Production Comparison of Hydraulic Fracturing Fluids in the Bakken and Three Forks Formations of North Dakota

Abstract

Abstract There have been extensive efforts to recover oil from the Bakken formation in North Dakota since it was discovered in 1951. However, these efforts were not particularly profitable until the 2000s when horizontal drilling and large, multistage hydraulic fracturing treatment methods were used. The new drilling and completions methods created a substantial increase to production, which escalated throughout recent years and created a demand for better, more efficient completions. One major component of these completions is the base fluid used for hydraulic fracturing treatments. This paper compares hydraulic fracturing treatments of a new, residue-free (res-free) hydraulic fracturing fluid to all other fracturing fluid treatments. The res-free fluid system was presented in 2012 as a premier fracturing fluid and economic alternative to guar-based systems to increase the resultant fracture conductivity. Since 2012, more than 40 wells have been completed in either the Bakken or Three Forks formations of North Dakota using the res-free fracturing fluid. While initial cost savings were realized, the production results from these wells have not been extensively studied. This paper presents the findings of a study comparing production from wells treated with res-free fracturing fluid to wells treated with other hydraulic fracturing fluids. Because the wells completed using the res-free system are widespread throughout North Dakota and belong to several different operators, choosing a specific study area was challenging. To overcome this challenge, a spatial sampling technique was used. Spatial sampling is a method for comparing a large group of wells to their direct offsets. For this study, spatial sampling was applied to compare wells completed using the res-free system to wells completed using other fluids. To normalize general completion methods, only wells completed since the beginning of 2012 are included in this study. Offset wells for this study are those within a 1-mile radius from the center well. The production data for all wells was obtained from public sources. The proppant amount and total fluid volumes were normalized per foot of lateral to minimize variables. Other factors, such as drilling placement, type of proppant, type of fluid, or compartmentalization can affect production; however, these effects are not considered during this study.