This paper presents a novel integrated approach for numerical simulation of foam core-flood experiments in the absence and presence of oil. The experiments consisted of the co-injection of gas and Alpha-Olefin Sulfonate (AOS) surfactant solution into Bentheimer sandstone samples initially saturated with the surfactant solution [see Simjoo & Zitha (2013)]. The foam model implemented is based on a local equilibrium and describes dependency of foam mobility reduction factor using several independent functions, such as liquid saturation, foam velocity, oil saturation and capillary number. First, a series of numerical simulation was conducted to investigate the effect of surfactant concentration on pressure drop across the core for the foam flooding in the absence of oil. To this end, the dry-out and gas velocity functions in the foam model were determined from the experimental data obtained at low and high-quality regimes of foam flow at a constant injection velocity. Next, pressure drop profiles of foam flooding at two different surfactant concentrations were modelled to determine the parameters of the surfactant-dependent function in the foam model. The simulation results fit the experimental data of pressure drops very well. Then, the numerical simulations investigated the oil displacement, by foam where the main goal was to determine the foam model parameters dedicated to the oil saturation-dependent function. The pressure drop across the core, oil-cut, and oil recovery factor were modelled, and an excellent match was obtained between the pressure profile and the oil recovery obtained numerically compared with those obtained from the corresponding core-flood experiments.

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The objective of this study is to discover a synergistic effect between foam stability in bulk and micro-emulsion phase behaviour to design a high-performance chemical system for an optimized alkaline–surfactant–foam (ASF) flooding for enhanced oil recovery (EOR). The focus is on the interaction of ASF chemical agents with oil in the presence and absence of a naphthenic acid component and in situ soap generation under bulk conditions. To do so, the impact of alkalinity, salinity, interfacial tension (IFT) reduction and in situ soap generation was systematically studied by a comprehensive measurement of (1) micro-emulsion phase behaviour using a glass tube test method, (2) interfacial tension and (3) foam stability analysis. The presented alkali–surfactant (AS) formulation in this study lowered IFT between the oil and aqueous phases from nearly 30 to 10⁻¹–10⁻³ mN/m. This allows the chemical formulation to create considerably low IFT foam flooding with a higher capillary number than conventional foam for displacing trapped oil from porous media. Bulk foam stability tests demonstrated that the stability of foam diminishes in the presence of oil with large volumes of in situ soap generation. At lower surface tensions (i.e. larger in situ soap generation), the capillary suction at the plateau border is smaller, thus uneven thinning and instabilities of the film might happen, which will cause acceleration of film drainage and lamellae rupture. This observation could also be interpreted by the rapid spreading of oil droplets that have a low surface tension over the lamella. The spreading oil, by augmenting the curvature radius of the bubbles, decreases the surface elasticity and surface viscosity. Furthermore, the results obtained for foam stability in presence of oil were interpreted in terms of phenomenological theories of entering/spreading/bridging coefficients and lamella number.

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Strong foam can be generated in porous media containing oil, resulting in incremental oil recovery; however, oil recovery factor is restricted. A large fraction of oil recovered by foam flooding forms an oil-in-water emulsion, so that costly methods may need to be used to separate the oil. Moreover, strong foam could create a large pressure gradient, which may cause fractures in the reservoir. This study presents a novel chemical-foam flooding process for enhanced oil recovery (EOR) from water-flooded reservoirs. The presented method involved the use of chemically designed foam to mobilize the remaining oil after water flooding and then to displace the mobilized oil to the production well. A blend of two anionic surfactant formulations was formulated for this method: (a) IOS, for achieving ultralow interfacial tension (IFT), and (b) AOS, for generating a strong foam. Experiments were performed using Bentheimer sandstone cores, where X-ray CT images were taken during foam generation to find the stability of the advancing front of foam propagation and to map the gas saturation for both the transient and the steady-state flow regimes. Then the proposed chemical-foam strategy for incremental oil recovery was tested through the coinjection of immiscible nitrogen gas and surfactant solutions with three different formulation properties in terms of IFT reduction and foaming strength capability. The discovered optimal formulation contains a foaming agent surfactant, a low IFT surfactant, and a cosolvent, which has a high foam stability and a considerably low IFT (1.6 × 10^-2 mN/m). Coinjection resulted in higher oil recovery and much less MRF than the same process with only using a foaming agent. The oil displacement experiment revealed that coinjection of gas with a blend of surfactants, containing a cosolvent, can recover a significant amount of oil (33% OIIP) over water flooding with a larger amount of clean oil and less emulsion.

