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

Abstract

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.

Study on the Plugging Limit and Combination of CO2 Displacement Flow Control System Based on Nuclear Magnetic Resonance (NMR)

“…The focus of the above researchers was on how to develop flow control systems with better results, but how to combine flow control systems with more mature processes to improve crude oil recovery seems to be the question of interest for oil producers. Currently, the main flow control systems that are used to seal gas scramble are water/gas alternate injection (WAG), CO 2 foam injection, and CO 2 foam gel injection [15][16][17]. In mine practice, improper combinations of different flow control systems and mismatches with formation pore throats have caused oil in large pore channels to be squeezed into small pore throats without being driven out [18], and plugging failure affecting the final recovery is reported from time to time.…”