石油实验地质

2019, 41(2): .

Abstract(345) PDF-CN(111)

Abstract:

Prospects for ultra-deep oil and gas in the “deep burial and high pressure” Tarim Basin

GU Yi, WAN Yanglu, HUANG Jiwen, ZHUANG Xinbing, WANG Bin, LI Miao

2019, 41(2): 157-164. doi: 10.11781/sysydz201902157

Abstract(1752) PDF-CN(592)

Abstract:
Ultra-deep oil and gas exploration technology is developing, and the thermal evolution of source rocks under high pressure in the Tarim Basin has become the focus of ultra-deep oil and gas resource evaluation and hydrocarbon generation theory research. Simulated hydrocarbon generation from source rocks under high temperature and pressure, combined with the geological conditions of “deep burial and high pressure” of the Shuntuoguole Uplift in the Tarim Basin, a study was carried out on the hydrocarbon generation, evolution and retardation under high pressure of marine source rocks in the Tarim Basin. Ever since the Yanshan period, the Cambrian source rocks still have geological conditions for generating high-maturity liquid hydrocarbon in the Shuntuoguole Uplift. The boundary conditions for thermal evolution retardation include: ①Long-term stable closed system; ②Source rocks deeper than 6 500 m with the fluid pressure above 60 MPa, and a low temperature with a gradient less than 20 ℃/km in the later period; ③Marine source rocks with type I and type Ⅱ₁ kerogen. The ultra-deep Cambrian marine source rocks in the Tarim Basin are mainly type I and type Ⅱ₁ kerogen, and the degree of inhibition is more obvious under high pressure. The scope and potential of the oil generation window are much higher than the traditional theoretical value. Therefore, the prospect for ultra-deep oil and gas exploration is considerable.

Tectonic evolution characteristics of Yingjisha and Pishan areas and the influence on petroleum accumulation in the southwest depression, Tarim Basin

XIE Qiaoming, WANG Zhenliang, YIN Chengming, LI Qingyao, LIAO Xiao, ZHAO Zilong, ZHANG Kuaile

2019, 41(2): 165-175. doi: 10.11781/sysydz201902165

Abstract(1358) PDF-CN(144)

Abstract:
The oil and gas exploration degree in the southwestern depression of the Tarim Basin is low overall. Complex tectonic evolution is one of the key factors that restrict the hydrocarbon accumulation and exploration in this depression. There are no major discoveries in the Yingjisha and Pishan areas that are geologically similar to those found in the oil and gas fields of Akmomu and Kekeya. Using a balanced section technology, and the geological circumstances and single well burial history as the constraints in the field, the tectonic evolution characteristics of the Yingjisha and Pishan areas and their effects on hydrocarbon accumulation were analyzed. Since the Permian, the Yingjisha area has undergone three stages of tectonic nappe, and developed tectonic styles such as imbricate thrusts, V-belt and fault related folds. It has the strongest nappe effect in the Miocene, with a strata shortening of 22.4%. The Pishan area has experienced four stages of tectonic thrust, developing styles such as imbricate thrusts and fault related folds. The strongest thrusting took place during the Pliocene with a strata shortening of 12.5%. There is a certain difference in time and intensity of tectonic movement in the Yingjisha and Pishan areas since the Miocene. Since the Neogene, the strong thrusting of the Yingjisha and Pishan areas has caused the formation of thick Cenozoic strata in the foreland depression, making the underlying source rocks enter the high-maturity and over-mature stage, resulting in large-scale hydrocarbon generation. Oil and gas migrated along faults and unconformities into anticline structures to form reservoirs. The difference in tectonic effects between the Yingjisha and Pishan areas since the Neogene has led to some differences in the conditions for hydrocarbon accumulation. The initial charging period of hydrocarbons and the main formation time of structural traps in the Yingjisha area were both in the Miocene epoch, and the primary oil and gas reservoirs were easily damaged in the Pliocene epoch. In the Pishan area, the initial charging period of hydrocarbons and the main formation time of structural traps were both in the Pliocene epoch, and the primary oil and gas reservoirs showed a low damage risk.

