METHOD OF TREATING BOTTOM-HOLE FORMATION ZONE

Abstract

The invention relates to the methods of treating a bottom-hole formation zone to increase in well productivity and rocks permeability. According to this method a pulse generator should be tripped in a well and the formation pulse treatment should be conducted by generating negative pressure pulses of amplitude higher than the tensile formation strength. The method provides the high fissuring rate by breaking formation fluid-bearing permeable rocks around a wellbore.

Description

DETAILED DESCRIPTION OF THE INVENTION

The invention is carried out as follows. A pulse generator should be tripped in a well and negative pressure pulses be generated around oil-bearing formation of amplitude higher than the tensile formation strength. A short and power pulse of magnitude of several MPa can initiate fissuring near a wellbore and in a created fracture (in case of hydraulic fracturing). Each next negative pressure pulse should make formation fissures grow. In case of hydraulic formation fracturing, pressure pulses can be fed as a breaking fissure grows. To create ruptures prior to pulse action the pressure is built in a bottom-hole well zone higher than pore pressure in a far-field zone for the formation; or in case of hydraulic fracturing the pressure is built in the created fracture higher than the principle maximum stress in the far-field zone for the formation. As an example let us consider an axisymmetric well of radius R being drilled straight, and the hydraulic fracturing (straight and vertical) of L long is in a permeable rock formation. The well cavity and the hydraulic fracturing are filled with fluid at a certain pressure P_w. For a well P_w>p₀, for hydraulic fracturing P_w>−σ₁^(f), where, p₀ is the pore pressure in the far-field zone (e.g. 5 MPa), and σ₁^(f) is the principle maximum stress in the far-field zone (e.g. 8 MPa) (it is taken that the tensile stress is positive). The pressure P_w has been applied for the set time to build up excessive pressure in the formation (i.e. fluid diffusion process). Elastic motion in the fluid-bearing pore medium is described by the following equations for a medium displacement vector u and a relative fluid displacement vector w:

$\begin{array}{cc}\rho +{\rho }_j=G\Delta \stackrel{\_}{u}+\stackrel{\_}{\nabla }\left[\left(K+\frac{1}{3}G+{\alpha }^2M\right)\left(\stackrel{\_}{\nabla }\stackrel{\_}{u}\right)+\alpha M\left(\stackrel{\_}{\nabla }\stackrel{\_}{w}\right)\right],& \left(1a\right)\\ {\rho }_f+\frac{T_{\varphi }}{\phi }{\rho }_f+\frac{\mu }{\kappa }=\stackrel{\_}{\nabla }\left[\alpha M\left(\stackrel{\_}{\nabla }\stackrel{\_}{u}\right)+M\left(\stackrel{\_}{\nabla }\stackrel{\_}{w}\right)\right].& \left(1b\right)\end{array}$

Where, p is the total mass density of the saturated rock, p_f is the pore fluid mass density, G is the shear modulus, K is the bulk modulus under drainage, M is the BioH modulus, α is the elastic pore medium coefficient, φ is the porosity, Tφ is the rock pore tortuosity coefficient, μ is the fluid viscosity, k is the rock permeability, and a point is the time derivative. Stress components and the pore pressure are in the form of the first space derivative {right arrow over (u)} and {right arrow over (w)}:

$\begin{array}{cc}{\sigma }_{\mathrm{ij}}=2{\mathrm{Ge}}_{\mathrm{ij}}+{\delta }_{\mathrm{ij}}\left(\left(K-\frac{2}{3}G+{\alpha }^2M\right)e-\alpha M\zeta \right),& \left(2a\right)\\ p=-\alpha \mathrm{Me}+M\zeta .\mathrm{Where},e_{\mathrm{ij}}=1/2\left(\partial u_i/\partial x_j+\partial u_j/\partial x_i\right),e=\sum _i\partial u_i/\partial x_i,\zeta =-\sum _i\partial w_i/\partial x_i.& \left(2b\right)\end{array}$

At the interface between the well fluid and the porous reservoir the following conditions are satisfied:

σ_nm=−P, σ_nτ=0, p=P  (3)

Where, the left-hand side of the equations has normal stress, shear stress and pore pressure, respectively, and P=P_w.+P(t) is the total pressure of the well fluid. Solving a problem (1) of the boundary conditions (3) for the wellbore and hydraulic fracturing gives the space stress and pore pressure distribution. The use of the below known criteria of the tensile failures and the failures according to a Mohr-Coulomb law is the possibility of estimating the tensile rock failure and the failure by shear fractures:

$\begin{array}{cc}{g}_{\mathrm{TC}}\equiv {\sigma }_1^{\mathrm{eff}}={\sigma }_1+p>T_0.& \left(4a\right)\\ g_{\mathrm{MC}}\equiv {\sigma }_1{\mathrm{tg}}^2\left(\frac{\pi }{4}+\frac{\varphi }{2}\right)-{\sigma }_3\ge {\sigma }_c& \left(4b\right)\end{array}$

Where, g_TC and g_MC are the function of fissure flow for ruptures and shear fractures, respectively, being analyzed to predict rock fracturing; T₀ and σ_c are the tensile strength and the crushing strength of the rock, respectively.

Dynamic pulses P(t) applied are of negative amplitude, for example, P(t)=−P-pulse exp⁻(−t²/T² pulse), where, P-pulse is the amplitude, and T-pulse is the pulse period.

Should the tensile formation strength T_o is 1 MPa, the amplitude P-pulse is rather powerful, e.g. 5 MPa, and the T-pulse duration for rock permeability k equal to 10⁻³ is rather short, e.g. 0.01 s; ruptures and shear fractures occurring around wellbore and created fractures. A fissure propagation direction can be predicted by the nature of the fissures themselves, i.e. ruptures or shear fractures. With pressure reduced, a maximum tensile component is radial relative to a wellbore wall and normal relative to a fissure direction at the surface of the fracturing. Therefore, ruptures propagate in parallel to the wellbore boundary or a created fracture. Shear fractures, if any, are inclined at an angle ψ_c=π/4−φ/2 to the direction of principle minimum stress, where, φ is the rock friction angle.

Claims

1. A method of treating a bottom-hole formation zone involving a pulse generator to be tripped in a well followed by formation pulse treatment distinguishing by the fact that negative pressure pulses should be generated of amplitude higher than tensile formation strength.

2. A method according to claim 1 distinguishing the fact that prior to pulse action the pressure is built in a bottom-hole well zone higher than the pore pressure in a far-field zone for the formation.

3. A method according to claim 1 distinguishing the fact that in case of hydraulic formation fracturing, pressure pulses should be fed as a breaking fissure grows.

4. A method according to claim 2 distinguishing the fact that prior to pulse action in the created fracture zone the pressure should be built higher than the principle maximum stress in a far-field zone for the formation.