Economic geology

@article{degolyer1918the,
    author = "DeGolyer, E.",
    title = "The Geology of Cuban Petroleum Deposits",
    year = "1918",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/3d932509-16b1-11d7-8645000102c1865d",
    doi = "10.1306/3d932509-16b1-11d7-8645000102c1865d",
    number = "1",
    openalex = "W2055650813",
    pages = "133-167",
    volume = "2"
}

@book{moore1940coal25,
    author = "Moore, E. S",
    title = "Coal",
    year = "1940",
    publisher = "Its Properties, Analysis, Classification, Extraction, Uses and Distribution [2nd ed.]: New York, John Wiley \& Sons, 473 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Moore, E. S., 1940, Coal: Its Properties, Analysis, Classification, Extraction, Uses and Distribution [2nd ed.]: New York, John Wiley \& Sons, 473 p.}"
}

@techreport{weaver1962challenge33,
    author = "Weaver, P",
    title = "Challenge to Cambrian prospecting",
    year = "1962",
    howpublished = "Bulletin of the American Association of Petroleum Geologists, v. 46, no. 10, p. 1941-1943",
    note = "talkorigins\_source = {true}; raw\_reference = {Weaver, P., 1962, Challenge to Cambrian prospecting: Bulletin of the American Association of Petroleum Geologists, v. 46, no. 10, p. 1941-1943.}"
}

@misc{brod1965oil7,
    author = "Brod, I. O. and Vysotskiy, I. V",
    title = "Oil and Gas Basins of the World",
    year = "1965",
    howpublished = "Moscow, Nedra Publishing House, 598 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Brod, I. O., and Vysotskiy, I. V., 1965, Oil and Gas Basins of the World: Moscow, Nedra Publishing House, 598 p.}"
}

@misc{popova1965organic27,
    author = "Popova, Z. P. and Glazunova, N. N",
    title = "Organic residues in the oil from Markovskii oil field",
    year = "1965",
    howpublished = "Academy of Sciences of the USSR Reports, v. 161, no. 3, p. 673-675; English translation by American Geological Institute, 1965, Academy of Science, USSR Reports, v.161, p. 67-69",
    note = "talkorigins\_source = {true}; raw\_reference = {Popova, Z. P., and Glazunova, N. N., 1965, Organic residues in the oil from Markovskii oil field: Academy of Sciences of the USSR Reports, v. 161, no. 3, p. 673-675; English translation by American Geological Institute, 1965, Academy of Science, USSR Reports, v.161, p. 67-69.}"
}

ABSTRACT The Cuanza basin is in northwestern Angola on the Atlantic Coast of West Africa. This basin is about 300 km. long north-south and 170 km. wide east-west, and contains an Early Cretaceous carbonate-evaporite sequence and a Late Cretaceous and Tertiary argillaceous-arenaceous sequence. The Precambrian crystalline basement is partly covered by extrusive rocks and granite-wash type sediments. Surface and subsurface sediments of the basin consist of Lower and Upper Cretaceous, Paleocene, Eocene, and Miocene strata. Occurrences of oil and gas have been reported in almost all of the stratigraphic units in the Cuanza basin, and there is major production from the Cretaceous rocks. Study of these hydrocarbon occurrences and of the geological history of the basin shows that close relationships exist between sources, migration, and entrapment of oil, and environment of deposition controlled by the basement and salt tectonics. During Early Cretaceous time, subsidence of the central part of a restricted basin determined the regional cyclical deposition of a carbonate-evaporite sequence providing a favorable situation for genesis and entrapment of oil. Thus, the deposition during Aptian time of a very fine crystalline limestone, interbedded with argillaceous limestone and overlain by an oölitic sandy calcarenite, itself underlying evaporites, had an important influence on the subsequent extent of oil accumulations in the Binga Formation. During Aptian-Albian time, differential subsidence on the western margin of the basin caused lateral interfingering of back-reef calcarenite, argillaceous carbonate, and evaporite. This interfingering is believed to be related closely to oil accumulations in this area. Very important vertical development of reef deposits in the Tonga area is related to lateral migration of the underlying Massive Salt, which flowed with the help of the excess of weight introduced by the growing reef. On the eastern margin, upper Albian reef buildups capped by marine shale also provided a favorable situation for generation and accumulation of oil. During Late Cretaceous and Tertiary time, a major basement flexure or fault zone appears to have been associated genetically downdip with deposits that accumulated with greater thickness than elsewhere. This flexure and the loci of maximum deposition moved eastward during Late Cretaceous and Paleocene, then westward during Eocene and Miocene. These thick formations, which are mainly argillaceous-arenaceous and which were deposited partly in deltaic and lagoonal environments, grade westward into thinner marine deposits and eastward into thinner continental deposits. During each particular epoch corresponding with a stabilization of this moving flexure, favorable conditions for genesis of hydrocarbons seem to be related to these transitional environments. Oil production is located above the Massive Salt at the crest of salt anticlines, and one small oil field has been discovered below the Massive Salt along a ridge of the Basement Complex in a pinch-out of sandstones between Precambrian mica-schist below, and salt above.

@article{doi1013065d25b47116c111d78645000102c1865d,
    author = "Brognon, Georges P. and Verrier, Georges R.",
    title = "Oil and Geology in Cuanza Basin of Angola",
    year = "1966",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The Cuanza basin is in northwestern Angola on the Atlantic Coast of West Africa. This basin is about 300 km. long north-south and 170 km. wide east-west, and contains an Early Cretaceous carbonate-evaporite sequence and a Late Cretaceous and Tertiary argillaceous-arenaceous sequence. The Precambrian crystalline basement is partly covered by extrusive rocks and granite-wash type sediments. Surface and subsurface sediments of the basin consist of Lower and Upper Cretaceous, Paleocene, Eocene, and Miocene strata. Occurrences of oil and gas have been reported in almost all of the stratigraphic units in the Cuanza basin, and there is major production from the Cretaceous rocks. Study of these hydrocarbon occurrences and of the geological history of the basin shows that close relationships exist between sources, migration, and entrapment of oil, and environment of deposition controlled by the basement and salt tectonics. During Early Cretaceous time, subsidence of the central part of a restricted basin determined the regional cyclical deposition of a carbonate-evaporite sequence providing a favorable situation for genesis and entrapment of oil. Thus, the deposition during Aptian time of a very fine crystalline limestone, interbedded with argillaceous limestone and overlain by an oölitic sandy calcarenite, itself underlying evaporites, had an important influence on the subsequent extent of oil accumulations in the Binga Formation. During Aptian-Albian time, differential subsidence on the western margin of the basin caused lateral interfingering of back-reef calcarenite, argillaceous carbonate, and evaporite. This interfingering is believed to be related closely to oil accumulations in this area. Very important vertical development of reef deposits in the Tonga area is related to lateral migration of the underlying Massive Salt, which flowed with the help of the excess of weight introduced by the growing reef. On the eastern margin, upper Albian reef buildups capped by marine shale also provided a favorable situation for generation and accumulation of oil. During Late Cretaceous and Tertiary time, a major basement flexure or fault zone appears to have been associated genetically downdip with deposits that accumulated with greater thickness than elsewhere. This flexure and the loci of maximum deposition moved eastward during Late Cretaceous and Paleocene, then westward during Eocene and Miocene. These thick formations, which are mainly argillaceous-arenaceous and which were deposited partly in deltaic and lagoonal environments, grade westward into thinner marine deposits and eastward into thinner continental deposits. During each particular epoch corresponding with a stabilization of this moving flexure, favorable conditions for genesis of hydrocarbons seem to be related to these transitional environments. Oil production is located above the Massive Salt at the crest of salt anticlines, and one small oil field has been discovered below the Massive Salt along a ridge of the Basement Complex in a pinch-out of sandstones between Precambrian mica-schist below, and salt above.",
    url = "https://doi.org/10.1306/5d25b471-16c1-11d7-8645000102c1865d",
    doi = "10.1306/5d25b471-16c1-11d7-8645000102c1865d",
    openalex = "W2029859313"
}

@article{drobot1966new10,
    author = "Drobot, D. I. and Isayev, V. P",
    title = "New data about the composition and properties of the lower Cambrian oil of the Prilenskii region of the Irkutskii oil basin",
    year = "1966",
    journal = "Academy of Science of the USSR, Siberian Department, Geology and Geophysics, v. 10, p. 32-41; English translation by American Geological Institute, 1967, International Geological Review, v.9, No.8, p. 1028-1035",
    note = "talkorigins\_source = {true}; raw\_reference = {Drobot, D. I., and Isayev, V. P., 1966, New data about the composition and properties of the lower Cambrian oil of the Prilenskii region of the Irkutskii oil basin: Academy of Science of the USSR, Siberian Department, Geology and Geophysics, v. 10, p. 32-41; English translation by American Geological Institute, 1967, International Geological Review, v.9, No.8, p. 1028-1035.}"
}

@misc{levorson1967geology24,
    author = "Levorson, A. I",
    title = "Geology of Petroleum [2nd ed.]",
    year = "1967",
    howpublished = "San Francisco, W.H. Freeman, 724 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Levorson, A. I., 1967, Geology of Petroleum [2nd ed.]: San Francisco, W.H. Freeman, 724 p.}"
}

@techreport{becker1968world5,
    author = "Becker, L. E. and Patton, J. B",
    title = "World occurance of petroleum in pre- Silurian rocks",
    year = "1968",
    howpublished = "Bulletin of the American Association of Petroleum Geologists, v. 52, no. 2, p. 224-245",
    note = "talkorigins\_source = {true}; raw\_reference = {Becker, L. E., and Patton, J. B., 1968, World occurance of petroleum in pre- Silurian rocks: Bulletin of the American Association of Petroleum Geologists, v. 52, no. 2, p. 224-245.}"
}

@misc{bakirov1969oil2,
    author = "Bakirov, A. A. and Ryabuknin, G. Y",
    title = "Oil and Gas Bearing Areas and Regions of the USSR",
    year = "1969",
    howpublished = "Moscow, Nedra Publishing House, 477 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Bakirov, A. A., and Ryabuknin, G. Y., 1969, Oil and Gas Bearing Areas and Regions of the USSR: Moscow, Nedra Publishing House, 477 p.}"
}

@misc{gladkov1970about15,
    author = "Gladkov, V. G. and Nikitin, V. P. and Khrenov, P. M",
    title = "About the question of kinematics of halogenating in the profiles and in the folded belt of the Southern part of the Siberian Platform",
    year = "1970",
    howpublished = "Academy of Sciences of the USSR Reports, v. 190, no. 2, p. 405-408; English translation by the American Geological Institute, 1970, Academy of Science, USSR Doklady, v.190, p. 42- 45",
    note = "talkorigins\_source = {true}; raw\_reference = {Gladkov, V. G., Nikitin, V. P., and Khrenov, P. M., 1970, About the question of kinematics of halogenating in the profiles and in the folded belt of the Southern part of the Siberian Platform: Academy of Sciences of the USSR Reports, v. 190, no. 2, p. 405-408; English translation by the American Geological Institute, 1970, Academy of Science, USSR Doklady, v.190, p. 42- 45.}"
}

@article{vassoyevich1970more32,
    author = "Vassoyevich, N. B. et al",
    title = "More about the question of oil and gas prospects in late Cambrian deposits",
    year = "1970",
    journal = "Soviet Geology, v. 4, p. 66-79; English translation by American Geological Institute, 1971, International Geology Review, v.13, No.3, p. 407-418",
    note = "talkorigins\_source = {true}; raw\_reference = {Vassoyevich, N. B. et al., 1970, More about the question of oil and gas prospects in late Cambrian deposits: Soviet Geology, v. 4, p. 66-79; English translation by American Geological Institute, 1971, International Geology Review, v.13, No.3, p. 407-418.}"
}

@misc{fassett1971geology11,
    author = "Fassett, J. E. and Hinds, J. S",
    title = "Geology and fuel resources of the Fruitland Formation and Kirtland Shale of the San Juan Basin, New Mexico and Colorado",
    year = "1971",
    howpublished = "United States Geological Survey, Professional Paper, v. 676; 76 pp",
    note = "talkorigins\_source = {true}; raw\_reference = {Fassett, J. E., and Hinds, J. S., 1971, Geology and fuel resources of the Fruitland Formation and Kirtland Shale of the San Juan Basin, New Mexico and Colorado: United States Geological Survey, Professional Paper, v. 676; 76 pp.}"
}

@misc{garilov1971about14,
    author = "Garilov, Y. Y. and Kulibakina, I. B. and Teplinskiy, G. I",
    title = "About the formation of hydrocarbon deposits of Markovskii oil field",
    year = "1971",
    howpublished = "Geology of Oil and Gas, v. 2, p. 30-31",
    note = "talkorigins\_source = {true}; raw\_reference = {Garilov, Y. Y., Kulibakina, I. B., and Teplinskiy, G. I., 1971, About the formation of hydrocarbon deposits of Markovskii oil field: Geology of Oil and Gas, v. 2, p. 30-31.}"
}

@misc{bazanov1973geological4,
    author = "Bazanov, E. A",
    title = "Geological structure of Yaraktinskoye oil field in Irkutsk region",
    year = "1973",
    howpublished = "Geology of Oil and Gas, v. 7, p. 15-18",
    note = "talkorigins\_source = {true}; raw\_reference = {Bazanov, E. A., 1973, Geological structure of Yaraktinskoye oil field in Irkutsk region: Geology of Oil and Gas, v. 7, p. 15-18.}"
}

Abstract The purpose of this work is to relate the principal observations of the various contributors to the volume within a broad background of regional geology and to make an estimation of the Canadian petroleum potential drawing heavily on this basic material. The 38 un-metamorphosed sedimentary basins recognized in this study have been classified into 7 types to provide a framework within which the petroleum potential could be estimated in a uniform manner, and to permit comparison with sedimentary basins of the world. Within the stable region 4 categories of basins are recognized: the craton centre, the craton margin, the craton margin disturbed (the latter lying at the interface with the mobile belt), and the rift or collapse basin. Two types of coastal margin basins are defined: the stable and unstable types. Finally, within the mobile belt are the intermontane basins. Each of these types is geometrically quite distinct as a result of its unique tectonic setting which in turn controls its sedimentological properties. The tectono-sedimentary character of each basin style is related in turn to a limited and characteristic association of types of petroleum occurrence. Those basins of relatively more negative tendency, i.e. the craton margin, rift, and unstable coastal margin types, are of higher petroleum potential because of their particular structural and stratigraphic attributes. An outline of the geological history of northern North America based on the study of four major stratigraphic sequences within the Phanerozoic serves to outline the evolution of the Canadian basins in time and space. The megasequences of continent-wide distribution were chosen to emphasize the significant tectonic events responsible for the basin formation, particularly with respect to generally accepted concepts of global tectonics. The estimates of potential are based on a variety of methods but all involve geological analysis. The volumetric method is used to test the reasonableness of the results against other regions of the world. The potential of the various basins varies widely from very low for those of the craton centre to high for those of the unstable coastal margins. These values are shown in a table that displays estimates of oil and gas resources and sedimentary volumes for all basins as well as a series of calculated parameters for each, such as oil and gas yields per cubic mile, combined yield of oil plus gas equivalent, etc. In addition, a tabular geological description for each basin provides a summary of the documentation for the estimates followed by an aggregate description of each basin type based on the described examples. Canada has a fairly comfortable conventional petroleum potential (including already discovered oil and gas) estimated at 85 billion barrels of oil and 577 trillion cubic feet of gas occurring within 3.5 million cubic miles of un-metamorphosed sedimentary rock, excluding the continental slopes. The bulk of the future resource lies in geographically remote areas and in areas involving severe logistical problems. No economic studies accompany this work so that it is impossible to say at what price and at what time the supply will be available. It is safe to say, however, that the bulk of it will be obtained only at relatively high cost. It is also fairly apparent that the short term lower cost future supply in the more accessible areas of the country is relatively small, amounting to a little over 6 billion barrels of oil and 55 trillion cubic feet of gas beyond that which has already been discovered. It is evident also that any possibility of major future reserves can lie only in three possible regions large enough volumetrically, or rich enough to contain them: the Mackenzie basin, the Sverdrup basin, and parts of the east coast off-shore area.

