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Effect of nanoparticles on phase behavior of surfactant-oil-water system: An application in multiphase flow system
Get PDFThis paper experimentally investigates how adding nanoparticles to Soloterra surfactant affects phase behavior and surfactant flooding. These experiments include three phases. In phase one, phase behavior tests are conducted on surfactant solutions to choose the compatible nanoparticle. Phase two entails measuring interfacial tension between the stable nanoparticle + surfactant solutions and hydrocarbon. In phase three, a series of micromodel flooding tests are conducted to experimentally study the possibility of enhancing oil recovery. A possible relationship between static phase behavior and dynamic fluid flow is studied to evaluate the effects of nanoparticles on surfactant solutions. The results of the phase behavior experiment show that Soloterra 964 is compatible with Al2O3 and Cu2O. Moreover, the Soloterra 964 + copper oxide solution can help observe all three Winsor types. The interfacial tension test results show that adding nanoparticles to solutions leads to lower interfacial tension. The results of micromodel flooding experiments indicate that adding surfactant and nanoparticle to the injected solution leads to higher breakthrough time and oil recovery. In addition, type III flooding produced a less stable displacement pattern than types II- and II+.Document Type: Short communicationCited as: Yarveicy, H. Effect of nanoparticles on phase behavior of surfactant-oil-water system: An application in multiphase flow system. Advances in Geo-Energy Research, 2023, 9(3): 152-155. https://doi.org/10.46690/ager.2023.09.0
Intelligent modeling with physics-informed machine learning for petroleum engineering problems
Get PDFThe advancement in big data and artificial intelligence has enabled a novel exploration mode for the study of petroleum engineering. Unlike theory-based solution methods, the data-driven intelligent approaches demonstrate superior flexibility, computational efficiency and accuracy for dealing with complex multi-scale, and multi-physics problems. However, these intelligent models often disregard physical laws in pursuit of error minimization, which leads to certain uncertainties. Therefore, physics-informed machine learning approaches have been developed based on data, guided by physics, and supported by machine learning models. This study summarizes four embedding mechanisms for introducing physical information into machine learning models, including input databased embedding, model architecture-based embedding, loss function-based embedding, and model optimization-based embedding mechanism. These “data + physics” dualdriven intelligent models not only exhibit higher prediction accuracy while adhering to physic laws, but also accelerate the convergence to improve computational efficiency. This paradigm will facilitate the guide developments in solving petroleum engineering problems toward a more comprehensive and efficient direction.Document Type: PerspectiveCited as: Xie, C., Du, S., Wang, J., Lao, J., Song, H. Intelligent modeling with physics-informed machine learning for petroleum engineering problems. Advances in Geo-Energy Research, 2023, 8(2): 71-75. https://doi.org/10.46690/ager.2023.05.0
Dynamic mechanisms of tight gas accumulation and numerical simulation methods: Narrowing the gap between theory and field application
Get PDFDespite the significant progress made in tight gas exploration and development in recent years, the understanding of the dynamic mechanisms of tight gas accumulation is still limited, and numerical simulation methods are lacking. In fact, the gap between theory and field application has become an obstacle to the development of tight gas exploration and development. This work sheds light on the dynamic mechanisms of hydrocarbon accumulation in tight formations from the aspect of capillary self-sealing theory by embedding calculation of pressure- and temperature-dependent capillary force in a pore network model. The microscale dynamic mechanisms are scaled up to the reservoir level by geological simulation, and the quantitative evaluation of reserves based on real geological sections is realized. From the results, several considerations are made to assist with resource assessment and sweet spot prediction. Firstly, the self-sealing effect of capillary in the micro-nano pore-throat system is at the core of tight sandstone gas accumulation theory; the hydrocarbon-generated expansion force is the driving force, and capillary force comprises the resistance. Furthermore, microscopic capillary force studies can be embedded into a pore network model and scaled up to a geological model using relative permeability curve and capillary force curve. Field application can be achieved by geological numerical simulations at the reservoir scale. Finally, high temperature and high pressure can reduce capillary pressure, which increases gas saturation and reserves.Document Type: Original articleCited as: Zhao, W., Jia, C., Song, Y., Li, X., Hou, L., Jiang, L. Dynamic mechanisms of tight gas accumulation and numerical simulation methods: Narrowing the gap between theory and field application. Advances in Geo-Energy Research, 2023, 8(3): 146-158. https://doi.org/10.46690/ager.2023.06.0
