Petroleum Engineering 324 Reservoir Performance. Objectives of Well Tests Review of Petrophysics Review of Fluid Properties 19 January 2007

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1 Petroleum Engineering 324 Reservoir Performance Objectives of Well Tests Review of Petrophysics Review of Fluid Properties 19 January 2007 Thomas A. Blasingame, Ph.D., P.E. Department of Petroleum Engineering Texas A&M University College Station, TX (USA) PETE 324 (07A) PTA Objectives; Petrophysics Review; PVT Review Slide 1

Objectives of Well Test/Production Data Analysis Parameters to be Estimated Objectives of PTA/PA: Basics The reservoir does not care how it is being produced.

2 Objectives of Well Test/Production Data Analysis Parameters to be Estimated Objectives of PTA/PA: Basics The reservoir does not care how it is being produced. Better data = better analysis = better estimates. PTA: pressure history good. PA: rate history good. PETE 324 (07A) PTA Objectives; Petrophysics Review; PVT Review Slide 2

3 Review of Petrophysics Objectives Review of Petrophysics: Must understand the small-scale in order to understand the large scale. Porosity and permeability vary significantly there is no "universal" concept (at least at present), all relations are defined by data. PETE 324 (07A) PTA Objectives; Petrophysics Review; PVT Review Slide 3

4 Review of Phase Behavior (PVT) Objectives Review of Phase Behavior: Correlations (p, T, composition) Gas: Correlations perform very well. Oil: Correlations perform reasonably well. Water: Correlations are simplistic, but sufficient. PETE 324 (07A) PTA Objectives; Petrophysics Review; PVT Review Slide 4

19 Pressure Transient Analysis Orientation/Diagnostics Thomas A. Blasingame, Texas A&M U. Department of Petroleum Engineering Texas A&M University College Station, TX Slide 1

20 Pressure Transient Analysis: Philosophy/Objectives Q. Issues with pressure transient analysis (PTA)? A. Design implementation interpretation analysis review. Objectives of Pressure Transient Testing: Evaluate reservoir pressure (initial or average pressure). Evaluate reservoir fluid (fluid samples collected for lab study). Estimate reservoir properties: k, S, x f, λ, ω, etc. Estimate reservoir volumetrics: fluid-in-place, drainage area. Input Data: BOTTOMHOLE pressure data (accurate to < 1 part in 10,000). SURFACE flowrate data (often poorly measured/recorded). Fluid properties: FVF, viscosity, compressibility,... Reservoir properties: h, φ, r w, c f,... Results of PTA Interpretation: Productive capacity of the WELL (damage/stimulation). Productive capacity of the RESERVOIR (transmissibility). Current average reservoir pressure. Reservoir limits (for production to pseudosteady-state). Well interference effects. Well/Reservoir specific parameters: C s, x f, λ, ω, L fault, r comp, k v /k h,... Discussion: Pressure Transient Analysis Philosophy/Objectives Design/implementation issues? Interpretation/analysis issues? (prepare well for testing, model test) (model uniqueness) Slide 2

21 Pressure Transient Analysis: Summary of Diagnostics Q. Key elements of PTA diagnostics? A. Utilize "regime-specific" data functions, use multiple data functions. Discussion: Pressure Transient Analysis Summary of Diagnostics Δp function (pressure drop)? (traditional diagnostic) Δp d function (Bourdet derivative)? (primary diagnostic IARF) Δp βd function (β-derivative)? (new diagnostic VF, NF, Hz, Faults, etc.) Slide 3

22 Diagnostic Plot: Infinite Acting Radial Flow Type Curve for an Unfractured Well in an Infinite-Acting Homogeneous Reservoir with Wellbore Storage and Skin Effects Legend: Radial Flow Type Curves p D Solution p Dd Solution p Dβd Solution p D, p Dd and p Dbd Wellbore Storage Domination Region C D e 2s = C D e 2s = Radial Flow Region C D e 2s = Wellbore Storage Distortion Region Discussion: Diagnostic Plot Infinite Acting Radial Flow t D /C D Δp function? ("hockey stick" behavior WBS IARF) Δp d function? (IARF p Dd = 1/2) Δp βd function? (WBS Domination p Dβd = 1) Slide 4

