Dehan Liu

Diamondoid hydrocarbon ratios : novel maturity indices for highly mature crude oils

Diamondoid hydrocarbons have been identified in oil and source rock samples from the Tarim, Yinggehai, Qiongdongnan and other Chinese basins. Two diamondoid hydrocarbon ratios have been used as novel high-maturity indices to evaluate the maturation and evolution of crude oils and condensates in these Chinese basins. The two ratios, 1-MA/(1-MA + 2-MA) (%) (MAI = methyl adamantane index) and 4-MD/(1-MD + 3-MD + 4-MD) (%) (MDI = methyl diamantane index) were found to increase with increasing vitrinite reflectance. The initial values for the ratios are ca. 50 and 30%, respectively. Diamondoid hydrocarbons are products of rearrangement of polycyclic hydrocarbons and their ratios are found to be affected by organic input to a minor extent. Based on this study, crude oils from the Tarim Basin are generally believed to be very mature (Ro > 1.1%). The Cambrian-Ordovician source beds are the major source rocks of crude oils and natural gases in this basin. Condensates from the Tarim, Yinggehai and Qiongdongnan Basins have higher maturities, equivalent to Ro values of 1.6–2.0%. Gases and condensates from the Yinggehai and Qiongdongnan basins are generated mainly from Tertiary source rocks below 4000–5000 m.

Determination of trapping pressure and temperature of petroleum inclusions using PVT simulation software - a case study of Lower Ordovician carbonates from the Lunnan Low Uplift, Tarim Basin

Abstract We report a case study carried out on Lower Ordovician reservoir carbonates of the Lunnan Low Uplift, Tarim Basin, to determine trapping pressures and temperatures of petroleum inclusions from the intersection of isochores of coeval petroleum and aqueous fluid inclusions using PVT SIM software. There are four types of petroleum inclusions from this sequence. Their trapping pressures and temperatures are: Type I 80–105 °C, 199–230 bar; Type II 135–145 °C, 235–250 bar; Type III 155–165 °C, 344–360 bar, and Type IV 220–252 °C, 345–390 bar, respectively, which are consistently higher than their homogenization temperature and saturation pressures by about 5–15 °C and 25–70 bar. To confirm the reliability of the PVT simulation approach, fluid inclusions were synthesized in calcite under controlled temperature and pressure conditions and studied using the same methods. The calculated trapping pressure and temperature of the synthetic petroleum inclusions closely match the actual pressure and temperature applied in the experiment. By reference to the burial and geothermal history of the Tarim host rocks, it was inferred that Types I, II and III petroleum inclusions represent fluids associated with three distinct phases of petroleum emplacement in the Lower Ordovician strata of this area, occurring during late Silurian to early Devonian, Cretaceous to early Tertiary, and late Tertiary, respectively. Type IV petroleum inclusions occur only in some fine calcite veins from few samples, and are believed to be related to an anomalous thermal event in this area. On the basis of the trapping pressures and trapping temperatures of the petroleum inclusions, three main phases of the petroleum-filling of the Lower Ordovician reservoirs can be delineated. Phase I and phase III petroleum events were related to petroleum migration and accumulation from the Lunnan Low Uplift or nearby area. The petroleum of the phase II petroleum event appears to have originated from Middle and Upper Ordovician source rocks in the northern slope area of the Manjiaer Depression with a long distance migration.

Multiple phases of hydrocarbon generation and migration in the Tazhong petroleum system of the Tarim Basin, People's Republic of China

Abstract Organic petrology, organic geochemical analysis and fluid inclusion methods were employed to investigate a series of core samples from the Tazhong Uplift. Bitumens and organic inclusions were found to occur widely in Paleozoic rocks, especially carbonates, and both can be subdivided into three groups. The reflectance ranges of the three bitumen groups are: 1.30-1.60% (I); 0.50-0.80% (II); and 0.15-0.40% (III), respectively, and the corresponding organic inclusion groups are: dark yellow fluorescence organic inclusions with a homogenization temperature of 200–240°C; blue-green fluorescence organic inclusions with a temperature of 160–200°C; and the strong yellow fluorescent organic inclusions with a temperature of 80–130°C. The wide occurrence of the three group bitumens and organic inclusions in the Tazhong Uplift reveals that there were three periods of large-scale oil migration and accumulation in this area. The analysis of hydrocarbon-generating history based on paleotemperature and burial history of source rocks shows that they underwent three oil-generating peaks, in Early Ordovician, Triassic and Cenozoic, respectively, which led to three phases of hydrocarbon generation and migration. It is believed that the Tazhong Uplift is an old uplift rich in oil and gas, and has been fed with oil and gas from nearby source areas during a long geological history, and also that it has great hydrocarbon potential.

An investigation of water-gas interface migration of the upper Paleozoic gas pool of the Ordos Basin using reservoir fluid inclusion information

There is a particular characteristic in the formation of the Upper Paleozoic gas pool in the Ordos Basin that is its water-gas interface migrated regional during geological history. However, there has been lack of detailed research on this problem and also no similar report on other basins. In this paper, the formation time of the fluid inclusions formed in the water-gas transition zone of the gas pool was deduced using their trapping temperatures and combining of the burial with geothermal history of the basin. On the basis of this, the isochrone of water-gas interface migration for the gas pool was mapped. The result shows that the gas pool began to form around the Yanan Area at about 165Ma, and then developed and enlarged toward the north direction. The gas pool finally formed at about 129 Ma. Since the basin uplifted from the late Cretaceous and gas supply decreased, the water-gas interface of the gas pool migrated back to the present position.