Experimental study and mechanism analysis of spontaneous imbibition of surfactants in tight oil sandstone
Get PDFThe process of spontaneous imbibition is the basis of oil recovery from tight oil reservoirs. In this study, spontaneous imbibition experiments were conducted based on tight oil weakly hydrophilic sandstone cores from the Honghe oilfield in the Ordos Basin. Four different types of surfactants, such as nonionic Triton X-100, nonionic Tween-80, cationic dodecyl trimethyl ammonium bromide, and anionic sodium dodecyl benzene sulfonate, were separately dissolved in 30 g/L potassium chloride solution as simulated formation water. The effects of surfactant type on spontaneous imbibition were analyzed, and the results indicated that, because the nonions are adsorbed on the surface via Van der Waals force and adsorb H+ through hydrogen bonds, the two nonionic surfactants altered the wettability of the core from weakly hydrophilic to strongly hydrophilic, the recovery rate was relatively high. The Triton X-100 was selected for subsequent spontaneous imbibition experiments by changing the mass concentration to adjust interfacial tension. It was found that the maximum recovery rate was 32% when the Triton X-100 mass concentration was 0.1%, which indicates that the enhanced recovery rate of spontaneous imbibition requires a sufficiently low wettability factor and a suitably high interfacial tension factor. Finally, the surfactants mixed with 0.03% sodium dodecylbenzene sulfonate and 0.1% Triton X-100 were used for spontaneous imbibition, attaining an oil recovery of up to 45%, which was 21.6% higher than that of single-surfactant imbibition. It was established that the synergistic mechanism depends on the wettability alteration of nonionic surfactant facilitating the spontaneous imbibition, while the anion accelerates oil removal from the core by continuously encasing oil droplets in the aqueous phase. This paper provides a theoretical basis for the imbibition development of weakly hydrophilic tight sandstone with high-salinity formation water.Document Type: Original article Cited as: Zhang, X., Ye, Q., Deng, J., Zhu, W., Tian, W., Kuang, S. Experimental study and mechanism analysis of spontaneous imbibition of surfactants in tight oil sandstone. Capillarity, 2023, 7(1): 1-12. https://doi.org/10.46690/capi.2023.04.0
Understanding gas-enhanced methane recovery in graphene nanoslits via molecular simulations
Get PDFShale gas and coalbed methane are energy sources that mainly consist of methane stored in an adsorbed state in the pores of the organic-rich rock and coal seams. In this study, the graphene nanoslit model is employed to model the nanometer slit pores in shale and coal. Grand canonical Monte Carlo and molecular dynamics modeling methods are used to investigate the mechanisms of adsorption and displacement of methane in graphene-based nanoslit pores. It is found that as the width of the slit pore increases, the adsorption amount of gas molecules increases, and the number density profile of adsorbed methane molecules alters from monolayer to multilayer adsorption. The minimum slit pore width at which methane molecules can penetrate the slit pore is determined to be 0.7 nm. Moreover, it is demonstrated that by lowering the temperature, the adsorption rate of the methane increases since the adsorption is an exothermic process. Enhancing methane recovery was investigated by the injection of gases such as CO2 and N2 to displace the adsorbed methane. The comparison of adsorption isotherms of gas molecules provides the following order in terms of the amount of adsorption, CO2 > CH4 > N2, for the same slit pore width and the same temperature and pressure conditions.Document Type: Original articleCited as: Bekeshov, D., Ashimov, S., Wang, Y., Wang, L. Understanding gas-enhanced methane recovery in graphene nanoslits via molecular simulations. Capillarity, 2023, 6(1): 1-12. https://doi.org/10.46690/capi.2023.01.0