@article{openalexw2207850532,
    author = "McCrossan, R. G. and Porter, J. W.",
    title = "The Geology and Petroleum Potential of the Canadian Sedimentary Basins — A Synthesis",
    year = "1973",
    abstract = "Abstract The purpose of this work is to relate the principal observations of the various contributors to the volume within a broad background of regional geology and to make an estimation of the Canadian petroleum potential drawing heavily on this basic material. The 38 un-metamorphosed sedimentary basins recognized in this study have been classified into 7 types to provide a framework within which the petroleum potential could be estimated in a uniform manner, and to permit comparison with sedimentary basins of the world. Within the stable region 4 categories of basins are recognized: the craton centre, the craton margin, the craton margin disturbed (the latter lying at the interface with the mobile belt), and the rift or collapse basin. Two types of coastal margin basins are defined: the stable and unstable types. Finally, within the mobile belt are the intermontane basins. Each of these types is geometrically quite distinct as a result of its unique tectonic setting which in turn controls its sedimentological properties. The tectono-sedimentary character of each basin style is related in turn to a limited and characteristic association of types of petroleum occurrence. Those basins of relatively more negative tendency, i.e. the craton margin, rift, and unstable coastal margin types, are of higher petroleum potential because of their particular structural and stratigraphic attributes. An outline of the geological history of northern North America based on the study of four major stratigraphic sequences within the Phanerozoic serves to outline the evolution of the Canadian basins in time and space. The megasequences of continent-wide distribution were chosen to emphasize the significant tectonic events responsible for the basin formation, particularly with respect to generally accepted concepts of global tectonics. The estimates of potential are based on a variety of methods but all involve geological analysis. The volumetric method is used to test the reasonableness of the results against other regions of the world. The potential of the various basins varies widely from very low for those of the craton centre to high for those of the unstable coastal margins. These values are shown in a table that displays estimates of oil and gas resources and sedimentary volumes for all basins as well as a series of calculated parameters for each, such as oil and gas yields per cubic mile, combined yield of oil plus gas equivalent, etc. In addition, a tabular geological description for each basin provides a summary of the documentation for the estimates followed by an aggregate description of each basin type based on the described examples. Canada has a fairly comfortable conventional petroleum potential (including already discovered oil and gas) estimated at 85 billion barrels of oil and 577 trillion cubic feet of gas occurring within 3.5 million cubic miles of un-metamorphosed sedimentary rock, excluding the continental slopes. The bulk of the future resource lies in geographically remote areas and in areas involving severe logistical problems. No economic studies accompany this work so that it is impossible to say at what price and at what time the supply will be available. It is safe to say, however, that the bulk of it will be obtained only at relatively high cost. It is also fairly apparent that the short term lower cost future supply in the more accessible areas of the country is relatively small, amounting to a little over 6 billion barrels of oil and 55 trillion cubic feet of gas beyond that which has already been discovered. It is evident also that any possibility of major future reserves can lie only in three possible regions large enough volumetrically, or rich enough to contain them: the Mackenzie basin, the Sverdrup basin, and parts of the east coast off-shore area.",
    openalex = "W2207850532"
}

@techreport{sozansky1973origin31,
    author = "Sozansky, V. I",
    title = "Origin of salt deposits in deep-water basins of Atlantic Ocean",
    year = "1973",
    howpublished = "Bulletin of the American Association of Petroleum Geologists, v. 57, p. 589-590",
    note = "talkorigins\_source = {true}; raw\_reference = {Sozansky, V. I., 1973, Origin of salt deposits in deep-water basins of Atlantic Ocean: Bulletin of the American Association of Petroleum Geologists, v. 57, p. 589-590.}"
}

Sediments of the Gabon basin, 16,000–18,000 m thick, range in age from Early Cretaceous, or perhaps latest Jurassic, to recent. A salt layer of late Aptian age separates the almost completely continental facies of the presalt or Cocobeach sequence from the largely marine postsalt sediment. Since its inception, the basin has taken the form of a half graben whose eastern edge consisted of a series of three, or perhaps more, hinge zones which migrated successively farther west and which controlled the distribution of depositional environments and facies changes. The recognition of the hinge zones is of great importance in predicting reservoir trends. In its central part, the basin was bordered on the west by the Anguille basement high, and as the position of this high remained more or less fixed at the (present) continental margin, the basin became narrower with time. It was not until Miocene time that the Anguille high subsided strongly and ceased to influence deposition. Mainly during late Cocobeach deposition the Lambarene-Ikassa Kongo-Gamba horst zone was formed. After the peneplanation of horsts and grabens alike, the sea invaded the Gabon basin for the first time. The relatively thin, transgressive, coastal-marine sequence between the unconformity and the overlying salt is called the “Gamba formation,” whose sandstones are important oil producers. The main productive trend is related to the structural configuration of the underlying horsts and grabens. The third hinge zone (Atlantic hinge belt) was active during deposition of much of the postsalt sequence. This hinge zone probably extends over the whole length of the basin and controlled the separation of deeper marine (source) environments on the west from shelf (reservoir) environments on the east. The lack of shale members to cap potential reservoir rocks along at least parts of the hinge belt may explain why no important oil accumulations have been found so far. The principal oil fields producing from the postsalt sediments are 60–100 km west of the Atlantic hinge belt, partly on the eastern slope of the Anguille basement high. The environments of deposition of the producing sediments vary from brackish-water estuarine to marine-distal deltaic; the largest oil fields are on the west not as a result of optimum reservoir conditions but because of the timely development of nonpiercing salt-induced domal structures of large areal extent. Steep salt piercements are present farther east in deeper parts of the depositional basin, and oil accumulations related to these piercements tend to be smaller.

@article{brink1974petroleum,
    author = "Brink, A. H.",
    title = "Petroleum Geology of Gabon Basin",
    year = "1974",
    journal = "AAPG Bulletin",
    abstract = "Sediments of the Gabon basin, 16,000–18,000 m thick, range in age from Early Cretaceous, or perhaps latest Jurassic, to recent. A salt layer of late Aptian age separates the almost completely continental facies of the presalt or Cocobeach sequence from the largely marine postsalt sediment. Since its inception, the basin has taken the form of a half graben whose eastern edge consisted of a series of three, or perhaps more, hinge zones which migrated successively farther west and which controlled the distribution of depositional environments and facies changes. The recognition of the hinge zones is of great importance in predicting reservoir trends. In its central part, the basin was bordered on the west by the Anguille basement high, and as the position of this high remained more or less fixed at the (present) continental margin, the basin became narrower with time. It was not until Miocene time that the Anguille high subsided strongly and ceased to influence deposition. Mainly during late Cocobeach deposition the Lambarene-Ikassa Kongo-Gamba horst zone was formed. After the peneplanation of horsts and grabens alike, the sea invaded the Gabon basin for the first time. The relatively thin, transgressive, coastal-marine sequence between the unconformity and the overlying salt is called the “Gamba formation,” whose sandstones are important oil producers. The main productive trend is related to the structural configuration of the underlying horsts and grabens. The third hinge zone (Atlantic hinge belt) was active during deposition of much of the postsalt sequence. This hinge zone probably extends over the whole length of the basin and controlled the separation of deeper marine (source) environments on the west from shelf (reservoir) environments on the east. The lack of shale members to cap potential reservoir rocks along at least parts of the hinge belt may explain why no important oil accumulations have been found so far. The principal oil fields producing from the postsalt sediments are 60–100 km west of the Atlantic hinge belt, partly on the eastern slope of the Anguille basement high. The environments of deposition of the producing sediments vary from brackish-water estuarine to marine-distal deltaic; the largest oil fields are on the west not as a result of optimum reservoir conditions but because of the timely development of nonpiercing salt-induced domal structures of large areal extent. Steep salt piercements are present farther east in deeper parts of the depositional basin, and oil accumulations related to these piercements tend to be smaller.",
    url = "https://doi.org/10.1306/83d913bc-16c7-11d7-8645000102c1865d",
    doi = "10.1306/83d913bc-16c7-11d7-8645000102c1865d",
    number = "2",
    openalex = "W2067055967",
    pages = "216-235",
    volume = "58",
    references = "doi1013060bda61ca16bd11d78645000102c1865d, doi1013065d25b47116c111d78645000102c1865d, openalexw2269081355"
}

@misc{levchenko1975prospects23,
    author = "Levchenko, I. G",
    title = "Prospects of oil and gas in Cambrian deposits of Tungusskaya syneclise and its belt",
    year = "1975",
    howpublished = "Geology of Oil and Gas, v. 1, p. 1-9",
    note = "talkorigins\_source = {true}; raw\_reference = {Levchenko, I. G., 1975, Prospects of oil and gas in Cambrian deposits of Tungusskaya syneclise and its belt: Geology of Oil and Gas, v. 1, p. 1-9.}"
}

@misc{richards1975lead28,
    author = "Richards, J. R",
    title = "Lead isotope data on three north Austrailian galena localities",
    year = "1975",
    howpublished = "Mineralium Deposita, v. 10, p. 287-301",
    note = "talkorigins\_source = {true}; raw\_reference = {Richards, J. R., 1975, Lead isotope data on three north Austrailian galena localities: Mineralium Deposita, v. 10, p. 287-301.}"
}

@book{degens1976stratabound8,
    author = "Degens, E. T. and Ross, D. A",
    title = "Strata-Bound Metalliferous Deposits Found In or Near Active Rifts, in Wolf, K. H., ed., Handbook of Strata-Bound Ore Deposits",
    year = "1976",
    publisher = "Amsterdam, Elsevier, v. 4, p. 165-202; 1976 [429 pp.]",
    note = "talkorigins\_source = {true}; raw\_reference = {Degens, E. T., and Ross, D. A., 1976, Strata-Bound Metalliferous Deposits Found In or Near Active Rifts, in Wolf, K. H., ed., Handbook of Strata-Bound Ore Deposits: Amsterdam, Elsevier, v. 4, p. 165-202; 1976 [429 pp.].}"
}

@misc{nevins1976the26,
    author = "Nevins, S. E",
    title = "The origin of coal",
    year = "1976",
    howpublished = "ICR Impact Series, v. 41, p. i-iv",
    note = "talkorigins\_source = {true}; raw\_reference = {Nevins, S. E., 1976, The origin of coal: ICR Impact Series, v. 41, p. i-iv.}"
}

@misc{balitov1977about3,
    author = "Balitov, N. V",
    title = "About genesis of sulphurous oils and hydrogen sulphide in gasses from Osinskii horizon of Irkutskii cirque",
    year = "1977",
    howpublished = "Geologiya i Geofizica, v. 9, p. 47-55",
    note = "talkorigins\_source = {true}; raw\_reference = {Balitov, N. V., 1977, About genesis of sulphurous oils and hydrogen sulphide in gasses from Osinskii horizon of Irkutskii cirque: Geologiya i Geofizica, v. 9, p. 47-55.}"
}

@misc{dikenshteyn1977oil9,
    author = "Dikenshteyn, G. K. et al",
    title = "Oil and Gas Regions of the USSR",
    year = "1977",
    howpublished = "Moscow, Nedra Publishing House, 328 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Dikenshteyn, G. K. et al., 1977, Oil and Gas Regions of the USSR: Moscow, Nedra Publishing House, 328 p.}"
}

@techreport{gretener1977on17,
    author = "Gretener, P. E",
    title = "On the character of thrust faults with particular reference to the basal tongues",
    year = "1977",
    howpublished = "Bulletin of Canadian Petroleum Geology, v. 25, p. 110-122",
    note = "talkorigins\_source = {true}; raw\_reference = {Gretener, P. E., 1977, On the character of thrust faults with particular reference to the basal tongues: Bulletin of Canadian Petroleum Geology, v. 25, p. 110-122.}"
}

@misc{kontorovich1977main20,
    author = "Kontorovich, A. A. et al",
    title = "Main steps and results of reconnaissance in West Siberian oil and gas province",
    year = "1977",
    howpublished = "Geology of Oil and Gas, v. 11, p. 21- 25",
    note = "talkorigins\_source = {true}; raw\_reference = {Kontorovich, A. A. et al., 1977, Main steps and results of reconnaissance in West Siberian oil and gas province: Geology of Oil and Gas, v. 11, p. 21- 25.}"
}

