Numerical Modeling of Variable Fluid Injection-Rate Modes on Fracturing Network Evolution in Naturally Fractured Formations

Wang, Yu; Xiao, Li; Zhang, Bo

doi:10.3390/en9060414

Cited by 12 publications

(2 citation statements)

References 32 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…In the 1950s, field experiments related to the miscibility of CO 2 and crude oil were carried out in the Permian Basin of the United States. CO 2 , one of the products generated after the combustion of crude oil, was injected into the reservoir from the wellhead to improve oil recovery [21][22][23][24]. CO 2 will be in a supercritical state under the conditions of high temperature and high pressure in the formation, as its density is similar to that of a liquid, and its viscosity is similar to that of a gas.…”

Section: Introductionmentioning

confidence: 99%

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

He,

Ma,

Lei

et al. 2024

Processes

View full text Add to dashboard Cite

Chemical sequestration is one important manner of CCUS. The injection of CO2 into an oil reservoir can not only sequestrate CO2 but also raise the oil recovery factor. The performance of chemical sequestration of CO2 depends on the interaction between CO2 solution and reservoir rock. In this paper, we have conducted three different scales of experiments, e.g., microscopic scale, core scale, and time scale, to fully investigate the interaction and resultant variation to mineral content, microscopic structure, porosity, and permeability under reservoir conditions (i.e., reservoir temperature of 90 °C) in Jimusar shale oil formation. The microscopic-scale experiment applied SEM and hyperspectral scanning to obtain microscopic pore throat structure and element distribution before and after soaking the rock in CO2 solution. The core-scale experiment employed XRD to evaluate mineral content variation caused by CO2 solution. Core flooding experiments were conducted to evaluate porosity and permeability variation caused by the dissolution of CO2 solution into the core samples. The third type of experiment was employed to investigate the effect of time sequence on the dissolution, in which the time ranged from 1 day to 14 days continuously. The experimental results indicate that, under Jimsar reservoir conditions, CO2 solution exhibits a relatively robust dissolution capability, causing significant alterations to the properties of the core samples. Specifically, the CO2 solution effectively dissolves carbonate upon contact. Calcite is the primary target for dissolution, followed by dolomite. In the presence of sufficient CO2, complete dissolution of all carbonates is achievable. On a microscopic scale, dissolution primarily occurs in the calcium-rich areas, leaving other regions unaffected. The typical pore size resulting from CO2 solution-induced dissolution ranges from several to dozens of micrometers. This dissolution process significantly enhances both porosity and permeability. For Jimsar shale core samples, porosity experienced an increase of over 20%, and permeability nearly doubled. Under Jimsar reservoir conditions at 90 °C, CO2 solution can consume all carbonates present in core samples within 8 days. The increase in porosity and permeability is rapid during the initial days and stabilizes around the 6th day. These research findings establish a theoretical foundation for CO2 chemical sequestration.

show abstract

Section: Introductionmentioning

confidence: 99%

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

He,

Ma,

Lei

et al. 2024

Processes

View full text Add to dashboard Cite

show abstract

“…However, with the advancement of computer technology and the improvement of computing power, scholars have begun to focus on the crucial effect of heterogeneity on hydraulic fracturing. Wang et al (2016c) investigated how reservoirs respond to variable injection rates in different hydraulic fracturing stages, and they considered the macroscopic characteristics and microscopic heterogeneous characteristics simultaneously by introducing heterogeneity of the failure strength and elastic modulus into their numerical discrete-fracture model. Yang et al conducted triaxial hydrofracturing tests of heterogeneous rock with irregular, randomly distributed gravel to study the heterogeneity effects of unconventional reservoir rock on the 3D initiation, growth, and distribution of hydrofracturing cracks.…”

Section: Introductionmentioning

confidence: 99%

Effect of matching relation of multi-scale, randomly distributed pores on geometric distribution of induced cracks in hydraulic fracturing

Peng

2020

Energy Exploration & Exploitation

View full text Add to dashboard Cite

Reservoir rock contains many multi-scale, unevenly distributed pores, and the pore structures of shale in different reservoirs and geological environments vary greatly. Because the seepage velocity and pressure field are related to the pore spatial variations, the inhomogeneity of the seepage is superimposed on the anisotropy of the rock’s physical properties, which will affect the distribution of the induced cracks. A method for calculating the pore size in the bonded particle model, based on Delaunay triangulation, is proposed. A modeling approach capable of simulating the multi-scale pore distribution of actual rock is presented based on the proposed method. To understand how microcracks connect micropores in the process of fracturing, several bonded particle model samples with different pore structures were established, and numerical experiments were conducted based on the coupling calculation of the discrete seepage algorithm and discrete element method. The focus of this study was on the interactions between the distribution characteristics of multi-scale pores, the specific physical properties of the fracturing fluid, and the distribution differences of the induced cracks caused by the special seepage characteristics when using different fracturing fluids. The numerical results showed that the advantages of supercritical CO2 fracturing are maximized in deep reservoirs (high in-situ stress) and that a suitable in-situ stress condition is required (i.e. a stress ratio close to 1).

show abstract

Laboratory investigation of hydraulic fracture propagation using real-time ultrasonic measurement in shale formations with random natural fractures

Wang

et al. 2017

Environ Earth Sci

View full text Add to dashboard Cite

Numerical Modeling of Variable Fluid Injection-Rate Modes on Fracturing Network Evolution in Naturally Fractured Formations

Cited by 12 publications

References 32 publications

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

An Experimental Investigation of Interaction between CO2 Solution and Rock under Reservoir Conditions in the Jimsar Shale Oil Formation

Effect of matching relation of multi-scale, randomly distributed pores on geometric distribution of induced cracks in hydraulic fracturing

Laboratory investigation of hydraulic fracture propagation using real-time ultrasonic measurement in shale formations with random natural fractures

Contact Info

Product

Resources

About