Heavy Oil Hydrocarbons and Kerogen Destruction of Carbonate–Siliceous Domanic Shale Rock in Sub- and Supercritical Water

Comparative study on the pyrolysis behavior and pyrolysate characteristics of Fushun oil shale during anhydrous pyrolysis and sub/supercritical water pyrolysis

Injected steam can be converted to the sub/supercritical state during the in situ exploitation of oil shale. Thus, the pyrolysis behavior and pyrolysate characteristic of Fushun oil shale during anhydrous pyrolysis and sub/supercritical water pyrolysis were fully compared. The results revealed that the discharged oil yields from sub/supercritical water pyrolysis were 5.44 and 14.33 times that from anhydrous pyrolysis at 360 °C and 450 °C, which was due to the extraction and driving effect of sub/supercritical water. Also, sub/supercritical water could facilitate the discharge and migration of shale oil from the pores and channels. The H₂ and CO₂ yields in sub/supercritical water pyrolysis were higher than that in anhydrous pyrolysis, resulting from the water–gas shift reaction. The component of shale oil was dominated by saturated hydrocarbons in anhydrous pyrolysis, which accounted for 50–65%. In contrast, a large amount of asphaltenes and resins was formed during pyrolysis in sub/supercritical water due to the solvent effect and weak thermal cracking. The shale oil from anhydrous pyrolysis was lighter than that from sub/supercritical water pyrolysis. Sub/supercritical water reduced the geochemical characteristic indices and lowered the hydrocarbon generation potential and maturity of solid residuals, which can be attributed to the fact that more organic matter was depolymerized and released. The pyrolysate characteristic of oil shale in sub/supercritical water pyrolysis was controlled by multiple mechanisms, including solvent and driving effect, chemical hydrogen-donation and acid–base catalysis.

Sub/supercritical water can directly extract oil and gas from oil shale due to the solvent and driving effects. Also, they can be considered as an acid–base catalyst, which can catalyze some reactions such as hydrolysis, addition and rearrangement.

Composition of Oil after Hydrothermal Treatment of Cabonate-Siliceous and Carbonate Domanic Shale Rocks

The hydrocarbon compositions of shale oils, generated from two different lithological–facial Domanic deposits of the Tatarstan Republic (Russia), were studied under hydrothermal impact with 30% of water addition in a 350 °С and CO2 environment. The samples were extracted from carbonate–siliceous rocks of the Semiluky–Mendym deposits of the Berezovskaya area, and carbonate deposits of the Dankovo–Lebedyan horizon of the Zelenogorskaya area of the Romashkino oil field. The distinctive features of rocks are in the composition and content of organic matter (OM), its thermal stability, as well as the structural-group composition of the shale oil products. The hydrothermal treatment of the rock samples increased the content of saturates and decreased the content of aromatics, resins and asphaltenes in the composition of crude oil. The decomposition of the polymer-like kerogen structure and destruction processes of high-molecular compounds, such as resins and asphaltenes, are accompanied with the formation of substances highly rich in carbons—carbenes and carboids. The contents of n-alkanes and acyclic isoprenoids increase in the composition of saturated hydrocarbons. According to the chemical classification of Al. A. Petrov, the character of the molecular mass distribution of such substances corresponds to oil type A1, which is considered paraffinic. The contents of dibenzothiophene, naphthalene and phenanthrene are increased in the composition of aromatic hydrocarbons, while the contents of tri-methyl-alkyl-benzene and benzothiophene are decreased. The increase in the aryl isoprenoid ratio (AIR = С13–С17/С18–С22) and maturity parameter (4-MDBT/1-MDBT) under the influences of hydrothermal factors indicates the increasing thermal maturity degree of the hydrocarbon system. The differences in the distribution behavior of saturated and aromatic hydrocarbons—biomarkers in rocks of various lithological-facies types, which are reasoned by different conditions of initial organic matter transformation as well as under the impact of hydrothermal factors—were revealed.

In-Situ Heavy Oil Aquathermolysis in the Presence of Nanodispersed Catalysts Based on Transition Metals

The aquathermolysis process is widely considered to be one of the most promising approaches of in-situ upgrading of heavy oil. It is well known that introduction of metal ions speeds up the aquathermolysis reactions. There are several types of catalysts such as dispersed (heterogeneous), water-soluble and oil soluble catalysts, among which oil-soluble catalysts are attracting considerable interest in terms of efficiency and industrial scale implementation. However, the rock minerals of reservoir rocks behave like catalysts; their influence is small in contrast to the introduced metal ions. It is believed that catalytic aquathermolysis process initiates with the destruction of C-S bonds, which are very heat-sensitive and behave like a trigger for the following reactions such as ring opening, hydrogenation, reforming, water–gas shift and desulfurization reactions. Hence, the asphaltenes are hydrocracked and the viscosity of heavy oil is reduced significantly. Application of different hydrogen donors in combination with catalysts (catalytic complexes) provides a synergetic effect on viscosity reduction. The use of catalytic complexes in pilot and field tests showed the heavy oil viscosity reduction, increase in the content of light hydrocarbons and decrease in heavy fractions, as well as sulfur content. Hence, the catalytic aquathermolysis process as a distinct process can be applied as a successful method to enhance oil recovery. The objective of this study is to review all previously published lab scale and pilot experimental data, various reaction schemes and field observations on the in-situ catalytic aquathermolysis process.