Frio formation

Abstract: The East White Point oil field is located in south-central San Patricio and north-central Nueces counties, Texas, on the Gulf Coastal Plain of South Texas. It is situated approximately midway between Galveston and Brownsville, 20 miles inland from the Gulf of Mexico, and 5 miles northward across Nueces Bay from the city and deep-water port of Corpus Christi. Subsequent to the discovery of oil in the 5,600-foot sand, by the Plymouth Oil Company in February, 1938, the field has been subjected to continuous development. As of January 1, 1941, approximately 240 oil and gas wells have been completed in the four productive sands between the depths of 4,100 feet and 5,900 feet, which wells have yielded approximately 512 million barrels of oil. Within the scope of this paper, the strata encountered in most of the wells below a depth of 4,000 feet have been grouped in the Oligocene formation, and the writers have restricted their study to the beds included in the interval below that depth and above the 5,600-foot (principal oil-producing) sand. Isopach and other geologic studies of the several sand and shale zones have presented interesting problems. The intermittent and periodic structure-making movements, and likewise the periods of quiescence, are reflected in the sedimentary intervals of the respective strata. The most outstanding feature of the stratigraphy, however, is the well developed erosional topography on the top of the 5,400-foot (Zone E) sand. Isopach maps of this stratum display the typical features of degradation and planation common to the erosion cycle of normal rivers in an area being subjected to cyclic rejuvenation. Similar maps of the overlying 5,300-foot (Zone D) shale reflect the effects of unequal deposition over the eroded topography. As suggested by the reconstructed terraces and slopes attendant thereto, three periods of uplift and erosion are present. The erosional unconformity thus established, and advocated by the writers, offers additional criteria and evidence for the following: first, offlap or regression of the Gulf of Mexico at the close of Frio time with the con sequent development of stream drainage and erosional topography on the land surface; second, the location of an ancient Gulf of Mexico at some distance removed from the present location of the East White Point field following the deposition of the 5,400-foot sand; and third, the delineation of the top of the Frio formation at the erosional break in the stratigraphy.

@article{doi1013063d93340416b111d78645000102c1865d,
    author = "Martyn, Phil F. and Sample, Charles H.",
    title = "OLIGOCENE STRATIGRAPHY OF EAST WHITE POINT FIELD, SAN PATRICIO AND NUECES COUNTIES, TEXAS",
    year = "1941",
    journal = "AAPG Bulletin",
    abstract = "Abstract: The East White Point oil field is located in south-central San Patricio and north-central Nueces counties, Texas, on the Gulf Coastal Plain of South Texas. It is situated approximately midway between Galveston and Brownsville, 20 miles inland from the Gulf of Mexico, and 5 miles northward across Nueces Bay from the city and deep-water port of Corpus Christi. Subsequent to the discovery of oil in the 5,600-foot sand, by the Plymouth Oil Company in February, 1938, the field has been subjected to continuous development. As of January 1, 1941, approximately 240 oil and gas wells have been completed in the four productive sands between the depths of 4,100 feet and 5,900 feet, which wells have yielded approximately 512 million barrels of oil. Within the scope of this paper, the strata encountered in most of the wells below a depth of 4,000 feet have been grouped in the Oligocene formation, and the writers have restricted their study to the beds included in the interval below that depth and above the 5,600-foot (principal oil-producing) sand. Isopach and other geologic studies of the several sand and shale zones have presented interesting problems. The intermittent and periodic structure-making movements, and likewise the periods of quiescence, are reflected in the sedimentary intervals of the respective strata. The most outstanding feature of the stratigraphy, however, is the well developed erosional topography on the top of the 5,400-foot (Zone E) sand. Isopach maps of this stratum display the typical features of degradation and planation common to the erosion cycle of normal rivers in an area being subjected to cyclic rejuvenation. Similar maps of the overlying 5,300-foot (Zone D) shale reflect the effects of unequal deposition over the eroded topography. As suggested by the reconstructed terraces and slopes attendant thereto, three periods of uplift and erosion are present. The erosional unconformity thus established, and advocated by the writers, offers additional criteria and evidence for the following: first, offlap or regression of the Gulf of Mexico at the close of Frio time with the con sequent development of stream drainage and erosional topography on the land surface; second, the location of an ancient Gulf of Mexico at some distance removed from the present location of the East White Point field following the deposition of the 5,400-foot sand; and third, the delineation of the top of the Frio formation at the erosional break in the stratigraphy.",
    url = "https://doi.org/10.1306/3d933404-16b1-11d7-8645000102c1865d",
    doi = "10.1306/3d933404-16b1-11d7-8645000102c1865d",
    openalex = "W2031148693"
}

ABSTRACT Recent development in the Gulf Coast of Texas has indicated the productive possibilities of many of the sands composing the lower part of the thick Frio formation of Oligocene age (considered to be Miocene by some workers). Exploration to the deeper sands of the Frio discloses facts of depositional conditions of this formation, which are as critical as structure for the accumulation of petroleum. In Orange and Jefferson counties the Frio formation is divisible into three lithologic units: an upper unit consisting primarily of sands; a middle unit of marine shale; and a lower unit consisting of sands and shale. Isopach maps reveal the location of ancient offshore bars and re-entrant basins and also show local thinning of beds in areas of structural uplift. The variation in stratigraphic position of certain foraminiferal associations is believed to be due to ecological changes and to the marine progressive overlap.

@article{doi1013063d933e1816b111d78645000102c1865d,
    author = "Reedy, Milton Frank",
    title = "Stratigraphy of Frio Formation Orange and Jefferson Counties, Texas",
    year = "1949",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT Recent development in the Gulf Coast of Texas has indicated the productive possibilities of many of the sands composing the lower part of the thick Frio formation of Oligocene age (considered to be Miocene by some workers). Exploration to the deeper sands of the Frio discloses facts of depositional conditions of this formation, which are as critical as structure for the accumulation of petroleum. In Orange and Jefferson counties the Frio formation is divisible into three lithologic units: an upper unit consisting primarily of sands; a middle unit of marine shale; and a lower unit consisting of sands and shale. Isopach maps reveal the location of ancient offshore bars and re-entrant basins and also show local thinning of beds in areas of structural uplift. The variation in stratigraphic position of certain foraminiferal associations is believed to be due to ecological changes and to the marine progressive overlap.",
    url = "https://doi.org/10.1306/3d933e18-16b1-11d7-8645000102c1865d",
    doi = "10.1306/3d933e18-16b1-11d7-8645000102c1865d",
    openalex = "W1980941728",
    references = "doi1013061013063d93378a16b111d78645000102c1865d, doi1013063d9331b216b111d78645000102c1865d, doi1013063d93340416b111d78645000102c1865d, doi1013063d93340616b111d78645000102c1865d, doi1013063d93372616b111d78645000102c1865d, doi1013063d9337c416b111d78645000102c1865d, doi1013063d9337c816b111d78645000102c1865d, doi1013063d93393816b111d78645000102c1865d, doi1013063d93398c16b111d78645000102c1865d"
}

@article{hinyard1951big,
    author = "Hinyard, Paul B.",
    title = "Big Foot Field, Frio County, Texas: ABSTRACT",
    year = "1951",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/3d93437c-16b1-11d7-8645000102c1865d",
    doi = "10.1306/3d93437c-16b1-11d7-8645000102c1865d",
    openalex = "W1964735752",
    volume = "35"
}

@article{hudgins1951history,
    author = "Hudgins, Mary D. and Lackey, Walter F.",
    title = "History of Newton County, Arkansas",
    year = "1951",
    journal = "The Arkansas Historical Quarterly",
    url = "https://doi.org/10.2307/40018485",
    doi = "10.2307/40018485",
    number = "2",
    openalex = "W2978962423",
    pages = "231",
    volume = "10"
}