@misc{kutukov1977prospects21,
    author = "Kutukov, A. V. and Vinnikovskiy, S. A. and Shershnev, K. S",
    title = "Prospects of oil and gas in Vendian deposits of Permskii Prikam'ya",
    year = "1977",
    howpublished = "Geology of Oil and Gas, v. 11, p. 37-43",
    note = "talkorigins\_source = {true}; raw\_reference = {Kutukov, A. V., Vinnikovskiy, S. A., and Shershnev, K. S., 1977, Prospects of oil and gas in Vendian deposits of Permskii Prikam'ya: Geology of Oil and Gas, v. 11, p. 37-43.}"
}

@misc{belenkiy1978ways6,
    author = "Belen'kiy, V. Y. and Kunin, N. Y",
    title = "Ways of improving the effectiveness of seismic reconnaissance when preparing [investigating] structures in Western Yakutia",
    year = "1978",
    howpublished = "Geology of Oil and Gas, v. 5, p. 22-30",
    note = "talkorigins\_source = {true}; raw\_reference = {Belen'kiy, V. Y., and Kunin, N. Y., 1978, Ways of improving the effectiveness of seismic reconnaissance when preparing [investigating] structures in Western Yakutia: Geology of Oil and Gas, v. 5, p. 22-30.}"
}

@misc{kazanskii1978methods19,
    author = "Kazanskii, V. V. et al",
    title = "Methods of influencing low permeability collector seams of East Siberia during teats",
    year = "1978",
    howpublished = "Geology of Oil and Gas, v. 4, p. 60-64",
    note = "talkorigins\_source = {true}; raw\_reference = {Kazanskii, V. V. et al., 1978, Methods of influencing low permeability collector seams of East Siberia during teats: Geology of Oil and Gas, v. 4, p. 60-64.}"
}

@misc{landis1978coal22,
    author = "Landis, E. R. and Averitt, P",
    title = "Coal, in Fairbridge, R. W., and Bourgeois, J., eds., The Encyclopedia of Sedimentology",
    year = "1978",
    howpublished = "Stroudsburg, Pa., Dowden, Hutchinson and Ross, p. 165-167",
    note = "talkorigins\_source = {true}; raw\_reference = {Landis, E. R., and Averitt, P., 1978, Coal, in Fairbridge, R. W., and Bourgeois, J., eds., The Encyclopedia of Sedimentology: Stroudsburg, Pa., Dowden, Hutchinson and Ross, p. 165-167.}"
}

@techreport{shibaoka1978hydrocarbon30,
    author = "Shibaoka, M. and Saxby, J. D. and Taylor, G. H",
    title = "Hydrocarbon generation in Gippsland basin, Australia--Comparison with Cooper Basin, Australia",
    year = "1978",
    howpublished = "Bulletin of the American Association of Petroleum Geologists, v. 62, no. 7, p. 1151-1158",
    note = "talkorigins\_source = {true}; raw\_reference = {Shibaoka, M., Saxby, J. D., and Taylor, G. H., 1978, Hydrocarbon generation in Gippsland basin, Australia--Comparison with Cooper Basin, Australia: Bulletin of the American Association of Petroleum Geologists, v. 62, no. 7, p. 1151-1158.}"
}

@misc{wszolek1978petroleumorigin34,
    author = "Wszolek, P. C. and Burlingame, A. L",
    title = "Petroleum--Origin and Evolution, in Fairbridge, R. W., and Bourgeois, J., eds., The Encyclopedia of Sedimentology",
    year = "1978",
    howpublished = "Stroudsburg, Pa., Dowden, Hutchinson and Ross, p. 565-574",
    note = "talkorigins\_source = {true}; raw\_reference = {Wszolek, P. C., and Burlingame, A. L., 1978, Petroleum--Origin and Evolution, in Fairbridge, R. W., and Bourgeois, J., eds., The Encyclopedia of Sedimentology: Stroudsburg, Pa., Dowden, Hutchinson and Ross, p. 565-574.}"
}

@misc{bakirov1979oil1,
    author = "Bakirov, A. A",
    title = "Oil and Gas Bearing Areas and Regions of the USSR",
    year = "1979",
    howpublished = "Moscow, Nedra Publishing House, 456 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Bakirov, A. A., 1979, Oil and Gas Bearing Areas and Regions of the USSR: Moscow, Nedra Publishing House, 456 p.}"
}

@misc{finlowbates1979cyclicity12,
    author = "Finlow-Bates, T",
    title = "Cyclicity in the lead-zinc-silver bearing sediments at Mount Isa mine, Queensland, Austrailia, and rates of sulfide accumulation",
    year = "1979",
    howpublished = "Economic Geology, v. 74, p. 1408-1419",
    note = "talkorigins\_source = {true}; raw\_reference = {Finlow-Bates, T., 1979, Cyclicity in the lead-zinc-silver bearing sediments at Mount Isa mine, Queensland, Austrailia, and rates of sulfide accumulation: Economic Geology, v. 74, p. 1408-1419.}"
}

@misc{fuks1979genesis13,
    author = "Fuks, A. B. and Fuks, B. A",
    title = "Genesis of the oil belt of the Nepsko- Butoubiskoy anticline deposits",
    year = "1979",
    howpublished = "Geology of Oil and Gas, v. 2, p. 13-18",
    note = "talkorigins\_source = {true}; raw\_reference = {Fuks, A. B., and Fuks, B. A., 1979, Genesis of the oil belt of the Nepsko- Butoubiskoy anticline deposits: Geology of Oil and Gas, v. 2, p. 13-18.}"
}

@misc{hunt1979petroleum18,
    author = "Hunt, J. M",
    title = "Petroleum Geochemistry and Geology",
    year = "1979",
    howpublished = "San Francisco, W.H. Freeman \& Co., 617 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Hunt, J. M., 1979, Petroleum Geochemistry and Geology: San Francisco, W.H. Freeman \& Co., 617 p.}"
}

@misc{goldberg1981razdelnyi16,
    author = "Gol'dberg, I. S. and Lebedev, B. A. and Frolov, B. M",
    title = "Razdel'nyi prognoz razmeshchenila gaza, nefti i bitumov na Sibirskoi platforme [Separate prediction of the distribution of gas, oil and bitumens on the Siberian Platform] [in Russian]",
    year = "1981",
    howpublished = "Geologiya Nefti i Gaza, v. 2, p. 22-26",
    note = "talkorigins\_source = {true}; raw\_reference = {Gol'dberg, I. S., Lebedev, B. A., and Frolov, B. M., 1981, Razdel'nyi prognoz razmeshchenila gaza, nefti i bitumov na Sibirskoi platforme [Separate prediction of the distribution of gas, oil and bitumens on the Siberian Platform] [in Russian]: Geologiya Nefti i Gaza, v. 2, p. 22-26.}"
}

ABSTRACT Tertiary and Quaternary nonmarine, petroleum-bearing sedimentary rocks in the Qaidam basin of remote western China have been extensively deformed by compressive forces. These forces created many folds which are current targets of Chinese exploration programs. Manual techniques of image analysis and interpretation were applied to computer-enhanced Landsat images of the western part of the Qaidam basin in an effort to evaluate the contributions of Landsat imagery in defining the geologic conditions of the basin and to determine its usefulness as an exploration tool in the region. Most success was realized in defining the structural geologic setting of the region. Image-derived interpretations of folds, strike-slip faults, thrust faults, normal or reverse faults, and fractures compared very favorably, in terms of locations and numbers mapped, with Chinese data compiled from years of extensive field mapping. The image studies resulted in the identification of at least one subsurface fold that had not been detected by field mapping. The results of this study have direct exploration significance. Many potential hydrocarbon trapping structures were precisely located and information was obtained that may have significant implications with respect to fluid migration or attempts to locate offset reservoirs and buried folds. In addition, the orientations of major structural trends defined from Landsat imagery correlate well with those predicted for the area based on global tectonic theory. These correlations suggest that similar orientations exist in the eastern half of the basin where folded rocks are mostly obscured by unconsolidated surface sediments and where limited exploration has occurred.

@article{doi10130603b5a7a016d111d78645000102c1865d,
    author = "Bailey, GM and Anderson, Patrick D.",
    title = "Applications of Landsat Imagery to Problems of Petroleum Exploration in Qaidam Basin, China",
    year = "1982",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT Tertiary and Quaternary nonmarine, petroleum-bearing sedimentary rocks in the Qaidam basin of remote western China have been extensively deformed by compressive forces. These forces created many folds which are current targets of Chinese exploration programs. Manual techniques of image analysis and interpretation were applied to computer-enhanced Landsat images of the western part of the Qaidam basin in an effort to evaluate the contributions of Landsat imagery in defining the geologic conditions of the basin and to determine its usefulness as an exploration tool in the region. Most success was realized in defining the structural geologic setting of the region. Image-derived interpretations of folds, strike-slip faults, thrust faults, normal or reverse faults, and fractures compared very favorably, in terms of locations and numbers mapped, with Chinese data compiled from years of extensive field mapping. The image studies resulted in the identification of at least one subsurface fold that had not been detected by field mapping. The results of this study have direct exploration significance. Many potential hydrocarbon trapping structures were precisely located and information was obtained that may have significant implications with respect to fluid migration or attempts to locate offset reservoirs and buried folds. In addition, the orientations of major structural trends defined from Landsat imagery correlate well with those predicted for the area based on global tectonic theory. These correlations suggest that similar orientations exist in the eastern half of the basin where folded rocks are mostly obscured by unconsolidated surface sediments and where limited exploration has occurred.",
    url = "https://doi.org/10.1306/03b5a7a0-16d1-11d7-8645000102c1865d",
    doi = "10.1306/03b5a7a0-16d1-11d7-8645000102c1865d",
    openalex = "W2129403815",
    references = "doi103133ofr80609"
}

@book{doi1010160167527382900481,
    author = "Ulmishek, Gregory F.",
    title = "Geology and petroleum resources of basins in western China",
    year = "1984",
    journal = "International Journal of Cardiology",
    url = "https://doi.org/10.1016/0167-5273(82)90048-1",
    doi = "10.1016/0167-5273(82)90048-1",
    openalex = "W7152732"
}

This report is based chiefly on generalized available published literature; a detailed statement of the geology is not available. The Chaidamu basin is an intermontane depression in the northwestern part of Qinghai Province, Northwest China. The depositional framework of the basin was initially formed on the Paleozoic basement of the Variscan eastern Kunlun Fold System during the late episode of Indosinian orogeny from late Late Triassic to early Early Jurassic. This basin evolved to its present form during the Tertiary Eocene and Oligocene-Miocene Himalayan orogeny.

@article{doi103133ofr84413,
    author = "Lee, Key-Woo",
    title = "Geology of the Chaidamu Basin, Qinghai Province, Northwest China",
    year = "1984",
    journal = "Antarctica A Keystone in a Changing World",
    abstract = "This report is based chiefly on generalized available published literature; a detailed statement of the geology is not available. The Chaidamu basin is an intermontane depression in the northwestern part of Qinghai Province, Northwest China. The depositional framework of the basin was initially formed on the Paleozoic basement of the Variscan eastern Kunlun Fold System during the late episode of Indosinian orogeny from late Late Triassic to early Early Jurassic. This basin evolved to its present form during the Tertiary Eocene and Oligocene-Miocene Himalayan orogeny.",
    url = "https://doi.org/10.3133/ofr84413",
    doi = "10.3133/ofr84413",
    openalex = "W1599921694",
    references = "doi103133ofr80609"
}

ABSTRACT In large lake basins, source rocks containing sapropelic kerogen have a high transformation ratio and a high potential for petroleum, and they offer the material basis for the formation of a large nonmarine oil field. On the basis of geologic and geochemical data and the results of thermal simulation of kerogen, it is confirmed that the maturation sequence of kerogen is type I, type II, and type III.

@article{doi101306ad462b8c16f711d78645000102c1865d,
    author = "Yang, Wanli and Yongkang, Li and Ruiqi, Gao",
    title = "Formation and Evolution of Nonmarine Petroleum in Songliao Basin, China",
    year = "1985",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT In large lake basins, source rocks containing sapropelic kerogen have a high transformation ratio and a high potential for petroleum, and they offer the material basis for the formation of a large nonmarine oil field. On the basis of geologic and geochemical data and the results of thermal simulation of kerogen, it is confirmed that the maturation sequence of kerogen is type I, type II, and type III.",
    url = "https://doi.org/10.1306/ad462b8c-16f7-11d7-8645000102c1865d",
    doi = "10.1306/ad462b8c-16f7-11d7-8645000102c1865d",
    openalex = "W2100019949"
}

@misc{lee1985geology,
    author = "Lee, K.Y.",
    title = "Geology of the petroleum and coal deposits in the Junggar (Zhungaer) Basin, Xinjiang Uygur Zizhiqu, Northwest China",
    year = "1985",
    booktitle = "Open-File Report",
    url = "https://doi.org/10.3133/ofr85230",
    doi = "10.3133/ofr85230",
    openalex = "W1555213978",
    references = "doi10100797836426157406, doi101111j174754571980tb00982x, doi10113000167606198495295aootpt20co2, doi101306bf9ab5c50eb611d78643000102c1865d, doi103133ofr80609, openalexw120412751, openalexw617865741"
}

The Songliao basin of Northeast China covers about 260,000 km2 with a sedimentary rock fill of about 1,560,000 km^. It lies generally within lat 4220' to 4920' N. and long 12000' to 12800' E. This large basin evolved on a Variscan folded cratonic basement marginal to the Da Hinggan Ling* Variscan eugeosyncline foldbelt on the west and northwest, the Xiao Hinggan Ling and the Zhangguangcai Ling Variscan eugeosyncline foldbelt on the northeast and southeast, and the Kangping hills of the Precambrian Nei Mong shield axis of the Sino-Korean platform on the south. It acquired its general form by the continental rifting fragmentation during the Late Triassic Indosinian orogeny. Subsequently, it reached full development through the Late Jurassic to Early Cretaceous extensional graben development, followed by the Middle Cretaceous basin-wide subsidence and syndepositional growth normal faulting during the Yanshanian orogeny (fig. The basin acquired further elements of its present configuration during the Neogene Himalayan orogeny.

