Experiment and Simulation of Gas Channeling Control Technique During CO₂ Flooding in Normal Pressure Tight Oil Reservoir of South Ordos Basin

HH Chang 8 tight sandstone reservoir in the South Ordos basin has been developed for more than 7 years on depletion mode. Because of normal pressure (0.8±), extra-low permeability (<0.3×10⁻³μm²), heterogeneous oil bearing, development effect is not satisfied. A pilot well group was selected to conduct CO₂–foam flooding in 2015, while gas channeling phenomenon is so serious that the oil stimulation is poor. To enlarge CO₂ sweep efficiency, it is necessary to evaluate adaptable plugging agents and simulate the inter-well fracture network blocking effect in tight reservoir with multiple-scale complicated fractures developed.

In this study, four different openings fractures were artificial fabricated in natural crop cores based on the fracture characteristics of the reservoir. Injection performances and plugging capability of the starch gel and the ethylenediamine were evaluated when the gas channeling phenomena appeared during CO₂ flooding by the laboratory experiment and the gas channeling control adaptability were analyzed. By experiment numerical simulation, the fracture conductivity multiple index (MULTX) was determined to simulate the fracture blocking effect. Then the reservoir simulation was conducted, classified MULTX were further optimized based on plugging characteristics of complicated fractures network during CO₂ flooding.

Experiment results indicate that the starch gel is suitable for blocking off fractures with openings between 0.42∼0.65mm. While the ethylenediamine is suitable for control fractures with openings less than 0.24mm, especially for 0.08mm. In Chang 8 tight reservoir, the medium- to large-scale fracture permeability is higher than 200 × 10⁻³ μm², the starch gel was applied to control the serious gas channeling. For small- to medium-scale fracture, the ethylenediamine was applied to mitigate gas channeling. Fracture blocking experiments were numerically simulated to determine MULTX being in the range of 10⁻⁸∼10⁻⁶. Numerical simulation of well group blocking was conducted in the complicated fracture G&G model, MULTX was further optimized to be lower than 10⁻⁶ for the medium- to large-scale fracture and 10⁻⁴∼10⁻³ for the small- to medium-scale fracture, keeping seepage capacity of micro-cracks. Well group CO₂ flooding shows a promising improving oil recovery, sweeping efficiency is increases from 1.4% to 24.1%, the utilization factor is 4.35 t/t oil, compared with 1.3% recovery factor of depletion mode, by 10 years CO₂ periodic injection, recovery factor is enhanced by 3.76%.

It is a big challenge to effectively develop the normal pressure continental deposit tight oil reservoir. In China reserves of tight reservoir amount to a large proportion in the unconventional oil reserves. Study results provide technology support for CO₂ flooding extended test in HH Chang 8 tight reservoir, also make CO₂ flooding method successful application possible in other low pressure tight sandstone oil reservoirs.