Hydraulic fracturing is a common stimulation technique in oil and gas production to stimulate wells with low permeability. An optimum fracture half-length is designed by injecting the right amount of fracturing fluid to achieve successful results. Otherwise, injecting lower than the optimal amount will cause a poor fracture network, water blockage, and phase trapping of oil and gas behind the fracture space while over injection may result in frac hits and unfavorable economics. This paper presents the importance of the optimum fracture half-length and the role of injection volumes to generate such a length. CMG models were created to study the correlation of different parameters during hydraulic fracturing in the Wolfcamp formation (Permian basin): fracture permeability, water saturation, and capillary pressure. Three CMG models with different fracture half-lengths of 100ft, 200ft, and 350 ft were created. Sensitivity analysis of facture permeability was performed on each model using different values, e.g. 0.1, 1, 10, and 100 md. Representative cases were selected based on the sensitivity analysis results on fracture permeability. Fracture permeability was then changed in each model and was 5 md for the first model, 10 md, and 20 md for the second and third models, respectively. The effect of water saturation was also studied by changing the water saturation from 45% to 55% in an increment of 5% in each simulated model. Finally, the capillary pressure data was added to each model to study the effect of water blockage. Economic analysis was studied to determine the best-case scenario in terms of higher NPVs and RORs. Sensitivity analysis of facture permeability indicated that as fracture permeability increases, then an increase in hydrocarbon production is achieved in which the water saturation was the conclusive parameter. For instance, hydrocarbon production rates were the lowest in the first model which had the lowest fracture half-length and, therefore; fewer water volumes were injected. The second model with a fracture half-length of 200ft as the optimum length provided the optimal amount of injected water and gave the highest amount of incremental Hydrocarbon production, i.e. water saturation and fracture permeability were higher than the previous one. The last model, which has the highest fracture half-length and also the highest amount of injected water showed a significant amount of formation damage. A higher amount of injected fluids caused a high capillary pressure that was responsible for blocking the fractures and caused a decrease in relative permeabilities. The amount of injected water during hydraulic fracturing will significantly affect oil and gas production. CMG models, decline curve analysis, and economic studies showed that designing the optimum amount of injection volumes is key to a successful hydraulic fracturing treatment and minimizing the risk of causing any damage to the formation.

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