Sedimentary characteristics and geological significance of tempestites in the Upper Cambrian Xixiangchi Formation, Chengkou area, northern margin of the Yangtze Platform

WANG Han, LI Zhiwu, LIU Shugen, SONG Jinmin, RAN Bo, LAI Dong, HAN Yuyue

2019, 41(2): 176-184. doi: 10.11781/sysydz201902176

Abstract(1219) PDF-CN(222)

Abstract:
The Upper Cambrian Xixiangchi Formation has been considered as a potential target for hydrocarbon exploration in the Sichuan Basin, but little is known about its sedimentary facies and controls on reservoir quality. The tempestite deposition found in the Xixiangchi Formation at the northern margin of the Yangtze Platform may provide some important constraints for that. Through field survey and thin section analysis, we present a detailed description on the tempestite deposition of the Upper Cambrian Xixiangchi Formation in Chengkou area on the northern margin of the Yangtze Platform, and further discuss the significance for paleogeography and implications for hydrocarbon reservoir in the northeastern Sichuan Basin. Many diagnostic sedimentary structures can be recognized in these Upper Cambrian tempestites of the Xixiangchi Formation in Chengkou area, such as basal scour-and-fill structures, rip-up clasts, hummocky cross stratification (HCS), graded bedding, and so on. Five types of tempestite sequences were recognized in terms of variant assemblies of storm-induced sedimentary structures, with a gradual transition from Type 1 at the bottom to Type 5 on the top. According to tempestite deposition, lithological association and sedimentary sequence, combined with the classical mode of tempestites developed in shallow water carbonate environments, we suggested that the sedimentary environment of tempestites of the Upper Cambrian Xixiangchi Formation in Chengkou area were dominated by middle ramp, and evolved from inner ramp at the bottom to mid-outer ramp on the top, with a deepening-upward trend. Integrated with regional geological background, it is speculated that the Upper Cambrian Xixiangchi Formation on the northern margin of the Yangtze Platform is dominated by mid-outer ramp facies to the northeast of Chengkou, and inner-ramp facies to the southwest. This implies that there were many geologic advantages for high quality shoal reservoirs in the Upper Cambrian Xixiangchi Formation developed in the northeastern Sichuan Basin to the southwest of Chengkou, worthy to be explored in the future.

Transmission model of secondary gas reservoir on the basin margin of Jiyang Depression

ZHANG Weizhong, ZHANG Yunyin, WANG Xingmou, ZHA Ming, DONG Li, LIU Haining, QU Zhipeng, YU Jingqiang

2019, 41(2): 185-192. doi: 10.11781/sysydz201902185

Abstract(1392) PDF-CN(122)

Abstract:
Heavy oil and gas have an association in a shallow fault basin reservoir. More than 50% of shallow gas reservoirs came from the biodegradation of heavy oil. However, there is little research on the migration process from the heavy oil reservoir to the shallow gas reservoir. Through the study of the carrier system type, distribution and elements of heavy oil and shallow gas reservoirs, two models were established, and the migration controls were clarified. There are two carrier system types: lateral and vertical. Lateral migration mainly developed in the high convex belt of the basin, and the shallow gas reservoir was distributed over the side of the heavy oil reservoir. The transmission process was dominated by lateral migration. Vertical migration also took place through diffusion along faults. Vertical migration mainly developed in the depression and low convection zone, and the shallow gas reservoir was located directly above the heavy oil reservoir. The transport process is dominated by vertical migration through faults.

Gas migration mode for the central canyon in deep-water Qiongdongnan Basin

LIU Jingjing, LIU Zhen, WANG Zisong, CAO Shang, SUN Xiaoming

2019, 41(2): 193-199. doi: 10.11781/sysydz201902193

Abstract(1155) PDF-CN(107)

Abstract:
Exploration results showed that the gas in the shallow Neogene central canyon reservoirs of the Qiongdongnan Basin mainly came from the deep Paleogene source rocks in the deep-water area. However, given that the late tectonic activity in the basin was weak, how did the gas in the deep formations migrate to the Neogene reservoirs? Using seismic frequency division technology, the resolution of 3D seismic data was improved. A fracture system below the central canyon was identified, and a gas transport mode was established by combining this interpretation with the development characteristics of regional faults. There were four stages of fault activity in the deep-water area of the basin, with pronounced periodicity. The activity and stationary periods happened alternately. Based on this, this paper proposed a concept of fracture cycle, which includes a shorter activity period and a longer stationary period. A fracture activity corresponds to a fracture cycle, and multiple fracture activities can be superimposed to form a stacking pattern of fracture cycles. Then, studying the difference of the migration mode for fractures in different periods, this paper proposed a fast inflow migration mode during the fault activity period and an effective seepage migration mode during the stationary period, and pointed out that it could enhance the efficiency of gas migration in a overpressure rift basin, if the inflow migration mode and seepage migration mode occurred alternately. In the Lingshui Depression, a series of ladder-like faults developed, connecting source rocks in the deep formations with many high-angle small faults in the shallow formations, which allowed deep natural gas migrate to shallow reservoirs. Thus, a relayed transport mode of “multi-stage fracturing and multiple faults” for gas migration in the central canyon was proposed.

