石油实验地质

2018, 40(4): .

Abstract(333) PDF-CN(119)

Abstract:

Geological characteristics of ‘strata-bound’ and ‘fault-controlled’ reservoirs in the northern Tarim Basin: taking the Ordovician reservoirs in the Tahe Oil Field as an example

LU Xinbian, YANG Min, WANG Yan, BAO Dian, CAO Fei, YANG Debin

2018, 40(4): 461-469. doi: 10.11781/sysydz201804461

Abstract(2382) PDF-CN(345)

Abstract:
The marine facies carbonate reservoirs in the northern Tarim Basin were studied using high-resolution 3D seismic data, as well as a large amount of actual drilling data and dynamic production data. The carbonate fractured-and-vuggy reservoirs in the study area were distinguished into two types:strata-bound karst reservoir and fault-controlled karstic-fault reservoir. The former was developed in the buried hill of the paleokarst system in the northern Tarim Basin, which can be further divided into two subtypes:residual hill type and paleo-channel type. Reservoirs are characterized by "vertically superimposed and quasi-stratified distribution" on the macroscopic scale, and feature large changes in reservoir space, coexistence of caves, pores and fractures, relatively contiguous reservoir units, and complex oil-water relationships. The karstic-fault reservoir mainly developed in the covered area of Middle-Upper Ordovician, which is controlled by different ordered strike slip faults and related dissolutions. The karstic-fault reservoir is a special type of oil and gas reservoir existing in nature. It has unique hydrocarbon accumulation characteristics, such as different sections of accumulation along fault belt, across different strata vertically and discontinued distribution and so on. The karstic-fault reservoir is a new trap type and a new target in deep carbonate oil and gas exploration and development.

Characteristics and dominating factors of lamellar fine-grained sedimentary rocks: A case study of the upper Es₄ member-lower Es₃ member, Dongying Sag, Bohai Bay Basin

WANG Miao, LU Jianlin, ZUO Zongxin, LI Hao, WANG Baohua

2018, 40(4): 470-478. doi: 10.11781/sysydz201804470

Abstract(1798) PDF-CN(291)

Abstract:
A case study was made in the Dongying Sag to meet the needs of shale oil zone evaluation.The characteristics and dominating factors of lamellar fine-grained sedimentary rocks from the upper Es₄ member to the lower Es₃ member in the Dongying Sag were studied based on core and cast thin section observations combined with drilling and logging data. By comparing the lamellar fine-grained sedimentary rocks in ancient lakes with those in recent lakes, five types of laminae were identified, including silty, clay, carbonate, organic-rich and mixed ones. The origin and sedimentary environment of each type of laminae was analyzed. The study considered both macroscopic and microscopic features of laminae and the factors of sedimentary source, transport process and depositional environment, and made a conclusion that tectonic movement, climate change and source determined laminar characteristics as follows. (1) From the upper Es₄ member to the lower Es₃ member, the distribution zone of lamellar fine-grained sedimentary rocks migrates from east to west, which is compatible with the evolution tendency of the tectonic subsidence center. Different laminar types developed in different tectonic units. The organic-rich laminae are mainly distributed in the deep depression and the southern slope. The silty laminae occur in the central anticline and the southern slope. The carbonate laminae are distributed in the inner slope. The mixed laminae are found in the central anticline and the southern slope. The clay laminae are distributed widely in all the above mentioned tectonic units. (2) An arid climate led to high lake salinity and carbonate laminae were deposited. So the carbonate laminae are relevant to an arid climate. The organic-rich laminae tend to be deposited in damp climates, which are well-developed in lacustrine transgressive system tracts from the upper Es₄ member to the lower Es₃ member. (3) Provenance has a significant control on limestone laminae distribution. A development mode of lamellar fine-grained sedimentary rocks was proposed.