@article{doi103133ofr86502,
    author = "Lee, K.Y.",
    title = "Petroleum geology of the Songliao basin, Northeast China",
    year = "1986",
    journal = "Antarctica A Keystone in a Changing World",
    abstract = "The Songliao basin of Northeast China covers about 260,000 km2 with a sedimentary rock fill of about 1,560,000 km^. It lies generally within lat 4220' to 4920' N. and long 12000' to 12800' E. This large basin evolved on a Variscan folded cratonic basement marginal to the Da Hinggan Ling* Variscan eugeosyncline foldbelt on the west and northwest, the Xiao Hinggan Ling and the Zhangguangcai Ling Variscan eugeosyncline foldbelt on the northeast and southeast, and the Kangping hills of the Precambrian Nei Mong shield axis of the Sino-Korean platform on the south. It acquired its general form by the continental rifting fragmentation during the Late Triassic Indosinian orogeny. Subsequently, it reached full development through the Late Jurassic to Early Cretaceous extensional graben development, followed by the Middle Cretaceous basin-wide subsidence and syndepositional growth normal faulting during the Yanshanian orogeny (fig. The basin acquired further elements of its present configuration during the Neogene Himalayan orogeny.",
    url = "https://doi.org/10.3133/ofr86502",
    doi = "10.3133/ofr86502",
    openalex = "W599755651",
    references = "doi103133ofr80609"
}

@misc{lee1986geology,
    author = "Lee, K.Y.",
    title = "Geology of the coal and petroleum deposits in the Ordos basin, China",
    year = "1986",
    booktitle = "Open-File Report",
    url = "https://doi.org/10.3133/ofr86278",
    doi = "10.3133/ofr86278",
    openalex = "W908642540"
}

@misc{crossref1989geology,
    title = "Geology of petroleum and coal deposits in the North China Basin, Eastern China",
    year = "1989",
    url = "https://doi.org/10.3133/b1871",
    doi = "10.3133/b1871",
    openalex = "W1562598360",
    references = "doi1010079783642878138, doi1010079783642964466, doi101017s0016756800030740, doi101306ad4616a616f711d78645000102c1865d, doi101306ad4616ab16f711d78645000102c1865d, doi101306ad4616b016f711d78645000102c1865d, doi101306m32427c19, doi101306m32427c20, doi103133ofr80609, openalexw1585657202, openalexw2508127278"
}

Abstract This chapter examines the petroleum potential of the sedimentary basins along the continental margins of the North American Plate in the Arctic Ocean region, including those beneath the continent itself and those beneath its fringing continental terraces. Basins within the Canadian Arctic Islands of North America and in the Baffin Bay regions are considered in other volumes of this series. The large petroleum potential of some of the sedimentary basins of the Arctic Ocean margin of the North American Plate, particularly those on the continental shelf, is already well established. The petroleum resource potential of the abyssal plains of the Arctic Ocean is poorly understood but is thought to represent only a minor portion of the total potential of the region. The basins in the periphery of the Arctic Ocean Basin are mainly continental terrace wedges on foundered passive continental margins and successor basins on extended continental shelves. The Kronprins Christian Basin on the East Greenland Shelf is separated from European basins by the Mid-Atlantic Ridge north of Iceland (Fig. 1). The rest of the basins along the edge of the North American continent area, from east to west, are the Wandel Sea Basin in Greenland, the Lincoln Sea Basin, the various sub-basins of the Canadian Arctic Coastal Plain and Shelf, the Mackenzie Delta–Beaufort Sea Basin in Canada, and the Kaktovik Basin, the Demarcation Subbasin, the Dinkum Graben, and the Nuwuk Basin off Alaska. West of Alaska and north of Siberia the broad continental shelf contains upper Paleozoic-Mesozoic successor

@incollection{doi101130dnaggnal503,
    author = "Haimila, N. E. and Kirschner, C. E. and Nassichuk, W W and Ulmichek, G. and Procter, R M",
    title = "Sedimentary basins and petroleum resource potential of the Arctic Ocean region",
    year = "1990",
    booktitle = "Geological Society of America eBooks",
    abstract = "Abstract This chapter examines the petroleum potential of the sedimentary basins along the continental margins of the North American Plate in the Arctic Ocean region, including those beneath the continent itself and those beneath its fringing continental terraces. Basins within the Canadian Arctic Islands of North America and in the Baffin Bay regions are considered in other volumes of this series. The large petroleum potential of some of the sedimentary basins of the Arctic Ocean margin of the North American Plate, particularly those on the continental shelf, is already well established. The petroleum resource potential of the abyssal plains of the Arctic Ocean is poorly understood but is thought to represent only a minor portion of the total potential of the region. The basins in the periphery of the Arctic Ocean Basin are mainly continental terrace wedges on foundered passive continental margins and successor basins on extended continental shelves. The Kronprins Christian Basin on the East Greenland Shelf is separated from European basins by the Mid-Atlantic Ridge north of Iceland (Fig. 1). The rest of the basins along the edge of the North American continent area, from east to west, are the Wandel Sea Basin in Greenland, the Lincoln Sea Basin, the various sub-basins of the Canadian Arctic Coastal Plain and Shelf, the Mackenzie Delta–Beaufort Sea Basin in Canada, and the Kaktovik Basin, the Demarcation Subbasin, the Dinkum Graben, and the Nuwuk Basin off Alaska. West of Alaska and north of Siberia the broad continental shelf contains upper Paleozoic-Mesozoic successor",
    url = "https://doi.org/10.1130/dnag-gna-l.503",
    doi = "10.1130/dnag-gna-l.503",
    openalex = "W2489644352"
}

ABSTRACT The sedimentary basins of Xinjiang Uygur Autonomous Region, China, are moderately to poorly explored for petroleum. Volumetric adequacy of petroleum source rocks is a critical exploration risk in these basins, particularly because source rock data are limited. This study provides new source rock data and speculatively assesses the source rock potential of Xinjiang basins. The Junggar (Zhungaer) basin, the best explored of the Xinjiang basins and containing a giant oil field, is underlain in many areas by an Upper Permian lacustrine oil-shale sequence remarkable for its organic richness and oil source quality. Depending on its position in the basin, the Permian section ranges from immature to overmature and is inferred to be the principal source of oil in the basin. Upper Triassic–Middle Jurassic coal measures, including lacustrine rocks, constitute a secondary source rock sequence in the basin. The smaller, intermontane Turpan (Tulufan) basin contains a very similar Upper Triassic–Middle Jurassic sequence, which, where sufficiently buried, probably comprises the only significant oil source sequence in the basin. The vast Tarim (Talimu) basin offers the greatest variety of potential source rocks of all Xinjiang basins but remains the least well documented. From limited but geologically planned and focused sampling, Cambrian, Carboniferous, and Permian strata are not considered major oil contributors in the dominantly shallow marine Paleozoic section of the northern Tarim basin. Only Ordovician black shales appear to have significant potential. The Upper Triassic–Middle Jurassic sequence of the northern Tarim basin is similar to that of the Junggar and Turpan basins—a section rich in coal and lacustrine shale that constitutes another potentially significant oil source. Due to the size, stratigraphic packaging, and structural relief of the northern Tarim basin, Paleozoic and Mesozoic potential oil source beds range from immature to overmature.

@article{doi1013060c9b233f171011d78645000102c1865d,
    author = "Graham, Stephen and Brassell, S. and Carroll, A. R. and Xiao, X. and Demaison, G. and Mcknight, C. L. and Liang, Y. and Chu, J. and Hendrix, M. S.",
    title = "Characteristics of Selected Petroleum Source Rocks, Xianjiang Uygur Autonomous Region, Northwest China",
    year = "1990",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The sedimentary basins of Xinjiang Uygur Autonomous Region, China, are moderately to poorly explored for petroleum. Volumetric adequacy of petroleum source rocks is a critical exploration risk in these basins, particularly because source rock data are limited. This study provides new source rock data and speculatively assesses the source rock potential of Xinjiang basins. The Junggar (Zhungaer) basin, the best explored of the Xinjiang basins and containing a giant oil field, is underlain in many areas by an Upper Permian lacustrine oil-shale sequence remarkable for its organic richness and oil source quality. Depending on its position in the basin, the Permian section ranges from immature to overmature and is inferred to be the principal source of oil in the basin. Upper Triassic–Middle Jurassic coal measures, including lacustrine rocks, constitute a secondary source rock sequence in the basin. The smaller, intermontane Turpan (Tulufan) basin contains a very similar Upper Triassic–Middle Jurassic sequence, which, where sufficiently buried, probably comprises the only significant oil source sequence in the basin. The vast Tarim (Talimu) basin offers the greatest variety of potential source rocks of all Xinjiang basins but remains the least well documented. From limited but geologically planned and focused sampling, Cambrian, Carboniferous, and Permian strata are not considered major oil contributors in the dominantly shallow marine Paleozoic section of the northern Tarim basin. Only Ordovician black shales appear to have significant potential. The Upper Triassic–Middle Jurassic sequence of the northern Tarim basin is similar to that of the Junggar and Turpan basins—a section rich in coal and lacustrine shale that constitutes another potentially significant oil source. Due to the size, stratigraphic packaging, and structural relief of the northern Tarim basin, Paleozoic and Mesozoic potential oil source beds range from immature to overmature.",
    url = "https://doi.org/10.1306/0c9b233f-1710-11d7-8645000102c1865d",
    doi = "10.1306/0c9b233f-1710-11d7-8645000102c1865d",
    openalex = "W1841833721",
    references = "lee1985geology"
}

Interior Cratonic Basins, a product for the World Petroleum Basins series of the American Association of Petroleum Geologists (AAPG), was approved in 1984 and initiated in early 1985.1 Contributors undertook to provide useful geologic information on the regional setting, stratigraphy, structure, tectonics and basin evolution, and oil and gas systems of seven cratonic basins.A detailed overview of the Illinois basin, selected by the AAPG ad hoc committee as a representative type (see Foreword), is followed by less detailed reviews of six other selected interior cratonic basins: the Williston, Michigan, Baltic, Paris, Parana, and Carpentaria basins. The goal is to develop a better understanding of the basin-forming, basin-filling, and basin-modifying processes that control hydrocarbon plays and resultant oil and gas fields in this class of basins. The idea is to describe and document the variations, opportunities, and exploration problems that can be expected.We selected seven basins, productive and nonproductive, from four continents (Figure 1): five basins formed on Precambrian crust (Illinois, Michigan, Williston, Baltic, and Parana basins); one formed on accreted Paleozoic crust (Paris basin); and one formed on Paleozoic and Proterozoic volcanics and sediments and Proterozoic metamorphic rocks (Carpentaria basin). Some are rift related; some are not.Information from other interior cratonic basins balances the coverage. At the conclusion of the introduction, a selection of paleogeographic maps is presented for later reference throughout the volume on the time, place, and setting of the seven basins. We conclude the volume with a section on interiorcratonic basins and their place in the scheme of global tectonics, and an epilogue highlights what we know and what we still do not know about these basins.Craton and cratonic (Sloss and Speed, 1974) have been difficult to define. The word craton was originally used by Stille (1936, 1941) in the sense of a strong unyielding buckler or shield (Sloss, 1998a). Presumably, the immobile shield was circumscribed by peripheral miogeosynclines. Kay (1947, 1951) recognized bounding flexures, the "Wasatch line" and "Adirondack line," which marked the western and eastern inboard limits of the North American miogeosynclines and defined the broad stable region between the flexures as the craton. Miogeosynclines faded out of vogue when it was recognized that the wedges or prisms of sediments associated with them are a consequence of deposition on subsident continental margins (Sloss, 1988a). This recognitoin left in limbo the definition of cratons and what IS or is not cratonic or extracratonic.

@incollection{doi101306m51530c32,
    author = "Ulmishek, Gregory F.",
    title = "Geologic Evolution and Petroleum Resources of the Baltic Basin",
    year = "1990",
    booktitle = "American Association of Petroleum Geologists eBooks",
    abstract = {Interior Cratonic Basins, a product for the World Petroleum Basins series of the American Association of Petroleum Geologists (AAPG), was approved in 1984 and initiated in early 1985.1 Contributors undertook to provide useful geologic information on the regional setting, stratigraphy, structure, tectonics and basin evolution, and oil and gas systems of seven cratonic basins.A detailed overview of the Illinois basin, selected by the AAPG ad hoc committee as a representative type (see Foreword), is followed by less detailed reviews of six other selected interior cratonic basins: the Williston, Michigan, Baltic, Paris, Parana, and Carpentaria basins. The goal is to develop a better understanding of the basin-forming, basin-filling, and basin-modifying processes that control hydrocarbon plays and resultant oil and gas fields in this class of basins. The idea is to describe and document the variations, opportunities, and exploration problems that can be expected.We selected seven basins, productive and nonproductive, from four continents (Figure 1): five basins formed on Precambrian crust (Illinois, Michigan, Williston, Baltic, and Parana basins); one formed on accreted Paleozoic crust (Paris basin); and one formed on Paleozoic and Proterozoic volcanics and sediments and Proterozoic metamorphic rocks (Carpentaria basin). Some are rift related; some are not.Information from other interior cratonic basins balances the coverage. At the conclusion of the introduction, a selection of paleogeographic maps is presented for later reference throughout the volume on the time, place, and setting of the seven basins. We conclude the volume with a section on interiorcratonic basins and their place in the scheme of global tectonics, and an epilogue highlights what we know and what we still do not know about these basins.Craton and cratonic (Sloss and Speed, 1974) have been difficult to define. The word craton was originally used by Stille (1936, 1941) in the sense of a strong unyielding buckler or shield (Sloss, 1998a). Presumably, the immobile shield was circumscribed by peripheral miogeosynclines. Kay (1947, 1951) recognized bounding flexures, the "Wasatch line" and "Adirondack line," which marked the western and eastern inboard limits of the North American miogeosynclines and defined the broad stable region between the flexures as the craton. Miogeosynclines faded out of vogue when it was recognized that the wedges or prisms of sediments associated with them are a consequence of deposition on subsident continental margins (Sloss, 1988a). This recognitoin left in limbo the definition of cratons and what IS or is not cratonic or extracratonic.},
    url = "https://doi.org/10.1306/m51530c32",
    doi = "10.1306/m51530c32",
    openalex = "W3127101473"
}

@book{sawkins1990metal29,
    author = "Sawkins, F. J",
    title = "Metal Deposits in Relation to Plate Tectonics [2nd ed.], 17 of Minerals and Rocks",
    year = "1990",
    publisher = "New York, Springer-Verlag, 461 p",
    note = "talkorigins\_source = {true}; raw\_reference = {Sawkins, F. J., 1990, Metal Deposits in Relation to Plate Tectonics [2nd ed.], 17 of Minerals and Rocks: New York, Springer-Verlag, 461 p.}"
}

