Investigation of Hydraulic Fracture Water Injection in Wolfcamp Formation

Abstract

Hydraulic fracturing in low permeability formations is one of the most important steps in oil and gas production. A successful hydraulic fracturing will most likely result in successful oil and gas production. Designing an optimum fracture half-length will result in injecting the perfect amount of fracturing fluid which will result in better hydrocarbon production. Otherwise, injecting less fluid will result in less hydrocarbon production and injecting more fluid will result in water blockage which will reduce relative permeability and also cause phase trapping where oil and gas are trapped and will not be produced. This thesis focuses on fracture half-length and the effect of water volumes injected to generate such a length. Many models were created to test different parameters such as the effect of permeability, water saturation, and capillary pressure on the water blockage issue in Wolfcamp formation. Economic analysis was done later to show which model is the most beneficial. Three different fracture half-length of 100ft, 200ft, and 350ft were selected for the models. Each model was tested separately with different permeability to show the effect of fracture permeability on oil and gas production. The fracture permeability, 0.1,1,10, and 100md, was used in three models, respectively. Representative cases were selected based on the sensitivity analysis results on fractures with different fracture half-length next. Fracture permeability was changed in each model and was 5md for the first model, 10md, and 20md for the second and third model, respectively. The effect of water saturation was studied by changing the water saturation from 45% to 55% in an increment of 5% in each model. Capillary pressure was then added to test its effect on the 3 models. All models had the same capillary pressure. Economic analysis was made to see which model is more beneficial. As fracture permeability increases the trend show an increase in hydrocarbon production. Water saturation was the conclusive parameter. Hydrocarbon production was the lowest in the first model. The first model, which has fracture half-length of 100ft, had the lowest fracture half-length, therefore less water was injected. As a result, water saturation was the lowest in this model. The second model, which has fracture half-length of 200ft, had the optimum fracture half-length which means this model had the perfect amount of injected water. Hydrocarbon production was the highest in this model. Water saturation and fracture permeability were higher in this model than the previous one. The last model, which has fracture half-length of 350ft, had the highest fracture half-length. This model had the highest amount of injected water. Injecting more water than needed resulted in formation damage. Water was blocking the fractures and caused decrease in relative permeability. Oil and gas were trapped in the formation as a result. This model’s hydrocarbon production was higher than the first model and lower than the second model. This model had the highest water saturation and fracture permeability.