Effective reservoir spaces of Paleogene shale oil in the Dongying Depression, Bohai Bay Basin

BAO Youshu

2018, 40(4): 479-484. doi: 10.11781/sysydz201804479

Abstract(2153) PDF-CN(246)

Abstract:
A comprehensive research method to determine effective reservoir spaces of shale oil was formulated based on GRI shale porosity and oil saturation testing, high-pressure mercury injection and geochemical analysis. The pore size distribution, the smallest pore diameter limit for oil occurrence, and the porosity condition for recoverable oil from the Paleogene shale in the Dongying Depression were discussed. The relationship between porosity and pore size distribution showed that shale porosity is negatively correlated to the volume portion of pores smaller than 10 nm (diameter), while positively correlated to the volume of pores with diameter larger than 10 nm, and that the pores wider than 10 nm are the critical contributor to the reservoir space of high-porosity shale. Shale oil mainly exists in pores wider than 10 nm. The statistical relationship between OSI (Oil Saturation Index) and porosity showed that the shale with a porosity above 6.5% is favorable for the occurrence of recoverable oil.

Relationship between porosity of Yingcheng sand-body migration channel and hydrocarbon injection of Dongling area, Changling Fault Depression, Songliao Basin

LU Yunqian, JIANG Youlu, WANG Wei, ZHU Jianfeng, LIU Jingdong

2018, 40(4): 485-492. doi: 10.11781/sysydz201804485

Abstract(1496) PDF-CN(168)

Abstract:
Hydrocarbon accumulation is a geological process. The reconstruction of reservoir porosity in a crucial period of hydrocarbon accumulation can help in quantitatively reconstructing geological conditions of that accumulation. A diagenetic sequence of the Dongling area, Changling Fault Depression was established based on a variety of technologies such as cast thin section interpretation, SEM observation, fluid inclusion analysis, mercury intrusion and petrophysical tests. Based on the timing of the diagenetic sequences of migration channel and the hydrocarbon accumulation period, the physical characteristics of a sand-body migration channel during each hydrocarbon accumulation period were restored by reservoir porosity inversion. Finally, combined with the sedimentary facies of the study area, the spatial distribution range of the advantageous hydrocarbon migration channel was clarified. The sand-body migration channel of the Yingcheng Formation in the study area mainly occurs during the A1 period of medium diagenetic stage. Compaction plays a controlling role, acid dissolution improves porosity, and cementation makes the migration channel more dense. The hydrocarbon source rocks of the Shahezi Formation generated hydrocarbon in two stages, with two hydrocarbon charges. After the oil and gas entered the Yingcheng Formation sand body, the transport performance of the sand body transport layer in the Yingcheng Formation has a significant influence. The oil and gas mainly migrated in the northwest oriented sand body with good physical properties and high connectivity, and finally accumulated in the eastern nose.

Provenance system of the Late Cretaceous Sifangtai Formation in the south of Daqing placanticline of the northern Songliao Basin

XIAO Peng, JIN Ruoshi, TANG Chao, LIU Huajian, DENG Yonghui, WEI Jialin, XU Zenglian

2018, 40(4): 493-501. doi: 10.11781/sysydz201804493

Abstract(1292) PDF-CN(166)

Abstract:
The provenance system restricted the flow direction of interlayer water and the distribution characteristics of sandstone reservoirs. The previous analysis of the upper Cretaceous provenance system in the northern Songliao Basin was focused below the Sifangtai Formation, and there was a lack of reports on the origin of the Sifangtai Formation. We systematically studied the characteristics of source systems of the Sifangtai Formation at the southern end of Daqing placanticline in the northern Songliao Basin using regional geological understanding, through sedimentary structural analysis, sand body distribution pattern and heavy mineral analysis, and identified the source direction and parent rock type. The results showed that the main parent rocks of the Sifangtai Formation are intermediate acid magmatic rocks and intermediate and high-grade metamorphic rocks. Through contrast analysis with the source regions, it was concluded that the provenance of the Sifangtai Formation in the south of Daqing placanticline was mainly from the Zhangguangcai Ranges, the eastern Jilin-Heilongjiang provinces and the southeastern region of the basin.

