Claudio Virues

Flowback Fracture Closure: A Key Factor for Estimating Effective Pore Volume

The importance of evaluating well productivity after hydraulic fracturing can not be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage fractured wells. Similarly, there has been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters such as fracture pore-volume, half-length and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture pore-volume independent of fracture geometry. This study starts by using rate-normalized pressure plots to observe changes in fluid flow mechanisms from multistage fractured wells. The fracture “pressure supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between rate normalized pressure and time, useful for interpreting flowback data in wells which show pseudo steady-state behavior (unit slope on log-log rate normalized-pressure plots). The linear relationship is implemented on a simple montecarlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture pore-volume, using probabilistic distributions of average fracture compressibility, and gas/water saturations respectively. Also, the proposed model investigates the contributions of various drive mechanisms during flowback including fracture closure, gas expansion and water depletion. Application of the proposed tank model to flowback data from fifteen shale gas and tight oil wells estimates the effective fracture porevolume and initial average gas saturation in the active fracture network. The results show that fracture pore-volume is most sensitive to fracture closure compared to gas expansion and water depletion, making fracture closure the primary drive mechanism during early flowback periods. Also, the initial average gas saturation for all wells is less than twenty percent. The parameters estimated from the proposed model could be used as input guides for more complex studies (such as discrete fracture network modeling and transient flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.. To order the full paper, visit https://doi.org/10.2118/175143-MS TECHNICAL PAPER

A Flowback-Guided Approach for Production Data Analysis in Tight Reservoirs

One key limitation of conventional production data analysis (PDA) is non-uniqueness of solution. This can cause huge uncertainty in reservoir parameter estimates and hydrocarbon forecasts. Hence, there is need for an alternative approach to PDA. This paper tackles this issue using flowback data analysis (FDA) as a constraint to guide PDA. We recently extended the existing linear dual-porosity model (DPM) to develop a flowback analysis model (FAM). Here, we intend to i) test the accuracy of FAM to predict gas production in the field, and ii) investigate how the results from its application on flowback data could reduce the uncertainty associated with conventional PDA. This study applies FAM to history match 2-phase flowback data from three multifractured shale-gas wells completed in the Horn River Basin. The history match estimatesFAM estimates effective half-length and initial gas-volume in hydraulic-fractures before flowback. It is also used to forecasts post-flowback gas production. This forecast is verified by comparing it actual post-flowback production data. An independent single-phase PDA on post-flowback production data from the same shale-gas wells overestimates hydraulic fracture(HF) half-lengths compared to the FAM history-match results. This could be a result of the presence of water plugged secondary fractures with negligible communication interface with the hydraulic fractures during flowback. The interface significantly increases during postflowback production periods as water gives way to gas from the matrix. One key result of this study is that HF half-lengths from PDA could significantly differ from those from post-flowback PDA. It is more appropriate to interpret both flowback and production data using a single multiphase model. FAM is an example of such models that captures the “necessary” physics for both flowback and production operations. PDA without considering flowback data could lead to inaccurate results. This study shows how to perform a robust flowback-data-analysis that complements PDA for comprehensive fracture/reservoir characterization. These results encourage the industry to start careful and accurate measurement of rate+pressure immediately after opening wells for flowback. To order the full paper, visit https://doi.org/10.2118/171636-MS TECHNICAL PAPER