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Foam generation and transport in porous media are a proven method to improve the sweep efficiency of a flooding fluid in enhanced oil recovery process and increase the effectiveness of a treatment fluid in well intervention procedures. Foam in the porous media is often generated using surfactant alternating gas or co-injection. Although these opera...
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... Foam systems consist of gas as the dispersed phase, exhibiting high apparent viscosity and adjustable density. Foam can selectively plug high-permeability zones and control the redirection of subsequent fluids from high-permeability to low-permeability areas to expand the swept volume [15][16][17]. It is highly applicable to fractured-vuggy reservoirs with strong heterogeneity. ...
Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.
... The destabilization of foam is related to coalescence, Ostwald ripen, and drainage of liquid film. At the same time, foam, as a continuous fluid with low density and high viscosity, can effectively reduce the mobility of CO 2 or other fluids and increase the sweep efficiency [26][27][28]. Two field tests were carried out with foam-assisted CO 2 flooding in an ultralow permeability reservoir with natural fractures in Cupiagua Oilfield, Colombia. ...
In this work, a visual two-dimensional (2D) heterogeneous fracture network model was designed to investigate CO2 foam generation, propagation and sweep with two different injection strategies (co-injection, COI; and surfactant solution alternating gas, SAG). In addition, gravitational effect was explored by this fracture model. In the case of the optimum foam quality (fg = 0.67), the results indicated the COI could form stable foam morphologies and differential pressures (ΔP), while the foam morphologies and ΔP showed a dynamic trend during each cycle of SAG. The ΔP of larger slug injection can establish 6–12 times than smaller slug injection in the fractured system. Because of CO2 breakthrough, the total sweep efficiency of continuous gas injection (CGI, 42%) and SAG (66%) were lower than COI (81%). Gravitational effect is insignificant during COI, whereas gravity has a considerable effect on SAG in terms of ΔP and sweep efficiency. As a result of gravitational effect, the entire ΔP curve decreased and required more fracture volume (FV) injected to achieve the final sweep efficiency during SAG. The results of this study provide preliminary observations that can provide new insights into mobility control by using CO2 foam in fractured tight reservoirs.
... Numerical simulations of coupled multiphasemulticomponent flow in porous media, using continuum mechanics approach [1], have been extensively applied in various fields including, hydrology [2,3], soil remediation [4,5], CO 2 storage [6], oil and gas, composite materials manufacturing [7,8]. One important application is enhanced oil recovery (EOR) in which various multicomponent phenomena arise, e.g., foam transport and generation [9,10], chemical flooding [11,12], in-situ upgrading [13], and asphaltene precipitation [14,15], flocculation, and remediation [16,17]. Due to this high number of applications, and the continuous development of new techniques for EOR based on chemical and thermal processes, robust and flexible numerical simulation frameworks are required to evaluate and optimize the field deployment of such technologies. ...
Subsurface multiphase flow in porous media simulation is extensively used in many disciplines. Large meshes with non-orthogonalities (e.g., corner point geometries) and full tensor highly anisotropy ratios are usually required for subsurface flow applications. Nonetheless, simulations using two-point flux approximations (TPFA) fail to accurately calculate fluxes in these types of meshes. Several simulators account for non-orthogonal meshes, but their discretization method is usually non-conservative. In this work, we propose a semi-implicit procedure for general compositional flow simulation in highly anisotropic porous media as an extension of TPFA. This procedure accounts for non-orthogonalities by adding corrections to residual in the Newton-Raphson method. Our semi-implicit formulation poses the guideline for FlowTraM (Flow and Transport Modeller ) implementation for research and industry subsurface purposes. We validated FlowTraM with a non-orthogonal variation of the Third SPE Comparative Solution Project case. Our model is used to successfully simulating a real Colombian oil field.
... (1) and (3) discretized with FVM are solved applying Newton-Raphson method and under the fully implicit procedure consideration. Codification of the deterministic solution under the mentioned conditions can be found in the literature (Valencia et al. 2018). ...
