Natral gas and processing and transmission 1

NNPC FSTP EngineersNatural Gas Processing and Transmission

Course ContentIntroduction to Reservoir FluidsNatural Gas PropertiesOil and Gas Separation ProcessHeat Transfer Processes and EquipmentNatural Gas ProcessingNatural Gas Compression and Transmission

Reservoir Fluids Definition

Reservoir is a naturally occurring complex mixture of hydrocarbons (petroleum) and other constituents.

The petroleum occurs as Natural gas - Gaseous

and/or Crude oil - Liquid Hydrocarbon

It occurs in varying degree of heaviness(viscosity) depending upon their unique composition and prevailing conditions of temperature and pressure in their depositional environment.

other constituents include, water, hydrogen sulphide, carbon dioxide,

nitrogen, metals, etc.

Reservoir fluid is also invariably referred to as petroleum because it is considered as a hydrocarbon fluid system with other constituents as contaminants.

Reservoir Fluids Reservoir Fluid Properties The physical and chemical properties of the reservoir fluid vary

considerably depending on the concentration of the various types of hydrocarbons and minor constituents present in the fluid.

The state of occurrence – liquid, gas or liquid and gas – also determines the properties and the fluid behaviour.

Furthermore, the accurate description of physical properties of crude oil or natural gas is of paramount interest in petroleum engineering studies due to their direct application in drilling, petroleum reservoir engineering problems, designing the production and processing of petroleum.

Finally, because natural gas does largely occurs as solution gas in crude oil, the study of crude oil properties relating to natural presence in oil becomes necessary in overall study of natural gas properties, processing and transmission.

Reservoir Fluids Crude Oil Properties Crude oil physical properties of primary interest in petroleum engineering

studies include: API - Crude gravity Specific gravity of the solution gas Crude Gas solubility Crude Bubble-point pressure Crude Oil formation volume factor Isothermal compressibility coefficient of undersaturated crude oils Oil density Total formation volume factor Crude oil viscosity Surface tension

Crude oil properties are either determined in the laboratory from the actual sample of the crude or from empirically derived correlations in the absence of experimentally determined quantities.

Reservoir Fluids Crude Oil Properties Crude Oil Density, Specific Gravity and API

Equation 1-1 below determines crude oil density taking into consideration the solution gas presence and the formation volume factor.

where o = specific gravity of the stock-tank oilRs = gas solubility, scf/STBo = oil density, lb/ft3

Bo = formation volume factor, res. bbl/stb

11.0136.04.62

eqn

BR

o

ssoo


Oil Density Determination from Empirical Correlations These estimate oil density of crude oil of unknown composition at the prevailing reservoir pressure and temperature.

They employ PVT data such as oil gravity, gas gravity and gas solubility Standing Correlation

Vasquez-Beggs Co.

whereA = 10-5 [-1,433 + 5 Rsb + 17.2 (T - 460) - 1,180 gs + 12.610API]

Petrosky-Farshad Co.

where A is as above

21.

46025.1000147.0972.0

0136.04.6275.1

eqn

TR

R

o

gs

gsoo

31.lnexp

eqn

PPA

bobo

41.exp 4094.04094.0 eqnPPA bobo


Solution Gas Specific Gravity Solution gas specific gravity is calculated based on the weighted-average specific gravity of gases from the several stages of separator.

Where; n = number of separators Rs = separator gas-oil ratio, scf/STB s = separator gas gravityRst = gas-oil ratio from the stock tank, scf/ STBst = gas gravity from the stock tank

61.1

1

eqnRR

RR

stni is

ni ststisis

g

Reservoir Fluids Crude Oil Properties Gas Solubility

This is the standard cubic feet(SCF) of natural gas which will dissolve in one stock-tank barrel(STB) of the crude oil at that pressure and temperature.

It is a direct function of the pressure and temperature under consideration, and the crude oil API and the natural gas gravity.

The most practical means of understanding reservoir fluid gas solubility is to view as a measure of the amount of gas evolving from reservoir fluid upon pressure drop on the crude rather than the amount of gas that can be dissolved into the crude at any pressure.

Fig 1-1 below illustrates this line of understanding


From fig 1-1, for any reservoir pressure (Pi) above the crude oil bubble point , NO gas evolves out upon any pressure drop as the crude is saturated and solubility remains constant.