ABSTRACT The character, distribution, and probable genesis of a typical lenticular oil-bearing sand body of the Gulf Coast Tertiary, namely, Zone 19B, an Oligocene sand of the Seeligson field, Texas, were determined for the purpose of developing and defining criteria by which such sand bodies can be readily identified and delimited in the subsurface. The stratigraphic framework was specified by cross sections, fence diagrams, isopach maps, and facies maps, prepared from electric logs and core descriptions, and the sediments were characterized by size, shape, thin-section, X-ray, differential thermal, and chemical analyses. Principal results are: (1) the isopachal trend of the sand body is nearly normal to the regional depositional strike; (2) the sand grades from medium grain at the base to fine at the top and can be divided into three zones on maximum grain size; (3) a typical specimen is a mixture of (a) well sorted sand, the framework size fraction, (b) interstitial clay, the tail of the size-distribution curve, and (c) interstitial calcite cement; (4) the mineral composition is similar to that of a Recent river sand, but dissimilar to that of beaches, of the same geological province. The sand body is probably an Oligocene alluvial-plain deposit as indicated by its similarity to such Recent deposits in external form, vertical textural zonation, colors of associated shales, mineralogy, presence of mud fragments, and absence of indigenous fauna. The often stated opinion that oil-field trends of the Gulf Coast, such as the Frio-Vicksburg, are “shore-line” trends has led many geologists to infer that the reservoir sands of these oil fields are strand-line deposits. The conclusions of the present study emphasize the risk of such deductions. The trends may be indirectly related to shore lines by reason of marine source beds, but many, or possibly most, of the reservoir sands may be of continental origin. The trapping in this zone arises from updip normal faulting and gentle doming of a lenticular alluvial sand body which is oriented in the direction of regional dip. The greatest value of these findings lies in the extrapolation and extension of this knowledge of local genesis to other parts of the section. In such a fashion a regional depositional and tectonic history can be outlined, centers of deposition for various geologic ages can be delimited, and areas favorable for the presence of permeable beds and oil accumulation can be approached.

@article{doi1013065ceadeb716bb11d78645000102c1865d,
    author = "Nanz, Robert Hamilton",
    title = "Genesis of Oligocene Sandstone Reservoir, Seeligson Field, Jim Wells and Kleberg Counties, Texas",
    year = "1954",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The character, distribution, and probable genesis of a typical lenticular oil-bearing sand body of the Gulf Coast Tertiary, namely, Zone 19B, an Oligocene sand of the Seeligson field, Texas, were determined for the purpose of developing and defining criteria by which such sand bodies can be readily identified and delimited in the subsurface. The stratigraphic framework was specified by cross sections, fence diagrams, isopach maps, and facies maps, prepared from electric logs and core descriptions, and the sediments were characterized by size, shape, thin-section, X-ray, differential thermal, and chemical analyses. Principal results are: (1) the isopachal trend of the sand body is nearly normal to the regional depositional strike; (2) the sand grades from medium grain at the base to fine at the top and can be divided into three zones on maximum grain size; (3) a typical specimen is a mixture of (a) well sorted sand, the framework size fraction, (b) interstitial clay, the tail of the size-distribution curve, and (c) interstitial calcite cement; (4) the mineral composition is similar to that of a Recent river sand, but dissimilar to that of beaches, of the same geological province. The sand body is probably an Oligocene alluvial-plain deposit as indicated by its similarity to such Recent deposits in external form, vertical textural zonation, colors of associated shales, mineralogy, presence of mud fragments, and absence of indigenous fauna. The often stated opinion that oil-field trends of the Gulf Coast, such as the Frio-Vicksburg, are “shore-line” trends has led many geologists to infer that the reservoir sands of these oil fields are strand-line deposits. The conclusions of the present study emphasize the risk of such deductions. The trends may be indirectly related to shore lines by reason of marine source beds, but many, or possibly most, of the reservoir sands may be of continental origin. The trapping in this zone arises from updip normal faulting and gentle doming of a lenticular alluvial sand body which is oriented in the direction of regional dip. The greatest value of these findings lies in the extrapolation and extension of this knowledge of local genesis to other parts of the section. In such a fashion a regional depositional and tectonic history can be outlined, centers of deposition for various geologic ages can be delimited, and areas favorable for the presence of permeable beds and oil accumulation can be approached.",
    url = "https://doi.org/10.1306/5ceadeb7-16bb-11d7-8645000102c1865d",
    doi = "10.1306/5ceadeb7-16bb-11d7-8645000102c1865d",
    openalex = "W2124852108"
}

ABSTRACT The South Texas Frio Trend extends along the coast from the Rio Grande River on the south through Calhoun and Victoria Counties on the north. The discovery of oil in Refugio Field of Refugio County in 1928 led to the development of the Golden Trend. The sediments of the Frio formation were deposited on a sinking continental shelf by transgressive and regressive seas, over an eroded Vicksburg surface. The Anahuac marine wedge overlaps the downdip Frio. The Catahoula sands and shales overlie and are in contact with the Anahuac wedge downdip and the Frio formation updip. Numerous facies changes and down-to-the-coast fault systems have accounted for the majority of the large producing fields. Approximately ninety percent of the Frio and Anahuac Fields that have produced over 25 million barrels of oil are located along the Vicksburg Flexure,(FOOTNOTE 2) Fields with an accumulative total of less than 25 million barrels of oil make up a large share of the tremendous reserves of this so-called Golden Trend. Producing structures include accumulations along the downthrown segment of down-to-the-coast faults, up-to-the-coast fault closures, closures on the up-thrown side of down-to-the-coast faults and salt-generated structures.

@article{openalexw1845753970,
    author = "Johnson, Ray B. and Mathy, Harold E.",
    title = "The South Texas Frio Trend",
    year = "1957",
    abstract = "ABSTRACT The South Texas Frio Trend extends along the coast from the Rio Grande River on the south through Calhoun and Victoria Counties on the north. The discovery of oil in Refugio Field of Refugio County in 1928 led to the development of the Golden Trend. The sediments of the Frio formation were deposited on a sinking continental shelf by transgressive and regressive seas, over an eroded Vicksburg surface. The Anahuac marine wedge overlaps the downdip Frio. The Catahoula sands and shales overlie and are in contact with the Anahuac wedge downdip and the Frio formation updip. Numerous facies changes and down-to-the-coast fault systems have accounted for the majority of the large producing fields. Approximately ninety percent of the Frio and Anahuac Fields that have produced over 25 million barrels of oil are located along the Vicksburg Flexure,(FOOTNOTE 2) Fields with an accumulative total of less than 25 million barrels of oil make up a large share of the tremendous reserves of this so-called Golden Trend. Producing structures include accumulations along the downthrown segment of down-to-the-coast faults, up-to-the-coast fault closures, closures on the up-thrown side of down-to-the-coast faults and salt-generated structures.",
    openalex = "W1845753970"
}

