Abstract: The tight sandstone reservoirs in a certain block of the Shengli Oilfield are characterized by high density and well-developed fractures, which make them highly susceptible to drilling fluid damage during drilling. Through evaluations of reservoir mineral composition, porosity and permeability characteristics, and sensitivities, the primary causes of reservoir damage were analyzed. Accordingly, this study developed a new temporary plugging agent capable of self-degradation at reservoir temperatures and constructed a low-damage water-based drilling fluid system. The results indicated that the reservoir faced damage from solid phase plugging of fractures, water blocking, water sensitivity, and acid sensitivity. The developed epoxy resin-based self-degradable temporary plugging agent underwent network depolymerization via ester bond hydrolysis and transesterification reactions at high temperatures, generating soluble oligomers. At a reservoir temperature of 120 ℃, its degradation rate reached 21.8% after 48 h and 96.4% after 96 h. In addition, its compressive strength significantly exceeded that of calcium carbonate, a commonly used temporary plugging agent. Performance evaluation experiments on the low-damage drilling fluid demonstrated that it possessed excellent properties in rheology, filtration control, lubricity, and clay hydration inhibition. Simulated fracture plugging and core permeability recovery experiments showed that solid phases, including the temporary plugging agent, rapidly formed a sealing layer within the fractures during drilling. This sealing layer maintained good pressure-bearing capacity even after standing for 48 h at 120 ℃. After standing for 48–72 h, the structure of the sealing layer broke down, and following a 24 h flowback period, the core permeability recovery exceeded 90%, namely that formation damage was avoided effectively. Field tests in three wells demonstrated that this drilling fluid exhibited excellent lost circulation prevention and control effects. Furthermore, it effectively protected the reservoir through the self-degradation of the temporary plugging agent, resulting in a 91.83% increase in crude oil production in comparison with offset wells. can undergo network depolymerization through ester bond hydrolysis at high temperatures, generating soluble oligomers. At the reservoir temperature of 120 ℃, its degradation rate reaches 21.8% after 48 hours and 96.4% after 96 hours, with compressive strength far exceeding that of calcium carbonate, which is the typical temporary plugging agent. Performance evaluation experiments of the low-damage drilling fluid show that it exhibits excellent rheological properties, filtration control, lubrication, and clay hydration inhibition. Simulated fracture plugging experiments and core permeability restoration tests demonstrate that solid-phase materials such as the temporary plugging agent rapidly form a plugging layer in fractures during drilling. After static placement at 120 ℃ for 48 hours, the plugging layer still maintains good pressure-bearing capacity. After 48 to 72 hours of static placement, the structure of the plugging layer breaks down, and the core permeability recovery value exceeds 90% after 24 hours of flowback, effectively avoiding reservoir damage. Field tests conducted on three wells indicate that the drilling fluid demonstrates excellent performance in leak prevention and plugging. Additionally, the self-degradation of the temporary plugging agent effectively protects the reservoir, resulting in a 91.83% increase in crude oil production compared to offset wells.