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2022 Vol. 44, No. 2

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2022, 44(2)
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A comparative study of geological conditions of tight oils in China and USA
LUO Qun, GAO Yang, ZHANG Zeyuan, WANG Shichen, HONG Lan, MA Wenyu, XU Qian
2022, 44(2): 199-209. doi: 10.11781/sysydz202202199
Abstract(817) HTML (250) PDF-CN(159)
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On the basis of formulating and perfecting the definition and connotation of tight oil, a comparative study was carried out on the basin formation, hydrocarbon generation, hydrocarbon preservation and reservoir formation for 9 tight oil basins of China and 6 of USA. It was concluded that China′s tight oil has great potential, but the accumulation conditions are complex and diverse. There are 9 tight oil basins in China located in 3 tectonic areas in the eastern, middle and western parts of mainland China. Due to the combined action of the 3 plates of the Pacific, Siberia and India, the type, scale and formation of tight oil basins as well as the generation, preservation and enrichment of hydrocarbon are varied and have regular change trends among the three tectonic areas. From the western tectonic area to the central and then to the eastern one, the distribution scale of tight oil changes from small to large and then to middle, and the number of tight oil distribution horizon decreases from the Upper Permian to the Middle Jurassic and finally to the Lower Cretaceous. The generation conditions of tight oil changed from bad to good and to relatively good. The types of tight oil reservoirs change from multiple and complex to relatively complex and then to relatively simple. The reservoir performance of tight oil reservoirs changes from relatively good to relatively poor and to relatively good, while permeability changes from relatively high to relatively low and to relatively high. The conditions of tight oil migration and accumulation change from relatively poor to good and to relatively good, and the types of tight oil reservoirs change from more to less and back to more. The exploration and development potential of tight oil is the largest in the western tectonic area, followed by the central and then the eastern one. The tight oil basins and tight oil accumulations in China and USA have both commonalities and obvious differences. The fundamental reasons for the differences are the stability of structures and the heterogeneity of sedimentary facies. The tight oil basins in China have poorer tectonic stability and continental deposition, while the tight oil basins in USA have better structural stability and marine deposition. As a result, the hydrocarbon generation capacity of tight oil basins in China is worse than that in USA, but the reservoir conditions are generally better than those in USA. The accumulation mechanism and model of tight oil enrichment in China are more complex than those in USA. The quality of tight oil in USA is generally better than that in China. The size of tight oil basins in USA and the exploration and development potential of tight oil are greater than those in China.
Pore structure and physical properties of Quaternary weak diagenetic shales
TANG Xianglu, JIANG Zhenxue, SHAO Zeyu, HOU Zesheng, HE Shijie, LIU Xiaoxue, WANG Yuchao
2022, 44(2): 210-218. doi: 10.11781/sysydz202202210
Abstract(469) HTML (163) PDF-CN(75)
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The biogas of Quaternary weak diagenetic shale has a wide exploration prospect, and the understanding of pore structure and physical properties of these shales is conducive to promote the geological theory of shale biogas reservoir. The Quaternary weak diagenetic shale from the Sanhu area of Qaidam Basin was employed as an example in this study, to study the pore structure and physical properties by the means of scanning electron microscopy, thin section observation, X-ray diffraction of whole-rock samples, overpressure pore permeability determination, relative permeability of gas-water etc. Results show that there are three types of lithofacies for the Quaternary weak diagenetic shales including clay shales, mixed shales and felsic shales, and pores appeared to include intergranular pores, inner pores of brittle mineral grains, inner pores of clay mineral grains and organic pores. The pore size of felsic shale is large, mainly micron pores. The pore size of clay shale and mixed shale are dominated by nano-scale pores. The peak porosity and permeability of Quaternary weak diagenetic shale distribute in the range of 15%-30% and (0.1-10) ×10-3 μm2, respectively, and significantly reduce under overburden conditions. The residual water saturation after displacement is high (with an average value of 58.7%). Due to clay expansion, the effective pore space is reduced and the fluidity of gas and water is restrained, resulting in very low relative permeability of gas and water in the two-phase co-flow zone.