The Northwest Hartburg field, located in southern Newton County, Texas, is in a structural belt which forms part of the Gulf Coast Frio (Oligocene-Miocene) producing trend and for which the name Hartburg flexure is suggested. The various structural and depositional features (folds, faults, truncation, channels, etc.) observed in this trend are particularly well exhibited in the Northwest Hartburg field area and indicate a structural development which, reaching a climax during earlier Frio time, can be divided into four stages. Stage 1.—During stage 1, continental shelf conditions prevailed throughout the area and a sedimentary series, consisting essentially of shale in its lower and a sandy section in its upper part, was deposited on the slowly subsiding shelf. The sand section is subdivided, in ascending order, into the Nodosaria sand, and lower and upper Hartburg sands, the latter two names replacing the more commonly used but misleading names “lower and upper Hackberry sands.” Stage 2.—Toward the end of upper Hartburg sand sedimentation, the area experienced a large scale and semi-regional structural disturbance in the form of a breakdown of a segment of the Gulf Coast geosynclinal floor. This event tilted the continental shelf, producing the Hartburg flexure (scarp) and an embayment which was later filled by the Hackberry shale. Stage 3.—The tilting of the continental shelf area induced gravity flow in the sedimentary beds which was essentially a downfolding process. The resulting synclinal folds formed deep troughs and trenches turning the scarp into one of considerable relief that resembled the topography of the present continental slope of the northwestern Gulf of Mexico. Most of the troughs show effects of local submarine erosion in the form of channels and scour scars, some of which extended also across the anticlinal fold adjoining the trough. Besides tilting the continental shelf, the regional downwarp also lowered the base level of erosion and depositions across the shelf area. In adjustment to the new profile of equilibrium the anticlinal folds were truncated as evidenced by the presence of a local angular unconformity between the Hackberry shale and underlying formations. Stage 4.—After gravity flow subsided and the new base level of erosion was attained, turbidity currents and sedimentary flows filled the troughs and channels with “channel-fill” deposits. On completion of the peneplaning action, the deposition of the Hackberry shale commenced restoring again to the area more normal depositional conditions. Mild folding and faulting continued or were rejuvenated during this and later depositional cycles on some of the local folds in the Hartburg trend.

@article{bornhauser1960depositional,
    author = "Bornhauser, Max",
    title = "Depositional and Structural History of Northwest Hartburg Field, Newton County, Texas",
    year = "1960",
    journal = "AAPG Bulletin",
    abstract = "The Northwest Hartburg field, located in southern Newton County, Texas, is in a structural belt which forms part of the Gulf Coast Frio (Oligocene-Miocene) producing trend and for which the name Hartburg flexure is suggested. The various structural and depositional features (folds, faults, truncation, channels, etc.) observed in this trend are particularly well exhibited in the Northwest Hartburg field area and indicate a structural development which, reaching a climax during earlier Frio time, can be divided into four stages. Stage 1.—During stage 1, continental shelf conditions prevailed throughout the area and a sedimentary series, consisting essentially of shale in its lower and a sandy section in its upper part, was deposited on the slowly subsiding shelf. The sand section is subdivided, in ascending order, into the Nodosaria sand, and lower and upper Hartburg sands, the latter two names replacing the more commonly used but misleading names “lower and upper Hackberry sands.” Stage 2.—Toward the end of upper Hartburg sand sedimentation, the area experienced a large scale and semi-regional structural disturbance in the form of a breakdown of a segment of the Gulf Coast geosynclinal floor. This event tilted the continental shelf, producing the Hartburg flexure (scarp) and an embayment which was later filled by the Hackberry shale. Stage 3.—The tilting of the continental shelf area induced gravity flow in the sedimentary beds which was essentially a downfolding process. The resulting synclinal folds formed deep troughs and trenches turning the scarp into one of considerable relief that resembled the topography of the present continental slope of the northwestern Gulf of Mexico. Most of the troughs show effects of local submarine erosion in the form of channels and scour scars, some of which extended also across the anticlinal fold adjoining the trough. Besides tilting the continental shelf, the regional downwarp also lowered the base level of erosion and depositions across the shelf area. In adjustment to the new profile of equilibrium the anticlinal folds were truncated as evidenced by the presence of a local angular unconformity between the Hackberry shale and underlying formations. Stage 4.—After gravity flow subsided and the new base level of erosion was attained, turbidity currents and sedimentary flows filled the troughs and channels with “channel-fill” deposits. On completion of the peneplaning action, the deposition of the Hackberry shale commenced restoring again to the area more normal depositional conditions. Mild folding and faulting continued or were rejuvenated during this and later depositional cycles on some of the local folds in the Hartburg trend.",
    url = "https://doi.org/10.1306/0bda5fff-16bd-11d7-8645000102c1865d",
    doi = "10.1306/0bda5fff-16bd-11d7-8645000102c1865d",
    number = "4",
    openalex = "W2045835314",
    pages = "458-470",
    volume = "44",
    references = "doi10113000167606195566203totcsi20co2, doi1013060bda5a8316bd11d78645000102c1865d, doi1013060bda5c2a16bd11d78645000102c1865d, doi1013063d933e1816b111d78645000102c1865d, doi1013063d933e2d16b111d78645000102c1865d, openalexw1565983386, openalexw2601390057"
}

@techreport{bornhauser1960depositional1,
    author = "Bornhauser, M",
    title = "Depositional and structural history of Northwest Hartburg Field, Newton County, Texas",
    year = "1960",
    howpublished = "American Association of Petroleum Geologists Bulletin, v. 44, p. 458-470",
    note = "talkorigins\_source = {true}; raw\_reference = {Bornhauser, M., 1960, Depositional and structural history of Northwest Hartburg Field, Newton County, Texas: American Association of Petroleum Geologists Bulletin, v. 44, p. 458-470.}"
}

ABSTRACT Port Acres and Port Arthur Gas Distillate Fields are located immediately west of the town of Port Arthur, Jefferson County, Texas, along the downdip portion of the Frio producing sand trend and on a semi-regional positive feature, generally known as the Vicksburg Platform. Port Acres is a classic example of a field producing from a stratigraphic trap while Port Arthur is an equally classic example of a field producing from an anticlinal closure developed on the downthrown side of a contemporaneous fault. Highlights of the prediscovery exploration between 1944 and 1957 are summarized. Two structural maps and two cross sections have been prepared to show the interrelationship of structure, stratigraphy and accumulation. A brief geological history describes the occurence of the lower Hackberry sand section as a delta deposited at the mouth of an ancient stream and influenced first by the rise of Spindletop salt dome to the northwest and later by the growth of Port Neches salt dome to the northeast. Statistics on the fields show that Port Acres covers 3200 acres on which 54 wells have been successfully completed and Port Arthur covers approximately 1700 acres on which 14 wells have been completed. Reserve estimates for both fields indicate 400 to 500 billion cubic feet of recoverable gas and 20 to 25 million barrels of distillate. It is concluded that other sands of the lower Hackberry section should be found productive at a proper pinch out point north and east of Port Acres and that other lower Hackberry deltas may be expected somewhere else across the eroded surface of the Vicksburg Platform.

