Post on 22-Apr-2023
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
Reservoir Fluids Crude Oil Properties Crude Oil Density, Specific Gravity and API
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
Reservoir Fluids Crude Oil Properties Crude Oil Density, Specific Gravity and API
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
Reservoir Fluids Crude Oil Properties Gas Solubility
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
Reservoir Fluids Crude Oil Properties Gas Solubility
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
Reservoir Fluids Crude Oil Properties Formation Volume Factor(Bo)
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)
Reservoir Fluids Crude Oil Properties Formation Volume Factor(Bo)
*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.
Reservoir Fluids Crude Oil Properties Formation Volume Factor(Bo)
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
Reservoir Fluids Crude Oil Properties Formation Volume Factor(Bo)
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
Hydrocarbon Systems 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),
Pure Substances Phase Behaviour
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.
Hydrocarbon Systems Phase Behaviour
Pure Substances Phase Diagram Lines represent Phase Changes
Regions represents Phases
Pure Substances Phase Behaviour
Gas
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 Behaviour
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 Behaviour
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
Pure Substances Phase Behaviour
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 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
Pure Substances Vapour Pressure
and Temperature Relationship
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
Pure Substances Vapour Pressure
and Temperature Relationship
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
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
Pure Substances Vapour Pressure
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
Pure Substances Vapour Pressure
and Volume Relationship
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
Pure Substances Vapour Pressure
and Volume Relationship
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
and Temperature Relationship
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 Component Mixture
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 Component Mixture
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
Types of Crude Oil and Gas Reservoirs
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
Types of Crude Oil and Gas Reservoirs
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
Types of Crude Oil and Gas Reservoirs
Dry Gas Reservoir ALL Gas in ALL conditions
Critical Point is to the Left of Two-Phase Region
3
Types of Crude Oil and Gas Reservoirs
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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.
Properties of Natural Gas
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
Properties of Natural Gas
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
Properties of Natural Gas
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).
air
gg M
M
iiYM
Natural Gas Specific GravityExampleCalculate the specific gravity of natural gas with the following composition
Natural Gas Properties
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 Properties
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
Natural Gas Properties