Structural styles of Huangqiao area, Lower Yangtze region

LIU Zhihua

2018, 40(4): 502-507. doi: 10.11781/sysydz201804502

Abstract(735) PDF-CN(147)

Abstract:
The Huangqiao area is a key exploration target for oil and gas in the Lower Yangtze region. However, due to strong later transformation and complex structure, the oil and gas exploration work is restricted in this area. The Huangqiao area experienced three stages of tectonic movement, forming a large number of normal faults, reverse faults and folds, resulting in various structural styles. Three types of structural styles were identified according to their causes, including compressive structures, extension structures and inversion structures, based on the regional tectonic analysis and the fine scale interpretation of 3D seismic profiles. There are three tectonic zones, including the northwest slope zone, the central uplift belt and the southeast low-lying zone. The central uplift belt, as a stable structure area, is favorable for hydrocarbon exploration.

Mud shale diapir structure and hydrocarbon distribution in the Rio del Rey Basin of Cameroon

YUAN Jingju, DING Yiping, SU Yushan, CHEN Zhankun, KHALID Abuganaya

2018, 40(4): 508-512. doi: 10.11781/sysydz201804508

Abstract(1964) PDF-CN(141)

Abstract:
The Rio del Rey Basin is located in Cameroon and the northeast of the Niger Delta. It is rich in oil and gas resources, and has more than 30 years of oil and gas exploration and development history. Long-term regression and delta sedimentation since the Eocene have formed the present Rio del Rey passive continental margin basin. Three stratigraphic units developed, including the Akata, Agbada and Benin formations respectively from bottom to top. In the process of delta progradation, the extensional, shale diapir and toe thrust tectonic zones were formed from north to south and also from onshore to offshore because of the gravity action of continental margin and the plastic over-thrusting of deltaic mudstone. In the mudstone diapir tectonic zone, many diapir anticlines or faulted-anticlines and lithologic traps related to mudstone diapirs or mudstone ridges have been formed. The large oil and gas fields that have been discovered to date are mainly related to these traps. At the same time, the activity of mudstone diapirs also provided superior conditions of reservoir and migration, which promoted the oil and gas enrichment and high yield in the diapir tectonic zone. Therefore, the mudstone diapir tectonic zone and the traps associated with mudstone diapirs are still the main targets for further exploration potential in the Rio del Rey Basin.

Petroleum geology and hydrocarbon accumulation pattern in the Lake Albert Basin of East African rift system

CUI Ge, JIN Aimin, WU Changwu, DING Feng, SHI Danni

2018, 40(4): 513-518. doi: 10.11781/sysydz201804513

Abstract(1938) PDF-CN(160)

Abstract:
The evolution and tectonic-sedimentary stratigraphic features of the Lake Albert Basin in the East Africa were studied using geological, seismic and drilling data. The petroleum geology features and the accumulation pattern and enrichment conditions were summarized. The basin was mainly affected by the tectonic movement of the East Africa rift system, forming a long and narrow (semi-) graben with deep faults on both sides. The sedimentary strata are dominated by Neogene clastic rocks, including mudstone, sandstone and conglomerate. Depositional fill is characterized by a river-(fan) delta-lacustrine sedimentary system. The Upper Miocene organic-rich shale, Miocene-Pliocene fluvial-(fan) delta sandstone and fine lacustrine mudstone formed a favorable source-reservoir-cap assemblage vertically. There are a large number of structural traps. Hydrocarbon generated in depressions, migrated vertically and laterally, and finally accumulated in upper formations, resulting in multiple sets of stacked reservoirs. High-quality sand bodies and vertical faults controlled the effective migration of oil and gas, and structural traps developed by fault control are the main sites for oil and gas accumulation.

