US 2026/0139574 A1 · Multifactorial optimization method for deep coal and rock gas pressure return nozzles

Abstract

This invention discloses an optimization method for flowback nozzles in deep coal and rock gas formations, considering the influence of multiple factors, belonging to the field of coal and rock gas extraction technology. Addressing the challenge of flowback fluid velocity control in deep coal and rock gas development, this method establishes models for matrix and fracture seepage and two-phase flow within the wellbore. It comprehensively considers the migration of pulverized coal and proppant, as well as the influence of coal seam cleavage fractures, to optimize wellhead nozzle size, reduce the probability of pulverized coal clogging fractures, and improve fracture conductivity. Compared to traditional methods, this invention has significant advantages in improving fracturing efficiency and high-efficiency coal and rock gas extraction, providing an innovative solution for the scientific research and engineering applications of deep coal and rock gas.

A multifactorial optimization method for deep coal and rock gas pressure return nozzles, characterized by comprising the following main steps:

(1) Based on the dual-porosity medium model, a multi-stage, multi-cluster fracturing-flowback model is established to continuously simulate the injection and production processes. The physical behavior of the gas-liquid two-phase flow during fracturing and flowback is characterized by adjusting the fracturing fluid rate during injection and production. The model specifically includes the following equations:
∇
[
k
f
⁢
k
r
⁢
g
⁢
f
μ
f
⁢
g
⁢
B
f
⁢
g
⁢
∇
(
p
f
⁢
g
-
ρ
f
⁢
g
⁢
g
⁢
H
)
]
+
q
gmf
*
-
q
ν
⁢
g
=
∂
∂
t
(
ϕ
f
⁢
S
f
⁢
g
B
f
⁢
g
)
(
1
)
∇
[
k
f
⁢
k
r
⁢
w
⁢
f
μ
fw
⁢
B
f
⁢
w
⁢
∇
(
p
f
⁢
w
-
ρ
fw
⁢
g
⁢
H
)
]
+
q
w
⁢
m
⁢
f
*
-
q
ν
⁢
w
=
∂
∂
t
(
ϕ
f
⁢
S
f
⁢
w
B
f
⁢
w
)
(
2
)
-
q
g
⁢
m
⁢
f
*
+
q
ν
⁢
m
=
∂
∂
t
(
ϕ
m
⁢
S
m
⁢
g
B
m
⁢
g
)
(
3
)
-
q
w
⁢
m
⁢
f
*
=
∂
∂
t
(
ϕ
m
⁢
S
m
⁢
w
B
m
⁢
w
)
(
4
)
In the formula, ∇ represents the gradient operator symbol (dimensionless);
∂ represents the partial differential symbol, (dimensionless);
t represents time, (s);
φf represents fracture porosity, (dimensionless);
kf represents fracture permeability, (10−3 μm2);
pfg and pfw represent the gas and water phase pressures in the fracture system, respectively (MPa);
μfg and μfw represent the viscosity of gas and water in the fracture system, respectively (mPa·s);
krgf and krwf represent the relative permeability of gas and water in the fracture system, (dimensionless);
ρfg and ρfw represent the density of gas and water in the fracture system, respectively (kg/m3):
g represents gravitational acceleration, taken as g=9.8 m/s2;
H represents formation depth (m);
Bfg and Bfw represent the gas and water phase volume coefficients in the fracture system (dimensionless);
Sfg and Sfw represent the gas and water phase saturation in the fracture system (dimensionless);
qvg and qvw represent the gas and water production per unit volume of coal reservoir, respectively (m3/(m3·s));
q*gmf and q*wmf represent the gas and water phase exchange rates between the fracture and matrix pore systems, respectively (m3/(m3·s));
φm represents the matrix porosity (dimensionless);
Smg and Smw represent the gas and water phase saturation rates in the matrix pore system, respectively (dimensionless);
Bmg and Bmw represent the gas and water volume coefficients within the matrix pores, respectively (dimensionless);
qvm represents the flow rate of desorbed gas from the matrix pore surface to the matrix pores (m3/(m3·s)).
(2) Establish flow models of nozzle and wellbore systems, and use the principle of material balance to establish the pressure transmission relationship between these two and the fracturing-flowback model;
(3) Establish a critical flow model for proppant and pulverized coal within the fracture;
(4) By using the reservoir IPR curve obtained in step (1), the relationship between the critical flow rate and the nozzle size obtained in step (2), and the critical flow rates corresponding to the proppant initiation and the pulverized coal initiation in the fracture obtained in step (3), the nozzle size range under a certain formation pressure is determined.
(5) As the flowback time increases, the formation pressure decreases and the phase changes. The reservoir IPR curve and the critical flow rates corresponding to proppant initiation and pulverized coal initiation in fractures will also change. Repeat step (4) to obtain the new nozzle size range after the formation pressure decreases. Integrate the wellhead pressure at this time with the optimized nozzle size range to obtain the relationship between nozzle size and wellhead pressure after fracturing of the well.

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Multifactorial optimization method for deep coal and rock gas pressure return nozzles

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Multifactorial optimization method for deep coal and rock gas pressure return nozzles

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Abstract

Claims5