The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results ind...The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results indicate that： 1） The specific surface area is 2.22-3.52 m2/g and has no correlation with the TOC content of the Permian Dalong Formation shales, nanopores are extremely undeveloped in the Dalong Formation kerogens, which have specific surface areas of 20.35-27.49 me/g; 2） the specific surface area of the Silurian Longmaxi Formation shales is in the range of 17.83-29.49 m2/g and is positively correlated with TOC content, the kerogens from the Longmaxi Formation have well-developed nanopores, with round or elliptical shapes, and the specific surface areas of these kerogens are as high as 279.84-300.3 m2/g; 3） for the Niutitang Formation shales, the specific surface area is 20.12-29.49 m2/grock and increases significantly with increasing TOC and smectite content. The Niuti- tang Formation kerogens develop a certain amount of nanopores with a specific surface area of 161.2 m2/g. Oil shale was also examined for comparison, and was found to have a specific surface area of 19.99 m2/g. Nanopores are rare in the Youganwo Formation kerogen, which has a specific surface area of only 5.54 m2/g, suggesting that the specific surface area of oil shale is due mainly to the presence of smectite and other clay minerals. The specific surface area and the number of pores present in shales are closely related to TOC, kerogen type and maturity, smectite content, and other factors. Low-maturity kerogen has very few nanopores and therefore has a very low specific surface area, whereas nanopores are abundant in mature to over- mature kerogen, leading to high specific surface areas. The Longmaxi Formation kerogen has more developed nanopores and a higher specific surface area than the Niutitang Formation kerogen, which may be due to differences in the kerogen type and maceral components. A high content of smectite may a展开更多
As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, form...As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated展开更多
Using well logs data only, the evaluation of shale gas hydrocarbon potential of Talhar Shale Member of Lower Goru Formation has been a challenge in Southern Lower Indus Basin in Pakistan. Well logs data analysis is he...Using well logs data only, the evaluation of shale gas hydrocarbon potential of Talhar Shale Member of Lower Goru Formation has been a challenge in Southern Lower Indus Basin in Pakistan. Well logs data analysis is helpful to evaluate the gas potential of source shale rocks. We introduced and applied empirical and graphical method to fulfil this task and derived geochemical parameters from well logs data. The method mentioned is cheap and fast. Talhar Shale has kerogen type Ⅲ and type Ⅱ which are montmorillonite clay and have potential to produce oil and gas. Talhar Shale has better sorption property. Empirical formulas are used to derive parameters, using well logs of porosity, density and uranium. Porosity and volume of kerogen, calculated from density log, give average values of 11.8% and 11.4%. Average value of level of maturity index （LMI） derived from log is 0.54, which indicates that it is at the early stage of maturity. Vitrinite reflectance is between 0.5%-0.55% as calculated by graphical method and empirical formula. Talhar Shale is at onset of oil generation, with main products of oil and gas. It is a good potential source in the study area.展开更多
The Huai Hin Lat Formation has a high-potential resource, and the Ban Nong Sai part was researched and sampled. To achieve this goal, petrographic analysis(kerogen types), geochemical analysis(total organic carbon con...The Huai Hin Lat Formation has a high-potential resource, and the Ban Nong Sai part was researched and sampled. To achieve this goal, petrographic analysis(kerogen types), geochemical analysis(total organic carbon content, TOC), vitrinite reflectance(Ro), and Rock–Eval(RE) pyrolysis were carried out in this study. According to the findings, types Ⅱ, Ⅲ, and Ⅳ were identified using a modified Van-Krevelen diagram because the higher mature source rock showing hydrogen index(HI) and oxygen index(OI) are continuously depleted and raised. However,microscopic observation describes macerals as primarily sapropelic amorphinite, therefore, type I is important. The TOC was determined