石油实验地质

2015, 37(1): .

Abstract(590) PDF-CN(1453)

Abstract:

Mechanism and development model of karsts in Ordovician buried hills in western Lungu area, Tarim Basin

Zhang Qingyu, Liang Bin, Cao Jianwen, Dan Yong, Hao Yanzhen, Li Jingrui

2015, 37(1): 1-7. doi: 10.11781/sysydz201501001

Abstract(1056) PDF-CN(1248)

Abstract:
In the western Lungu area in the Tarim Basin, dissolution pores, holes and fractures served as reservoir space in the Ordovician carbonate rocks. The karst reservoirs had a strong heterogeneity, and were classified into four types, including fracture, hole, fracture-hole, and cave. In different landscape units, the karsted fracture and hole system was vertically zoned. The mechanism of karst was studied with sheet analysis, and a developmentmodel of the karst reservoir in the Ordovician western Lungu carbonate rocks was established. The Lungu7 block in the east was the highest in the study area, and recharged the buried hills in Lunnan. The karst platform in the western Lungu area recharged the western Lungu area. Meteoric water infiltrated, forming dissolution pores and fractures, which were filled by clays and calcites. On the karst slope, groundwater migrated horizontally, and a karst river/pipeline system developed, filled by karst breccias and clays. The karst basin drainage area determined the scale of karst development.

Diagenesis and diagenetic facies of crust-weathered ancient karst carbonate reservoirs

He Jiang, Feng Chunqiang, Ma Lan, Qiao Lin, Wang Yong

2015, 37(1): 8-16. doi: 10.11781/sysydz201501008

Abstract(1129) PDF-CN(1045)

Abstract:
In the north of the Jingbian Gas Field in the Ordos Basin, a case study was made of the first section of the fourth sub-member of the fifth member of the Majiagou Formation (M5₄¹). Through detailed subsurface geological analysis, a realistic description of typical diagenetic features, systematic sampling and laboratory testing, with geological background and petrological characteristics as main clue, the diagenesis characteristics of crust-weathered ancient karst carbonate reservoirs were analyzed, and the diagenetic facies were recognized. The marine diagenetic environment of M5₄¹ was influenced by dolomitization and anhydritization, and was controlled by the palaeogeographic framework. As to the epidiagenetic environment controlled by ancient karst physiognomy, dissolution and packing effects of dissolved pore, fracture and cave types took place. For the buried diagenetic environment, extensive dissolution was common. Based on the coupling relationship between diagenesis and porosity-permeability network, a "diagenesis in marine diagenetic environment + diagenesis in epidiagenetic environment" combination principle was adopted to divide the diagenetic facies into four typical types: (Ⅰ) medium-weak filling facies of anhydrite small nodule dolomitization-dissolved pore and fracture type; (Ⅱ) medium-strong filling facies of anhydrite small nodule dolomitization-dissolved pore and fracture type; (Ⅲ) strong filling facies of dolomitization-dissolved cave type; and (Ⅳ) strong filling facies of anhydrite lithification-dissolved pore and fracture type, and strong filling facies of dissolved cave type. With well-developed premium reservoir rocks, moderate karst intensity and medium-weak (deposition) filling, the type-Ⅰ area was favorable for fracture-cave reservoir development.

Vertical zoning of karst formations in reservoirs with thick limestones: A case study of district 4 in Tahe Oilfield

Qu Quangong, Zhang Jingxuan, Lu Youming, Zhu Fengyun

2015, 37(1): 17-21. doi: 10.11781/sysydz201501017

Abstract(1077) PDF-CN(1174)

Abstract:
In district 4 of the Tahe Oilfield, the Ordovician Yingshan Formation was most petroliferous. Marine carbonate rocks with big thickness were widespread. Secondary pores, including dissolution pores, fractures and caves, served as the main reservoir spaces, while primary pores were poorly developed. According to modern karst hydraulic unit theory, a conceptual model of karst was established. Three palaeo-hydraulic zones were identified: vadose zone (including infiltration sub-zone and percolation sub-zone), phreatic zone and tranquil zone. The distribution of reservoirs was described using stochastic seismic inversion technology. The reservoirs were controlled by palaeo-hydraulic zones vertically and karst landforms horizontally, which was proved by field work.