Elemental geochemical characteristics and geological significance of Majiagou Formation, eastern Ordos Basin

WANG Linlin, FU Yun, FANG Shijie

2018, 40(4): 519-525. doi: 10.11781/sysydz201804519

Abstract(1325) PDF-CN(232)

Abstract:
Rock type and the distribution of major and trace elements of the Ordovician Majiagou Formation in the eastern Ordos Basin were used to elucidate the sedimentary environment and the origin of the sediments. The results showed that the main rock types in the Majiagou Formation are carbonate and evaporite rocks. The CaO and MgO contents are high and vary widely. SiO₂, Al₂O₃, Fe₂O₃, K₂O, Ti₂O and other major representatives of a terrigenous component have low contents, indicating marine facies deposits. The average contents of Sr and U in the trace elements are slightly enriched compared with the upper crust, and the average contents of Ba, Rb, Zn, and Cr are lower than those in the upper crust, indicating a poor terrigenous supply. The distribution curves of Mgo/Cao, Rb/Sr, Sr/Cu and Sr/Ba ratios indicated that the Majiagou Formation was deposited in a marine environment under a dry and warm climate accompanying a dry-wet climate evolution. During the O₂m₂, O₂m₄ and O₂m₅ stages, there was a brief transition from dry-hot climate to relatively humid climate.

Features and hydrocarbon potential of source rocks in the Hongdi 1 well, Hongmiaozi Basin, Liaoning province

WANG Dandan, ZHANG Wenhao, LI Shizhen, ZHOU Xingui, LIU Weibin

2018, 40(4): 526-531. doi: 10.11781/sysydz201804526

Abstract(1128) PDF-CN(169)

Abstract:
The Hongmiaozi Basin is one of the newly-identified Mesozoic sedimentary basins in the southeastern segment of the periphery of Songliao Basin. The degree of basic oil and gas geology research in the Hongmiaozi Basin is extremely low. The source rock types, organic geochemical features and hydrocarbon generation potential in the basin are unknown, which constrains the exploration and development of oil and gas resources in the basin. Based on the new drilling results of well Hongdi 1, some core samples were collected and tested for organic matter abundance, type and maturity of dark mudstone. The source rocks in the study area are mainly composed of black mudstone and silty mudstone in the Xiahuapidianzi Formation, Lower Cretaceous. The dark mudstone has a cumulative thickness of 101.16 m, and the single thickest layer is 24.85 m, finding fifty layers with oil and gas shows. The experimental results showed that source rocks of the Xiahuapidianzi Formation in the Hongmiaozi Basin have a medium organic matter abundance. The types of organic matter are mainly Ⅱ₂-Ⅲ, partly Ⅱ₁ and Ⅰ. The vitrinite reflectance ranges from 1.31% to 1.84%, with an average of 1.53%, indicating for a high maturity stage. Scanning electron micro-scopy analysis revealed that the mineral composition of source rocks consisted of clay and brittle minerals with average contents of 58.4% and 41.4%, respectively. Microporosity developed between muddy crystal grains, which is conducive to the improvement of storage space and migration channels, and to facilitate late artificial fracturing. The study showed that source rocks in the Hongmiaozi Basin have some potential for hydrocarbon generation, and there is an urgent need for continuous and intensive research.

Compound-specific carbon stable isotope analysis of 16 polycyclic aromatic hydrocarbons in sediments by Gas Chromatography-Combustion-Isotope Ratio Mass Spectrometry (GC-C-IRMS)

LU Yan, WANG Xiaoyun, CAO Jianping

2018, 40(4): 532-537. doi: 10.11781/sysydz201804532

Abstract(1597) PDF-CN(184)

