Deep low-resistivity pay (LRP) reservoirs contain significant hydrocarbon volumes that frequently evade detection because high clay content and complex pore geometries reduce electrical resistivity contrasts against surrounding conductive shales. The same factors also weaken the elastic contrast on which acoustic-impedance (AI) inversion relies. To address this challenge, this study tests an empirical seismic inversion workflow in which a power-exponential Poro-Resistivity (PR) attribute, calculated from porosity and resistivity logs, is used as a proxy for AI in synthetic seismic modeling and colored inversion. PR is not an elastic property. Its use is justified here by its strong correlation with AI and by an Extended Elastic Impedance (EEI) analysis, which shows that the PR log correlates strongly with EEI (R > 0.9) over a wide range of pseudo-angles that includes 0°, the angle at which EEI equals AI and which is represented by post-stack data. The workflow was applied to three deepwater Gulf of Mexico wells and to SEAM seismic data. At well No. 1, PR correlates with AI at R = 0.95, compared with R = 0.53 for raw resistivity, and R exceeds 0.94 in wells No. 1 and 3. Along two seismic lines through well No. 1, the PR volume shows a more continuous and more sharply bounded sand body than the AI volume. This comparison is qualitative, rests on one tied well and on thick sands (25–40 m), and has not been tested on laminated sand–shale sequences. PR is therefore proposed as a complementary attribute for sand–shale discrimination, not as a replacement for AI inversion or for EEI inversion of pre-stack data, which remains the physically preferable approach when angle stacks are available.
Drilling-mud recycling supports resource recovery and environmental management, but circular supply chain implementation is constrained by barriers that are difficult to prioritize under uncertain expert judgments. This study develops a multi-criteria decision-making (MCDM) framework integrating interval-valued Fermatean fuzzy sets (IVFFSs), the Best–Worst Method (BWM), and Ranking of Alternatives through Functional Mapping of Criterion Sub-Intervals into a Single Interval (RAFSI). Five specialists evaluated ten barriers against six criteria. Separate IVFFS-BWM models were solved for each expert, and the resulting criterion weights were averaged. IVFFS-RAFSI was then applied to each expert’s barrier assessments, followed by aggregation of the final scores and cross-expert sensitivity analysis. Cost, implementation time, and technical complexity received the highest criterion weights. Technological limitations, insufficient infrastructure, and process complexity and uncertainty obtained the highest mean barrier scores. These three barriers showed less score dispersion across experts than financial and regulatory barriers. The contribution lies in integrating expert-specific weighting, barrier prioritization, and cross-expert robustness assessment within a structured workflow tailored to circular drilling-mud supply chains. The findings support prioritizing technological upgrading, infrastructure development, and process stabilization in the analyzed context. The five-expert, single-country application warrants further validation using broader expert panels and operational performance data.
Multiple thermal fluid (MTF) injection, which co-injects steam/water, CO₂, and N₂, is a promising enhanced oil recovery (EOR) method for heavy oil reservoirs, especially thin and layered ones. However, the synergistic viscosity reduction mechanisms and displacement characteristics during MTF injection remain incompletely understood. The PVT viscosity-measuring tests were carried out to compare the apparent viscosity change of the CO2/water, N2/water, the MTF-heavy oil system under different shearing stages at 100 °C and 20 MPa. Then one-dimensional sand-packed tube with permeability of approximately 2200 mD was used to conduct displacement tests using the injected fluid under 200 °C and 20 MPa. Results reveal that the viscosity reduction process of MTF under shearing exhibited a distinct two-stage evolution, which comprised gas dissolution followed by foamy emulsion formation. The MTF-oil system achieved a viscosity reduction rate of 77
Multi-layer heterogeneous oil reservoirs at the ultra-high water-cut stage commonly suffer from severe interlayer conflicts, inefficient circulation of injected water, and uneven reserve mobilization, which together restrict further recovery. To improve zonal water-injection regulation under these conditions, a dynamic control framework was developed by integrating an inter-well connected element model with a balanced-displacement water-injection optimization model. Production history matching was first used to invert the connected volumes between injectors and producers; an IMPES-type connected-element simulator and SPSA-based parameter inversion were used to update the model. An exponential function was then fitted to the oil–water relative permeability ratio and coupled with material balance to derive the critical condition for maximum water-flooding efficiency. The method was applied to a four-layer block in the Daqing Oilfield containing four oil production wells and one water injection wells with an average water cut of 95.2
Water-in-crude oil emulsions are a major challenge in petroleum production due to increased viscosity, pipeline corrosion, and higher processing costs. Conventional demulsifiers are often expensive or environmentally harmful, motivating the development of low-cost and recyclable alternatives. In this study, natural bentonite was modified with the cationic surfactant cetyltrimethylammonium bromide (CTAB) to produce a heterogeneous demulsifier (CTAB/Be). The material was characterized by XRD, FTIR, SEM, zeta potential, IFT, contact angle, and DLS. Demulsification performance was evaluated using bottle tests under varying dosage, temperature, settling time, and salinity, and recyclability was assessed over five cycles. Modification increased the basal spacing from 14.70 Å to 21.94 Å, changed the water contact angle from 0° to 48.3°, and reversed the zeta potential from − 4.8 mV to + 45.7 mV. CTAB/Be reduced the oil–water interfacial tension from 26.7 mN/m to 6.5 mN/m. Under selected conditions (5 g/L CTAB/Be, 60 °C, 24 h), 89.95
