Restoring Original Pore-Fluid Occurrence in Conventionally Cored Shales: Insights from Alternating Oil–Water Spontaneous Imbibition and Nuclear Magnetic Resonance

The mobility and producible volume of shale oil are key factors controlling the effectiveness of shale oil exploration and development and are fundamentally governed by the occurrence state of hydrocarbons within shale pore systems. Consequently, accurate identification and quantitative characterization of oil–water occurrence in shales represent a core scientific challenge in shale oil research. Current investigations rely heavily on fresh or pressure-preserved cores. However, during routine coring, handling, and storage, substantial fluid loss is inevitable, rendering most conventionally cored shale samples unsuitable for in situ fluid-occurrence analysis. Although pressure-preserved coring can effectively maintain original fluid states, its high operational cost severely restricts large-scale application. Therefore, restoring the original pore-fluid occurrence in conventionally cored shales has become a critical technical bottleneck.To overcome this limitation, we develop a novel workflow integrating alternating oil–water spontaneous imbibition with nuclear magnetic resonance (NMR) measurements to recover the original fluid-occurrence state in conventionally cored shales. Pressure-preserved shale cores were first exposed to laboratory conditions to simulate fluid loss during conventional coring. Subsequently, a multistage alternating spontaneous imbibition procedure was implemented using n-dodecane and 15 wt% KCl brine as imbibing fluids to progressively restore the original oil and water contents. Throughout the entire fluid-loss and restoration processes, NMR T₁–T₂ maps were continuously acquired to dynamically monitor variations in oil and water contents and their pore-scale migration behaviour.

The results indicate that shale cores experience rapid oil–water loss during the initial 0–80 h, followed by a markedly reduced loss rate between 80 and 500 h, and reach a quasi-steady state after approximately 500 h, with a cumulative fluid loss of ~45%. During the alternating imbibition procedure, the samples undergo four successive stages, namely primary oil imbibition, water imbibition, secondary oil imbibition, and secondary water imbibition, each approaching a new dynamic equilibrium. After restoration, the oil and water saturations of the conventionally cored shales show strong agreement with those of the corresponding pressure-preserved samples.These findings demonstrate that the proposed method can effectively recover the original pore-fluid occurrence state in conventionally cored shales, enabling reliable characterization of shale oil and water distribution. The workflow is expected to significantly improve the accuracy of shale oil sweet-spot evaluation and provide new technical support for shale reservoir exploration and development.