Development characteristics and hydrocarbon accumulation significance of fractures in Lower Silurian Kalpintag Formation, northern slope of central Tarim Basin

Guo Hui, Ma Zhongyuan, Zhang Li, Huang Wei, Yang Suju

2015, 37(1): 22-27. doi: 10.11781/sysydz201501022

Abstract(981) PDF-CN(832)

Abstract:
Based on the data of core, microscope thin section, scanning electron microscope, cathode lumine-scence, and conventional and dipole acoustic logging, the development characteristics and hydrocarbon accumulation significance of fractures in the Lower Silurian Kalpintag Formation on the northern slope of the central Tarim Basin were studied. A large number of mainly high-angle or vertical fractures developed in the study area. They feature low density, long length, medium width and low filling extent. More fractures were found in the relatively weak bands of rock, such as the margins and interlayers of boulder clays. Conventional logging curves showed two peaks and one order of magnitude difference. The anisotropy of fast shear wave in dipole acoustic logging showed that fracture development was influenced by NE trending strike-slip faults and the NE-SW trending maximum horizontal principal stress. The fractures in the Kalpintag Formation played important roles in the formation of tight sandstone reservoirs. They improved the porosity and permeability of tight sandstones, and the large-scale, high-angle or vertical fractures served as pathways for vertical migration of hydrocarbons. For the small-scale adjustment of hydrocarbon migration, the small-scale, low-angle or horizontal fractures were important.

Main controlling factors of phase evolution and charging pattern of hydrocarbons in northern Dongpu Sag

Tan Yuming, Jiang Youlu, Zhao Lijie, Mu Xiaoshui, Xu Tianwu

2015, 37(1): 28-34. doi: 10.11781/sysydz201501028

Abstract(1101) PDF-CN(962)

Abstract:
Base on statistics of gas oil ratios in reservoirs, thermal-pressure simulation experiments, and analysis of oil/gas accmulation conditions, the distribution and controlling factors of hydrocarbon phases in the northern Dongpu Sag were analyzed. From shallow to deep formations in the study area, liquid hydrocarbon, gaseous hydrocarbon containing gas condensate, and gaseous hydrocarbon were found in turn. The vertical distribution and dipartite degree of hydrocarbon phase varied among different regions, and the charging characteristics during different periods were distinctive. The evolution of hydrocarbon phase was controlled by the type of organic matter in the source rock, the thermal evolution degree of the source rock, and temperature-pressure environment of hydrocarbon migration and accumulation. In the deep formations, gases generated mainly form crude oil cracking. The majority of middle and shallow gas were evaporated from oils. There were three types of oil and gas source, including "single sag and single source", "single sag and multiple sources", and "multiple sags and multiple sources", and the corresponding phase evolution patterns were defined as "early oil phase and late gas phase", "early mixed phase and late oil phase", and "horizontal oil phase in multiple stages", "verticaloil phase in multiple stages". These contributed to various oil and gas charging patterns in different sags.

Reef evolution on a fault-controlled Miocene platform margin, western deep water area of South China Sea

Huang Hongguang, Du Xuebin, Lu Yongchao, Chen Ping

2015, 37(1): 35-39. doi: 10.11781/sysydz201501035

Abstract(1203) PDF-CN(953)

Abstract:
In the South China Sea, there were favorable conditions for reef development. However, the reef structure was not precisely described due to the lack of high-quality seismic data. Geologic and geophysical analyses were used to study the reefs in the fault-controlled margin of the southern uplift of the western deep-water area in the South China Sea. The reefs showed hummocky or lenticular shape, and the internal reef crest and reef ditch were observed clearly. Vertically, the reef structure displayed aggradational and progradational characteristics. There were three types of reef identified according to their growth speed, including slow-growth, constant-growth and fast-growth ones. For the first type, reefs grew slowly and retrograded to continents. For the other two types, reefs grew fast and aggraded vertically. The spatial distribution and growth speed of reefs were controlled by sea level changes, space changes and ancient morphology.

