Zhuo Gong, Shangbin Chen, Hubert Ishimwe, Shaojie Zhang, Jamil Khan, Yang Wang, Xiong Sun
The micromechanical properties of shale are crucial for the modeling and prediction of its macromechanical properties. However, the elastic properties have not been comprehensively understood at nano- and microscales. In the present study, the mechanics-component mapping and logarithm filtering methods are proposed to overcome the defect of atomic force microscopy in identifying shale components to investigate the micromechanical properties of shale. Microscopically, the elasticity of shale is heterogeneous. Heterogeneous elastic characteristics of dolomite and quartz are caused by crystal structure anisotropy, isomorphism, and lattice defects. The anisotropy of crystal structure dominates the variation of Young’s modulus of dolomite and quartz. The Young’s modulus of framboidal pyrite depends greatly on its crystal evolution. The heterogeneous elasticity of organic matter is caused by the disordered molecular structure, the maturity variation, and the mixing of different organic macerals. Because of the difference in Young’s modulus among minerals, the metasomatism of feldspar by calcite, quartz, and clay minerals alters the micromechanical properties of shale. Our study reveals that mineral crystal structure characteristics, diagenesis, and organic petrological factors control the mechanical properties of shale microscopically.
{"title":"Study on microscale mechanical properties of minerals and organic matter in shale based on atomic force microscopy","authors":"Zhuo Gong, Shangbin Chen, Hubert Ishimwe, Shaojie Zhang, Jamil Khan, Yang Wang, Xiong Sun","doi":"10.1306/11152322060","DOIUrl":"https://doi.org/10.1306/11152322060","url":null,"abstract":"The micromechanical properties of shale are crucial for the modeling and prediction of its macromechanical properties. However, the elastic properties have not been comprehensively understood at nano- and microscales. In the present study, the mechanics-component mapping and logarithm filtering methods are proposed to overcome the defect of atomic force microscopy in identifying shale components to investigate the micromechanical properties of shale. Microscopically, the elasticity of shale is heterogeneous. Heterogeneous elastic characteristics of dolomite and quartz are caused by crystal structure anisotropy, isomorphism, and lattice defects. The anisotropy of crystal structure dominates the variation of Young’s modulus of dolomite and quartz. The Young’s modulus of framboidal pyrite depends greatly on its crystal evolution. The heterogeneous elasticity of organic matter is caused by the disordered molecular structure, the maturity variation, and the mixing of different organic macerals. Because of the difference in Young’s modulus among minerals, the metasomatism of feldspar by calcite, quartz, and clay minerals alters the micromechanical properties of shale. Our study reveals that mineral crystal structure characteristics, diagenesis, and organic petrological factors control the mechanical properties of shale microscopically.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"170 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139902401","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Aly Abdelaziz, Greg M. Baniak, Thomas F. Moslow, Alessandro Terzuoli, Giovanni Grasselli
Sedimentology is a key technical discipline in the energy and resource industry. One of its greatest benefits is in the detailed description and interpretation of full-diameter core as well as wellbore cutting samples. Such information adds significant value to hydrocarbon exploration and development by providing the basis for determining reservoir characterization and constructing precise subsurface stratigraphic models. Typically, such information is gathered in a hand-drawn format and/or produced in a computer-aided graphic illustration software format. Although this information is invaluable, it is hard to come by due to associated costs, and when available, it is limited to the above formats. The work presented herein proposes a novel approach to digitize the information contained within graphic logs. The digitized data are captured in a manner that allows it to be mapped into various other software. Hence, adopting such an approach provides unprecedented value in terms of harvesting sedimentological and petrographic data and integrating them into various other fields.