The West Siberian oil-gas province comprises the largest flat land area in the world (3.5 million km2, or 1.3 million mi2). Over most of the region, elevations rarely exceed 100 m (330 ft). The basin is bounded on the west by the Uralian and Novaya Zemlya uplifts, on the east by the Siberian craton and Taymyr uplift, on the south by the Kazakh and Altay-Sayan uplifts, and on the north by the North Siberian sill. Structurally, the basm is a broad, relatively gentle downwarp filled with 3-10 km (10,000-33,000 ft) of post-Paleozoic marine, nearshore marine, and continental clastic sedimentary rocks. The basement is composed of Precambrian and Paleozoic fold systems with large areas of partly metamorphosed Paleozoic carbonate and clastic rocks and numerous areas of Paleozoic or older granitic and mafic igneous bodies. In the central part of the basin, the basement is cut by an extensive, northerly oriented Triassic rift system.Paleostructural and stratigraphic trapping are important aspects of West Siberian petroleum geology. Oil source rocks are mainly marine Jurassic and Lower Cretaceous bituminous shales. Gas source rocks are mainly Upper Cretaceous humic and coaly shales. Petroleum production in the basin occurs in four major areas: (1) Middle Ob: primarily oil from Lower Cretaceous deltaic-marine clastic reservoirs on broad regional uplifts; the Samotlor and other supergiant fields are located in this area; (2) Near-Ural: primarily oil in the south and gas in the north from Upper Jurassic and Lower Cretaceous clastic reservoirs in paleo- structural-stratigraphic traps; (3) Southern Basin: oil and oil-gas from Jurassic clastic reservoirs, mainly on anticlines or arches inherited from basement highs; and (4) Northern Basin: gas primarily from Upper Cretaceous (Cenomanian) and gas-condensate from Lower Cretaceous and Jurassic clastic reservoirs on large anticlinal traps sealed by Cretaceous shales or permafrost. Urengoy, the world's largest gas field, and several other supeigiant gas fields are located in this latter area.Large parts of the basin are relatively unexplored, particularly the northern offshore segments. The interrelated paleostructural and depo- sitional character of this enormous basin provides excellent prospects for stratigraphic trap accumulations. An estimated 70 billion bbl of oil and 1000 tcf (trillion cubic feet) of gas have been found in the basin. U.S. Geological Survey estimates (1987) of undiscovered, conventionally recoverable petroleum resources are 30 billion bbl of oil and 350 tcf of gas.

@book{doi101306st32544,
    author = "Peterson, James A. and Clarke, James W.",
    title = "Geology and Hydrocarbon Habitat of the West Siberian Basin",
    year = "1991",
    booktitle = "American Association of Petroleum Geologists eBooks",
    abstract = "The West Siberian oil-gas province comprises the largest flat land area in the world (3.5 million km2, or 1.3 million mi2). Over most of the region, elevations rarely exceed 100 m (330 ft). The basin is bounded on the west by the Uralian and Novaya Zemlya uplifts, on the east by the Siberian craton and Taymyr uplift, on the south by the Kazakh and Altay-Sayan uplifts, and on the north by the North Siberian sill. Structurally, the basm is a broad, relatively gentle downwarp filled with 3-10 km (10,000-33,000 ft) of post-Paleozoic marine, nearshore marine, and continental clastic sedimentary rocks. The basement is composed of Precambrian and Paleozoic fold systems with large areas of partly metamorphosed Paleozoic carbonate and clastic rocks and numerous areas of Paleozoic or older granitic and mafic igneous bodies. In the central part of the basin, the basement is cut by an extensive, northerly oriented Triassic rift system.Paleostructural and stratigraphic trapping are important aspects of West Siberian petroleum geology. Oil source rocks are mainly marine Jurassic and Lower Cretaceous bituminous shales. Gas source rocks are mainly Upper Cretaceous humic and coaly shales. Petroleum production in the basin occurs in four major areas: (1) Middle Ob: primarily oil from Lower Cretaceous deltaic-marine clastic reservoirs on broad regional uplifts; the Samotlor and other supergiant fields are located in this area; (2) Near-Ural: primarily oil in the south and gas in the north from Upper Jurassic and Lower Cretaceous clastic reservoirs in paleo- structural-stratigraphic traps; (3) Southern Basin: oil and oil-gas from Jurassic clastic reservoirs, mainly on anticlines or arches inherited from basement highs; and (4) Northern Basin: gas primarily from Upper Cretaceous (Cenomanian) and gas-condensate from Lower Cretaceous and Jurassic clastic reservoirs on large anticlinal traps sealed by Cretaceous shales or permafrost. Urengoy, the world's largest gas field, and several other supeigiant gas fields are located in this latter area.Large parts of the basin are relatively unexplored, particularly the northern offshore segments. The interrelated paleostructural and depo- sitional character of this enormous basin provides excellent prospects for stratigraphic trap accumulations. An estimated 70 billion bbl of oil and 1000 tcf (trillion cubic feet) of gas have been found in the basin. U.S. Geological Survey estimates (1987) of undiscovered, conventionally recoverable petroleum resources are 30 billion bbl of oil and 350 tcf of gas.",
    url = "https://doi.org/10.1306/st32544",
    doi = "10.1306/st32544",
    openalex = "W2311921368"
}

Not only are rift basins the foundation for much of the geologic history of the earth, but they also are very attractive areas for hydrocarbon accumulations. Klemme stated that this geographic area has provided significant hydrocarbon reserves: "By area, these basins represent slightly over 5% of the world's basins (50% productive). However, high recovery has resulted, as they contain 10% of the world's present reserves (12% of the oil reserves and 4% of the gas reserves)." The rift basins discussed in this volume are only a few of the productive and, more importantly, potentially productive rift basins in the world. The term "rift" was coined by Gregory (1896) for the graben that now bears his name in the Kenyan portion of the East African rift system. The study of geology of rift basins began in the Rhine graben. The discovery of hydrocarbons in rift basins about the turn of the century provided new motivation for understanding these basins. This publication was initiated by the AAPG Publications Committee in 1985 and contributors were invited to write. AAPG designed their "World Petroleum Basins" series and sought to publish the definitive volume on each of several basin types. In this volume, "Interior Rift Basins," a detailed, 3-paper overview was written about the Suez Rift basin as representative of interior rift basins. The key papers were followed by less detailed reviews of three other selected interior basins: Pripyat and Dnieper-Donets Basins; Reconcavo Basin, Brazil; Albuquerque Basin Segment of the Rio Grande Rift.

@incollection{doi101306m59582c5,
    author = "Ulmishek, Gregory F. and Bogino, V. A. and Keller, Martin and Poznyakevich, Z. L.",
    title = "Structure, Stratigraphy, and Petroleum Geology of the Pripyat and Dnieper-Donets Basins, Byelarus and Ukraine",
    year = "1994",
    booktitle = "American Association of Petroleum Geologists eBooks",
    abstract = {Not only are rift basins the foundation for much of the geologic history of the earth, but they also are very attractive areas for hydrocarbon accumulations. Klemme stated that this geographic area has provided significant hydrocarbon reserves: "By area, these basins represent slightly over 5\% of the world's basins (50\% productive). However, high recovery has resulted, as they contain 10\% of the world's present reserves (12\% of the oil reserves and 4\% of the gas reserves)." The rift basins discussed in this volume are only a few of the productive and, more importantly, potentially productive rift basins in the world. The term "rift" was coined by Gregory (1896) for the graben that now bears his name in the Kenyan portion of the East African rift system. The study of geology of rift basins began in the Rhine graben. The discovery of hydrocarbons in rift basins about the turn of the century provided new motivation for understanding these basins. This publication was initiated by the AAPG Publications Committee in 1985 and contributors were invited to write. AAPG designed their "World Petroleum Basins" series and sought to publish the definitive volume on each of several basin types. In this volume, "Interior Rift Basins," a detailed, 3-paper overview was written about the Suez Rift basin as representative of interior rift basins. The key papers were followed by less detailed reviews of three other selected interior basins: Pripyat and Dnieper-Donets Basins; Reconcavo Basin, Brazil; Albuquerque Basin Segment of the Rio Grande Rift.},
    url = "https://doi.org/10.1306/m59582c5",
    doi = "10.1306/m59582c5",
    openalex = "W3108955205"
}

@article{doi103133ofr94426,
    author = "Ryder, Robert T. and Rice, Dudley D. and Zhao-cai, Sun and Yigang, Zhang and Yun-yu, Qiu and Zhengwu, Guo",
    title = "Petroleum geology of the Sichuan basin, China; report on U.S. Geological Survey and Chinese Ministry of Geology and Mineral Resources field investigations and meetings, October 1991",
    year = "1994",
    journal = "Antarctica A Keystone in a Changing World",
    url = "https://doi.org/10.3133/ofr94426",
    doi = "10.3133/ofr94426",
    openalex = "W1549098449",
    references = "doi103133ofr934"
}

ABSTRACT Lower and Middle Jurassic coal-bearing strata occur widely throughout central Asia and are well developed in northwestern China, where their thicknesses in the southern Junggar, northern Tarim, and Turpan basins exceed 2500, 2300, and 1500 m, respectively. Examination of these strata along 13 transects across basin margin outcrop belts indicates that they are entirely nonmarine meandering fluvial deposits with local development of braided fluvial and lacustrine deltaic facies. Chinese subsurface data suggest that regional Jurassic lacustrine facies are present down depositional dip, consistent with predictions from global circulation modeling of Early and Middle Jurassic monsoonal precipitation. Laboratory analyses of coals and organic-rich shales show a dominance of terrestrial, higher plant components. Visual kerogen analysis indicates that vitrinite, inertinite, and exinite are the dominant macerals, and elemental analysis characterizes most kerogens as type III. Rock-Eval analyses yield moderate hydrogen index values (50-300) and very low oxygen index values (<20). Jurassic source rock extracts are characterized by odd-over-even normal alkane distributions, high pristane/phytane and high hopane/sterane ratios, dominance of C29 sterane homologs, local abundance of diterpenoid compounds, and low abundance of tricyclic terpanes. Geochemical correlation with four petroleums from the Junggar, Tarim, and Turpan basins strongly suggests that the Jurassic coaly deposits and their lacustrine equivalents downdip are petroleum source rocks. Sterane and hopane distributions of petroleums and extracts of their putative Jurassic source rock are similar and can be easily distinguished from published distributions of these compounds in other source rock layers. Additional correlation parameters include high pristane/phytane; low abundance or lack of tricyclic terpanes, but similar distributions where present; and lack of gammacerane (with one exception) and carotanes, compounds that characterize Permian and Ordovician source rocks and their respective petroleums. Pyrolysis-gas chromatography of selected Jurassic samples suggests that they possess potential for liquid hydrocarbon generation. Expulsion of C15+ hydrocarbons from Jurassic source rocks appears likely, despite the traditional view that bituminous coals are incapable of expelling long-chain hydrocarbons.

@article{doi1013068d2b2187171e11d78645000102c1865d,
    author = "Hendrix, Marc S. and Brassell, Simon C. and Carroll, Alan R. and Graham, Stephan A.",
    title = "Sedimentology, Organic Geochemistry, and Petroleum Potential of Jurassic Coal Measures: Tarim, Junggar, and Turpan Basins, Northwest China",
    year = "1995",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT Lower and Middle Jurassic coal-bearing strata occur widely throughout central Asia and are well developed in northwestern China, where their thicknesses in the southern Junggar, northern Tarim, and Turpan basins exceed 2500, 2300, and 1500 m, respectively. Examination of these strata along 13 transects across basin margin outcrop belts indicates that they are entirely nonmarine meandering fluvial deposits with local development of braided fluvial and lacustrine deltaic facies. Chinese subsurface data suggest that regional Jurassic lacustrine facies are present down depositional dip, consistent with predictions from global circulation modeling of Early and Middle Jurassic monsoonal precipitation. Laboratory analyses of coals and organic-rich shales show a dominance of terrestrial, higher plant components. Visual kerogen analysis indicates that vitrinite, inertinite, and exinite are the dominant macerals, and elemental analysis characterizes most kerogens as type III. Rock-Eval analyses yield moderate hydrogen index values (50-300) and very low oxygen index values (\<20). Jurassic source rock extracts are characterized by odd-over-even normal alkane distributions, high pristane/phytane and high hopane/sterane ratios, dominance of C29 sterane homologs, local abundance of diterpenoid compounds, and low abundance of tricyclic terpanes. Geochemical correlation with four petroleums from the Junggar, Tarim, and Turpan basins strongly suggests that the Jurassic coaly deposits and their lacustrine equivalents downdip are petroleum source rocks. Sterane and hopane distributions of petroleums and extracts of their putative Jurassic source rock are similar and can be easily distinguished from published distributions of these compounds in other source rock layers. Additional correlation parameters include high pristane/phytane; low abundance or lack of tricyclic terpanes, but similar distributions where present; and lack of gammacerane (with one exception) and carotanes, compounds that characterize Permian and Ordovician source rocks and their respective petroleums. Pyrolysis-gas chromatography of selected Jurassic samples suggests that they possess potential for liquid hydrocarbon generation. Expulsion of C15+ hydrocarbons from Jurassic source rocks appears likely, despite the traditional view that bituminous coals are incapable of expelling long-chain hydrocarbons.",
    url = "https://doi.org/10.1306/8d2b2187-171e-11d7-8645000102c1865d",
    doi = "10.1306/8d2b2187-171e-11d7-8645000102c1865d",
    openalex = "W2121406728",
    references = "doi101306a25fe3dd171b11d78645000102c1865d, lee1985geology"
}

@article{crossref1996the,
    title = "The wolf effect in spherically symmetric systems",
    year = "1996",
    journal = "Journal of Modern Optics",
    url = "https://doi.org/10.1080/09500349608232755",
    doi = "10.1080/09500349608232755",
    number = "2",
    pages = "433-433",
    volume = "43"
}

@article{postma1997the,
    author = "Postma, George",
    title = "The geology of fluvial deposits, sedimentary facies, basin analysis and petroleum geology",
    year = "1997",
    journal = "Sedimentary Geology",
    url = "https://doi.org/10.1016/s0037-0738(96)00081-4",
    doi = "10.1016/s0037-0738(96)00081-4",
    number = "1-2",
    openalex = "W2936162658",
    pages = "149-150",
    volume = "110"
}

Abstract Based on numerous empirical observations of lacustrine basin strata, we propose a three-fold classification of lacustrine facies associations that accounts for the most important features of lacustrine petroleum source rocks and provides a predictive framework for exploration in nonmarine basins where lacustrine facies are incompletely delineated. 1. The fluvial-lacustrine facies association is characterized by freshwater lacustrine mudstones interbedded with fluvial-deltaic deposits, commonly including coal. Shoreline progradation dominates basin fill, resulting in the stacking of indistinctly expressed cycles up to 10 m thick. In map view, the deposits may be regionally widespread but laterally discontinuous and contain strong facies contrasts. Transported terrestrial organic matter contributes to mixed type I-III kerogens that generate waxy oil (type I kerogen is hydrogen rich and oil prone; type III kerogen is hydrogen poor and mainly gas prone). The Luman Tongue of the Green River Formation (Wyoming) and the Honyanchi Formation (Junggar basin, China) provide examples of this facies association, which is also present in the Songliao basin of northeastern China, the Central Sumatra basin, and the Cretaceous Doba/Doseo basins in west-central Africa. 2. The fluctuating profundal facies association represents a combination of progradational and aggradational basin fill and includes some of the world's richest source rocks. Deposits are regionally extensive in map view, having relatively homogenous source facies containing oil-prone, type I kerogen. Examples include the Laney Member of the Green River Formation (Wyoming), the Lucaogou Formation (Junggar basin, China), the Bucomazi Formation (offshore west Africa), and the Lagoa Feia Formation (Campos basin, Brazil). 3. The evaporative facies association represents dominantly aggradational fill related to desiccation cycles in saline to hypersaline lakes and may include evaporite and eolianite deposits. Sublittoral organic-rich mudstone facies are relatively thin but may be quite rich and widespread. The highest organic enrichment coincides with the deepest lake stages. Low input of land plant organic matter results in minimal lateral contrasts in organic content. In some cases a distinctive type I-S (sulfur-rich) kerogen may generate oil at thermal maturities as low as 0.45% vitrinite reflectance equivalent. Examples include the Wilkins Peak Member of the Green River Formation (Wyoming), the Jingjingzigou Formation (Junggar basin, China), the Jianghan and Qaidam basins (China), and the Blanca Lila Formation (Argentina).