23 Diagnostic Plot: Sealing Faults Legend: "Bourdet" Well Test Pressure Derivative Dimensionless Pressure Derivative Type Curves for Sealing Faults (Inifinite-Acting Homogeneous Reservoir) Single Fault Case 2 Perpendicular Faults (2 at 90 Degrees) 2 Parallel Faults (2 at 180 Degrees) 3 Perpendicular Faults (3 at 90 Degrees) 3 Perpendicular Faults β-pressure Derivative Function, p Dβd = (t D /p D ) d/dt D (p D ) Undistorted Radial Flow Behavior 3 Perpendicular Faults Legend: β-pressure Derivative Function p Dβd = (t D /p D ) dp D /dt D Single Fault Case 2 Perpendicular Faults (2 at 90 Degrees) 2 Parallel Faults (2 at 180 Degrees) 3 Perpendicular Faults (3 at 90 Degrees) p Dd = t D dp D /dt D t D /L D 2 (LD = L fault /r w ) 2 Parallel Faults 2 Perpendicular Faults 2 Parallel Faults Single Fault 2 Perpendicular Faults Single Fault "Bourdet" Well Test Pressure Derivative, p Dd = t D dp D /dt D Discussion: Diagnostic Plot Sealing Faults Δp function? Δp d function? Δp βd function? (not included in this plot) (IARF p Dd = 1/2; single/2-perpendicular faults = constant) (2-parallel/3-perpendicular faults = constant) Slide 5

24 Diagnostic Plot: Fractured Well (no WBS) 10 1 Type Curve for a Well with a Finite Conductivity Vertical Fractured in an Infinite-Acting Homogeneous Reservoir (C fd = (wk f )/(kx f ) = 0.25, 0.5, 1, 2, 5, 10, 20, 50, 100, 200, 500, 1000, 10000) 10 0 C fd = C fd = Radial Flow Region p D, p Dd and p Dβd C fd = C fd = t Dxf Legend: p D Solution p Dd Solution p Dβd Solution Discussion: Diagnostic Plot Fractured Well (no WBS) Δp function? (BLF: p D = 1/4 slope, FLF: p D = 1/2 slope) Δp d function? (BLF: p Dd = 1/4 slope, FLF: p Dd = 1/2 slope, IARF: p Dd = 1/2) Δp βd function? (BLF: p Dβd = 1/4, FLF: p Dβd = 1/2) Slide 6

25 Diagnostic Plot: Fractured Well (w/wbs) Type Curve for a Well with Finite Conductivity Vertical Fracture in an Infinite-Acting Homogeneous Reservoir with Wellbore Storage Effects C fd = (wk f )/(kx f )= Legend: C fd = (wk f )/(kx f )= 10 p D Solution p Dβd Solution Wellbore Storage Domination Region C Df = p D and p Dβd C Df = Radial Flow Region 10-3 Wellbore Storage Distortion Region t Dxf /C Df Discussion: Diagnostic Plot Fractured Well (w/wbs) (THIS CASE) Δp function? (WBS: p D = 1 slope, BLF: p D = 1/4 slope) Δp d function? (not included on this plot) Δp βd function? (WBS: p Dβd = 1, BLF: p Dβd = 1/4) Slide 7

26 Diagnostic Plot: Horizontal Well (no WBS) 10 2 Type Curve for a Infinite Conductivity Horizontal Well in an Infinite-Acting Homogeneous Reservoir (L D = 0.1, 0.125, 0.25, 0.5, 1, 5, 10, 25, 50, 100). p D, p Dd and p Dβd L D = L D = Infinite Conductivity Vertical Fracture Legend: p D Solution p Dd Solution p Dβd Solution 1 Infinite Conductivity Vertical Fracture L= Discussion: Diagnostic Plot Horizontal Well (no WBS) t DL (THIS CASE) Δp function? (FLF: p D = 1/2 slope) Δp d function? (FLF: p Dd = 1/2 slope, IARF: p Dd = 1/2) Δp βd function? (FLF: p Dβd = 1/2) Slide 8

