COPYRIGHT. Reservoir Fluid Core. Single Phase, Single Component Systems. By the end of this lesson, you will be able to:

Single Phase, Single Component Systems Learning Objectives Reservoir Fluid Core Single Phase, Single Component Systems By the end of this lesson, you will be able to: Define terms used to describe the properties of a single phase, single component fluid. Describe how the properties of a single phase, single component fluid change with pressure and temperature. 1

Single Phase, Single Component Systems Species Liquids vs. Gases Pressure Liquid Phase Single component fluid = only one kind of molecule. The one molecule defines the species. Vapor Phase Temperature 2

Single Phase, Single Component Systems Volume vs. Temperature Volume Volume vs. Pressure Volume Pressure remains the same. Temperature Temperature remains the same. Pressure 3

Single Phase, Single Component Systems Volume vs. Temperature: Pressure Effect? Volume Increased Pressure Temperature Volume vs. Pressure: Temperature Effect? Volume Increased Temperature Pressure 4

Single Phase, Single Component Systems Equation of State Example: Ideal Gas Equation of State Where: P = pressure V = volume = the number of moles = the universal gas constant T = temperature How Steep? Coefficient of thermal expansion Volume changes with temperature. Mathematical relationships can be developed between pressure, volume, and temperature if volume is measured when conditions are varied. Compressibility Volume changes with pressure. 5

Single Phase, Single Component Systems How Steep? Coefficient of thermal expansion 1 Compressibility 1 Volume Density Pressure Volume Temperature 6

Single Phase, Single Component Systems Molar Volume Molecular Mass 7

Single Phase, Single Component Systems Density vs. Pressure Temperature remains the same. Density Density vs. Temperature Density Pressure Pressure remains the same. Temperature 8

Single Phase, Single Component Systems Fluid Gradient DEPTH Specific Gravity PRESSURE 9

Single Phase, Single Component Systems Specific Gravity Specific Gravity Alternative scale From American Petroleum Institute Usually employed for Oils 141.5 131.5 10

Single Phase, Single Component Systems Viscosity Dynamic Kinematic Oilfield: SI: mpa.s Viscosity vs. Pressure Viscosity Temperature remains the same. Oilfield: SI: m2 Kinematic viscosity is the dynamic viscosity divided by density. Pressure 11

Single Phase, Single Component Systems Viscosity vs. Temperature Viscosity Formation Volume Factor Pressure remains the same. Temperature 12

Single Phase, Single Component Systems Expansion Factor Inverse of formation volume factor Popular for gases Learning Objectives Define terms used to describe the properties of a single phase, single component fluid. Describe how the properties of a single phase, single component fluid change with pressure and temperature. 13

Single Component, Multiphase Systems Learning Objectives Reservoir Fluid Core Single Component, Multiphase Systems By the end of this lesson, you will be able to: Define terms used to describe the properties of a multi-phase, single component fluid. Describe how a single component fluid can transition from one phase to another. 1

Single Component, Multiphase Systems Vapor Pressure Curve Pressure Boiling Point Pressure Liquid Phase Temperature Vapor Pressure Curve Vapor Phase Boiling Point Vapor Pressure Curve Temperature 2

Single Component, Multiphase Systems Boiling Point vs Pressure and the Critical Point Pressure Interfacial Tension Describes the strength of the surface that forms between two fluids. Also known as Surface Tension. Temperature Vapor Pressure Curve Critical Point Critical density (Both fluids have the same density) Interfacial tension is 0 3

Single Component, Multiphase Systems Liquid Properties vs. Pressure Pressure Vapor Properties vs. Pressure Pressure Liquid Phase Temperature Vapor Pressure Curve Vapor Phase Critical Point Vapor Pressure Curve Critical Point Temperature 4

Single Component, Multiphase Systems Interfacial Tension Phase Transitions Pressure Liquid Phase Vapor Pressure Curve Vapor Phase Temperature 5

Single Component, Multiphase Systems Phase Transitions at Constant Temperature Pressure Phase Transitions Liquid Temperature Vapor 6

Single Component, Multiphase Systems Learning Objectives Define terms used to describe the properties of a multi-phase, single component fluid. Describe how a single component fluid can transition from one phase to another. 7

Multi-Component, Multiphase Systems Learning Objectives Reservoir Fluid Core Multi-Component, Multiphase Systems By the end of this lesson, you will be able to: Describe how multi-component fluids behave differently from single component fluids. Define terms used to describe multi-component fluids. 1

Multi-Component, Multiphase Systems Binary Mixtures Heavy Component Light component, A Heavy component, B Light component, A Heavy component, B Vapor Pressure Curves 2

Multi-Component, Multiphase Systems Critical Point Critical Point Phase Envelope Where two phases exist in equilibrium Light component, A Heavy component, B Vapor Pressure Curves Light component, A Phase Envelope Critical Point Heavy component, B Vapor Pressure Curves 3

Multi-Component, Multiphase Systems Pseudo-Critical Point Moves around depending on composition of mixture Pseudo Critical Point Multi-Phase Light component, A Phase Envelope Heavy component, B Vapor Pressure Curves Light component, A Pseudo Critical Point Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves 4