{"title":"A novel method for digitizing sedimentological graphic logs and exporting into reservoir modeling software","authors":"Aly Abdelaziz, Greg M. Baniak, Thomas F. Moslow, Alessandro Terzuoli, Giovanni Grasselli","doi":"10.1306/10182321114","DOIUrl":"https://doi.org/10.1306/10182321114","url":null,"abstract":"Sedimentology is a key technical discipline in the energy and resource industry. One of its greatest benefits is in the detailed description and interpretation of full-diameter core as well as wellbore cutting samples. Such information adds significant value to hydrocarbon exploration and development by providing the basis for determining reservoir characterization and constructing precise subsurface stratigraphic models. Typically, such information is gathered in a hand-drawn format and/or produced in a computer-aided graphic illustration software format. Although this information is invaluable, it is hard to come by due to associated costs, and when available, it is limited to the above formats. The work presented herein proposes a novel approach to digitize the information contained within graphic logs. The digitized data are captured in a manner that allows it to be mapped into various other software. Hence, adopting such an approach provides unprecedented value in terms of harvesting sedimentological and petrographic data and integrating them into various other fields.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"29 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769819","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Super giants of oil are present in the hypersaline Qianjiang shale of the Jianghan Basin. Although the oil in place of intersalt shale is controlled potentially by the total organic carbon (TOC) content, the extremely high values of the oil saturation index (OSI), ranging from 100 to 600 mg/g TOC, are widely revealed to be a result of lateral charging of self-sourced petroleum from deep sags. However, a comprehensive review of the literature combined with a case study of producing wells leads to new insights into the retention and migration of oil within the hypersaline Qianjiang shale. Except for the lateral migration, vertical oil migration and oil retention within sulfur-rich kerogen in situ are important replenishments, if not key factors, accounting for the enrichment of high-quality petroleum fluids in the Qianjiang shale. Intraformational migration of oil vertically from source rock layers to juxtaposed shale reservoirs is evidenced by (1) anomalously high OSI values of >400 mg/g TOC, (2) negative expulsion efficiency values, and (3) preferential expulsion of saturate hydrocarbons > aromatic hydrocarbons > polar compounds. Notably, the widely used maturity parameters are unsuitable for assessing the sulfur-rich Qianjiang shale play. Therefore, previous findings on the updip oil migration within individual cyclothem units are questionable. We believe that the present concerns regarding oil retention and migration within the hypersaline Qianjiang shale deserve the focus of much debate and suggest their re-examination.
{"title":"New insights on the retention and migration of shale oil within the hypersaline Qianjiang Formation in the Jianghan Basin, China","authors":"Zhiliang He, Yuanjia Han, Qinglai Luo, Fu Wang, Furong Wang, Shiqiang Wu","doi":"10.1306/11022323026","DOIUrl":"https://doi.org/10.1306/11022323026","url":null,"abstract":"Super giants of oil are present in the hypersaline Qianjiang shale of the Jianghan Basin. Although the oil in place of intersalt shale is controlled potentially by the total organic carbon (TOC) content, the extremely high values of the oil saturation index (OSI), ranging from 100 to 600 mg/g TOC, are widely revealed to be a result of lateral charging of self-sourced petroleum from deep sags. However, a comprehensive review of the literature combined with a case study of producing wells leads to new insights into the retention and migration of oil within the hypersaline Qianjiang shale. Except for the lateral migration, vertical oil migration and oil retention within sulfur-rich kerogen in situ are important replenishments, if not key factors, accounting for the enrichment of high-quality petroleum fluids in the Qianjiang shale. Intraformational migration of oil vertically from source rock layers to juxtaposed shale reservoirs is evidenced by (1) anomalously high OSI values of >400 mg/g TOC, (2) negative expulsion efficiency values, and (3) preferential expulsion of saturate hydrocarbons > aromatic hydrocarbons > polar compounds. Notably, the widely used maturity parameters are unsuitable for assessing the sulfur-rich Qianjiang shale play. Therefore, previous findings on the updip oil migration within individual cyclothem units are questionable. We believe that the present concerns regarding oil retention and migration within the hypersaline Qianjiang shale deserve the focus of much debate and suggest their re-examination.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"8 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769822","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The modern karst systems of Guizhou Province in southern China are examined as the key analogues for fault-controlled paleokarst reservoirs of the Shunbei oil field in the Tarim Basin in northwestern China. The size, distribution, and geometry of karst features are quantitatively described on millimeter-to-kilometer scales, and then we discuss their relationships to the faults, fractures, and bedding surfaces. A three-stage evolutionary model of the modern Guizhou karst is proposed, illustrating how faults and fractures control the flow pathways of drainage and the extent and processes of karstification. Middle Ordovician karstification in Shunbei was controlled by strike-slip faults and followed a similar pattern with Guizhou modern karst. Surface drainage flowed mostly along the gently sloping stratigraphic boundary between the Middle Ordovician and the Upper Ordovician (T74) stratigraphic surface and then downward along steep strike-slip faults. The consistency between the No. 1 fault strike and the southwest-oriented slope resulted in the formation of large-scale underground interconnected paleokarst cave systems at depths of 60 to 107 m. However, No. 5 and No. 7 faults formed fault-controlled paleokarst cavity along deep faults at depths of 0 to 450 m, displaying heterogeneous vertical distribution and poor connectivity in plane. These findings can aid in the design of well trajectories and thus improve exploration and development efficiency in Shunbei and similar fault-controlled paleokarst-dominated carbonate reservoirs.