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This thesis presented an extensive study on various aspects of ASF flooding process for EOR. It provides insight into hybrid EOR processes that are of a combination of immiscible gas and chemicals injection in sandstone reservoir. We wanted to discover the mechanism of oil displacement by ASF flooding in terms of 1) formation of oil bank, 2) transport of dispersed oil, and 3) movement and pushing of oil bank and dispersed oil by foam. The main premise of this thesis is whether immiscible foam flooding as an EOR technique can be improved by ASF flooding by a combination of the mechanisms of ASP EOR and Foam EOR methods? The first part of the thesis, chapters two and three, is devoted to numerical simulation and mechanistic modelling of the Foam flooding EOR process and the ASP flooding EOR process. Knowledge obtained from these two chapters formed the basis for further study of the behavior of foam in bulk and porous media in the presence of oil. The second part, chapters four to six, is based on the systematic laboratory experimental study of ASF EOR in the bulk and in the consolidated porous media conditions, and subsequently proposing a novel chemical EOR approach. Below we will give a summary of the main findings obtained in this thesis.@en

Alkaline−surfactant−polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the suboptimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with morecomplicated geochemical conditions. @en

The efficiency of alkali-surfactant-polymer (ASP) flooding for enhanced oil recovery (EOR) can be muchless than expected under various reservoir conditions that include low permeability, high temperature,high formation brine salinity and the presence of divalent cations (Ca+2, Mg+2) in the formation brine. Thisis due to polymer degradation and low injectivity, alkali precipitation and scaling in the well and surfaceequipment. Moreover, polymers substantially reduce the capability of treatment of produced water tobe used for re-injection, upcycling or discharge.This paper reports on an experimental study of new chemical EOR approach that has the potential toovercome the above drawbacks. The new chemical formulation consists of the combination of a non-polymeric viscosity enhancement compound and a blend of two surfactants. The performance of thischemical formulation was evaluated by a series of coreflood tests on Bentheimer sandstone cores, understable gravity conditions, with the aid of X-ray Computed Tomography. A significant reduction in theresidual oil saturation was observed by constructing the capillary desaturation curves (CDC), suggestingthat the proposed formulation is potentially a good chemical EOR agent.@en

The purpose of this research is to determine an actual optimal solution through cyclic optimization of CO2-Gas Assisted Gravity Drainage (GAGD) process in a heterogeneous sandstone reservoir under geological uncertainties. We propose an integrated approach to optimize durations of gas injection, soaking, and oil production under geological uncertainties. Therefore, 100 stochastic reservoir realizations of the 3D permeability and porosity distributions were created honouring geological constraints. Ranking was applied through quantifying of reservoir oil response to select P10, P50, and, P90 that represent the overall reservoir uncertainty. More than 400 training simulation runs were created including the durations and geological uncertainty parameters through Latin Hypercube Design to build the second-order proxy model along with approximately 200 extra verification runs. The verification runs led to keep the solutions in global optima and obtain satisfactory proxy model through an iterative validation procedure. The cyclic optimization has shown its feasibility to increase oil recovery through the GAGD process from 71.5% to 75.5% with incremental cumulative oil production of 225 million barrels. The presented robust optimization workflow under geological uncertainties led to higher recovery factor than nominal realization optimization with providing degrees of freedom for the decision-maker to significantly reduce the project risk. @en

This paper presents a simple physical-based numerical model that simulates the surfactant-polymer (SP) flooding process for enhanced oil recovery (EOR). In this study, black-oil subsystems based on volume fraction balance was proposed for developing numerical model. The model was upgraded by taking into account different aspects of SP EOR process such as gravity effect, capillary pressure, mobility reduction factor, polymer/surfactant adsorption on rock and interfacial tension (IFT) reduction. The Langmuir isotherm coefficients for the adsorption of polymer and of surfactant were chosen from separately laboratory experiments of single component injection of surfactant and of polymer in the Bentheimer sandstone core. The systems of equations were solved in the Finite Elements based Method (FEM). The validity of the implementation was tested by comparing the results attained from simplified numerical model with laboratory core-flooding experimental data of SP flood into Bentheimer sandstone core. A comparison showed excellent agreement between the numerical results with the core flooding experimental results. This confirms that the developed numerical model in this work is robust and has capability to reproduce the main features of surfactant/polymer flooding (SP) EOR in the consolidated sandstone porous media. @en