To maximize shale volatile oil field liquids production, an integrated study was conducted by quantifying the relative contributions of fluid properties, drawdown rates and hydraulic fracturing designs. The first part of this study includes analyzing production data from dozens of wells in the area of interest and examining available PVT reports to delineate fluid phase boundaries. Strong correlations have been observed between well productivity and estimated initial GOR, and an optimal GOR range has been identified for higher liquid production. The data analysis also demonstrated the high uncertainty of surface PVT sampling under aggressive pressure drawdowns. The recommendation is to consider the measured GOR under certain surface PVT sampling conditions as a key uncertainty for production optimization modeling.
Secondly, several wells were selected with similar geology and executed hydraulic frac designs for verifying the impacts of different drawdown rates on liquid production. The data clearly demonstrates the sensitivity of oil production, water cut and GOR based on drawdown rate. We conclude that there is an optimal pressure drawdown strategy that will maximize both the short period and the long-term oil recovery.
Finally, we used our tight-rock specific history-matching workflow to quantify the complex interaction of drawdown rates, GOR and hydraulic fracture designs in tight unconventional formations. Production from two wells of significantly different drawdown history and GOR has been matched. The resulting geo-mechanical compaction curves demonstrate significantly more permeability degradation for the aggressive drawdown case compared with that of the moderate drawdown. Simulation demonstrates aggressive drawdown only reduces pressure near the fracture, while the moderate drawdown can deplete the reservoir more evenly. Managing the gas production (reservoir energy) could balance the drawdown force with tight pore capillary pressure to keep GOR/WCT low and to deliver the high oil production. The history matched models have been very valuable to explain the production difference among the wells, and to define the basis of design with reliable production forecasts and optimal fracture designs.