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Abstract Sand-related degradation remains the primary constraint on Electric Submersible Pump (ESP) reliability in the BS field of the R Block, with Dismantle Inspection and Failure Analysis (DIFA) repeatedly documenting impeller/diffuser erosion, thrust-washer wear, and solids packing in stage clearances. These observations indicated that the dominant mechanism was not only abrasive cutting, but also adhesive fines bridging and torque instability, which conventional hardware-based solutions alone could not fully mitigate. In response, a field-engineered ESP–chemistry integration program was deployed in nine wells, combining multi-expertise in ESP design, materials, production operations, and oilfield chemistry. A non-ionic sand dispersant formulation selected through compatibility review, operating-envelope screening, and dose-effect evaluation was delivered via continuous capillary injection at the ESP intake. Performance was evaluated under normal operating conditions using run life, overload activity, motor-current behavior, and surface solids/BSW signatures, with overloads, deferred days, and lost-production opportunity (LPO) normalized to an annual basis to enable consistent comparison across wells. The operating strategy applied an initial conditioning phase at ∼200–300 ppm followed by controlled step-down toward ∼100–200 ppm as current stabilized and separation remained intact. The program demonstrated a material improvement in ESP reliability and operating behavior. Run life increased in seven of ten wells, shifting the median from 134 to 239 days (+78%) and increasing the mean by 131 days. Annualized overloads declined from 82 to 45 events (−45%), LPO decreased from ∼7,079 to ∼2,836 bbl/yr (−60%), and annualized deferred days dropped from ∼1,146 to ∼73 days/yr (−93%). Responding wells exhibited a consistent sequence: an initial surface fines purge, convergence of amperage from saw-tooth to tight-band profiles and sustained lower trip frequency at the stabilized dose. The economic implication is favorable at field scale. Across the responding wells, four deferred workovers collectively avoided approximately ∼$0.10 MM in rig exposure, while 760 – 1050 incremental well-days of uptime correspond to ∼30 – 42 kbbl of potential recovery at 40 BOPD. These outcomes are tied to the engineered pairing of ESP operating envelope, materials compatibility, and field-tuned dispersant delivery, and should not be generalized to unsupported chemical substitution. Overall, the work shows that when fines-driven adhesive behavior governs failure, capillary-delivered, interface-wetting dispersion can stabilize stage clearances, damp torque excursions, and extend ESP run life as a complement not a replacement to mechanical design and sand-handling practices.