New Approach to Simulating Multicomponent Fluids Flow to Hydraulic Fractured Well

Abstract

High accurate reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gas-condensate field. In recent years, numerous research efforts were focused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for the whole reservoir with grid refining in fracture domain and couldn't completely account all phenomenon within reasonable computational time. New approach for simulation of multiphase multicomponent steady state flow around the hydraulic fractured well is proposed. The approach is based on the splitting the thermodynamic and hydrodynamic problems of multiphase and multicomponent fluids flow. It is also assumed that conductive fracture could be described by 2D surface in 3D permeable formation. Additional coordinate system inside fracture allows to simulate the heterogeneous internal structure of fracture and account the details of the exchange process between fracture and reservoir. Relative permeability and non-Darcy effects in fracture and formation and non-uniform fracture conductivity could be taken account as well. Proposed model can be used for simulation of the steady-state multiphase multicomponent flow to hydraulic fracture of any arbitrary shape. Excellent agreement with commercial dynamic simulators was achieved for gas condensate flows simulation. Significant decrease in computational time in comparison with the existent simulators had been achieved. Introduction Hydraulic fracturing has been proven to be one of the most effective methods for improvement of well deliverability in gas condensate formation. Carlson and Maer1 and Settari et. al2 showed that loss in well productivity due to condensation can be lessened by fracturing the well. Additional advantage of hydraulic fracturing in gas condensate reservoir is reduction of the pressure drawdown that leads to less liquid drop-out. The pressure and flow rate behavior of gas condensate is extremely different from the behavior of a two-phase gas or oil reservoir. A number of published papers have documented the peculiarities of gas condensate mixtures inflow to well: condensate bank accumulation because of condensate drop-out, stripping and non-Darcy effects and etc which can't be described on the basis of so called "black oil" technique. So the multicomponent multiphase fluid model is necessary to predict the performance of hydraulically fractured well in gas condensate formations. The different approaches are being used for gas condensate flow to fractured wells. The most popular of them is based on the multicomponent flow simulation that is done using single computational grid for the reservoir and the fracture. For detailed description of the flow within fracture computational grid is refined around and within fracture using some special techniques for proper grid construction. Such approach was used in papers2,3–6 and allowed to account of various phenomenon taking place under gas condensate flow in vicinity of the hydraulically fractured well. Nevertheless this approach has some certain disadvantages and first of all: large amount of the grid cells and excessive requirements to the computational resources as sequence, difficulties with grid generation around fracture (especially for complex shape fracture), problems with account of vertical heterogeneity of fracture and others. The other approach is to build simplified model of gas condensate inflow to fractured wells. For example the linear model was developed to study of condensate damage at the face of hydraulic fracture by R.R. Ravari et al 7–8. This model was analogous to linear flow toward an infinite conductivity fracture propagating to entire extent of rectangular section of reservoir. Wang et al9 and Indriati10 presented an optimization method for fractures in gas condensate reservoirs, taking into account the relative permeability-to-gas reduction, using an analogy to fracture face damage as presented by Cinco-Ley and co-workers11. The main disadvantage of such models is they can be used only for rough estimation of fractured well productivity in gas condensate formations.

Towards Multiscale Digital Rocks: Application of a Sub-Resolution Production Model to a multiscale Sandstone

“…For these high clay content sandstones, with half of the pore space below the microCT image resolution, the current workflow predicts porosities within 5%, absolute permeability within 10% and relative permeability 𝐾 curves consistent with existing lab results. The current workflow demonstrate that is possible to use simplified models to extend the scope of application of digital rock technology to some challenging rock types, like high clay content sandstones, without having to explicitly simulate fluids movement in the unresolved pore regions using other multiscale multiphase flow methods such as [26][27][28][29][30]. In cases where the main percolating path is capture, but still a significant pore space fraction is unresolved, the method proposed in this paper could be computationally less expensive than full multiscale multiphase fluid flow methods [26][27][28][29][30].…”

“…In this case it is impossible to cover all pore scales in one digital rock analysis. There are several studies on the effect of unresolved pores and how to predict petrophysical properties, such as porosity, capillary pressure, absolute and relative permeabilities [6][7][8][9][10][26][27][28][29][30] but none, to our knowledge, on how to predict relative permeability curves by using multiphase fluid flow from direct numerical simulation in high clay content sandstones, such as the case just described, leading to a model with significant amount of unresolved porosity. This work investigate this case, a high clay content sandstone, by using an extension of current numerical digital rock workflows [11] to simulate fluid flow in rocks where a connected pore-space is resolved and unresolved pores do not provide a significant contribution to single phase flow, however for multiphase flow can provide critical connectivity paths for the wetting phase and impact the overall behavior of 𝑘 and 𝑃 curves.…”