The generation and accumulation of natural gas from Yinan 2 gas pool in Kuqa Depression

By using the methods of hydrocarbon generation kinetics and carbon isotope kinetics, combined with geological background of natural gas pool formation, the generation and accumulation of natural gas from Yinan 2 gas pool was studied in Kuqa Depression of the Tarim Basin. Natural gas of Yinan 2 gas pool is mainly derived from Middle and Lower Jurassic coal-bearing source rocks, and generally belongs to long time-accumulated gas. It is suggested that Yinan 2 gas is chiefly accumulated in the last 5 Ma, itsR0 ranges from 1.25% to 1.95%, and the loss rate of natural gas is about 25%–30%. This work not only complements and reduces the deficiency of formation model of natural gas pools which traditionally depends on the matching relationships between source rock, reservoir, cap rock, and trap, but also is a useful reference in the study of other gas pools.

Experimental study and evaluation on hydrocarbon generation of macerals

Some typical coal and maceral samples are selected for oil and gas-generating systematic thermal simulation experiments, Rock-Eval, GC and GC-MS analyses. Results cause productivity curves of extracts and gaseous, light, liquid as well as total hydrocarbon. Effects of macerals and maturation on hydrocarbon productivities and compositions are synthetically discussed. Evaluation indexes and plan on coal-generated oil and gas in bituminous coal rank are suggested according to the data from experiments and analyses.

Laser-induced fluorescence microscopy - application to possible high rank and carbonate source rocks

Abstract It is difficult to obtain useful fluorescence information from coals and source rocks of high maturity by means of conventional fluorescence microscopy due to the low fluorescence intensity of the macerals. A laser-induced fluorescence microscopy (LIFM) designed by the authors was applied to target the problem. An investigation was made by means of this technique on a suite of coals having a range of mean random vitrinite reflectance (VRo)=0.3–2.5%, and some high maturity source rocks of early Palaeozoic age. The results show that LIFM greatly improves several functions of conventional fluorescent microscopy. LIFM is very sensitive to organic matter in sediments and for the suite of Chinese coals and possible source rocks investigated, considerably extends the maturity range over which visible fluorescence can be observed. The range is extended from about 1.40% to 2.0% VRo for vitrinite of normal composition, from 1.30% to about 1.50% VRo for alginite and other liptinites, and from about 2.5% to 3.2% VRo for organic inclusions and asphalt-absorbed minerals. With LIFM, it was found that the organic matter in some early Palaeozoic carbonates and argillaceous limestones is distributed very unevenly. In these rocks, which are believed to have been significant source rocks, some microregions are very rich in organic matter or contain a large number of organic inclusions although the total organic carbon (TOC) of the whole rock is low. A microchannel network for petroleum expulsion and migration, comprised of grain boundaries, bedding planes and suture textures containing hydrocarbons was revealed in carbonate strata. LIFM of organic matter in rocks should extend the application of organic petrology in petroleum exploration.

Dating hydrocarbon generation and migration based on bitumen reflectance

On the basis of thermal maturation theories of organic matter in sediments and an improved Karweil’s method, a method for dating hydrocarbon generation and migration by means of bitumen reflectance has been suggested. A few representative boreholes in the Tazhong Area of the Tarim Basin was investigated by this method. The results indicate that the three phases of bitumen from the Tazhong Area formed during Middle and Late Ordovician, Late Cretaceous-Early Tertiary, and Late Tertiary, respectively. This implicates that there were three phases of hydrocarbon generation and migration occurring in this area during geological history. This study provided a new idea for the geological application of geochemical data of bitumen.

Natural gas releasing simulation experiment of coal in process of temperature decreasing and decompression and preliminary application in Ordos Basin

Natural gas releasing simulation experiments were carried out in laboratory for researching the gas storage capacity in state of high temperature and high pressure and its gas releasing potential in process of temperature decreasing and decompression. The exiting phase state was studied through measuring gas adsorption of coal and PVT phase calculating of natural gas. Gas volume, gas molecular and isotope compositions in process of temperature decreasing and decompression were measured, natural-gas yields released from the Upper Paleozoic coal strata after later Cretaceous (K3) were calculated and the formation of the reservoir was studied combining with the geological background. The results indicate that natural gas stored in coal has still bigger releasing potential after the uplift of Upper Paleozoic strata. There exists a weak gas supply-effluent equilibrium in the reservoir of Ordos Basin, which is another possible evidence that the Upper Paleozoic gas reservoir may be a deep basin gas reservoir.

Factors controlling the enrichment of natural gas in Kuche depression, Tarim Basin, NW China: Molecular geochemical evidence from sedimentary organic matter

Using molecular geochemical data from infrared spectrometer and pyrolysis gas chromatography-mass spectrometry, this paper investigates the petroleum generation characteristics of Jurassic coal measures from Kuche depression, Tarim Basin, NW China. The results showed that the Jurassic coaly rocks with medium maturity (R0%: 0.8–1.1) were enriched in gas-prone functionalities (-CH3) and low molecular weight pyrolysates (< nC21), indicating that the coaly rocks from Kuche depression were gas/condensate prone at the stages of middle to high maturation, and it was further supported by the oil/source correlation from well Yinan 2 in this region.