Geological characteristics and exploration direction of continental shale gas in Jurassic Daanzhai Member, Sichuan Basin
FENG Dongjun
2022, 44(2): 219-230. doi: 10.11781/sysydz202202219
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Productive breakthroughs have been achieved for the exploration and development of marine shale gas in the Sichuan Basin, and 6 shale gas fields have been built including Fuling, Weiyuan, Changning, Zhaotong, Weirong and Yongchuan. Continental shale gas is an important exploration replacement layer series with great potential. By the approaches of whole rock X-ray diffraction, TOC content, carbon isotope of kerogen, organic petrology, combined determination of high-pressure mercury injection and nitrogen adsorption, argon ion polishing and scanning electron microscope, and physical property test, the formation conditions of shale gas in the Jurassic Daanzhai Member of the Sichuan Basin were discussed, and the main controlling factors of shale gas enrichment were proposed. Results show that continental shale in the Jurassic Daanzhai Member in the Sichuan Basin is featured by rapid lithofacies changes, strong heterogeneity, frequent interbedding of shale, sandstones and limestones, low organic matter abundance, TOC ranging from 0.04% to 3.89% with type Ⅱ2 and Ⅲ of organic matters, low degree of thermal evolution with Ro values ranging from 1.10% to 1.83%, producing both condensate oil and wet gas. Continental shale has high porosity, ranging from 0.95% to 8.42%, There are mainly inorganic mineral pores dominated by micropores and mesopores. The average gas content of field test is 0.96 m3/t. It is clear that semi-deep lacustrine facies, favorable lithofacies assemblage, fractures and preservation conditions are the main controlling factors of continental shale gas enrichment. Based on the analysis of main controlling factors, highlighting the quality and thermal evolution degree of continental shale, combined with preservation conditions and engineering technical conditions, an evaluation criterion of favorable areas for continental shale gas in the Daanzhai Member in the Sichuan Basin was established. Combined with GIS integrated spatial superposition technology, several favorable zones were proposed, including the southwest of Yuanba, the southeast of Langzhong, Yilong, the northwest of Fuling and the northwest of Jiannan areas.
Residual strata and hydrocarbon accumulation model of marine sediments in Subei Basin
PAN Wenlei, PENG Jinning, ZHAI Changbo, LI Haihua, QIU Jianhua, CAO Qian, LI Fengxun, LU Yongde
2022, 44(2): 231-240. doi: 10.11781/sysydz202202231
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Based on the understandings of previous studies and exploration results, with the analyses of regional geophysical profiles and drilling data, it was discussed in this paper the deformation and distribution of marine sediments in the northern Jiangsu area under the superimposed transformation of Indosinian-Yanshanian compressional structures and Himalayan extensional structures. On this basis, the possible types of hydrocarbon accumulation and their key controlling factors of the study area were summarized by comprehensive analysis of accumulation assemblage. Results indicate that: (1) Bounded by Huaiyin-Dongtai fault, the Lower Paleozoic strata dominate the remaining strata of the west side, which basically show a stratum inversion in vertical direction and gradually change from old to new from north to south. The remaining strata of the east side are dominated by the Upper Paleozoic, which are normally distributed vertically and gradually change from old to new from north to south. (2) There are four types of hydrocarbon accumulation related to marine strata in the northern Jiangsu area, including early-stage primary-generation and residual type, late-stage new-generation and ancient-storage type, late-stage ancient-generation and new-storage type, and ancient-generation and ancient-storage type. For the early-stage primary-generation and residual type, two factors must be occurred: the favorable area for early accumulation and the weak degree of reconstruction and damage in the Yanshanian period. For the late-stage new-generation and ancient-storage type, the connection between continental hydrocarbon kitchen and marine reservoir is needed. For the late-stage ancient-generation and new-storage type, there must be late hydrocarbon generation kitchen and vertical migration channel to continental reservoir. For the late-stage ancient-generation and ancient-storage type, there must be late hydrocarbon generation kitchen and vertical regional cap rocks. The late-stage ancient-generation and new-storage type is a favorable target for recent breakthroughs in marine exploration, and the late-stage ancient-generation and ancient-storage type is favorable for further exploration.