Gas hydrate sources in Wuli-Kaixinling permafrost, southern Qinghai province

Tang Shiqi, Lu Zhenquan, Luo Xiaoling, Wang Ting, Tan Panpan

2015, 37(1): 40-46. doi: 10.11781/sysydz201501040

Abstract(953) PDF-CN(919)

Abstract:
Based on the past two years' data on gas source survey in compliance with the National Thematic Project of Gas Hydrate Resources' Exploration and Test-Production Engineering in the Wuli-Kaixinling permafrost of the southern Qinghai province, organic geochemical indicators were analyzed on the hydrocarbon (gas) source rocks of the Nayixiong Formation in the Upper Permian Wuli Group and the Bagong Formation in the Upper Triassic Jiezha Group. Results showed that organic matter contents were at moderate levels in the hydrocarbon (gas) source rocks of the two formations. The main organic matter was type III with high maturity. For most samples, organic matter was mature or over-mature, at the wet to dry gas phase. The source rocks produced a large amount of hydrocarbon gases to meet the needs of gas hydrate formation. Mudstones in the Nayixiong Formation in the Upper Permian Wuli Group and limestones in the Bagong Formation in the Upper Triassic Jiezha Group worked as major gas source rocks for gas hydrate formation.

Characteristics, origin and quantitative evaluation of overpressure in strike-slip and compression-shear booster zone of Tan-Lu Fault: A case study in JZ27 section of Liaodong Bay, Bohai Sea

Wei Ajuan

2015, 37(1): 47-52. doi: 10.11781/sysydz201501047

Abstract(1041) PDF-CN(417)

Abstract:
In the JZ27-A well block of the strike-slip and compression-shear booster zone in the JZ27 section of the Liaodong Bay in the Bohai Sea area of the Tan-Lu Fault, overpressure developed in the third member of the Shahejie Formation, and the pressure coefficient reached an average of 1.5. Thick mudstones sealed the overpressure on the top. Particle fragmentation was obvious in the overpressure zone. The area and thickness of the overpressure were controlled by the range of the pressure booster zone and the intense development of strike-slip and compression-shear zone, mainly restricted to the third member of the Shahejie Formation in the JZ27-A well block. The origin for overpressure was interpreted to be as follows. From the end of the third member of the Dongying Formation to the early stage of the second member of the Dongying Formation, influenced by the intense dextral strike-slip of the Tan-Lu Fault, stress concentrated in the JZ27-A well block of the strike-slip and compression-shear booster zone. Thereby, horizontal structural compression stress formed. At the same time, because of overlying thick-bedded mudstones, stress could not be released effectively. As a result, overpressure occurred. According to the balance of reservoir pressure, the contribution of strike-slip stress to overpressure was quantitatively evaluated. The contribution of strike-slip stress to overpressure was 30%-35% and occurred earlier than the period with large amounts of hydrocarbon generation and expulsion. The overpressure impeded the charging of oil tremendously.

Petroleum geology characteristics and exploration targets of pre-salt formations in Santos Basin, Brazil

Wu Changwu

2015, 37(1): 53-56. doi: 10.11781/sysydz201501053

Abstract(1213) PDF-CN(912)