Multi-Component, Multiphase Systems Single Phase Pseudo Critical Point Binary Mixtures Liquid Phase Liquid Phase Light component, A Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Vapor Phase Light component, A Pseudo Critical Point Still Liquid Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Vapor Phase 5

Multi-Component, Multiphase Systems Binary Mixtures Pseudo Critical Point Saturated Liquid Phase Still Liquid Liquid Phase Still Liquid Light component, A Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Light component, A Vapor Phase All Vapor Pseudo Critical Point Saturated Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Vapor Phase All Vapor 6

Multi-Component, Multiphase Systems Under-Saturated Pseudo Critical Point Bubble Points Still Liquid Light component, A Saturated Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Light component, A Pseudo Critical Point Bubble Point Saturated Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Undersaturated Liquid Phase liquid Still Liquid Vapor Undersaturated Phase All Vapor Vapor Undersaturated Liquid Phase liquid Vapor Undersaturated Phase All Vapor Vapor 7

Multi-Component, Multiphase Systems Dew Points Pseudo Critical Point Quality Lines Still Liquid Bubble Point Light component, A Saturated Two Phase Envelope Phases Heavy component, B Vapor Pressure Curves Dew Point Undersaturated Liquid Phase liquid Vapor Undersaturated Phase All Vapor Vapor 8

Multi-Component, Multiphase Systems Multi-Component Mixtures Phase Transitions Bubble Point 75% 9

Multi-Component, Multiphase Systems Bubble Point? B Key B Bubble point Volume Initial Conditions? Volume B Pressure A Key B Bubble point A Initial conditions Oil volume is smaller than it is at bubble point because of compression. Pressure 10

Multi-Component, Multiphase Systems 75% Liquid? B Key B Bubble point A Initial conditions C 75% liquid point A Volume Bubble Point? Solution gas oil ratio C B Pressure Inside of the phase envelope, the volume of the oil is smaller than at bubble point because of the vaporization of the gas. Key B Bubble point Pressure 11

Multi-Component, Multiphase Systems Initial Conditions? B Key B Bubble point A Initial conditions A Solution gas oil ratio Density Density B Pressure Key B Bubble point Density increases above the bubble point because of compression, and increases below bubble point because of the loss of lighter ends. Pressure 12

Multi-Component, Multiphase Systems Viscosity Key B Bubble point Viscosity Learning Objectives B Pressure Density Oil viscosity increases increases above both the above bubble and point below bubble because point pressure. of compression, and increases below bubble point because of the loss of lighter ends. Describe how multi-component fluids behave differently from single component fluids. Define terms used to describe multi-component fluids. 13

Reservoir Fluid Types Learning Objectives Reservoir Fluid Core Reservoir Fluid Types By the end of this lesson, you will be able to: Describe how reservoir fluids can be categorized based on physical behavior. Describe how phase transitions in the reservoir vary based on fluid type. 1

Reservoir Fluid Types Reservoir Fluid Types Bitumen Oil Black Oil Reservoir Fluids Reservoir Fluid Types Reservoir Fluids Gas Oil Volatile Oil Gas Condensate Wet Gas Dry Gas Bitumen Black Oil Volatile Oil Gas Condensate Liquid phase Gas Wet Gas Dry Gas 2

Reservoir Fluid Types Reservoir Fluid Types Bitumen Oil Black Oil Liquid phase Oil Reservoir Reservoir Fluids Gas GAS CAP Volatile Oil Gas Condensate Wet Gas Dry Gas Vapor phase 3

Reservoir Fluid Types Gas Cap Requirement Where is the reservoir pressure and temperature? Gas Cap Requirement inside the total fluid phase envelope. Where is the reservoir pressure and temperature? inside the total fluid phase envelope. on the bubble point line of the oil phase envelope for equilibrium conditions. 4

Reservoir Fluid Types Gas Cap Requirement Where is the reservoir pressure and temperature? Black Oil inside the total fluid phase envelope. on the bubble on the point dew line point curve of the oil phase of the envelope gas phase envelope for equilibrium for equilibrium conditions. conditions. Reservoir Fluids Oil Bitumen Black Oil Volatile Oil Gas Condensate Gas Wet Gas Dry Gas 5

Reservoir Fluid Types Black Oil Low Shrinkage Oils Under Saturated Bubble Point Pressure Volatile Oil Reservoir Fluids Oil Bitumen Black Oil Volatile Oil Gas Condensate Gas Wet Gas Dry Gas 6

Reservoir Fluid Types Volatile Oil High Shrinkage Oils Volatile Oil High Shrinkage Oils Volatile Oil 7

Reservoir Fluid Types Volatile Oil High Shrinkage Oils Lighter Lower viscosities Higher producing gas-oil ratios Reservoir temperatures tend to be closer to the critical temperature Gas Condensate Reservoir Fluids Oil Bitumen Black Oil Volatile Oil Gas Condensate Gas Wet Gas Dry Gas 8

Reservoir Fluid Types Gas Condensate Under Saturated Gas Condensate 9

Reservoir Fluid Types Gas Condensate Saturated Gas Condensate 10

Reservoir Fluid Types Gas Condensate Gas Condensate 11

Reservoir Fluid Types Gas Condensate Gas Condensate Return to single phase Condensate refers to liquefied hydrocarbons 12

