r Pw = pressure at the wellbore

rw/rln)PwP(khq

μ−π

=2

. rrw

PERMEABILITY PERMEABILITY ––

POROSITY POROSITY CROSSPLOTCROSSPLOT

100

10

1

0.1

0.01 0.01

0.1

1

10

100

1000

2 6 10 14 2 6 10 14 18

Perm

eabi

lity

(md)

Porosity (%)

Limestone A1 Sandstone A1

• Oil

• Water

• Gas

kkk eo

ro =

kkk ew

rw =

kk

k egrg =

CALCULATING RELATIVE CALCULATING RELATIVE PERMEABILITIESPERMEABILITIES

Relative Permeability CurveRelative Permeability Curve

IRREDUCIBLE WATER SATURATIONIRREDUCIBLE WATER SATURATION• 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 thecapillarypressure issmaller.

TRANSITION ZONETRANSITION ZONE• The phenomenon of capillary pressure gives rise to the

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

• The rock can be thought of as a bundle of capillary tubes.• The length of the zone depends on the pore size and the

density difference between the two fluids.

Relative Relative PermeabilityPermeability

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

• Force oil into the core until irreducible water saturation is attained (Swirr). (A-> C -> D)

• Reverse the process: force water into the core until the residual saturation is attained. (B)

• During the process, measure the relative permeabilities to water and oil.

FLUID SATURATIONSFLUID SATURATIONS• Basic concepts of hydrocarbon accumulation

– Initially, pore space filled 100% with water– Hydrocarbons migrate up dip into traps– Hydrocarbons distributed by capillary forces and gravity– Connate water saturation remains in hydrocarbon zone

• Fluid saturation is defined as the fraction of pore volume occupied by a given fluid

• DefinitionsSw = water saturationSo = oil saturationSg = gas saturationSh = hydrocarbon saturation = So + Sg

• Saturations are expressed as percentages or fractions, e.g. – Water saturation of 75% in a reservoir with porosity of 20%

contains water equivalent to 15% of its volume.

SATURATIONSATURATION

• Amount of water per unit volume = φ

Sw

• Amount of hydrocarbon per unit volume = φ

(1 - Sw ) = φ

Sh

φ

Matrix1 −

φ

WaterHydrocarbonφ (1-Sw )

φ Sw

RESERVOIR PRESSURERESERVOIR PRESSURE

• 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 PRESSURERESERVOIR PRESSURE• Reservoir Pressures are normally controlled by the

gradient in the aquifer.• High pressures exist in some reservoirs.

Reservoir Pressure CalculationReservoir Pressure Calculation

RESERVOIR TEMPERATURE GRADIENTRESERVOIR TEMPERATURE GRADIENT

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.

FLUIDS IN A RESERVOIRFLUIDS IN A RESERVOIR• 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.

HYDROCARBON COMPOSITIONHYDROCARBON COMPOSITION• Typical hydrocarbons have the following composition in Mol Fraction

• Hydrocarbon C1 C2 C3 C4 C5 C6+

• Dry gas .88 .045 .045 .01 .01 .01

• Condensate .72 .08 .04 .04 .04 .08

• Volatile oil .6-.65 .08 .05 .04 .03 .15-.2

• Black oil .41 .03 .05 .05 .04 .42

• Heavy oil .11 .03 .01 .01 .04 .8

• Tar/bitumen 1.0

• The 'C' numbers indicated the number of carbon atoms in the molecular chain.

HYDROCARBON STRUCTUREHYDROCARBON STRUCTURE

• The major constituent of hydrocarbons is paraffin.

HYDROCARBON CLASSIFICATIONHYDROCARBON CLASSIFICATION• Hydrocarbons are also defined by their weight and the Gas/Oil ratio. The

table gives some typical values:

GOR API Gravity

• Wet gas 100mcf/b 50-70

• Condensate 5-100mcf/b 50-70

• Volatile oil 3000cf/b 40-50

• Black oil 100-2500cf/b 30-40

• Heavy oil 0 10-30

• Tar/bitumen 0 <10

HYDROCARBON GASHYDROCARBON GAS• 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".

FLUID PHASESFLUID PHASES

• 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.

PVT ExperimentPVT Experiment

PHASE DIAGRAM SINGLE COMPONENTPHASE DIAGRAM SINGLE COMPONENT• 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

FLUIDSBlack Oil

Criticalpoint

Pres

sure

, psi

a

Bubblepoint line

Separator

Pressure pathin reservoir Dewpoint line

9080

907060

5040

10

30

20

% Liquid

Temperature, °F

Pres

sure

Temperature

Separator

% Liquid

Bubblepo

int line

Dewpoint line

Dewpoint line

Volatile oil

Pressure pathin reservoir

3

2

1

5

103

30

20

40

5060

708090

Criticalpoint

3

3020

15

10

40

Separator

% Liquid

Pressure pathin reservoir

1

2Retrograde gas

Criticalpoint

Bubble

point

line

Dewpo

int lin

e

50

Pres

sure

Temperature

Pres

sure

Temperature

% Liquid

2

1

Pressure pathin reservoir

Wet gas

Criticalpoint

Bubb

lepo

int

line

Separator

152530De

wpo

int l

ine

Pres

sure

Temperature

% Liquid

2

1

Pressure pathin reservoir

Dry gas

Separator25

Dew

poin

t lin

e150

Retrograde Gas Wet Gas Dry Gas

Black Oil Volatile Oil

THREE GASES -

WHAT ARE THE DIFFERENCES?