@article{doi1013068626ca5f173b11d78645000102c1865d,
    author = "Carroll, Alan R. and Bohacs, Kevin M.",
    title = "Lake-Type Controls on Petroleum Source Rock Potential in Nonmarine Basins",
    year = "2001",
    journal = "AAPG Bulletin",
    abstract = "Abstract Based on numerous empirical observations of lacustrine basin strata, we propose a three-fold classification of lacustrine facies associations that accounts for the most important features of lacustrine petroleum source rocks and provides a predictive framework for exploration in nonmarine basins where lacustrine facies are incompletely delineated. 1. The fluvial-lacustrine facies association is characterized by freshwater lacustrine mudstones interbedded with fluvial-deltaic deposits, commonly including coal. Shoreline progradation dominates basin fill, resulting in the stacking of indistinctly expressed cycles up to 10 m thick. In map view, the deposits may be regionally widespread but laterally discontinuous and contain strong facies contrasts. Transported terrestrial organic matter contributes to mixed type I-III kerogens that generate waxy oil (type I kerogen is hydrogen rich and oil prone; type III kerogen is hydrogen poor and mainly gas prone). The Luman Tongue of the Green River Formation (Wyoming) and the Honyanchi Formation (Junggar basin, China) provide examples of this facies association, which is also present in the Songliao basin of northeastern China, the Central Sumatra basin, and the Cretaceous Doba/Doseo basins in west-central Africa. 2. The fluctuating profundal facies association represents a combination of progradational and aggradational basin fill and includes some of the world's richest source rocks. Deposits are regionally extensive in map view, having relatively homogenous source facies containing oil-prone, type I kerogen. Examples include the Laney Member of the Green River Formation (Wyoming), the Lucaogou Formation (Junggar basin, China), the Bucomazi Formation (offshore west Africa), and the Lagoa Feia Formation (Campos basin, Brazil). 3. The evaporative facies association represents dominantly aggradational fill related to desiccation cycles in saline to hypersaline lakes and may include evaporite and eolianite deposits. Sublittoral organic-rich mudstone facies are relatively thin but may be quite rich and widespread. The highest organic enrichment coincides with the deepest lake stages. Low input of land plant organic matter results in minimal lateral contrasts in organic content. In some cases a distinctive type I-S (sulfur-rich) kerogen may generate oil at thermal maturities as low as 0.45\% vitrinite reflectance equivalent. Examples include the Wilkins Peak Member of the Green River Formation (Wyoming), the Jingjingzigou Formation (Junggar basin, China), the Jianghan and Qaidam basins (China), and the Blanca Lila Formation (Argentina).",
    url = "https://doi.org/10.1306/8626ca5f-173b-11d7-8645000102c1865d",
    doi = "10.1306/8626ca5f-173b-11d7-8645000102c1865d",
    openalex = "W2135030700",
    references = "doi1010160016703795000739, doi1013060c9b238f171011d78645000102c1865d, doi101306bdff8b0a171811d78645000102c1865d"
}

Abstract Coalbed gas has been produced commercially from the northern Appalachian basin since the 1930s and from the San Juan basin since the early 1950s. However, the magnitude and economic significance of coalbed gas resources were realized only in the 1970s and early 1980s when the U.S. Bureau of Mines, U.S. Department of Energy, the Gas Research Institute, and oil and gas operators made a concerted effort to demonstrate commercial production of coalbed gas from vertical wells. Exploration and development expanded in the late 1980s and early 1990s, due partly to an unconventional fuels tax credit. By 2000, coalbed gas accounted for 8.8% of the reserves (15.7 tcf [0.44 Tm3]) and 9.2% of the annual production (1.38 tcf [40 Gm3]) of dry gas in the United States. From 1989 through 2000, cumulative United States coalbed gas production was 9.63 tcf (272 Gm3). Today, coalbed gas development has spread to about a dozen basins in the United States, and exploration is progressing worldwide. Coal beds are self-sourcing reservoirs that can contain thermogenic, migrated thermogenic, biogenic, or mixed gas. Coalbed gas is stored primarily within micropores of the coal matrix in an adsorbed state and secondarily in micropores and fractures as free gas or solution gas in water. The key parameters that control gas resources and producibility are thermal maturity, maceral composition, gas content, coal thickness, fracture density, in-situ stress, permeability, burial history, and hydrologic setting. These parameters vary greatly in the producing fields of the United States and the world. In 2000, the San Juan basin accounted for more than 80% of the United States coalbed gas production. This basin contains a giant coalbed gas play, the Fruitland fairway, which has produced more than 7 tcf (0.2 Tm3) of gas. The Fruitland coalbed gas system and its key elements contrast with the Fort Union coalbed gas play in the Powder River basin. The Fort Union coalbed play is one of the fastest developing gas plays in the United States. Its production escalated from 14 bcf (0.4 Gm3) in 1997 to 147.3 bcf (4.1 Gm3) in 2000, when it accounted for 10.7% of the United States coalbed gas production. By 2001, annual production was 244.7 bcf (6.9 Gm3). Differences between the Fruitland and Fort Union petroleum systems make them ideal for elucidating the key elements of contrasting coalbed gas petroleum systems.

@article{doi10130661eeddaa173e11d78645000102c1865d,
    author = "Ayers, Walter B.",
    title = "Coalbed Gas Systems, Resources, and Production and a Review of Contrasting Cases from the San Juan and Powder River Basins",
    year = "2002",
    journal = "AAPG Bulletin",
    abstract = "Abstract Coalbed gas has been produced commercially from the northern Appalachian basin since the 1930s and from the San Juan basin since the early 1950s. However, the magnitude and economic significance of coalbed gas resources were realized only in the 1970s and early 1980s when the U.S. Bureau of Mines, U.S. Department of Energy, the Gas Research Institute, and oil and gas operators made a concerted effort to demonstrate commercial production of coalbed gas from vertical wells. Exploration and development expanded in the late 1980s and early 1990s, due partly to an unconventional fuels tax credit. By 2000, coalbed gas accounted for 8.8\% of the reserves (15.7 tcf [0.44 Tm3]) and 9.2\% of the annual production (1.38 tcf [40 Gm3]) of dry gas in the United States. From 1989 through 2000, cumulative United States coalbed gas production was 9.63 tcf (272 Gm3). Today, coalbed gas development has spread to about a dozen basins in the United States, and exploration is progressing worldwide. Coal beds are self-sourcing reservoirs that can contain thermogenic, migrated thermogenic, biogenic, or mixed gas. Coalbed gas is stored primarily within micropores of the coal matrix in an adsorbed state and secondarily in micropores and fractures as free gas or solution gas in water. The key parameters that control gas resources and producibility are thermal maturity, maceral composition, gas content, coal thickness, fracture density, in-situ stress, permeability, burial history, and hydrologic setting. These parameters vary greatly in the producing fields of the United States and the world. In 2000, the San Juan basin accounted for more than 80\% of the United States coalbed gas production. This basin contains a giant coalbed gas play, the Fruitland fairway, which has produced more than 7 tcf (0.2 Tm3) of gas. The Fruitland coalbed gas system and its key elements contrast with the Fort Union coalbed gas play in the Powder River basin. The Fort Union coalbed play is one of the fastest developing gas plays in the United States. Its production escalated from 14 bcf (0.4 Gm3) in 1997 to 147.3 bcf (4.1 Gm3) in 2000, when it accounted for 10.7\% of the United States coalbed gas production. By 2001, annual production was 244.7 bcf (6.9 Gm3). Differences between the Fruitland and Fort Union petroleum systems make them ideal for elucidating the key elements of contrasting coalbed gas petroleum systems.",
    url = "https://doi.org/10.1306/61eeddaa-173e-11d7-8645000102c1865d",
    doi = "10.1306/61eeddaa-173e-11d7-8645000102c1865d",
    openalex = "W2031982848",
    references = "doi101016s0166516297000128, doi101016s0166516299000646, doi101029jb085ib11p06113, doi1011300016760619788959peotsj20co2, doi101306a25feaa9171b11d78645000102c1865d, doi101306m60585c1, doi101306st38577c7, doi101306st38577c9, doi10211836737ms, doi10211852607pa, doi103133pp676, fassett1971geology"
}

Geochronological, structural, and sedimentological data provide the basis for a regional synthesis of the evolution of the Cordilleran retroarc thrust belt and foreland basin system in the western U.S.A. In this region, the Cordilleran orogenic belt became tectonically consolidated during Late Jurassic time (∼155 Ma) with the closure of marginal oceanic basins and accretion of fringing arcs along the western edge of the North American plate. Over the ensuing 100 Myr, contractile deformation propagated approximately 1000 kilometers eastward, culminating in the formation of the Laramide Rocky Mountain ranges. At the peak of its development, the retroarc side of the Cordillera was divided into five tectonomorphic zones, including from west to east the Luning-Fencemaker thrust belt; the central Nevada (or Eureka) thrust belt; a high-elevation plateau (the "Nevadaplano"); the topographically rugged Sevier fold-thrust belt; and the Laramide zone of intraforeland basement uplifts and basins. Mid-crustal rocks beneath the Nevadaplano experienced high-grade metamorphism and shortening during Late Jurassic and mid- to Late Cretaceous time, and the locus of major, upper crustal thrust faulting migrated sporadically eastward. By Late Cretaceous time, the middle crust beneath the Nevadaplano was experiencing decompression and cooling, perhaps in response to large-magnitude ductile extension and isostatic exhumation, concurrent with ongoing thrusting in the frontal Sevier belt. The tectonic history of the Sevier belt was remarkably consistent along strike of the orogenic belt, with emplacement of regional-scale Proterozoic and Paleozoic megathrust sheets during Early Cretaceous time and multiple, more closely spaced, Paleozoic and Mesozoic thrust sheets during Late Cretaceous--Paleocene time. Coeval with emplacement of the frontal thrust sheets, large structural culminations in Archean-Proterozoic crystalline basement developed along the basement step formed by Neoproterozoic rifting. A complex foreland basin system evolved in concert with the orogenic wedge. During its early and late history (∼155 - 110 Ma and ∼70 - 55 Ma) the basin was dominated by nonmarine deposition, whereas marine waters inundated the basin during its midlife (∼110 - 70 Ma). Late Jurassic basin development was controlled by both flexural and dynamic subsidence. From Early Cretaceous through early Late Cretaceous time the basin was dominated by flexural subsidence. From Late Cretaceous to mid-Cenozoic time the basin was increasingly partitioned by basement-involved Laramide structures. Linkages between Late Jurassic and Late Cretaceous Cordilleran arc-magmatism and westward underthrusting of North American continental lithosphere beneath the arc are not plainly demonstrable from the geological record in the Cordilleran thrust belt. A significant lag-time (∼20 Myr) between shortening and coeval underthrusting, on the one hand, and generation of arc melts, on the other, is required for any linkage to exist. However, inferred Late Jurassic lithospheric delamination may have provided a necessary precondition to allow relatively rapid Early Cretaceous continental underthrusting, which in turn could have catalyzed the Late Cretaceous arc flare-up.

