Analysis of hydraulic fracture initiation and vertical propagation behavior in laminated shale formation

Numerical investigation of hydraulic fracture network propagation in naturally fractured shale formations


 Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.

Physical Simulation of Hydraulic Fracturing of Large-Sized Tight Sandstone Outcrops

Analysis of hydraulic fracture initiation and propagation in deep shale formation with high horizontal stress difference

Experimental study on the growth behavior of supercritical CO 2 -induced fractures in a layered tight sandstone formation

Multistage fracturing of the horizontal well is recognized as the main stimulation technology for shale gas development. The hydraulic fracture geometry and stimulated reservoir volume (SRV) is interpreted by using the microseismic mapping technology. In this paper, we used a computerized tomography (CT) scanning technique to reveal the fracture geometry created in natural bedding-developed shale (cubic block of 30 cm × 30 cm × 30 cm) by laboratory fracturing. Experimental results show that partially opened bedding planes are helpful in increasing fracture complexity in shale. However, they tend to dominate fracture patterns for vertical stress difference Δσ
 v
  ≤ 6 MPa, which decreases the vertical fracture number, resulting in the minimum SRV. A uniformly distributed complex fracture network requires the induced hydraulic fractures that can connect the pre-existing fractures as well as pulverize the continuum rock mass. In typical shale with a narrow (<0.05 mm) and closed natural fracture system, it is likely to create complex fracture for horizontal stress difference Δσ
 h
  ≤ 6 MPa and simple transverse fracture for Δσ
 h
  ≥ 9 MPa. However, high naturally fractured shale with a wide open natural fracture system (>0.1 mm) does not agree with the rule that low Δσ
 h
 is favorable for uniformly creating a complex fracture network in zone. In such case, a moderate Δσ
 h
 from 3 to 6 MPa is favorable for both the growth of new hydraulic fractures and the activation of a natural fracture system. Shale bedding, natural fracture, and geostress are objective formation conditions that we cannot change; we can only maximize the fracture complexity by controlling the engineering design for fluid viscosity, flow rate, and well completion type. Variable flow rate fracturing with low-viscosity slickwater fluid of 2.5 mPa s was proved to be an effective treatment to improve the connectivity of induced hydraulic fracture with pre-existing fractures. Moreover, the simultaneous fracturing can effectively reduce the stress difference and increase the fracture number, making it possible to generate a large-scale complex fracture network, even for high Δσ
 h
 from 6 MPa to 12 MPa.

Experimental Investigation into Hydraulic Fracture Network Propagation in Gas Shales Using CT Scanning Technology

The flow capacity of hydraulic fracturing fractures with low concentration proppant specifically monolayer proppant in coal beds is measured by using FCES-100 fracture flow capacity instrument,and on which the effects of proppant embedment and natural fractures are considered.The experimental results show that under lower closure pressure,monolayer proppant can support the hydraulic fracturing fractures in coal beds and good flow capacity of fracturing fractures can be obtained.There is difference in flow capacity of fracturing fractures in the coal beds of different mechanical properties.Under higher closure pressure,the flow capacity of fracturing fractures will be damaged by the proppant embedding into soft coal rock.Besides,time and natural fractures will produce influence on the flow capacity of fracturing fractures with monolayer proppant.

Experimental study on the flow capacity of the fracturing fractures with monolayer proppant in coal beds

The mathematical model of brittle rock triaxial compression simulation is established and solved by the secondary development of COMSOL, and the numerical model is verified by rock uniaxial compression experiment and triaxial compression experiment. The meso-damage evolution of brittle rock under triaxial compression is simulated, and the influence of heterogeneity coefficient, confining pressure and loading rate on stress-strain curve and ultimate failure mode are studied. The results show that: The enhancement of rock heterogeneity makes the core failure position more dispersed, and when the coefficient of heterogeneity decreases from 10 to 0.8, the young's modulus decreases by 14.92%, and the peak strength decreases by 35.45%; The increase of confining pressure makes the failure events gather to the fault surface, and when the confining pressure increases from 0MPa to 40MPa, the young's modulus increases by 22.57%, the peak strength increased by 94.47%, and the residual strength increased by 112 times; The increase of loading rate makes the rock failure unit relatively dispersed, resulting in two fault planes, and when the loading rate increases from 0.01 × 10−3 to 0.2 × 10−3, the peak strength increases by 7%. This paper provides a reference for more accurate, rapid and comprehensive study of rock triaxial compression numerical simulation.

Meso-numerical simulation of rock triaxial compression based on the damage model

The average burial depth of carbonate reservoirs in Shunbei area exceeds 7300 meters, and the bottom hole temperature is as high as 160°C. The commonly used cross-linked acid system cannot meet the needs of acid fracturing. Therefore, this article uses AM, AMPS, acrylamide (AM) modified monomers, acrylic acid (AA) modified monomers to synthesize thickener SBCH-1, the organic zirconium crosslinking agent SBJL1 was synthesized with zirconium oxychloride, isopropanol, citric acid and diethanolamine. And other auxiliary agents are selected, and the final formula is determined as: 220% HCl+0.8% SBCH-1 thickener +0.8% SBJL-lcrosslinking agent +0.8% SBYC-1 crosslinking retarder +2% SBHS-1A high temperature corrosion inhibitor +2% SBHS-1B high temperature corrosion inhibitor +1% SBTW-4 iron ion stabilizer +1% SBZP-2 drainage aid +1% SBPR-1 demulsifier. The viscosity of the system stabilized above 200mPa⋅s after continuous shearing at 160°C, 170s-1 for 30min.

https://iopscience.iop.org/article/10.1088/1755-1315/687/1/012148/pdf

Guo Tiankui

Papers

Experimental Investigation into Hydraulic Fracture Network Propagation in Gas Shales Using CT Scanning Technology

Experimental study on the flow capacity of the fracturing fractures with monolayer proppant in coal beds

Meso-numerical simulation of rock triaxial compression based on the damage model

Research and development of ultra-high temperature delayed crosslinking acid system