Abstract This study presents key lessons learned from hydraulic fracturing challenges in the unconventional tight carbonate Middle Marrat Formation in North Kuwait Jurassic Gas fields. The horizontal appraisal well was drilled through two porous geo-bodies separated by a tight layer, intersecting 17 faults, which introduced structural complexity and wellbore stability risks. A multi-stage hydraulic fracturing approach was applied, integrating 3D Deep Fracture Mapping (3DDFM), mechanical earth modeling (MEM), and real-time formation imaging to optimize stimulation. This paper will demonstrate how integration of reservoir characterization diagnostics improves fracture connectivity mapping, stimulation design and diversion efficiency, understand structural challenges and how all such factors affect well productivity in addition to plug and perf operational challenges in horizontal monobore wells. To overcome uncertainties in reservoir connectivity, a slim Dipole Sonic (SDST) tool was deployed in the 4.5 inch cased lateral, conveyed by a slim tractor for acoustic velocity measurements. 3DDFM provided insights into far-field fracture connectivity between the two porous geo-bodies, aiding in stimulation design. A four-stage acid fracturing treatment was executed using Single Phase Retarded Acid System (SPRAS) and viscoelastic acid diverter, with real-time multi-finger caliper (MFC) logging due to restrictions in setting plugs. The number of fracturing stages was reduced after detecting liner deformations at locations of suspected active faults. The 3DDFM confirmed the structural dip of the geo-bodies and identified sub-layer connectivity through faulted fractures. Reservoir geosteering inversion further validated reservoir heterogeneity, but stimulation planning required additional stress profiling. MEM analysis confirmed high stress anisotropy, with closure pressures changes up to 2,700 psi. During execution, MFC revealed severe liner deformations at active fault locations, correlating directly with faults mapped by 3DDFM. These restrictions prevented full coiled tubing access during post-fracturing. Datafrac results showed low fluid efficiency, suggesting high fluid leak-off into natural fractures. However, particulate diverters successfully controlled fracture height growth, with pressure responses confirming effective diversion. This case study highlights the importance of integrating geophysical and geomechanical data in complex carbonate formations, demonstrating how fault mapping, mechanical modeling, and real-time diagnostics can mitigate risks and improve hydraulic fracturing success. This study represents the first integration of 3DDFM, Reservoir geosteering inversion, and MEM analysis for stimulation optimization in the unconventional Upper Middle Marrat Formation. The findings provide critical insights into fault-controlled fracture propagation, wellbore stability risks, and acid fracturing efficiency in tight carbonates. The lessons learned establish best practices for planning multi-stage hydraulic fracturing in structurally complex reservoirs, ensuring better connectivity, reduced fluid loss, and improved long-term well performance.
Al-Saeed et al. (Tue,) studied this question.