{"title":"Guizhou modern karsts as analogues for paleokarst reservoirs in the Shunbei oil field, Tarim Basin, China","authors":"Jingbin Wang, Dongya Zhu, Zhiliang He, Haiming Song, Quanyou Liu, Cheng Zeng, Tianbo Yang, Qian Ding","doi":"10.1306/11152321157","DOIUrl":"https://doi.org/10.1306/11152321157","url":null,"abstract":"The modern karst systems of Guizhou Province in southern China are examined as the key analogues for fault-controlled paleokarst reservoirs of the Shunbei oil field in the Tarim Basin in northwestern China. The size, distribution, and geometry of karst features are quantitatively described on millimeter-to-kilometer scales, and then we discuss their relationships to the faults, fractures, and bedding surfaces. A three-stage evolutionary model of the modern Guizhou karst is proposed, illustrating how faults and fractures control the flow pathways of drainage and the extent and processes of karstification. Middle Ordovician karstification in Shunbei was controlled by strike-slip faults and followed a similar pattern with Guizhou modern karst. Surface drainage flowed mostly along the gently sloping stratigraphic boundary between the Middle Ordovician and the Upper Ordovician (T74) stratigraphic surface and then downward along steep strike-slip faults. The consistency between the No. 1 fault strike and the southwest-oriented slope resulted in the formation of large-scale underground interconnected paleokarst cave systems at depths of 60 to 107 m. However, No. 5 and No. 7 faults formed fault-controlled paleokarst cavity along deep faults at depths of 0 to 450 m, displaying heterogeneous vertical distribution and poor connectivity in plane. These findings can aid in the design of well trajectories and thus improve exploration and development efficiency in Shunbei and similar fault-controlled paleokarst-dominated carbonate reservoirs.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"10 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769816","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wenzhi Zhao, Hongliu Zeng, Zhaohui Xu, Suyun Hu, Qilong Fu
Broad, low-relief carbonate platforms are commonly relatively flat lying and show minimal topographic relief. These characteristics make the platforms difficult to interpret using seismic data. To systematically analyze these platforms for reservoirs, a seismic-sedimentological workflow was implemented to investigate the paleogeomorphology and reservoir quality of the Cambrian Longwangmiao Formation (LWM) in the Moxi–Gaoshiti area of the Sichuan Basin, China.Conventional core and wire-line log data indicate that carbonate lithofacies are composed of completely dolomitized grainstones, packstones, and wackestones to mudstones. Associated depositional environments were interpreted as shoal complex (shoal crest, shoal margin, and intershoal), lagoon, and deep shelf. The low (4%–8%) porosity reservoirs are largely related to the shoal complex facies. Two third-order sequences were correlated throughout the field area, each demonstrating an upward-shallowing trend. The reservoir-quality rocks were formed in the highstand systems tracts of the sequences.Lacking diagnostic shallow-water indicative seismic facies (e.g., the topset of clinoforms), seismic paleogeomorphology was assessed by restoring the paleostructure at the top of the LWM and then evaluating the gross thickness of the LWM to establish the accumulation rate of sediments across the area. This approach demonstrated a fair correlation to measured reservoir-thickness data from wire-line logs, indicating that the paleogeomorphology and depositional facies were largely controlled by a syndepositional, en echelon fault system that determined the distribution of shallow-water shoal complexes and deeper shelf areas across the field area. Seismic lithology determination by amplitude analysis of multiple frequency panels provided a quantitative assessment of reservoir distribution, supplementing the qualitative paleogeomorphologic maps for field development and reservoir modeling.