to be between 1.90% and 7.06%,which is considered very good to excellent. The original total organic carbon(TOCo) was decided to use its maceral components to determine how to convert extremely mature TOC to TOCo. It varies between 5.13% and 10.74% and reaches a maximum of 57.21% which is comparable to TOC. At 0.82%–1.04%, 443–451 ℃, 0.50%–38.10%, and69.00%–99.59% are the vitrinite reflectance(Ro), maximum temperature(Tmax), production index(PI), and transformation ratio(TR), respectively. Late peak maturity refers to a mixture of oil and gas, whereas most TR ratios refer to the main gas phase. Similarly, the petroleum residual shows no indication of gas trapped at a volume of6309.50 mcf/ac-ft. In summary, source rock potential was assessed within a suitable risk range defined by Tmax(445.70 ℃), Ro(0.91%), TR(90.63%), TOC(8.15%),shale thickness(46 m), and kerogen type(type I).展开更多
Carbonaceous shale exposures of the Late Cretaceous Mamu Formation along Ifon-Uzebba road in western arm(Benin Flank) of Anambra Basin, southwestern Nigeria, were analyzed for bulk organic geochemical, molecular biolo...Carbonaceous shale exposures of the Late Cretaceous Mamu Formation along Ifon-Uzebba road in western arm(Benin Flank) of Anambra Basin, southwestern Nigeria, were analyzed for bulk organic geochemical, molecular biological and poly-aromatic hydrocarbon(PAH) compositions to investigate the organic matter source, paleo-depositional condition, thermal maturity and petroleum potential of the unit. The bulk organic geochemistry was determined using Leco and Rock-Eval pyrolysis analyses while the biomarkers and PAH compositions were investigated using gas chromatography-mass spectrometer(GC-MS).The bulk organic geochemical parameters of the shale samples showed total organic carbon(TOC)(1.11-6.03 wt%), S2(0.49-11.73 mg HC/g Rock), HI(38-242 mg HC/g TOC) and Tmax(425-435 C) indicating good to excellent hydrocarbon source-rock. Typical HI-Tmax diagram revealed the shale samples mostly in the gas-prone Type Ⅲ kerogen region with few gas and oil-prone Type Ⅱ-Ⅲ kerogen. The investigated biomarkers(n-alkane, isoprenoid, terpane, hopane, sterane) and PAH(alkylnaphthalene, methylphenanthrene and dibenzothiophene) indicated that the carbonaceous shales contain mix contributions of terrestrial and marine organic matter inputs that were deposited in a deltaic to shallow marine settings and preserved under relatively anoxic to suboxic conditions.Thermal maturity parameters computed from Rock-Eval pyrolysis, biomarkers(hopane, sterane) and PAH(alkylnaphthalene, alkylphenanthrene, alkyldibenzothiophene) suggested that these carbonaceous shales in Anambra Basin have entered an early-mature stage for hydrocarbon generation. This is also supported by fluoranthene/pyrene(0.27-1.12), fluoranthene/(fluoranthene + pyrene)(0.21-0.53) ratios and calculated vitrinite reflectance values(0.49-0.63% Ro) indicative that these shales have mostly reached early oil window maturity, thereby having low hydrocarbon source potential.展开更多
This paper makes an approach to the characteristics of the compound and carbon iso-topic composition of condensate in the Sichuan, Shaanxi-Gansu-Ningxia, Dongpu and Jiyangbasins in China. The results we have obtained ...This paper makes an approach to the characteristics of the compound and carbon iso-topic composition of condensate in the Sichuan, Shaanxi-Gansu-Ningxia, Dongpu and Jiyangbasins in China. The results we have obtained show that the compound properties are re-lated to the maturity. The Paraffin Index Ⅰ and the Saturated-Aromatic Index (SAI) increasegradually from the immature to mature (or over mature) condensate. and the SAI valueincrease from 2 to more than 30. The carbonisotopic composition of condensate is control-led by the type of parent matter. If the oil and condensate come from the same source rock,they will have similar carbon isotopic composition. In the same region there is an obviousdifference in carbon isotopic composition between the condensate generated from coal-bear-ing strata and that from oil-source rocks. The difference can be regarded as a parameter fordistinguishing the coal-type gas from the oil-type gas. In the same basin the carbon isotop-ic composition of the natural gas-oil-condensate-kerogen related to the coal-bearing strata isdifferent from that related to the oil-source rock.展开更多
Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and...Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. Anza basin occurs on a fault block within a Paleocene</span></span><span style="font-family:Verdana;"><span style="font-family:Verdana;"><span style="font-family:Verdana;">-</span></span></span><span><span><span style="font-family:""><span style="font-family:Verdana;">Cretaceous rift basin. T</span><span style="font-family:Verdana;">he methodological approach used for the evaluation of source rocks i</span><span style="font-family:Verdana;">ncluded petrophysical and geochemical methods to ascertain their potential. Well sections with </span></span></span></span><span style="font-family:Verdana;"><span style="font-family:Verdana;"><span style="font-family:Verdana;">a </span></span></span><span><span><span style="font-family:""><span style="font-family:Verdana;">higher shale-volume ratio were sampled for geochemical screeni</span><span style="font-family:Verdana;">ng to determine the organic richness and thermal maturity of poten</span><span style="font-family:Verdana;">tial source rocks, respectively. Source rock with organic richness ≥ 0.5</span><span style="white-space:nowrap;font-family:Verdana;">%</span><span style="font-family:Verdana;"> were evaluated further for their petroleum potential using Rock-Eval pyrolysis to determine their thermal maturity, organo-facies and </span><i><span style="font-family:Verdana;">in-situ </span></i><span style="font-family:Verdana;">generated hydrocarbons present in sedimentary facies. The geochemical evaluation of rock samples from the drilled wells’ sections of Chalbi-3 and Sirius-1 confirmed both oil and gas potential. Gas Chromatography and Mass Spectrometry (GCMS) were used to characterize the biomarker signatures and oil-oil correlation of Sirius-1 samples. A predictive model was developed to integrate the petrophysical and geochemical da展开更多
Azraq area occupied more than 1400 sq. km in the central part of Jordan. The stratigraphic sequences in the area consist of a lithological bedding of classic and carbonate rocks with representing good factors for oil ...Azraq area occupied more than 1400 sq. km in the central part of Jordan. The stratigraphic sequences in the area consist of a lithological bedding of classic and carbonate rocks with representing good factors for oil generation and accumulation. Wadi Sir (WS-2) Sediments have geochemical characteristics of a typical source rocks for oil source rocks which are mature below 9843 ft, and carbonate rocks of Hummar, Shueb, and Wadi Sir-2 formation formations (Turonian Cenomanian age) are a reservoir rocks, where reservoirs are capped by shale and argillaceous limestone which is sufficiently thick to cap underlying reservoir. Twenty wells have been drilled in different blocks in the Azraq area, and oil of 32 API has been discovered in 1982, in the area, and starts natural flow production about 1500 bbl/day from few wells, then production start decreasing due to lower reservoir pressure, then sucker rod pumps were used to produce oil. In this study, the regional maturity of the Wadi Sir-2 sediments appear that mature oil generation sources rocks occur within the northwesterly trending depression of the area where maturity of WS-2 sediments below 9843 ft occurs, these mature source rocks amount to about 220 sq. km, based on average thickness of 108.27 ft for WS-2 sediments and extractable organic matter that was determined 3008 ppm. The volumetric method indicates that the total oil in place in the area is 480215 tons, taking a primary recovery factor of 12% then the total recoverable oil is 57,625 tons, while the cumulative oil producing is 53,137 tons.展开更多