Abstract:
A method for the compound-specific carbon stable isotope analysis of 16 polycyclic aromatic hydrocarbons (PAHs) in ocean sediments by Gas Chromatography-Combustion-Isotope Ratio Mass Spectrometry (GC-C-IRMS) was established for monitoring PAHs, tracing pollutant sources and controlling pollution. The compound-specific carbon stable isotope of 16 PAHs was determined by Elementary Analyzer-Isotope Ratio Mass Spectrometry (EA-IRMS) with a peak area deviation of 0.03‰-0.15‰ (n=10) (<0.2‰). The isotope fractionation of the 16 PAHs caused by High Performance Thin Layer Chromatography (HPTLC), injection volume of GC, purge time or sampling concentration was investigated using GC-C-IRMS and PAH-MIX. The results indicated that there was no apparent isotope fractionation during the whole process of analysis. Some calibration curves were obtained according to the changes of GC-C-IRMS data corresponding to the concentrations of PAH-MIX and the differences between GC-C-IRMS and EA-IRMS data, and the R² value was higher than 0.99. The curves were used to determine the compound-specific carbon stable isotope of 16 PAHs in sediments, which offers strong evidence for tracing the source of PAHs in ocean sediments.

FTIR study of hydrocarbon generation reactions of coal

ZHANG Shuang, YAO Suping, YIN Hongwei

2018, 40(4): 538-544. doi: 10.11781/sysydz201804538

Abstract(623) PDF-CN(146)

Abstract:
The thermal evolution characteristics of bulk coal as well as chemical structural characteristics of aliphatic and aromatic groups within an artificially matured coal series were characterized and analyzed combining the FTIR analysis with a computer curve-fitting method. The results showed that except for thermal cracking reactions, the aromatization reactions of aliphatic structures and the condensation reactions of aromatic structures also played important roles in the hydrocarbon formation of coal. Both contents of aliphatic hydrogen and aromatic hydrogen were subjected to more than one type of chemical reaction. Functional group analysis alone cannot accurately reflect the mechanism of hydrocarbon generation reactions and the hydrocarbon generation potential of coal. Further investigations on the thermal evolution characteristics of aliphatic and aromatic chemical structures indicated that the initial phase of hydrocarbon generation of coal is dominated by the formation of oil products due to the prior cleavage of long-chain aliphatic groups with lower bond energies. The highest yield of oil products is reached at 325℃. Except for generating gaseous hydrocarbons via further thermal cracking, a significant proportion of long chain aliphatic structures are involved in aromatization reactions in the range of 325-400℃, leading to the increased content of aromatic hydrogen of coal. With increasing temperature, the short chain aliphatic substituents begin to cleave from the β-position to aromatic rings, indicating the methylation of aliphatic substituents. At higher temperature stage further demethylation takes place with the breaking of methyl and bridged bonds connected to aromatic rings. The condensation reactions during hydrocarbon formation of coal take place in stages. The lower temperature phase in the range of 300-400℃ is dominated by the condensation of aromatization products. Due to the steric hindrance of substituents and bridged bonds, the condensation between the primary aromatic structures of coal mainly takes place along with the demethylation effect in the range of 500-600℃.

Change of physical properties at different heating rates, time and water content for oil shale

XU Liangfa, MA Zhongliang, ZHENG Lunju, BAO Fang

2018, 40(4): 545-550. doi: 10.11781/sysydz201804545

Abstract(2618) PDF-CN(123)

Abstract:
An oil shale in situ pyrolysis simulation experiment with different heating rates, heating time and water contents was carried out to assess the influences of these parameters on the physical properties of oil shale in situ conversion production. The physical properties of oil shale in situ conversion production were analyzed using nuclear magnetic resonance T₂ spectra. The results showed that the slow heating rate (the increase of reaction time) was beneficial to the development of organic micro-pores, while the increase of heating rate was beneficial to the development of micro-cracks. With the increase of constant temperature time, the physical properties of oil shale can be improved, and small pores gradually develop into relatively larger pores. High-temperature water may be used as a catalyst, reactant and solvent to participate in the reaction. On the one hand, it is beneficial to react with organic matter to generate organic pores; on the other hand, high-temperature water may react with oil shale minerals, thus improving the physical properties of oil shale.