Technology transition from traditional oil and gas reservoir simulation to the next generation energy development
Get PDFEnergy transition has been a focus in both scientific research and social concerns in the past decade, thanks to the urgent need of reducing carbon emissions, slowing down the abnormal speed of global climate and achieving a balance between environmental protection and economic development. Although the global energy sector is shifting from the fossil-based energy systems, including oil and gas, to the renewable energy resources like hydrogen, the necessity of conventional energy development has received increasing attentions with regard to the stable supply and maturely developed technologies. The long-history simulation techniques developed for oil and gas reservoir investigations have enabled the deeper explorations into reservoir properties and enhanced significantly the resource recovery. As a main direction in energy transition, the development of hydrogen energy is profoundly influencing the long-term reconstruction of the world’s energy supply and application system, and is accelerating the transition and generational evolution in the fields of transportation, power generation, chemicals, and housing. In this paper, three research directions are proposed as the potential focus of technology transition, where traditional oil and gas reservoir simulation technologies can be adjusted and improved to be used to benefit the development of hydrogen energy.Document Type: Research highlightCited as: Zhang, T., Liu, J., Sun, S. Technology transition from traditional oil and gas reservoir simulation to the next generation energy development. Advances in Geo-Energy Research, 2023, 7(1): 69-70. https://doi.org/10.46690/ager.2023.01.0
Open-source high-performance software packages for direct and inverse solving of horizontal capillary flow
Get PDFThis work introduces Fronts, a set of open-source numerical software packages for nonlinear horizontal capillary-driven flow problems in unsaturated porous media governed by the Richards equation. The software uses the Boltzmann transformation to solve such problems in semi-infinite domains. The scheme adopted by Fronts allows it to be faster and easier to use than other tools, and provide continuous functions for all involved fields. The software is capable of solving problems that appear in hydrology, but also in other particular domains of interest such as paper-based microfluidics. As the first known open-source implementation to adopt this approach, Fronts has been validated against analytical solutions as well as existing software achieving remarkable results in terms of computational costs and numerical precision, and is meant to aid the study and modeling of capillary flow. Fronts can be freely downloaded and installed, and offers a friendly environment for new users with its complete documentation and tutorial cases.Document Type: Original articleCited as: Gerlero, G. S., Berli, C. L. A., Kler, P. A. Open-source high-performance software packages for direct and inverse solving of horizontal capillary flow. Capillarity, 2023, 6(2): 31-40. https://doi.org/10.46690/capi.2023.02.0
Insights from Boltzmann transformation in solving 1D counter-current spontaneous imbibition at early and late time
Get PDFCounter-current 1D spontaneous imbibition in scaled form is investigated using Boltzmann transform before and after water meets the closed boundary (early and late time). At early time the system is self-similar and only depends on position divided by square root of time. At late time it also depends on the interaction with the no-flow boundary and hence a second variable, which is set as the square root of time. Diffusion coefficients shifted to high saturations result in early time spatial saturation profiles with shorter front distance, higher average saturation within the imbibition profile and larger imbibed amount. Strongly water-wet systems have zero oil mobility at the inlet, while mixed-wet systems have finite non-zero mobility. The imbibition rate is proportional to inlet diffusion coefficient, inlet saturation gradient (regarding position divided by square root of time) and inverse square root of time. Accordingly, the saturation gradient is infinite and finite for strongly water-wet and mixed-wet systems. At early time, the profile does not change, thus recovery is proportional to square root of time. When the front meets the no-flow boundary (critical time), the saturation profile deviates from the early time profile first at the no-flow boundary, then towards the inlet. When the inlet gradient changes, imbibition rate declines faster than inverse square root of time. The interaction at the inlet and not the closed boundary, thus determines when recovery stops being proportional to square root of time and explains why such proportionality after critical time is reported. The findings were confirmed by matching experimental data.Document Type: Original articleCited as: Andersen, P. Ø. Insights from Boltzmann transformation in solving 1D counter-current spontaneous imbibition at early and late time. Advances in Geo-Energy Research, 2023, 7(3): 164-175. https://doi.org/10.46690/ager.2023.03.0
