A New Method for Modeling Multi-Phase Flowback of Multi-Fractured Horizontal Tight Oil Wells to Determine Hydraulic Fracture Properties

Abstract

Unconventional light oil reservoirs are currently a primary focus of exploration and development activity in North America. Operators are seeking new methods to characterize hydraulic fractures generated during stimulation of multi-fractured horizontal wells completed in these reservoirs, particularly early in the well life. One such method is to quantitatively analyze flowback fluids immediately after fracturing operations. In previous studies it has been shown that flowback fluid rates and pressures can be modeled to obtain hydraulic fracture half-length and conductivity. In this work, we develop an analytical procedure and methods for analyzing pre- and post-breakthrough of hydrocarbons during flowback of light tight oil wells. Flowback of multi-fractured horizontal wells, stimulated with water-based fluids in tight oil reservoirs, often consists of a short period of single-phase (water) flow followed by breakthrough of hydrocarbons, after which multi-phase flow (oil, water and gas) occurs. Our modeling approach therefore accounts for these multiple stages of flowback fluid production. The first flowback regime typically observed is fracture storage/depletion – this stage is analyzed by modeling single-phase depletion of the fracture pore volume from which a pre-hydrocarbon breakthrough estimate of fracture permeability and half-length is obtained. A stress-dependent permeability can be included to account for fracture closure and consequent conductivity loss during flowback. Fracture storage is followed by formation fluid breakthrough, which causes a deviation from the depletion signature. This stage is modeled by assuming transient linear flow of oil and formation water to the fracture, and accounting for consequent multi-phase flow in the fracture. The primary properties adjusted to match pre- and post-hydrocarbon breakthrough fluid production include fracture half-length and permeability, fracture relative permeability, breakthrough pressure and reservoir permeability. We have observed, as have others, that effective fracture half-length may be significantly reduced following hydrocarbon breakthrough. Our new method for tight oil reservoir flowback analysis is tested against a field example. As with previous studies associated with shale gas, significant uncertainty in fracture property estimation results from the analysis, which we will address in future work.

Innovative use of rate-transient analysis methods to obtain hydraulic-fracture properties for low-permeability reservoirs exhibiting multiphase flow

“…For this purpose, a simple single-phase flow, transient to boundary-dominated flow simulator, as Clarkson and Williams-Kovacs (2013) describe, is used (Figures 5c and 5d).…”

“…We cannot simply apply the straight-line or type-curve methods described above to derive an after-breakthrough estimate of fracture permeability and half-length. Instead, we have used the coupled fracture-formation flow model described in Clarkson and Williams-Kovacs (2013) to match fluid rates and cumulative production for this purpose. As noted above, this model approximates …”

“…Relative permeability, fluid saturations, and after-breakthrough fracture permeability and half-length are used as history-matching parameters, whereas formation permeability (actually effective permeability to oil in the formation) is estimated from DFIT analysis. Clarkson and Williams-Kovacs (2013) discuss details of the history-matching procedure and additional constraints applied in the modeling. Figure 6 gives the end result of the history match of beforeand after-breakthrough data.…”

“…In this work, we illustrate for the first time efforts to extract and compare hydraulic-fracture properties from multifractured horizontals completed in tight-oil reservoirs using production data collected during early flowback and later on-line Clarkson and Williams-Kovacs (2013) and Williams-Kovacs and Clarkson (2013) discuss analysis of flowback data associated with this well. Analysis of long-term production data and comparison of results to flowback-derived properties and other data provided in Figure 1 are not discussed in Clarkson and Williams-Kovacs (2013) and Williams-Kovacs and Clarkson (2013) and are unique to this study.…”

“…Analysis of long-term production data and comparison of results to flowback-derived properties and other data provided in Figure 1 are not discussed in Clarkson and Williams-Kovacs (2013) and Williams-Kovacs and Clarkson (2013) and are unique to this study.…”