@article{doi102475ajs3042105,
    author = "DeCelles, Peter G.",
    title = "Late Jurassic to Eocene evolution of the Cordilleran thrust belt and foreland basin system, western U.S.A.",
    year = "2004",
    journal = "American Journal of Science",
    abstract = {Geochronological, structural, and sedimentological data provide the basis for a regional synthesis of the evolution of the Cordilleran retroarc thrust belt and foreland basin system in the western U.S.A. In this region, the Cordilleran orogenic belt became tectonically consolidated during Late Jurassic time (∼155 Ma) with the closure of marginal oceanic basins and accretion of fringing arcs along the western edge of the North American plate. Over the ensuing 100 Myr, contractile deformation propagated approximately 1000 kilometers eastward, culminating in the formation of the Laramide Rocky Mountain ranges. At the peak of its development, the retroarc side of the Cordillera was divided into five tectonomorphic zones, including from west to east the Luning-Fencemaker thrust belt; the central Nevada (or Eureka) thrust belt; a high-elevation plateau (the "Nevadaplano"); the topographically rugged Sevier fold-thrust belt; and the Laramide zone of intraforeland basement uplifts and basins. Mid-crustal rocks beneath the Nevadaplano experienced high-grade metamorphism and shortening during Late Jurassic and mid- to Late Cretaceous time, and the locus of major, upper crustal thrust faulting migrated sporadically eastward. By Late Cretaceous time, the middle crust beneath the Nevadaplano was experiencing decompression and cooling, perhaps in response to large-magnitude ductile extension and isostatic exhumation, concurrent with ongoing thrusting in the frontal Sevier belt. The tectonic history of the Sevier belt was remarkably consistent along strike of the orogenic belt, with emplacement of regional-scale Proterozoic and Paleozoic megathrust sheets during Early Cretaceous time and multiple, more closely spaced, Paleozoic and Mesozoic thrust sheets during Late Cretaceous--Paleocene time. Coeval with emplacement of the frontal thrust sheets, large structural culminations in Archean-Proterozoic crystalline basement developed along the basement step formed by Neoproterozoic rifting. A complex foreland basin system evolved in concert with the orogenic wedge. During its early and late history (∼155 - 110 Ma and ∼70 - 55 Ma) the basin was dominated by nonmarine deposition, whereas marine waters inundated the basin during its midlife (∼110 - 70 Ma). Late Jurassic basin development was controlled by both flexural and dynamic subsidence. From Early Cretaceous through early Late Cretaceous time the basin was dominated by flexural subsidence. From Late Cretaceous to mid-Cenozoic time the basin was increasingly partitioned by basement-involved Laramide structures. Linkages between Late Jurassic and Late Cretaceous Cordilleran arc-magmatism and westward underthrusting of North American continental lithosphere beneath the arc are not plainly demonstrable from the geological record in the Cordilleran thrust belt. A significant lag-time (∼20 Myr) between shortening and coeval underthrusting, on the one hand, and generation of arc melts, on the other, is required for any linkage to exist. However, inferred Late Jurassic lithospheric delamination may have provided a necessary precondition to allow relatively rapid Early Cretaceous continental underthrusting, which in turn could have catalyzed the Late Cretaceous arc flare-up.},
    url = "https://doi.org/10.2475/ajs.304.2.105",
    doi = "10.2475/ajs.304.2.105",
    openalex = "W2135909516",
    references = "doi101016004019519390295u, doi10102993rg02030, doi101029jb075i014p02625, doi101029jb088ib02p01153, doi101029jb093ib04p03211, doi101029tc005i002p00227, doi101038270403a0, doi101038386061a0, doi101046j13652117199601491x, doi1011300016760619881001023papsol23co2, doi101130001676062000112324tothas20co2, doi101130dnaggnac2463, doi101130dnaggnag3261, doi101130mem151p355, doi101130spe206, doi101130spe206p1, doi1013062f9188fb16ce11d78645000102c1865d"
}

@incollection{hutchison2005mineral,
    author = "Hutchison, Charles S",
    title = "Mineral, Petroleum and Coal Deposits",
    year = "2005",
    booktitle = "Geology of North-West Borneo",
    url = "https://doi.org/10.1016/b978-044451998-6/50010-7",
    doi = "10.1016/b978-044451998-6/50010-7",
    openalex = "W944922819",
    pages = "151-161"
}

Abstract Hydrocarbon-bearing zoned calcite cements occur widely in Jurassic–Cretaceous fault-zone cores and sandstone outcrops of the northwestern Junggar Basin (northwest China). Hydrocarbon-bearing bands alternate with nearly hydrocarbon-free bands at a micron scale. Analytical results from biomarker organic geochemistry, Fourier transform infrared microspectroscopy, and trace-element geochemistry on these zoned cements suggest that at least three different types of fluids have participated in their formation. The first fluid type is probably primary, unmodified lacustrine formation water, from which the hydrocarbon-poor bands are formed and are characterized by Mg-rich calcite. The other two types of fluids include basinal fluids (e.g., hot hydrocarbon-bearing fluids) and meteoric water. The hydrocarbon-rich bands in which the hydrocarbons have been biodegraded and the Mn content is relatively high suggest a mixture of hydrocarbon-bearing basinal fluid and meteoric water. The alternating growth of hydrocarbon-bearing and hydrocarbon-free bands of calcite cements implies that the cement formation is episodic; it is related to alternating episodes of mixed petroleum-bearing fluid and unmodified primary formation waters, respectively. The fault appears to have been a mixing zone where seismic pumping during the movement of associated regional faults occurred. Thus, in the northwestern Junggar Basin, the micron-scale hydrocarbon-bearing zoned structure of the calcite cements is likely a reflection of episodic petroleum fluid migration in fault zones.

@article{doi10130606050807124,
    author = "Jin, Zhijun and Cao, Jian and Hu, Wenxuan and Zhang, Yijie and Yao, Suping and Wang, Xulong and Zhang, Yueqian and Tang, Yong and Xinpu, Shi",
    title = "Episodic petroleum fluid migration in fault zones of the northwestern Junggar Basin (northwest China): Evidence from hydrocarbon-bearing zoned calcite cement",
    year = "2008",
    journal = "AAPG Bulletin",
    abstract = "Abstract Hydrocarbon-bearing zoned calcite cements occur widely in Jurassic–Cretaceous fault-zone cores and sandstone outcrops of the northwestern Junggar Basin (northwest China). Hydrocarbon-bearing bands alternate with nearly hydrocarbon-free bands at a micron scale. Analytical results from biomarker organic geochemistry, Fourier transform infrared microspectroscopy, and trace-element geochemistry on these zoned cements suggest that at least three different types of fluids have participated in their formation. The first fluid type is probably primary, unmodified lacustrine formation water, from which the hydrocarbon-poor bands are formed and are characterized by Mg-rich calcite. The other two types of fluids include basinal fluids (e.g., hot hydrocarbon-bearing fluids) and meteoric water. The hydrocarbon-rich bands in which the hydrocarbons have been biodegraded and the Mn content is relatively high suggest a mixture of hydrocarbon-bearing basinal fluid and meteoric water. The alternating growth of hydrocarbon-bearing and hydrocarbon-free bands of calcite cements implies that the cement formation is episodic; it is related to alternating episodes of mixed petroleum-bearing fluid and unmodified primary formation waters, respectively. The fault appears to have been a mixing zone where seismic pumping during the movement of associated regional faults occurred. Thus, in the northwestern Junggar Basin, the micron-scale hydrocarbon-bearing zoned structure of the calcite cements is likely a reflection of episodic petroleum fluid migration in fault zones.",
    url = "https://doi.org/10.1306/06050807124",
    doi = "10.1306/06050807124",
    openalex = "W2133461810",
    references = "lee1985geology"
}

The distribution of coal gas pools is controlled by many geological factors in China. The accumulation and pool-forming process of coal measures gas is studied from aspects of structure, source rock evolution, reservoir, pool-forming history, etc. The comparison results show that there are many similarities in geology between the Upper Paleozoic gas pools in Ordos Basin and the Upper Triassic Xujiahe Formation gas pools in Sichuan Basin, and the difference of the gas pools features in the two basins is caused by different structural evolutions and pool-forming processes. In Ordos Basin, water shoved by gas migrated from lower to higher positions in the formation process of the gas pools, and the abnormality of low gas reservoir pressure was caused by the water and gas reversal. In Sichuan Basin, structural traps controlled the gas pools distribution in Xujiahe Formation, lithologic gas pools was found locally, and the main factors for the abnormally high pressure are the undercompaction due to quick deposition, the hydrocarbon generation of source rocks and the structural compression during the Himalayan period.

@article{doi101016s1876380409601294,
    author = "Shuichang, Zhang and Mi, Jingkui and Liuhong, Liu and Shizhen, Tao",
    title = "Geological features and formation of coal-formed tight sandstone gas pools in China: Cases from Upper Paleozoic gas pools, Ordos Basin and Xujiahe Formation gas pools, Sichuan Basin",
    year = "2009",
    journal = "Petroleum Exploration and Development",
    abstract = "The distribution of coal gas pools is controlled by many geological factors in China. The accumulation and pool-forming process of coal measures gas is studied from aspects of structure, source rock evolution, reservoir, pool-forming history, etc. The comparison results show that there are many similarities in geology between the Upper Paleozoic gas pools in Ordos Basin and the Upper Triassic Xujiahe Formation gas pools in Sichuan Basin, and the difference of the gas pools features in the two basins is caused by different structural evolutions and pool-forming processes. In Ordos Basin, water shoved by gas migrated from lower to higher positions in the formation process of the gas pools, and the abnormality of low gas reservoir pressure was caused by the water and gas reversal. In Sichuan Basin, structural traps controlled the gas pools distribution in Xujiahe Formation, lithologic gas pools was found locally, and the main factors for the abnormally high pressure are the undercompaction due to quick deposition, the hydrocarbon generation of source rocks and the structural compression during the Himalayan period.",
    url = "https://doi.org/10.1016/s1876-3804(09)60129-4",
    doi = "10.1016/s1876-3804(09)60129-4",
    openalex = "W2071384249"
}

The structure and geological history of the Caucasus are largely determined by its position between the still-converging Eurasian and Africa-Arabian lithospheric plates, within a wide zone of continental collision. During the Late Proterozoic-Early Cenozoic, the region belonged to the Tethys Ocean and its Eurasian and Africa-Arabian margins where there existed a system of island arcs, intra-arc rifts, back-arc basins characteristic of the pre-collisional stage of its evolution of the region. The region, along with other fragments that are now exposed in the Upper Precambrian-Cambrian crystalline basement of the Alpine orogenic belt, was separated from western Gondwana during the Early Palaeozoic as a result of back-arc rifting above a south-dipping subduction zone. Continued rifting and seafloor spreading produced the Palaeotethys Ocean in the wake of northward migrating peri-Gondwanan terranes. The displacement of the Caucasian and other peri-Gondwanan terranes to the southern margin of Eurasia was completed by ~350 Ma. Widespread emplacement of microcline granite plutons along the active continental margin of southern Eurasia during 330-280 Ma occurred above a north-dipping Palaeotethyan subduction zone. However, Variscan and Eo-Cimmerian-Early Alpine events did not lead to the complete closing of the Palaeozoic Ocean. The Mesozoic Tethys in the Caucasus was inherited from the Palaeotethys. In the Mesozoic and Early Cenozoic, the Great Caucasus and Transcaucasus represented the Northtethyan realm - the southern active margin of the Eurasiatic lithospheric plate. The Oligocene-Neogene and Quaternary basins situated within the Transcaucasian intermontane depression mark the syn- and post-collisional evolution of the region; these basins represented a part of Paratethys and accumulated sediments of closed and semiclosed type. The final collision of the Africa-Arabian and Eurasian plates and formation of the present-day intracontinental mountainous edifice of the Caucasus occurred in the Neogene-Quaternary period. From the Late Miocene (c. 9-7 Ma) to the end of the Pleistocene, in the central part of the region, volcanic eruptions in subaerial conditions occurred simultaneously with the formation of molasse troughs. The geometry of tectonic deformations in the Transcaucasus is largely determined by the wedge-shaped rigid Arabian block intensively indenting into the Asia Minor-Caucasian region. All structural-morphological lines have a clearly-expressed arcuate northward-convex configuration reflecting the contours of the Arabian block. However, farther north, the geometry of the fold-thrust belts is somewhat different - the Achara-Trialeti fold-thrust belt is, on the whole, W-E-trending; the Greater Caucasian fold-thrust belt extends in a WNW-ESE direction.

@article{doi103906yer100511,
    author = "Adamia, Shota and Zakariadze, Guram and Chkhotua, Tamar and Sadradze, Nino and Tsereteli, Nino and Chabukiani, A. and Gventsadze, Aleksandre",
    title = "Geology of the Caucasus: A Review",
    year = "2011",
    journal = "TURKISH JOURNAL OF EARTH SCIENCES",
    abstract = "The structure and geological history of the Caucasus are largely determined by its position between the still-converging Eurasian and Africa-Arabian lithospheric plates, within a wide zone of continental collision. During the Late Proterozoic-Early Cenozoic, the region belonged to the Tethys Ocean and its Eurasian and Africa-Arabian margins where there existed a system of island arcs, intra-arc rifts, back-arc basins characteristic of the pre-collisional stage of its evolution of the region. The region, along with other fragments that are now exposed in the Upper Precambrian-Cambrian crystalline basement of the Alpine orogenic belt, was separated from western Gondwana during the Early Palaeozoic as a result of back-arc rifting above a south-dipping subduction zone. Continued rifting and seafloor spreading produced the Palaeotethys Ocean in the wake of northward migrating peri-Gondwanan terranes. The displacement of the Caucasian and other peri-Gondwanan terranes to the southern margin of Eurasia was completed by \textasciitilde 350 Ma. Widespread emplacement of microcline granite plutons along the active continental margin of southern Eurasia during 330-280 Ma occurred above a north-dipping Palaeotethyan subduction zone. However, Variscan and Eo-Cimmerian-Early Alpine events did not lead to the complete closing of the Palaeozoic Ocean. The Mesozoic Tethys in the Caucasus was inherited from the Palaeotethys. In the Mesozoic and Early Cenozoic, the Great Caucasus and Transcaucasus represented the Northtethyan realm - the southern active margin of the Eurasiatic lithospheric plate. The Oligocene-Neogene and Quaternary basins situated within the Transcaucasian intermontane depression mark the syn- and post-collisional evolution of the region; these basins represented a part of Paratethys and accumulated sediments of closed and semiclosed type. The final collision of the Africa-Arabian and Eurasian plates and formation of the present-day intracontinental mountainous edifice of the Caucasus occurred in the Neogene-Quaternary period. From the Late Miocene (c. 9-7 Ma) to the end of the Pleistocene, in the central part of the region, volcanic eruptions in subaerial conditions occurred simultaneously with the formation of molasse troughs. The geometry of tectonic deformations in the Transcaucasus is largely determined by the wedge-shaped rigid Arabian block intensively indenting into the Asia Minor-Caucasian region. All structural-morphological lines have a clearly-expressed arcuate northward-convex configuration reflecting the contours of the Arabian block. However, farther north, the geometry of the fold-thrust belts is somewhat different - the Achara-Trialeti fold-thrust belt is, on the whole, W-E-trending; the Greater Caucasian fold-thrust belt extends in a WNW-ESE direction.",
    url = "https://doi.org/10.3906/yer-1005-11",
    doi = "10.3906/yer-1005-11",
    openalex = "W2142982425",
    references = "doi101016004019518690199x, doi101016037702739090018b, doi101016jtecto200206004, doi1010291996jb900351, doi1010291999jb900351, doi1010292003gl018019, doi1010292003tc001530, doi1010292005jb004051, doi101111j1365246x1988tb01387x, doi101111j1365246x1990tb06579x"
}

This report discusses the geologic framework and petroleum geology used to assess undiscovered petroleum resources in the Bohaiwan basin province for the 2000 World Energy Assessment Project of the U.S. Geological Survey. The Bohaiwan basin in northeastern China is the largest petroleum-producing region in China. Two total petroleum systems have been identified in the basin. The first, the Shahejie–Shahejie/Guantao/Wumishan Total Petroleum System, involves oil and gas generated from mature pods of lacustrine source rock that are associated with six major rift-controlled subbasins. Two assessment units are defined in this total petroleum system: (1) a Tertiary lacustrine assessment unit consisting of sandstone reservoirs interbedded with lacustrine shale source rocks, and (2) a pre-Tertiary buried hills assessment unit consisting of carbonate reservoirs that are overlain unconformably by Tertiary lacustrine shale source rocks. The second total petroleum system identified in the Bohaiwan basin is the Carboniferous/Permian Coal–Paleozoic Total Petroleum System, a hypothetical total petroleum system involving natural gas generated from multiple pods of thermally mature coal beds. Low-permeability Permian sandstones and possibly Carboniferous coal beds are the reservoir rocks. Most of the natural gas is inferred to be trapped in continuous accumulations near the center of the subbasins. This total petroleum system is largely unexplored and has good potential for undiscovered gas accumulations. One assessment unit, coal-sourced gas, is defined in this total petroleum system.

