Visbreaking of Heavy Oil under Supercritical Water Environment

Dissolution Behavior of Polycyclic Aromatic Hydrocarbons in Heavy Oil in the Presence of Supercritical Cyclohexane

Supercritical cyclohexane (SC-cyclohexane) shows significant advantages in mild operating conditions and the modulation of product distribution. To gain insights into the upgrading process of heavy oil in SC-cyclohexane, the dissolution process of polycyclic aromatic hydrocarbons (PAHs) contained in heavy oil was simulated based on molecular dynamics with the use of naphthalene, benzopyrene, and mixtures of naphthalene and benzopyrene as the model compounds. As indicated by the radial distribution function results, in SC-cyclohexane exhibiting low density, cyclohexane formed a solvent shell around PAHs such that the local concentration was reduced and the aggregation of PAHs was inhibited. The results of the solvation free energy suggested that van der Waals forces between PAHs and cyclohexane were mainly dominant. As revealed by the dissolution process of the model compounds in SC-cyclohexane, a low density and a suitable temperature contributed to the solubilization of PAHs. An appropriate temperature and a low density can be selected for the upgrading reaction to limit coke formation.

Study on Hydrothermal Cracking of Heavy Oil under the Coexisting Conditions of Supercritical Water and Non-condensate Gas

This study looked at the effects of temperature, water-oil ratio, and the addition of non-condensable gas on the thermal cracking of extra-heavy oil in the lab. The goal was to learn more about the properties and reaction rates of deep extra-heavy oil under supercritical water conditions, which are not well understood. The changes in the composition of the extra-heavy oil were analyzed with and without the presence of non-condensable gas. The reaction kinetics of the thermal cracking of extra-heavy oil were quantitatively characterized and compared between the two conditions of supercritical water alone and supercritical water mixed with non-condensable gas. The results showed that (1) under supercritical water conditions, the extra-heavy oil underwent significant thermal cracking, which led to a significant increase in the amount of light components, the release of CH₄, and the formation of a new component, coke, which led to a noticeable decrease in the viscosity of the oil; (2) increasing the water-oil ratio could promote the thermal cracking of extra-heavy oil and led to a significant decrease in oil viscosity, indicating a more complete thermal cracking reaction. Moreover, increasing the water-oil ratio was found to facilitate the flowability of the cracked oil; (3) the addition of non-condensable gas intensified the conversion of coke but inhibited and slowed down the thermal cracking of asphaltene, which is detrimental to the thermal cracking of extra-heavy oil; and (4) the kinetic analysis showed that the addition of non-condensable gas resulted in a decrease in the thermal cracking rate of asphaltene, which is detrimental to the thermal cracking of heavy oil.

Oily sludge treatment in subcritical and supercritical water: A review

Oily sludge, an inherent byproduct of the petroleum industry, presents dual characteristics of petroleum resources and hazardous waste. Owing to the unique physicochemical properties of sub-/supercritical water, hydrothermal technologies have been increasingly used for oily sludge treatment. This review is the first to focus on oily sludge treatment using sub-/supercritical water. Eight hydrothermal technologies used for different purposes are summarized herein: pressurized hot water extraction (PHWE) for hydrocarbon separation, thermal hydrolysis (TH) for dewaterability improvement, hydrothermal carbonization (HTC) for hydrochar production, wet air oxidation (WAO) for biodegradability improvement, hydrothermal liquefaction (HTL) for bio-oil production, supercritical water upgrading (SCWU) for light oil production, supercritical water oxidation (SCWO) for complete degradation, and supercritical water gasification (SCWG) for H₂-rich syngas production. Moreover, a general reaction pathway for sub-/supercritical water treatment of oily sludge is presented, with a particular focus on the chemical mechanism at temperatures above 350 °C. Lastly, two reaction maps are included to illustrate the reaction pathways of two groups of identifiable model compounds in oily sludge: aliphatic and aromatic hydrocarbons. This review provides detailed information that can promote a better understanding of various hydrothermal technologies, a guideline for selecting the suitable hydrothermal process for a particular oily sludge, and recommendations for further researches.

