Аңдатпа
In the development of oil and gas fields with elevated and high formation temperatures, the effectiveness of hydraulic fracturing (HF) operations is largely determined by the correct selection of the breaker system, which ensures controlled degradation of the polysaccharide gel after pumping and proppant placement. In conventional HF design practice, breaker type and concentration are typically selected based on a static formation temperature, while variations in the near-wellbore thermal regime during pumping are only partially considered. This study presents the results of an analysis of formation temperature dynamics recorded in real time using an autonomous downhole pressure–temperature gauge during an HF operation, including the injection test, mini-frac, and main fracturing stages. It was established that injection of fracturing fluid at a surface temperature of approximately 20 °C leads to a rapid reduction of near-wellbore temperature by several tens of degrees relative to the initial formation temperature. Operational pauses result in partial temperature recovery; however, the original thermal state is not restored before subsequent stages. The results demonstrate that the effective temperature governing HF fluid performance during a significant portion of the operation differs substantially from the static formation temperature. This discrepancy affects gel degradation kinetics and the efficiency of persulfate-type oxidative breakers. Comparison of field temperature data with laboratory rheological test results obtained using a Chandler 5550 viscometer confirms the necessity of accounting for dynamic temperature conditions when selecting breaker systems. Incorporating actual thermal history into breaker design improves selection reliability and enhances fracture cleanup efficiency in hightemperature reservoirs.