Lithologic Reservoirs ›› 2026, Vol. 38 ›› Issue (3): 173-181.doi: 10.12108/yxyqc.20260315

• PETROLEUM ENGINEERING AND OIL & GAS FIELD DEVELOPMENT • Previous Articles     Next Articles

Pressure dynamic characteristics of CO2 flooding in dual porosity media reservoirs

CAO Xiutai1(), ZHONG Huiying1,2(), SUN Yuxin1, ZHOU Hongliang3, FU Jing4   

  1. 1 Key Laboratory of Enhanced Recovery of Ministry of Education, Northeast Petroleum University, Daqing 163318, Heilongjiang, China
    2 Key Laboratory of Reservoir Stimulation, China National Petroleum Corporation, Daqing 163318, Heilongjiang, China
    3 Yushulin Company Geological Technology Research Institute， Daqing Oilfield Co., Ltd., Daqing 163318, Heilongjiang, China
    4 Department of Petroleum Engineering, Colorado School of Mines, Golden 80401, Colorado, USA
  • Received:2025-09-23 Revised:2025-11-06 Online:2026-05-01 Published:2026-01-22

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Abstract:

Shale oil reservoirs subjected to complex hydraulic fracturing are prone to evolve into dual porosity media. Due to differences in matrix-fracture seepage behavior and the areal heterogeneity of “concentration-viscosity” after CO2 injection, the pressure-response mechanism of CO2 flooding becomes highly complex, resulting in insufficient accuracy in pressure-transient characterization and parameter inversion. Fick’s law was employed to investigate the CO2 distribution characteristics. A dual porosity flow model was established by simultaneously accounting for concentration-viscosity-pressure coupling and the matrix threshold pressure gradient. The governing flow equations are solved numerically to generate pressure-transient curves for CO2 flooding in dual porosity reservoirs, and effects of the matrix threshold pressure gradient, elastic storativity ratio, interporosity-flow coefficient, injection rate, and diffusion coefficient on the pressure-transient behavior were analyzed. The results show that: (1) A larger matrix threshold pressure gradient leads to a more pronounced late-time upturn of both pressure and pressure-derivative curves on the well testing curve. （2） A smaller elastic storativity ratio produces a wider and deeper “trough” in the pressure-derivative curve during the interporosity-flow stage. （3） With decreasing interporosity-flow coefficient, matrix-to-fracture crossflow slows down,the “trough” in the pressure-derivative curve moves to the right and becomes deeper. A larger interporosity-flow coefficient makes the late-time upturn in the pressure curve more evident. （4） A higher injection rate increases both pressure and pressure-derivative levels over the entire testing period and narrows the “trough” during the interporosity-flow stage. （5） The diffusion coefficient mainly influences the radial-flow stage of the composite system in the late stage: a larger diffusion coefficient causes this stage to occur earlier, reduces flow resistance, and shifts the pressure and pressure-derivative curves downward. （6） The proposed model enables quantitative characterization of pressure-transient features during CO2 injection in fractured wells of Daqing Oilfield.

Key words: dual porosity media, CO2 flooding, pressure-transient curve, threshold pressure gradient, elastic storativity ratio, interporosity-flow coefficient, injection rate, diffusion coefficient, seepage mathematical model

CLC Number: 

  • TE353

Fig. 1

Physical model of CO2 flooding in a dual porosity media reservoir"

Fig. 2

Schematic of the configuration of fracture-pore dual porosity media reservoir"

Table 1

Dimensionless variables"

无因次变量 定义 无因次变量 定义
无因次渗透率 ${K}_{D}=\frac{{K}_{m}}{{K}_{f}}$ 无因次半径 ${r}_{D}=\frac{r}{{r}_{w}}$
无因次压力 ${{p}_{D}}_{{}_{j}}\left({r}_{D},{t}_{D}\right)=\frac{2\pi {K}_{f}h}{q{\mu }_{g}B}\left({p}_{0}-{p}_{j}\right)$
j=m,f		 无因次启动压力梯度 ${G}_{D}=\frac{2\pi {K}_{f}h{r}_{w}}{q{\mu }_{g}B}G$
无因次井筒储集系数 ${C}_{D}=\frac{1}{2\pi {\varphi }_{f}{C}_{tf}h{r}_{w}^{2}}C$ 无因次黏度 ${\mu }_{D}=\frac{{\mu }_{0}}{{\mu }_{mix}}$

Fig. 3

Comparison of the pressure dynamic curves calculated by the established model and tNavigator software"

Table 2

Reservoir parameters from S151 block of Daqing Oilfield"

参数 数值 参数 数值
CO2注入速度/
(m3·s-1)		 4.63×10-4 油藏厚度/m 5.0
扩散系数/(m2·s-1) 2.46×10-6 井筒半径/m 0.1
外边界半径/m 100 体积系数 1.12
基质渗透率/mD 0.500 裂缝渗透率/mD 1 000
启动压力梯度/
(Pa·m-1)		 4×104 井筒存储系数/(m3·Pa-1) 1×10-8
表皮系数 0.1 原油初始黏度/(Pa·s) 0.35×10-3
CO2黏度/(Pa·s) 0.05×10-3 窜流系数 1×10-6
弹性储能比 0.01 综合压缩系数/
Pa-1		 4×10-8

Fig. 4

CO2 concentration variation curves in dual porosity media reservoirs"

Fig. 5

Mixed viscosity change curves in dual porosity media reservoirs"

Fig. 6

Pressure dynamic curves of CO2 flooding in dual porosity media reservoirs"

Fig. 7

Pressure and pressure-derivative curves under different dimensionless threshold gradient"

Fig. 8

Pressure and pressure-derivative curves of w under different elastic storativity ratio"

Fig. 9

Pressure and pressure-derivative curves of λ under different interporosity-flow coefficient"

Fig. 10

Pressure and pressure-derivative curves of Q under different CO2 injection rate"

Fig. 11

Mixed viscosity curves of H under different diffusion coefficients with identical time (180 days)"

Fig. 12

Pressure and pressure-derivative curves of H under different diffusion coefficients"

Fig. 13

CO2 flooding well testing fitting curves of dual porosity media reservoirs in typical measured wells"

Table 3

Well testing interpretation results of well X11 and well X302 in S151 block and S11 block of Daqing Oilfield"

井号 井筒储集系数/(m3·Pa-1) 表皮
系数		 基质
渗透率/mD		 裂缝
渗透率/mD		 窜流系数 弹性
储能比		 扩散系数/
(m2·s-1)		 启动压力梯度/(Pa·m-1)
X11井 2.91×10-8 0.15 0.132 1 120 2.314×10-5 0.112 2.46×10-6 2.4×104
X302井 2.48×10-8 0.20 0.793 1 460 1.056×10-6 0.009 2.12×10-6 —
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