Feasibility Study of Fracturing of Water Bearing Sandstone Gas Reservoir on the North Slope of Lingshui

The Lingshui Beipo gas reservoir is located in the northern part of the Qiongdongnan Basin in the South China Sea, and is a typical high-temperature, high-pressure, and low-permeability sandstone gas reservoir developed in the Cenozoic fault basin at the junction of the ancient South China Platform and the ancient South China Platform. The main gas reservoir of this gas reservoir is the Meishan Formation, which is a typical medium porosity and low permeability reservoir with little natural production capacity. Based on the experience of onshore oil fields, hydraulic fracturing is an effective way to achieve industrial production in such reservoirs. However, the risk of fracturing in offshore gas reservoirs is extremely high, and feasibility studies on hydraulic fracturing are urgently needed. Therefore, this article analyzes the basic characteristics and main problems of the Meishan Formation gas reservoir, and conducts a feasibility study on hydraulic fracturing of the Meishan Formation from the aspects of fracture pressure, treatment pressure prediction, gas-water layer analysis relationship, and simulation of fracture height and permeability. Analysis suggests that the use of high pumping rate fracturing may lead to high treatment pressure, small stress differences between the reservoir and barrier layer, which can easily lead to uncontrollable fracture height, and the use of fracturing may lead to communication with the water layer, resulting in water flooding of the gas well. These are key issues that constrain the fracturing of this gas reservoir. A fracture pressure prediction model for the Lingshui North Slope gas reservoir was established using extended finite element method. The predicted fracture pressure of the Meishan Formation was 69-98 MPa, and the predicted treatment pressure was 70-100 MPa. The use of large-sized oil pipes is beneficial for reducing treatment risks. A three-dimensional fracture propagation model was established using the Cohesive pore pressure element. The simulation shows that the pumping rate and liquid volume are the key factors affecting the fracture height. When there is a water layer, the pumping rate should not exceed 6m3/min and the liquid volume should not exceed 250 m3. In the absence of a barrier between the gas and water layers, it is difficult to avoid hydraulic fracturing from communicating with the water layers. Therefore, hydraulic fracturing is not recommended for such reservoirs. The hydraulic fracturing treatment pressure of Lingshui North Slope Gas Reservoir is high, and the risk of communicating with water layers is high. It is necessary to moderately control the pumping rate and scale, optimize the combination of fracturing fluid and pipe string, and reduce the risk of offshore fracturing.