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Foam flooding is an important pathway for enhanced oil recovery. However, the evaluation of foam properties is usually carried out in free space, which can not accurately reflect the performance of foam in porous oil formation. In the present work, by investigating the foamability and stability of foam systems in sand-pack models with average pore throat radius from 1.24 μm to 4.28 μm, the effects of porous media on foam properties are studied. Compared with foam systems in free space, foam systems in porous media have longer foam halflife, longer drainage half-life, and higher foam comprehensive index. The foam volume of foam systems in porous media could be higher or lower than that in free space, depending on the average pore throat radius of the porous media. Generally, in porous media, with the decreasing of pore throat radius, the foamability of the foam systems gradually decreases while the foam stability gradually increases. Moreover, the bubble size and liquid film thickness also decrease with the decreasing of pore throat radius of the porous media. Above all, the behaviors of foams are significantly affected by porous media. When investigating a foam system to evaluate its performance for foam flooding in oil recovery or other applications in porous media, porous models which could reflect the target conditions should be considered to obtain more trustable results.

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Enhancing oil recovery factor to 70% to fulfill the demand increase for crude oil is a great goal and a big challenge in the industry. This way may be more economical and less risky than the development of unconventional resources. For heterogeneous waterflood oilfield, the paper proposed and tested a new EOR method, comparing to the traditional polymer flooding technology. Considering both macroscopic and microscopic heterogeneities, the prevailing flowing channels were graded. The formation heterogeneity causes uneven sweeping. Different degrees of water flowing channels are generated based on different sizes of pores and throats. Inhibiting prevailing flow and improving the pore-scale sweeping efficiency is the key for the achievement of 70% recovery factor. Different from the traditional polymer solution, a viscous continuous phase, which enhances oil recovery by increasing injection water viscosity to modify mobility ratio, the new method used a type of micro-nano particle-type polymer dispersion, which is with low viscosity. The polymer particle can temporarily block or inhibit relatively large pores with prevailing flowing, making the water diverted, at the same time, into small pores to displace the remaining oil there. So it can dynamically adjust the relative permeability of different degrees of water flowing channels by using different sizes of polymer particles, to more efficiently adjust the mobility ratio, achieving oil recovery enhancement. The pore-scale microscopic model experiment was conducted. Taking the post polymer flooding reservoir SB1 in Daqing Oilfield as an example, and 3D large-scale models (300mm ×300mm × 45mm) were used to conduct experiments to explore the feasibility of recovery increase up to 70%. And a pilot field test was conducted as a validation. Results showed that, during the middle-late stage of water flooding, the remaining oil was scattered in the pores and throats, and was hard to be moved. The high recovery factor EOR difficulty was both to inhibit different sized prevailing flowing channels, and to ensure not plugging oil flowing path, so as to efficiently produce remaining oil. The experiments on the pore-scale microscopic model showed that, the traditional polymer flooding relies on viscosity to increase the flowing resistance of all the swept area, and it cannot differentiate between high and low permeability or big and small pores. So the remaining oil in the low permeability zones or small pores can get high driving pressure and be produced. When the viscosity is high to some extent, it is hard to move the remaining oil. The new particle type polymer SMG is a type of low viscosity discontinuous phase fluid, and the SMG particles have priority to access relatively high permeability zone or big pore and throat, to temporarily block or inhibit the flowing there, and at the same time, the water can be diverted into the relatively low permeability zones or small pore and throat, to push the remaining oil out as a piston. It is defined as Synchronous Diversion-Flooding (SDF). The experiments on the 3D large-scale model showed that, after traditional polymer flooding get 55% recovery factor, SMG dispersion injection can make the model get recovery up to 66.6%. If adding some amount of surfactant, the recovery can reach up to 69.7%. The filed test on the dying complex fault reservoir, with high recovery factor of 63.2%, still obtained obvious technical and economic benefit. All the above proved the efficiency and economic feasibility of the method. SDF has different EOR mechanism with the traditional polymer flooding technology. It can efficiently sweep and initiate the scattered remaining oil, which is the technical key for enhancing recovery factor to more than 70%. The paper made some exploratory studies, and obtained preliminary progress.

Compared with conventional reservoirs, shale gas reservoirs usually have no natural productivity or lower productivity, and the rate of production decline is high in the later stage. The production of shale gas can be effectively improved by designing reasonably or fracturing. Therefore, it is critical for shale gas reservoir to study how to design proper parameters to make it effectively developed. Based on data of block-A region of the Zhejiang gas field, considering the contribution of rock compression to the production, the productivity formula of horizontal well at different seepage stages is deduced. Data from block-A are verified by orthogonal experiment, including gas reservoir parameters and engineering parameters. The results show that the order of reservoir parameters that affect the development of shale gas is as follows: Langmuir pressure, diffusion coefficient, cross flow coefficient, and Langmuir volume; the order of engineering parameters that affect the development of shale gas is as follows: number of fractures, horizontal section length, production pressure, fractures length, row spacing, and well spacing. The research results have been applied to the Zhejiang gas field. The initial rate of decline after adjustment is reduced by 26.08% and production increases by 17.06% after stabilization compared to wells without adjustment parameters. The research has important reference significance for the efficient development of similar gas reservoirs.