@article{openalexw1526438593,
    author = "Halbouty, Michael T. and Barber, Thomas D.",
    title = "Port Acres and Port Arthur Fields Jefferson County, Texas",
    year = "1961",
    abstract = "ABSTRACT Port Acres and Port Arthur Gas Distillate Fields are located immediately west of the town of Port Arthur, Jefferson County, Texas, along the downdip portion of the Frio producing sand trend and on a semi-regional positive feature, generally known as the Vicksburg Platform. Port Acres is a classic example of a field producing from a stratigraphic trap while Port Arthur is an equally classic example of a field producing from an anticlinal closure developed on the downthrown side of a contemporaneous fault. Highlights of the prediscovery exploration between 1944 and 1957 are summarized. Two structural maps and two cross sections have been prepared to show the interrelationship of structure, stratigraphy and accumulation. A brief geological history describes the occurence of the lower Hackberry sand section as a delta deposited at the mouth of an ancient stream and influenced first by the rise of Spindletop salt dome to the northwest and later by the growth of Port Neches salt dome to the northeast. Statistics on the fields show that Port Acres covers 3200 acres on which 54 wells have been successfully completed and Port Arthur covers approximately 1700 acres on which 14 wells have been completed. Reserve estimates for both fields indicate 400 to 500 billion cubic feet of recoverable gas and 20 to 25 million barrels of distillate. It is concluded that other sands of the lower Hackberry section should be found productive at a proper pinch out point north and east of Port Acres and that other lower Hackberry deltas may be expected somewhere else across the eroded surface of the Vicksburg Platform.",
    openalex = "W1526438593"
}

ABSTRACT Big Hill field is in the Frio sand trend on the western flank of the Big Hill salt dome. Multiple reservoirs in Miocene and Oligocene sandstones are on the downthrown side of a regional, up-to-the-coast growth fault across which early Miocene and older sediments increase in thickness by 57%. One reservoir in the Oligocene Hackberry is bounded by two growth faults and an unconformity (Hackberry unconformity). The hydrocarbons trapped in this reservoir evidently were generated within the surrounding rocks. An isopachous map of the interval between the top of the Frio and the Hackberry unconformity indicates that growth of the Big Hill salt dome occurred prior to the close of Frio time, and that the crest of the dome was north of the present-day salt spine. This map also suggests the presence of a buried, down-to-the-coast growth fault which traverses the western flank of Big Hill field but which does not intersect any wells. Pressure-performance histories of two reservoirs and of two wells producing from other reservoirs are shown graphically in order to illustrate the problems involved in explaining wells that are in pressure communication. Four gas-fluid contacts in a continuous Marginulina sandstone reservoir differ in elevation by 600± ft. These original gas-fluid contacts were established by the migration of hydrocarbons into a complexly faulted area. Accumulation of oil downdip from these gas-fluid contacts can be explained reasonably in terms of gravity-segregation effects.

@article{doi101306a66337d416c011d78645000102c1865d,
    author = "Dollison, Robert S.",
    title = "Big Hill Field, Jefferson County, Texas",
    year = "1965",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT Big Hill field is in the Frio sand trend on the western flank of the Big Hill salt dome. Multiple reservoirs in Miocene and Oligocene sandstones are on the downthrown side of a regional, up-to-the-coast growth fault across which early Miocene and older sediments increase in thickness by 57\%. One reservoir in the Oligocene Hackberry is bounded by two growth faults and an unconformity (Hackberry unconformity). The hydrocarbons trapped in this reservoir evidently were generated within the surrounding rocks. An isopachous map of the interval between the top of the Frio and the Hackberry unconformity indicates that growth of the Big Hill salt dome occurred prior to the close of Frio time, and that the crest of the dome was north of the present-day salt spine. This map also suggests the presence of a buried, down-to-the-coast growth fault which traverses the western flank of Big Hill field but which does not intersect any wells. Pressure-performance histories of two reservoirs and of two wells producing from other reservoirs are shown graphically in order to illustrate the problems involved in explaining wells that are in pressure communication. Four gas-fluid contacts in a continuous Marginulina sandstone reservoir differ in elevation by 600± ft. These original gas-fluid contacts were established by the migration of hydrocarbons into a complexly faulted area. Accumulation of oil downdip from these gas-fluid contacts can be explained reasonably in terms of gravity-segregation effects.",
    url = "https://doi.org/10.1306/a66337d4-16c0-11d7-8645000102c1865d",
    doi = "10.1306/a66337d4-16c0-11d7-8645000102c1865d",
    openalex = "W2270779054"
}

ABSTRACT A study of available subsurface data from wells drilled in the South Texas Counties of Aransas, Nueces, Refugio, and San Patricio discloses the presence of a barrier bar system in the Frio formation (Oligocene in age) which is easily divisible into three distinct depositional environments. With the termination of the major Vicksburg transgression, the seas began their slow withdrawal and deposition of Frio clastics commenced. Within this regressive framework of the Frio, a massive sand bar developed which is analogous to the present day Padre-Mustang-St. Joseph-Matagorda Island complex. These Frio bar sands were transported by longshore currents from an area to the southwest where extensive deltas were being built by the ancestral Rio Grande River. Within the Frio bar system continental shelf, bar, and lagoonal environments are recognizable. Prolific production has been established in sands occurring in each of these environments. The success of future exploration within the Frio is largely contingent upon a thorough understanding of the depositional framework of this Frio barrier bar system.

@article{doi1013065d25b47916c111d78645000102c1865d,
    author = "Boyd, Don R. and Dyer, Byron F.",
    title = "Frio Barrier Bar System of South Texas",
    year = "1966",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT A study of available subsurface data from wells drilled in the South Texas Counties of Aransas, Nueces, Refugio, and San Patricio discloses the presence of a barrier bar system in the Frio formation (Oligocene in age) which is easily divisible into three distinct depositional environments. With the termination of the major Vicksburg transgression, the seas began their slow withdrawal and deposition of Frio clastics commenced. Within this regressive framework of the Frio, a massive sand bar developed which is analogous to the present day Padre-Mustang-St. Joseph-Matagorda Island complex. These Frio bar sands were transported by longshore currents from an area to the southwest where extensive deltas were being built by the ancestral Rio Grande River. Within the Frio bar system continental shelf, bar, and lagoonal environments are recognizable. Prolific production has been established in sands occurring in each of these environments. The success of future exploration within the Frio is largely contingent upon a thorough understanding of the depositional framework of this Frio barrier bar system.",
    url = "https://doi.org/10.1306/5d25b479-16c1-11d7-8645000102c1865d",
    doi = "10.1306/5d25b479-16c1-11d7-8645000102c1865d",
    openalex = "W2113372090",
    references = "doi1013060bda5c2a16bd11d78645000102c1865d, openalexw1565983386"
}

Abstract The Day dome, 1 mi west of Madisonville, Madison County, Texas, is in the southerly extension of the East Texas basin. Caprock (anhydrite) is present at an average depth of 2,600 ft and rock salt at a depth of about 3,100 ft. The dome was formed at the northern end of a NNW-SSE-trending, troughlike depression. This trough, about 12-13 mi long, is flanked on each side by a ridge, the Madisonville field being on the western one. The sedimentary beds covering the salt core were uplifted slightly, but the roof later collapsed and now forms a local central depression on top of the salt dome. The sedimentary beds on the flanks of the dome show very little or no upturn (drag) against the salt core; this fact seems to be associated with the mode of salt emplacement. The geologic setting suggests that the present trough formerly was occupied by a salt anticline which apparently furnished the salt for the formation of the Day dome. To explain the absence of drag in the flanking sedimentary beds and the presence of a relatively thick anhydrite caprock, it is concluded that the growth of the dome was mainly by downbuilding and by extrusive flow of salt, the top of the salt core remaining continuously near the depositional surface, at least until the time of Wilcox deposition. As evidenced by the domed roof and also by the presence of a truncation unconformity formed before deposition of the Sparta sands, some minor upward growth took place after Wilcox deposition, but was slowed and finally stopped by increased and more rapid sedimentary loading, salt solution, and diminishing salt supply. The growth history of the Day dome appears to have been controlled to a considerable degree by the strength of the surrounding sedimentary rocks. The stronger, more competent Mesozoic formations surrounding the dome permitted very little intrusive movement of salt, and their presence seems to explain the absence of drag.