{"title":"Seismic sedimentology of a broad, low-relief carbonate platform: The Cambrian Longwangmiao Formation, Moxi–Gaoshiti area, Sichuan Basin, China","authors":"Wenzhi Zhao, Hongliu Zeng, Zhaohui Xu, Suyun Hu, Qilong Fu","doi":"10.1306/02242318016","DOIUrl":"https://doi.org/10.1306/02242318016","url":null,"abstract":"Broad, low-relief carbonate platforms are commonly relatively flat lying and show minimal topographic relief. These characteristics make the platforms difficult to interpret using seismic data. To systematically analyze these platforms for reservoirs, a seismic-sedimentological workflow was implemented to investigate the paleogeomorphology and reservoir quality of the Cambrian Longwangmiao Formation (LWM) in the Moxi–Gaoshiti area of the Sichuan Basin, China.Conventional core and wire-line log data indicate that carbonate lithofacies are composed of completely dolomitized grainstones, packstones, and wackestones to mudstones. Associated depositional environments were interpreted as shoal complex (shoal crest, shoal margin, and intershoal), lagoon, and deep shelf. The low (4%–8%) porosity reservoirs are largely related to the shoal complex facies. Two third-order sequences were correlated throughout the field area, each demonstrating an upward-shallowing trend. The reservoir-quality rocks were formed in the highstand systems tracts of the sequences.Lacking diagnostic shallow-water indicative seismic facies (e.g., the topset of clinoforms), seismic paleogeomorphology was assessed by restoring the paleostructure at the top of the LWM and then evaluating the gross thickness of the LWM to establish the accumulation rate of sediments across the area. This approach demonstrated a fair correlation to measured reservoir-thickness data from wire-line logs, indicating that the paleogeomorphology and depositional facies were largely controlled by a syndepositional, en echelon fault system that determined the distribution of shallow-water shoal complexes and deeper shelf areas across the field area. Seismic lithology determination by amplitude analysis of multiple frequency panels provided a quantitative assessment of reservoir distribution, supplementing the qualitative paleogeomorphologic maps for field development and reservoir modeling.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"45 8 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769898","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The paleokarst systems of the Ordovician carbonate rocks in the Tarim Basin, northwestern China, comprise economically significant oil and gas reservoirs and display complex cave architectures. Based on comprehensive analysis of seismic, well log, core, and outcrop data, the cave architecture and controlling processes of the Ordovician paleokarst systems in the western margin and central uplift belt of the basin are documented. Cave fills of the paleokarst systems are composed mainly of collapse breccias, crackle or mosaic breccias, chaotic breccias, terrestrial sediment fills, and calcareous muddy deposits. Primary architectural elements of the paleokarst systems include surface collapse caves or pits, fractured roofs and walls, sinkholes and associated small-scale caves, cave-level or fault-cave complexes, fractured layers with fractured pores or cavities, and densely spaced small cavity layers. The paleokarst cave structures are characterized by the development of multiple phreatic cave-level or fault-cave complexes and were constrained mainly by the interplay of changing phreatic zones due to multiple stage uplifts or relative sea-level falls and existing high-angle fault belts. They were also transformed by karstification with composite unconformities and hypogenic process. The paleokarst system in the central uplift belt formed in a carbonate island environment during the late Middle Ordovician, whereas the system in the western basin margin developed in an attached carbonate platform setting at the end of the Late Ordovician. Partially filled cave-level or fault-cave complexes, fractured cave roofs, or fractured intervals with fractured pores or cavities comprise the most significant reservoirs in the paleokarst systems.
