Types of Oil and Gas reservoirs

1. Types of Oil and Gas reservoirs

2. Phase Diagram (Basic Concepts) Single phase Gas Single phase liquid C Pressure Bubble-point (pressure) line Dew-point (pressure) line gas Temperature

3. Volatile Oil Black Oil Dewpoint line Critical point Pressure path in reservoir 1 Pressure path in reservoir 2 Dewpoint line 90 Critical point Volatile oil 70 80 60 Black Oil 50 % Liquid Pressure 40 Pressure, psia 90 30 Bubblepoint line % Liquid 80 90 70 Bubblepoint line 20 60 50 10 40 3 3 30 5 20 10 Separator Separator Dewpoint line Temperature Temperature, °F Pressure path in reservoir 1 Pressure path in reservoir Retrograde gas 2 Pressure path in reservoir 1 Dewpoint line 1 Pressure Critical point Dewpoint line Dry gas Wet gas Dewpoint line Pressure % Liquid Bubblepoint line Pressure 40 30 20 15 % Liquid 3 10 % Liquid Critical point 2 2 5 Bubblepoint line Separator 0 50 30 25 25 5 1 1 Separator Temperature Separator Temperature Retrograde Gas Wet Gas Dry Gas Temperature The Five Reservoir Fluids

4. Oil Formation Volume Factor (Bo)

5. Fluid properties, why? • To estimate hydrocarbons in place and reserves • To understand reservoir processes • To predict reservoir behavior • To understand well-flow performance • To design proper surface facilities • Contracting • Marketing

6. Five General Reservoir Fluid Types • Black Oils • Volatile Oils • Retrograde Gas-Condensates • Wet Gases • Dry Gases • The basic principles of waterflooding apply to both oil types (black & volatile) • Modeling volatile oil phase behavior is more complicated than that of black oils

7. Typical Hydrocarbon Mixture Compositions (mol %) Dry Gas Wet Gas Retrograde Gas Cond. Volatile Oil Black Oil Component C1 96.30 88.7 72.7 66.7 52.6 3.00 6.0 10.0 9.0 5.0 C2 0.40 3.0 6.0 6.0 3.5 C3 0.07 0.5 1.0 0.8 0.7 i-C4 0.10 0.8 1.5 2.5 1.1 n-C4 0.02 0.3 0.8 0.8 0.4 i-C5 0.02 0.3 1.0 1.2 0.4 n-C5 0.02 0.2 2.0 2.0 0.9 C6 0.00 0.2 5.0 27.9 11.0 C7+ plus inorganics: N2, CO2, H2O, H2S

8. Field Identification

9. Phase Diagram (Basic Concepts) Single phase Gas Single phase liquid C Pressure Bubble-point (pressure) line Dew-point (pressure) line gas Temperature

10. PVT tests to build a phase diagram

11. Phase Diagram (Basic Definitions) Definitions: 1. Bubble-point line: the point where the first bubble is formed during pressure decrease at constant temperature. 2. Dew-point line: the point where the first liquid drop is formed during pressure increase at constant temperature. Note: Pure-component system can be regarded as a special case of two-component system where two-phase region shrinks to form a line. Critical point: the point where the bubble-point line meets the dew-point line C liquid Pressure 60% 80% 100% liquid (0% gas) 40% 0% liquid (100% gas) 20% gas Temperature Pressure Temperature Plane

12. Phase Diagram (Basic Definitions) Definitions: Cricondenbar: the pressure above which two phases can no longer exist. Cricondentherm: the temperature above which two phases do not exist. Additional points: Cricondenbar C liquid Pressure Cricondentherm gas Temperature

13. Path A Path B C liquid Pressure Liquid-mixture-gas “Retrograde condensation” gas Temperature Basic definitions (cont.) Definitions: Retrograde condensation: phenomenon that the dew point line is crossed (i.e., from gas phase to liquid) as pressure decreases rather than increases. Because this is the reverse of normal behaviour, it is called “retro”.

14. Reservoir Classification • Oil reservoir • In general Tres<Tc of reservoir fluid • Gas reservoir • In general, Tres>Tc of reservoir fluid (hydrocarbon systems)

15. Classification of petroleum fluids/reservoirsgasgas-condensatevolatile oilconventional oilheavy oilgas-oiloil-gasgas-condensate-oilWOC – water-oil contactGWCGOCThick gas-condensate-oil reservoirs without GOC

16. Reservoir Classification • Oil reservoir • In general Tres<Tc of reservoir fluid • Gas reservoir • In general, Tres>Tc of reservoir fluid (hydrocarbon systems)

17. Oil Reservoir • Under-saturated oil reservoir • initial reservoir pressure, pi > the bubble-point pressure, pb of the reservoir fluid • Saturated oil reservoir • pi = pb • Gas-cap reservoir or two phase reservoir • pi < pb Note The appropriate quality line gives the ratio of volume of liquid (oil) to volume of gas