The Lower Cambrian Niutitang and Sinian Doushantuo shales are the most important and widespread source rocks and target layers in South China. Reliable data of the thermal maturity of organic matter(OM) is widely used...The Lower Cambrian Niutitang and Sinian Doushantuo shales are the most important and widespread source rocks and target layers in South China. Reliable data of the thermal maturity of organic matter(OM) is widely used to assess hydrocarbon generation and is a key property used in determining the viability and hydrocarbon potential of these new shales. Nevertheless, traditional thermal maturity indicators are no longer suited to the vitrinite-lack marine shales. This study aims to combine high throughput Raman and infrared spectroscopy analysis to confirm and validate the thermal maturity in comparison with the bitumen reflectance(R_(b)). Raman parameters such as the differences between the positions of the two bands(V_(G)–V_(D)) are strong parameters for calculating the thermal maturity in a large vitrinite reflectance(R_(o)) ranging from 1.60% to 3.80%. The infrared spectroscopy analysis indicates that the aromatic C=C bands and CH_(2)/CH_(3) aliphatic groups both are closely correlated with thermal maturity. The calculated R_(o) results from Raman and infrared spectroscopy are in strong coincidence with the R_(b). The relationships between R_(b) and pore volumes/surface areas(calculated from N_(2) adsorption) indicate that the sample with R_(b) of 3.40% has the lowest pore volumes and surface areas. Focused ion beam scanning electron microscopy(FIB-SEM) observations of OM pores indicate that R_(o) of approximately 3.60% may be an upper limit for OM porosity development. Obviously, kerogen Raman and infrared spectroscopy can indicate methods for reducing the risk in assessing maturity with practical, low-cost accurate results. Exploration of shale gas in the high maturity(>3.40%–3.60%) region carries huge risks.展开更多
基金supported by National Basic Research Program of China(Grant No.2012CB214704)Major National Science and Techno-logy Project(Grant No.2011ZX05008-002-20)National Natural Science Foundation of China(Grant No.4123058)
文摘The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results indicate that： 1） The specific surface area is 2.22-3.52 m2/g and has no correlation with the TOC content of the Permian Dalong Formation shales, nanopores are extremely undeveloped in the Dalong Formation kerogens, which have specific surface areas of 20.35-27.49 me/g; 2） the specific surface area of the Silurian Longmaxi Formation shales is in the range of 17.83-29.49 m2/g and is positively correlated with TOC content, the kerogens from the Longmaxi Formation have well-developed nanopores, with round or elliptical shapes, and the specific surface areas of these kerogens are as high as 279.84-300.3 m2/g; 3） for the Niutitang Formation shales, the specific surface area is 20.12-29.49 m2/grock and increases significantly with increasing TOC and smectite content. The Niuti- tang Formation kerogens develop a certain amount of nanopores with a specific surface area of 161.2 m2/g. Oil shale was also examined for comparison, and was found to have a specific surface area of 19.99 m2/g. Nanopores are rare in the Youganwo Formation kerogen, which has a specific surface area of only 5.54 m2/g, suggesting that the specific surface area of oil shale is due mainly to the presence of smectite and other clay minerals. The specific surface area and the number of pores present in shales are closely related to TOC, kerogen type and maturity, smectite content, and other factors. Low-maturity kerogen has very few nanopores and therefore has a very low specific surface area, whereas nanopores are abundant in mature to over- mature kerogen, leading to high specific surface areas. The Longmaxi Formation kerogen has more developed nanopores and a higher specific surface area than the Niutitang Formation kerogen, which may be due to differences in the kerogen type and maceral components. A high content of smectite may a
基金the Department of Science & Technology (DST Ministry of Science & Technology, Government of India), for providing funding for his research through the DST-Inspire Assured Opportunity of Research Career (AORC) scheme
文摘As shale exploitation is still in its infancy outside North America much research effort is being channelled into various aspects of geochemical characterization of shales to identify the most prospective basins, formations and map their petroleum generation capabilities across local, regional and basin-wide scales. The measurement of total organic carbon, distinguishing and categorizing the kerogen types in terms oil-prone versus gas-prone, and using vitrinite reflectance and Rock-Eval data to estimate thermal maturity are standard practice in the industry and applied to samples from most wellbores drilled. It is the trends of stable isotopes ratios, particularly those of carbon, the wetness ra- tio （C1/~＇（C2＋C3））, and certain