{"title":"Paleocave architectures and controlling processes of the Ordovician carbonate paleokarst systems in western and central Tarim Basin, northwestern China","authors":"Changsong Lin, Haijun Yang, Jianfa Han, Jingyan Liu, Zhenzhong Cai, Hao Li, Manli Zhang","doi":"10.1306/09212319006","DOIUrl":"https://doi.org/10.1306/09212319006","url":null,"abstract":"The paleokarst systems of the Ordovician carbonate rocks in the Tarim Basin, northwestern China, comprise economically significant oil and gas reservoirs and display complex cave architectures. Based on comprehensive analysis of seismic, well log, core, and outcrop data, the cave architecture and controlling processes of the Ordovician paleokarst systems in the western margin and central uplift belt of the basin are documented. Cave fills of the paleokarst systems are composed mainly of collapse breccias, crackle or mosaic breccias, chaotic breccias, terrestrial sediment fills, and calcareous muddy deposits. Primary architectural elements of the paleokarst systems include surface collapse caves or pits, fractured roofs and walls, sinkholes and associated small-scale caves, cave-level or fault-cave complexes, fractured layers with fractured pores or cavities, and densely spaced small cavity layers. The paleokarst cave structures are characterized by the development of multiple phreatic cave-level or fault-cave complexes and were constrained mainly by the interplay of changing phreatic zones due to multiple stage uplifts or relative sea-level falls and existing high-angle fault belts. They were also transformed by karstification with composite unconformities and hypogenic process. The paleokarst system in the central uplift belt formed in a carbonate island environment during the late Middle Ordovician, whereas the system in the western basin margin developed in an attached carbonate platform setting at the end of the Late Ordovician. Partially filled cave-level or fault-cave complexes, fractured cave roofs, or fractured intervals with fractured pores or cavities comprise the most significant reservoirs in the paleokarst systems.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"36 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139769907","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Many authors become frustrated with the amount of time it takes to review, accept, and publish their work in peer-reviewed scientific journals. An analysis of papers published in volume 107 of the AAPG Bulletin through November 2023 shows publication took an average of 25 months from manuscript submission to publication. Most of the time is consumed during the review period that averaged 15 months. The length of the review period includes the time taken to complete revisions, which averaged 12 months, and is a function of the manuscript quality and the number of revisions required prior to the final decision. Recommendations are provided to assist authors in preparing manuscripts for submission and guidelines for reviewers to help expedite the review process.
{"title":"Why does it take so long to publish a paper in the AAPG Bulletin?","authors":"Wayne K. Camp","doi":"10.1306/11092323076","DOIUrl":"https://doi.org/10.1306/11092323076","url":null,"abstract":"Many authors become frustrated with the amount of time it takes to review, accept, and publish their work in peer-reviewed scientific journals. An analysis of papers published in volume 107 of the AAPG Bulletin through November 2023 shows publication took an average of 25 months from manuscript submission to publication. Most of the time is consumed during the review period that averaged 15 months. The length of the review period includes the time taken to complete revisions, which averaged 12 months, and is a function of the manuscript quality and the number of revisions required prior to the final decision. Recommendations are provided to assist authors in preparing manuscripts for submission and guidelines for reviewers to help expedite the review process.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"11 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139483625","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Karst reservoirs in the Ordovician carbonates of Tarim Basin are currently major targets of deep and ultra-deep hydrocarbon exploration and development in China. New drilling and seismic data show that these deep-buried carbonate karst reservoirs are spatially dependent on strike-slip faulting. Based on the geological and geophysical data, this study developed an attempt to determine the impact and spatial distribution of strike-slip faulting on carbonate karst reservoirs in the Tahe oil field. Strike-slip faults in the Taha area can be classified as first order, second order, and third order. Fault damage zones are distributed along the strike-slip faults, and their widths have a positive correlation with fault order. Influenced by strike-slip faults, fault-related fractures, and rock mechanical properties, the development degree and spatial distribution of carbonate karst reservoirs display strong heterogeneity. The horizontal heterogeneity of karst reservoirs is controlled by strike-slip faults with different scales and strikes, and the vertical heterogeneity is combined results of the strike-slip faulting and mechanical properties of carbonates. In the Tahe area, ultra-deep carbonate karst reservoirs are generally concentrated within 550 m (∼1800 ft) of the damage zone of north-northeast– and north-northwest–striking first-order and second-order strike-slip faults. Fewer and smaller-scale karst reservoirs are developed further away from the fault core. Additionally, fracture intensity is greater in more brittle facies enhancing the karstification. The results from this research provide an analogue for understanding the distribution of fault-controlled karsting in deep carbonate reservoirs around the world.
