Assessment of movable resources of lacustrine shale oil based on mass oil content: a case study of the 2nd member of Kongdian formation in Cangdong Sag of the Bohai Bay Basin

Shale samples commonly exhibit hydrocarbon losses and organic matter adsorption, leading to inaccurate assessments of movable shale oil resources. To address this challenge, a closed-core sample was obtained at a depth of 45 meters from well G19-25 in the Kong 2th Member of the Cangdong Sag in the Bohai Bay Basin, China. An innovative approach was adopted, involving 45 sets of comparative experiments, categorized into three types (0 h vs. 24 h, closed vs. open, conventional vs. multi-temperature stages) for shale pyrolysis, and 12 sets of kerogen swelling experiments. This study established correction coefficients for light hydrocarbon recovery and organic matter adsorption. The results indicate that the average light hydrocarbon loss rate after 24 hours sample placement is 29.4%. Under open condition, the average light hydrocarbon loss rate for fractured samples is 21.0%, while for conventional pyrolysis, the average light hydrocarbon loss rate is 15.5%, and the average comprehensive loss ratio is 47.1%. The underground original light hydrocarbon is approximately twice that of conventional pyrolysis (shale oil light hydrocarbon correction coefficient Kcal = 2.0). The 12 sets of kerogen swelling experiments show that the amount of hydrocarbon adsorbed by kerogen gradually decreased with the increase of vitrinite reflectance Ro. Specifically, when Ro is between 0.8% and 1.1%, the average adsorption coefficient for shale organic matter is 0.1. A novel methodology for assessing the quality oil content method in shale oil movable resources is established, which suggests using the shale oil content rate (mass fraction of oil) Sf to characterize the movable hydrocarbon content in shale after removing hydrocarbons adsorbed by organic matter. According to this approach, the quantity of movable shale oil resources in the Kong 2th member of the Kongdian formation is 6.8 × 108 t. This method can provide reference for similar shale oil research in comparable basins.