Analysis of wettability alteration in low salinity water flooding using a zeta potential-based model
Get PDFThis study introduces a zeta potential-based model which connects low salinity water flooding oil recovery to the reservoir wettability. The model assumed that the reservoir wettability is controlled by the electrostatic forces that exist between rock-brine and oil-brine interfaces. Therefore, it links the wettability to the zeta potentials present at the corresponding interfaces. Using the model, various literature oil recovery data were simulated and then statistically compared the trend of the oil recovery factor with the trend of the wettability indicator values. The Pearson correlation coefficient was used for the statistical analysis. The results from the suggested model were compared with the outputs computed from other pre-existing models for wettability alteration. The simulation outcome indicated that a strong relationship exists between reservoir wettability and the zeta potentials produced at the rock-brine and oil-brine interfaces. The Pearson correlation coefficient calculated for the suggested model exceeded 0.7 for all the experimental cases simulated. However, most of the other pre-existing models showed weak relationships between the wettability indicator values and the oil recovery factor, with some models producing the Pearson correlation coefficient below 0.2. This study highlights the role of zeta potentials at the rock-brine and oil-brine interfaces on the wettability alteration during low salinity water flooding. The suggested model can be utilized in the decision making and implementation of low salinity water flooding works.Document Type: Original article Cited as: Boampong, L. O., Rafati, R., Haddad, A. S. Analysis of wettability alteration in low salinity water flooding using a zeta potential-based model. Capillarity, 2023, 7(2): 32-40. https://doi.org/10.46690/capi.2023.05.0
Asymptotic hydrodynamic homogenization and thermodynamic bounds for upscaling multiphase flow in porous media
Get PDFThis paper presents a novel technique for upscaling multiphase fluid flow in complex porous materials that combines asymptotic homogenization approach with hydrodynamicand thermodynamic bounds. Computational asymptotic homogenization has been widely utilised in solid mechanics as a method for analysing multiscale expansion and convergence coefficients in heterogeneous systems. Computations are performed over several volumes by increasing the size until convergence of the material parameters under different load scenarios is achieved. It works by simplifying the problem with a homogenization method and is ideally suited for estimating the representative elementary volume of microporous material by expanding algorithms. The validity of the method to include complex multiphase hydrodynamic processes and their interaction with the matrix structure of porous media lacks a sound theoretical foundation. To overcome this problem, a variational thermodynamic approach is used. Upper and lower bounds of entropy production are proposed to provide effective material properties with uncertainties. This allows multiple possibilities to address dynamics via thermodynamically linked processes. This work utilizes volume of fluid approach to model multiphase porous media flow in models based on micro-computerized tomography x-ray data of Bentheimer sandstone and Savonnieres carbonate. It is found that the representative elementary volume sizes obtained by the conventional asymptotic homogenization methods do not satisfy thermodynamic bounds which consistently require larger representative elementary volume sizes. For the Savonnieres carbonate the entropic bounds have not converged fully questioning the reliability of the effective properties obtained from the classical method.Document Type: Original articleCited as: Hussain, S. T., Regenauer-Lieb, K., Zhuravljov, A., Hussain, F., Rahman, S. S. Asymptotic hydrodynamic homogenization and thermodynamic bounds for upscaling multiphase flow in porous media. Advances in Geo-Energy Research, 2023, 9(1): 38-53. https://doi.org/10.46690/ager.2023.07.0