{"title":"Strike-slip fault control on karst in ultra-deep carbonates, Tarim Basin, China","authors":"Lianbo Zeng, Jinxiong Shi, Qingyou Ma, Wenya Lyu, Shaoqun Dong, Dongsheng Cao, Hehua Wei","doi":"10.1306/09212321161","DOIUrl":"https://doi.org/10.1306/09212321161","url":null,"abstract":"Karst reservoirs in the Ordovician carbonates of Tarim Basin are currently major targets of deep and ultra-deep hydrocarbon exploration and development in China. New drilling and seismic data show that these deep-buried carbonate karst reservoirs are spatially dependent on strike-slip faulting. Based on the geological and geophysical data, this study developed an attempt to determine the impact and spatial distribution of strike-slip faulting on carbonate karst reservoirs in the Tahe oil field. Strike-slip faults in the Taha area can be classified as first order, second order, and third order. Fault damage zones are distributed along the strike-slip faults, and their widths have a positive correlation with fault order. Influenced by strike-slip faults, fault-related fractures, and rock mechanical properties, the development degree and spatial distribution of carbonate karst reservoirs display strong heterogeneity. The horizontal heterogeneity of karst reservoirs is controlled by strike-slip faults with different scales and strikes, and the vertical heterogeneity is combined results of the strike-slip faulting and mechanical properties of carbonates. In the Tahe area, ultra-deep carbonate karst reservoirs are generally concentrated within 550 m (∼1800 ft) of the damage zone of north-northeast– and north-northwest–striking first-order and second-order strike-slip faults. Fewer and smaller-scale karst reservoirs are developed further away from the fault core. Additionally, fracture intensity is greater in more brittle facies enhancing the karstification. The results from this research provide an analogue for understanding the distribution of fault-controlled karsting in deep carbonate reservoirs around the world.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"20 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139484000","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. Taras Bryndzia, Calum I. Macaulay, Alexander P. Litvinchuk, Brian D. Monteleone
Bedding-parallel calcite layers (BPCLs) preserving a fibrous “beef” texture are common throughout the overmature Haynesville Formation shale. Their interfaces with the host shale contain radiating splays of anhydrite pseudomorphs after gypsum rosettes, suggesting either a primary evaporitic or an early burial origin. In places, the calcite layers contain remnant barite or anhydrite in crystallographic alignment with its host calcite, indicating that the calcite formed by replacing a fibrous sulfate precursor phase.During burial and heating, maturation of source rock organic matter resulted in the expulsion of hydrocarbons (oil and gas). Consequently, the redox state of the shale and hydrocarbon system became reducing, as indicated by the ubiquitous presence of H2S. Both anhydrite and barite are unstable in the presence of H2S and were consumed by thermochemical sulfate reduction. At peak burial, liquid hydrocarbons cracked to CH4 gas and remnant solid pyrobitumen, which typically occupies the median suture zone of the fibrous calcite layers. It was along this median suture that calcite replacement of anhydrite and barite was initiated, proceeding to replace sulfate minerals from the center of the layer out toward the shale contact.We estimated the in situ CH4 pressure attending thermochemical sulfate reduction in the Haynesville shale by using microlaser Raman spectroscopy to directly measure the density of CH4 gas inclusions in BPCLs. Average fluid pressure gradients preserved within the fibrous calcite are approximately 0.87 ± 0.03 psi/ft (±1σ; n = 4), considerably above hydrostatic but below both overburden and shale fracture gradients. We found no evidence to suggest that fluid pressures exceeded lithostatic or that fibrous calcite grew in dilated vein systems from their margins toward the center of the BPCLs.The replacement of primary bedded anhydrite and barite by calcite preserves the original orientation of the precursor sulfate minerals—in other words, their fibrous beef texture is an inherited feature. The replacement of sulfate by calcite results in a solid volume loss of approximately 20 to 30 vol. %. Collapse of the layers due to loss of volume and overburden stress results in the minimum horizontal stress being parallel to bedding. Pyrobitumen layers were compressed and disaggregated due to tensile failure. Both late-stage calcite and disaggregated pyrobitumen subsequently grew in the direction of minimum horizontal stress (i.e., parallel to bedding).
