The need to minimize surfactant adsorption on rock surfaces has been a challenge for surfactant-based, chemicalenhanced oil recovery (cEOR) techniques. Modeling of adsorption experimental data is very useful in estimating the extent of adsorption and, hence, optimizing the process. This paper presents a mini-review of surfactant adsorption isotherms, focusing on theories of adsorption and the most frequently used adsorption isotherm models. Two-step and four-region adsorption theories are well-known, with the former representing adsorption in two steps, while the latter distinguishes four regions in the adsorption isotherm. Langmuir and Freundlich are two-parameter adsorption isotherms that are widely used in cEOR studies. The Langmuir isotherm is applied to monolayer adsorption on homogeneous sites, whereas the Freundlich isotherm suites are applied to multilayer adsorption on heterogeneous sites. Some more complex adsorption isotherms are also discussed in this paper, such as Redlich− Peterson and Sips isotherms, both involve three parameters. This paper will help select and apply a suitable adsorption isotherm to experimental data.

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Empirical equations for estimating viscosity: above, at, and below the bubble point pressure were developed based on data from Saudi Arabian crude oils. Both statistical and graphical techniques have been employed to evaluate these equations as compared to other published crude oil viscosity correlations using the same data. It is shown that the developed correlations provide more accurate estimates of viscosity in all three regimes of pressure. Introduction Viscosity is the measure of resistance to fluid flow. Knowledge of viscosity is required in reservoir simulation, fluid flow through porous media and pipelines, well testing, and design of production pipelines, well testing, and design of production equipment. Crude oil viscosity can be classified into three regimes. Bubble Point Oil Viscosity It is the viscosity of crude oil at the bubble point pressure and a given temperature. point pressure and a given temperature. Oil Viscosity Above the Bubble Point It is defined as the crude oil viscosity at a pressure higher than the bubble point pressure and a pressure higher than the bubble point pressure and a given temperature. Oil Viscosity Below the Bubble Point It is the viscosity of crude oil below the bubble point pressure and a given temperature. With the point pressure and a given temperature. With the lowering of pressure below the bubble point pressure, gas is released leaving behind a saturated oil at the new pressure. When the pressure is lowered to atmospheric pressure, there is no dissolved gas left in the oil and such oil is called dead oil whose viscosity is referred to as the dead oil viscosity. In many cases, the only information available from PVT analysis of an oil sample are simple and readily PVT analysis of an oil sample are simple and readily measurable parameters such as gas relative density, oil API gravity, and gas-oil ratio. Direct viscosity measurements or complete compositional analyses of crude oils are expensive, therefore, empirical correlations, which are functions of these readily measurable PVT properties, are used to estimate oil viscosity. A number of different viscosity correlations have been presented in the literature, as shown in Table 1, and reviewed in detail by Khan. Most of these correlations were based on limited data from different geographical locations which introduced large potential errors. Moreover, these correlations involve complex mathematical expressions which do not explain the behavior of oil viscosity very clearly. In this study, an alternative approach to viscosity correlation development, along with new viscosity equations have been derived. In this approach, emphasis is placed on the natural variation of viscosity with PVT parameters. In this paper, the new correlations and four of the published correlations, namely those of Beal, Chew and Connally, Beggs and Robinson, and Vazquez, will be evaluated using Saudi Arabian crude oil viscosity data which was used to develop the new correlations. VISCOSITY DATA This study utilized viscosity data for 75 bottom hole samples taken from 62 Saudi Arabian oil reservoirs. P. 251

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The need to reduce surfactant adsorption on rock surfaces has been a difficult task in chemical enhanced oil recovery, as it directly impacts the economics of the project. This requires a comprehensive insight into the adsorption mechanism on rocks. The adsorption mechanism of an in-house cationic gemini surfactant on different rocks has been studied in this work. The novel surfactant is compatible with high temperature and high salinity environments. All experiments were conducted at room temperature and in deionized water. Adsorption in sandstone rocks was found to be significantly higher than that in carbonates because of the high density of negative charges. The differences in the quantity of the adsorbed surfactant can be explained by different layer structures. It is proposed that an interdigitated bilayer is formed on carbonate rocks, whereas a noninterdigitated bilayer is formed in sandstone rock samples. The maximum and minimum adsorption values were found to be around 9 and 1 mg/g-rock in sandstone and carbonates, respectively. Scanning electron microscopy showed that the surface of sandstone rocks was rougher after the adsorption of the gemini surfactant, whereas no substantial variation in the morphology of carbonates was found. Similarly, Fourier transform infrared spectroscopy showed the symmetric and asymmetric vibration of the CH2 groups in the post-adsorption analysis of sandstone but not in carbonates. Adsorption isotherm modeling was also conducted to investigate the adsorption mechanism of the gemini surfactant on different rocks. All rocks follow a Hill isotherm, showing that the adsorption process is cooperative. However, better curve fitting was obtained using a Redlich–Peterson isotherm in sandstone, whereas both the Langmuir and Redlich–Peterson isotherm performed better for carbonates. The experimental results confirm the formation of interdigitated and noninterdigitated bilayer of the employed surfactant, which explains its adsorption behavior in different rocks and how this adsorption follows different adsorption models in different rocks.

Chemical reactions believed to cause fuel formation for in-situ combustion have been studied and modeled. A thin, packed bed of sand/oil mixture is heated under nitrogen flow at linearly increasing temperatures, simulating the approach of a combustion front. Analysis of gases produced from the reaction cell revealed that pyrolysis of crude oil in porous media goes through three overlapping stages: distillation, mild cracking (visbreaking), and severe cracking (coking). Expressions that govern the rates of the two cracking reactions are derived, and a technique is outlined to obtain initial estimates for their parameters from the experimental data. The parameters of a proposed distillation function, as well as refined estimates for the cracking reaction parameters, are obtained by non-linear regression methods based on an overall kinetic model.Successful matching of the experimental data, including the total amount of fuel deposited, was achieved with this model. It was found that fuel formation was a result of two successive cracking reactions that the oil undergoes at temperatures above 280°C [536°P]. Also, distillation of crude oil at temperatures below 280°C [536°F] played an important role in shaping the nature and extent of the cracking reactions. The operating pressure and the rate of heating of the sand/oil sample were found to affect the fuel-formation process only through the influence exerted on distillation. Clay minerals showed a catalytic effect on the cracking reactions, especially coking. Finally, the asphaltene fraction of a crude oil was found to correlate with the fuel content of that oil.

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