• 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

BlackOil

VolatileOil

RetrogradeGas

WetGas

DryGas

InitialProducingGas/LiquidRatio, scf/STB

<1750 1750 to3200

> 3200 > 15,000* 100,000*

Initial Stock-Tank LiquidGravity, °API

< 45 > 40 > 40 Up to 70 NoLiquid

Color of Stock-Tank Liquid

Dark Colored LightlyColored

WaterWhite

NoLiquid

*For Engineering Purposes

LABORATORY ANALYSIS

BlackOil

VolatileOil

RetrogradeGas

WetGas

DryGas

PhaseChange inReservoir

Bubblepoint Bubblepoint Dewpoint NoPhase

Change

NoPhase

ChangeHeptanesPlus, MolePercent

> 20% 20 to 12.5 < 12.5 < 4* < 0.8*

OilFormationVolumeFactor atBubblepoint

< 2.0 > 2.0 - - -

*For Engineering Purposes

PRIMARY PRODUCTION TRENDSG

OR

GO

R

GO

R

GO

R

GO

R

Time Time Time

TimeTimeTimeTimeTime

TimeTime

Noliquid

Noliquid

DryGas

WetGas

RetrogradeGas

VolatileOil

BlackOil

°A

PI

°A

PI

°A

PI

°A

PI

°A

PI

BLACK OIL FLUID PROPERTIES

Sample : DRY GAS FLUID PROPERTIS

FVF Formation

Volume Factor• Fluids at bottom hole

conditions produce different fluids at surface:

• Oil becomes oil plus gas.

• Gas usually stays as gas unless it is a Condensate.

• Water stays as water with occasionally some dissolved gas.

FLUID VISCOSITY

FLUID & FORMATION COMPRESSIBILITY

DRIVE MECHANISMS• A virgin reservoir has a pressure controlled by the local

gradient.• Hydrocarbons will flow if the reservoir pressure is sufficient to

drive the fluids to the surface (otherwise they have to be pumped).

• As the fluid is produced reservoir pressure drops.• The rate of pressure drop is controlled by the Reservoir Drive

Mechanism.• Drive Mechanism depends on the rate at which fluid expands

to fill the space vacated by the produced fluid.• Main Reservoir Drive Mechanism types are:

1. Water drive.2. Gas cap drive.3. Gas solution drive

Water Invasion• Water invading an oil zone, moves

close to the grain surface, pushing the oil out of its way in a piston-

like fashion.

• The capillary pressure gradient 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

• Water moves up to fill the "space" vacated by the oil as it is produced.

Oil producing well

Water Water

Cross Section

Oil Zone

Bottom Water Drive

• Water moves up to fill the "space" vacated by the oil as it is produced.

Oil producing well

Cross Section

Oil Zone

Water

Water Drive 2

• This type of drive usually keeps the reservoir pressure fairly constant.

• After the initial “dry” oil production, water may be produced. The amount of produced water increases as the volume of oil in the reservoir decreases.

• Dissolved gas in the oil is released to form produced gas.

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

• As oil production declines, gas production increases.

• Rapid pressure drop at the start of production.

Solution Gas Drive

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

Solution Gas Drive 2

• An initial high oil production is followed by a rapid decline.• The Gas/Oil ratio has a peak corresponding to the higher

permeability to gas. • The reservoir pressure exhibits a fast decline.

GRAVITY DRAINAGE

Oil

Oil

Oil

Point A

Point B

Point C

Gas

Gas

Gas

Recovery = to 60% of OOIP

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.

5

4

3

2

1

0

Cumulative oil produced, percent of original oil in place

0 20 40 60 80 100

Gas

/oil

ratio

, MSC

F/ST

B

Water drive

Gas-cap drive

Solution- gas drive

Gas/oil Ratio Trends

Average Oil RecoveryFactors,

% of OOIPDrive Mechanism

Range AverageSolution-gas drive 5 - 30 15Gas-cap drive 15 - 50 30Water drive 30 - 60 40Gravity-drainagedrive

16 - 85 50

Average Gas RecoveryFactors,

% of OGIPDrive Mechanism

Range AverageVolumetric reservoir(Gas expansion drive)

70 - 90 80

Water drive 35 - 65 50

Average Recovery Factors

Drive ProblemsWater 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• Secondary recovery covers a range of techniques used to

augment the natural drive of a reservoir or boost production at a later stage in the life of a reservoir.

• A field often needs enhanced oil recovery (EOR) techniques to maximise its production.

• Common recovery methods are:– Water injection.– Gas injection.

• In difficult reservoirs, such as those containing heavy oil, more advanced recovery methods are used:– Steam flood.– Polymer injection. .– CO2 injection.– In-situ combustion.

Secondary Recovery 2

water injection

gas injection