Abstract:
The Santos Basin in Brazil has experienced three tectonic evolution stages (rifting, transitional and passive continental) with three sequences deposited (pre-salt, salt and post-salt). Source rocks in the pre-salt formations in the lower rift were the most effective source rocks in the basin. Microbial limestones in the upper rift and depression, and coquina limestones in upper rift served as the main reservoirs for the pre-salt source rocks. The salt formations had strong capping capacity thanks to great thickness and continuous distribution in the deep water area. The basement horst belt helped the formation of various structural traps. All these advantageous geologic conditions provided a good basis for the generation of giant oil and gas pools in the pre-salt formations in the basin. The basement horst belt in the deep water area in the north of the basin was a favorable location for the pre-salt hydrocarbon accumulation, where the source rocks were moderately mature, and the thick, continuously distributed salt formations provided a good preservation environment. In the shallow water area formed by a basement horst, carbonate reservoirs were well-developed, and traps such as horsts, tilted fault blocks and drape anticlines were very common. Hydrocarbons generated in the surrounding grabens migrated to and accumulated in the horsts. The other pre-salt formations had poor accumulation conditions.

Hydrocarbon accumulation characteristics and enrichment controls of LB block in Llanos Basin

Feng Fang, Wang Xiaojie, Hu Junfeng, Hu Ping, Wang Huan

2015, 37(1): 57-63. doi: 10.11781/sysydz201501057

Abstract(1048) PDF-CN(868)

Abstract:
Based on the analysis of hydrocarbon generation, migration and accumulation, the controlling elements and pattern of reservoirs in the LB block of the Llanos Basin were summarized. The influencing factors for local hydrocarbon enrichment were identified, and favorable exploration targets were predicted. The LB block had a good potential for hydrocarbon migration and accumulation. In the major reservoir (the Carbonera Formation), multiple sets of reservoir-cap assemblages developed. Traps included faulted noses and faulted anticlines associa-ted with normal faults. Structure and reservoir were the main controlling factors of hydrocarbon accumulation. Hydrocarbon migrated laterally along massive sandstones in the C7 section of the Carbonera Formation. Firstly, they accumulated in structural traps in the C7 section, and then partially migrated upwards into the C5 section through faults and accumulated in structural and lithologic traps adjacent to the faults at the bottom of C5. Local hydrocarbon enrichment was affected by various factors, such as tectonic background, trap amplitude and reservoir quality.Low-amplitude faulted anticline reservoirs developed far away from faults in the C7 section and lithologic updip pinch-out reservoirs in the downthrown side of faults in the C5 section were predicted.

Distribution of C₂₆ norcholestanes in Ordovician crude oils from Tahe Oilfield and its geological significance

Li Meijun, Wang Tieguan, Zhang Weibiao

2015, 37(1): 64-70. doi: 10.11781/sysydz201501064

Abstract(1056) PDF-CN(867)

Abstract:
A series of C₂₆ norcholestanes was detected in the Ordovician crude oils from the Tahe Oilfield, the Tarim Basin, northwest China. The abundance of 24-norcholestanes in most of the Ordovician crude oils was lower than that of 27-norcholestanes. The oils from well T904 in the eastern Tahe Oilfield and well TD2 in the eastern Tarim Basin, however, were characterized by relatively higher 24-norcholestane abundance. The distribution of C₂₆ norcholestane of the Upper Ordovician marls from the wells LN46 and BD2 resembled that of the most Ordovician crude oils from the Tahe Oilfield. The distribution of C₂₆ norcholestanes in typical Cambrian black shales and gray limestones from the wells TD2, He4 and outcrops from Keping profile resembled that of the crude oils from the wells T904 and TD2. Criteria are proposed relative to C₂₆ norcholestanes that could be used to classify oil families within the Ordovician reservoirs. Oils with NCR (defined as 24/(24+27)-norcholestanes) >0.50 and NDR (defined as 24/(24+27)-nordiacholestanes) >0.35 were thought to be derived from the Cambrian source rocks, and oils with NCR<0.40 and NDR<0.35 were thought to be derived from the Upper Ordovician source rocks. Therefore, C₂₆ norcholestanes were effective molecular markers to classify oil genetic families in the Tahe Oilfield. They could also provide molecular evidence for the origin and evolution of diatoms and dinoflagellates and the plate drift of the Tarim Basin.

