Browsing by Author "Bashtani, Farzad"

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    Random Network Modeling of Tight Formations
    (2016) Bashtani, Farzad; Kantzas, Apostolos; Maini, Brij; Clarkson, Chris; Dong, Mingzhe; Lines, Laurence
    The objective if this study is investigating the capability of random network modeling techniques to predict fluid flow behaviour in unconventional formations. 3D random networks are constructed in order to represent Berea sandstone, synthetic oil-sand, and the Mesaverde formation located in north Wyoming, United States. The modified network modeling software solves the fundamental equations of single-phase and two-phase immiscible flow incorporating wettability and contact angle assuming a quasi-static displacement mechanism. Macroscopic properties network such as porosity, absolute permeability, and formation factor are calculated and compared to experimental data. The model is modified in order to implement the wetting phase trapping during the primary drainage process. A new methodology for reconstruction of digital porous media using experimental MICP data is introduced. Subsequently, immiscible two phase flow properties such as capillary pressure, relative permeability, and resistivity curves are predicted and compared to available experimental data.
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    Scale Up of Pore Level Flow Properties; Application in Wellbore Modelling Containing Inflow Control Devices
    (2021-08-31) Bashtani, Farzad; Kantzas, Apostolos; Clarkson, Christopher; Maini, Brij; Tutolo, Benjamin Michael; Gostick, Jeffrey
    Prediction of reservoir production using different technical scenarios and designs is essential for optimization of a reservoir development plan. Due to the scale of a reservoir, simulators use simplified discretized equations to predict the production and other properties of the reservoir. Therefore, they cannot observe complicated physical phenomena that occur at the pore scale. Such phenomena have a significant effect on the relative permeability of the fluids which is an important factor for predicting multiphase flow behavior at the reservoir scale. Commercial reservoir simulator software use correlations to calculate relative permeability of the fluids. Even though such method is proven practical for conventional reservoirs, it is not accurate for unconventional and tight reservoirs if not calibrated and matched using SCAL data and can lead to erroneous predictions. The objective of this research is to calculate the single-phase and immiscible two-phase flow properties including porosity, permeability, capillary pressure, and relative permeability using random-network modelling technique at the pore scale and then scale up the results to macro scale, and core scale using analytical and numerical methods available in the literature and develop new scale up methods when the current methods prove to be inaccurate. The scaled-up flow properties are then used to construct a comprehensive near well bore model with complex well completion setups which contain tubing-deployed and liner-deployed flow control devices (FCDs). The effect of various completion designs such as open-hole, single and parallel tubing, liner-deployed FCD, and retrofitted tubing-deployed FCD setups in conjunction with the scaled-up flow properties obtained from pore level modelling is incorporated in a comprehensive software package. The application of the coupled scaled-up micro-scale simulation and near well bore modelling is illustrated in two aspects: Control of gas coning in horizontal wells with tubing deployed FCDs and application of PNM in simulation of black oil reservoirs. Control of gas coning in horizontal wells using tubing deployed FCDs is studied and the scaled-up relative permeability curves were incorporated during simulation. In this study, a new formulation is also developed to capture the phase-change normal to the well. In this model a modified version of boundary-element-method (BEM) is implemented, and the pressure is used as a tracer and all the properties such as saturation and mobility variation are calculated normal to the well bore. This is a new semi-analytical method where all the integration terms are calculated numerically. Application of PNM and its corresponding scaled-up results in near well bore simulation is also studied. We explain the variability of pore structure on its relative-permeability and capillary pressure curves, and for a similar formation and identical permeability how other factors can vary the characteristic curves. By using a boundary-element-method we also incorporate such variations into well/reservoir interaction. As a result of such modelling one may evaluate the performance of the well on different gas cresting/coning scenarios. The results show that such variability in the pore network has less than 10% on production gas rates, but its effect on oil production can be extensive. The results of such work show the importance of PNM in well completion design and probabilistic analysis of the performance and can be extended on different factors of the reservoir in the future works.