Jiameng Hu

CO₂ channeling limits the effectiveness of immiscible flooding in the Chang 6 low-permeability reservoir of the Qiaojiawa Oilfield. This study integrates core- and fluid-property data, slim-tube minimum miscibility pressure (MMP) measurements, facies-controlled geological modeling, and CMG-GEM compositional simulation to examine channeling controls and screen differentiated treatments. The initial reservoir pressure (12.90 MPa) was below the reported CO₂–oil MMP of approximately 22.15 MPa. The simulated responses are consistent with the combined effects of mobility contrast and high-permeability pathways. Three representative well groups were classified as weak, moderate, and strong using permeability contrast, earliest breakthrough, and peak gas–oil ratio (GOR). At year 10, simulated recovery factors were 19.2% for continuous injection, 20.7% for intermittent gas injection (IGI), 23.4% for water-alternating-gas injection (WAG), and 27.2% for foam-assisted mobility control (FAM). These results describe the prescribed schedules and provide a basis for preliminary treatment screening.

Carbon dioxide-enhanced oil recovery (CO₂-EOR) in ultra-low-permeability reservoirs requires a reliable understanding of CO₂–oil phase behavior and minimum miscibility pressure (MMP), particularly where multiple stratigraphic members are co-developed. In this study, recovered live-oil samples from the Chang 4 + 5-producing Well 272 and the Chang 6-producing Well 651 of the Yanchang Formation in the Ordos Basin were compared using compositional analysis, conventional PVT tests, CO₂-swelling experiments, slim-tube displacement tests, and Peng–Robinson equation-of-state (PR-EOS) characterization. The PR-EOS model used pseudo-component characterization, grouped binary interaction parameters and CO₂-swelling saturation-pressure constraints to support the interpretation of EOS-predicted phase behavior and the evaluation of internal consistency. The two recovered samples have similar measured bubble-point pressures and dead-oil densities, whereas the Well 651 sample has a lower live-oil viscosity and a slightly higher C₂–C₁₂ hydrocarbon fraction. Slim-tube tests gave approximate MMPs of 17.8 MPa for the Well 272 sample at 59.94 °C and 16.1 MPa for the Well 651 sample at 69.30 °C. Because the samples were tested at their respective reservoir temperatures, temperature and composition varied simultaneously and their independent contributions cannot be separated using the present dataset. Accordingly, the comparison is limited to the two sampled well-fluid systems under the documented sampling and test conditions; the results should not be generalized to interval-wide Chang 4 + 5 or Chang 6 fluid properties without additional representative sampling.