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

Kai Liao,Yushi Zou,Xinfang Ma,Shicheng Zhang

doi:10.3390/en12071189

Abstract

Multi-stage hydraulic fracturing along with horizontal wells are widely used to create complex fracture networks in tight oil reservoirs. Analysis of field flowback data shows that most of the fracturing fluids are contained in a complex fracture network, and fracture-closure is the main driving mechanism during early clean up. At present, the related fracture parameters cannot be accurately obtained, so it is necessary to study the impacts of fracture compressibility and uncertainty on water-loss and the subsequent production performance. A series of mechanistic models are established by considering stress-dependent porosity and permeability. The impacts of fracture uncertainties, such as natural fracture density, proppant distribution, and natural fracture heterogeneity on flowback and productivity are quantitatively assessed. Results indicate that considering fracture closure during flowback can promote water imbibition into the matrix and delay the oil breakthrough time compared with ignoring fracture closure. With the increase of natural fracture density, oil breakthrough time is advanced, and more water is retained underground. When natural fractures connected with hydraulic fractures are propped, well productivity will be enhanced, but proppant embedment can cause a loss of oil production. Additionally, the fracture network with more heterogeneity will lead to the lower flowback rate, which presents an insight in the role of fractures in water-loss.

Highlights

The development of conventional petroleum reservoirs has been unable to keep pace with the increasing global energy demand, which has shifted industrial attention to low permeability or tight reservoirs [1]
The whole reservoir consiststhe of functions triple media: matrix (M), A series of numerical models constructed by fully exploiting of commercial hydraulic fracture (HF), and natural fracture (NF)
The grid structure of a segment is shown segment is selected for simulation in this work, and its results can be mapped back to the whole in Figure 1, where the horizontal wellbore is along the x‐direction and the hydraulic fracture is along horizontal well scale [44]

Summary

Introduction

The development of conventional petroleum reservoirs has been unable to keep pace with the increasing global energy demand, which has shifted industrial attention to low permeability or tight reservoirs [1]. Rapid development of horizontal wells and multi-stage hydraulic fracturing technology enables unconventional tight reservoirs to be exploited [2,3]. Well productivity could be substantially increased if complex fracture networks are created by hydraulic fracturing [4,5]. Different from conventional fracturing, slickwater is the most commonly used fracturing fluid in unconventional reservoirs. Slickwater has a relatively low cost and low viscosity, which may help to create complex fracture networks [5,6,7]. Horizontal wells that undergo multi-stage fracturing operations often require a large amount of water injected into the formation to create a large stimulated reservoir volume. After hydraulic fracturing is completed, the flowback treatment of fracturing fluid should be carried out, followed by long-term production [8,9,10]. Field data show that the Energies 2019, 12, 1189; doi:10.3390/en12071189 www.mdpi.com/journal/energies

Methods

Results

Conclusion