Reservoir Fluid Types Wet Gas Bitumen Oil Black Oil Wet Gas Reservoir Fluids Gas Volatile Oil Gas Condensate Wet Gas Dry Gas 13

Reservoir Fluid Types Dry Gas Bitumen Oil Black Oil Dry Gas Reservoir Fluids Gas Volatile Oil Gas Condensate Wet Gas Dry Gas 14

Reservoir Fluid Types Dry Gas Dry Gas Most dry gases actually do produce small quantities of hydrocarbon condensate when brought to the surface. 15

Reservoir Fluid Types Dry Gas The practical line between dry and wet is based on how much condensate is significant. Dry Gas Water drop-out at the surface is possible with a dry gas. (per reservoir engineering definition.) 16

Reservoir Fluid Types Example Phase Envelopes Pressure Dry Wet Example Phase Envelopes Pressure Black Volatile Retrograde Temperature Black Volatile Retrograde Wet The heavier the fluid, the larger the phase envelope will be. Dry Temperature 17

Reservoir Fluid Types Can a wet gas and a gas condensate have the same composition? Gas Condensate Wet Gas Can a volatile oil and a gas condensate share the same composition? Volatile Oil Gas Condensate 18

Reservoir Fluid Types Learning Objectives Describe how reservoir fluids can be categorized based on physical behavior. Describe how phase transitions in the reservoir vary based on fluid type. 19

Oil & Gas Types Learning Objectives Reservoir Fluid Core Oil & Gas Types By the end of this lesson, you will be able to: Describe how oils and gases can be categorized based on chemical makeup. Describe how oil type is based on the oil history. Describe how basic oil properties vary with chemical makeup. 1

Oil & Gas Types Recent Source Recent Source Reservoir Oil Reservoir Oil Surface Oil Surface Oil Reservoir Gas Reservoir Gas Crude Condensate 2

Oil & Gas Types Lighter Crudes Heavier Crudes 3

Oil & Gas Types Oil Types Paraffinic Lighter Colorful Yield: Lots of wax Great lubricants Paraffinic Mixed No strong characteristics Naphthenic Heavier Black Yield: Lots of asphalt Great gasoline Recent Source Reservoir Oil Surface Oil Reservoir Gas Mixed Naphthenic Crude Condensate 4

Oil & Gas Types Gas Condensates Recent Source Surface Oil Reservoir Reservoir Oil Gas Crude Falls Out Forced Out Seriously Forced Out 5

Oil & Gas Types Recent Source Surface Oil Ancient Source Reservoir Oil Reservoir Gas Crude Natural Gas Liquids (NGL) Liquified Petroleum Gas (LPG) Liquified Natural Gas (LNG) 6

Oil & Gas Types Ancient Source Ancient Source 7

Oil & Gas Types Legal Source Learning Objectives Describe how oils and gases can be categorized based on chemical makeup. Describe how oil type is based on the oil history. Describe how basic oil properties vary with chemical makeup. 8

Fluid Components Learning Objectives Reservoir Fluid Core Fluid Components By the end of this lesson, you will be able to: State the names and nick-names for the major, naturally occurring hydrocarbon families. Describe the differences in molecular arrangement between the families. Define carbon numbers and isotopes. Describe how component properties vary with carbon number within a hydrocarbon family. 1

Fluid Components Hydrogen and Carbon Hydrocarbon Families Hydrocarbons Aliphatics Paraffins Aromatics Olefins Acetylenes Cycloparaffins 2

Fluid Components Oil Types Paraffinic Hydrocarbon Families Hydrocarbons Naphthenic Mixed Aliphatics Paraffins Aromatics Olefins Acetylenes Cycloparaffins 3

Fluid Components Hydrocarbon Families Paraffins Hydrocarbons Hydrocarbon Families Hydrocarbons Aliphatics Aromatics Aliphatics Olefins Acetylenes These are also saturated hydrocarbons. Paraffins Aromatics Yet to find a petroleum deposit dominated by members of this family. Olefins Acetylenes Cycloparaffins Cycloparaffins 4

Fluid Components Hydrocarbon Families Paraffins Hydrocarbons Hydrocarbon Families Hydrocarbons Aliphatics Aromatics Also called: Alkanes Saturated hydrocarbons Aliphatics Aromatics Olefins Acetylenes Paraffins Olefins Acetylenes Cycloparaffins Cycloparaffins Not found in natural petroleum 5

Fluid Components Paraffins Paraffins 6

Fluid Components Paraffins (Carbon atoms are identified by.) Saturated (Paraffins): Absence of double or triple bonds between carbon atoms Hydrocarbon Families Hydrocarbons Aliphatics Paraffins Aromatics Olefins Acetylenes Cycloparaffins Also called: Naphthenes Alicyclic hydrocarbons Cyclo alkanes 7

Fluid Components Cyclo-paraffins Hydrocarbon Families Hydrocarbons Aliphatics Paraffins Aromatics Also called: Arenes Aryl hydrocarbons Olefins Acetylenes Cycloparaffins 8