The Visbreaking of Heavy Oil in Supercritical Cyclohexane: The Effect of H-Donation

The performance of heavy oil visbreaking in supercritical cyclohexane (SCC6H12) was evaluated, followed by a comparison with its reaction in supercritical benzene (SCC6H6). The dealkylation-based viscosity reduction in the SCC6H12 was accelerated by improving the diffusivity, through which a product viscosity (80 °C) as low as 0.5 Pa.s was readily obtained by visbreaking at 380 °C for 5 min. A competition between dealkylation and condensation took place throughout the visbreaking process. As the reaction proceeded or the temperature increased, condensation played an increasingly dominant role in the visbreaking. Unlike the inert SCC6H6, the SCC6H12 participated in the visbreaking by saturating the alkyl carbon radicals essential for dealkylation and the aromatic carbon radicals essential for condensation. The viscosity reduction efficiency of the visbreaking in the SCC6H12 was initially suppressed by the H-donation of the solvent, but recovered rapidly due to the improved diffusion environment. Benefiting from the saturation of the aromatic carbon radicals, the asphaltene content of the product obtained in the SCC6H12 was lower than the corresponding value of the product obtained in the SCC6H6.

Deep Insights into Heavy Oil Upgrading Using Supercritical Water by a Comprehensive Analysis of GC, GC-MS, NMR, and SEM-EDX with the Aid of EPR as a Complementary Technical Analysis

Upgrading of heavy oil in supercritical water (SCW) was analyzed by a comprehensive analysis of GC, GC-MS, NMR, and SEM-EDX with the aid of electron paramagnetic resonance (EPR) as a complementary technical analysis. The significant changes in the physical properties and chemical compositions reveal the effectiveness of heavy oil upgrading by SCW. Especially, changes of intensities of conventional EPR signals from free radicals (FRs) and paramagnetic vanadyl complexes (VO²⁺) with SCW treatment were noticed, and they were explained, respectively, to understand sulfur removal mechanism (by FR intensity and environment destruction) and metal removal mechanism (by VO²⁺ complexes' transformation). For the first time, it was shown that electronic relaxation times extracted from the pulsed EPR measurements can serve as sensitive parameters of SCW treatment. The results confirm that EPR can be used as a complementary tool for analyzing heavy oil upgrading in SCW, even for the online monitoring of oilfield upgrading.

On the optimum operating temperature for steam floods

The technical, environmental and economic performances of a steam flood are partly influenced by the operating temperature (pressure). However, the definition and procedure for determining the optimum operating temperature are still debatable. Employing a combination of analytic modelling and numerical simulations, this paper investigates the existence (or otherwise) of an optimum injection temperature Topt for saturated-steam floods. Considering the maximization of productivity and thermal efficiency as objective, an analytic procedure, which explores the effects of temperature on injectivity, total steam enthalpy, oil viscosity and relative permeabilities, shows that the operating temperature (pressure) of a steam flood should not exceed 515 K (3.5 MPa). A simple closed-form expression is proposed for Topt as a function of basic rock and fluid properties. For an example three-dimensional reservoir model comprising an 8-m oil shale unit sandwiched between two sandy units each 15 m thick, numerical simulations show sensitivity to temperature (and viscosity effect) in the range 350–450 K, but becomes increasingly insensitive in the band 500–650 K. It is established that ~500–550 K is the optimum band when the optimization objective is to maximize both discounted oil recovery and cumulative oil-steam ratio. These results agree with an optimum injection temperature of ~501 K estimated from the proposed analytical model in this case. Therefore, based on the results of the analytical model, thermal simulations and other considerations, it is concluded that the optimum steam-injection temperature is project and system specific. The insights gained should find relevance in the design and management of steam floods, as well as other steam-based recovery processes.