chemical biomarkers that have proved to be most informative about the status of shales as a petroleum system. These data make it possible to identify production ＂sweet- spots＂, discriminate oil-, gas-liquid- and gas-prone shales from kerogen compositions and thermal ma- turities. Rollovers and reversals of ethane and propane carbon isotope ratios are particularly indica- tive of high thermal maturity exposure of an organic-rich shale. Comparisons of hopane, strerane and terpane biomarkers with vitrinite reflectance （Ro） measurements of thermal maturity highlight dis- crepancies suggesting that Ro is not always a reliable indicator of thermal maturity. Major and trace element inorganic geochemistry data and ratios provides useful information regarding provenance, paleoenvironments, and stratigraphic-layer discrimination. This review considers the data measure- ment, analysis and interpretation of techniques associated with kerogen typing, thermal maturity, sta- ble and non-stable isotopic ratios for rocks and gases derived from them, production sweet-spot identi- fication, geochemical biomarkers and inorganic chemical indicators. It also highlights uncertainties and discrepancies observed in their practical application, and the numerous outstanding questions as- sociated
文摘Using well logs data only, the evaluation of shale gas hydrocarbon potential of Talhar Shale Member of Lower Goru Formation has been a challenge in Southern Lower Indus Basin in Pakistan. Well logs data analysis is helpful to evaluate the gas potential of source shale rocks. We introduced and applied empirical and graphical method to fulfil this task and derived geochemical parameters from well logs data. The method mentioned is cheap and fast. Talhar Shale has kerogen type Ⅲ and type Ⅱ which are montmorillonite clay and have potential to produce oil and gas. Talhar Shale has better sorption property. Empirical formulas are used to derive parameters, using well logs of porosity, density and uranium. Porosity and volume of kerogen, calculated from density log, give average values of 11.8% and 11.4%. Average value of level of maturity index （LMI） derived from log is 0.54, which indicates that it is at the early stage of maturity. Vitrinite reflectance is between 0.5%-0.55% as calculated by graphical method and empirical formula. Talhar Shale is at onset of oil generation, with main products of oil and gas. It is a good potential source in the study area.
基金supported by The Commission on Higher Education,Ministry of Education of Thailand and the Royal Golden Jubilee Program of the Thailand Research Fund(RGJ-TRF)the NSFC (Project No.41172202)+1 种基金China Geological Survey Program (No.1212011121256)granted special funding from the State Key Laboratory of Geological Processes and Mineral Resources。
文摘The Huai Hin Lat Formation has a high-potential resource, and the Ban Nong Sai part was researched and sampled. To achieve this goal, petrographic analysis(kerogen types), geochemical analysis(total organic carbon content, TOC), vitrinite reflectance(Ro), and Rock–Eval(RE) pyrolysis were carried out in this study. According to the findings, types Ⅱ, Ⅲ, and Ⅳ were identified using a modified Van-Krevelen diagram because the higher mature source rock showing hydrogen index(HI) and oxygen index(OI) are continuously depleted and raised. However,microscopic observation describes macerals as primarily sapropelic amorphinite, therefore, type I is important. The TOC was determined to be between 1.90% and 7.06%,which is considered very good to excellent. The original total organic carbon(TOCo) was decided to use its maceral components to determine how to convert extremely mature TOC to TOCo. It varies between 5.13% and 10.74% and reaches a maximum of 57.21% which is comparable to TOC. At 0.82%–1.04%, 443–451 ℃, 0.50%–38.10%, and69.00%–99.59% are the vitrinite reflectance(Ro), maximum temperature(Tmax), production index(PI), and transformation ratio(TR), respectively. Late peak maturity refers to a mixture of oil and gas, whereas most TR ratios refer to the main gas phase. Similarly, the petroleum residual shows no indication of gas trapped at a volume of6309.50 mcf/ac-ft. In summary, source rock potential was assessed within a suitable risk range defined by Tmax(445.70 ℃), Ro(0.91%), TR(90.63%), TOC(8.15%),shale thickness(46 m), and kerogen type(type I).