Below the bubble point pressure(Pb), gas will begin to evolve upon any pressure and amount of gas evolved depends on the magnitude of the pressure drop.

Note that even at these pressures, there is the maximum amount of gas(Rs) the crude can handle at the specific pressure and temperature

Pi


No. Correlation Equation Remark

1 Standing X = 0.0125API – 0.00091(T-460)P = psiaT = 0R

2 Vasquez-Beggs Correlation

Coefficient API 30 API > 30C1 0.0362 0.0178C2 1.0937 1.1870C3 25.7240 23.931

ggs = gas gravity at the reference separator pressure

3 Glaso’s Correlation

is a correlating number and is defined by the following expression = 10X

X = 2.8869 – [14.1811 – 3.3093log(P)]0.5

4 Marhoun’s Correlation

g = gas specific gravityo = stock-tank oil gravityT = temperature, °Ra–e = coefficients having these values:a = 185.843208b = 1.877840c = -3.1437d = -1.32657e = 1.398441

5 Petrosky-Farshad Correlation

X = 7.916(10-4)(API)1.5410 – 4.561(10-5)(T-460)1.3911

*bP *bP

2048.1

104.12.18

x

gsPR

TAPICPCR C

gss 31 exp2

2255.1*

172.0

989.0

460

bgs P

TAPIR

edco

bgs PTaR

73184.18439.0 10340.12727.112

x

gsPR

Table 1-1Solution Gas Solubility Correlations

7.114log46010912.51 5 sepsepggs

PTAPI

*bP *bP *bP

*bP

Reservoir Fluids Crude Oil Properties Formation Volume Factor(Bo)

Crude Formation Volume This is the volume relationship between a specific volume of the oil in the reservoir and resulting volume after the evolvement of solution gas.

It is defined as the ratio of the volume of oil (plus the gas in solution) at the prevailing reservoir temperature and pressure to the volume of oil at standard conditions.

It can also be defined as the volume in barrels that one stock tank barrel(at standard conditions) of oil will occupy in the reservoir at reservoir pressure and temperature with all its solution gas

Bo is always greater than or equal to unity.

Generally, it is viewed as the volume of fluid at reservoir conditions as a measure of the volume at standard conditions of temperature and pressure.

*bP *bP *bP *bP *bP


Mathematically, it is represented by the following equation;

Bo = Vr /Vs eqn. 1-7where; Vr = Crude reservoir volume with

solution gas Vs = Equivalent

volume in stock tank that Vr will give rise to on the surface

*bP *bP *bP *bP *bP

Formation Volume Factor vs. Res. Pressure

If Pr Pb (of crude oil), upon pressure reduction as a result of production;

Gas evolvesVolume change is strictly due crude shrinkageStock Volume Reservoir VolumeBo increases with increasing Pr because at higher Pr more gas goes into solution causing crude to swell(increase in volume)


*bP *bP *bP *bP *bP

Formation Volume Factor vs. Res. Pressure

If Pr Pb (of crude oil), upon pressure reduction as a result of production;

No Gas evolvesVolume change is strictly due crude compressibilityStock Volume Reservoir Volume due to expansionBo decreases with increasing Pr because at higher Pr no more gas goes into solution and oil is compressedBo remains nearly constant at pressures above bubble-point pressure.


Dead Oil Oil which has no decrease whatsoever between the reservoir volume and the surface volume

Pr = Ps Bo becomes unity (1).

At Bubble Point – Mathematically by Standing

Above Bubble Point – Mathematically by

Bob = Bo at bubble point

*bP *bP *bP *bP *bP

RPbPoCobo eBB


Total Formation Volume Factor(Bt) Also called two-phase formation volume factor

Unit: - bbl/STB + bbl/SCF * (SCF/STB)bbl/STB + bbl/SCF * (SCF/STB)

*bP *bP *bP *bP *bP

ssbgot RRBBB

Reservoir Fluids Crude Oil Properties Compressibility

This is a measure of the response of crude volume to pressure changes at constant temperature or pressure.