{"title":"Origin of bedding-parallel calcite “beef” layers in the Upper Jurassic Haynesville shale, northwestern Louisiana","authors":"L. Taras Bryndzia, Calum I. Macaulay, Alexander P. Litvinchuk, Brian D. Monteleone","doi":"10.1306/01192321189","DOIUrl":"https://doi.org/10.1306/01192321189","url":null,"abstract":"Bedding-parallel calcite layers (BPCLs) preserving a fibrous “beef” texture are common throughout the overmature Haynesville Formation shale. Their interfaces with the host shale contain radiating splays of anhydrite pseudomorphs after gypsum rosettes, suggesting either a primary evaporitic or an early burial origin. In places, the calcite layers contain remnant barite or anhydrite in crystallographic alignment with its host calcite, indicating that the calcite formed by replacing a fibrous sulfate precursor phase.During burial and heating, maturation of source rock organic matter resulted in the expulsion of hydrocarbons (oil and gas). Consequently, the redox state of the shale and hydrocarbon system became reducing, as indicated by the ubiquitous presence of H2S. Both anhydrite and barite are unstable in the presence of H2S and were consumed by thermochemical sulfate reduction. At peak burial, liquid hydrocarbons cracked to CH4 gas and remnant solid pyrobitumen, which typically occupies the median suture zone of the fibrous calcite layers. It was along this median suture that calcite replacement of anhydrite and barite was initiated, proceeding to replace sulfate minerals from the center of the layer out toward the shale contact.We estimated the in situ CH4 pressure attending thermochemical sulfate reduction in the Haynesville shale by using microlaser Raman spectroscopy to directly measure the density of CH4 gas inclusions in BPCLs. Average fluid pressure gradients preserved within the fibrous calcite are approximately 0.87 ± 0.03 psi/ft (±1σ; n = 4), considerably above hydrostatic but below both overburden and shale fracture gradients. We found no evidence to suggest that fluid pressures exceeded lithostatic or that fibrous calcite grew in dilated vein systems from their margins toward the center of the BPCLs.The replacement of primary bedded anhydrite and barite by calcite preserves the original orientation of the precursor sulfate minerals—in other words, their fibrous beef texture is an inherited feature. The replacement of sulfate by calcite results in a solid volume loss of approximately 20 to 30 vol. %. Collapse of the layers due to loss of volume and overburden stress results in the minimum horizontal stress being parallel to bedding. Pyrobitumen layers were compressed and disaggregated due to tensile failure. Both late-stage calcite and disaggregated pyrobitumen subsequently grew in the direction of minimum horizontal stress (i.e., parallel to bedding).","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"11 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139495497","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Analyses of oil production data from the Weyburn Midale oil pool reveal that CO2 injection substantially reduced the decline trend of annual oil outputs in an exponential way with an average decline rate of 2.5%, which is two times lower than that of the worldwide total giant oil fields (5.5% or 6.5%). Based on its production data, it is projected that without CO2 injection the pool would have ended its life by 2016 with an ultimate cumulative oil output of 448.1 million bbl (71.2 million m3) and a recovery factor of only 24.4%. However, with continuous CO2 injection, by 2055 when the pool will be celebrating its 100th birthday, it can still produce 4 million bbl (0.6 million m3) of oil annually with a cumulative output of 801.8 million bbl (127.5 million m3) of oil and a recovery factor of 43.7%, whereas an additional 9.2 TCF (259.9 billion m3) of CO2 will be poured into the pool. By 2100, after 100 yr of CO2 injection, the pool’s annual oil output could be near 1.5 million bbl (0.2 million m3) and its cumulative oil output would reach 914.0 million bbl (145.3 million m3) representing a recovery factor of 49.8%, whereas 21.3 TCF (604 billion m3) of more CO2 could be injected into and permanently stored in the pool. The CO2-enhanced oil recovery could extend the pool’s lifespan to 39 or even 84 more years.
{"title":"The impact of CO2-enhanced oil recovery on oil production and lifespan of old oil pools: A Canadian example","authors":"Mengwei Zhao","doi":"10.1306/09212322125","DOIUrl":"https://doi.org/10.1306/09212322125","url":null,"abstract":"Analyses of oil production data from the Weyburn Midale oil pool reveal that CO2 injection substantially reduced the decline trend of annual oil outputs in an exponential way with an average decline rate of 2.5%, which is two times lower than that of the worldwide total giant oil fields (5.5% or 6.5%). Based on its production data, it is projected that without CO2 injection the pool would have ended its life by 2016 with an ultimate cumulative oil output of 448.1 million bbl (71.2 million m3) and a recovery factor of only 24.4%. However, with continuous CO2 injection, by 2055 when the pool will be celebrating its 100th birthday, it can still produce 4 million bbl (0.6 million m3) of oil annually with a cumulative output of 801.8 million bbl (127.5 million m3) of oil and a recovery factor of 43.7%, whereas an additional 9.2 TCF (259.9 billion m3) of CO2 will be poured into the pool. By 2100, after 100 yr of CO2 injection, the pool’s annual oil output could be near 1.5 million bbl (0.2 million m3) and its cumulative oil output would reach 914.0 million bbl (145.3 million m3) representing a recovery factor of 49.8%, whereas 21.3 TCF (604 billion m3) of more CO2 could be injected into and permanently stored in the pool. The CO2-enhanced oil recovery could extend the pool’s lifespan to 39 or even 84 more years.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"4 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139507591","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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