Capillary Pressure Properties of Mesaverde Group Low-Permeability Sandstones in Six Basins, Western U.S.

Transcription

1 Capillary Pressure Properties of Mesaverde Group Low-Permeability Sandstones in Six Basins, Western U.S. Alan P. Byrnes (KGS- now Chesapeake Energy) Robert M. Cluff John C. Webb (The Discovery Group Inc) (KGS Student Research Assts.) Daniel S. Osburn Andrew Knoderer Owen Metheny Troy Hommertzheim Joshua Byrnes US DOE # DE-FC26-05NT42660

2 US DOE Project Summary Solicitation DE-PS26-04NT subtopic area 1: Understanding Tight Gas Resources Award Date: October 1, 2005 Completion Date: June 30, 2008 Contract # DE-FC26-05NT42660 Organization: University of Kansas, Kansas Geological Survey Principal Investigator: Alan P. Byrnes, KGS KGS-Discovery Group, Inc. co-participants DOE share $411,030 (80%) Industry share $2,804 (20%)

3 Objectives The project will provide petrophysical tools that address: 1) minimum gas flow, critical and residual gas saturation, Sgc=f(lithofacies, Pc, architecture) 2) capillary pressure, Pc=f(P), Pc=f(lithofacies, k, φ, architecture) 3) electrical properties, m* 4) facies and upscaling issues 5) wireline log interpretation algorithms 6) providing a web-accessible database of advanced rock properties.

4 Sampling 44 wells/6 basins Describe ~7000 ft core 2200 core samples advanced properties samples Utah Green River Wind River Washakie Wyoming Powder River N Uinta Piceance Colorado

5 Sampled across wide range of lithofacies

6 Sampled over wide range of porosity and permeability Klinkenberg Permeability (4,000 psi, md) Green River Piceance Powder River Uintah Washakie Wind River logk=0.3phi-3.7 logk=0.3phi In situ calc Porosity (%)

7 Capillary Pressure in Uniformly Variable Capillary Pc = 2τ cosθ/r (after Lake, 2005) Pc = capillary pressure τ = interfacial tension θ = contact angle r = pore radius

8 Mercury Capillary Pressure (after Jennings, 1981)

9 Depth (after Doveton, 1999)

10 Capillary Pressure Equations Pc = 2τ cosθ/r r = 2τ cosθ/pc where: Pc = capillary pressure τ = interfacial tension θ = contact angle r = pore radius H = Pcres. (σbrine-σoil,gas) x Pcres = Pcair-Hg τcosθres τcosθair-hg

11 Resistance Reference Cell Capilary Pressure Measurement Three different air-hg measurements Unconfined (n=150) In situ Drainageimbibition (n=37) Drainage only (n=90) NES = 4000 psi high-p fluid high -P core holder Pressure transducer Core Plug In situ Mercury Intrusion mercury in electric insulator Unconfined (routine) Mercury Intrusion high -P core holder Pressure transducer Core Plug mercury in

12 Unconfined Capillary Pressure Capillary Pressure Varies with Lithofacies and associated pore size distribution and permeability

13 Pc Normalization - Leverett J J(S w ) = C Pc (k/φ) 0.5 /τcosθ J = dimensionless Pc function, function of Sw C = conversion constant = Pc = capillary pressure (psi) τcosθ = interfacial tension (dyne/cm) X cosine of the contact angle (degrees) k = permeability (md) φ = porosity (fraction) function

14 Normalization: Leverett J Function J function works poorly for mixed lithofacies and between basins Does work OK for single lithofacies in a small area Leverett J Function md md md md md md md md md 0.012md 0.013md 0.032md 0.046md 0.085md 0.25md 0.41md 0.56md 0.84md 2.24md

15 Normalization: Brooks- Corey Capillary Pressure Transform taking logarithm of Pc and Sw λ represents pore throat size distribution Standard unimodal curves can be reduced to intercept (Pce = extrapolated threshold entry) and slope (λ) Pc = 1.54E+07Sw R 2 = λ Pce