The various equations associated with oil compressibility are as follows:

Bo = Oil Formation Volume factor – bbl/stb

o = Oil Density – lb/ft3

V = Liquid Volume; VM = Liquid Mole Volume; v = Crude Specific Volume

Integrating above eqns. with assumption of Co = Constant

Bo = Bob e –co(p – pb)

o = ob e co(p – pb )

*bP *bP *bP *bP *bP

101.11111

eqnPB

BCor

PCor

Pv

vCor

PV

VCor

PV

VC

T

o

oo

T

o

oo

To

T

M

Mo

To

2112

PPC oevv

Reservoir Fluids Crude Oil Properties Compressibility

The various equations associated with oil compressibility are as follows:Now, since oil compressibility is quite small, when above equations are developed by Taylor’s series we have the approximations below

V2 ≈V1 [1+Co(P1− P2)]lnV2 ≈ lnV1 + Co(P1− P2)Bo ≈ Bob[1 – Co(p – pb) ]o ≈ ob[1 + Co(p – pb)] This approximation is valid when Co(P2− P1) « 1.

At Pr Pb reservoir pressures below the bubble point pressure,

Bg = Gas formation factor in bbl/scf

*bP *bP *bP *bP *bP

T

s

o

g

T

o

oo P

RBB

PB

BC

1

Reservoir Fluids Crude Oil Properties CompressibilityIsobaric Compressibility is crude compressibility measured

at Constant Pressure and given by the following equation:

Where o is the co-efficient of isobaric thermal expansion of the crude and integrating above equation with assumption of = constant and for small t. is crude density.

*bP *bP *bP *bP *bP

P

o

oPo TT

vv

11

1212

1212

11

TTTTvv

oo

Behaviour Of Hydrocarbon Systems Factors Determining Molecules Behaviour

TemperatureReflection of System Kinetic EnergyA Measure of the System Molecules Kinetic Energy A Measure of the Degree of Hotness OR Coldness in a Body

A Measure of the System Molecular Motion

PressureReflection of the Number of the Molecules Present in the System and their Mass Motion Rate

Measure of the Number of Times the Molecules Strike the Wall of the System

Forcing Molecules Closer Increases the System Pressure

Factors Determining Molecules Behaviour System’s Molecular Attraction and Repulsion

Pressure Pushes Molecules Together Molecular Attraction

Temperature Pulls Molecules Apart Molecular Repulsion

Molecules Distance Greater with Gas Molecules When Large; Molecular Attraction Occurs When Small; Molecular Repulsion Occurs Attraction Gives Rise to Repulsion When Molecular Distance is such that Molecules Electronic Fields Overlap

Liquid Has More Repulsion Gas Has More Attraction

Behaviour Of Hydrocarbon Systems

Phase A Homogenous and Physically Distinct Part of a System with a Definite Bounding Surfaces (Interface).

Part of System Which Differs in its Intensive Properties and Physically Separable from Other Phases.

Bounding Surfaces(Interfaces) are Determined by Condition of:PressureTemperature

Hydrocarbon Systems Phase Behaviour

SITP / O & G

Ono SLIDE 23

Hydrocarbon System Phase Behaviour

Phase Different States of a Phase

Gaseous Water VapourLiquid WaterSolid Ice Different Crystalline Nature of Solid

3 Phases of Water

Phase Hydrocarbon System Phase Behaviour

Phase BehaviourConditions of Pressure and Temperature Under Which Different Phases of Substance can Exist

Phase Controlling VariablesPressureTemperatureVolume

Nature of Phase is Determined by Changes in Variable(s) When Other Variables(s) are Held Constant


Phase TransitionPhase Transition

Pure Substances Phase Behaviour

Pure Substances Substances with constant composition. Composed of a Single Chemical Species, Which May Exist in More

Than One Phase.

Types of SubstancesA Pure Substance can be either an element Elemental SubstanceExamples:

Iron (Fe) Copper (Cu) Oxygen (O2).

OR A Compound of Elements Compound Substance Examples:

Table Salt (Sodium Chloride, NaCl), Sugar (Sucrose) Water (H2O),


Phase Phase Diagram

Temperature-Pressure Diagram Illustrating Various Conditions(T-P) Under Which Different Phases of a System(Substance) Exist

Diagram that indicates whether substance exists as Solid, Liquid or Vapor at any Given Temperature and Pressure

A Pictorial Representation of the Conditions of Temperature and Pressure for Each Phase of a Pure Substance.

The Phase Diagram Also Describes the Temperatures and Pressure Where the Phases Are in Equilibrium.