We developed a model for simulating scalar transport and non-equilibrium interfacial mass transfer in porous media based on a hybrid probabilistic/deterministic approach. The probabilistic model formulation accounts for different mass transfer mechanisms, such as interfacial mass transfer and attachment/detachment phenomena, occurring under equilibrium or non-equilibrium conditions. Mass transport equations are solved using both finite volume method (FVM) and stochastic particle method (SPM). Specifically, the SPM allows to solve the probabilistic component of the hybrid method. The impact of the number of particles and the mesh size cell for computing the ensemble average is analyzed in this work. The core flooding setup of an inert tracer is initially simulated and compared to experimental data reported in the literature displaying a good agreement. Values of root mean square less than 0.088 were obtained for all the cases studied. Besides, the non-equilibrium mass transfer capabilities of the model are appraised by simulating the injection of a nanoparticle dispersion in the core and comparing the simulation results with reported experimental data. The probabilistic model shows advantages with respect to the deterministic description at localization of “sharp” profile or high gradients and reduction in complexity of the transport equation described by SPM, allowing to obtain additional information such as the standard deviation of the field scalar variables of the transport process, which is directly related to equilibrium/non-equilibrium state of the system.
Article Highlights
The stochastic particle model is extended to consider compressible particles, making the description of the phases more realistic.
The model is applied to the description of nanoparticle transport considering additional phenomena.
This method allows one to describe the deterministic transport model in a simpler way.
... Typical injection strategies of foam in laboratory studies, as well as field applications, are simultaneously injecting gas and surfactant solution (known as co-injection) [22][23][24], or alternately injecting slugs of surfactant solution and gas (known as SAG) [25][26][27][28]. A relative new concept of dissolving surfactants directly into the CO 2 phase (by dissolution) has also been suggested and used, which can help to secure the utilization of foaming agent and the placement of foam to the target CO 2 flow paths intended to block [29,30]. With all the above three injection/generation strategies, foam is formed in the reservoir by in-situ generation mechanisms [16,20,31,32]. ...
The high mobility of CO2 in porous media is an issue in most subsurface CO2 projects worldwide, demonstrated by uncontrolled and rapid migration through the reservoir, early well breakthroughs and poor sweep efficiency. Improved mobility control of CO2 is needed to accelerate and improve the value-creation from subsurface CO2 projects, both in terms of energy produced and volumes of CO2 stored. Field-proven conformance and mobility control techniques, such as foam, provide a cost-effective and sustainable alternative to overcome geological and process constraints observed with CO2 flow in reservoirs.
In this laboratory study, we have investigated CO2 mobility control by foam in sandstone core samples at typical North Sea reservoir conditions, 220 barg and 100°C, respectively. Two important aspects related to any field application of foam have been evaluated and discussed: I) Can strong CO2-foams be generated at reservoir conditions using AOS surfactant? If not, II) can relatively simple modifications to the foam system be made to improve foam properties and CO2 mobility control?
Our results show that only high-mobility CO2-foams with low degree of CO2 mobility reduction are obtained at 220 barg and 100°C. An easy way to improve the foam properties at reservoir conditions is suggested by changing the gas-phase in foam to nitrogen (N2). The N2-foams display improved foam generation performance, larger mobility control in terms of mobility reduction factors (MRF) and ability to block subsequent CO2 injection.
An alternative strategy for applying foam for CO2 conformance and mobility control in subsurface CO2 projects, which emerges from this study, is to initiate the foam treatment with nitrogen followed by subsequent CO2 injection to change the main direction of CO2 flow to enhance the displacement area or reduce uncontrolled CO2 production between the injecting and producing wells (as illustrated in the graphical abstract). The possible mechanisms explaining the observed differences in foam properties using CO2 versus N2, including implications that could be helpful for future studies and CO2 field applications are discussed further in more detail.
The efficiency and limitations of miscible CO2 flooding to recover oil and simultaneously store CO2 after extensive water flooding are also demonstrated in this article, which are relevant to enhanced oil recovery (EOR) and subsequent CO2 storage applications, known as the Carbon Capture Utilization and Storage (CCUS).
... A continuación se mencionan los autores que presentan modelos matemáticos en elárea de la simulación de procesos de recobro mejorado e ilustran el dominio de aplicación con diversas representaciones. Valencia (2016) y Valencia et al. (2018) desarrollan un modelo de simulación para la generación de espumas in situ inyectando químicos dispersos en gas, describiendo los fenómenos físicos y mecanismos, de los fluidos y del químico inyectado, que se presentan en el yacimiento. Adicionalmente, presentan las ecuaciones de su modelo matemático y un diagrama de flujo del proceso de solución de las mismas. ...
