Summary The pronounced spatial heterogeneity of wettability in shale reservoirs poses a fundamental challenge for accurately predicting fluid distribution. Experimental tools capable of resolving this heterogeneity at the core scale, however, remain critically lacking. Conventional spatially resolved nuclear magnetic resonance (NMR) techniques are severely hindered by the ultrashort relaxation times inherent to shales, which cause rapid signal attenuation. To address this challenge, we developed a spatially resolved NMR methodology specifically tailored for shales, building upon our previously established zero echo time (ZTE) imaging sequence and combining it with relaxation correlation analysis. Spontaneous imbibition experiments were conducted on two representative shale cores from two different blocks. The experiments demonstrate a spatially resolved NMR methodology for mapping core-scale wettability heterogeneity. Our results reveal that imbibition behavior is governed primarily by the spatial distribution of wettability. Fracture networks served as preferential migration pathways during early-stage imbibition, whereas the final equilibrium saturation was dictated by the degree of microporosity development. Notably, water imbibition was substantially inhibited in organic-rich regions, underscoring the decisive role of wettability heterogeneity in shaping ultimate fluid distributions. By integrating the Lucas-Washburn (L-W) equation with nanoconfined flow theory, we established a mechanistic framework linking pore-scale wettability to macroscopic transport behavior. The regional water wettability index is strongly correlated with equilibrium water imbibition (R2 >0.85). The water-to-oil wettability index ratio is correlated with water sorptivity (R2 >0.8). This work delivers the first quantitative spatial distribution of shale wettability and provides a robust foundation for advancing the understanding and prediction of multiphase fluid occurrence and transport in shale reservoirs.
Summary Enhanced oil recovery (EOR) in unconventional shale reservoirs is significantly influenced by capillary forces, heterogeneous pore structures, and surface chemistry, which depends on mineralogy. The Eagle Ford (EF) and some sections of the Wolfcamp (WC) shales are calcite-dominant, where anionic surfactant mechanisms developed for clay/silicate-rich formations may not be optimal. This study evaluates an EOR strategy that integrates a nonionic alkyl polyglucoside (APG) chemical blend (CB) with supercritical CO2 under near-miscible huff-and-puff (HnP) conditions at 176°F and 3,000 psig pressure. Unlike previous research on Mancos shale utilizing anionic formulations, this investigation explores wettability alteration induced by nonionic adsorption in calcite-rich shale. Interfacial tension (IFT) measurements showed a reduction from 20.5 to approximately 1 mN/m, representing moderate IFT reduction rather than ultralow values. Contact angle (CA) measurements demonstrated wettability alteration toward water-wet conditions, which is critical in tight shales, where the capillary pressure is strongly controlled by CA effects. Nuclear magnetic resonance (NMR) transverse relaxation time (T2) analysis was used to evaluate pore-scale recovery mechanisms. The results indicate that macropore-associated domains are the primary contributors to oil production. However, the APG_CB and CO2 combination generates additional depletion in short-T2 (micropore) regions relative to brine or CO2-only injection. The results of spontaneous imbibition (SI) in WC shales support the findings related to oil recovery driven by wettability alteration and moderate IFT reduction, with APG_CB achieving an ultimate recovery of 22%, while brine resulted in 6% recovery. In the EF shale, the combination of CO2 and APG_CB enhanced the ultimate liquid recovery of HnP from 33.8% (brine + CO2) to 44.3% under similar conditions. These findings indicate that nonionic APG_CB improves oil recovery in carbonate-rich shales, where the use of anionic surfactants may result in chemical losses. Furthermore, the study revealed that chemically assisted CO2 HnP can partially extract oil associated with micropores, although macropores significantly contribute to the oil production observed at laboratory timescales.