Geochemical features of source rocks and crude oils in central Llanos Basin, South America

Yu Qing, Xu guosheng, Xu Fanghao, Xu Shenghui, Zheng Lihui

2015, 37(1): 71-79. doi: 10.11781/sysydz201501071

Abstract(1122) PDF-CN(901)

Abstract:
The central Llanos Basin in South America is an important petroliferous province. The analysis of the geochemical features of source rocks and crude oils in the study area revealed the process of hydrocarbon expulsion, migration and accumulation as well as the biodegradation features of crude oils. According to rock evaluation and crude oil composition, and combined with a variety of biomarker parameters, the geochemical features of source rocks and crude oils were analyzed systematically and comprehensively. Several conclusions were made as follows. Firstly, source rocks in the Gacheta Formation were deposited in a saline-water and weakly oxidizing to weakly reducing environment with little terrestrial organic matter, and kerogen in the Gacheta Formation was of sapropel-humic type. Source rocks in the Los Cuervos Formation were deposited in an oxidizing brackish-water environment with abundant terrestrial organic matter, and kerogen in the Los Cuervos Formation was of sapropel- humic and humic types. Source rocks in the Gacheta and Los Cuervos formations were both low-maturity and medium-maturity, showing large hydrocarbon-generating potentials. Secondly, 3 crude oil families were found in the central basin, named families A, B and C. Crude oils of family A originated from Cretaceous source rocks, while those of family B from Paleogene, and those of family C were a mixture of families A and B. Thirdly, for most of the crude oil samples, rearranged sterane was abundant, the dibenzothiophene/phenanthrene ratio was low, and the Pr/Ph value was high, indicating that the source rocks were marine-facies shales rather than carbonates. Finally, crude oil composition was controlled by biodegradation and recharge. From the Santiago Oilfield to the La Gloria Oilfield, biodegradation effect weakened toward the NE. Influenced by the recharge of light oils, crude oils from the Cupiagua and Buenos Aires Oilfields had much higher API gravity values than those from the La Gloria and other oilfields.

Application of tricyclic terpanes in biodegraded oil-source correlation in Biyang Sag

Guo Pengfei, He Sheng, Zhu Shukui, Chai Derong, Yin Shiyan

2015, 37(1): 80-87. doi: 10.11781/sysydz201501080

Abstract(1181) PDF-CN(953)

Abstract:
Biodegraded oils from the northern slope of the Biyang Sag were analyzed to examine the application of tricyclic terpanes to biodegraded oil-source correlation. Tricyclic terpanes are resistant to biodegradation (biode-gradation rank 8) . New tricyclic terpane parameters, such as (C₂₃-C₂₆/C₁₉-C₂₂)-tricyclic terpanes, (C₁₉-C₂₆/C₂₈-C₂₉)-tricyclic terpanes and (C₁₉-C₂₆)-tricyclic terpanes/C₂₉-Ts are effective oil-source correlation parameters. Correlation results suggested that the biodegraded oils in the lower member of Eh₃ on the northern slope of the Biyang Sag came from the mudstones in the lower member of Eh₃ of the central sag, and the oils in the upper member of Eh₃ mainly came from the mudstones in the upper member of Eh₃ of the central sag. The correlation results of oils and source rocks in the ZhuⅠ Depression of the Pearl River Mouth Basin determined by the three tricyclic terpane parameters were consistant with previous results, further supporting the effectiveness of the parameters.

Differences of nitrogen isotopes in crude oils from different depositional environments

Liu Yazhao, Wu Minghui, Shi Shengbao, Wang Jie, Li Wei

2015, 37(1): 88-91. doi: 10.11781/sysydz201501088

Abstract(1167) PDF-CN(970)

Abstract:
As an important element of oil and organic matter, the contents and isotopes of nitrogen are different due to different sources from different environments and different late diagenetic processes after burial.The contents and isotopes of nitrogen in urea and caffeine show that these nitrogen parameters of samples are highly variable and indicate different depositional environments. The carbon and especially the nitrogen isotopes of crude oils formed in marine environments are lighter than those in continental environments, For samples from the same environment, high-temperature cracking causes nitrogen isotope fractionation. ¹⁴N is enriched in crude oils and nitrogen isotopes are lighter in high-maturity oils.

