Permeability Enhancement via Acetic Acid (CH₃COOH) Acidizing in Coals Containing Fracture-Filling Calcite

Abstract

Calcite is one of the most common fracture-filling minerals in low-permeability coal seams and can be dissolved easily by acid. Although much attention has been paid recently to coal seam acidizing, only few studies have focused on the permeability evolution during the injection of organic acid, which has a very different reaction rate and dissolution structure morphology from those of conventional strong acids (e.g., HCl and HF). In this study, 0.25−1.0 mol/L acetic acid (CH 3 COOH) was injected into the coal plug samples from the Fuxin Basin in China, whose fractures were completely infilled by calcite. The evolution of plug permeability during CH 3 COOH flooding was monitored. Before and after flooding experiments, the coal plugs were characterized using micro-computed tomography imaging, scanning electron microscopy, and nuclear magnetic resonance. The results showed that fracture-filling calcite exhibits high reactivity after exposure to CH 3 COOH at the temperatures of 20, 30, and 40 °C, and the macro-/microscale highly conductive flow channels between the inlet and the outlet of coal plugs can be formed in several hours. Thus, a significant permeability improvement from less than 0.02 mD to over 27 mD was observed during CH 3 COOH flooding. These increases ranging from 131 to 2720 times of the initial permeability are mainly due to the presence of fracture-filling calcite with high connectivity and the absence of fine migration, clay swelling, and secondary Fe-rich precipitation in the CH 3 COOH environment. The results also suggested that the minimum volume of CH 3 COOH required for a highly conductive flow channel breakthrough can be less than 1.0 PV. This investigation demonstrated the potential of deep matrix-acidizing treatment using CH 3 COOH for improving the permeability and enhanced coalbed methane recovery in coal seams containing fracture-filling calcite.

Heating-Induced Enhancement of Shale Gas Transport and Its Application for Improving Hydraulic Fracturing Performance

“…However, only 5–50% of the injected fracturing water returns to the surface after the fracturing process due to leak-off and capillary imbibition from the fracture face into the shale matrix. − Recent experimental observations suggest that because shale formation exhibits ultra-low initial water saturation and high clay content, the imbibed water and clay swelling may block the gas transport pathway in the shale matrix (Figure ), thus preventing migration of shale gas to the fracture. − The impact of retained fracturing water on shale gas transport (gas diffusivity and permeability) has been evaluated in many published literature studies. Chen et al (2022) reported 57% reduction in diffusivity when Longmaxi organic-rich shale was exposed to water for 48 h. A similar blockage effect was also documented in many other organic-rich tight rocks dominated by nanopore systems. − The negative effect on matrix permeability is also observed to be a drastic reduction when exposed to water. For example, Chakraborty et al reported that the matrix permeability of Marcellus and Haynesville shale core plugs was observed to be a reduction of as much as 90–99% due to counter-current spontaneous imbibition of fracturing water .…”

A fault location method based on polarization analysis for coal mine

“…Combined with tomography method, the fault location accuracy can be further improved (Dong et al, 2022). As a typical water and gas channel (Chen et al, 2021;Tian et al, 2022), the fault can be further monitored by acoustic emission method after positioning by LFVS method (Rui et al, 2022a;Rui et al, 2022b).…”

Experimental Study on the Influence of Hydrochemical Properties on the Migration of Coal Fines Containing Kaolinite in Propped Fractures

“…During the development of coalbed methane (CBM), the production of coal fines is a common occurrence due to the low elastic modulus and hardness of coal, which make it susceptible to stress-induced fragmentation. − Coal fines have a tendency to aggregate and settle to different extents when the fluid is discharged, resulting in the retention of coal fines within fractures, blockage of fractures, and reduction of coal reservoir permeability. , The aggregation of coal fines in the wellbore and their entry into the discharge system can result in the entrapment of pumps and subsequent pump failures, which significantly hamper the efficient development of CBM. − During CBM development, the generation of coal fines is influenced by various factors. − Fluids of different natures, such as groundwater, drilling fluid, fracturing fluid, etc., are exposed in the reservoir and propped fractures. Physical or chemical reactions between the fluids and reservoir rock can affect the generation, migration, and production of coal fines. − The inorganic mineral content of coal fines produced from coalbed methane wells in the Hancheng block can be as high as fifty percent. − As a result, these inorganic minerals significantly impact the migration of coal fines in CBM wells. , …”