Shouchun Zhang

Formation fluid characteristics and hydrocarbon accumulation in the Dongying sag, Shengli Oilfield

Abstract Based on the analysis of geochemical characteristics and distribution of different formation waters, a new origin identification standard was established for the formation water in the Paleogene Shahejie Formation in the Dongying Sag. The migration paths of the connate water expelled from source rocks are similar to those of the hydrocarbons coming from the same rocks, so the geochemical characteristics of the connate water coming from the source rocks can be used as auxiliary indexes to study hydrocarbon migration. Considering fluid pressure and formation water distribution, the Paleogene fluids are divided into three fluid systems: normal-pressure open fluid system, overpressure confined fluid system, and transition fluid system. The differences in hydrocarbon-bearing fluid characteristics, hydrocarbon migration dynamic, hydrocarbon-bearing fluid flow type between these fluid systems were studied. According to characteristics of the hydrocarbon-bearing fluid charging into traps, and formation water drainage pattern, three typical oil accumulation models were classified. In the overpressure confined fluid system, the main oil accumulation mode is high oil saturation fluid entering traps and displacing formation water, and “continuous” reservoirs are prone to form, and fluid oil saturation, fluid charging pressure and fluid seeping conditions affect reservoirs’ oil accumulation extent. In the normal-pressure open fluid system, the main oil accumulation modes include low oil saturation fluids enter a trap while formation water is overflowing out of the trap, and low oil saturation fluids enter a trap while formation water is seeping out of the trap. The amount of hydrocarbon-bearing fluid, fluid oil saturation, trap height, and caprock sealing ability affect reservoirs oil accumulation extent.

Hydrocarbon formation and accumulation of the deep Paleogene of the Jiyang Depression, Shengli Oilfield

Abstract Using geochemistry, sedimentary and petroleum geology methods, and based on the analysis of spatial distribution of deep source rocks and sedimentary organic facies, the favorable exploration prospects in the Jiyang Depression, Shengli Oilfield are studieded. There are 4 types of sedimentary organic facies (including anoxic organic facies, anaerobic organic facies, dysaerobic organic facies and aerobic organic facies) in deep source rocks of Kongdian Formation - Sha-4 Member, Paleogene. The source rocks of Anoxic facies and anaerobic facies are discovered in the Sha-4 Member and are proved as excellent source rocks, while the Kongdian Formation source rocks compose mainly of the dysaerobic facies and aerobic facies and served as common source rocks. The whole hydrocarbon expulsion process is divided into 3 stages, including free water expulsion, hydrocarbon generation and energy accumulation, and hydrocarbon expulsion from microfractures. The hydrocarbon expulsion from deep source rocks mainly occurs in the stage of hydrocarbon expulsion from microfractures, during which there are three oil and gas migration modes with different geologic conditions, including vertical migration, lateral migration and downward migration. The studies indicated that the hydrocarbons in shallow and medium formations from the Sha-4 Member excellent source rocks of anoxic and anaerobic facies are mainly accumulated through vertical migration along the faults, while the reservoirs formed by lateral migration and downward migration are still waiting to be revealed. So there is great exporation potential for the deep Paleogene of the Jiyang Depression.

Simulation experiment of immature oil genetic mechanism in lake facies of semi-salt water

The Immature calcareous shale in the south slope of Dongying sag, Jiyang depression, plays a significant role in immature oil genesis, and is sampled to make simulation experiment. The geochemical characters of the products of soluble organic matter and kerogen are researched respectively. The yields of the two components and their relations are made out. The contribution ratio between soluble organic matter and kerogen undergoing earty degradation in lake facies of semi-salt water is figured out for the first time, so the research into the genetic mechanism of immature oil is developed.

Geochemical evolution during the cracking of crude oil into gas under different pressure systems

Two comparative simulation experiments (a normal atmospheric-pressure opening system and a 20 MPa closed system) were conducted to study the geochemical evolution of n-alkane, sterane, and terpane biomarkers in the process of oil cracking into gas under different pressures. With an initial experimental temperature set at 300°C, the temperature was increased to 650°C at a heating rate of 30°C/h. The products were tested every 50°C starting at 300°C, and a pressure of 20 MPa was achieved using a water column. The low-maturity crude oil sample was from the Paleogene system in the Dongying sag in eastern China. The threshold temperature obtained for the primary oil cracking process in both pressure systems was 450°C. Before the oil was cracked into gas, some components, including macromolecular n-alkanes, were cracked into medium- or small-sized n-alkanes. The secondary oil cracking of heavy hydrocarbon gases of C2–5 to methane mainly occurred between 550°C to 650°C, and the parameters Ln(C1/C2) and Ln(C1/C3), as well as the dry coefficients, increased. Overpressure inhibited the oil cracking process. In the 20 MPa system, the oil conversion rate decreased, the temperature threshold for gas generation rose, and oil cracking was inhibited. Compared with the normal pressure system, high-carbon n-alkanes and other compounds in the 20 MPa pressure system were reserved. Furthermore, the parameters ΣC21−/Σ22+, Ln(C1/C2), and Ln(C1/C3), as well as the dry coefficients, decreased within the main temperature range. During secondary oil cracking (550°C to 600°C), the Ph/nC18 and Pr/nC17 decreased. High pressure influenced the evolution of the biomarkers Ts and Tm, C31 homohopane, C29 sterane, and their related maturity parameters to different extents during oil cracking under different temperature ranges.

Water consumption in hydrocarbon generation and its significance to reservoir formation

Abstract The geochemical effects of water consumption during hydrocarbon generation were studied on the basis of evolution laws of source rocks and simulation experiments on hydrocarbon generation. Water consumption statistics were obtained in order to study the relationship between water consumption during hydrocarbon generation and hydrocarbon migration and reservoir formation. The simulation experiments of hydrocarbon generation were performed under hydrous and anhydrous conditions for correlation. The geochemical characteristics of organic evolution under these two conditions were analyzed and the variations of hydrocarbon generation potential and carbon transformation ratio were emphasized. The results show the effects that organic matter and water have on each other during hydrocarbon generation: part of unavailable carbon is activated in kerogen and hydrogen is increased in degraded products, which leads to the increase of total hydrocarbon generation potential. According to water consumption mechanisms, the quantitative evaluation method of water consumption in hydrocarbon generation was put forward and used in the studies of the main source rocks in the Dongying Sag. Both of the water consumption and the depth range of the Upper Es4 Member are larger, while those of the Lower and Middle Es3 Members are smaller. Water consumption affects hydrocarbon migration and accumulation by increasing organic carbon degradation rate to increase fluid volume. Pore fluid pressure and oil-bearing saturation are consequently increased. The matching relationship between water-consuming hydrocarbon generation intervals and water-consuming diagenesis intervals enhances the dynamic forces of hydrocarbon migration, which benefits the formation of self-generating and self-preserving reservoirs or lower-generating and upper-preserving reservoirs.