Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir

A new semi-analytical flow model for multi-branch well testing in natural gas hydrates

The regulation of the seasonal energy supply for natural gas and the storage of fossil energy are important to society. To achieve it, storing a large amount of natural gas in porous underground media is one of the government’s choices. Due to the successful lesson learned from the oil and gas industry, natural gas storage in underground porous media has been regarded as the most potential long−term energy storage method. In this paper, we developed a new workflow to evaluate the performance of gas reservoir−type underground natural gas storage (UGS). The theoretical background of this workflow includes the correction of the average formation pressure (AFP) and gas deviation factor by error theory and the analytical mathematical model of UGS wells. The Laplace transform, line source function, and Stehfest numerical inversion methods were used to obtain pressure solutions for typical vertical and horizontal wells in UGS. The pressure superposition principle and weighting method of the gas injection−withdrawal rate were used to obtain the AFP. Through the correction of the AFP and gas deviation factor in the material balance equation, the parameters for inventory, effective inventory (the movable gas volume at standard condition), working gas volume (the movable gas volume is operated from the upper limit pressure to the lower limit pressure), and effective gas storage volume (the available gas storage volume at reservoir condition) were determined. Numerical data from the numerical simulator was used to verify the proposed model pressure solution. Actual data from China’s largest Hutubi UGS was used to illustrate the reliability of the proposed workflow in UGS performance evaluation. The results show that large−scale gas injection and withdrawal rates lead to composite heterogeneity in gas storage wells. The nine injection and production cycles’ pressure and effective inventory changes from Hutubi UGS can be divided into a period of rapid pressure rise and a period of slow pressure increase. The final AFP is 32.8 MPa. The final inventory of the Hutubi UGS is 100.1 × 10⁸ m³, with a capacity filling rate (the ratio of effective inventory to designed gas storage capacity) of 93.6%. The effective inventory is 95.3 × 10⁸ m³, and the inventory utilization ratio (the ratio of effective inventory to inventory) is 95.2%. The working gas volume is 40.3 × 10⁸ m³. This study provides a new method for inventory evaluation of the gas reservoir−type UGS.

Low permeability oil reservoir resources are rich and their efficient development is considered an important way to solve energy security issues. However, the development process of low permeability oil reservoirs is faced with the challenges of insufficient natural energy and rapid production decline. The high-pressure water injection technology is a method that relies on high-pressure and large-volume to inject fluid into the reservoir to replenish energy. It is considered as an important technical means to quickly replenish formation energy. This study focuses on the injection capacity for the high-pressure water injection technology of low permeability oil reservoir. Firstly, the fluid-structure interaction mathematical model for two-phase fluid flow was established. The solution of the mathematical model was then obtained by coupling the phase transport in porous media module and Darcy’s law module on the COMSOL numerical simulation platform. The numerical model established in this study was verified through the Buckley-Leverett model. The study on the injection capacity of high-pressure water injection technology was conducted using the geological background and reservoir physical properties of Binnan Oilfield (Shengli, China). The results show that the production pressure difference is the key factor in determining the injection capacity. When the production pressure difference increases from 5 MPa to 30 MPa, the cumulative injection volume increases by 8.1 times. In addition, sensitivity analysis shows that the injection capacity is significantly influenced by the properties of the reformation area. The effect of these parameters from high to low is as follows: stress sensitivity factor, permeability, rock compressibility, and porosity. Compared to the reformation area, the influence of the physical parameters of the matrix area on the injection capacity is negligible. Therefore, effective reservoir reformation is essential for enhancing the injection capacity. This research provides a theoretical basis for the design and optimization of the high-pressure water injection technology schemes for low permeability oil reservoir.