Reservoir Fluid Fundamentals COPYRIGHT. Dry Gas Fluid Basic Workflow Exercise Review

Transcription

1 Pseudo-Critical Properties Reservoir Fluid Fundamentals Dry Gas Fluid Basic Workflow Exercise Review B C D E F 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] Calculate the pseudo-critical properties of this dry gas using the Brown correlation. 1

2 Pseudo-Critical Properties Pseudo Critical Pressure [psia] [kpa.a] Pseudo Critical Temperature [degf] [degc] Pseudo-Critical Properties Pseudo Critical Pressure =stan_pc(c3,"dry") [psia] Pseudo Critical Temperature =stan_tc(c3,"dry") [degf] Conversion p pc kpa p pc psia T K T R 5 9 pc pc o T R T F pc pc T C T K pc pc Input for Brown correlation is specific gravity. Use the dry gas version of the correlation. Make sure you notice the unit choices required for your answer. 2

3 Pseudo-Reduced Properties J K L M N 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Pseudo Critical Pressure [psia] [kpa.a] 11 Pseudo Critical Temperature [degf] [degc] Calculate the pseudo-reduced properties for this dry gas. Pseudo-Reduced Properties Pseudo Reduced Pressure [ ] [ ] Pseudo Reduced Temperature [ ] [ ] 3

4 Pseudo-Reduced Properties Pseudo Reduced Pressure =(K8+K6)/K10 [ ] Pseudo Reduced Temperature =(K )/(K ) [ ] Remember to use absolute units for both pressure and temperature. Units in the numerator and denominator need to be the same, or you calculate rubbish. Gas Deviation Factor R S T U V 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Pseudo Reduced Pressure [ ] [ ] 11 Pseudo Reduced Temperature [ ] [ ] Calculate the gas deviation factor for this dry gas. 4

5 Gas Deviation Factor Gas Deviation Factor [ ] [ ] Gas Deviation Factor Gas Deviation Factor =Abou_Z(S10,S11,1) [ ] Remember that the Dranchuk and Abou-Kassem correlation is the most accurate correlation in general use. A starting guess of unity is usually a good choice for a dry gas. 5

6 Formation Volume Factor Z AA AB AC AD 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Gas Deviation Factor [ ] [ ] 11 Universal Gas Constant [psi.cuft/mol/degr] [J/mol/K] 12 Air Apparent Molecular Mass [lb/mol] [g/mol] Calculate the formation volume factor for this dry gas. Formation Volume Factor Gas Formation Volume Factor E 03 [cuft/scf ] E 03 [m 3 /sm 3 ] Conversion 3 3 B m / sm B cuft / scf 1 g g 6

7 Formation Volume Factor Gas Formation Volume Factor =(AA10*(AA )/(AA8+AA6))*(AA6/(AA )) [cuft/scf] Remember that Bg is reservoir volume divided by surface volume. Remember that the gas deviation factor at standard conditions is usually very close to unity. Remember that pressures and temperatures have to be in absolute units. Apparent Molecular Mass AH AI AJ AK AL 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Gas Deviation Factor [ ] [ ] 11 Universal Gas Constant [psi.cuft/mol/degr] [J/mol/K] 12 Air Apparent Molecular Mass [lb/mol] [g/mol] Calculate the apparent molecular mass of this dry gas. 7

8 Apparent Molecular Mass Apparent Molecular Mass [lb/mol] [g/mol] Apparent Molecular Mass Apparent Molecular Mass =AI3*AI12 [lb/mol] Conversion M g / g mol M lb/ lb mol 1 w w Remember that apparent molecular mass does not change unless composition changes. Remember that gas density at standard conditions is directly proportional to molecular mass. 8

9 In-Situ Density AP AQ AR AS AT 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Gas Deviation Factor [ ] [ ] 11 Universal Gas Constant [psi.cuft/mol/degr] [J/mol/K] 12 Air Apparent Molecular Mass [lb/mol] [g/mol] In-Situ Density Calculate the in-situ density of this dry gas. In Situ Gas Density [lb/cuft] [kg/m 3 ] 9

10 In-Situ Density In Situ Gas Density =AQ3*AQ12*(AQ6+AQ8)/(AQ10*AQ11*(AQ )) [lb/cuft] Conversion kg lb m ft Remember that density is mass over volume. If you utilize molecular mass, then you need a molar volume to match. Watch out for your units! In-Situ Compressibility AP AQ AR AS AT 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Gas Deviation Factor [ ] [ ] 11 Universal Gas Constant [psi.cuft/mol/degr] [J/mol/K] 12 Air Apparent Molecular Mass [lb/mol] [g/mol] 14 Pressure [psig] [kpa.g] 15 Temperature [degf] [degc] 16 Gas Deviation Factor [ ] [ ] Calculate the in-situ compressibility of this dry gas. 10