Fault characteristics and controls on hydrocarbon accumulation in Changling Faulted Depression, Songliao Basin

ZUO Zongxin, LU Jianlin, WANG Miao, LI Ruilei, LI Hao, ZHU Jianfeng

2019, 41(2): 200-206. doi: 10.11781/sysydz201902200

Abstract(1313) PDF-CN(158)

Abstract:
Multiple types of oil and gas reservoirs have been found in the Changling Faulted Depression, and the reservoir types and pool size are variable in different areas. Fault characteristics, forming mechanisms and activity periods were studied based on seismic interpretation. The fault controls on hydrocarbon accumulation were discussed, and the main exploration targets in different areas were identified. Three types of fault were formed during the fault, depression and inversion periods. Under a NNE direction sinistral strike-slip and tension stress background, many NE, NS-NNW and NW direction secondary faults were generated. The fault activity characteristics varied in different areas. Due to fault activities, multiple types of structural traps were formed. The faults have a great influence on oil and gas migration and accumulation in the Changling Faulted Depression. In the areas that the faults are inactive and the tectonics are stable during the depression and the inversion periods, primary reservoirs were well preserved. As a result, the primary reservoirs in the Huoshiling, Shahezi and Yingcheng formations are main exploration targets. The secondary reservoirs are important exploration directions for the long duration of fault activity, especially in the deep faults and strike-slip faults.

Pore structure characteristics of the Lower Cambrian black shale in the Cengong block, southeastern Guizhou area

WANG Ruyue, HU Zongquan, YANG Tao, GONG Dajian, YIN Shuai, LIU Zhongbao, GAO Bo

2019, 41(2): 207-214. doi: 10.11781/sysydz201902207

Abstract(1256) PDF-CN(137)

Abstract:
Based on the mineralogy, organic geochemistry, nitrogen adsorption, physical properties and FE-SEM observation, the pore structure characteristics of the Niutitang and Bianmachong marine shales of the Lower Cambrian in the southeastern Guizhou area were systematically analyzed. The dominant pore types of the organic-lean shale with a high clay mineral content in the Niutitang and Bianmachong formations are plate-like and slit-like inter particle pores with average pore sizes commonly greater than 5 nm. However, the organic-rich shale in the Niutitang Formation mainly contains slit-like and ink-bottle-like pores with average pore sizes less than 3-4 nm, and the specific surface area is 2-3 times of that of the organic-lean shale. In addition, the total pore volume and specific surface area have a positive correlation, and there is also a correlation between clay mineral content and average pore size, but the correlations between total pore volume/specific surface area and clay mineral content/average pore size are negative. Under favorable preservation conditions, the shale has a relatively high development level of organic matter pores, greater values of porosity, pore size and peak diameter with a positive correlation between porosity and permeability, which are represented as “high porosity and low permeability”. Under unfavorable preservation conditions, the reservoir parameters have lower values except the permeability, which leads to the overdevelopment of fractures and has the feature of “low porosity and high permeability”. Besides, the TOC content has a significant control on pore structure and generally has a positive correlation with total pore volume, specific surface area and porosity and a negative correlation with average pore size. Nevertheless, in the intervals with an excessive TOC content, the decrease and increase of pore size and ductility with increasing TOC coupled with compaction and/or unfavorable preservation will result in the atrophy, collapse and close of narrow pores and throats which leads to the negative correlations between TOC and reservoir parameters.