Fluid Components Aromatics Carbon Number Methane Ethane Propane Butane Hexane 9

Fluid Components Isomers Different molecules belonging to the same family can have the same number of carbon atoms. Example: Isomers Number of Isomers 400 350 300 250 200 150 100 Normal Butane Iso Butane Branched carbon chain 50 0 0 1 2 3 4 5 6 7 8 9 10 11 12 Carbon Number 10

Fluid Components Light Components Component Carbon Number M w [lb-mol] T b [ o F] Oilfield version T c [ o F] P c [psia] V c [cuft/lbm] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 4 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 5 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S Not hydrocarbons but commonly 0 34.08-76.50 212.45 found in hydrocarbon fluids. 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Light Components Oilfield version Component Carbon M w T b T c P c V c Z c ω γ o Number [lb-mol] [ o F] [ o F] [psia] [cuft/lbm] [ ] [ ] [ ] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 4 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 5 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S Not hydrocarbons but commonly 0 34.08-76.50 212.45 found in hydrocarbon fluids. 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Z c [ ] ω [ ] γ o [ ] 11

Fluid Components Light Components Component Carbon Number CH4 M w [lb-mol] T b [ o F] Oilfield version T c [ o F] P c [psia] V c [cuft/lbm] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 4 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 5 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S 0 34.08-76.50 212.45 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Light Components Oilfield version Component Carbon M w T b T c P c V c Z c ω γ o Number [lb-mol] [ o F] [ o F] [psia] [cuft/lbm] [ ] [ ] [ ] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 Normal 4 paraffin 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 5 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S 0 34.08-76.50 212.45 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Z c [ ] ω [ ] γ o [ ] 12

Fluid Components Light Components Component Carbon Number M w [lb-mol] T b [ o F] Oilfield version T c [ o F] P c [psia] V c [cuft/lbm] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 4 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 Branched 5 paraffin 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S 0 34.08-76.50 212.45 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Light Components Oilfield version Component Carbon M w T b T c P c V c Z c ω γ o Number [lb-mol] [ o F] [ o F] [psia] [cuft/lbm] [ ] [ ] [ ] C1 1 16.04-258.73-116.67 666.40 0.0988 0.2867 0.0104 0.3000 C2 2 30.07-127.49 89.92 706.50 0.0783 0.2819 0.0979 0.3562 C3 3 44.10-43.75 206.06 616.00 0.0727 0.2763 0.1522 0.5070 ic4 4 58.12 10.78 274.46 527.90 0.0714 0.2779 0.1852 0.5629 nc4 4 58.12 31.08 305.62 550.60 0.0703 0.2738 0.1995 0.5840 ic5 5 72.15 82.12 369.10 490.40 0.0679 0.2700 0.2280 0.6247 nc5 5 72.15 96.92 385.80 488.60 0.0675 0.2621 0.2514 0.6311 nc6 6 86.18 155.72 453.60 436.90 0.0688 0.2642 0.2994 0.6638 nc7 7 100.20 209.16 512.70 396.80 0.0691 0.2632 0.3494 0.6882 nc8 8 114.23 258.21 564.22 360.70 0.0690 0.2586 0.3977 0.7070 nc9 9 128.26 303.47 610.68 331.80 0.0684 0.2533 0.4445 0.7219 nc10 10 142.29 345.48 652.00 305.20 0.0679 0.2471 0.4898 0.7342 CO2 0 44.01-109.26 87.91 1071.00 0.0344 0.2757 0.2667 0.8180 H2S 0 34.08-76.50 212.45 1300.00 0.0461 0.2830 0.0948 0.8014 N2 0 28.01-320.45-232.51 493.70 0.0510 0.2889 0.0372 0.8094 Note: For reference, the SI version of this table follows. Z c [ ] ω [ ] γ o [ ] 13

Fluid Components Light Components Component Carbon Number M w [g-mol] T b [ o C] SI version T c [ o C] P c [kpa] V c [m 3 /kg] C1 1 16.04-161.51-82.59 4594.67 1.5826 0.2867 0.0104 0.3000 C2 2 30.07-88.60 32.18 4871.15 1.2542 0.2819 0.0979 0.3562 C3 3 44.10-42.08 96.71 4247.17 1.1645 0.2763 0.1522 0.5070 ic4 4 58.12-11.78 134.71 3639.74 1.1437 0.2779 0.1852 0.5629 nc4 4 58.12-0.51 152.02 3796.25 1.1261 0.2738 0.1995 0.5840 ic5 5 72.15 27.85 187.28 3381.19 1.0877 0.2700 0.2280 0.6247 nc5 5 72.15 36.07 196.56 3368.78 1.0812 0.2621 0.2514 0.6311 nc6 6 86.18 68.74 234.23 3012.32 1.1021 0.2642 0.2994 0.6638 nc7 7 100.20 98.43 267.06 2735.84 1.1069 0.2632 0.3494 0.6882 nc8 8 114.23 125.68 295.68 2486.94 1.1053 0.2586 0.3977 0.7070 nc9 9 128.26 150.82 321.49 2287.68 1.0957 0.2533 0.4445 0.7219 nc10 10 142.29 174.16 344.45 2104.28 1.0877 0.2471 0.4898 0.7342 CO2 0 44.01-78.47 31.07 7384.29 0.5510 0.2757 0.2667 0.8180 H2S 0 34.08-60.27 100.26 8963.18 0.7385 0.2830 0.0948 0.8014 N2 0 28.01-195.80-146.94 3403.94 0.8169 0.2889 0.0372 0.8094 Typical Compositions Component Dry Gas Wet Gas Retrograde Gas Volatile Oil Black Oil [mol%] [mol%] [mol%] [mol%] [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Z c [ ] ω [ ] γ o [ ] 14