27 Diagnostic Plot: Horizontal Well (w/wbs) Type Curve for an Infinite Conductivity Horizontal Well in an Infinite-Acting Homogeneous Reservoir with Wellbore Storage Effects (L D = 100) Legend: L D = 100 p D Solution p Dβd Solution Wellbore Storage Domination Region Radial Flow Region p D and p Dβd C DL = C DL = Wellbore Storage Distortion Region t DL /C DL Discussion: Diagnostic Plot Horizontal Well (w/wbs) (THIS CASE) Δp function? (WBS: p D = 1 slope, FLF: p D = 1/2 slope) Δp d function? (not included on this plot) Δp βd function? (WBS: p Dβd = 1, FLF: p Dβd = 1/2) Slide 9

59 PVT Concepts (Reservoir Fluids) Thomas A. Blasingame, Ph.D., P.E. Department of Petroleum Engineering Texas A&M University College Station, TX (USA) Orientation Phase Behavior Slide 1

60 PVT Concepts (Reservoir Fluids) Self-Evaluation: PVT Concepts 1.Reservoir Fluids: "Black Oil" (p>p b ): B o, μ o, c o are ASSUMED constant "Solution-Gas Drive" (all p): B o, μ o, c o = f(p) "Dry Gas" (p>p d ): B g, μ g, c g = f(p) 2.Diffusivity Equations: "Black Oil" case. "Solution-Gas Drive" case. "Dry Gas" case. Orientation Phase Behavior Slide 2

61 PVT Concepts (Reservoir Fluids) 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" (all p) 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 Orientation Phase Behavior Slide 3

62 Reservoir Fluids Schematic Diagram for a Single Component System From: Properties of Petroleum Reservoir Fluids Bursik (1957). Schematic p-t Diagram: Single Component System Note the "Liquid+Vapor" line. Single component systems not of interest, other than for illustration. Orientation Phase Behavior Slide 4

63 Reservoir Fluids Generic Schematic Diagram for a Multi-Component System From: Fundamentals of Reservoir Engineering Calhoun (1953). Schematic p-t Diagram: Multi-Component (Hydrocarbon) System Note the "Bubble Point" and "Dew Point" lines. Location of critical point determines fluid type. Orientation Phase Behavior Slide 5

64 Reservoir Fluids Generic Schematic Diagram for Hydrocarbon Reservoir Fluids From: Fundamentals of Reservoir Engineering Calhoun (1953). (modified to reflect various reservoir fluid cases) Schematic p-t Diagram: Hydrocarbon Reservoir Fluids Names represent conventional nomenclature. Locations of names represent relative locations of these fluid types. Orientation Phase Behavior Slide 6

65 Reservoir Fluids Black Oil p-t Diagram From: Properties of Petroleum Fluids McCain (1990). Schematic p-t Diagram: Black Oil Fluid is typically dark black, brown, or dark green. γ o >40 o API, (GOR) i < 2000 scf/stb, B oi < 2.0 RB/STB, C 7+ > 20 %. Orientation Phase Behavior Slide 7

66 Reservoir Fluids Volatile Oil p-t Diagram From: Properties of Petroleum Fluids McCain (1990). Schematic p-t Diagram: Volatile Oil Fluid is typically dark brown, orange or green. γ o <45 o API, 2000 < (GOR) i < 3300 scf/stb, B oi > 2.0 RB/STB, 12.5 < C 7+ < 20 %. Orientation Phase Behavior Slide 8

67 Reservoir Fluids Retrograde Gas p-t Diagram From: Properties of Petroleum Fluids McCain (1990). Schematic p-t Diagram: Retrograde Gas Fluid is typically light brown, orange, green, or water-white. 45<γ o <60 o API, 3300 < (GOR) i < 150,000 scf/stb, C 7+ < 12.5 %. Orientation Phase Behavior Slide 9

68 Reservoir Fluids Wet Gas p-t Diagram From: Properties of Petroleum Fluids McCain (1990). Schematic p-t Diagram: Wet Gas Fluid is typically very light water-white. (GOR) i > 50,000 scf/stb. Orientation Phase Behavior Slide 10

69 Reservoir Fluids Dry Gas p-t Diagram From: Properties of Petroleum Fluids McCain (1990). Schematic p-t Diagram: Dry Gas No fluid is produced at surface or in the reservoir. Orientation Phase Behavior Slide 11