@article{doi1013065d25c85b16c111d78645000102c1865d,
    author = "Bornhauser, Max",
    title = "Geology of Day Dome (Madison County, Texas)—A Study of Salt Emplacement",
    year = "1969",
    journal = "AAPG Bulletin",
    abstract = "Abstract The Day dome, 1 mi west of Madisonville, Madison County, Texas, is in the southerly extension of the East Texas basin. Caprock (anhydrite) is present at an average depth of 2,600 ft and rock salt at a depth of about 3,100 ft. The dome was formed at the northern end of a NNW-SSE-trending, troughlike depression. This trough, about 12-13 mi long, is flanked on each side by a ridge, the Madisonville field being on the western one. The sedimentary beds covering the salt core were uplifted slightly, but the roof later collapsed and now forms a local central depression on top of the salt dome. The sedimentary beds on the flanks of the dome show very little or no upturn (drag) against the salt core; this fact seems to be associated with the mode of salt emplacement. The geologic setting suggests that the present trough formerly was occupied by a salt anticline which apparently furnished the salt for the formation of the Day dome. To explain the absence of drag in the flanking sedimentary beds and the presence of a relatively thick anhydrite caprock, it is concluded that the growth of the dome was mainly by downbuilding and by extrusive flow of salt, the top of the salt core remaining continuously near the depositional surface, at least until the time of Wilcox deposition. As evidenced by the domed roof and also by the presence of a truncation unconformity formed before deposition of the Sparta sands, some minor upward growth took place after Wilcox deposition, but was slowed and finally stopped by increased and more rapid sedimentary loading, salt solution, and diminishing salt supply. The growth history of the Day dome appears to have been controlled to a considerable degree by the strength of the surrounding sedimentary rocks. The stronger, more competent Mesozoic formations surrounding the dome permitted very little intrusive movement of salt, and their presence seems to explain the absence of drag.",
    url = "https://doi.org/10.1306/5d25c85b-16c1-11d7-8645000102c1865d",
    doi = "10.1306/5d25c85b-16c1-11d7-8645000102c1865d",
    openalex = "W2018923972",
    references = "bornhauser1960depositional, doi10119011439861, doi1013060bda5a8316bd11d78645000102c1865d, doi1013060bda5cfc16bd11d78645000102c1865d, doi1013060bda61ca16bd11d78645000102c1865d, doi1013063d932b9c16b111d78645000102c1865d, doi1013065ceae2dd16bb11d78645000102c1865d, openalexw2259904668"
}

@article{dgbebout1978deltaic,
    author = "D. G. Bebout, R. G. Loucks",
    title = "Deltaic Depositional Style in Salt-Withdrawal Basin, Frio Formation, Brazoria County, Texas: ABSTRACT",
    year = "1978",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/c1ea48dd-16c9-11d7-8645000102c1865d",
    doi = "10.1306/c1ea48dd-16c9-11d7-8645000102c1865d",
    openalex = "W2327269921",
    volume = "62"
}

Progressive burial diagenesis of the Oligocene Frio Formation in Brazoria County, Texas, has resulted in extensive reaction between pore fluids and sediment in a major shift toward water/rock equilibrium. Carbon and oxygen isotopic data, combined with fluid isotopic data from the literature, indicate that quartz cement formed at 75 to 80°C and kaolinite at approximately 100°C. The zone of most rapid albitization is near 150°C. Authigenic carbonates formed over a wide range of temperatures, and those within the peak zone of hydrocarbon generation are depleted in 13C. At depths shallower than approximately 2,600 m, quartz and carbonate cementation in primary intergranular pore spaces (passive diagenesis) dominated. Below 2,600 m, within the geopressured zone, reaction of detrital components (active diagenesis) is the major process. Organic maturation, albitization, and the transition of smectite to illite are the processes that contribute most of the components required for precipitation of cements. Quartz cementation occurred quite early in the burial history of the Frio (beginning at approximately 1,500 m of burial), when rates of fluid expulsion were at a maximum and when little of the Frio sandstone section had reached the zone of albitization.

@article{milliken1981history,
    author = "Milliken, K. L. and Land, L. S. and Loucks, R. G.",
    title = "History of Burial Diagenesis Determined from Isotopic Geochemistry, Frio Formation, Brazoria County, Texas",
    year = "1981",
    journal = "AAPG Bulletin",
    abstract = "Progressive burial diagenesis of the Oligocene Frio Formation in Brazoria County, Texas, has resulted in extensive reaction between pore fluids and sediment in a major shift toward water/rock equilibrium. Carbon and oxygen isotopic data, combined with fluid isotopic data from the literature, indicate that quartz cement formed at 75 to 80°C and kaolinite at approximately 100°C. The zone of most rapid albitization is near 150°C. Authigenic carbonates formed over a wide range of temperatures, and those within the peak zone of hydrocarbon generation are depleted in 13C. At depths shallower than approximately 2,600 m, quartz and carbonate cementation in primary intergranular pore spaces (passive diagenesis) dominated. Below 2,600 m, within the geopressured zone, reaction of detrital components (active diagenesis) is the major process. Organic maturation, albitization, and the transition of smectite to illite are the processes that contribute most of the components required for precipitation of cements. Quartz cementation occurred quite early in the burial history of the Frio (beginning at approximately 1,500 m of burial), when rates of fluid expulsion were at a maximum and when little of the Frio sandstone section had reached the zone of albitization.",
    url = "https://doi.org/10.1306/03b59558-16d1-11d7-8645000102c1865d",
    doi = "10.1306/03b59558-16d1-11d7-8645000102c1865d",
    number = "8",
    openalex = "W2124135935",
    pages = "1397-1413",
    volume = "65",
    references = "doi1010160016703769901781, doi101029jz071i016p03869, doi101038142234b0, doi10106311747785, doi10113000167606197687725mobmoa20co2, doi101306212f76bc2b2411d78648000102c1865d, doi10130683d9142516c711d78645000102c1865d, doi101346ccmn19700180306, doi102110pec79260175, doi102110pec80280087"
}

ABSTRACT The Frio Formation (Oligocene-Miocene) is one of the major Tertiary progradational wedges of the Texas Gulf coastal plain and has yielded nearly 6 billion bbl of oil and 60 tcf of gas. The Frio, and its updip equivalent, the Catahoula Formation, consists of deposits of two large fluvial and associated deltaic systems, centered in the Houston and Rio Grande embayments. Structural history in the Houston embayment is dominated by syndepositional deformation of underlying Jurassic salt; mobilization of thick, undercompacted prodelta and slope muds characterized the tectonic evolution of the deltaic sequence in the Rio Grande embayment. These two major deltaic depocenters are separated by a vertically stacked; strike-parallel coastal barrier and strand-plain system. Underlying, interbedded, and transgressive shelf, prodelta, and continental slope mudstone sequences provide principal source and sealing facies. Sparse organic geochemical data, regional thermal gradients, and distribution patterns of hydrocarbons show that large volumes of oil and gas have likely been generated within and effectively expulsed upward and landward from thermally mature, normally to moderately undercompacted sequences of bounding mudstone facies. All Frio depositional systems contain major, geologically defined, hydrocarbon-producing plays. Oil and gas field productivity data show a log normal frequency distribution for all but the largest fields. Per volume productivity, production styles, and types of hydrocarbons within each of the ten recognized plays reflect available source rock types, differing thermal and compaction histories, and variable reservoir and trap configurations that characterize each depositional system. Systematic distribution patterns of both physical and chemical properties of produced hydrocarbons can be related to source facies, regional thermal regime, and post generation modification by (1) continued maturation, thermal cracking, and deasphalting, (2) migration and attendant chromatographic separation, and (3) bacterial alteration.

