Abstract Ghazij gas reservoir is characterized by thin laminated limestone stringers that are interbedded with reactive shales, forming multiple lobes that are distributed as conventional and tight reservoirs. To develop tighter lobes, two-stage frac job was performed against the inherent uncertainties of shale reactivity, fracture complexity, perforation strategy, and interfacial slippage. Suboptimal results in Stage- 1, triggered the need for rapid reassessment of Stage-2. Success achieved by implementing learning from stage-1, highlighting the need for adaptive, optimized fracturing framework tailored to heterogenous reservoir behavior. To prove the concept, two-stage fracturing strategy developed to validate fracture placement and enhance productivity. Stage-1 focused on establishing fracability and calibrating geomechanical parameters using conservative design with controlled fluid volumes, pad ratio, proppant sizes, and step volume. Post-treatment diagnostics, including a fall-off test and its pressure transient analysis using the downhole gauges data, indicated suboptimal fracture geometry and conductivity, which guide to the reassessment of the Stage-2 design. This reassessment included an optimized perforation strategy, re-engineered frac fluid for improved leak-off control to lower the residue, and more aggressive treatment schedule. TSO design with a larger mesh proppant and breaker loading was tailored to match the thermal conditions, ensuring polymer degradation to preserve the fracture conductivity. During Stage-1, successfully placed treatment volumes. Post-frac diagnostics, including MiniFrac and net pressure analysis, indicated limited net pressure, suggesting narrow fractures and low conductivity, which correlated with negligible production improvement. ISIP gradient analysis (0.9 psi/ft) and calibrated 1D MEM confirmed a dominant normal faulting regime, alleviating initial concerns of strike-slip regime. Low treating pressures across varying proppant sizes demonstrated favorable proppant transport and reservoir receptiveness. However, delayed post-frac flowback - likely driven by fluid imbibition, contributed to slow fluid recovery. This understanding provided critical insights for Stage-2 design refinement. Stage-2 adopted a data-driven optimization strategy and utilized the TSO approach. Furthermore, the perforation length was adjusted to avoid multiple fractures, DFIT was enhanced with the high-concentration breaker system, low-viscous pad fluids with optimized clay stabilizer to control the height growth, reduce the formation damage and minimize the shale reactivity. Gel and methanol concentrations were refined to mitigate fluid imbibition and improve cleanup. The optimized fracturing strategy effectively overcame Stage-1 challenges, resulting in a four-fold production increase, improved net pressure, and the rapid flowback. This validated the effectiveness of the design and the fluid selection, leading to better reservoir stimulation and performance. This paper presents the fracturing strategy in a thin laminated heterogenous reservoir that addresses the associated challenges like shale reactivity, fracture complexity, height growth and fluid imbibition. The integration of TSO approach and optimized frac fluid rheology enhanced the fracture conductivity and the fluid recovery. The key learnings from this paper offers valuable insights to overcome similar challenges by optimizing fracturing strategies. Future work will focus on multi-stage frac and use of advanced diagnostic tools to measure the height growth and further improve stimulation efficiency.
Hafeez et al. (Mon,) studied this question.