No abstract

No abstract

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

The simultaneous flow of gas and water is controlled by a threshold pressure gradient (TPG) effect during CO 2 injection of tight gas reservoirs. The TPG effect is dynamic because it varies with both the effective stress and the water saturation. The sensitivity of TPG to effective stress and mobile water is affected by the porethroat microstructure. In this paper, we report the results of dynamic TPG tests on six cores with similar permeability. The influence of the pore-throat microstructure on the sensitivity of the TPG to stress and to mobile water was also quantitatively studied using a fractal method, and the distribution of the threshold pressure and corresponding gas production loss were calculated during CO 2 injection in tight gas reservoirs. The test results show that TPG decreases logarithmically with the increase of the pore fluid pressure during CO 2 injection, a change of 0.1−50 MPa in the pore fluid pressure corresponding to a 1.8−3.5 times increase of the TPG variation. The TPG increases exponentially by 3.5−6.7 times from irreducible water saturation to a mobile water saturation of 30%. The fractal dimension (D) of the heterogeneity of the rock pore-throat microstructure has a linear relationship with both the stress sensitivity coefficient (λ) and mobile water sensitivity coefficient (η), with the larger values of λ and η being associated with more heterogeneous pore-throat microstructures. The reservoir threshold pressure showed a significant nonlinear distribution in near-well reservoirs at low bottom-hole flow pressures of the production well during CO 2 injection. The calculated gas well production loss as a result of a dynamic threshold pressure is 7−16% higher than that of the fixed threshold pressure, and the difference is larger at low pressures.

No abstract