18. Gas Reservoir Dry gas reservoir • initial reservoir temperature higher than cricondentherm temperature (light components) • even at low pressure (separator) and temperature, fluid is 100% gas • Wet gas reservoir • initial reservoir temperature higher than cricondentherm temperature • But even at low pressure (separator) and temperature, some gas condensate to liquid • Retrograde gas-condensate reservoir • Reservoir temperature lies between Tc and Tcri (Tc<Tr<Tcr) • Near critical gas-condensate • Reservoir temperature is nearly equal to critical temperature of fluid (Tr ~Tc)

19. Volatile Oil Black Oil Dewpoint line Critical point Pressure path in reservoir 1 Pressure path in reservoir 2 Dewpoint line 90 Critical point Volatile oil 70 80 60 Black Oil 50 % Liquid Pressure 40 Pressure, psia 90 30 Bubblepoint line % Liquid 80 90 70 Bubblepoint line 20 60 50 10 40 3 3 30 5 20 10 Separator Separator Dewpoint line Temperature Temperature, °F Pressure path in reservoir 1 Pressure path in reservoir Retrograde gas 2 Pressure path in reservoir 1 Dewpoint line 1 Pressure Critical point Dewpoint line Dry gas Wet gas Dewpoint line Pressure % Liquid Bubblepoint line Pressure 40 30 20 15 % Liquid 3 10 % Liquid Critical point 2 2 5 Bubblepoint line Separator 0 50 30 25 25 5 1 1 Separator Temperature Separator Temperature Retrograde Gas Wet Gas Dry Gas Temperature The Five Reservoir Fluids

20. Critical point Pc Pressure Tc temperature P-T diagram Phase behavior: description of equilibria between the phases as P, V, and T of the system changes

21. Single-component system

22. Two-component system

23. Two-component system

24. Multi-component system

25. Dynamic phase behavior

26. Dry-gas reservoir

27. Wet-gas reservoir

28. Retrograde-gas condensate reservoir

29. Volatile-oil reservoir

30. Black-oil reservoir

31. Summary

32. Oil Formation Volume Factor (Bo) • Oil formation volume factor, Bo = (reservoir oil volume)/(stock tank volume) As the reservoir pressure increases: • Bo increases to a maximum value at the bubble point (Pb). • this is due to increasing gas volumes being condensed in the liquid • Once the bubble point is reached, the liquid volume decreases with increasing pressure • single phase compressible liquid

33. Oil Formation Volume Factor (Bo)

34. Solution Gas-Oil Ratio (Rs) • The solution gas oil ratio (Rs) represents the solubility of gas in oil. • Rs = (solution gas volume)/(stock tank volume of oil) As the reservoir pressure increases: • Rs increases to a maximum value at the bubble point (Pb). • increasing gas volumes are condensed in the liquid • Once the bubble point is reached, the value of Rs remains constant with increasing pressure.

35. Solution Gas-Oil Ratio (Rs)

36. Gas Formation Volume Factor (Bg) • The gas formation volume factor (Bg) is defined as the volume of gas in the reservoir divided by the volume of solution gas at standard conditions. • Bg = (reservoir gas volume)/(standard conditions gas volume). • SI units are usually m3/ m3, while oilfield units are reservoir barrels/thousand standard ft3.

37. Gas Formation Volume Factor (Bg)

38. Two-Phase Formation Volume Factor (Bt) • Bt is the total volume that would be occupied if all of the liberated solution gas remained in the reservoir: • Bt = Bo + Bg(Rsi – Rs) • Rsi is the initial solution gas-oil ratio • Above the bubble point (Pb) the solution gas-oil ratios are the same (Rsi = Rs); Bt = Bo • Below the bubble point, the gas-oil ratio (Rs) is less than its initial value (Rsi)

39. Two-Phase Formation Volume Factor (Bt) Bt Bo

40. ViscosityShear stress Textbooks: viscosity of gas, oil, water, gas-condensate, volatile oil, heavy oil Relations between cp and Pa*s

41. Oil, Gas & Water Viscosities • Changes in oil viscosity can have a significant effect upon waterflood performance. • Given decreasing pressure, oil viscosity decreases slightly (to the bubble point), then increases significantly as the lighter components of the gas are removed from the oil. • The gas & water viscosities seldom vary enough to impact waterflood behavior.

42. Oil Viscosity

43. Compressibility If compressibility is roughly constant, volume at any pressure can be obtained in terms of original pressure and temperature

44. Formation/Rock Compressibility Reservoir engineers are most concerned with pore volume compressibility The change in pore volume with pressure is usually due to compaction.

45. above the bubble point: below the bubble point: Oil Compressibility Coa represents the “apparent” oil compressibility Below the bubble point the oil compressibility actually has two terms, the compressibility of the oil itself (without any changes in solution gas content) and the swelling effect introduced by condensing additional light ends into the liquid phase with increasing pressure.

46. Water & Gas Compressibility Since gas can be dissolved in water, a similar result holds for water compressibility: Gas compressibility is represented by the following equation:

47. Total Compressibility Total compressibility in a multi-phase system involves these “apparent” compressibilities:

48. Compressibility • Compressibility controls the behavior of a reservoir in the depletion phase. • If a waterflood is maintained at a constant pressure, compressibility is of minimal importance; however . . . • With gradually decreasing pressure, compressibility effects may occur due to • development of gas caps • compaction drive