Experiment and Modelling of Massive Fracturing Considering Drainage and Imbibition Process in Tight Oil Reservoirs

Abstract Spontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition. An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification. Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning. Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.