Pure Substances Phase Diagram Lines represent Phase Changes

Regions represents Phases


Gas

Pure Substances Phase DiagramPhase Diagram of Water


Pure Substances Phase Diagram Vapour-Pressure Line

Bubble PointDew Point

Melting Point LineMelting Point

Sublimation Point LineSolid Giving Rise to Gas: Vice Versa

Triple PointThree Phase Giving Rise to One Another SUBLIMATION

TRIPLE POINT

Superheated Vapor

Sub-Cooled or Compressed Liquid

Gas

Dense

Fluid


Pure Substances Phase Diagram Critical Point

Point at Which No Matter How High the Pressure Exerted on the Sample, the Phase of the Pure Substance Can Not Change.

Above the Critical Point an Increase in Pressure Will Not Change the Phase.

At the Critical Point Only a Single Phase Exist which Appears Most Like a Vapor.

At Higher Temperatures or Pressures Above the Critical Point the Sample Remains in a Single Phase, but the Density of the Sample Changes.

Fluid is Referred to as Super-critical Fluids Not Really Exactly a Liquid or Exactly a Gas


Pure Substances Phase Diagram Critical Point

Critical Pressure Pressure Above Which the Liquid and Gas Phases CANNOT Co-exist Regardless of Temperature

Critical Temperature Temperature Above Which Gas CANNOT be Liquefied Regardless of Pressure Applied

Above Critical Point: No Liquid, No Gas Only “Dense Fluid”

SUBLIMATION

TRIPLE POINT

Superheated Vapor

Sub-Cooled or Compressed Liquid

Gas

Dense

Fluid


5

6

8

7

Isothermal Expansion


SITP / O & G

Ono SLIDE 34

Pure Substances Isothermal

Vaporization .

T = Constant TC

P1 PB

T = Constant TC T = Constant TC T = Constant TC

P1 = PB P1 = PB P1 PB

Hg removed.

Cell full of liquid.

Liquid expands.

Temperature remain constant

Liquid

Hg

SITP / O & G

Ono SLIDE 35


Isobaric Temperature Change

5 6

7 58T

SITP / O & G

Ono SLIDE 36

Pure Substances Isobaric

VaporizationFig 2-10

Cell heated.

Cell full of liquid.Liquid expands.Hg removed for pressure to remain constant

Liquid

Hg

Boiling Point and Evaporation Point of LiquidLiquids may change to a vapor at temperatures below their boiling points through the process of Evaporation.

Evaporation is a surface phenomenon in which molecules located near the vapor/liquid surface escape into the vapor phase.

On the other hand, boiling is a process in which molecules anywhere in the liquid escape, resulting in the formation of vapor bubbles within the liquid.

Pure Substances Vapour Pressure

and Temperature Relationship

Clausius-Claperyron EquationInvestigates Vapour-Pressure Line

LV = Heat of Vaporization of One Mole of Liquid T = Absolute Temperature PV = Vapour Pressure VMg = Gas Volume of One Mole VML = Liquid Volume of One Mole

VML - VMg = Change in Volume of One Mole in Going From Liquid to Gaseous State

Since Liquid Specific Vol. is Small Compared to that of Gas:

Eqn. 2-2

12.)(

EqnVVT

LvdTdP

MLMg

V

Mg

VV

VTL

dTdP



Clausius-Claperyron Equation From Ideal Gas Law: PV VMg = RT Eqn. 2-3 Combining Eqn 2-2 and 2-3

Assuming LV, is Constant, Rearranging and Integrating:

Resulting in:

C = Constant of Integration

Doing Away with C and Integrating between T1 and T2,

42.2 EqnTRLP

dTdP VVV

52.2 EqnTdT

RL

PdP V

V

V

72.1121

2

1

Eqn

TTRL

PPLn VV

V

72.1121

2

1

Eqn

TTRL

PPLn VV

V

62.1

EqnC

TRLPLn V

V



Clausius-Clapeyron Vapor Pressure Plot

Equations 2-6 and 2-7 are Clausius-Clapeyron

They Define Relationship Between Vapour Pressure and Absolute Temperature of Pure Substances along the Vapour-Pressure Line

72.1121

2

1

Eqn

TTRL

PPLn VV

V

62.1

EqnCTR

LPLn VV

Vapour Pressure-Temperature Plot for n-HexanePressure psia

Pressure psia

Clausius-Clapeyron Vapor Pressure Plot

Cox - Chart Observations and Reservations on Clausius-Clapeyron Vapor

Pressure Plot Lv is NOT Constant

This is Responsible for Curve NOT Being Straight

A Plot of Logarithm of Vapour Pressure against a Modified Arbitrary Temperature Scale Produces Straight Line Curve

