A method for determining core permeability in pulse decay experiments, the method comprising the steps of: connecting an upstream reservoir to one end of a sample holder comprising a core sample (130, 230) of a subsurface formation; connecting a downstream reservoir to another end of the sample holder; providing a constant confining pressure (P c) within the sample holder; saturating the sample holder and the core sample (130, 230) with nitrogen at a saturation pressure, P saturation; applying a pressure pulse, P pulse, to one end of the sample holder; determining porosity purely from the mobile continuum when the pressure in the upstream reservoir, the downstream reservoir, and the mobile continuum within the core sample (130, 230), is in equilibrium, and the pressure in the upstream reservoir and the pressure in the downstream reservoir are equal; wherein the method is characterised in that the porosity purely from the mobile continuum is determined by the formulas: V u + V d + V f ρ saturation + V u ρ pulse = V u + V d + V f ρ A; φ f = V f V bulk; φ f < φ t; where 'Φ f ' is the porosity of the sample purely from the mobile continuum, 'Φ t ' is the total porosity, 'V f ' is the pore volume of the mobile continuum, and 'V bulk ' is the bulk volume of the sample (130, 230) (where V bulk = L * A; 'L' is the sample length, and 'A' is the cross-sectional area of the sample (130, 230)), and ρ saturation, ρ pulse, ρ A are gas densities corresponding to pressures of P saturation, P pulse, and P A, respectively, and subscript A indicates the time when the pressure inside the upstream reservoir, the downstream reservoir, and the mobile continuum reaches equilibrium; and determining core permeability using the porosity purely from the mobile continuum, wherein the core permeability is determined by solving the following formulas for "k": t D = kt c μφ f L 2; a = V t V u; b = V t V d; tan θ = a + b θ θ 2 − ab; Δ P t D = P u t D − P d t D P u 0 − P d 0 = 2 ∑ m = 1 ∞ exp − t D θ m 2 a b 2 + θ m 2 − − 1 m b a 2 + θ m 2 b 2 + θ m 2 0.5 θ m 4 + θ m 2 a + a 2 + b + b 2 + ab a + b + ab where 'c' is the gas compressibility, 'μ' is the gas viscosity, 'V u ' is the upstream reservoir volume, 'V d ' is the downstream reservoir volume, 'P u (t)' is the pressure of the upstream side, 'P d (t)' is the pressure of the downstream side, 'k' is the core permeability, and `t' is time. connecting an upstream reservoir to one end of a sample holder comprising a core sample (130, 230) of a subsurface formation; connecting a downstream reservoir to another end of the sample holder; providing a constant confining pressure (P c) within the sample holder; saturating the sample holder and the core sample (130, 230) with nitrogen at a saturation pressure, P saturation; applying a pressure pulse, P pulse, to one end of the sample holder; determining porosity purely from the mobile continuum when the pressure in the upstream reservoir, the downstream reservoir, and the mobile continuum within the core sample (130, 230), is in equilibrium, and the pressure in the upstream reservoir and the pressure in the downstream reservoir are equal; wherein the method is characterised in that the porosity purely from the mobile continuum is determined by the formulas: V u + V d + V f ρ saturation + V u ρ pulse = V u + V d + V f ρ A; φ f = V f V bulk; φ f < φ t; where 'Φ f ' is the porosity of the sample purely from the mobile continuum, 'Φ t ' is the total porosity, 'V f ' is the pore volume of the mobile continuum, and 'V bulk ' is the bulk volume of the sample (130, 230) (where V bulk = L * A; 'L' is the sample length, and 'A' is the cross-sectional area of the sample (130, 230)), and ρ saturation, ρ pulse, ρ A are gas densities corresponding to pressures of P saturation, P pulse, and P A, respectively, and subscript A indicates the time when the pressure inside the upstream reservoir, the downstream reservoir, and the mobile continuum reaches equilibrium; and determining core permeability using the porosity purely from the mobile continuum, wherein the core permeability is determined by solving the following formulas for "k": t D = kt c μφ f L 2; a = V t V u; b = V t V d; tan θ = a + b θ θ 2 − ab; Δ P t D = P u t D − P d t D P u 0 − P d 0 = 2 ∑ m = 1 ∞ exp − t D θ m 2 a b 2 + θ m 2 − − 1 m b a 2 + θ m 2 b 2 + θ m 2 0.5 θ m 4 + θ m 2 a + a 2 + b + b 2 + ab a + b + ab where 'c' is the gas compressibility, 'μ' is the gas viscosity, 'V u ' is the upstream reservoir volume, 'V d ' is the downstream reservoir volume, 'P u (t)' is the pressure of the upstream side, 'P d (t)' is the pressure of the downstream side, 'k' is the core permeability, and `t' is time.