Coupled geomechanics and transient multiphase flow at fracture-matrix interface in tight reservoirs.

Kukha Hawez, Haval Rostam

Abstract

Fractured hydrocarbon reservoirs play a significant role in the world economy and energy markets. Fluid injection (normally water) forces the hydrocarbons out of the reservoirs. Geomechanics, externally applied stress on the rock, play a significant role in the oil recovery from fractured reservoirs. Subsurface fluid injection modifies pore pressure and in-situ stresses locally. In response to the pressure/stress combined effects, the pores and fracture regions undergo deformation. Similarly, it is a well-known fact that pore volume significantly impacts the absolute and relative permeability of fractured tight reservoirs. The governing factors that characterize multiphase fluid flow mechanisms in naturally-fractured tight reservoirs - such as wellbore stability, CO2 sequestration and improved hydrocarbon recovery - are relative permeability and capillary pressure. Although the effects of geomechanical parameters on single-phase fluid flow in naturally-fractured tight reservoirs are well documented, the interdependence between geomechanical and multiphase flows are severely lacking. This study aims to bridge this knowledge gap using advanced numerical techniques, focusing on accurately capturing complex flow phenomena at the fracture-matrix interface to enhance the accuracy of predicting oil recovery from naturally-fractured tight reservoirs, leading towards more efficient operations and reduced costs. Extensive sets of numerical investigations have been carried out in the present study, using an advanced Computational Fluid Dynamics (CFD) solver, to accurately capture transient multiphase flow (oil and water) phenomena within naturally-fractured tight reservoirs. Special attention has been paid towards accurate multiphase flow modelling and characterisation at the fracture-matrix interface. The numerical models have been validated against Berea Sandstone experimental data. Two separate numerical models have been developed with the aim to identify the most appropriate modelling technique for accurate numerical predictions of multiphase flow in naturally-fractured tight reservoirs. These two models are based on duct flow theory and flow through porous medium theory, respectively, while the Brooks and Corey method has been utilised to compute fluid saturation, relative permeability and capillary pressure at the fracture-matrix interface. The results obtained show that the difference between the numerical and experimental results is 30% when duct flow model is considered, while it is 2.57% when porous medium is considered. In order to critically evaluate the dependence of multiphase flow on the geomechanical parameters of naturally-fractured tight reservoirs, a one-way FEACFD coupling scheme has been implemented in the present study, not taking into consideration the pore pressure. The effects of externally applied stress loading on the geomechanical (porosity and fracture aperture) and multiphase flow characteristics (permeability, capillary pressure, relative permeability and fluid saturation) at the fracture-matrix interface have been thoroughly analysed. For accurate modelling and numerical predictions in naturally-fractured tight reservoirs, a viscous loss term has been incorporated in the momentum-conservation equations. The numerical predictions from the one-way coupled model matches well with Clashach core flooding experimental data, with 9% average difference between the two. The results obtained clearly indicate that external stress loading has significant impact on the geomechanical and multiphase flow characteristics at the fracture-matrix interface. Finally, a novel numerical model has been developed based on the full coupling scheme, with the aim to enhance the accuracy of the numerical predictions regarding oil recovery from naturally-fractured tight reservoirs for efficient and cost effective operations. The porous elasticity interface is coupled with multiphase flow in porous media where the mass conservation of each phase, and an extended Darcy's equation, underpin multiphase flow characteristics. The fully coupled model takes into consideration the pore pressure and has been validated against Clashach core flooding experimental data. The developed model has been shown to significantly enhance the prediction accuracy from 9%, for one-way coupled model, to 4%, and has the ability to capture complex multiphase flow phenomena at the fracture-matrix interface. Moreover, the novel model accurately predicts the effects of geomechanical parameters on multiphase flow characteristics. It is envisaged that the novel fully coupled model developed in this study will pave the way for future scientific research in the area of geomechanical-fluid flow coupling for enhanced oil recovery in naturally-fractured tight reservoirs.

Citation

KUKHA HAWEZ, H.R. 2023. Coupled geomechanics and transient multiphase flow at fracture-matrix interface in tight reservoirs. Robert Gordon University, PhD thesis. Hosted on OpenAIR [online]. Available from: https://doi.org/10.48526/rgu-wt-1987869

• Thesis Type: Thesis
• Deposit Date: Jun 15, 2023
• Publicly Available Date: Jun 15, 2023
• DOI: https://doi.org/10.48526/rgu-wt-1987869
• Keywords: Multiphase flow; Fluid dynamics; Petroleum engineering; Oil wells; Tight reservoirs
• Public URL: https://rgu-repository.worktribe.com/output/1987869
• Award Date: Jan 31, 2023