All Points on the Straight Curve Represent Bubble Point Pressure/Temperature Sets

Critical Point Indicated by a Circular Dot

Lines are Not Actually Expected to Extend Beyond The Critical Points

Cox - Chart Vapour Pressure-Temperature Plot for n-Paraffins

Pressure - Volume Diagram (Fig. 2-10) Constant System TemperaturePV Bubble Point Pressure

Line 1- 2 Liquid Phase Press-Vol. Line

Line 2- 3 Constant Press Vaporization Line

Line 3- 4 Gas Phase Press-Vol. Line

Line 1, 2, 3, 4 Press-Vol. Relationship Curve

Line 5 - 6 Press-Vol. Line above C.P

Line of Continuous Volume Expansion without Change in

Phase


and Volume Relationship

At Bubble Point and Dew Point: 2-3 Pressure Remains Constant

Volume Continues to Expand

23

4

6

51

Bubble and Dew Points in Press-Volume Curves



Saturation Envelope Isotherm Press-Volume Curve at

Constant Temperature

Saturation EnvelopeArea Covered by Line Joining ALL Bubble Points and Dew Points of ALL Isotherms of a Substance

Region Where Liquid and Gas Co-exist

Critical Point From Press-Vol. PlotHighest Point on the Saturation Envelope

Critical Temperature IsothermIsotherm that Goes Through the Critical Point

Has Inflection at Critical Point

Pure Substance Pressure-Volume Diagram



Saturation Envelope Saturation Envelope for

Temp.-Volume Diagram

Pure Substance Temperature-Volume Diagram

Pure Substances Temperature and Volume Relationship at Constant Pressure

Density-Temperature Diagram Curves Refer to Densities of Gas and

Liquid Co-existing in the Saturated Envelope

This is a Two-Phase Region

These Sets of Densities are Called Saturated Densities

Density-Temp. Curve Critical Point Point Where Gas and Liquid Densities

are Equal

Beyond Critical Point, Density is ONE Phase(Fluid)

Dotted Line Represents Average Density

Law of Rectilinear DiameterAverage Density of Gas and Liquid in Equilibrium Will Plot a Straight Horizontal Line Passing Through the Critical Point

Pure Substances Vapour Density


Pure Substance Density-Temperature Diagram

Two Component Mixture

Behaviour Controlling Factors Types of Components

Proportion of each Component

Properties of Highest Proportion Component Dominates Mixtures Properties

Phase Diagram for Two Pure Components System

3

4

2

5

4532

Superheated

Vapour

Two Component Mixture Features of Two Components

System Bubble Point and Dew Point

DO NOT Occur at the Same Pressure

Point 3 Bubble Point

Point 4 Dew Point

Dotted Line Dew Point Line

Solid Line(100%) Bubble Point Line

Beyond Points 4 Superheated Vapour

Features of Two Components System

Two Components System Critical Point Meeting Point of Bubble and Dew Points

Liquid and Gas Properties are Identical

Liquid and Gas DO Co-exist Beyond Critical Pressure and Temperature

Phase Diagram for Two Pure Components System

3

4

2

5

4 532

Superheated

Vapour


Two Phase Region Region of Co-existence of Liquid and Gas

Made up of Liquid Content P-V Lines Lines of Different Proportions(%) of Liquid and Gas

Cricondentherm Temperature Above Which NO Liquid Can FORM REGARDLESS of Amount of PRESSURE Exerted

Cricondenbar Pressure Above Which NO Gas Can be FORMED out of Liquid REGARDLESS the Amount of TEMPERATURE INCREASE

Cricondentherm and Cricondenbar


Two Components Press-Volume

Diagram Two Components Pressure-Volume Pressure Decreases as System

Goes From Bubble Point to Dew Point

Slope of Curve Between the Two Points Due to Change in Composition of Liquid and Gas as System Goes Through Two Phase

Composition of Liquid is Equal to that of the Whole Mixture at Bubble Point Except that of the Bubble Which is Richer in More Volatile Components