Effectiveness of marine carbonate source rocks: a case study of Middle Triassic Leikoupo Formation in Western Sichuan Depression
MIAO Jiujun, WU Xiaoqi, SONG Xiaobo, ZHENG Lunju, CHEN Yingbin, ZENG Huasheng
2022, 44(2): 241-250. doi: 10.11781/sysydz202202241
Abstract(840) HTML (312) PDF-CN(76)
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The Middle Triassic Leikoupo Formation (T2l) has been regarded as one of the most important strata for natural gas exploration in the Western Sichuan Depression of the Sichuan Basin. The main gas source has not been determined due to the controversy on the effectiveness of the T2l marine carbonate source rocks and exploration direction is breezing. Integrated studies on organic petrology and organic geochemistry indicate that, the organic macerals of kerogen in the T2l carbonate rocks in the Western Sichuan Depression are mainly consisted of sapropelic amorphous bodies. The total organic carbon (TOC) contents of both algal laminae and non-laminae sections insignificantly varied. The TOC content of the 3rd member of T2l is positively correlated with the content of clay minerals and negatively correlated with the content of carbonate minerals. If carboxylate is included to be calculated for these carbonates, the TOC content show increments no more than 0.2%. The T2l carbonate rocks in the Western Sichuan Depression mainly display low organic abundance and hydrocarbon potential, and only6.13% of the studied samples reach the standard values of effective source rocks, moreover, relative organic-rich layers are limitedly distributed. It is concluded that T2l marine carbonate rocks in the Western Sichuan Depression is unlikely to be main source rocks solely, and they can only contribute to the gas accumulation with a limited amount. Therefore, the migrating conditions is an important controlling factor to be considered for the T2l gas exploration, and the exploration of large-scale gas accumulation should focus on the areas with developed faults connecting the underlying Upper Permian source rocks.
Key controlling factors and enrichment mechanisms of tight reservoirs in 6th member of Triassic Yanchang Formation, Chaishangyuan area, southeastern Ordos Basin
WANG Zhuo, ZHAO Jingzhou, MENG Xuangang, ZHAO Shihu, SHEN Zhenzhen, ZHANG Heng, GAO Feilong
2022, 44(2): 251-261. doi: 10.11781/sysydz202202251
Abstract(481) HTML (156) PDF-CN(61)
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Chaishangyuan area locates in the Qilicun Oilfield of the southeastern Ordos Basin, the first onshore oil field discovered in China, and its main layer for oil-producing is the 6th member of Triassic Yanchang Formation (Chang 6). At present, the comprehensive study on the key controlling factors of Chang 6 tight oil reservoir in this area is not clear. In this paper, a large number of drilling, logging, core, production test and other data, combined with laboratory experimental observation were carried out to progress the understanding of the factors controlling reservoir formation. In addition, the concepts of the ratio of underlying sand thickness to formation thickness and the ratio of overlying mud thickness to formation thickness were introduced to comprehensively analyze the forming characteristics of Chang 6 reservoir in the study area and the controlling effects of source rocks, reservoirs, structures, caprocks and migration conditions on Chang 6 tight reservoirs. The Chang 6 tight reservoir in the study area is a lithologic reservoir with undeveloped edge and bottom water, which has the characteristics of clustered and quasi-continuous distribution, and its formation and distribution were controlled by four factors: hydrocarbon source, transport condition, reservoir and direct caprock, and the controlling effect of the four factors on the reservoir is weakened in turn. In the eastern area where source rock quality is poor, crude oil was mainly enriched in the lower strata where sand bodies were well developed, while in the western area where source rock quality is relatively better, the enrichment of crude oil was more controlled by caprock and transport conditions. The better the coupling relationship between them, the more conducive to reservoir formation.
Accumulation of natural gas hydrate based on migrating system: a case study of H zone of Qiongdongnan Basin
FAN Qi, LI Qingping, WU Tao, LI Lixia, PANG Weixin, ZHU Zhenyu
2022, 44(2): 262-269. doi: 10.11781/sysydz202202262
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Gas hydrate is greatly developed in the Qiongdongnan Basin which is one of the key exploration targets in the South China Sea, but the geological study of gas hydrate is insufficient. With 3D seismic data interpretation, geochemical data analysis and a large number of investigations, a related research work of H zone in the Qiongdongnan Basin was carried out in this paper, with accumulation system as the main line and focused on migration and transportation system. According to the analysis of 48 sets of geochemical data, the hydrate decomposition gas in H zone has a methane carbon isotope value (δ13C1) of -48.2‰ and a higher content of ethane and propane (C2+=21%), indicating that the gas is mainly thermogenic, and some are mixed gas. Seismic interpretation showed that the Quaternary tectonic activity in H zone was weak, and the NNE-trending gas chimney structure group, polygonal fault-silt complex and submarine slump body constituted the main migrating system and high-quality reservoir in the study area. Based on the gas source characteristics and migrating system of natural gas hydrate in H zone, three accumulation types were proposed, including the gas chimney type hydrate rich in thermogenic gas, the polygonal fracture-silt composite hydrate rich in thermogenic gas, and the submarine slump hydrate rich in thermogenic gas and mixed genetic gas.