@article{doi10130603b5a2f516d111d78645000102c1865d,
    author = "Galloway, William E. and Hobday, David K. and Magara, Kinji",
    title = "Frio Formation of Texas Gulf Coastal Plain: Depositional Systems, Structural Framework, and Hydrocarbon Distribution",
    year = "1982",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The Frio Formation (Oligocene-Miocene) is one of the major Tertiary progradational wedges of the Texas Gulf coastal plain and has yielded nearly 6 billion bbl of oil and 60 tcf of gas. The Frio, and its updip equivalent, the Catahoula Formation, consists of deposits of two large fluvial and associated deltaic systems, centered in the Houston and Rio Grande embayments. Structural history in the Houston embayment is dominated by syndepositional deformation of underlying Jurassic salt; mobilization of thick, undercompacted prodelta and slope muds characterized the tectonic evolution of the deltaic sequence in the Rio Grande embayment. These two major deltaic depocenters are separated by a vertically stacked; strike-parallel coastal barrier and strand-plain system. Underlying, interbedded, and transgressive shelf, prodelta, and continental slope mudstone sequences provide principal source and sealing facies. Sparse organic geochemical data, regional thermal gradients, and distribution patterns of hydrocarbons show that large volumes of oil and gas have likely been generated within and effectively expulsed upward and landward from thermally mature, normally to moderately undercompacted sequences of bounding mudstone facies. All Frio depositional systems contain major, geologically defined, hydrocarbon-producing plays. Oil and gas field productivity data show a log normal frequency distribution for all but the largest fields. Per volume productivity, production styles, and types of hydrocarbons within each of the ten recognized plays reflect available source rock types, differing thermal and compaction histories, and variable reservoir and trap configurations that characterize each depositional system. Systematic distribution patterns of both physical and chemical properties of produced hydrocarbons can be related to source facies, regional thermal regime, and post generation modification by (1) continued maturation, thermal cracking, and deasphalting, (2) migration and attendant chromatographic separation, and (3) bacterial alteration.",
    url = "https://doi.org/10.1306/03b5a2f5-16d1-11d7-8645000102c1865d",
    doi = "10.1306/03b5a2f5-16d1-11d7-8645000102c1865d",
    openalex = "W2105289954",
    references = "doi1010079783642964466, doi1010160016703780901404, doi101111j174754571980tb00707x, doi1013065ceadeb716bb11d78645000102c1865d, doi10130683d90e9416c711d78645000102c1865d, doi101306c1ea47ed16c911d78645000102c1865d, doi101306c1ea525616c911d78645000102c1865d, doi101306ce15408, openalexw1497775251, openalexw1526438593, openalexw1849800232"
}

@article{freed1982clay,
    author = "Freed, Robert L.",
    title = "Clay Mineralogy and Depositional History of Frio Formation in Two Geopressured Wells, Brazoria County, Texas: ABSTRACT",
    year = "1982",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/03b5a836-16d1-11d7-8645000102c1865d",
    doi = "10.1306/03b5a836-16d1-11d7-8645000102c1865d",
    openalex = "W1993469805",
    volume = "66"
}

The Upper Jurassic Haynesville Formation in Teague Townsite Field, Freestone County, Texas, consists of grainy limestones, muddy limestones, shales, and quartz conglomerates. Constituent grains in the limestones are primarily non-skeletal with ooids being the most common grain type. Composition and textural data from petrographic studies were grouped into seven microfacies. These microfacies represent three depositional environments: (1) tidal bar, (2) open marine, and (3) restricted marine. The distribution of these environments was controlled by contemporaneous salt movement. A major shoaling upwards sequence is present in the Haynesville Formation. Nine smaller, local cycles are also present; these local cycles were probably caused by intermittent salt movement during deposition. Four major diagenetic environments are recognized: (1) marine phreatic, (2) mixed or brackish phreatic, (3) meteoric phreatic, and (4) subsurface environments. Dissolution of ooids in the meteoric phreatic environment created very fine, intragranular porosity in oolite grainstones. Leached zones occur at the crests of the upper shoaling cycles. Virtually all intergranular porosity has been filled by subsurface coarse, mosaic spar cement. Production is from the intragranular porosity created by early meteoric leaching.

@incollection{faucette1984depositional,
    author = "FAUCETTE, ROBERT C. and AHR, WAYNE M.",
    title = "DEPOSITIONAL AND DIAGENETIC HISTORY OF UPPER JURASSIC HAYNESVILLE FORMATION, TEAGUE TOWNSITE FIELD, FREESTONE COUNTY, TEXAS",
    year = "1984",
    booktitle = "The Jurassic of the Gulf Rim",
    abstract = "The Upper Jurassic Haynesville Formation in Teague Townsite Field, Freestone County, Texas, consists of grainy limestones, muddy limestones, shales, and quartz conglomerates. Constituent grains in the limestones are primarily non-skeletal with ooids being the most common grain type. Composition and textural data from petrographic studies were grouped into seven microfacies. These microfacies represent three depositional environments: (1) tidal bar, (2) open marine, and (3) restricted marine. The distribution of these environments was controlled by contemporaneous salt movement. A major shoaling upwards sequence is present in the Haynesville Formation. Nine smaller, local cycles are also present; these local cycles were probably caused by intermittent salt movement during deposition. Four major diagenetic environments are recognized: (1) marine phreatic, (2) mixed or brackish phreatic, (3) meteoric phreatic, and (4) subsurface environments. Dissolution of ooids in the meteoric phreatic environment created very fine, intragranular porosity in oolite grainstones. Leached zones occur at the crests of the upper shoaling cycles. Virtually all intergranular porosity has been filled by subsurface coarse, mosaic spar cement. Production is from the intragranular porosity created by early meteoric leaching.",
    url = "https://doi.org/10.5724/gcs.84.03.0103",
    doi = "10.5724/gcs.84.03.0103",
    openalex = "W2271998934",
    pages = "103-120",
    references = "doi1013062f918a6316ce11d78645000102c1865d, doi1013062f91941d16ce11d78645000102c1865d, doi1013062f91999516ce11d78645000102c1865d, openalexw1575605242, openalexw1834345359"
}

ABSTRACT Gas and condensate production at the North Sabine Lake field is from sands of the Hackberry wedge of the Oligocene Frio Formation. These lower Hackberry sands were deposited in a preexisting submarine canyon. Multiple sand bodies are present, and five patterns of sand deposition are recognized from SP logs: (1) incised channel fill, (2) braided fan channel, (3) intermediate suprafan, (4) proximal suprafan, and (5) overbank. Although three faults surround the field, the primary trapping mechanism is stratigraphic. The development and production history of the field indicate that many small sand lenses have coalesced to form a single large reservoir; however, differences in permeability have caused variations in water influx and in the levels of gas-water contacts. Sand lenses that are not connected to the larger reservoir are of limited size and have produced small amounts of hydrocarbon. Development of the field has been complicated by casing damage probably caused by reservoir compaction.