Jurassic coal bed methane characteristics and gas-bearing property evaluation in Iqe Coalfield, northern Qaidam Basin

CHEN Lei, TIAN Jingchun, WEN Huaijun, LIU Shiming, YANG Ying

2019, 41(2): 215-221. doi: 10.11781/sysydz201902215

Abstract(1274) PDF-CN(122)

Abstract:
The northern margin of the Qaidam Basin is rich in coal and coal bed methane resources. The Iqe Coalfield is a typical area rich in coalbed methane, which mainly occurs in the Shimengou and Dameigou formations in the Middle Jurassic. Gas contents vary in different areas of the Iqe Sag influenced by regional tectonics. The M5 coal seam of the Shimengou Formation and the M7 coal seam of the Dameigou Formation show a good resource prospect. The relationship between depth and gas-bearing properties shows a gas-bearing gradient and the discreteness of the relationship between depth and gas-bearing property is small in the Erjingtian area. The gas-bearing capacity of M7 coal seam decreases first and then increases with burial depth, and increases first and then decreases in the Caxiu, Yangshuihe and Yuka areas. The gas-bearing properties of M7 coal seam of Jurassic in the Iqe Sag vary greatly in different tectonic units and show obvious heterogeneity. On the whole, the gas-bearing capacity of coal seams in the western Iqe Sag is significantly higher than that of the eastern part, and slightly better in the north than in the south, which shows a trend of decreasing first and then increasing from south to north. There are two relatively high gas content areas in a small anticline structure in the north of the Iqe Coalfield, controlled by F2 and F10 faults, and the coal seam gas content gradually increases from south to north. While the gas content is generally lower in the Beishan and Erjingtian areas in the east of the Iqe Coalfield.

Differential tectonic evolution and a dynamic oil pool in the south of block 17, Oriente Basin

FU Zhifang, GAO Jun, KONG Fanjun, ZHANG Liwei, ZHANG Wencai, TENG Binbin

2019, 41(2): 222-227. doi: 10.11781/sysydz201902222

Abstract(1247) PDF-CN(78)

Abstract:
The foreland region of the Oriente Basin, which has suffered multiple stages of differential tectonic deformation under continuous EW compression, is critical for hydrocarbon accumulation and has become a predominant factor for a dynamic oil pool in the basin. This study shows an oil pool in the foredeep axis area of this basin using detailed 2D seismic sequence boundaries with a tilted oil-water contact, which is not controlled by the current simple nose structure but by a paleo-anticline trap from the earlier stage. In addition, reservoir dynamics, such factors as the current low dip formation, heavy oil property, as well as the perpendicular relationship between the NS trending nose structure and the sandstone distribution in the EW direction, are all unfavorable for hydrocarbon re-migration, which has eventually formed a metastable oil pool whose planar oil-bearing area mismatches with the current trap area.

Difference of lithofacies mechanical properties of the fourth member of Shahejie Formation in the Bonan Subsag, Bohai Bay Basin

LI Zhipeng, BU Lixia

2019, 41(2): 228-233. doi: 10.11781/sysydz201902228

Abstract(1147) PDF-CN(91)

Abstract:
Based on the data of well cores in low permeability reservoirs in the fourth member of Shahejie Formation in the Bonan Oilfield, the rock facies types were studied. Using conventional three axis compression test data of different lithofacies, restored static rock mechanical parameters were established under reservoir confining pressure conditions. The differences of static mechanical parameters and stress-strain relation between lithofacies were analyzed. The low permeability reservoirs in the Bonan Oilfield can be divided into 5 types: coarse grained sandstones, fine sandstones, siltstones, mudstones and carbonate sandstones. In the same rock, with the increasing confining pressure, the Young’s modulus becomes larger, and the Poisson’s ratio increases slightly. With the increase of rock gain size, the Young’s modulus increases and the Poisson’s ratio decreases. However, the Poisson’s ratio of coarse grained sandstones does not follow the overall trend, and is larger than that of fine sandstones and smaller than that of siltstones. As the grain size of rock becomes coarser, the stress-strain relation becomes more linear. And the initial grain rearrangement plastic section and the high stress plastic section become smaller.