In situ occurrence of shale oil in micro-nano pores in Permian Lucaogou Formation in Jimsar Sag, Junggar Basin
LIU Jin, WANG Jian, ZHANG Baozhen, CAO Jian, SHANG Ling, ZHANG Xiaogang, WANG Guijun
2022, 44(2): 270-278. doi: 10.11781/sysydz202202270
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The development of micro-nano pores and throats in shale oil reservoirs has made it complicated and diversified for the occurrence and state of oil, and is difficult to be studied. A case study was carried out with the Middle Permian Lucaogou Formation in the Jimsar Sag of Junggar Basin by the approaches of Field Emission Scanning Electron Microscopy (FESEM), Nuclear Magnetic Resonance (NMR), Laser Scanning Confocal Microscope (LSCM) and nano-CT. The plane porosities of siltstones and dolomitic siltstones in sweet spots of the study area range from 11.0% to 23.5%, and the dissolved pores and intragranular dissolved pores larger than 2 μm account for more than 49.0%. The distribution of oil and pore water has strong differentiation in micro-nano scale, which is controlled by complex factors such as overpressure migration of hydrocarbon generation, pore surface adsorption and oil quality difference in different stages of continuous shale oil accumulation. In sweet spot reservoirs, intermediate oil and free water occur in the center of pores larger than 2 μm, while heavy oil exists on pore surface as thin film. Pores with the size smaller than 2 μm are mainly filled with heavy oil. Intermediate oil is relatively easier to be explored, while heavy oil is a more realistic and feasible target for enhanced oil recovery in the future.
Geochemical characteristics and source of Permian formation water in Hangjinqi area, Ordos Basin
ZHAO Yongqiang, NI Chunhua, WU Xiaoqi, ZHU Jianhui, LIU Guangxiang, WANG Fubin, JIA Huichong, ZHANG Wei, QI Rong, AN Chuan
2022, 44(2): 279-287. doi: 10.11781/sysydz202202279
Abstract(664) HTML (192) PDF-CN(96)
Abstract:
The Permian stratum in Hangjinqi area is one of the important fields to increase gas reserves and outputs in the Ordos Basin in recent years. The studies of the origin and source of formation water are still insufficient due to the complexity of relationship between gas and formation water. Based on the analysis of major components, trace elements, as well as hydrogen and oxygen isotopes, the indication of geochemical characteristics for the source of formation water is then revealed. The Permian formation water in Hangjinqi area is mainly of CaCl2 type, and the average total dissolved solids (TDS) of formation water to the north and south of the Borjianghaizi fault are 52.1 and 41.9 g/L, respectively. Different water chemical parameters indicate favorable formation sealing conditions, and the formation water has experienced strong concentrated metamorphism with beneficial preservation conditions for natural gas. The formation water is mainly terrigenous one after evaporation and concentration, and the stratum has experienced albitization of plagioclase and dolomitization of cements. The δD and δ18O values of the formation water are mainly in the ranges of -81‰ to -75‰ and -12.1‰ to -8.8‰, respectively, suggesting weaker water-rock interaction than that in the Sulige gas field. Due to the mixing of condensate water in regional uplift since the Late Cretaceous or the seepage of surface water along faults, a small number of formation water samples display more negative δD values.
