In Situ Fluid Content Evaluation of Shale Oil Reservoirs: Insights from Laboratory and Wellsite Mobile Full-Diameter Core NMR

Abstract

Accurate assessment of in situ fluid occurrence and content in complex shale reservoirs is crucial for effective resource evaluation and shale oil extraction. Laboratory tests on placed samples often lead to misestimations due to movable fluid loss. Low-field nuclear magnetic resonance (NMR) technology, which eliminates the need to crush cores for pyrolysis experiments, is emerging as a vital tool for studying shale pore fluids. Simultaneously, mobile full-diameter core (MFDC) NMR at wellsite is advancing rapidly, allowing for the first-time testing of cores immediately after extraction. However, research in this field remains limited. This study employed an innovative laboratory oil–water restoration technique alongside two-dimensional (2D) transverse (T₁) – longitudinal relaxation time (T₂) NMR and wellsite MFDC to evaluate the in situ fluid content in the lower first member of Cretaceous Tengger (K₁bt₁) and Aershan (K₁ba) Formations of the Wuliyasitai Depression, Erlian Basin. Our findings demonstrate that the 2D T₁–T₂ NMR technique effectively detected various hydrogen-containing components in shale oil reservoirs. Combined with quantitative analysis, it revealed the dynamic characteristics of oil–water signals during restoration, establishing a reliable method for assessing shale oil–water content. The multistage Rock-Eval (MRE) pyrolysis method strongly correlated with the 2D NMR results, confirming the reliability of NMR. Due to maturity-related variation in shale oil composition, the MRE pyrolysis results of the lower K₁bt₁ and K₁ba shales exhibited a different linear correlation with the 2D NMR data of as-received (AR) state shale, prompting adjustments to the NMR calibration coefficients for lower K₁bt₁ shale. The total oil content of the in situ fluid state shale was calculated to be 1.9582 and 3.2489 times greater than that of the AR state for the lower K₁bt₁ and K₁ba formations, respectively. The laboratory-measured oil content of the in situ state shale aligned well with MFDC NMR results, indicating that integrating laboratory oil–water restoration techniques with NMR provides a more effective and accurate representation of in situ fluid occurrence and content. Furthermore, the empirical S₁-corrected model developed for lower K₁bt₁ and K₁ba shales in the Erlian Basin holds potential for broader application in shale oil operations. Our research offers valuable insights into evaluating in situ fluids in shale oil reservoirs.