A new viewpoint about the relationship between carbonate content and acidolysis hydrocarbon

Yang Jun, Shen Zhongmin, Wang Guojian, Cheng Tongjin, Lu Li

2015, 37(1): 92-96. doi: 10.11781/sysydz201501092

Abstract(920) PDF-CN(830)

Abstract:
Using unary linear regression, the relationship between carbonate content and acidolysis hydrocarbon in a well was investigated, which was different in wells with long production history, dry wells or wells with short production history. The gradient in the mudstone and related coefficient were greater than that in the sandstone in the wells with long production history, but the reverse was true in the dry wells or the wells with short production history. Then the reasons for the characteristics were analyzed from the carbonate mineral formation and the different lithology's adsorption property. According to the characteristics, a new method was developed for hydrocarbon prediction in exploration wells and the re-examination of old wells. This method was fast and with low cost, and could effectively improve the success rate of new and old wells re-examination.

Effect of fluid medium in source rock porosity on oil primary migration

Ma Zhongliang, Zheng Lunju, Zhao Zhongxi, Ge Ying, Xu Qin

2015, 37(1): 97-101. doi: 10.11781/sysydz201501097

Abstract(1049) PDF-CN(966)

Abstract:
With the self-designed simulation instrument for hydrocarbon generation and expulsion in formation porosity under controlled heating and pressuring conditions, a series of experiments was made with different systems such as nitrogen-water vapor, water vapor-liquid water, liquid water, and anhydrous. Oil discharge efficiency was compared to study the effect of the fluid medium in source rock porosity on oil primary migration. In the oil and gas generation phase, pore space in the source rock was charged by fluids (hydrocarbon gas, non-hydrocarbon gas, oil, formation water) with certain temperature and pressure. Liquid water was an indispensable transport carrier in oil primary migration process. Water might adsorb onto the surface of minerals, preventeding the adsorption of hydrocarbon and was favorable for hydrocarbon migration. CO₂ associated with hydrocarbon generation easily dissolved in oil, which reduced the interfacial tension between the oil and water, oil viscosity and oil migration resistance, and promoted oil primary migration.

A new PVT simulation method for hydrocarbon-containing inclusions and its application to reconstructing paleo-pressure of gas reservoirs

Zhang Junwu, Zou Huayao, Li Pingping, Fu Xiaoyue, Wang Wei

2015, 37(1): 102-108. doi: 10.11781/sysydz201501102

Abstract(1259) PDF-CN(1274)

Abstract:
PVT numerical simulation of fluid inclusions was an important method to reconstruct the paleo-pressure of hydrocarbon accumulations; however, in high-maturity gas reservoirs, gas-liquid petroleum inclusions were very rare, so the traditional PVT simulation methods could not be applied. It was urgent to develop a new method. Hydrocarbon-containing inclusions were widely distributed in gas reservoirs. They could dissolve a little gaseous hydrocarbon and their trapping temperatures were close to homogenization temperatures. Using PVTsim software and combining with some parameters such as vapor/liquid ratio and homogenization temperature of hydrocarbon-containing inclusions, a new PVT simulation method was proposed to get the trapping pressure of inclusions, which was then applied to reconstruct the paleo-pressure of the Yuanba gas reservoir in the northeastern Sichuan Basin. The Xujiahe reservoir developed weak overpressure at about 160 Ma, and the pressure coefficient reached 1.11. Then the paleo-pressure increased rapidly until 148 Ma at which time the pressure coefficient reached 1.86. At about 100 Ma, the paleo-pressure reached its peak, but the pressure coefficient decreased to 1.60 because the formation burial depth was the deepest. The comprehensive analyses of hydrocarbon generation, paleo-pressure evolution and reservoir-cap combination indicated that the overpressure transferred from source rock to reservoir through the process of hydrocarbon generation and accumulation was an important mechanism for the development of overpressure in the Xujiahe reservoir.