An improved method and indications for the compound specific isotopic analysis of hopanes in source rock extracts
LU Zhongdeng, LIU Yan, CHEN Zulin, FAN Yunpeng, WEN Zhigang, XU Yaohui, NIU Jin, TIAN Yongjing, LIU Bo, XIE Xiaomin, XIE Wei
2022, 44(2): 288-294. doi: 10.11781/sysydz202202288
Abstract(1016) HTML (145) PDF-CN(59)
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With a mixed stationary phase of 5Å molecular sieve/alumina, extracts of various kinds of source rocks are separated by column and sub-fractions dominated by hopanoid compounds were successfully obtained. The sub-fractions are suitable for the direct analysis on GC-IRMS to obtain compound specific isotopic values of hopanes. Comparison is carried out on isotopic signatures of specific hopanes in a lacustrine oil shale (Permian Lucaogou shale, Junggar Basin, NW China) and another Permian marine shale (NW of Sichuan Basin). Results show that the Permian Lucaogou shale had the δ13C values of hopanes distributed between -40.7‰ and -62.7‰, and decrease with the increasing of carbon number. The δ13C values of hopanes in marine shale of Sichuan Basin are apparently heavier, distribute between -20.5‰ and -45.4‰, and they appeared to be firstly decreased and then increased as carbon number increases. In both of the shales analyzed, the variation range of carbon isotopes of hopanes can be more than ±20‰ (±24.9‰ for the Sichuan Basin shale), which indicates multiple contribution to these compounds. The isotopic signatures of hopanes may be constrained by paleoenvironment, sources as well as maturation, however, compound specific isotope of hopanes is still a useful indicator for oil-source correlation.
Effect of evaporative fractionation on the distribution and composition of diamondoids in crude oils: a case study of crude oils from Yangtake structure, Kuqa Depression, Tarim Basim
YANG Xi, BAO Jianping, NI Chunhua, ZHU Cuishan
2022, 44(2): 295-305. doi: 10.11781/sysydz202202295
Abstract(412) HTML (129) PDF-CN(46)
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Two sets of crude oil samples from the Yangtake structure in the Kuqa Depression of Tarim Basin were analyzed with the aid of GC and GC-MS to evaluate the effect of evaporative fractionation on the distribution and composition of diamondoid hydrocarbon in crude oils. The light hydrocarbon signatures of oils from wells YT 5 and YT 101 indicate secondary products of evaporative fractionation for the condensates from the upper reservoirs, and the oils from the lower reservoirs are residuals. Moreover, the distribution and composition of steranes and terpanes in two sets of crude oils appeared to be comparable, suggesting that these oils shared a same source. Evaporative fractionation has imperceptible effect on the distribution and relative abundance of alkyl admantanes and diamantanes, but their concentrations in secondary condensates and residual oils appeared to be significantly varied. For example, the concentration of diamondoids in secondary condensates is much higher than that in residual oils, and the increasing extent of concentration for alkyl admantanes in secondary condensates is much higher than that in residual oils. Therefore, it should be very cautious to use the concentration of diamondoids to determine the degree of maturity of crude oils if evaporative fractionation occurred. However, the effect caused by evaporative fractionation to the maturity parameters such as MAI and MDI is relatively minor and they can still be used as indicators to evaluate maturity of crude oils even with the alteration of evaporative fractionation.
Molecular composition of asphaltene in wellbore blockage on the southern margin of Junggar Basin
LI Erting, JIN Jun, CHEN Liang, LU Feng, SHI Quan, WU Jianxun, ROUZI Dilidaer, ZHANG Yu
2022, 44(2): 306-313. doi: 10.11781/sysydz202202306
Abstract(540) HTML (234) PDF-CN(52)
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Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) was employed to analyze the compositional differences of asphaltene of oil and blockage extracts of well Gaotan 1 on the southern margin of Junggar Basin. The correlation between asphaltene composition and structure and precipitation was discussed, which is important for the research of asphaltene precipitation and accumulation. Results showed that the asphaltene molecules of oil and blockage extracts of well Gaotan 1 are mainly composed of N1, N1O1, O1, O2, O3 and O4 class species. However, the degree of asphaltene condensation in blockage extract is significantly higher than that in oil, and it is enriched with O2, O3 and O4 class species. It indicates that during the flow of formation crude oil in wellbore, the precipitation of asphaltenes with different compositions has a certain selectivity. Asphaltene components with high condensation degree preferentially precipitate and deposit, forming a solid core. Among them, polyoxo-heteroatom compounds have relative strong polarity, which accelerates the precipitation of other asphaltene components in crude oil to form blockage. Asphaltene in blockage extract has a complex molecular structure and a wide range of condensation degree. The DBE values distribute between 9 and 30. Its molecular polar force parameter is larger and the distribution range is wider. Therefore, it is ideal to select a mixed solvent similar to the polar force parameter of blockage asphaltene to remove blockage.