Thermo-compression simulation of hydrocarbon generation and expulsion of inter-salt dolomitic shale, Qianjiang Sag, Jianghan Basin

PAN Yinhua, LI Maowen, SUN Yongge, LI Zhiming, LI Luyun, LIAO Yuhong

2018, 40(4): 551-558. doi: 10.11781/sysydz201804551

Abstract(1112) PDF-CN(143)

Abstract:
The inter-salt dolomitic shales in the Qianjiang Sag of Jianghan Basin have a potential to form considerable amounts of shale oil resources. The study on the thermal evolution of inter-salt dolomitic shales plays an important guiding role on shale oil resource evaluation as well as oil exploration and development. A thermo-compression simulation of hydrocarbon generation and expulsion was performed with an immature dolomitic shale source rock from the Qianjiang Formation. The quantitative yields of the products generated from source rocks with an increasing thermal maturity were calculated to explore the hydrocarbon generation and expulsion of inter-salt dolomitic shales. The results showed that there is a precursor-product relationship between residual oil and expelled oil, suggesting that oil generation is a simultaneous two-step process, namely kerogen→bitumen→oil. A strict Boltzmann distribution was observed between TR and EasyR_o value in this study, which can be used as a method to describe hydrocarbon expulsion during maturation within the oil window. Within a TR range of 0-25%, the contents of group fractions of expelled oil show slight changes. However, within a TR range of 25%-100%, the content of asphaltene fraction rapidly decreases while the contents of both saturated and aromatic fractions increase significantly. This indicated that bitumen is the main source of saturated and aromatic hydrocarbons that are gradually enriched in expelled oil. Meanwhile, the generated light hydrocarbons improve the liquidity of hydrocarbon fluid and thus enhance hydrocarbon expulsion, which results in a rapid increase in the product yield of expelled oil in this stage.

Microscopic pore structure characteristics of shale reservoir based on low-temperature argon adsorption experiments

ZHU Hanqing, JIA Ailin, WEI Yunsheng, JIA Chengye, JIN Yiqiu, YUAN He

2018, 40(4): 559-565. doi: 10.11781/sysydz201804559

Abstract(890) PDF-CN(168)

Abstract:
Shale reservoirs have a strong microscopic heterogeneity and a wide pore size distribution. In this study, argon was used as the adsorbent, and argon isotherm adsorption experiments at 87 K were used to investigate the microscopic pore structure characteristics of six organic-rich shale samples taken from the Upper Ordovician Wufeng-Lower Silurian Longmaxi formations in southern Sichuan Basin. The effect of total organic carbon content on the microscopic pore structure of shale samples was also discussed. The results showed that the pore shape of organic-rich shale samples is slit-like, with an average specific surface area of 31.65 m²/g and an average pore volume of 0.062 2 cm³/g. Over 90% of the specific surface area of the shale samples was provided by micro pores and meso pores, which were less than 50 nm in size, and the 2-100 nm meso pores and macro pores comprising over 90% of the pore volume. TOC content is the main factor affecting the development of organic-rich shale microscopic pores. With the increase of organic carbon content in shale, the specific surface area and pore volume of shale increase, the micro pore ratio increases, and the fractal dimension of pore surface increases, which means that the heterogeneity of pore structure is enhanced. All these factors will enhance the methane adsorption capacity of shale.

Mass method adsorption characteristics of shale gas under high pressure

GAO Yongli, LI Teng, GUAN Xin, NIU Huiyun, KONG Xu

2018, 40(4): 566-572. doi: 10.11781/sysydz201804566

Abstract(804) PDF-CN(113)

