Shijia Chen

Tight oil accumulation mechanisms of Triassic Yanchang Formation Chang 7 Member, Ordos Basin, China

Abstract The sedimentary environment, petrology, pore throat structure, migration and accumulation power, and accumulation process are analyzed to study the oil accumulation mechanism and distribution of Triassic Chang 7 Member tight oil in Ordos Basin. Chang 7 tight oil reservoirs are mainly semi-deep lake – deep lake sandy debris flow deposits and delta front underwater distributary channel deposits. The results of field emission scanning electron microscopy, CT scans and other high-resolution microscopy techniques show the physical properties of Chang 7 oil reservoirs are poor, micro- and nano-meter pore throats are developed, inter-granular pores and feldspar dissolved pores are the main pores, and tube- and strip-shaped pores are favorable reservoir space. The hydrocarbon generation and accumulation simulation of tight oil reservoirs shows that the hydrocarbon charging power of Chang 7 high-quality source rocks is strong. The oil saturation of the Chang 7 were more than 50% in the accumulation phase and even reached 70% or more with the continued power increase and oil enrichment. The source and reservoir rocks of Chang 7 tight oil coexist, so the hydrocarbons migrated under high pressure to migrate along relatively high permeable superimposed sands, reticular fractures and other pathways, and formed large-area continuous or quasi-continuous lithologic oil reservoirs.

The influence of bitumen on reservoir properties and hydrocarbon accumulation in the Santai Area of the Junggar Basin, North Western China

ABSTRACT Bitumens influence on reservoir properties and hydrocarbon accumulation in Santai area was studied by experiment measures and geochemical evidences. The porosity and permeability of the sandstones containing bitumen increased significantly by dissolving experiments, implying that bitumen strongly influences the reservoir properties. The analysis reveals that there were two stages of hydrocarbon accumulation. In the first stage oil migrated into coarse-grained sandstone and then degraded to bitumen, which deteriorated the reservoir properties. The second stage oil had to migrate into fine-grained sandstones, or the residual pores of the bitumen-containing coarse-grained sandstone. Exploration in this area should avoid the bitumen distribution zone.

Features and origin of oil degraded gas of Santai field in Junggar Basin, NW China

Abstract Based on comprehensive analysis of the natural gas composition, carbon isotopes and associated oil carbon isotopes, saturated hydrocarbon chromatography, and gas chromatography-mass spectrography, the features and formation mechanisms of natural gas in Santai area, Junggar Basin are studied. The Jurassic natural gas in Santai area is characterized by light ethane carbon isotopes, and the features of associated oil are light carbon isotopes, low Pr/Ph ratio, high C 29 and C 28 sterane value and low C 27 sterane value, which shows that the hydrocarbons were mainly derived from the sapropelic source rock of the Permian Pingdiquan Formation in Fukang sag. The natural gas composition is dominated by methane. The methane carbon isotope value of the natural gas is higher than that of biogenic gas, but it is lower than that of thermogenic gas. Natural gas reservoirs were buried shallowly and always associated with or close to heavy oil which was subjected to serious biodegradation, with occurrence of 25-norhopane. All above indicate that the natural gas in Santai area is typical oil degraded gas by bacteria. Biodegradation was a process of water-hydrocarbon reaction which was affected by the bacteria and thermodynamics. The methane bacteria made use of CO 2 and H 2 to reduce light carbon isotopes preferentially to generate methane of light carbon isotopic compositions. Biodegraded heavy oil and oil sand are widely distributed in the petroliferous basin, therefore, reservoir oil degradation gas has good exploration prospects.

Geochemical characteristic and origin of solid bitumen in the Jurassic and Triassic sandstone reservoir of Santai Area, Junggar Basin, NW China

ABSTRACT Solid bitumen was identified in the pore spaces of the Jurassic and Triassic sandstone reservoir in the Santai Area, Junggar Basin, NW China, which limits economic petroleum production, even influencing hydrocarbon accumulation. Organic geochemical techniques were figured out the origin of bitumen and its formation mechanisms. Carbon isotope characteristics of the crude oil and bitumen-reservoir extracts suggests the bitumen mainly derived from sapropelic-type source rock of Pingdiquan Formation, which was deposited in the semideep and deep lacustrine environment. Biomarker date indicates bitumen was formed from petroleum in low thermally mature stage and biodegradation was responsible for formation of the bitumen.