Fluid Components Typical Compositions Component Component Dry Gas [mol%] Typical Compositions Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Dry Gas [mol%] Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 15

Fluid Components Typical Compositions Component Component Dry Gas [mol%] Typical Compositions Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Dry Gas [mol%] Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 Lighter 1.72 Fluids 0.28 Heavier 0.71 Fluids0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 16

Fluid Components Typical Compositions Component Dry Gas [mol%] Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Total 100.00 100.00 100.00 100.00 100.00 MWC7+ - 130 184 228 274 SGC7+ - 0.763 0.816 0.858 0.920 Typical Compositions Component Dry Gas [mol%] Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Total 100.00 100.00 100.00 100.00 100.00 MWC7+ - 130 184 228 274 SGC7+ - 0.763 0.816 0.858 0.920 17

Fluid Components Typical Compositions Component Dry Gas [mol%] Wet Gas [mol%] Retrograde Gas [mol%] Volatile Oil [mol%] Black Oil [mol%] CO2 0.10 1.41 2.37 0.93 0.02 N2 2.07 0.25 0.31 0.21 0.34 C1 86.12 92.46 73.19 58.77 34.62 C2 5.91 3.18 7.80 7.57 4.11 C3 3.58 1.01 3.55 4.09 1.01 ic4 1.72 0.28 0.71 0.91 0.76 nc4-0.24 1.45 2.09 0.49 ic5 0.50 0.13 0.64 0.77 0.43 nc5-0.08 0.68 1.15 0.21 C6-0.14 1.09 1.75 1.61 C7+ - 0.82 8.21 21.76 56.40 Total 100.00 100.00 100.00 100.00 100.00 MWC7+ - 130 184 228 274 SGC7+ - 0.763 0.816 0.858 0.920 Correlations and Predictions Reservoir Fluid Initial Producing Gas-Oil Ratio [scf/stb] [m3/m3] C7+ Fraction in Initial Reservoir Fluid [mol%] Dry Gas > 100,000 > 17810.8 < 0.5 Wet Gas 15,000 100,000 2671.6 17810.8 0.5 4.0 Gas Condensate 3,200 15,000 569.9 2671.6 4.0 12.9 Volatile Oil 1,900 3,200 338.4 569.9 12.9 18.0 Black Oil < 1,500 < 267.2 > 26.5 18

Fluid Components Five Fluid Types Table 4-8 Guidelines for Determining Fluid Type from Field Data Black Oil Volatile Oil Retrograde Gas Wet Gas Dry Gas Initial producing gas/liquid ratio, scf/stb <1,750 1,750 to 3,200 >3,200 >15,000* 100,000* Initial stock-tank liquid gravity, o API <45 >40 >40 Up to 70 No liquid Color of stock-tank liquid Dark Colored Lightly colored Water white No liquid *For engineering purposes Table 4-9 Expected Results of Laboratory Analysis of the Five Fluid Types Black Oil Volatile Oil Retrograde Gas Wet Gas Dry Gas Phase change in reservoir Bubblepoint Bubblepoint Dewpoint No phase change No phase change Heptanes plus, mol% >20% 20 to 12.5 <12.5 <4* <0.7* Oil FVF at bubblepoint <2.0 >2.0 *For engineering purposes Molecular Mass M w [lb/mol] or [g/mol] 0 2 4 6 8 10 Carbon Number [ ] 19

Fluid Components Normal Boiling Point T b [ o F] or [ o C] 0 2 4 6 8 10 Critical Temperature T c [ o F] or [ o C] Carbon Number [ ] 0 2 4 6 8 10 Carbon Number [ ] 20

Fluid Components Critical Pressure P c [psia] or [kpa] 0 2 4 6 8 10 Critical Volume v c [cuft/lb] or [m 3 /kg] Carbon Number [ ] 0 2 4 6 8 10 Carbon Number [ ] 21

Fluid Components Critical Compressibility Factor 0.29 0.285 0.28 Z c [ ] 0.275 0.27 0.265 0.26 0.255 0.25 0.245 0 2 4 6 8 10 Acentric Factor ω [ ] Carbon Number [ ] 0 2 4 6 8 10 Carbon Number [ ] 22

Fluid Components Specific Gravity γ o [1/air] 0 2 4 6 8 10 Learning Objectives Carbon Number [ ] State the names and nick-names for the major, naturally occurring hydrocarbon families. Describe the differences in molecular arrangement between the families. Define carbon numbers and isotopes. Describe how component properties vary with carbon number within a hydrocarbon family. 23

Fluid Sampling Learning Objectives Reservoir Fluid Core Fluid Sampling By the end of this lesson, you will be able to: Describe the different methods available for obtaining representative fluid samples. List the strength and weaknesses of each method. 1