@article{doi101306703c803d170711d78645000102c1865d,
    author = "Eubanks, L. G.",
    title = "North Sabine Lake Field: Complex Deposition and Reservoir Morphology of Lower Hackberry (Oligocene), Southwest Louisiana",
    year = "1987",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT Gas and condensate production at the North Sabine Lake field is from sands of the Hackberry wedge of the Oligocene Frio Formation. These lower Hackberry sands were deposited in a preexisting submarine canyon. Multiple sand bodies are present, and five patterns of sand deposition are recognized from SP logs: (1) incised channel fill, (2) braided fan channel, (3) intermediate suprafan, (4) proximal suprafan, and (5) overbank. Although three faults surround the field, the primary trapping mechanism is stratigraphic. The development and production history of the field indicate that many small sand lenses have coalesced to form a single large reservoir; however, differences in permeability have caused variations in water influx and in the levels of gas-water contacts. Sand lenses that are not connected to the larger reservoir are of limited size and have produced small amounts of hydrocarbon. Development of the field has been complicated by casing damage probably caused by reservoir compaction.",
    url = "https://doi.org/10.1306/703c803d-1707-11d7-8645000102c1865d",
    doi = "10.1306/703c803d-1707-11d7-8645000102c1865d",
    openalex = "W1986714408",
    references = "bornhauser1960depositional, doi1013062f9195d516ce11d78645000102c1865d, doi1013065d25c2d316c111d78645000102c1865d, doi101306a66337d416c011d78645000102c1865d, doi101306c1ea4f7c16c911d78645000102c1865d, doi1021183479ms, doi1023867gc8407d, openalexw1490157941, openalexw1526438593, openalexw2601390057"
}

@article{mazzullo1987stratigraphy,
    author = "Mazzullo, Louis J.",
    title = "Stratigraphy and Depositional History, Bone Spring Formation, Lea County, New Mexico: ABSTRACT",
    year = "1987",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/94886e20-1704-11d7-8645000102c1865d",
    doi = "10.1306/94886e20-1704-11d7-8645000102c1865d",
    openalex = "W2085067229",
    volume = "71"
}

ABSTRACT The lower Oligocene Vicksburg Formation of the Gulf Coastal plain contains major petroleum reservoirs in the Rio Grande embayment and is an economically viable target in other areas of Texas. Knowledge of the distribution of Vicksburg depositional systems is essential to understanding sandstone concentrations and, therefore, is fundamental to effective exploration and production of the Vicksburg section. The depositional setting of the Vicksburg reservoirs, their position in a sequence stratigraphic framework, and the influence these factors have on the petroleum geology of the Vicksburg are the focus of this paper. Surface and subsurface geological and geophysical data provided the framework for an analysis of the depositional systems and the petroleum geology of the Vicksburg. The two primary Texas Vicksburg depocenters, the Rio Grande embayment and the Houston embayment, are separated by the San Marcos arch, a deep-rooted structural nose. Within the embayments, sand-rich deltaic complexes merged along strike with barrier/strand plains. Contemporaneous growth faulting controlled depositional patterns of shelf-edge deltas in the Rio Grande embayment, but had only a minor effect on the configuration of the shelfal deltas in the Houston embayment. Smaller wave-dominated shelf delta complexes interspersed with barrier/strand plains extended across the San Marcos arch. Updip of these sandy paralic depocenters, fluvial systems traversed mud-rich coastal plain units. Seaward of the paralic systems, sand and mud deposits prograded across and built up over the relict Jackson shelf and shelf-margin shales. These depositional complexes are contained in the systems tracts of one eustatic (Exxon) sequence. Vicksburg production from each of the three structural regions of Texas is characterized by reservoirs from different systems tracts and of distinct, different depositional origins.

@article{doi101306bdff8f88171811d78645000102c1865d,
    author = "Combes, Janet M.",
    title = "The Vicksburg Formation of Texas: Depositional Systems Distribution, Sequence Stratigraphy, and Petroleum Geology",
    year = "1993",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The lower Oligocene Vicksburg Formation of the Gulf Coastal plain contains major petroleum reservoirs in the Rio Grande embayment and is an economically viable target in other areas of Texas. Knowledge of the distribution of Vicksburg depositional systems is essential to understanding sandstone concentrations and, therefore, is fundamental to effective exploration and production of the Vicksburg section. The depositional setting of the Vicksburg reservoirs, their position in a sequence stratigraphic framework, and the influence these factors have on the petroleum geology of the Vicksburg are the focus of this paper. Surface and subsurface geological and geophysical data provided the framework for an analysis of the depositional systems and the petroleum geology of the Vicksburg. The two primary Texas Vicksburg depocenters, the Rio Grande embayment and the Houston embayment, are separated by the San Marcos arch, a deep-rooted structural nose. Within the embayments, sand-rich deltaic complexes merged along strike with barrier/strand plains. Contemporaneous growth faulting controlled depositional patterns of shelf-edge deltas in the Rio Grande embayment, but had only a minor effect on the configuration of the shelfal deltas in the Houston embayment. Smaller wave-dominated shelf delta complexes interspersed with barrier/strand plains extended across the San Marcos arch. Updip of these sandy paralic depocenters, fluvial systems traversed mud-rich coastal plain units. Seaward of the paralic systems, sand and mud deposits prograded across and built up over the relict Jackson shelf and shelf-margin shales. These depositional complexes are contained in the systems tracts of one eustatic (Exxon) sequence. Vicksburg production from each of the three structural regions of Texas is characterized by reservoirs from different systems tracts and of distinct, different depositional origins.",
    url = "https://doi.org/10.1306/bdff8f88-1718-11d7-8645000102c1865d",
    doi = "10.1306/bdff8f88-1718-11d7-8645000102c1865d",
    openalex = "W2001605075",
    references = "doi1010079781468401707, doi101029pa002i001p00001, doi10113000917613198614535scaia20co2, doi10130603b5a2f516d111d78645000102c1865d, openalexw1497775251, openalexw1599441881, openalexw1603938237, openalexw1604095676, openalexw1907683511, openalexw2232990748"
}

@article{djoebenson1996depositional,
    author = "D. Joe Benson, Lisa M. Pultz, D. D.",
    title = "Depositional History of the Smackover Formation, Appleton Field, Escambia County, Alabama: ABSTRACT",
    year = "1996",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/64eda4ec-1724-11d7-8645000102c1865d",
    doi = "10.1306/64eda4ec-1724-11d7-8645000102c1865d",
    openalex = "W2166413638",
    volume = "80"
}

Abstract A Geographic Information System (GIS) database incorporating information from 241 publications, theses, and dissertations; well logs and paleontologic reports; and interpreted University of Texas Institute for Geophysics (UTIG) deep-basin seismic lines was used to map and interpret 18 basinwide genetic stratigraphic sequences that form the Gulf of Mexico basin Cenozoic fill. Eight principal extrabasinal fluvial axes provided the bulk of the sediment infill in the basin. First-order temporal and spatial use of these axes reflects four continent-scale phases of crustal uplift. Abundant sediment supply has prograded the northern and northwestern basin margin 150 to 180 mi (240 to 290 km) from its inherited Cretaceous position. Margin outbuilding has been locally and briefly interrupted by hypersubsidence due to salt withdrawal and mass wasting. Three depositional systems tracts characterize Cenozoic genetic sequences: (1) fluvial -> delta -> delta-fed apron, (2) coastal plain -> shore zone -> shelf -> shelf-fed apron, and (3) delta flank -> submarine fan. One or more examples of the fluvial -> delta -> delta-fed apron systems tract occur in each of the major genetic sequences. Immense volumes of sand have bypassed the shelf margin to be deposited in slope and base-of-slope systems, primarily within fluvial -> delta -> delta-fed apron system tracts, during all major Paleogene and Neogene depositional episodes. Deposition and preservation of volumetrically significant coastal plain -> shore zone -> shelf -> shelf-fed apron tracts is typical of Paleogene through Miocene depositional episodes only. Fan system origin was commonly associated with major continental margin failures, but large submarine canyons occur mainly in Pleistocene sequences. Thick, potential reservoir sand bodies occur in offlapping delta-fed slope and subjacent basin floor aprons, in autochthonous slope aprons and related infills of slide scars and canyon cuts, and in submarine fans.