文摘Carbonaceous shale exposures of the Late Cretaceous Mamu Formation along Ifon-Uzebba road in western arm(Benin Flank) of Anambra Basin, southwestern Nigeria, were analyzed for bulk organic geochemical, molecular biological and poly-aromatic hydrocarbon(PAH) compositions to investigate the organic matter source, paleo-depositional condition, thermal maturity and petroleum potential of the unit. The bulk organic geochemistry was determined using Leco and Rock-Eval pyrolysis analyses while the biomarkers and PAH compositions were investigated using gas chromatography-mass spectrometer(GC-MS).The bulk organic geochemical parameters of the shale samples showed total organic carbon(TOC)(1.11-6.03 wt%), S2(0.49-11.73 mg HC/g Rock), HI(38-242 mg HC/g TOC) and Tmax(425-435 C) indicating good to excellent hydrocarbon source-rock. Typical HI-Tmax diagram revealed the shale samples mostly in the gas-prone Type Ⅲ kerogen region with few gas and oil-prone Type Ⅱ-Ⅲ kerogen. The investigated biomarkers(n-alkane, isoprenoid, terpane, hopane, sterane) and PAH(alkylnaphthalene, methylphenanthrene and dibenzothiophene) indicated that the carbonaceous shales contain mix contributions of terrestrial and marine organic matter inputs that were deposited in a deltaic to shallow marine settings and preserved under relatively anoxic to suboxic conditions.Thermal maturity parameters computed from Rock-Eval pyrolysis, biomarkers(hopane, sterane) and PAH(alkylnaphthalene, alkylphenanthrene, alkyldibenzothiophene) suggested that these carbonaceous shales in Anambra Basin have entered an early-mature stage for hydrocarbon generation. This is also supported by fluoranthene/pyrene(0.27-1.12), fluoranthene/(fluoranthene + pyrene)(0.21-0.53) ratios and calculated vitrinite reflectance values(0.49-0.63% Ro) indicative that these shales have mostly reached early oil window maturity, thereby having low hydrocarbon source potential.
文摘This paper makes an approach to the characteristics of the compound and carbon iso-topic composition of condensate in the Sichuan, Shaanxi-Gansu-Ningxia, Dongpu and Jiyangbasins in China. The results we have obtained show that the compound properties are re-lated to the maturity. The Paraffin Index Ⅰ and the Saturated-Aromatic Index (SAI) increasegradually from the immature to mature (or over mature) condensate. and the SAI valueincrease from 2 to more than 30. The carbonisotopic composition of condensate is control-led by the type of parent matter. If the oil and condensate come from the same source rock,they will have similar carbon isotopic composition. In the same region there is an obviousdifference in carbon isotopic composition between the condensate generated from coal-bear-ing strata and that from oil-source rocks. The difference can be regarded as a parameter fordistinguishing the coal-type gas from the oil-type gas. In the same basin the carbon isotop-ic composition of the natural gas-oil-condensate-kerogen related to the coal-bearing strata isdifferent from that related to the oil-source rock.
