Estimating Effective Fracture Pore Volume From Flowback Data and Evaluating Its Relationship to Design Parameters of Multistage-Fracture Completion

Abstract

Summary Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.

Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs

“…Pressure data from diagnostic fracture injection test (DFIT) can be used to determine representative matrix permeability, minimum in-situ stress, characterize the roughness of fracture walls and estimate the pressure/stress dependent conductivity of un-propped fractures (Wang and Sharma 2017;. Flow back data can also be useful to infer effective fracture pore volume if fracture compliance can be estimated from DFIT (Fu et al 2017). The data of stretched transitional flow period can possibly yield information on fracture complexity and heterogeneity (Jorge 2016;.…”

The Effect of Temperature on Flowback Data Analysis in Shale Gas Reservoirs: A Simulation-Based Study

“…Fracture networks in shale can be quite complex due to the reactivation of natural fractures by hydraulic fracturing. Also, studies suggest that most fracturing water remains in natural fractures after the fracturing treatment [47,87]. The results of temperature change may thus be influenced by the simplified fracture geometry for shale gas wells.…”

Numerical Investigation of Fracture Compressibility and Uncertainty on Water-Loss and Production Performance in Tight Oil Reservoirs

“…The results of his simulations indicated that the closure of unpropped fractures within fracture networks resulted in low water recovery. Fu et al [25] collated and processed the early flowback data of seven multi-fractured horizontal wells in tight reservoirs. Data analysis suggested that most of the facture systems were un-propped after stimulation and held most of the fracturing water.…”