... Enfoques Modelos matemáticos Trazabilidad de conceptos Trazabilidad del proceso Representación de eventos Valencia (2016) x Valencia et al. (2018) x Mozo (2017) x x Isaza (2017) x x Solano et al. (2019) x x Zaza et al. (2016) x x Wang et al. ( , 2017 x Fang et al. (2017) x x Qiao et al. (2017) x Flemisch et al. (2011) x x Cao (2002) x x x DeBaun et al. (2005) x x x Mohammad et al. (2017) x Wang et al. (2015) x Zhang et al. (2007) x x x x Hu et al. (2013) x Zaydullin et al. (2014) x ...
Enhanced oil recovery (EOR) processes simulation is governed by mass conservation laws. In such laws, flow, accumulation, sources and sinks phenomena in porous media are described. Multiple proposals for framework and simulation elaboration have been defined. However, they lack concepts and processes tracing and event representation for physical phenomena. Preconceptual Schemas (PS) are used for including the complete structure of an application domain and representing processes emerging in such a domain. Cohesion, consistency, and tracing between concepts and processes is obtained by using PS. In this MSc. Thesis an executable model for enhanced oil recovery processes simulation based on preconceptual schemas is proposed. The executable model is validated by running a study case. The results are in accordance with data reported in the literature. The proposed executable model allows for tracing consistently the concepts, processes, and events, which are present in EOR processes simulation.
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https://repositorio.unal.edu.co/handle/unal/75603
... The advantages of injecting dispersed chemicals in the gas injection wells have been observed in pilot studies, initially for condensate mobilization and asphaltene control (Restrepo et al., 2012(Restrepo et al., , 2014, and more recently for in-situ foams Valencia et al.,2018a;2018b) and chemicals for EOR applications (Valencia et al., 2018c). An engineered nozzle is placed to atomize the chemicals into the gas injection line. ...
This paper address the numerical simulation of the chemically enhanced gas injection technology (ChEGasEOR) at core and reservoir scales. In this technique, a liquid chemical solution, having engineered
properties, is sprayed along with the gas stream. The mist travels through the wellbore and further introduced in the reservoir. Previous lab tests, pilot studies in light & intermediate oil reservoirs indicate that the application of CheGas-EOR allows for a reduction in operational costs, increases the chemical penetration radii and decreases the retention rate in the rock. However, the associated uncertainty is still too high to develop this process on a productive scale. In this work we use a developed phenomenological model to build a tool that assist in design and evaluation of Chemical Gas EOR operations aiming to reduce the uncertainties and optimize oil recovery. We developed a mathematical model, based on the most important transport and surface phenomena.
Non-equilibrium mass transfer between phases during the interception of the chemical solution droplets with the liquid phases. Active chemical concentration in miscible liquid phases is much lower than liquidbased chemical injection opperations. As a consequence, dissolution and adsorption rate of active chemicals
with reservoir rocks are slow. The model is base on the extended black-oil model formulation coupled to local mass balance equations of active chemicals. Non-equilibrium mass transfer processes are represented with interception, dissolution and a first order kinetic sorption models.
The model was adjusted and then validated using experimental data from core-.flooding tests. Good agreement of the simulations results with experimental observations were obtained. The model can predict
the relevant behavior of the disperse chemical injection in the gas phase in porous media. Also, well
injections simulations at reservoir scale using the matched parameters from laboratory, reproduced pilot field results. Simulation experiments predict that the CheGasEOR process can increased substantially the oil recovery factor. For the first time, a model for disperse chemical injection for EOR applications is developed and validated at core and reservoir scale. The simulation model allows the evaluation of this technology at different scales. Therefore, it is possible to use it to optimize operating conditions and perform sensitivity analysis for field applications.
... Existen varias técnicas para la generación de espumas en el medio poroso para fines de recobro mejorado [12,27,28,29,30]. Una de estas técnicas es la inyección de espumante disperso en gas, la cual ha sido previamente estudiada e implementada por la empresa colombiana Equion Energia Limited y la Universidad Nacional de Colombia [30,31,32,33]. Diversas pruebas llevadas a cabo a nivel de laboratorio, así como los pilotos desarrollados a escala de campo, han demostrado la efectividad de esta técnica en la generación de espumas in-situ [32,3]. ...