Microscopic heterogeneity of Toutunhe Formation and its relationship with crucial short-term base level cycle in Fudong slope area, Junggar Basin

LIU Ni, TANG Qunying, LIU Jing, YU Jingwei, LI Qinzhao, HOU Xiaoxiao

2019, 41(2): 234-242. doi: 10.11781/sysydz201902234

Abstract(1221) PDF-CN(83)

Abstract:
The Middle Jurassic Toutunhe Formation in the Fudong slope area of the Junggar Basin is a typical reservoir. Many problems such as remaining oil which is hard to extract and low recovery efficiency are found in deep development. To solve these problems, the microscopic heterogeneity in the second member of Toutunhe Formation was studied. In order to describe grain heterogeneity, pore throat heterogeneity and interstitial material heterogeneity, some methods such as mercury injection, X-ray diffraction and scanning electron microscopy were used to investigate microscopic heterogeneity in detail. Within a high resolution sequence stratigraphic framework, the relationship between crucial short-term base level cycle (SSC4 and SSC7) and microscopic heterogeneity are discussed. Through different structures of cycles because of A/S, pore throat heterogeneity induced by grain heterogeneity and interstitial material heterogeneity (especially matrix) affects reservoir microscopic heterogeneity in rising half cycle in SSC4 under the condition of A/S≤1. Pore throat heterogeneity induced by grain heterogeneity and interstitial material heterogeneity (especially cement) affects reservoir microscopic heterogeneity in rising half cycle in SSC4 under the condition of A/S>1. Pore throat heterogeneity induced by grain heterogeneity affects reservoir microscopic heterogeneity in rising half cycle in SSC7. Drift in intensity of microscopic heterogeneity should be noticed when planning development in reservoir sands in different important short-term cycles in order to enhance oil recovery.

Sequence stratigraphy and isotope geochemical response and development pattern of reef and shoal: a case study of Changxing Formation in the marginal zone of Eastern Sichuan Chengkou-Western Hubei Oceanic Trough

DONG Qingmin, HU Zhonggui, CAI Jialan, LI Shilin, SU Nan, ZUO Mingtao, QIN Peng

2019, 41(2): 243-250. doi: 10.11781/sysydz201902243

Abstract(1091) PDF-CN(146)

Abstract:
The Upper Permian Changxing Formation reef and shoal in the eastern Sichuan Basin has great potential for oil and gas exploration. The analysis of sequence stratigraphic and isotopic composition response as well as reef and shoal development patterns can provide a reliable geologic basis for reef and shoal exploration in this area. Observation of the typical outcrop section and the sequence stratigraphic analysis of the margin of the Chengkou-Western Hubei Oceanic Trough, combined with the carbon isotope composition of the Changxing Formation, show the sequence stratigraphic and geochemical response characteristics of the Changxing Formation and the reef and shoal development patterns. The Changxing Formation was divided into two third-order sequences and five fourth-order sequences. The carbon isotope distributions in the sequence framework have a good relationship with sea level fluctuation. There are obvious differences in the development patterns of reef and shoal in different sedimentary facies belts. The Panlongdong section on the windward side is in the highest energy platform margin belt, where reef and shoal are the most developed, the dolomitization of reef and shoal is obvious, and the reservoir is developed. In the Yanggudong section, which is on the leeward side of the platform margin, the development of reef and shoal takes the second place, and the dolomitization is weak. However, only the intra-platform grain shoal is developed in the Dukou section in the open platform, and reservoir is not developed.

Geochemical characteristics and source of crude oil in Xihu Sag, East China Sea Shelf Basin

CAO Qian, SONG Zaichao, ZHOU Xiaojin, LIANG Shiyou, WANG Ling

2019, 41(2): 251-259. doi: 10.11781/sysydz201902251

Abstract(839) PDF-CN(120)

Abstract:
The geochemical characteristics of oil in the Central Anticline, Santan Sag and Baochu Slope were determined, and the oil source correlation and the process of oil accumulation were analyzed based on geological and geochemical analyses. There are differences in crude oil maturity, parent material source and accumulation process in different tectonic zones. The crude oil in the Xihu Sag is distributed in the mature or high maturity range. The Central Anticline is dominated by mature crude oil, and that in the Santan Sag and Baochu Slope is in the mature or high maturity range. The oil source correlation results show that the crude oil in the Huagang Formation mainly sourced from the argillaceous source rocks in the Huagang Formation in the Central Anticline, and the argillaceous source rocks in the Pinghu and Huagang formations in the Santan Sag. The crude oil in the Pinghu Formation on the Baochu Slope mainly originated from the coal-series source rocks in the Pinghu Formation, while those in the Baoshi Formation mainly sourced from the argillaceous source rocks in the Baoshi Formation. The crude oil in the Xihu Sag generally has the accumulation mechanism of “evaporative fractionation and gas-washing fractionation”, and those on the Baochu Slope are the most typical.