At Dew Point Reverse is the Case

Press-Volume Diagram of Low Isotherms Have NO Dew Points

Pressure-Volume Diagram of Two-Components System

Pure Substances Properties

vs. Those of Their Mixture Two Components Pressure-

Volume Liquid and Gas Mixture Co-exist in Two Phase Region Between the Vapour-Pressure Lines of the Two Pure Substances

Mixture Critical Pressure is Above That of EITHER of the Two

Mixture Critical Temperature is Between Those of the Individual Components

Each Individual Component Influence on the Mixture Depends on Proportion of that

Component

Mixture Critical Point Tilts Towards that of Component with Highest Portion

Mixture Highest Critical Pressure Occurs at 50:50 Mixture

Mixture Two-Phase Region is Also Largest at 50:50 Mixture

Magnitude of Critical Pressure is Determined by Difference Between Components Molecular Sizes

Critical Point Locus is Dash Line Connecting ALL Critical Points of Possible Mixtures of the Components

Two Components System 50:50 Mixture Phase Diagram

Pure Substances Properties

vs. Those of Their Mixture

Methane-Ethane Seven Different Mixtures Phase Diagram

Critical Loci Methane-Decane Mixture

Ethane

Methane

Pure Substances Properties vs. Those of Their Mixture

Pure Substances Properties vs. Those of Their Mixture

100% C7H16

972.4 o R, 396.8 psia)

P

T

100% C2H6

(343 o R, 667.8 psia)

P

T

50% C2H650% C7H16

LIQUID

GAS LIQUID

GAS

Phase diagrams for (a) pure ethane and (b) pure heptane and (c) for a 50%-50% mixture of the two

Retrograde Conditions

Retrograde Condensation An Usual Formation of Liquid From Gas With Pressure Reduction

An Usual Decrease in Liquid Formation From Gas With Temperature Reduction

Region of Retrograde Occurrence Between Critical Temperature and Cricondentherm

Between Critical Pressure and Cricondenbar

Retrograde Vaporization An Usual Decrease in Condensation (Vaporization) with Pressure Increase

An Unusual Increased Formation of Gas(Vaporization) from Gas with Temperature Formation

Reaching Dew Point From Two Phase Region with Temperature Reduction

Retrograde Conditions

Multiple Components

Mixture Region of Equilibrium

Bubble Point and Dew Point Lines Bound Gas and Liquid Equilibrium Region

Separation Between Bubble Point and Dew Point Enhanced by: Number of Components

Diverse Sizes of the Components

Uses of Phase Diagram Determines Type of Reservoir Fluid System

Enables the Design of Most Efficient Method of Depletion

Enables the Design of Most Economic Method of Depletion

Enables the Design of Optimum Condition of Processing of reservoir Fluid

Used to Determine Most Economic and Efficient Method of Processing for Maximum Liquid Recovery

Types of Reservoirs From Phase Diagram

Multiple Components

Mixture

Types of Crude Oil and Gas Reservoirs

Low Shrinkage Reservoir Reservoir Conditions Above Bubble

Point

Reservoir Oil is Undersaturated

Crude Critical Temperature Greater than Reservoir Temperature

High % Liquid Recovery at Separator (85%)

Two Phase Region Covers Wide Range of Temperature

At P3 75% Reservoir Fluid Remains Liquid

Critical Point is to the Right of Reservoir Condition

.

High Shrinkage Reservoir Has High % of Press-Vapor Lines

Close Together

Consequently Higher % of Vapour Comes out Crude with Minimal Pressure Drop

Pressure Range Between Bubble Point and Low Liquid Content P-V Line is Very Short

Given Same Separation Conditions 65% Liquid Yield Will Be Realised at Separator

At P3, 40% Mole of Reservoir Fluid is Liquid

Critical Point is to the Right of Reservoir Condition


Increase in Reservoir Liquid as Pressure Drops

At Separator Conditions Only 25% Liquid is Recovered

At P3 Only 7% Mole Remains in Reservoir as Liquid

Critical Point is Close to the Centre of Two-Phase Region and to the LEFT of the Reservoir Condition.