11 In-Situ Compressibility Gas Compressibility E 04 [1/psi] E 05 [1/kPa] In-Situ Compressibility Gas Compressibility =(1/AY8) (1/AY10)*(AY16 AY10)/(AY14 AY8) [1/psi] Conversion c 1/ kpa c 1/ psia ; p kpa p psia g g This answer uses finite differences rather than an analytical differentiation of the gas deviation factor equation. Therefore, the smaller the p, the more accurate the answer, once we don t approach the limits of machine precision. 11

12 In-Situ Viscosity In-Situ Viscosity BF BG BH BI BJ 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Reservoir Pressure [psig] [kpa.g] 9 Reservoir Temperature [degf] [degc] 10 Gas Deviation Factor [ ] [ ] 11 Universal Gas Constant [psi.cuft/mol/degr] [J/mol/K] 12 Air Apparent Molecular Mass [lb/mol] [g/mol] Calculate the in-situ viscosity of this dry gas. In Situ Gas Viscosity E 02 [cp] E 02 [mpa.s] 12

13 In-Situ Viscosity In Situ Gas Viscosity =Lee2_Ugb(Lee2_Ugd(BG3,BG9),BG3,BG8+BG6,BG9,BG10) [cp] Conversion mpa. s cp 1 Atmospheric gas viscosity is a function of specific gravity and temperature. Correction for the effect of pressure is a function of in-situ gas density in g/cc. Gas density is a function of specific gravity, pressure, temperature and gas deviation factor. 13

14 Reservoir Fluid Fundamentals Wet Gas Fluid Basic Workflow Exercise Review Surface Gas Gravity and Surface Gas-Stock Tank Oil Ratio B C D E F 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 58.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 10.0 [stb/mmscf] E 05 [sm 3 /sm 3 ] Calculate the surface gas gravity and surface gas-stock-tank oil ratio of this wet gas. 14

15 Surface Gas Gravity and Surface Gas-Stock Tank Oil Ratio Surface Gas Gravity [1/air] [1/air] Surface Gas/Stock Tank Oil Ratio 100,267 [scf/stb] [sm 3 /sm 3 ] Surface Gas Gravity and Surface Gas-Stock Tank Oil Ratio Surface Gas Gravity =(1000*1000*C3/C11+C10*C8)/(1000*1000/C11+C10) [1/air] Surface Gas/Stock Tank Oil Ratio =1000*1000/C11+C10 [scf/stb] Conversion 3 sm stb sm MMscf This is a recombination on a molar basis. Since different gases have the same molar volume at standard temperature and pressure, we use standard volumes as proxies for molar quantities. It is common to use different units for separator and stock-tank gas. 15

16 Molar Mass Molar Mass J K L M N 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 56.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 13.0 [stb/mmscf] E 05 [sm 3 /sm 3 ] Calculate the molar mass of this stock tank oil using the Cragoe correlation. Stock Tank Oil Apparent Molecular Mass [lb/mol] [g/mol] 16

17 Molar Mass Surface Gas Gravity =6084/(K9 5.9) [lb/mol] Careful with the constants. There are many revisions to the Cragoe correlation available in the literature. This version requires specific gravity in API degrees. In-Situ Specific Gravity R S T U V 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 54.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 16.0 [stb/mmscf] E 05 [sm 3 /sm 3 ] 12 Surface Gas Gravity [1/air] [1/air] 13 Surface Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 14 Stock Tank Oil Apparent Molecular Mass [lb/mol] [g/mol] Calculate the in-situ specific gravity of this wet gas. 17

18 In-Situ Specific Gravity Reservoir Gas Specific Gravity [1/air] [1/air] In-Situ Specific Gravity Reservoir Gas Specific Gravity =(S12*S *api2sgo(S9))/(S *api2sgo(S9)/S14) [1/air] Remember that the values of the constants 4591 and are functions of the standard temperature and pressure, which vary from state to state, and country to country. Otherwise, this is a molar recombination of stock tank oil and surface gases. 18

