Numerical simulation of fractured imbibition in a shale oil reservoir based on the discrete fracture model
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摘要: 對于含黏土礦物較高的頁巖油儲層，地層水的礦化度可高達4.786×103 mol·m?3，壓裂過程中與注入的低礦化度壓裂液形成的滲透壓作用顯著。為探究滲透壓對滲吸的影響作用，建立了綜合考慮滲透壓和毛管力滲吸作用的油水兩相二維離散裂縫網絡模型，開展了頁巖油儲層壓裂液泵注和關井階段滲透壓、毛管力、關井時間、鹽濃度、膜效率、分支縫面積占比等對滲吸的影響規律研究。結果表明：①濾失主要由壓力差、毛管力和滲透壓3種機制驅動，其中壓力差是濾失的關鍵控制機制；②關井時間對壓裂液的滲吸作用影響較大，關井50 d時，前15 d滲吸量可達到總滲吸量的80%，且關井壓力擴散會波及到兩側壓裂段；③與壓力擴散相比，滲透壓達到平衡的時間較長，對于地層水礦化度為4.786×103 mol·m?3的情況，裂縫附近的礦化度達到600 mol·m?3左右所需關井時間為50 d；④由于壓力差是滲吸主要驅動力，頁巖膜效率對滲透壓力擴散影響微弱，頁巖膜效率30%與5%相比滲吸量僅增加4%；⑤對于密切割壓裂，關井后，含水飽和度受小間距水力裂縫控制，分支縫對滲吸含水飽和度的影響有限。Abstract: When a shale oil reservoir contains a mass of clay minerals, the salinity of formation water can reach up to 4.786×103 mol·m?3 and the formation water and low salinity fracturing fluid create significant osmotic pressure during the fracturing process. To investigate the effect of osmotic pressure on the imbibition effect, a two-dimensional, oil-water, two-phase, discrete fracture network model was established. This model comprehensively considers osmotic pressure and capillary force. Additionally, a series of studies were carried out to explore the influence of osmotic pressure, capillary force, shut-in time, salt concentration, membrane efficiency, and the proportion of branch fracture area on the imbibition effect in shale oil reservoirs during fracturing fluid pumping and shut-in. The results show that: (1) Filtration is mainly influenced by pressure difference, capillary force, and osmotic pressure, and pressure difference is the key control mechanism of filtration. (2) The shut-in time has a great influence on the imbibition effect of fracturing fluid. The imbibition amount in the first 15 d can reach 80% of the total imbibition amount when the well is shut in for 50 d, leading to the shut-in pressure spreading to the fracturing interval on either side. (3) Osmotic pressure takes longer to reach equilibrium than diffusion pressure. Osmotic pressure takes 50 d to shut in the well and make the salinity near the fracture reach 600 mol·m?3 when the salinity of local layer water is 4.786×103 mol·m?3. (4) As pressure difference is the main factor that affects the imbibition effect and the effect of shale film efficiency on seepage pressure diffusion is weak, the extent of imbibition increases by only 4% when the shale film efficiency increases from 5% to 30%. (5) Water saturation is controlled using hydraulic fractures through small spacing during shut-in, and the influence of branch fractures on water saturation is limited in intensive volume fracturing to horizontal wells.
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Key words:
- shale oil reservoir /
- imbibition /
- osmotic pressure /
- discrete fracture model /
- numerical simulation /
- shut-in time
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圖 9 不關井情況下的飽和度，壓力，鹽濃度分布
Figure 9. Saturation, pressure, and salt concentration without shut-in
圖 10 關井50 d后的飽和度，壓力，鹽濃度分布
Figure 10. Saturation, pressure, and salt concentration distribution after 50 days of shut-in
圖 15 不同礦化度下的鹽濃度分布。（a）泵注后；（b）關井后
Figure 15. Distribution of salt concentration under various salinity levels: (a) after pump injection; (b) after the shut-in
圖 16 關井后不同礦化度下的飽和度分布
Figure 16. Distribution of saturation under various salinity levels
圖 19 不同分支縫面積占比的剖面圖。（a）含水飽和度；（b）鹽濃度
Figure 19. Sectional views of various branch joint area proportions: (a) water saturation; (b) salt concentration
表 1 模型參數
Table 1. Simulation parameters
Parameter Value Parameter Value Reservoir area/（m×m） 200 × 500 Hydraulic fracture spacing/m 15 Initial reservoir pressure/MPa 30 Reservoir temperature/℃ 90 Rock compressibility/Pa?1 2 × 10?9 Initial water saturation/dimensionless 0.2 Water compressibility/Pa?1 5 × 10?9 Oil compressibility/Pa?1 2×10?9 Permeability of matrix/mD 0.01 Permeability of hydraulic fracture/D 10 Porosity of matrix 0.1 Porosity of hydraulic fracture 0.25 Water density/(kg·m?3) 1000 Oil density/(kg·m?3) 800 Water viscosity/(mPa·s) 1 Oil viscosity/(mPa·s) 5 Hydraulic fracture width/mm 5 Pumping rate/(m3·min?1) 15 Residual oil saturation 0.05 residual water saturation 0.2 Initial reservoir salt concentration /(mol·m?3) 2.565 × 103 [15] Fracturing fluid salt concentration/(mol·m?3) 17.1 [15] Diffusion coefficient/(m2·s?1) 1 × 10?9 [14] Osmotic efficiency 10% [15] Secondary fracture permeability/D 1 Secondary fracture porosity 0.15 Unconnected natural fracture permeability/mD 10 Unconnected natural fracture porosity 5 × 10?4 Hydraulic fracture half-length/m 200 Secondary fracture length/m 20–70 Secondary fracture aperture /mm 2 Unconnected natural fracture aperture/mm 0.5 
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