Pore structure of two organic-rich shales in southeastern Chongqing area: Insight from Focused Ion Beam Scanning Electron Microscope (FIB-SEM)

Ma Yong, Zhong Ningning, Cheng Lijun, Pan Zhejun, Li Hongying, Xie Qingming, Li Chao

2015, 37(1): 109-116. doi: 10.11781/sysydz201501109

Abstract(1457) PDF-CN(1152)

Abstract:
We used a Focused Ion Beam Scanning Electron Microscope (FIB-SEM) to observe the pore structures of the Lower Cambrian Niutitang shale and the Upper Ordovician Wufeng to Lower Silurian Longmaxi shale, sampled in the southeast of Chongqing.Three-dimensional distributions of the nanometer-sized organic-matter pores were reconstructed and their pore structure parameters were analyzed quantitatively. Our work indicated that microfractures between strata, interparticle and intraparticle pores in the mineral matrix, and organic-matter pores were well-developed in the Wufeng-Longmaxi formations. Pores within organic matter form a well-distributed honeycomb like structure with good connectivity, and the pore radius is between 3 and 100 nm. Porosity of organic matter calculated using the FIB-SEM 3-D reconstruction is between 9.13% and 18.42%,and the contribution of organic-matter pores in the total porosity is correlated with the total organic carbon (TOC) content. Dissolution pores and interparticle pores are developed in the Niutitang Formation while organic-matter pores are unevenly distributed. The organic-matter pores are tabular or pinhole with the pore radius between 3 and 25 nm and have poor connectivity. The calculated organic-matter porosity is below 1.59% and has little relationship with the TOC content. So the total porosity in the Niutitang shale mainly comes from the mineral matrix pores. The FIB-SEM results have shown significant differences in the pore structure of the two shales.

Improving evaluation of predicted hydrocarbon reserve zones

Qin Weijun, Fu Zhaohui

2015, 37(1): 117-123. doi: 10.11781/sysydz201501117

Abstract(1276) PDF-CN(1031)

Abstract:
Predicted hydrocarbon reserves were studied, and four evaluation methods for improving reserve estimates were proposed, including possibility evaluation, upgrading rate evaluation, economic evaluation and comprehensive evaluation. A difficulty index was used to evaluate the possibility of reserve upgrading. Reserve upgrading probability calculation and test were used to evaluate the upgrading rate. A discounted cash flow method was applied in the economic evaluation. The difficulty index, probability calculation and economic methods were jointly used in the comprehensive evaluation. The predicted hydrocarbon reserve blocks were classified into four types according to the comprehensive evaluation, including the blocks with large or medium potential for upgrading, the blocks with medium or small potential for upgrading, the blocks remaining for evaluation, and the blocks not to upgrade at present.

Reserves growth trend and potential analysis of Junggar Basin

Chen Ping, Zhang Ling, Wang Huimin

2015, 37(1): 124-128. doi: 10.11781/sysydz201501124

Abstract(1239) PDF-CN(1014)

Abstract:
The Junggar Basin is one of early explored petroliferous basins in China. Since the discovery of the Karamay Oil Field in 1955, over 30 oil fields have been found. The geologic features, hydrocarbon accumulation mechanisms and distribution characteristics of the Junggar Basin were studied in this paper. The basin has undergone rapid and effective exploration in past years, which helped potential prediction. The present estimate of recoverable oil and gas resources in the basin is 45.3% and 30.3%, respectively. Exploration is in the middle and late stages. There are (9.42~16.92)×10⁸ t oil remaining unproved. Lithologic, igneous rocks and tight sandstones are the main targets for future exploration in the basin.

Li Zhiming

2015, 37(1): 129-129.

Abstract(601) PDF-CN(519)

Abstract:

2015 Vol. 37, No. 1

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