文摘Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. Anza basin occurs on a fault block within a Paleocene</span></span><span style="font-family:Verdana;"><span style="font-family:Verdana;"><span style="font-family:Verdana;">-</span></span></span><span><span><span style="font-family:""><span style="font-family:Verdana;">Cretaceous rift basin. T</span><span style="font-family:Verdana;">he methodological approach used for the evaluation of source rocks i</span><span style="font-family:Verdana;">ncluded petrophysical and geochemical methods to ascertain their potential. Well sections with </span></span></span></span><span style="font-family:Verdana;"><span style="font-family:Verdana;"><span style="font-family:Verdana;">a </span></span></span><span><span><span style="font-family:""><span style="font-family:Verdana;">higher shale-volume ratio were sampled for geochemical screeni</span><span style="font-family:Verdana;">ng to determine the organic richness and thermal maturity of poten</span><span style="font-family:Verdana;">tial source rocks, respectively. Source rock with organic richness ≥ 0.5</span><span style="white-space:nowrap;font-family:Verdana;">%</span><span style="font-family:Verdana;"> were evaluated further for their petroleum potential using Rock-Eval pyrolysis to determine their thermal maturity, organo-facies and </span><i><span style="font-family:Verdana;">in-situ </span></i><span style="font-family:Verdana;">generated hydrocarbons present in sedimentary facies. The geochemical evaluation of rock samples from the drilled wells’ sections of Chalbi-3 and Sirius-1 confirmed both oil and gas potential. Gas Chromatography and Mass Spectrometry (GCMS) were used to characterize the biomarker signatures and oil-oil correlation of Sirius-1 samples. A predictive model was developed to integrate the petrophysical and geochemical da
文摘Azraq area occupied more than 1400 sq. km in the central part of Jordan. The stratigraphic sequences in the area consist of a lithological bedding of classic and carbonate rocks with representing good factors for oil generation and accumulation. Wadi Sir (WS-2) Sediments have geochemical characteristics of a typical source rocks for oil source rocks which are mature below 9843 ft, and carbonate rocks of Hummar, Shueb, and Wadi Sir-2 formation formations (Turonian Cenomanian age) are a reservoir rocks, where reservoirs are capped by shale and argillaceous limestone which is sufficiently thick to cap underlying reservoir. Twenty wells have been drilled in different blocks in the Azraq area, and oil of 32 API has been discovered in 1982, in the area, and starts natural flow production about 1500 bbl/day from few wells, then production start decreasing due to lower reservoir pressure, then sucker rod pumps were used to produce oil. In this study, the regional maturity of the Wadi Sir-2 sediments appear that mature oil generation sources rocks occur within the northwesterly trending depression of the area where maturity of WS-2 sediments below 9843 ft occurs, these mature source rocks amount to about 220 sq. km, based on average thickness of 108.27 ft for WS-2 sediments and extractable organic matter that was determined 3008 ppm. The volumetric method indicates that the total oil in place in the area is 480215 tons, taking a primary recovery factor of 12% then the total recoverable oil is 57,625 tons, while the cumulative oil producing is 53,137 tons.
基金The authors would like to thank the National Natural Science Foundation of China(Nos.41672139,41690134)China Geological Survey Project(No.DD20190561-1)China National Science and Technology Major Project(No.2016ZX05034-002-003)for financial assistance to this research。
文摘The Lower Cambrian Niutitang and Sinian Doushantuo shales are the most important and widespread source rocks and target layers in South China. Reliable data of the thermal maturity of organic matter(OM) is widely used to assess hydrocarbon generation and is a key property used in determining the viability and hydrocarbon potential of these new shales. Nevertheless, traditional thermal maturity indicators are no longer suited to the vitrinite-lack marine shales. This study aims to combine high throughput Raman and infrared spectroscopy analysis to confirm and validate the thermal maturity in comparison with the bitumen reflectance(R_(b)). Raman parameters such as the differences between the positions of the two bands(V_(G)–V_(D)) are strong parameters for calculating the thermal maturity in a large vitrinite reflectance(R_(o)) ranging from 1.60% to 3.80%. The infrared spectroscopy analysis indicates that the aromatic C=C bands and CH_(2)/CH_(3) aliphatic groups both are closely correlated with thermal maturity. The calculated R_(o) results from Raman and infrared spectroscopy are in strong coincidence with the R_(b). The relationships between R_(b) and pore volumes/surface areas(calculated from N_(2) adsorption) indicate that the sample with R_(b) of 3.40% has the lowest pore volumes and surface areas. Focused ion beam scanning electron microscopy(FIB-SEM) observations of OM pores indicate that R_(o) of approximately 3.60% may be an upper limit for OM porosity development. Obviously, kerogen Raman and infrared spectroscopy can indicate methods for reducing the risk in assessing maturity with practical, low-cost accurate results. Exploration of shale gas in the high maturity(>3.40%–3.60%) region carries huge risks.