NMR method to calculate the bitumen saturation in the deposit

ABSTRACT Deposit bitumen is a highly viscous, asphaltene-rich hydrocarbon that can fill in the pores as the cement reduce the porosity in the deposit. The authors comparatively analyzed the experimental data of the nuclear magnetic resonance before and after the dissolving of bitumen-rich core samples. The short transverse relaxation times (T2) and consequently lower NMR porosity are characteristics of bitumen-rich zones. An NMR method was used to reconcile core data as well as to calculate the saturation of bitumen in the deposit.

Relationship between methylphenanthrene distribution and organic matter maturity: a case study of Yangchang Formation Chang 7 source rocks, Erdos Basin, China

Abstract The methylphenanthrene component of Chang 7 source rocks in the Ordos Basin was analyzed using gas chromatograph-mass method. The relationship between methylphenanthrene index (MPI), methylphenanthrene distribution fraction (MPDF) and vitrinite reflectance (Ro) was established. The comparative analysis results showed that the MPDF and Ro were positively correlated and the correlation coefficient was high. Therefore, it was more accurate that the Chang 7 source rocks were determined by MPDF. Based on the established relational expression, the maturity of Chang 7 lacustrine source rocks in the Ordos Basin was calculated. The obtained results were consistent with actual geological background.

Geochemical characteristics and origins of the crude oil of Yanchang Formation Chang 2 in Ansai Area, Erdos Basin, China

Abstract Ansai Oilfield is one of the earliest discovered oilfields in the Ordos Basin. In this paper, based on the scientific exploration and exploitation, the geochemical characteristics of the Chang 2 crude oil and potential source rocks were analyzed using gas chromatography–mass spectrometry method. The correlation of biomarkers showed that the parent materials of the Chang 2 crude oil formed in freshwater-mildly brackish water environment and were sourced from low-grade aquatic organisms and terrigenous higher plants. Oil-source correlation results showed that the Chang 2 crude oil in Ansai area was derived from the source rocks of Chang 7.

Controlling factors for the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation, Guang’an Area, Sichuan Basin:

Tight sandstone gas characterized by a wide distribution, local enrichment and a complex gas–water distribution has high exploration potential. This study, using the Xujiahe Formation in the Guang’an gas field as an example, aims to determine the main controlling factors of the enrichment of tight gas through comprehensive analyses of the source rock and reservoir characteristics, pressure evolution and structural effects by using various methods including well logging, geochemistry, mercury injection, reservoir physical properties and formation pressure. The results show that the proximal-source, interbedded hydrocarbon accumulation results from a dispersed hydrocarbon supply, which is the root cause of the widely distributed tight sandstone gas. The abnormally high reservoir pressure caused the enrichment of tight sandstone gas even under insufficient hydrocarbon generation dynamics; in addition, natural gas preferentially accumulated in the relatively high-quality reservoirs under the same hydrocarbon supply, which means that differences in the reservoir physical properties control gas charge in the reservoir. Structure controls the gas–water differentiation under the stable tectonic background, and the higher the structure is, the more abundant the gas–water differentiation is, and the easier pure gas reservoirs form. Therefore, the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation is controlled by source rocks, abnormally high reservoir pressure and the physical properties and structure of the reservoir.

The influence of water on the thermal simulation experiment of hydrocarbon generation and expulsion

ABSTRACT Thermal simulation experiment of hydrocarbon generation and expulsion is an important method for the study of source rock evolution. The role played by water in organic material evolution was clarified by summarizing the effect of water on different pyrolysis systems. According to the results, the hydrous experiment has a better hydrocarbon generation rate than the anhydrous experiment in the closed system. In the semi-open system, high-pressure water vapor has good effect to gas generation, while near-critical water (NCW) improves the oil and total hydrocarbon productive rate. So, it is inferred that NCW improves the conversion of kerogen to hydrocarbon reactions, and increases the dissolving capacity of hydrocarbons.

Overpressure water zone influence on hydrocarbon migration and oil reservoir distribution in low Cretaceous formations of Yinger sag, China

ABSTRACT The low Cretaceous Zhonggou, Xiagou, and Chijinpu formations are major source rocks in Yinger sag, Jiudong Basin, China. Oil reservoirs were discovered in Zhonggou and Chijinpu formation, which were on the top and bottom of overpressure water zone, but no hydrocarbon was discovered within overpressure zone. The impact of overpressure zone on oil accumulation was indicated by reservoir fluorescence and oil-source correlation study through geochemical analysis. The result shows the overpressure zone reservoirs have less fluorescence display and reservoir extracts dissimilar to source rocks of Chijinpu or Zhonggou formation, implying the inexistence of oil migration in overpressure zone.