Experiments on the generation of dimethyldibenzothiophene and its geochemical implications

WU Jia, QI Wen, LUO Qingyong, CHEN Quan, SHI Shengbao, LI Meijun, ZHONG Ningning

2019, 41(2): 260-267. doi: 10.11781/sysydz201902260

Abstract(967) PDF-CN(98)

Abstract:
Dibenzothiophene (DBT) and its homologues are important molecular markers in petroleum geochemistry. However, DBT-related geochemical indicators were derived mainly based on empirical observations due to insufficient understanding of the mechanisms through which these organosulfur compounds were generated in sedimentary environments. Thermal simulation experiments with 3,3’-dimethylbiphenyl and sulfur in closed gold tubes at 200-500 ℃ and 10 MPa afforded three main dimethyldibenzothiophene isomers (DMDBTs). Importantly, DBTs could be generated at a temperature as moderate as 200 ℃ under geological conditions, because the temperature threshold of the reaction could be reduced by increasing the system pressure. Further investigations revealed that the regioselectivity of the thiophene formation reaction was strongly influenced by temperature. This is similar to the process that occurs in natural geological systems. It should also be noted that the maturity index 4-/1-MDBT (MDR) reaches a maximum around 1.5% (Easy%R_o). It indicates that MDR index should be used in a suitable maturity regions combined with the given geological setting.

Genesis of hydrogen sulfide in Du 84 block, Liaohe Oilfield

HOU Guoru

2019, 41(2): 268-273. doi: 10.11781/sysydz201902268

Abstract(758) PDF-CN(85)

Abstract:
During the thermal recovery of extra heavy oil in the Liaohe Oilfield, the concentration of H₂S increased, which results in the increased cost of the desulfurization facility and oil-and-gas treatment. Crude oil, associated gas, formation water and reservoir minerals were analyzed and the H₂S production had no significant correlation with the sulfur content in the crude oil and the SO₄^2- concentration in the formation water, but had a good covariance with the pyrite content in reservoir. The sulfur in pyrite had biological source, and its isotopic range was basically consistent with that of crude oil, which originates in the thickening stage of crude oil and forms in large quantities in the thermal recovery stage of heavy oil. Except for the thermal decomposition of organic sulfur compounds (TDS) and thermochemical sulfate reduction (TSR), the thermal simulation experiment shows that the decomposition of pyrite is also one of the ways to produce H₂S in the process of steam thermal recovery. When injected, lower salinity steam dilutes the formation water and pyrite decomposition becomes the main source of H₂S. The production concentration of hydrogen sulfide was controlled by reservoir geology, the thermal recovery method, heating time and temperature.

Molecular dynamics simulation and microscopic mechanism of CO₂ composite flooding

JIANG Yongping

2019, 41(2): 274-279. doi: 10.11781/sysydz201902274

Abstract(1185) PDF-CN(135)

Abstract:
A CO₂ composite flooding method was proposed for remaining oil exploitation and achieved significant effects in pilot well tests in order to improve residual oil recovery efficiency in complex fault block oilfields during high water cut period. There are few related studies on the microscopic mechanism of CO₂ composite flooding, and the basic research in this field is urgently demanded. Based on the CT scanning results, combined with the actual development of reservoir, it was clear that the drop-like and film-like residual oil are two types of remain-ing oil that were difficult to recover. A dissolved oil droplet model and a stripped oil film model were constructed and simulated using a molecular dynamics method. The simulation results of the dissolved oil droplet method showed that CO₂ first diffused into oil droplets and increased their volume, and then the oil droplet molecules gradually dissolved into the oil displacement system. The molecular dynamics simulation results of the stripped oil film showed that CO₂ first formed diffusion channels in the oil phase, and then preferentially passed through the diffusion channels to the rock surface. CO₂ formed hydrogen bonds on the surface and generated adsorption.

