BACKGROUND Improving the prediction ability of relatively high-quality reservoirs under tight backgrounds is a bottleneck and a challenge in current oil and gas exploration and development theories. For tight reservoirs, exploring the dissolution mechanism of organic acid fluids on the reservoir is particularly important. Previous researchers have conducted a large number of water rock reaction simulation experiments on the dissolution of organic acids leading to the formation of secondary pores. It is proposed that the dissolution effect of acidic fluids is the main factor for increasing porosity in tight reservoirs, and it is also a key way to find “sweet spots” in tight reservoirs³. Based on previous research on dissolution pores in sandstone, scholars have focused on studying the chemical mechanism of organic acids in the dissolution of carbonate and feldspar minerals. Some studies have shown that the dissolution of calcite requires a lower pH¹⁹ and the acidity of binary acid is very strong, which can greatly improve the solubility of aluminosilicate minerals^20-22. However, the heterogeneity of tight sandstone reservoirs is strong, and its complex mineral components and pore structure characteristics differ greatly; it has a higher content of clay minerals, and during the diagenesis process, clay minerals often precipitate on the rigid particle surface of the pore inner wall as authigenic minerals. The main mineral in contact with crude oil is of clay composition in dense sandstone reservoirs^23-25. Chlorite, kaolinite, illite and other minerals are common and important clay mineral types. As important factors affecting reservoir exploration and development, their organic acid dissolution effects on clay minerals need to be further studied.

OBJECTIVES (1) In order to explore the main influencing factors of organic acids on the dissolution of clay minerals in tight sandstone, by analyzing the influence of time, temperature and different types of organic acids on the dissolution of clay minerals. (2) To reveal the dissolution reaction mechanism between organic acid fluids and tight sandstone, providing a theoretical basis for improving the prediction ability of relatively high-quality reservoirs under tight backgrounds.

METHODS (1) The Triassic Yanchang Formation in the Ordos Basin was selected as the research object, and the ratio of reaction fluid to sandstone dissolution simulation experiment was conducted according to the type and content of organic acid in the thermal evolution fluid of Source rock. (2) After the reaction, the column rock sample was rinsed multiple times with distilled water, placed in a drying oven, dried for 24h, and then taken out for testing. The porosity and permeability of the column rock sample after the reaction were tested on the PoroPDP-200 overlying pressure pore permeability meter before and after the experiment, and the intensity of dissolution was quantitatively calibrated. (3) Small samples of 5-8cm for argon ion polishing were selected, and observed under the Quanta450FEG field emission environment scanning electron microscope (Lanzhou Oil and Gas Resources Research Center, Chinese Academy of Sciences). Then, through thin section identification and scanning electron microscope observation of the petrology characteristics of the samples, the cement and pore characteristics of the samples before and after the experiment were compared. (4) Using Optima 8000 inductively coupled plasma-optical emission spectrometer (PerkinElmer Company, USA) to detect cations, the practical range of the measured standard curve was 0.1-20mg/L, and samples that were not within the test range were diluted. The standard curve solution contains a total of 8 ions: K, Ca, Na, Mg, Al, Si, P and Mn.

RESULTS (1) With the increase of time (1-9 days), the increase of porosity dissolution increases first and then decreases, reaching its peak at 6 days; the increase of penetration rate shows a continuous growth trend. The increase in temperature can also promote the dissolution of sandstone by organic acids (Fig.3, Fig.4). (2) Different types of organic acids have selective dissolution of clay minerals. Tartaric acid mainly dissolves clay minerals, detrital feldspar and a small amount of calcite cement; on the contrary, acetic acid mainly dissolves calcite. The sequence of propionic acid dissolution is from calcite to feldspar detrital particles, from dissolution cement matrix to argillized feldspar; the mixed acid solution of formic acid, acetic acid and propionic acid and mixed acid solution of formic acid, acetic acid, propionic acid and tartaric acid preferentially dissolve chlorinated and argillized feldspar and calcite until calcite is completely dissolved (Fig.4, Fig.5). (3) The improvement of pores by formic acid is not significant among different types of organic acids. Propionic acid greatly improves porosity. The influence of combined acids on porosity is a comprehensive reflection of the influence of single acids (Fig.6).

CONCLUSIONS Formic acid has little effect on porosity, whereas acetic acid and propionic acid have obvious effect on porosity. The combined effects of formic acid, acetic acid, propionic acid, and tartaric acid on porosity and permeability are a comprehensive reflection of the improvement of a single acid. The selective dissolution of clay minerals in tight sandstone by different types of organic acids has different effects on the physical properties of the reservoir, providing a scientific basis for improving the prediction ability of relatively high-quality reservoirs under tight background.