Abstract:
The isothermal adsorption characteristics of shale gas under high pressure are investigated with a magnetic suspension mass method isothermal adsorption instrument. The experimental results showed that the adsorption characteristics of shale gas at low pressure conform to the Langmuir model. After the experimental pressure exceeds 10-12 MPa, the adsorption of shale shows obvious excess adsorption. Under high pressure, the sample container volume decreases in an exponential manner, which is related to the compressibility of the sample container under high pressure. The volume of shale samples increases exponentially and tends to equilibrate within a relatively small pressure range, which is related to the slight adsorption of He by shales. The densities of adsorbed phase CH₄, acquired from the linear fitting with the excess adsorption capacities and the densities of gaseous phase CH₄, are also dynamic. The adsorbed phase CH₄ density is close to the true one when using the contiguous excess adsorption capacities and the densities of gaseous phase CH₄ after the maximum excess adsorption. Combined with the dynamic changes of sample container volume, sample volume and the adsorbed phase CH₄ volume before and after the maximum excess adsorption, the absolute adsorption capacities can be calculated, which can present the adsorption characteristics of shale gas accurately. The absolute adsorption of shale gas under high pressure also follows the Langmuir model.

Content determination and critical precipitation pressure of elemental sulfur in sour gas rich in H₂S in Puguang Gas Field

PENG Song, JIANG Yiwei, SU Yaxian, JIANG Shuxia, LIU Jianyi

2018, 40(4): 573-576. doi: 10.11781/sysydz201804573

Abstract(1150) PDF-CN(136)

Abstract:
The actual content and critical precipitation pressure of elemental sulfur in sour gas with a high H₂S content are regarded as two key parameters for studying sulfur deposition problems in the Puguang Gas Field. These two parameters have been quantitatively assessed using GC-MS, DMDS-DMA sulfur solvent and downhole gas samples from well 104-1 in the Puguang Gas Field. The experimental results showed that the sour gas in the Puguang Gas Field is unsaturated with an elemental sulfur content of 0.78 g/m³ at initial conditions. The critical precipitation pressure of sulfur in sour gas is 30.5 MPa, which means sulfur deposition has not yet occurred in a reservoir where a pressure of 35 MPa is greater than the critical precipitation pressure.

Experimental study of the breakthrough pressure of capillaries and the sealing ability of shale

ZHANG Wentao

2018, 40(4): 577-582. doi: 10.11781/sysydz201804577

Abstract(1207) PDF-CN(178)

Abstract:
Several experiments were made with mono-capillary-tubes to study how breakthrough pressure of mudstone cap rock changes when there are multiple two-phase interfaces in the flow path. The results indicated that breakthrough pressure is related to diameter but not the length of the capillary tube when there is only liquid phase in the tube. However, with two mixed phases in the tube, the breakthrough pressure slightly increases with the number of two-phase interfaces, and the increase becomes more remarkable when the wettability of tube surface changes from hydrophilic to a mix of hydrophilic and hydrophobic. The results indicated that the sealing ability of black shale could be improved by the presence of organic matter and hydrocarbon generation. Additionally, for shales with two phases in pore system, breakthrough pressure has a positive relation with the thickness of cap rock. This interpretation is different from previous ones with respect to breakthrough pressure being related to the thickness of cap rock. Mixed phases of oil/gas and water is also an important explanation why fluids can only be mobilized when the driving pressure gradient reaches a critical value, which is called starting pressure gradient in low permeability pools.

Key parameters of a conceptual development scheme in economic evaluation of trap

ZHANG Zhonghua, TONG Ying, WU Yongchao

2018, 40(4): 583-588. doi: 10.11781/sysydz201804583

Abstract(832) PDF-CN(94)