Thermal conductivity properties of rocks in the Chang 7 shale strata in the Ordos Basin and its implications for shale oil in situ development

CUI Jingwei, HOU Lianhua, ZHU Rukai, LI Shixiang, WU Songtao

2019, 41(2): 280-288. doi: 10.11781/sysydz201902280

Abstract(1122) PDF-CN(128)

Abstract:
In situ conversion is a key area of China’s continental shale oil research. The thermal properties of rocks in the seventh member of the Triassic Yanchang Formation (Chang 7) in the Ordos Basin, especially the high temperature thermal properties are still unknown, which seriously restricts the optimization and feasibility evaluation of in situ conversion. Some fresh samples were collected from the Chang 7 shale layer and tested with a quick thermal conductivity meter, differential scanning calorimetry and thermal expansion instrument to obtain the thermal diffusivity, specific heat capacity, thermal expansion coefficient, and thermal conductivity parameter of muddy siltstones, tuffs, mudstones and shale. The thermal diffusivity and thermal conductivity of rocks with different lithologies in the Chang 7 member are different, and decrease with the decrease of sandy content, namely argillaceous siltstones > tuffstones > mudstones > shale. The thermal diffusivity and thermal conductivity have anisotropy, and the horizontal direction is 1 to 3.5 times the vertical direction, and the difference increases as the temperature increases. With the increase of temperature, the thermal diffusivity of rock decreases, the specific heat capacity of rocks increases and the thermal conductivity first decreases and then increases. The anisotropy of shale thermal properties is the strongest, which is a manifestation of rock heterogeneity, and is related to microscopic strata. The sandstone anisotropy may be related to permeability in different directions of rock.

Thermal conductivity of gas-bearing shale of the Longmaxi Formation in the southern Sichuan

CHENG Chao, LIN Haiyu, JIANG Yuqiang, FENG Lei, XIA Yu, MU Chunhao

2019, 41(2): 289-294. doi: 10.11781/sysydz201902289

Abstract(1406) PDF-CN(142)

Abstract:
The deep gas-bearing shale in the Longmaxi Formation in the southern Sichuan Basin was used to explore basic characteristics of deep gas-bearing shale and factors controlling those characteristics, such as mineral composition, TOC content, porosity and thermal conductivity. The thermal conductivity of the gas-bearing shale in the Longmaxi Formation in the study area mainly ranged 2.0-3.0 W/(m·K), with a maximum measured value of 5.15 W/(m·K), and a minimum value of 1.22 W/(m·K), averaging 2.50 W/(m·K). On this basis, the relationships between thermal conductivity and mineral composition, porosity, TOC content and temperature were discussed, and the influencing factors of thermal conductivity were analyzed. The thermal conductivity of shale is closely related to mineral composition. Pyrite and quartz are the minerals that have a great influence on thermal conductivity. Furthermore, thermal conductivity decreases with the increasing porosity of shale reservoir. With the increase of TOC content, thermal conductivity decreases. When the value of TOC content is low, the corresponding thermal conductivity decreases rapidly. When the value of TOC content is high, thermal conductivity decreases slowly. Temperature is a most important factor affecting thermal conductivity, which is restricted by the TOC content of shale. When TOC content is low, thermal conductivity decreases with the increase of temperature. When TOC content is high, thermal conductivity increases with the increase of temperature.

Analysis of main controls of stratigraphic reservoirs in Xingouzui Formation of Jiangling Sag based on a multivariate statistical method

PENG Wei, HUANG Hua, DU Xuebin, ZHANG Cheng, HE Yunlong, LI Chen, ZHAO Ke, YANG Pan

2019, 41(2): 295-302. doi: 10.11781/sysydz201902295

Abstract(1437) PDF-CN(91)

Abstract:
Stratigraphic reservoirs are important areas for future oil and gas exploration in the Jiangling Sag of Jianghan Basin, but their hydrocarbon accumulation controls have not been systematically studied. Based on a multivariate statistical method, some key controls of stratigraphic reservoir formation were analyzed. It was proposed that reservoir conditions were the key factors for reservoir formation in stratigraphic reservoirs in the Paleogene Xingouzui Formation in the Jiangling Sag. When the Xingouzui Formation was deposited, the Jiangling Sag was a salt lake basin. The anhydrite cement content played a major role in controlling sandstone densification in stratigraphic reservoirs in the Xingouzui Formation. The anhydrite cement content of 7.5% is a critical value of reservoir physical properties. When the content is less than 7.5%, the physical properties are good. When the content is more than 7.5%, the reservoir physical properties are obviously deteriorated, and the logging interpretation indicates no petroleum resource. The relationship between paleo water depth and anhydrite content can be used to classify the distribution of favorable reservoirs.

2019, 41(2): 303-303.

Abstract(368) PDF-CN(92)

Abstract:

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