@article{doi103133sir20115010,
    author = "Ryder, Robert T. and Qiang, Jin and McCabe, Peter J. and Nuccio, Vito F. and Persits, Felix",
    title = "Shahejie-Shahejie/Guantao/Wumishan and Carboniferous/Permian Coal-Paleozoic Total Petroleum Systems in the Bohaiwan Basin, China (based on geologic studies for the 2000 World Energy Assessment Project of the U.S. Geological Survey)",
    year = "2012",
    journal = "Scientific investigations report",
    abstract = "This report discusses the geologic framework and petroleum geology used to assess undiscovered petroleum resources in the Bohaiwan basin province for the 2000 World Energy Assessment Project of the U.S. Geological Survey. The Bohaiwan basin in northeastern China is the largest petroleum-producing region in China. Two total petroleum systems have been identified in the basin. The first, the Shahejie–Shahejie/Guantao/Wumishan Total Petroleum System, involves oil and gas generated from mature pods of lacustrine source rock that are associated with six major rift-controlled subbasins. Two assessment units are defined in this total petroleum system: (1) a Tertiary lacustrine assessment unit consisting of sandstone reservoirs interbedded with lacustrine shale source rocks, and (2) a pre-Tertiary buried hills assessment unit consisting of carbonate reservoirs that are overlain unconformably by Tertiary lacustrine shale source rocks. The second total petroleum system identified in the Bohaiwan basin is the Carboniferous/Permian Coal–Paleozoic Total Petroleum System, a hypothetical total petroleum system involving natural gas generated from multiple pods of thermally mature coal beds. Low-permeability Permian sandstones and possibly Carboniferous coal beds are the reservoir rocks. Most of the natural gas is inferred to be trapped in continuous accumulations near the center of the subbasins. This total petroleum system is largely unexplored and has good potential for undiscovered gas accumulations. One assessment unit, coal-sourced gas, is defined in this total petroleum system.",
    url = "https://doi.org/10.3133/sir20115010",
    doi = "10.3133/sir20115010",
    openalex = "W1498596239",
    references = "crossref1989geology, doi1010160016703788903705, doi101016004019518790268x, doi101016014663809090067a, doi1010160264817287900456, doi101016s0146638096000496, doi101016s0264817297000275, doi101016s0920410503001426, doi101038313444a0, doi10130664eda0d2172411d78645000102c1865d, doi101306m60585, doi103133ofr934"
}

A review on the geology and petroleum potentials of the Nigerian Benue Trough and Anambra Basin is done to identify potential petroleum systems in the basins. The tectonic, stratigraphic and organic geochemical evaluations of these basins suggest the similarity with the contiguous basins of Chad and Niger Republics and Sudan, where commercial oil discovery have been made. At least two potential petroleum systems may be presented in the basins: the Lower Cretaceous petroleum system likely capable of both oil and gas generation and the Upper Cretaceous petroleum system that could be mainly gas-generating. These systems are closely correlative in temporal disposition, structures, source and reservoir rocks and perhaps generation mechanism to what obtains in the Muglad Basin of Sudan and Termit Basin of Niger and Chad Republics. They are very effective in planning future exploration campaigns in the basins.

@article{doi104236nr201451005,
    author = "Abubakar, M.B.",
    title = "Petroleum Potentials of the Nigerian Benue Trough and Anambra Basin: A Regional Synthesis",
    year = "2014",
    journal = "Natural Resources",
    abstract = "A review on the geology and petroleum potentials of the Nigerian Benue Trough and Anambra Basin is done to identify potential petroleum systems in the basins. The tectonic, stratigraphic and organic geochemical evaluations of these basins suggest the similarity with the contiguous basins of Chad and Niger Republics and Sudan, where commercial oil discovery have been made. At least two potential petroleum systems may be presented in the basins: the Lower Cretaceous petroleum system likely capable of both oil and gas generation and the Upper Cretaceous petroleum system that could be mainly gas-generating. These systems are closely correlative in temporal disposition, structures, source and reservoir rocks and perhaps generation mechanism to what obtains in the Muglad Basin of Sudan and Termit Basin of Niger and Chad Republics. They are very effective in planning future exploration campaigns in the basins.",
    url = "https://doi.org/10.4236/nr.2014.51005",
    doi = "10.4236/nr.2014.51005",
    openalex = "W1975787804",
    references = "doi101111j174754571980tb00982x"
}

@article{doi101016jmarpetgeo201802010,
    author = "Chen, Xiaoyan and Hao, Fang and Guo, Liuxi and Wang, Daojun and Yin, Jie and Yang, Fan and Zou, Huayao",
    title = "Origin of petroleum accumulation in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin, China: Insights from biomarker and geological analyses",
    year = "2018",
    journal = "Marine and Petroleum Geology",
    url = "https://doi.org/10.1016/j.marpetgeo.2018.02.010",
    doi = "10.1016/j.marpetgeo.2018.02.010",
    openalex = "W2789468233",
    references = "doi101306ad4616ab16f711d78645000102c1865d"
}

Sedimentary basins have been well documented for many years, but their boundaries are often inadequately represented. This study delineated 764 basins using global geologic datasets to create more consistent basin outlines that can be utilized to conduct future global studies. Every sedimentary basin contains an incomplete record of Earth's history, but the study of all of the global basins provides a more complete view of the evolution of the planet as well as a better framework to study the resources within these basins. Additional basin attributes were captured that will aid future research and modeling (name, type, age, area, depth, presence of evaporites, evaporite type, presence of volcanics, etc.). Most sedimentary basins formed during the breakup of Rodinia, Pannotia, and Pangea (Proterozoic-Cambrian and Mesozoic). Many of the older basins are now situated in the interiors of continents as intracratonic and foreland basins, whereas most of the younger basins are located at the edges of the continents as passive margins, strike-slip, or arc-related basins. The basin type also was found to relate to the maximum sediment thickness with passive margin, foreland, fold and thrust belt, and intracratonic basins often having the thickest sedimentary sequences (>3.0–4.0 km). It was also found that 217 basins contained 369 evaporite intervals and that these sequences were most often located within passive margins and foreland basins, and almost never observed in backarc - marginal sea and forearc basins. Temporally, evaporite deposition was somewhat intermittent throughout Earth's history, but there was widespread deposition during the late Permian and late Triassic intervals with other notable events during the Neoproterozoic-early Cambrian, Aptian-Albian, middle Eocene, and late Miocene (Messinian) time periods. Based on paleogeographic reconstructions, almost all of the 369 evaporite units were deposited within 45 degrees of the equator and were likely influenced by confluence of regional and global factors (e.g., tectonic events, geographical restrictions, and climate).

@article{doi101016jearscirev2021103564,
    author = "Evenick, Jonathan C.",
    title = "Glimpses into Earth's history using a revised global sedimentary basin map",
    year = "2021",
    journal = "Earth-Science Reviews",
    abstract = "Sedimentary basins have been well documented for many years, but their boundaries are often inadequately represented. This study delineated 764 basins using global geologic datasets to create more consistent basin outlines that can be utilized to conduct future global studies. Every sedimentary basin contains an incomplete record of Earth's history, but the study of all of the global basins provides a more complete view of the evolution of the planet as well as a better framework to study the resources within these basins. Additional basin attributes were captured that will aid future research and modeling (name, type, age, area, depth, presence of evaporites, evaporite type, presence of volcanics, etc.). Most sedimentary basins formed during the breakup of Rodinia, Pannotia, and Pangea (Proterozoic-Cambrian and Mesozoic). Many of the older basins are now situated in the interiors of continents as intracratonic and foreland basins, whereas most of the younger basins are located at the edges of the continents as passive margins, strike-slip, or arc-related basins. The basin type also was found to relate to the maximum sediment thickness with passive margin, foreland, fold and thrust belt, and intracratonic basins often having the thickest sedimentary sequences (>3.0–4.0 km). It was also found that 217 basins contained 369 evaporite intervals and that these sequences were most often located within passive margins and foreland basins, and almost never observed in backarc - marginal sea and forearc basins. Temporally, evaporite deposition was somewhat intermittent throughout Earth's history, but there was widespread deposition during the late Permian and late Triassic intervals with other notable events during the Neoproterozoic-early Cambrian, Aptian-Albian, middle Eocene, and late Miocene (Messinian) time periods. Based on paleogeographic reconstructions, almost all of the 369 evaporite units were deposited within 45 degrees of the equator and were likely influenced by confluence of regional and global factors (e.g., tectonic events, geographical restrictions, and climate).",
    url = "https://doi.org/10.1016/j.earscirev.2021.103564",
    doi = "10.1016/j.earscirev.2021.103564",
    openalex = "W3131383366",
    references = "doi101017s0016756818000110, doi101111j174754571980tb00982x"
}

The Carboniferous-Permian was an important period for the formation of coal mines and coaly source rocks across the world. Controlled by the paleoclimate, Cathaysia flora, and transitional sedimentary environment of the delta, the Early Permian Shanxi Formation in the Huanghua Depression formed several layers of coal and coaly source rocks that can be explored in the whole depression. However, the development regularity and distribution prediction of high-quality coaly source rocks are still not well understood. The coaly source rocks of the Shanxi Formation in the Huanghua Depression were taken as the research object. With the determination and analysis of organic carbon content, rock pyrolysis, and vitrinite reflectance, we found that the organic matter abundance (i.e., TOC which changed from 20.3 % to 80.0 %), hydrocarbon generation potential (i.e., S1 + S2 which varied from 7.82 mg/g to 208.81 mg/g), and kerogen types (mainly type II2) of the coal were better than carbonaceous mudstone and coaly shale. Maceral component identification indicated that coal and carbonaceous mudstone had more liptinite (i.e. cutinite and sporinite)and hydrogen-rich vitrinite, while coaly shale was mainly composed of hydrogen-poor vitrinite and a small amount of liptinite. The analysis of the ratios of major and trace elements, normal alkanes, and isoparaffin suggested that the paleo-water salinity of coal and carbonaceous mudstone deposition was more than that of part coaly shale. Revealed by the weak reduction of their depositional environment, the development of high-quality coal and carbonaceous mudstone was mostly controlled by the input of oil- and gas-prone organic matter. The formation of high-quality coaly shale was chiefly dominated by a strong reduction environment with an insignificant amount of organic matter input. The formation model of high-quality coaly source rocks was established. This model can be used to predict the distribution of coal mines and coaly source rocks in the Huanghua Depression and Bohai Bay Basin.

@article{doi101016joregeorev2023105315,
    author = "Xu, Jinjun and Cheng, Xiangang and Peng, Shunan and Jin, Qiang and Cheng, Fuqi and Lou, Da and Zhang, Feipeng and Li, Fulai",
    title = "Depositional environment and hydrocarbon potential of Early Permian coals deposit in the Huanghua Depression, Bohai Bay Basin",
    year = "2023",
    journal = "Ore Geology Reviews",
    abstract = "The Carboniferous-Permian was an important period for the formation of coal mines and coaly source rocks across the world. Controlled by the paleoclimate, Cathaysia flora, and transitional sedimentary environment of the delta, the Early Permian Shanxi Formation in the Huanghua Depression formed several layers of coal and coaly source rocks that can be explored in the whole depression. However, the development regularity and distribution prediction of high-quality coaly source rocks are still not well understood. The coaly source rocks of the Shanxi Formation in the Huanghua Depression were taken as the research object. With the determination and analysis of organic carbon content, rock pyrolysis, and vitrinite reflectance, we found that the organic matter abundance (i.e., TOC which changed from 20.3 \% to 80.0 \%), hydrocarbon generation potential (i.e., S1 + S2 which varied from 7.82 mg/g to 208.81 mg/g), and kerogen types (mainly type II2) of the coal were better than carbonaceous mudstone and coaly shale. Maceral component identification indicated that coal and carbonaceous mudstone had more liptinite (i.e. cutinite and sporinite)and hydrogen-rich vitrinite, while coaly shale was mainly composed of hydrogen-poor vitrinite and a small amount of liptinite. The analysis of the ratios of major and trace elements, normal alkanes, and isoparaffin suggested that the paleo-water salinity of coal and carbonaceous mudstone deposition was more than that of part coaly shale. Revealed by the weak reduction of their depositional environment, the development of high-quality coal and carbonaceous mudstone was mostly controlled by the input of oil- and gas-prone organic matter. The formation of high-quality coaly shale was chiefly dominated by a strong reduction environment with an insignificant amount of organic matter input. The formation model of high-quality coaly source rocks was established. This model can be used to predict the distribution of coal mines and coaly source rocks in the Huanghua Depression and Bohai Bay Basin.",
    url = "https://doi.org/10.1016/j.oregeorev.2023.105315",
    doi = "10.1016/j.oregeorev.2023.105315",
    openalex = "W4317725994",
    references = "doi103133sir20115010"
}