No abstract

No abstract

The mechanical properties of the high-temperature and high-pressure reservoirs in the southern margin of Junggar Basin have not been clearly understood, which correspondingly results in uncertainties when predicting the breakdown pressure. To address this issue, firstly, rock mechanical experiments under high temperature, high confining pressure, and high pore pressure were carried out. Secondly, empirical formulas related to the transformation of dynamic and static mechanical parameters in the regional strata were proposed. Finally, the existing prediction model for the formation breakdown pressure was improved by taking the wellbore seepage and thermal stress into consideration. Results show that under the reservoir condition of high temperature and high pressure, the rock sample tends to form closed shear cracks. High temperature causes thermal damages and the reduction of the compressive strength and elastic modulus, while the combined effects of high confining pressure and pore pressure enhance the compressive strength and plasticity of the rock sample simultaneously. Based on the correlation analysis, it is found that the static elastic modulus is linearly related to the dynamic value, while static Poisson’s ratio is a quadratic function of the dynamic value. These fitting functions can be used to obtain the profiles of static elastic modulus and Poisson’s ratio based on their dynamic values from the logging interpretation. Besides, the improved prediction model for the rock breakdown pressure can yield more accurate results indicated by the error less than 2%. Therefore, the proposed breakdown pressure prediction model in this study can provide theoretical guidance in the selection of fracturing truck groups and the design of the pumping schedule for high-temperature and high-pressure reservoirs.

No abstract

Efficient development of deep tight reservoirs in the southern margin of the Junggar Basin requires stimulation technology, and effective propped hydraulic fractures are the key to successful stimulation. To optimize the proppant selected for reservoir stimulation, the important parameters of proppant selection were determined through the proppant conductivity evaluation experimental study and field test, considering the influences of high temperature and high closure pressure. The results show that closure pressure, temperature, and sand concentration have a great influence on the conductivity of the proppant pack. The conductivity of the proppant pack decreases by about 10% at high temperatures, which is because the high temperature will rupture more proppant and thus reduce proppant pack permeability. In the long term, the Scenario B placement pattern can maintain high conductivity, and the long-term conductivity is increased by 6–26% compared with the Scenario C placement pattern. Furthermore, increasing the proppant placement concentration is conducive to the long-term conductivity of the fracture. During the operation of the test well, the treatment pressure was stable, and the fractures were effectively propped. No proppant flowing back occurred in the test production after the fracturing treatment, which achieved the purpose of the evaluation well, provided support for the large-scale development of subsequent development wells, and ensured orderly development.