A comparative study on the geochemical characteristics of expelled and retained oil from hydrocarbon generation simulation of Australian Tasmanian oil shale Ⅱ: molecular geochemical characteristics
WU Fenting, XIE Xiaomin, XU Yaohui, LIN Jingwen, ZHANG Lei, XU Jin, MA Zhongliang
2022, 44(2): 314-323. doi: 10.11781/sysydz202202314
Abstract(468) HTML (130) PDF-CN(46)
Abstract:
The Australian Tasmanian oil shale is a special set of source rocks in which a single species of planktonic algae (Tasmanite) is significantly enriched and has relatively lower degree of maturity with equivalent vitrinite reflectance of 0.5%. It can be considered as a good material for artificial maturation experiment. In order to compare the molecular geochemical characteristics of expelled oil and retained oil at different simulation temperatures, a hydrocarbon generation and expulsion simulation experiment was carried out. Results show that: (1) The extracts of original rock sample and the retained oil indicate a reducing environment, while a mixed source region of both reduction and oxidation is indicated by the expelled oil. (2) The maturity-related biomarker parameters (e.g C29 steranes 20S/(20S+20R), C29 hopanes ββ/(αα+ββ) and Ts/(Ts+Tm)) indicate that the retained and expelled oil are mature at 350 ℃ of the experiment. These biomarker parameters in retained oil increase with temperature before the simulation temperature lower than 350 ℃; however, the correlation is poor for expelled oil. When temperature is higher than 350 ℃, the parameters of retained or expelled oil have irrelevant correlation with the simulated temperature. (3) The distribution of C27, C28 and C29 steranes in retained and expelled oil shows variations with maturation degree, and changes fromreverse "L" type, to slightly asymmetric "V" type, and finally to "L" type at 400 ℃. At the same temperature, retained oil and expelled oil are comparable. Therefore, at the same maturity stage, the sterane distribution characteristics is effective for oil source correlation; while at different maturity stages, the comparability of expelled oil and retained oil may vary greatly. It is revealed by this study the differences of molecules between expelled oil and retained oil, as well as the influence of simulated temperature on the parameters. The influence of maturity to the biomarker parameters has to be considered when studies of depositional environment, maturity and oil-source correlation are carried out, especially after the peak of oil generation.
Gas source of BZ19-6 condensate gas field in Bozhong Sag, Bohai Sea area
TONG Zhigang, LI Youchuan, HE Jiangqi, YAO Shuang
2022, 44(2): 324-330. doi: 10.11781/sysydz202202324
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The discovery of BZ19-6 condensate gas field in the Bozhong Sag of Bohai Sea area brought hope and confidence for giant gas fields. Intensive study of the source and genesis of natural gas in BZ19-6 gas field plays an important role for guiding natural gas exploration in the Bohai Sea. Open and sealed system pyrolysis as well as geochemical and numerical simulation show that the high-quality sapropelic lacustrine source rocks with an average TOC content of 3.93% and an IH index of 727 mg/g in the Bohai Sea area mainly generate oil, and only 10% of kerogens in the source rocks crack into gas. For humic-prone source rocks, about 30% of kerogens generate into gas when IH reaches 100 mg/g. However, the humic-prone source rocks still expel gas which is cracked from residual hydrocarbon due to the adsorption of kerogens. The natural gas in BZ19-6 gas field are mainly sourced from Ⅱ1, Ⅱ2 and Ⅲ type source rocks in the third member of Shahejie Formation during mature to high-maturity stages. They are mixtures of kerogen cracked gas and residual hydrocarbon cracking gas sourced from parts of the southwestern Bozhong Sag. The source rocks of the third member of Shahejie Formation in the hydrocarbon supply area mainly discharge oil in the early stage, and changed to gas after 15 Ma, accounting for 82% of the total gas discharge. To find large gas fields in the Bozhong Sag, the targets where source rocks have large gas/oil ratio and mainly expel gas should be focused on.
