Estimating Klinkenberg-Corrected Permeability From Mercury-Injection Capillary Pressure Data: A New Semianalytical Model for Tight Gas Sands Conference Paper uri icon

abstract

  • Abstract This paper presents the practical applications of a semi-analytical model for estimating the Klinkenberg-corrected per-meability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The fundamental relationships be-tween rock pore size/geometry and basic rock properties are well-documented in the petroleum literature. Moreover, since rock pore characteristics can be accurately quantified from interpretation of mercury-injection capillary pressure data, the literature is replete with models for estimating permeability from Hg-pc data. However, existing Hg-pc models tend to yield inconsistent results --- and few models have been shown to be directly applicable for low-permeability sands. The basis of our model is the Purcell/Burdine model (bundle of capillary tubes) combined with the Brooks/Corey model (power law relationship of capillary pressure versus wetting phase saturation). We tested our model using more than 100 sets of mercury-injection capillary pressure data. Effective porosity in our data set ranges from 4 to 14 percent, while absolute permeability ranges from 0.005 to 0.5 md. The primary technical contribution of this paper is a tuned model for estimating Klinkenberg-corrected permeability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The final form of our model allows estimation of the absolute (Klinkenberg-corrected) permeability as a function of effective porosity, irreducible wetting phase saturation, dis-placement pressure, and pore size characteristics. The model is also reversible --- we can estimate a capillary pressure profile from routine permeability and porosity data. Introduction Concepts: This work follows closely the concept and form of a recent study that sought to quantify permeability estimates using only capillary pressure data [Huet et al (2005)]. In the original study, the primary objective was to establish the feasibility of a correlation of k = f(f, pd, Swi, l) --- where the pd, Swi, and l-parameters are estimated (specifically) from an Hg-pc data set. The generic (power law) correlation model given by Huet et al (2005) is given as: Equation (1) Where: k = Permeability, md f = porosity, fraction of pore volume pd = Capillary displacement (or threshold) pressure, psia Swi = Irreducible wetting phase saturation, fraction l = Brooks-Corey pore-size index, dimensionless The "units" of Eq. 1 (k-md and pd-psia) are arbitrary because this relation is "tuned" to data --- the user can adjust the relation as desired, provided attention is given to the multiplier coefficient (a1). For comparison to Eq. 1, we present the general form of the Nakornthap and Evans/Brooks-Corey result Equation (2) Where: k = permeability, md 10.66 = units conversion constant, md-(psia)2/(dynes/cm)2 w = pore throat "impedance" factor, dimensionless n = number of entrances/exits in a pore, dimensionless sHg-air = mercury-air interfacial tension, dynes/cm q = contact angle of incidence for wetting phase, radians f = porosity, fraction of pore volume pc = capillary pressure, psia pd = Capillary displacement (or threshold) pressure, psia Swi = Irreducible wetting phase saturation, fraction l = Brooks-Corey pore-size index, dimensionless

name of conference

  • Rocky Mountain Oil & Gas Technology Symposium

published proceedings

  • All Days

author list (cited authors)

  • Blasingame, T. A., Rushing, J. A., Huet, C. C., & Newsham, K. E

complete list of authors

  • Blasingame, Thomas Alwin||Rushing, Jay Alan||Huet, Caroline Cecile||Newsham, Kent Edward

publication date

  • January 1, 2007 11:11 AM

publisher

  • SPE  Publisher