Summary Intelligent drilling and completion systems have become the critical frontier in modern oil and gas engineering, and intelligent drill bits represent a key research direction. However, acquiring high-fidelity, real-time operational data at the microscopic cutting level remains a significant engineering challenge. To address downhole sensing limitations, a first-of-its-kind polycrystalline diamond compact (PDC) smart cutter (SCutter), integrating two temperature sensors and a preloaded lead zirconate titanate (PZT) piezoelectric force-sensing element, was developed. The external cutting force acting on the cutting face generates a time-varying internal stress field within the cutter body. The resultant compressive force produced by this internal stress field on the PZT interface is converted into an electrical response, thereby enabling the SCutter to sense internal stress variations and estimate the external cutting force through whole-cutter calibration. The PZT element has a calculated maximum axial compressive load capacity of 13.62 kN. In the dynamic internal stress sensing experiment, signals were acquired at 50 Hz, and the SCutter voltage response yielded a Pearson correlation coefficient of r=0.943 with the resultant voltage response of an external triaxial force sensor. The mean relative tracking error between the SCutter response and the scaled resultant response of the external triaxial force sensor across five cutting depths was 8.39%. These results confirm that the SCutter voltage response induced by internal stress is highly consistent with the external reference response in terms of time-domain characteristics, load envelopes, and variation trends. This pioneering study breaks conventional measurement limitations, providing a fundamental in-situ data foundation for PDC cutter online health evaluation, formation lithology identification, and closed-loop control of intelligent drilling systems.
Summary Accurate evaluation of fault sealing is essential for understanding trap effectiveness and reducing exploration risk in fault-controlled reservoirs. This study presents a displacement pressure-based 3D fault seal evaluation framework based on displacement pressure contrasts between fault rocks and juxtaposed reservoirs. Using the K area of the Pinghu Slope in the Xihu Depression as a case study, structural modeling and geological property modeling were integrated to construct a fault surface-based framework. Within this framework, key controlling factors, including shale content, burial depth, and stress conditions, were incorporated to estimate the displacement pressures of fault rocks and juxtaposed reservoirs. The resulting displacement pressure contrasts were then used as a direct criterion for evaluating fault sealing potential in both vertical and lateral directions. The results indicate that fault sealing potential in the K-area is markedly heterogeneous both vertically and laterally. Strong vertical sealing is mainly developed in the P3 and P7 intervals, which constitute the principal sealing horizons in the study area, whereas the P5 and P6 intervals represent favorable reservoir intervals under relatively strong sealing conditions. Fault segments located closer to the depocenter generally exhibit stronger sealing potential than those toward the slope margin, and the lower reservoir-seal assemblage shows stronger lateral sealing potential than the upper assemblage, implying more favorable conditions for hydrocarbon preservation in deeper structural sectors. The workflow enables continuous spatial characterization of fault sealing behavior across fault surfaces and provides a practical basis for identifying favorable fault segments and exploration targets in structurally complex regions.
Summary Waxy crude oil contains a significant amount of paraffinic hydrocarbons, which can crystallize during transit when the temperature drops below the wax appearance temperature (WAT). This can cause increased viscosity, flow restriction, pipeline obstruction, and financial losses. By altering wax crystallization, pour-point depressants (PPDs) and wax inhibitors are frequently used to lessen these difficulties. However, many traditional PPDs have poor biodegradability and could be hazardous to the environment. This research work is concerned with the preparation of a biodegradable PPD made from oleic acid-maleic anhydride-aniline (OMA) and its application to improve the flow properties of Indian waxy crude oil at low temperatures. The performance of OMA was evaluated against that of a commercial ethylene-vinyl acetate (EVA)-based PPD (PPD-A). OMA was synthesized via free-radical polymerization and analyzed using advanced permeation chromatography (APC), thermogravimetric analysis (TGA), dynamic light scattering (DLS), X-ray diffraction (XRD), carbon/hydrogen/nitrogen/sulfur (CHNS) elemental analysis, Fourier transform infrared (FTIR) spectroscopy, and 1H nuclear magnetic resonance (1H NMR). Wax crystal formation behavior and wax morphology were studied by differential scanning calorimetry (DSC) and cross-polarized microscopy. At 650 ppm, OMA and the commercial EVA caused a 9°C drop in the pour point of crude oil. OMA showed a 71% reduction in wax deposition, which was higher than that for commercial PPD (64.16%) at this concentration. OMA also had an excellent influence on the rheology of the crude oil, making flow restart easier and with lower energy consumption. Observations under microscopy revealed that OMA could break larger wax crystal clusters and form smaller ones. Therefore, OMA can be considered a better wax deposition inhibitor and flow enhancer than the commercial EVA. Consequently, OMA can be viewed as a prospective PPD for waxy crude-oil flow improvement.
