Mitigating Fracture Height Growth: Fracturing Design Sets Strategy in Field Development

A field in northern Oman within the largest Block X (block number remains confidential), is characterized by heterogeneous sandstone lithology with a relatively thin gross reservoir, confined between two distinct shale formations. Diagnostic Fracture Injection Tests (DFITs) indicated significant fracture height growth potential. This paper presents an engineered hydraulic fracturing strategy, integrating real-time data and field trials, to mitigate downward fracture propagation and optimize water injector performance, enhancing reservoir pressure support within the developing field. A conventional hydraulic fracturing treatment, modeled in a 3D simulator, was initially designed to enhance reservoir conductivity and injectivity. However, the lower shale formation posed a significant risk of excessive fracture height growth and compromising the fracture conductivity. To mitigate this risk, the initial fracturing design incorporated classic containment strategies, including lowered to 20% pad volume and a reduced pumping rate of 2.25 m3/min. However, based on pre-job DFIT and G-function analysis confirmed height recession, with net pressure values as low as 3.9 MPa, indicating the potential for uncontrolled height growth. To address this, a controlled proppant bridging barrier was strategically placed during the fluid efficiency test (FET), based on SPE literature and field learnings. This approach effectively limited fracture growth into the lower formation. The primary objective of placing 40 metric tons (MT) of proppant was successfully achieved. Post-treatment tracer logs confirmed controlled fracture height growth, ensuring the integrity of the target zone. The well’s injectivity improved significantly, with post-fracturing performance exceeding expectations by a factor of 14. This enhancement helped maintain pressure in nearby oil producers, resulting in a 10% increase in daily production. The operation validated the importance of adaptive fracturing design and real-time diagnostics in overcoming containment challenges. The revised strategy demonstrated a reliable, field-proven method for managing fracture geometry in thin, heterogeneous sandstone reservoirs typical of Project Field and similar fields. This study introduces a novel integration of real-time diagnostic data with engineered proppant bridging to manage fracture height in challenging stratigraphy. The approach mitigated downward fracture growth, safeguarding zonal isolation and enhancing injector performance in Project Field. These findings offer valuable insights for operators managing height containment risks in analogous reservoirs and contribute to the evolution of optimized fracturing practices in northern Oman.