Fluid Sampling Sampling Surface Separator Samples Surface Separator Samples Down-hole Wellbore Samples Down-hole Formation Samples 2

Fluid Sampling Surface Separator Samples Surface Separator Samples 3

Fluid Sampling Surface Separator Samples Surface Sample Issues Steady Rates The well must be flowing into the separator at a steady rate. Saturation Pressure The bubble point of the oil or the dew point of the gas in the reservoir needs to be below the flowing bottom hole pressure of the well flowing into the separator. Air Surface samples cannot contain air. Single Phase The oil sample needs to be 100% liquid and the gas sample has to be 100% vapour. Water Production Reduces probability of steady flow and single phase samples. 4

Fluid Sampling Down-hole Wellbore Samples Wellbore Sample Issues Saturation Pressure If multiphase flow starts upstream of the sample point, there is absolutely no guarantee that the sample taken is representative. Sample Size Downhole sample containers are smaller so less fluid is available for laboratory experiments. Obtaining more samples costs more. Water Production Less flexibility in limiting water capture in sample, further reducing the sample size. Drilling Mud OBM less easily separated in the lab. 5

Fluid Sampling Formation Samples Learning Objectives Describe the different methods available for obtaining representative fluid samples. List the strength and weaknesses of each method. 6

Fluid Laboratory Experiments I Learning Objectives Reservoir Fluid Core Fluid Laboratory Experiments I By the end of this lesson, you will be able to: Describe the different types of laboratory experiments that are routinely carried on oil, water, and gas samples. Pull important information out of reports based on laboratory experiments. 1

Fluid Laboratory Experiments I Laboratory Experiments Constant Mass Expansion Differential Liberation Constant Volume Depletion Separator Test Single Stage Flash Gas Chromatograph Water Samples Constant Mass Expansion 2

Fluid Laboratory Experiments I Constant Mass Expansion Constant Mass Expansion 3

Fluid Laboratory Experiments I Constant Mass Expansion Constant Mass Expansion Bubble Point Pressure Estimate 4

Fluid Laboratory Experiments I Constant Mass Expansion Bubble Point Pressure Estimate Volume Estimate Constant Mass Expansion Bubble Point Pressure Estimate Also called: Constant Composition Expansion Volume Estimate 5

Fluid Laboratory Experiments I Constant Mass Expansion Report Constant Mass Expansion Report 6

Fluid Laboratory Experiments I Constant Mass Expansion Report Constant Mass Expansion Report 7

Fluid Laboratory Experiments I Constant Mass Expansion Report Constant Mass Expansion Report 8

Fluid Laboratory Experiments I Differential Liberation Differential Liberation Pressure reduced Fluid expands Gas phase formed Fluid equilibrates Two phases in cell 10

Fluid Laboratory Experiments I Differential Liberation Differential Liberation Gas is extracted at constant pressure, reducing the volume of the cell and returning the oil saturation to 100%. Remove gas at the right speed. Too fast? Pressure drop Too slow? Composition change 11

Fluid Laboratory Experiments I Differential Liberation Differential Liberation The mass, volume and composition of the removed gas is measured. Note: No material removed in Constant Mass Expansion Volume of the remaining fluid will increase. Second gas saturation develops. 12

Fluid Laboratory Experiments I Differential Liberation Differential Liberation What happens? Volume decreases Mass of fluid decreases Pressure remains unchanged* Repeat the steps 13

Fluid Laboratory Experiments I Differential Liberation Differential Liberation until the pressure reaches atmospheric pressure. 14

Fluid Laboratory Experiments I Differential Liberation Differential Liberation 15

Fluid Laboratory Experiments I Differential Liberation Report 16

Fluid Laboratory Experiments I 17

Fluid Laboratory Experiments I 18

Fluid Laboratory Experiments I 19

Fluid Laboratory Experiments I 20

Fluid Laboratory Experiments I 21

Fluid Laboratory Experiments I Differential Liberation Report 22

Fluid Laboratory Experiments I Separator Test Separator Test Formation Separator Specific Separator Separator Gas/Oil Gas/Oil Stock Tank Volume Volume Gravity of Pressure Temperature Ratio Ratio Gravity Factor Factor Flashed Gas [psig] [ o F] [1] [2] [ o API @ 60 o F] [3] [4] 23 100 648 680 1.049 0.885 0 60 42 42 43.2 1.472 1.000 1.579 [1] [2] [3] [4] Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ indicated pressure and temperature. Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ 60 o F. Formation Volume Factor is barrels of saturated oil @ 2620 PSI gauge and 220 o F per barrel of stock tank oil @ 60 o F. Separator Volume Factor is barrels of oil @ indicated pressure and temperature per barrel of stock tank oil @ 60 o F. 24