19 Pseudo-Critical Properties Z AA AB AC AD 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 52.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 10.0 [stb/mmscf] E 05 [sm 3 /sm 3 ] 12 Surface Gas Gravity [1/air] [1/air] 13 Surface Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 14 Stock Tank Oil Apparent Molecular Mass [lb/mol] [g/mol] 15 Reservoir Gas Specific Gravity [1/air] [1/air] Pseudo-Critical Properties Calculate the pseudo-critical properties of this wet gas using the Brown Correlation. In situ Gas Pseudo Critical Pressure [psia] [kpa.a] In situ Gas Pseudo Critical Temperature [degf] [degc] 19

20 Pseudo-Critical Properties In situ Gas Pseudo Critical Pressure =stan_pc(aa15,"wet") [psia] In situ Gas Pseudo Critical Temperature =stan_tc(aa15,"wet") [degf] Conversion p pc kpa p pc psia T K T R 5 9 pc pc T R T F pc pc Remember Standing built the equations to describe the graphical Brown correlation. Remember Brown had separate correlations for wet and dry gases. Mole Fractions AH AI AJ AK AL 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 58.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 18.0 [stb/mmscf] E 04 [sm 3 /sm 3 ] 12 Surface Gas Gravity [1/air] [1/air] 13 Surface Gas/Stock Tank Oil Ratio [scf/stb] 9942 [sm 3 /sm 3 ] 14 Stock Tank Oil Apparent Molecular Mass [lb/mol] [g/mol] 15 Reservoir Gas Specific Gravity [1/air] [1/air] 16 Reservoir Gas Pseudo Critical Pressure [psia] [kpa.a] 17 Reservoir Gas Pseudo Critical Temperature [degf] [degc] Calculate the mole fractions of surface gas and stock tank oil making up this wet gas. 20

21 Mole Fractions Mole Fraction Surface Oil in Reservoir Gas [ ] [ ] Mole Fraction Surface Gas in Reservoir Gas [ ] [ ] Mole Fractions Mole Fraction Surface Oil in Reservoir Gas =28.966*(AI15 AI12)/(AI *AI12) [ ] Mole Fraction Surface Gas in Reservoir Gas =1 AI31 [ ] Surface oil is defined as the hydrocarbon liquid which is stable at standard temperature and pressure. Everything else that is not aqueous is considered surface gas. The mole fractions of surface oil and surface gas have to add up to unity. 21

22 Formation Volume Factor AP AQ AR AS AT 3 Separator Gas Specific Gravity [1/air] [1/air] 4 Separator Pressure [psig] [kpa.g] 5 Separator Temperature 80.0 [degf] [degc] 6 Standard Pressure 14.7 [psia] [kpa.a] 7 Standard Temperature 60.0 [degf] [degc] 8 Stock Tank Gas Specific Gravity [1/air] [1/air] 9 Stock Tank Oil Specific Gravity 56.0 [ o API] [ o API] 10 Stock Tank Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 11 Stock Tank Oil/Separator Gas Ratio 13.0 [stb/mmscf] E 05 [sm 3 /sm 3 ] 12 Surface Gas Gravity [1/air] [1/air] 13 Surface Gas/Stock Tank Oil Ratio [scf/stb] [sm 3 /sm 3 ] 14 Stock Tank Oil Apparent Molecular Mass [lb/mol] [g/mol] 15 Reservoir Gas Specific Gravity [1/air] [1/air] 16 Reservoir Gas Pseudo Critical Pressure [psia] [kpa.a] 17 Reservoir Gas Pseudo Critical Temperature [degf] [degc] 18 Mole Fraction Surface Gas in Reservoir Gas [ ] [ ] 19 Reservoir Pressure [psia] [kpa.a] 20 Reservoir Temperature [degf] [degc] 21 Reservoir Gas Deviation Factor [ ] [ ] Calculate the formation volume factor of this wet gas. Formation Volume Factor Formation Volume Factor E 03 [cuft/scf] E 03 [m 3 /sm 3 ] 22

23 Formation Volume Factor Formation Volume Factor =(AQ21*(AQ )/AQ19)*(AQ6/(AQ )) [cuft]/[scf] Conversion 3 3 B m / sm B cuft / scf 1 g g Remember that all the gas in the reservoir does not remain in the vapor phase at the surface for wet gases. 23

24 Reservoir Fluid Fundamentals Under-Saturated Oil Basic Workflow Under-Saturated Compressibility Exercise Review B C D E F 3 Separator Gas Gravity 0.7 [1/air] 0.7 [1/air] 4 Stock Tank Oil Gravity 35 [ o API] 35 [ o API] 5 Separator Gas/Stock Tank Oil Ratio 500 [scf/stb] [sm 3 /sm 3 ] 6 Bubble Point Pressure [psia] [kpa.a] 7 Reservoir Temperature 125 [degf] [degc] 8 Bubble Point Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] 9 Bubble Point Density [lb/cuft] [kg/m 3 ] 10 Bubble Point Viscosity [cp] [mpa.s] 11 Reservoir Pressure 5000 [psia] [kpa.a] Calculate the under-saturated compressibility of this oil using the Vazquez and Beggs Correlation. 24