16 Stress effect on Pc 0 R ft k = 113 md φ = 24.5% 0 R ft k = 7.96 md φ = 19.2% 113 md 8 md 0 E ft k = md φ = 12.2% 0 E ft k = mD φ = 9.5% 0 0 LD43C ft k = md φ = 12.9% 0.6 md 0.2 md B ft k = mD φ = 4.4% 0.04 md 0.02 md 0 0 no significant difference in high-low pairs at high K increasing Pce separation with decreasing K merging of curves at 35-50% Sw smaller pores are in protected pore space users of Winland R35 need to adjust for confining stress PA ft k = mD φ = 12.7% B ft k = md φ = 2.6% md md

17 Threshold Entry Pore Diame ter (µm) A Threshold Entry Gas Column Height (ft) C y = 11.77x 0.50 R 2 = 0.77 y = 11.28x 0.50 R 2 = E Klinkenberg Permeability/Porosity (md/%) y = 6.48x R 2 = 0.77 y = 6.75x R 2 = E-06 1E Klinkenberg Permeability/Porosity (md/%) threshold entry pressure is predictable from K/φ at any confining pressure correct unconfined Pce to insitu Pce based on perm change with stress

18 Brooks-Corey Slope Leverett J(Sw) = Pc (k/φ) 0.5 /τcosθ Implicitly assumes Pc slope = Constant Poor fit because Pc slope C = f(k, lith) Brooks-Corey Capillary Pressure Slope PSD expressed by Pc slope Pc slope = f (k) Pc slope with P y = Ln(x) R 2 = in situ unconfined y = Ln(x) R 2 = E In situ Klinkenberg Permeability (md)

19 Height above free water (ft) Modeled Pc curves k= md k=0.001 md k=0.01 md k=0.1 md k=1 md k= md Water Saturation (fraction) Pc properties evolve over time as diagenesis changes porosity and pore architecture Height above free water (ft) 1 Modeled Pc Curves Modeled Pc curves k= md k=0.001 md k=0.01 md k=0.1 md k=1 md k= md Water Saturation (fraction)

20 Drainge-Imbibition what is the residual trapped gas when a reservoir leaks or along a gas migration path? Approx. Height above Free Water Level (ft) Primary Drainage First Imbibition Secondary Drainage Second Imbibition Tertiary Drainage Third Imbibition

21 Trapping increases with increasing initial saturation (after Lake 2005)

22 Air-Hg C apillary Pressure (psia) k ik 0 E ft φ = 17.4% = 28.9 md 0 E ft φ = 15.0% = 1.93 md 0 Primary Drainage First Imbibition Secondary Drainage Second Imbibition Tertiary Drainage Third Imbibition Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition B ft (B) φ = 7.6% = md 0 Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition E ft (A) φ = 9.5% = md 0 Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition B ft (A) φ = 12.3% = 6.74 md 0 Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition 1 R ft (B) φ = 9.2% = md 0 Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition 1 S ft (B) φ = 8.6% = md Air-Hg Capillary Pressure (psia ) 0 Primary Drainage Primary Imbibition Second Drainage Second Imbibition Third Drainage Third Imbibition KM ft (B) φ = 5.9% = md Residual Gas Saturation C = 1/[(Snwr-Swi)-1/(Snwi-Swi)] Snwr = 1/[C + 1/Snwi] C = 0.55 (min ε); Swi = 0 Residual Nonwetting Phase Saturation (Snwr) unconfined confined Land C=0.66, Swi=0 Land C =0.54, Swi= Initial Nonwetting Phase Saturation (Snwi)

23 Residual 1.0 gas saturation Trapping constant, C consistent with cemented sandstone Residual Nonwetting Phase Saturation (Snwr) Complete trapping, C=0 Vuggy, isolated moldic, C=0.3 Mesaverde high C =0.35 Mesaverde Ss, C=0.55 Mesaverde low, C=0.9 Cemented Ss, C=0.7 Berea, C=1.7 Unconsolidated, sucrosic, oolitic, C= Initial Nonwetting Phase Saturation (Snwi)

24 Conclusions Drainage capillary pressure (Pc) can be modeled using equations for threshold entry pressure (Pte) and Brooks- Corey λ slopes. Confining pressure decreases largest pores consistent with permeability decrease but has little influence on smaller pores (pores largely protected by matrix) Snwr with Snwi Land-type relation: Snwr = 1/[ /Snwi] Mesaverde Project website is