70 Reservoir Fluids "Black Oil" Fluid Properties (Various) "Black Oil" PVT Properties: (general behavior, p b =5000 psia) Note the dramatic influence in properties at the bubblepoint pressure. The oil compressibility is the most affected variable (keep this in mind). Orientation Phase Behavior Slide 12

71 Reservoir Fluids "Solution-Gas Drive" Properties (1/(μ o B o ) for p<p b ) "Solution-Gas Drive" PVT Properties: (1/(μ o B o ), p<p b, p b =5000 psia) Attempt to illustrate that 1/(μ o B o ) constant for p<p b. This would allow us to approximate behavior using "liquid" equations. Orientation Phase Behavior Slide 13

72 Reservoir Fluids "Solution-Gas Drive" Properties (μ o c o for p<p b ) "Solution-Gas Drive" PVT Properties: (μ o c o, p<p b, p b =5000 psia) Attempt to illustrate that μ o c o is NEVER constant. CAN NOT approximate behavior using "liquid" equations (or so it seems). Orientation Phase Behavior Slide 14

73 Reservoir Fluids "Dry Gas" μ g z vs. p "Dry Gas" PVT Properties: (μ g z vs. p) Basis for the "pressure-squared" approximation (i.e., use of p 2 variable). Concept: (μ g z) = constant, valid only for p<2000 psia. Orientation Phase Behavior Slide 15

74 Reservoir Fluids "Dry Gas" p/(μ g z) vs. p "Dry Gas" PVT Properties: (p/(μ g z) vs. p) Basis for the "pressure" approximation (i.e., use of p variable). Concept: (p/μ g z) = constant (never valid). Orientation Phase Behavior Slide 16

75 Reservoir Fluids "Dry Gas" μ g c g vs. p "Dry Gas" PVT Properties: (μ g c g vs. p) Concept: If μ g c g constant, pseudotime NOT required. Readily observe that μ g c g is NEVER constant, pseudotime required. Orientation Phase Behavior Slide 17

76 Reservoir Fluids Summary: Formation Volume Factor Formation Volume Factor: B o,g,w Fluid volume at reservoir conditions B o,g,w = Fluid volume at standard conditions B o,g,w is defined as a volume conversion for oil, gas, or water and is defined on a mass (or density) basis. 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 Orientation Phase Behavior Slide 18

77 Reservoir Fluids Summary: Fluid Viscosity 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 Water: 0.5 to 1.05 cp Orientation Phase Behavior Slide 19

78 Reservoir Fluids Summary: Fluid Compressibility Fluid Compressibility: c o,g,w c 1 = B db dp o o + o B B g o dr dp Typical values: Oil: 5 to 20 x10-6 psi -1 (p>p b ) 30 to 200 x10-6 psi -1 (p<p b ) Gas: 50 to 1000x10-6 psi -1 Water: 3 to 5 x10-6 psi -1 Formation Compressibility: c f 1 dφ c f = φ dp Typical values: Normal: 2 to 10 x10-6 psi -1 Abnormal: 10 to 100 x10-6 psi -1 so c g 1 = B g db g dp c 1 = B db dp w w + w B B g w dr dp sw Orientation Phase Behavior Slide 20

79 Reservoir Fluids Summary: Oil PVT Correlations Oil PVT Correlations 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) Orientation Phase Behavior Slide 21

80 Reservoir Fluids Summary: Gas PVT Correlations Gas PVT Correlations 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: c g 1 = B g db g dp 1 1 p z Orientation Phase Behavior Slide 22 = dz dp

81 PVT Concepts (Reservoir Fluids) End of Module Thomas A. Blasingame, Ph.D., P.E. Department of Petroleum Engineering Texas A&M University College Station, TX (USA) Orientation Phase Behavior Slide 23

Petroleum Engineering 324 Reservoir Performance. Objectives of Well Tests Review of Petrophysics Review of Fluid Properties 29 January 2007

Petroleum Engineering 324 Reservoir Performance Objectives of Well Tests Review of Petrophysics Review of Fluid Properties 29 January 2007 Thomas A. Blasingame, Ph.D., P.E. Department of Petroleum Engineering