25 Under-Saturated Compressibility Undersaturated Oil Compressibility E 06 [1/psi] E 07 [1/kPa] Under-Saturated Compressibility Undersaturated Oil Compressibility =vasq_co(c11,c7,c3,c4,c5) [1/psi] Conversion c 1/ 1/ o kpa c o psia 3 3 R scf / stb R sm / sm s s T F T K p psia p kpa Under-saturated oil compressibility is NOT independent of pressure, so that the pressure of interest is used in the calculation. 25

26 Formation Volume Factor J K L M N 3 Separator Gas Gravity 0.7 [1/air] 0.7 [1/air] 4 Stock Tank Oil Gravity 30 [ o API] 30 [ o API] 5 Separator Gas/Stock Tank Oil Ratio 500 [scf/stb] [sm 3 /sm 3 ] 6 Bubble Point Pressure [psia] [kpa.a] 7 Reservoir Temperature 125 [degf] [degc] 8 Bubble Point Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] 9 Bubble Point Density [lb/cuft] [kg/m 3 ] 10 Bubble Point Viscosity [cp] [mpa.s] 11 Reservoir Pressure 5000 [psia] [kpa.a] 12 Undersaturated Oil Compressibility E 06 [1/psi] E 07 [1/kPa] Formation Volume Factor Calculate the formation volume factor of this under-saturated oil using the classic formula. Undersaturated Oil Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] 26

27 Formation Volume Factor Undersaturated Oil Formation Volume Factor =K8*EXP( K12*(K11 K6)) [bbl/stb] Viscosity Conversion c 1/ 1/ o kpa c o psia p psia p kpa B m / sm B bbl / stb 1.0 o o R S T U V 3 Separator Gas Gravity 0.7 [1/air] 0.7 [1/air] 4 Stock Tank Oil Gravity 35 [ o API] 35 [ o API] 5 Separator Gas/Stock Tank Oil Ratio 500 [scf/stb] [sm 3 /sm 3 ] 6 Bubble Point Pressure [psia] [kpa.a] 7 Reservoir Temperature 125 [degf] [degc] 8 Bubble Point Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] 9 Bubble Point Density [lb/cuft] [kg/m 3 ] 10 Bubble Point Viscosity [cp] [mpa.s] 11 Reservoir Pressure 5000 [psia] [kpa.a] Calculate the viscosity of this under-saturated oil using the Vazquez & Beggs correlation. 27

28 Viscosity Undersaturated Oil Viscosity [cp] [mpa.s] Viscosity Undersaturated Oil Viscosity =begg_uou(s10,s6,s11) [cp] Conversion mpa. s cp 1 ou ou p psia p kpa This viscosity correlation does not need any additional fluid properties, it uses the bubble point oil viscosity and corrects it for pressure. 28

29 Under-Saturated Density Z AA AB AC AD 3 Separator Gas Gravity 0.6 [1/air] 0.6 [1/air] 4 Stock Tank Oil Gravity 30 [ o API] 30 [ o API] 5 Separator Gas/Stock Tank Oil Ratio 500 [scf/stb] [sm 3 /sm 3 ] 6 Bubble Point Pressure [psia] [kpa.a] 7 Reservoir Temperature 125 [degf] [degc] 8 Bubble Point Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] 9 Bubble Point Density [lb/cuft] [kg/m 3 ] 10 Bubble Point Viscosity [cp] [mpa.s] 11 Reservoir Pressure 6000 [psia] [kpa.a] 12 Undersaturated Oil Compressibility E 06 [1/psi] E 07 [1/kPa] 13 Undersaturated Oil Formation Volume Factor [bbl/stb] [m 3 /sm 3 ] Under-Saturated Density Calculate the under-saturated density of this oil at reservoir pressure. Undersaturated Oil Density [lb/cuft] [kg/m 3 ] 29

30 Under-Saturated Density Undersaturated Oil Density =AA9*AA8/AA13 [lb/cuft] Conversion / / Bo m sm Bo bbl stb 3 kg m lb cuft o o / / / Under-saturated oil density can be calculated with reasonable accuracy by dividing the density at bubble point by the formation volume factor at elevated pressure and then multiplying by the formation volume factor at bubble point conditions. 30