Fluid Laboratory Experiments I Separator Test Formation Separator Specific Separator Separator Gas/Oil Gas/Oil Stock Tank Volume Volume Gravity of Pressure Temperature Ratio Ratio Gravity Factor Factor Flashed Gas [psig] [ o F] [1] [2] [ o API @ 60 o F] [3] [4] 23 100 648 680 1.049 0.885 0 60 42 42 43.2 1.472 1.000 1.579 [1] [2] [3] [4] Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ indicated pressure and temperature. Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ 60 o F. Separator Test Formation Volume Factor is barrels of saturated oil @ 2620 PSI gauge and 220 o F per barrel of stock tank oil @ 60 o F. Separator Volume Factor is barrels of oil @ indicated pressure and temperature per barrel of stock tank oil @ 60 o F. Formation Separator Specific Separator Separator Gas/Oil Gas/Oil Stock Tank Volume Volume Gravity of Pressure Temperature Ratio Ratio Gravity Factor Factor Flashed Gas [psig] [ o F] [1] [2] [ o API @ 60 o F] [3] [4] 23 100 648 680 1.049 0.885 0 60 42 42 43.2 1.472 1.000 1.579 [1] [2] [3] [4] Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ indicated pressure and temperature. Gas/Oil Ratio in cubic feet of gas @ 60 o F and 14.65 PSI absolute per barrel of oil @ 60 o F. Formation Volume Factor is barrels of saturated oil @ 2620 PSI gauge and 220 o F per barrel of stock tank oil @ 60 o F. Separator Volume Factor is barrels of oil @ indicated pressure and temperature per barrel of stock tank oil @ 60 o F. 25

Fluid Laboratory Experiments I Single Stage Flash Fluid Laboratory Experiments Part I Constant Mass Expansion Differential Liberation Constant Volume Depletion Separator Test Single Stage Flash Gas Chromatograph Water Samples Continue to Part II for a review of the remaining topics. 28

Fluid Laboratory Experiments II Laboratory Experiments Constant Mass Expansion Differential Liberation Constant Volume Depletion Separator Test Single Stage Flash Gas Chromatograph Water Samples Reservoir Fluid Core Fluid Laboratory Experiments II 1

Fluid Laboratory Experiments II Constant Volume Depletion Fluid in PVT cell at reservoir temperature and saturation pressure Oil saturation pressure = bubble point pressure Gas saturation pressure = dew point pressure Constant Volume Depletion Saturation pressure is determined beforehand by performing the constant mass expansion. 2

Fluid Laboratory Experiments II Constant Volume Depletion The cell volume is measured and recorded after the fluid sample equilibrates. Constant Volume Depletion Pressure reduced Volume increases Temperature is constant Second phase forms For oil, the second phase is gas For a retrograde gas condensate sample, it is oil 3

Fluid Laboratory Experiments II Constant Volume Depletion Cell returns to original volume Remove gas at constant pressure and temperature. Cell contents will be two phase. Constant Volume Depletion Cell returns to original volume Measure the mass, volume and properties of the gas removed from the cell. 4

Fluid Laboratory Experiments II Constant Volume Depletion Cell returns to original volume Measure the position of the interface between the phases to calculate the volume of the remaining second phase. Constant Volume Depletion Pressure reduced Volume increases 5

Fluid Laboratory Experiments II Constant Volume Depletion Cell returns to original volume Remove only gas at constant temperature. Constant Volume Depletion Cell returns to original volume Measure and record the mass, volume and properties of the gas removed from the cell, as well as the position of the interface separating the remaining fluids in the cell. 6

Fluid Laboratory Experiments II Constant Volume Depletion Constant Volume Depletion This minimum pressure is usually well above atmospheric. In order for the expanded sample to fit in the PVT cell at the end of each expansion phase (typically performed on volatile oil and gas condensate samples), either: the number of pressure steps has to increase (increasing costs) or the original size of the sample has to be decreased (decreasing accuracy) 7

Fluid Laboratory Experiments II Constant Volume Depletion This minimum pressure is usually well above atmospheric. The measurement of the residual liquid volume is not key to the interpretation of the test. Constant Volume Depletion 8

Fluid Laboratory Experiments II Constant Volume Depletion Second phase volume Constant Volume Depletion Report 9

Fluid Laboratory Experiments II Constant Volume Depletion Constant Volume Depletion 10

Fluid Laboratory Experiments II Constant Volume Depletion Constant Volume Depletion 11

Fluid Laboratory Experiments II Constant Volume Depletion Fluid Compositions Constant Volume Depletion Fluid Compositions 13

Fluid Laboratory Experiments II Volatile Analysis Corporation Huntsville AL Stock Tank Liquid Chromatogram 14

Fluid Laboratory Experiments II Volatile Analysis Corporation Huntsville AL Separator Liquid Composition 15

Fluid Laboratory Experiments II Separator Liquid Composition Separator Liquid Composition Proportions 16

Fluid Laboratory Experiments II Separator Liquid Composition Laboratory Experiments Constant Mass Expansion Differential Liberation Constant Volume Depletion Separator Test Single Stage Flash Gas Chromatograph Water Samples 17

Fluid Laboratory Experiments II Water Sample Report Water Sample Report Summary TDS: total dissolved solids ph: a measure of the acidity of the sample, with 7 being neutral Concentrations Dissolved 18

Fluid Laboratory Experiments II Stiff Diagram Two Samples on Same Plot 19

Fluid Laboratory Experiments II Learning Objectives Describe the different types of laboratory experiments that are routinely carried on oil, water, and gas samples. Pull important information out of reports based on laboratory experiments. 20