... Por otro lado, la presión capilar en las fracturas se puede considerar nula puesto que tienen una apertura que es superior a los diámetros típicos de garganta del medio poroso [13]. [33,52,53,34,54]. ...
... La inyección de químicos bajo esta técnica se realiza a partir de la dispersión de una solución líquida en la corriente de gas que ingresa al yacimiento. Para este fin, se utiliza un equipo esquematizado en la Figura 2-6, el cual consta de una boquilla que añade el químico en forma de gotas a corriente gaseosa para formar una niebla [32,33]. De acuerdo con Valencia [31], cuando la corriente gaseosa ingresa al yacimiento, se presentan varias de dinámicas de transferencia entre fases que permiten que el químico cumpla su función dentro del medio poroso. ...
A model for numerical reservoir simulation is developed in this Master's Thesis. This model represents the dynamics associated with foaming by dispersed-in-gas foamer injection in Naturally Fractured Reservoirs, based on a multidomain scheme. This proposal was developed under a phenomenological approach which is based on phenomena characterization. After that, its numerical solution was implemented by adaptation of DFTmp Simulator, which is capable of predicting well and reservoir variables after the application of dispersed foamer injection in Naturally Fractured Reservoirs. This model is validated using laboratory test data carried out on the core level, and simulations on the field-scale are proposed, in order to study the effect of model parameters in the reservoir behavior.
While high working pressure and complex procedure restrict application of conventional foam fracturing, in-situ foam can overcome the limitations because it is liquid while pumping, reducing flow friction and dosage of special equipment. It gradually foams in the formation with large amount of heat released and pressure increased, improving flowback performance. Thus, this study developed an in-situ foam fracturing fluid stabilized by a novel microbial polysaccharide called diutan gum, evaluated its performance, and investigated its proppant suspension mechanism at high temperature.
First, based on the foam comprehensive value, the polysaccharide stabilizer and foaming agent systems of N2 foam and CO2 foam were selected separately. Second, the self-generated N2 systems and self-generated CO2 systems were screened in terms of gas production efficiency and rate. Third, on the premise of meeting compatibility, the selected foam systems and self-generated gas systems were combined, and necessary additives were introduced to prepare in-situ N2 and in-situ CO2 foam fracturing fluid systems, respectively. The stability and foaming ability of in-situ foams were evaluated at high temperature, and the optimal ones were selected. Then, the proppant suspension performance, heat and shear resistance, and viscoelasticity of the optimal ones were evaluated at high temperature, and this study tailored a method for evaluating proppant suspension performance of the in-situ foam fracturing fluid due to its difference from the conventional ones. Finally, based on experimental data and rules, the proppant suspension mechanism of in-situ foam fracturing fluid at high temperature was revealed.
The combination of diutan gum and AOS exhibited outstanding ability in enhancing the foam comprehensive value of both N2 and CO2 foam, and two kinds of CO2 foam and N2 foam systems with higher comprehensive values were selected respectively. The self-generated nitrogen and carbon dioxide systems with the highest gas production rate and efficiency were respectively selected, with the highest gas production efficiency reaching 95.9%. Thanks to these two excellent components, the in-situ N2foam volume reached 518mL which was 26 times of the base fluid of 20mL and remained 480mL within 90 minutes even at 70°C, demonstrating excellent foaming ability and foam stability. However, the stability of the in-situ CO2 foam was poor, as the foam volume dropped from 515mL to 250mL in just about 13 minutes. The in-situ N2 foam fracturing fluid obtained remarkable proppant suspension performance that with only 20mL of base fluid, it fully suspended 25mL of 70/140 mesh ceramic proppant for up to 120min, achieving proppant volume fraction as high as 55.6%. The in-situ CO2 foam could not even suspend 5mL of proppant, so it was eliminated and the in-situ N2 foam fracturing fluid was determined as the optimal system whose rheological properties was also extraordinary. After continuous shear for 2h at 70° and 170s−1, it maintained a viscosity of 59.4mPa·s, and it exhibited brilliant elasticity that its storage modulus was always greater than the loss modulus, ensuring its excellent proppant suspension performance. Ultimately, its proppant suspension mechanism was revealed in four stages.
The results suggest that the in-situ foam fracturing fluid stabilized by diutan gum obtains promising applications and is supposed to be further studied.