A new method for the evaluation of the utilization potential of proved undeveloped reserves and its application: a case study of Y reservoir
SU Yinghong
2022, 44(2): 331-336. doi: 10.11781/sysydz202202331
Abstract(585) HTML (174) PDF-CN(50)
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Most of the proven undeveloped reserves are presently low-grade ones. Overall effective utilization is difficult with current economic and technical conditions. Most of the existing methods evaluate overall utilization potential, which is no longer suitable for evaluating the utilization potential of currently-proven undeveloped reserves. In this paper, a case study has been carried out in Y reservoir. According to the heterogeneity of the spatial distribution of reservoir parameters, the selectivity of development technology and the uncertainty of economic parameters, a prediction model of single-well-controlled recoverable reserves under different development technologies is built. Combined with the economic limits of single-well-controlled recoverable reserves under different technical and economic conditions, movable probability can be obtained, and the movable potential of geological reserves can be further calculated. Field application shows that the coincidence rate of the movable potential reserves calculated by the method in this paper and the actual produced reserves reaches 97.2%, which has high accuracy and can meet the needs of field. The research in this paper provides an effective method for the evaluation of the potential of undeveloped reserves.
Classification and evaluation of undeveloped reserves in low-permeability reservoirs based on development technologies
FAN Yumei
2022, 44(2): 337-341. doi: 10.11781/sysydz202202337
Abstract(425) HTML (125) PDF-CN(42)
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Reservoir with low-permeability is the future object of oil exploration and development. After multiple rounds of screening, the remaining reserves have poor grade. Therefore, the applicable conditions of development technology are the key factors for whether the reservoir can be produced. Taking SINOPEC low-permeability reservoirs as an example, it is discussed in this paper for the status of development technology and production conditions of proved undeveloped reserves in low-permeability reservoirs with different permeability levels since the 12th Five-Year Plan. Moreover, the classification of development potential of undeveloped reserves was carried out. Combined with the existing types of hard-to-develop reserves and technological development trends, the future technical requirements and research directions of low-permeability reservoirs were further clarified.
Determination of surface relaxivity for tight sandstone cores based on T2 cut-off value
YU Yue, SUN Yidi, GAO Rui, DA Lina, HOU Jingwei, YANG Mi
2022, 44(2): 342-349. doi: 10.11781/sysydz202202342
Abstract(805) HTML (172) PDF-CN(59)
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The surface relaxivity for tight cores is commonly determined by the methods of average pore radius (ARS) or surface-to-volume ratio (SVR). The ARS method is time-consuming, and permanent damage to core samples will occur due to the injection of mercury. In this study, a non-destructive method is proposed, instead of the ARS method, to calculate the surface relaxivity of tight core samples based on T2 cut-off value. Firstly, surface relaxivity is calculated using the new method (pseudo T2 cut-off, PTC). Secondly, the calculated surface relaxivity of ARS and SVR methods are compared. Thirdly, the T2 spectrum is converted into pore diameter distribution by choosing appropriate surface relaxivity. Finally, residual oil distribution can be obtained. The ultimate surface relaxivity values for tight sandstone core samples are 5.85, 2.98, 4.66, and 2.17 μm/s. Moreover, we obtained the pore diameter distribution in mesopores and macropores by jointly using these three methods. Residual oil is mainly distributed in micropores and mesopores. The new method proposed in this study is nondestructive and is helpful to quickly and efficiently determine the surface relaxivity of tight cores.