Adjusting Fluid Data to Separator Conditions Learning Objectives Reservoir Fluid Core Adjusting Fluid Data to Separator Conditions By the end of this lesson, you will be able to: Explain why laboratory data has to be adjusted before it can be used in engineering calculations. Adjust oil formation volume factors to separator conditions. Adjust solution gas-oil ratios to separator conditions. 1

Adjusting Fluid Data to Separator Conditions 2

Adjusting Fluid Data to Separator Conditions Final oil volume in the differential liberation test is more analogous to the residual oil volume at the end of production. Final oil volume in the separator test better represents the oil that would be sold from the field (early life). 3

Adjusting Fluid Data to Separator Conditions Convert all relative volumes to a stock tank oil basis. 4

Adjusting Fluid Data to Separator Conditions McCain Adjustments Where: R s (p) = converted solution gas-oil ratio for the pressure of interest R sd (p) = differential test solution gas-oil ratio (at the pressure of interest) R sfb = solution gas-oil ratio from the separator experiment (conditions at the bubble point pressure) R sdb = differential test solution gas-oil ratio (at bubble point pressure) Where: B o (p) = converted oil formation volume factor for the pressure of interest B od (p) = differential test oil formation volume factor (at the pressure of interest) B ofb = oil formation volume factor from the separator experiment (conditions at the bubble point pressure) B odb = differential test oil formation volume factor (at bubble point pressure) Differential Liberation Test Solution Gas-Oil Ratios 5

Adjusting Fluid Data to Separator Conditions Corrected Differential Liberation Test Oil Formation Volume Factors 6

Adjusting Fluid Data to Separator Conditions Corrected Constant Composition Expansion Test 7

Adjusting Fluid Data to Separator Conditions Under-saturated Adjustments Where: Rs ( p) R B ( p) B o sfb ofb V t (p) = relative volume from the constant mass expansion test at the pressure of interest V b = relative volume from the constant mass expansion test at bubble point pressure B ofb = oil formation volume factor from the separator experiment Final Solution Gas-Oil Ratio V t ( p) Vb 8

Adjusting Fluid Data to Separator Conditions Final Formation Volume Factor Learning Objectives Explain why laboratory data has to be adjusted before it can be used in engineering calculations. Adjust oil formation volume factors to separator conditions. Adjust solution gas-oil ratios to separator conditions. 9

Cubic Equations of State Learning Objectives Reservoir Fluid Core Cubic Equations of State By the end of this lesson, you will be able to: Describe how cubic equations of state handle non-ideal behavior. Describe how liquid and gas volumes are calculated from an equation of state. Describe how cubic equations of state handle mixtures of components. 1

Cubic Equations of State Equations of State Ideal Gas Law Real Gas Law van der Waals Redlich-Kwong Soave-Redich-Kwong Peng-Robinson Ideal Gas Law p RT V m 2

Cubic Equations of State Real Gas Law Real Gas Law p p ZRT V m ZRT V m Z describes how the volume deviates from ideal behavior. 3

Cubic Equations of State Real Gas Law When Z = 1, the equation reverts to the ideal gas equation. Z-Factor Chart p ZRT V m 4

Cubic Equations of State van der Waals Repulsive Term Attractive Term p Liquid V RT a b V 2 m m co-volume Constant Temp. Slightly Below Critical Temp. Vapor constant 5

Cubic Equations of State Temperature Well Above Critical Temperature Liquid-like Critical Point Critical Point Gas-like 6

Cubic Equations of State Calculating a, b Ωa = 0.421875 Ωb = 0.125 Calculating Z c 7

Cubic Equations of State Solving vdw: Single Root Liquid Solving for volumes at these pressures is no problem. Solving vdw: Double Root Two Phase 1 Liquid 2 Vapor 3 8

Cubic Equations of State Solving vdw: Single Root Vapor Calculating Compressibility Factor van der Waals re-arranged: Real Gas Law substituted into Van Der Waals Real Gas Law: 0 van der Waals: 9

Cubic Equations of State Handling Mixtures Attractive parameter: Co-volume: Learning Objectives Describe how cubic equations of state handle non-ideal behavior. Describe how liquid and gas volumes are calculated from an equation of state. Describe how cubic equations of state handle mixtures of components. 10

Cubic Equations of State PetroAcademy TM Applied Reservoir Engineering Skill Modules Properties Analysis Management This is Reservoir Engineering Core Reservoir Rock Properties Core Reservoir Rock Properties Fundamentals Reservoir Fluid Core Reservoir Fluid Fundamentals Reservoir Flow Properties Core Reservoir Flow Properties Fundamentals Reservoir Fluid Displacement Core Reservoir Fluid Displacement Fundamentals Reservoir Material Balance Core Reservoir Material Balance Fundamentals Decline Curve Analysis and Empirical Approaches Core Decline Curve Analysis and Empirical Approaches Fundamentals Pressure Transient Analysis Core Rate Transient Analysis Core Enhanced Oil Recovery Core Enhanced Oil Recovery Fundamentals Reservoir Simulation Core Reserves and Resources Core Reservoir Surveillance Core Reservoir Surveillance Fundamentals Reservoir Management Core Reservoir Management Fundamentals 11