Optimization of Fracture Cleanup Using Flowback Analysis

Abstract A field study in north-central Texas shows how flowback procedures can be optimized to improve fracture cleanup and well productivity in low-permeability formations. Load water and polymer returns from 15 Barnett shale hydraulic fractures were analyzed and quantified. These were massive hydraulic fracturing treatments (1.4 million lbm of sand and 10,000 to 15,000 bbl of fluid) in an ultra-low-permeability (0.001 md) formation. These wells were fractured using low gel loading borate-crosslinked fluid. Well productivity is correlated with fracture cleanup. Aggressive flowback procedures improved fracture cleanup and well productivity. The maximum flowback rate was increased from 0.6 bbl/min at the beginning of the field test, to as high as 6 bbl/min. Polymer returns at conservative flowback rates, < 3 bbl/min, averaged 31 ± 6% of the total amount pumped on the job. Polymer returns from wells aggressively flowed back, >3 bbl/min, averaged 46 ± 9%. Aggressively flowed back wells produced on average 19% more gas over the first 180 days of production than conservatively flowed back offsets. Recovery of polymer continued throughout the early stages of production in addition to the polymer returned during flowback. Significant polymer concentrations were recorded in produced water samples collected up to five months following the treatment. Recovery during production can yield 10 to 13 % of the polymer pumped during the job in addition to the amount recovered during flowback. Similar patterns of polymer recovery are observed when the Barnett shale results are compared with those from the Codell formation (0.010 md) in Colorado. This is in spite of differences in treatment size, job design, and fluid selection. Therefore, it is plausible that the results from these two studies can be generalized, and applied to many other low-permeability formations. Significant differences are observed when the Barnett results are compared with those from the Cotton Valley formation in east Texas. These differences are primarily due to the production of water by the latter formation.