Abstract:
Conceptual development scheme is the key in the economic evaluation of trap. Its design method is basically mature. How to scientifically and reasonably determine the conceptual scheme parameters is the core issue. Due to limited geological parameters in the economic evaluation of trap, it can not meet the design requirements of a development plan in the usual sense. Therefore, the conceptual development scheme is mainly based on the statistical analogy of similar developed areas or similar developed oil and gas reservoirs, or by empirical evaluation. In various target evaluation, the workload is large and the deviation is obvious, which affects the reliability of evaluation result. The prediction models and parameters for three key parameters including oil production rate, well pattern density and production decline rate in the conceptual scheme were established based on the study of the relationship between geological trapping parameters of oil and gas and the conceptual development scheme. Two typical examples were selected, namely, Shengtuoyong 559 South and Chengbei 313 South Paleozoic buried hill traps for application calculation. The calculation results are in good agreement with production practice. This key parameter determination method has good practicability for sandstone oil and gas reservoirs in East China. However, for the western carbonate fractured-and-vuggy reservoirs, due to the large difference in reservoir seepage characteristics, the applicability is relatively insufficient and needs to be further studied.

Sample size design for oil and gas reservoir core-plug experiments

LÜ Zhou, WANG Yupu, LI Li, HOU Xiulin, XUE Xiaomin, ZHANG Baohui

2018, 40(4): 589-594. doi: 10.11781/sysydz201804589

Abstract(672) PDF-CN(111)

Abstract:
Experimental data of oil and gas reservoirs are the basis of oil and gas geology research, rock geophysical evaluation and petroleum engineering calculations. However, the number of core samples is limited and the experiment costs are high, making it difficult to obtain large amounts of data, resulting in the uncertainty of reservoir evaluation. This paper presented a sample size design method for the core data of oil and gas reservoirs, and discussed some reasonable sample size design steps using a random sampling method. The effect of sample size design was analyzed combined with the experimental data. The results showed that using adjacent well data and well logging data can effectively predict sample size, reduce experiment cost and improve the application effect of experimental data. In the design of core experiments, we should pay full attention to sample design, and adopt randomized, repeated and segmented experiment design strategies, which are important for saving experiment cycles and costs and improving the reliability of core experiment data.

Multi-method synergistic characterization of total pore structure of extra-low permeability sandstone reservoirs: case study of the Heshui area of Ordos Basin

OUYANG Siqi, SUN Wei, HUANG Hexing

2018, 40(4): 595-604. doi: 10.11781/sysydz201804595

Abstract(1384) PDF-CN(269)

Abstract:
Mercury injection capillary pressure (MICP), rate-controlled porosimetry (RCP) and nuclear magnetic resonance (NMR) have limitations in describing the characteristics of microscopic pore structure characteristics of extra-low permeability sandstone reservoirs, and the results are not completely consistent with the observation of thin sections and scanning electron microscopy. Five ultra-low permeability sandstone reservoir samples were collected from the Heshui area of Ordos Basin. A collaborative multi-method for characterizing pore throat structure was proposed in order to describe the detailed characteristics of pore size distribution. MICP and NMR combined with MICP were used to obtain pore connectivity. The connectivity ratio of adsorption throat, micro throat, fine throat, middle throat was calculated. Nuclear magnetic resonance data were used to achieve the conversion of transverse relaxation time to pore throat radius. The specific surface area was calculated by MICP, and the relaxation rate was calibrated by RCP and the T₂ spectrum. The synergistic calculated pore throat distribution results were multiplied by the corresponding pore throat connectivity ratio to obtain the spatial distribution curves of throat and pore connectivity at different scales. The results showed that the adsorption throat connectivity ratio was the lowest, and the ratio of other sizes was relatively higher, but the difference is not significant. The throat radius ranged from 0.003 to 3.661 μm, which was greater than constant rate-controlled porosimetry test results. The pore radius ranged from 0.8 to 91.4 μm and the pore-throat ratio ranged from 16.4 to 58.6 μm, both of which were smaller than rate-controlled porosimetry test results. The final calculation results were basically in accordance with the observed results of cast thin section and scanning electron microscopy. It showed that the collaborative calculation of multiple methods overcomes the superposition of throat and pores on high-pressure mercury-injection and the calculation error of rate-controlled porosimetry, which is closer to the true state of reservoir.

2018, 40(4): 605-605.

Abstract(355) PDF-CN(118)

Abstract:

2018 Vol. 40, No. 4

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