PVT. Properties of Reservoir Fluids. as function of. Pressure. Volume. Temperature. T.Blasingame Kappa 2004

Transcription

1 PVT Properties of Reservoir Fluids as function of Pressure Volume Temperature

2 PVT Behaviour Main Reservoir Fluids: Black Oil p>p b B o, µ o, c o are ASSUMED constant Solution-Gas Drive p<p b B o, µ o, c o = f(p) Dry Gas p>p d B g, µ g, c g = f(p)

3 Reservoir Fluids Schematic Phase Diagrams Generic (single and multi-component cases) Black Oil Solution-Gas Drive Dry Gas Black Oil (p>p b ) Properties: B o, µ o, c o (ASSUMED constant) Solution-Gas Drive (p<p b ) Properties: B o, µ o, c o Dry Gas (p>p d ) Properties: B g, µ g, c g Summary of Fluid Properties and Sources

4 Pressure - Volume Behaviour Single Component System Pressure Liquid Bubble point Dew point FIRST BUBBLE OF GAS LAST DROP OF LIQUID Gas Volume

5 Pressure vs Temperature Single Component System

6 3D Phase Diagram Single Component System Liquid Pressure Gas Liquid Critical point Gas Volume Temperature

7 Pressure - Volume Behaviour Two Component System Pressure Liquid Bubble point Dew point FIRST BUBBLE OF GAS LAST DROP OF LIQUID Gas Volume

8 P - T Behaviour 2 Component System

9 Diagram for a Multi-Component System Note the "Bubble Point" and "Dew Point" lines. Location of critical point determines fluid type.

10 Reservoir Fluids Hydrocarbon Reservoir Fluids types

11 Reservoir Fluids Black Oil p-t Diagram Black Oil : γ o >40 o API, (GOR) i < 2000 scf/stb, B oi < 2.0 RB/STB, C 7+ > 20 %.

12 Reservoir Fluids Volatile Oil p-t Diagram Volatile Oil: γ o <45 o API, 2000 < (GOR) i < 3300 scf/stb, B oi > 2.0 RB/STB, 12.5 < C 7+ < 20 %.

13 Reservoir Fluids Retrograde Gas p-t Diagram Retrograde Gas : 45<γ o <60 o API, 3300 < (GOR) i < 150,000 scf/stb, C 7+ < 12.5 %.

14 Reservoir Fluids Wet Gas p-t Diagram Wet Gas: (GOR) i > 50,000 scf/stb.

15 Reservoir Fluids Dry Gas p-t Diagram Dry Gas

16 Reservoir Fluids Formation Volume Factor: B o,g,w B o,g,w = Fluid volume at reservoir conditions Fluid volume at standard conditions The Formation Volume Factor "converts" surface volumes to downhole conditions. Typical values: Oil: 1.2 to 2.4 RB/STB Gas: to 0.01 rcf/scf 100 to 333 scf/rcf (=expansion factor)

17 Formation Volume factors Solution gas Surface conditions Solution gas Oil Gas Water Bo Rs Bg Rsw Bw Reservoir conditions Oil Gas Water

18 Retrograde Gas Condensate Condensate Surface conditions GLR Gas Bg Reservoir conditions Gas

19 Reservoir Fluids Viscosity: µ o,g,w Is a measure of a fluid's internal resistance to flow, - the proportionality of shear rate to shear stress - a sort of internal friction. Fluid viscosity depends on pressure, temperature and fluid composition. Typical values: Oil: 0.2 to 30 cp Gas: 0.01 to 0.05 cp

20 Compressibility Important reservoir parameters: drained area permeability reservoir thickness porosity compressibility Of importance is the TOTAL system compressibility: HC: hydrocarbon, w: water, f: formation c t = c hc.s hc + c w.s w + c f

21 Compressibility Hydrocarbon Compressibility: c o,g Oil 1 db B dr c o g so o = + Bo dp Bo dp Typical values p > p b 5 to 20 x10-6 psi -1 p < p b 30 to 200 x10-6 psi -1 Gas 1 dbg cg = Bg dp Typical values 50 to 1000 x10-6 psi -1

22 Compressibility Water 1 db B dr c w g sw w = + Bw dp Bw dp Typical values 3 to 5 x10-6 psi-1 Formation c f 1 dφ = φ dp Typical values: 2 to 10 x10-6 psi -1 normal 10 to 100 x10-6 psi -1 very high

23 Fluid Correlations Oil PVT Correlations used in Topaze or Saphir R s /p b B o µ o c o Standing - - Lasater Vasquez and Beggs - Glaso - Lasater- Standing Petrosky and Farshad - Beggs and Robinson - - Beal generally used as default)

24 Gas Correlations Gas PVT Correlations used in Topaze or Saphir z-factor µ g Dranchuk, et al. - Beggs and Brill - Hall and Yarborough - Lee, et al. - Carr, et al. - generally used as default Gas compressibility (c g ) is computed from the z-factor using: 1 dbg 1 1 dz cg = = Bg dp p z dp

25 General Oil Properties Black Oil PVT Properties: (general behavior, p b =5000 psia)

26 Oil Reservoir below Bubble Point: "Solution-Gas Drive" 1. Pressure above Bubble Point. Wells produce oil and associated gas. 2. Pressure drops below Bubble Point. Bubbles of solution gas form in reservoir. 3. Critical gas saturation reached. Gas is now mobile. 4. Gas flows towards producing wells. Wells now produce oil, associated gas and solution gas.

27 Oil Reservoir below Bubble Point: "Solution-Gas Drive" 1. As fluid is produced, the reservoir pressure drops towards abandonment. 2. The Oil production is high at first, rapidly dropping off as more gas is produced. 3. At critical gas saturation, the Gas-Oil ratio rises rapidly to a maximum, then falls as the lower gas compressibility offsets the increased gas mobility.

28 Dry Gas In terms of equations solutions the main difference between the oil and gas case is that the gas properties are highly pressure dependent. Viscosity µ g and Compressibility c t are function of the pressure

29 Dry gas In order to keep the liquid flow equations linear, the variations in gas properties are accounted for by the real gas pseudopressure function ( ) mp = p p 0 2 pdp. µ ( p). z( p) Pseudo-pressure function is then substituted for pressure in the analysis. To take into account the varying mgcg a pseudo- time can be used in the analysis.

30 References 1. Fundamentals of Reservoir Engineering Calhoun (1953). 2. Properties of Petroleum Fluids McCain (1990).