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In the Changning block of the southern Sichuan Basin, the shale gas wells in the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (Wufeng-Longmaxi) demonstrate significant difference in flowback rate of fracturing fluid, given the same fracturing scale and production time. Based on the P90 curve of flowback rate with time, wells with high flowback rates in this area are categorized, and they are generally defined with the 100-day flowback rate of >40%, the 200-day flowback rate of >50%, and the first-year flowback rate >60%. Through comprehensive research on the geological characteristics of the Changning block, the geological factors that cause high gas well backflow rates have been identified. The results are obtained in four aspects. First, gas wells with high flowback rates generally show higher flow rates for smaller distances to the fault, and the NE faults formed during the late Yanshanian to early Himalayan and with fault throw >200 m have the greatest impact on the flowback rate. Second, plane heterogeneity of water saturation contributes to the high flowback rate of some wells. Third, the proportion of the Middle Ordovician Baota Formation in the horizontal section of wells is positively related to the flowback rate, and the drilling and fracturing of the Baota limestone with high water content can lead to high flowback rates of gas wells to some extent. Fourth, unidirectional linear natural fractures between wells can easily cause inter-well frac-hit, leading to high flowback rates of gas wells. In conclusion, the research results are helpful in predicting areas where high backflow rate gas wells may occur and developing corresponding drainage and production methods in advance. [ABSTRACT FROM AUTHOR]

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Water saturation estimation faced a great challenge in tight gas sandstone reservoirs because of the effect of pore structure and strong heterogeneity. The classic Archie’s equation cannot be always well used. To quantify the effect of pore structure to rock resistivity in tight gas sandstones, taking Triassic Xujiahe Formation of northwestern Sichuan Basin as an example, 35 core samples were recovered and applied for resistivity experiments in laboratory under the simulated formation temperature and pressure environment, and 18 of them were simultaneously applied for nuclear magnetic resonance (NMR) and high-pressure mercury injection experimental measurements. Relationships between pore structure and resistivity parameters were analyzed. The results clearly illustrated that cementation exponent (m) and saturation exponent (n) were heavily affected by pore structure. Rocks with superior pore structure contained relatively higher cementation exponent and lower saturation exponent, and vice versa. Afterward, we raised a parameter of pore size index, which was defined as the ratio of macropore and micro-pore percentage contents, to characterize rock pore structure, and established a model to calculate optimal saturation exponent from NMR data. Meanwhile, cementation exponent prediction model was also raised by combining with porosity and irreducible water saturation (Swirr). Combining with calculated cementation exponent and saturation exponent, we optimized the Archie’s equation to predict water saturation in our target tight gas sands. Field examples illustrated that the predicted cementation exponent and saturation exponent matched well with core-derived results. The absolute errors between predicted cementation exponent and saturation exponent with core-derived results were lower than 0.05 and 0.07, separately. By using optimized Archie’s equation, water saturations were precisely predicted from well logging data in our target tight gas sandstone reservoirs; whereas, the classic Archie’s equation underestimated formation water saturation. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Thickness marine shale of Paleozoic Wufeng-Longmaxi Formations is deposited in the northwestern Guizhou province, which borders on the shale gas production area in southeast Sichuan Basin. However, few studies have been performed to characterize shale gas reservoir of the Wufeng-Longmaxi Formations in this area. In this study, 80 shale samples collected from the LY1 well were designed to conduct a series of analyses, aiming to obtain microstructure features and reveal their controlling factors. Shales within the Upper Longmaxi Formation characterized by low total organic carbon (TOC) content, high clay mineral content and low porosity are considered to be unfavorable interval for shale gas exploration. Whereas, a high-quantity shale (TOC>2%, clay<40%) interval with thickness of about 27 m exists within Lower Longmaxi Formation and Wufeng Formation. Pores in the studied shales are dominated by organic matter (OM) pores, followed intraparticle (intraP) within carbonates and intercrystalline pores within pyrite framboids. OM pores could be divided into three types, as OM pores within solid bitumen, in-situ amorphous kerogen and graptolite. OM pores are extremely developed in solid bitumen and in-situ amorphous kerogen, and the former have larger diameter than the latter. Rare pores are developed in graptolite. The total porosity and specific surface area of the shales within the Lower Longmaxi Formation and Wufeng Formation are twice more than those within the Upper Longmaxi Formation. Samples with higher TOC values commonly have higher porosities and specific surface areas, suggesting TOC content determines shale physical property. Clay mineral content exhibits a negative influence on microstructure and porosity but determines water saturation. Water saturation has significant negative relationships with micro-to mesopore volumes, porosity and TOC content, illustrating water molecular stores mainly in hydrophilic pores associated with clay minerals rather than OM-hosted nanopores. The gas generation, reservoir quantity and gas content of the Longmaxi-Wufeng shales in northwestern Guizhou are also compared with those of the famous Fuling and Weiyuan districts in eastern Sichuan Basin, and we considered that the shale gas prospect in northwestern Guizhou is excellent. • The microstructure and porosity of the studied shales were investigated by various means. • OM pores, divided into three subtypes: OM pores in solid bitumen, amorphous kerogens and graptolites. • Brittle minerals could enhance shale porosity due to strong compaction resistance. • Clay minerals have a negative influence on porosity but determine water saturation. [ABSTRACT FROM AUTHOR]