Introduction The Eagle Ford Shale is upper cretaceous hydrocarbon-bearing marl that is currently being aggressively developed over a 15,000 square mile, 26 county area in south Texas. It varies in thickness from 50 to 300 feet and is productive at depths ranging from 5,000 to 14,000 feet subsea. The Eagle Ford formation is bounded at the base by the lower Cretaceous Buda Limestone and overlain by the Austin Chalk. It has relatively low total clay content and a calcite volume greater than 50% making it a more brittle rock favourable for hydraulic fracturing operations. The highly laminated, impermeable and anisotropic nature of the reservoir requires increasingly sophisticated completion designs. In addition, the high per acre valuation has pushed operators to optimize the location and spacing of development wells within their leasehold, in order to maximize the ultimate production of reserves, resulting in the necessity to drill wells across major fault zones. An E&P company drilled two horizontal laterals in the gas/condensate window of the Eagle Ford shale trend in Karnes County, Texas. The respective Wells A and B consist of two parallel, toe-down laterals drilled approximately 330 feet apart (Fig. 1). The main challenge associated with the wells was drilling and completing the laterals across a major fault zone while targeting a fairly narrow vertical interval within the lower Eagle Ford formation. In fact, the downthrown portion of the Well B lateral drifted into the Buda limestone for about 80 feet (Fig. 1), highlighting the validity of this concern. Microseismic monitoring provided the opportunity to identify fault interaction in real-time and analyse the mechanisms of interaction after the job. The integration of treatment data with the microseismic results proved essential for the analysis in both real-time and post-job.