Measurements of position-specific carbon isotopic compositions in propane by on-line Gas Chromatography-Pyrolysis-Gas Chromatography-Isotope Ratio Mass Spectrometer (GC-Py-GC-IRMS) and its preliminary application
MA Yuanyuan, TAO Cheng, BA Liqiang, WANG Jie, LI Jipeng, LI Luyun, SUN Yongge
2022, 44(2): 350-356. doi: 10.11781/sysydz202202350
Abstract(623) HTML (251) PDF-CN(57)
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In this study, an on-line Gas Chromatography-Pyrolysis-Gas Chromatography-Isotope Ratio Mass Spectrometer (GC-Py-GC-IRMS) was established to conduct position-specific isotope analysis (PSIA) by enrichment of compound interested, chromatographic separation, instantaneous pyrolysis and isotope ratio measurement. Propane, as its instantaneous pyrolysis can be kinetically controlled, was selected for tests. The molar conversion (mol%) of propane during pyrolysis and the carbon isotopic compositions of pyrolysis products upon temperature sequence show that the optimal pyrolysis temperature of propane is 780-820 ℃ for its position-specific carbon isotope analysis. Integrated with carbon isotopic fractionation during the propane pyrolysis, the carbon isotopes of central and terminal carbon were successfully calculated. Two natural gas samples from the Daniudi Gas Field, Ordos Basin were collected for central and terminal carbon isotope measurements in propane. Similar δ13C values of central carbon of propane in natural gas from the Ordovician and Carboniferous-Permian reservoirs could be indicative of the same source strata. While 13C-enrichment in the terminal C-atom of propane in natural gas from the Carboniferous-Permian reservoirs probably indicates that natural gas accumulated in the Carboniferous-Permian reservoir maybe have experienced a higher thermal maturation compared to that from the Ordovician reservoirs. The results suggest that the PSIA in propane can be a potentially powerful tool to probe the mechanisms on natural gas generation.
Crystal characteristics of fibrous calcite veins based on Electron Back Scattered Diffraction (EBSD)
ZHAO Lanquan, LI Zhipeng, ZOU Kaizhen, MA Xiaonan, LIU Zhenyang, YIN He, LEI Liqing, YU Baojun, MA Cunfei
2022, 44(2): 357-364. doi: 10.11781/sysydz202202357
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Abstract:
Calcite veins are widely developed in organic-rich shale, and their petrological characteristics and genetic mechanism are the focus of research. The Electron Back Scatter Diffraction (EBSD) can characterize the micro-structure and orientation of mineral crystals in situ, which has been widely used in the field of material science and has been rapidly developed in the field of geology. In order to clarify the crystal characte-ristics of fibrous calcite veins in organic-rich shale of the Longmaxi Formation in the Sichuan Basin, EBSD was used to characterize the mineralogical and crystallographic characteristics of calcite veins. The calcite veins are mainly composed of calcite and quartz. Calcite is the main body, with an average grain size of 372 μm, while quartz is mainly distributed at the interface of calcite lamina. The calcite crystals in calcite veins belong to trigonal[JP] or rhombohedral system, and the corresponding unit cell is trigonal or rhombohedral. The lattice parameters are a0=b0=4.99 Å, c0=17.061 Å, α=β=90°, γ=120°, respectively. Calcite veins have a certain preferred orientation on longitudinal section, which is due to the development of polysynthetic twin crystals in calcite grains. The adjacent twin crystal stripes have different crystal orientations, and the crystal misorientation is 75° while the alternate twin stripes have the same crystal orientation, and the crystal orientation of the same twin stripe is the same. In calcite grains, perfect cleavage occurs in groups with sharp angle with twin crystal stripes. Both cleavage and twin crystal stripes are formed by tectonic compression and shearing during the crystallization of calcite, and the maximum principal stress direction is parallel to the twin crystal stripes.
Temperature-sensitivity of underground gas reservoir storage and its effect on well deliverability
ZHENG Shaojing, ZHENG Dewen, SUN Junchang, LI Chun, WU Zhide, ZHU Sinan, LIU Xianshan
2022, 44(2): 365-372. doi: 10.11781/sysydz202202365
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Abstract:
The temperature change under alternating injection-production conditions of underground gas reservoir storage is a key factor for permeability and even deliverability. To explore the temperature-sensitivity of sandstone reservoir permeability and its effect on the deliverability of gas well, experimental studies at multiple rounds were carried out within the realistic temperature range of underground gas storage to simulate more accurately. Results show that: (1) Reservoir permeability negatively correlates with temperature. Permeability exhibits a hysteresis effect under cyclic alternating temperature, and the hysteresis effect gradually weakens with the variation of temperature. (2) Permeability and temperature are linearly correlated, and the hysteresis effect does not change with temperature, which is different from stress-sensitivity. (3) Based on the experimental results, a deliverability equation modified with temperature-sensitivity was established. Calculation shows that, ignoring the temperature-sensitivity of permeability will underestimate the performance of gas well, and its effect will aggravate with the increasing elevation and injection flowrate.
2022, 44(2): 373-373.
Abstract(254) PDF-CN(49)
Abstract:

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