Retrograde Gases also known asRetrograde Condensate GasesGas CondensatesCondensates

Retrograde Gas Condensate Reservoir


Wet Gas Reservoir Reservoir and P3 Conditions are ALL in Gas Phase

Separator Condition in Two Phase Region

ALL gas in Reservoir BUT Produces Liquid on Surface

Critical Point is to the Left of Two-Phase Region

3


Dry Gas Reservoir ALL Gas in ALL conditions

Critical Point is to the Left of Two-Phase Region

3


Properties of Natural Gas

Introduction Natural gas is gaseous mixture of methane, ethane, propane, butane, pentane, and

small amounts of hexanes and heavier and other impurities such as helium, carbon dioxide, hydrogen sulfide, and nitrogen.

It is an environmentally friendly clean fuel compared to other fossil fuels such as coal or crude oil due to its low to negligible emissions of sulfur dioxide, nitrous oxide and carbon dioxide.

These low emission helps to reduce problems of acid rain, ozone layer depletion, or greenhouse gases.

The detailed understanding of the properties of the natural gas is required to understand: the working mechanism of a natural gas reservoirthe efficient production of the reservoirthe processing of the produced natural gasthe principles and processes at play when this natural gas is subjected to changes in pressure and temperature.


Introduction Physically and in its pure form, natural gas is colorless,

odorless, tasteless, shapeless, and lighter than air

Units of Measurement of Natural GasVolume mm scf Energy British Thermal Unit(BTU). One Btu is the amount of natural gas that will produce enough energy to heat one pound of water by one degree at normal pressure.

One cubic foot of natural gas contains about 1,027 Btus.


Introduction Sale Specification

PressureTemperature, Hydrocarbon and water dew points.Calorific value, Wobbe index Acid gas content Appropriate odorization(with mercaptan also called a thiol)

Odorization ConditionThat user is able to detect gas presence by odor when the concentration reaches 1% of gas in air.

This is equivalent to one-fifth the lower limit of flammability of natural gas which is approximately 5%.

That the combustion of these trace amounts of odorant does not create any serious environmental pollution problems of sulfur content or toxicity.


Sources of Natural Gas Fossil Fuel Association

Oil Wells - Associated gas in solution (AG)Condensate Wells Natural Gas Wells - Non Associated Gas (NAG)

Coal Beds as Methane Clathrates Found dispersed throughout the pores and fractures of the coal bed.

Also created by methanogenic organisms in marshes, bogs and landfills

Town GasA mixture of methane and other highly toxic gases such as Carbon Dioxide from bituminous coal.


Sources of Natural Gas Synthetic Natural Gas (SNG)

Hydrocarbon Gas obtained by heating Coal or refining Heavy Hydrocarbons

Bio Gas (Natural Biogas)Methane-rich natural gas produced from anaerobic decay of non-fossil organic matter commonly called Biomass.

It is produced from agricultural waste, manure, etc, in anaerobic environment and also in swamps, marshes, landfills, sewage sludge and manure.


Sources of Natural GasLandfill Gas

Methane-Rich natural gas produced from the decomposition of waste materials in Landfills and contains other contaminants such as Water vapor, Carbon dioxide, Nitrogen, Oxygen, Hydrogen, Hydrogen Sulfide and Siloxane – in traces

Hydrates GasNatural gas (primarily methane) that exists in the form of

Hydrates under sediment offshore continental shelves and on land in arctic regions.

As at 2009 viable technology to produce natural gas economically from Hydrates is yet to be developed.


Classification of Natural Gas

S/N TYPE GOR API COMPOSITIONC1 C2 C3 C4 C5 C6+

1 Dry Gas 100 mscf/stb

0.9 0.0 - 5

0.0 - 3

0.01

0.0 - 1

0.0 - 1

2 We gas 100 mscf/stb

50 - 70

3 Condensate

18 - 70 mscf/stb

50 - 70

0.7 - 5

0.0 - 8

0.0 - 4

0.03

0.0 - 2

0.0 - 8

4 High Shrinkage(Volatile) Oil

800 scf/stb

40 - 50

0.6 - 5

0.0 - 8

0.0 - 5

0.04

0.0 - 3

0.1 - 5

5 LowShrinkage

(Black)Oil

500 scf/stb

30 - 40

0.4 - 4

0.0 - 4

0.0 - 4

0.03

0.0 - 2

0.4 - 3

6 Heavy Oil

0 20 - 25

0.2 - 0

0.0 - 3

0.0 - 2

0.02

0,0 - 2

0.7 - 5

7 Tar/Butimen

0 10 0.9 +

Classification and Composition of Reservoir Fluid or Petroleum.


Sources of Natural Gas Sour and Sweet Natural Gas

Sour Natural gas containing hydrogen sulfide (H2S) above statutory limit .

Sweet Natural gas containing hydrogen sulfide (H2S) below statutory limit or no H2S.

Generally, sweet means the gas contains less than 4 ppmv of H2S.

The amount of H2S allowable in pipeline-quality gas is between 0.25 and 1.0 grains per 100 scf (6 to 24 mg/Sm3, 4 to 16 ppmv).

Acidic Natural GasNatural gas containing carbon dioxide(CO2) and/or H2S above statutory limit and non-acidic if it has it below statutory limit or no CO2.


Sources of Natural Gas Natural Gas Liquid (NGL)

These are various shades of hydrocarbon liquids processed out of natural gas. They include:

• Propane, • Butane, • Pentane, • Hexane• Heptane+

Classification of NGL• Low Vapor Pressure NGL - Condensate• Intermediate Vapor Pressure NGL - Natural Gasoline• High Vapor Pressure NGL - LPG• Condensate

Very light and volatile mixture of liquid hydrocarbons that condense out of natural gas having gravity in the range between 500-700 API. It is transparent /straw white to light brown in colour

Natural Gas PropertiesWobbe Index

Wobbe Index (often referred to as the Wobbe number) is an indicator of fuel gas quality.

It also indicates Interchangeability of Fuel Gases

It actually compares the heat produced by a specific natural gas to that of Propane-Air mixture when they burns through a defined orifice in standard temperature and pressure

It therefore gives a measure of the heat input to an appliance through a given aperture at a given gas pressure.

It is an indicator of quality of fuel gas

The Wobbe index relates fuel gas heating characteristics in a manner that is useful for blending fuel gases.

Natural Gas PropertiesWobbe Index

Quantitatively defined as the ratio of Btu's per cubic foot to the square root of the specific gravity of the gas

Mathematically, it is defined as: Wobbe Index = Higher Heating value Square Root of Specific Gravity Units: Btu/SCF or Megajoules/SCM (1000 BTU/scf = 37.3 MJ/m3).

Higher Heating Value is the Gross Calorific Value or Gross Energy of a Fuel or the amount of heat released by specified fuel quantity Initially at 25°C and once it is combusted and the products have returned to a temperature of 25°C.

Natural Gas Properties

Wobbe IndexUses of Wobbe Index

To compare Energy Input into an appliance with different composition fuel gases.

Fuels having identical Wobbe Indices, for a given burner pressure will

Have Identical Energy Input. Produce an Equal Amount of Heat and Combustion Products Will Require Same Amount of Combustion Air.

It allows matching One Gas (in this case, Natural Gas) to a Replacement Gas (in This Case, Propane-air).


PTTPz

PnRT

PznRT

BSC

SC

SC

SCg

PTzBg 02827.0

air

gg M

M

iiYM

Natural Gas Specific GravityExampleCalculate the specific gravity of natural gas with the following composition


Components

Mole Fraction (Yi)

Molecular Weight (Mi)

MiYi

Methane C1 0.697Ethane C2 0.112Propane C3 0.096Butane C4 0.061Propane plusC5+

0.034

MiYi

air

gg M

M

iiYM

42.0345304.096.28

eqnMMMM

RTMP

RTMP

aa

air

a

sc

airsc

sc

asc

g

Natural Gas Specific GravitySpecific gravity of gas is defined as

where Mair molecular weight of air, which is equal to 29.Mg molecular weight of Natural Gas

Mi molecular weight of each component of the natural gas Yi mole fraction of each component of the natural gas

If both air and gas are assumed ideal mixtures, above equation can be expressed as

where g = gas specific gravityair = density of the airMair = apparent molecular weight of the air = 28.96Ma = apparent molecular weight of the gas

Psc = standard pressure, psia

Tsc = standard temperature, °R


Natural Gas DensityGas density is defined as mass per unit volume

and so can also be derived and calculated from the real gas law

ρg = m = PM V ZRTNow, the molecular weight of gas is product of specific gravity and

molecular weight of air and the value of R is 10.73 in field units

[8.314 in SI units], above equation can be written as;

ρg = 2.7 P γg

ZTwhere

ρg is in lbm/ft3, P is in psia, T is in 0R. γg = gas specific gravity


Natral gas and processing and transmission 1

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