@article{doi1013068626c37f173b11d78645000102c1865d,
    author = "Galloway, William E. and Ganey-Curry, Patricia and Li, Xiang and Buffler, Richard T.",
    title = "Cenozoic Depositional History of the Gulf of Mexico Basin",
    year = "2000",
    journal = "AAPG Bulletin",
    abstract = "Abstract A Geographic Information System (GIS) database incorporating information from 241 publications, theses, and dissertations; well logs and paleontologic reports; and interpreted University of Texas Institute for Geophysics (UTIG) deep-basin seismic lines was used to map and interpret 18 basinwide genetic stratigraphic sequences that form the Gulf of Mexico basin Cenozoic fill. Eight principal extrabasinal fluvial axes provided the bulk of the sediment infill in the basin. First-order temporal and spatial use of these axes reflects four continent-scale phases of crustal uplift. Abundant sediment supply has prograded the northern and northwestern basin margin 150 to 180 mi (240 to 290 km) from its inherited Cretaceous position. Margin outbuilding has been locally and briefly interrupted by hypersubsidence due to salt withdrawal and mass wasting. Three depositional systems tracts characterize Cenozoic genetic sequences: (1) fluvial -\> delta -\> delta-fed apron, (2) coastal plain -\> shore zone -\> shelf -\> shelf-fed apron, and (3) delta flank -\> submarine fan. One or more examples of the fluvial -\> delta -\> delta-fed apron systems tract occur in each of the major genetic sequences. Immense volumes of sand have bypassed the shelf margin to be deposited in slope and base-of-slope systems, primarily within fluvial -\> delta -\> delta-fed apron system tracts, during all major Paleogene and Neogene depositional episodes. Deposition and preservation of volumetrically significant coastal plain -\> shore zone -\> shelf -\> shelf-fed apron tracts is typical of Paleogene through Miocene depositional episodes only. Fan system origin was commonly associated with major continental margin failures, but large submarine canyons occur mainly in Pleistocene sequences. Thick, potential reservoir sand bodies occur in offlapping delta-fed slope and subjacent basin floor aprons, in autochthonous slope aprons and related infills of slide scars and canyon cuts, and in submarine fans.",
    url = "https://doi.org/10.1306/8626c37f-173b-11d7-8645000102c1865d",
    doi = "10.1306/8626c37f-173b-11d7-8645000102c1865d",
    openalex = "W2105082865",
    references = "caughey1981deltaic, doi10100797814684827687, doi1010079783642610189, doi1010160025322771900533, doi101086629710, doi1011300091761319930210483nagmhf23co2, doi101130dnaggnaj245, doi1013060c9b2321171011d78645000102c1865d, doi1013061d9bc5bb172d11d78645000102c1865d, doi1013061d9bc5d9172d11d78645000102c1865d, doi101306703c9afa170711d78645000102c1865d, doi101306bdff8876171811d78645000102c1865d, doi101306bdff8f88171811d78645000102c1865d, doi102110pec95040129, doi105724gcs84050109, openalexw1599441881"
}

ABSTRACT: Brittle deformation, together with grain rearrangement and ductile grain deformation, is a key mechanism of compaction in sandstones. Quartz cementation, by virtue of its impact on sandstone mechanical properties, is expected to affect the compaction progress by these various mechanisms. Sandstone samples of different ages and compositions, taken from two basins with contrasting burial histories, are used to quantify the relationship between brittle deformation and quartz cementation in the context of burial compaction. Exponential trends of increasing deformation by microfracturing are observed in both the lithic-rich Frio Formation from the Gulf of Mexico basin (r2 5 0.81) and in the quartz-rich Mount Simon Formation from the Il-linois basin (r2 5 0.78). The two formations contrast in terms of the observed rate of grain fracture increase with depth. A larger number of quartz grains in the Mount Simon Formation undergo fracturing at shallow burial (, 2 km) compared to the Frio Formation, whereas at

@article{doi101306051003731007,
    author = "Makowitz, Astrid and Milliken, K.L.",
    title = "Quantification of Brittle Deformation in Burial Compaction, Frio and Mount Simon Formation Sandstones",
    year = "2003",
    journal = "Journal of Sedimentary Research",
    abstract = "ABSTRACT: Brittle deformation, together with grain rearrangement and ductile grain deformation, is a key mechanism of compaction in sandstones. Quartz cementation, by virtue of its impact on sandstone mechanical properties, is expected to affect the compaction progress by these various mechanisms. Sandstone samples of different ages and compositions, taken from two basins with contrasting burial histories, are used to quantify the relationship between brittle deformation and quartz cementation in the context of burial compaction. Exponential trends of increasing deformation by microfracturing are observed in both the lithic-rich Frio Formation from the Gulf of Mexico basin (r2 5 0.81) and in the quartz-rich Mount Simon Formation from the Il-linois basin (r2 5 0.78). The two formations contrast in terms of the observed rate of grain fracture increase with depth. A larger number of quartz grains in the Mount Simon Formation undergo fracturing at shallow burial (, 2 km) compared to the Frio Formation, whereas at",
    url = "https://doi.org/10.1306/051003731007",
    doi = "10.1306/051003731007",
    openalex = "W2143266529",
    references = "doi10130603b5a2f516d111d78645000102c1865d"
}

Abstract A detailed analysis of Oligocene Frio Formation intraslope, growth-faulted subbasins in the Corpus Christi, Texas, area indicates that deposition during relative lowstands of sea level was the main initiator, or trigger, of growth faulting. Lowstand depocenters on the low-gradient, upper continental slope comprising basin-floor fan facies, slope-fan systems, and prograding lowstand delta systems exerted sufficient gravity stress to trigger major sections of outer shelf and upper slope strata to fail and move basinward. The faults sole out deep in the basin, and rotation of hanging-wall blocks mobilized deep-water muds and forced the mud basinward and upward to form mud (shale) ridges that constitute the basinward flank of intraslope subbasins overlying footwall fault blocks. Sedimentation associated with third-order relative falls of sea level produced load stress that triggered a major regional syndepositional growth-fault system. Subbasins on the downthrown side of each arcuate fault segment that constitute a regional fault system are filled during the lowstands of sea level. Consequently, genetically similar but noncontemporaneous lowstand depositional systems filled each successive growth-faulted subbasin trend. The subbasin stratigraphy becomes younger basinward because the subbasin development and fill process extended the Frio shelf edge stepwise into the Oligocene Gulf of Mexico Basin, coinciding with relative third-order sea level cycles. The subbasins have been prolific petroleum targets for decades and are now the focus of prospecting for deep gas. Lowstand sandstones are principal reservoirs, and synsedimentary tectonics produced anticlinal and fault traps and associated stratigraphic pinch-out traps on the flanks of the structures. Understanding the origin of the faulted subbasins and their chronostratigraphic relationships and depositional processes provides a perspective that can improve deep gas exploration.

@article{doi10130607010404023,
    author = "Brown, L. Frank and Loucks, Robert G. and Treviño, Ramón and Hammes, Ursula",
    title = "Understanding growth-faulted, intraslope subbasins by applying sequence-stratigraphic principles: Examples from the south Texas Oligocene Frio Formation",
    year = "2004",
    journal = "AAPG Bulletin",
    abstract = "Abstract A detailed analysis of Oligocene Frio Formation intraslope, growth-faulted subbasins in the Corpus Christi, Texas, area indicates that deposition during relative lowstands of sea level was the main initiator, or trigger, of growth faulting. Lowstand depocenters on the low-gradient, upper continental slope comprising basin-floor fan facies, slope-fan systems, and prograding lowstand delta systems exerted sufficient gravity stress to trigger major sections of outer shelf and upper slope strata to fail and move basinward. The faults sole out deep in the basin, and rotation of hanging-wall blocks mobilized deep-water muds and forced the mud basinward and upward to form mud (shale) ridges that constitute the basinward flank of intraslope subbasins overlying footwall fault blocks. Sedimentation associated with third-order relative falls of sea level produced load stress that triggered a major regional syndepositional growth-fault system. Subbasins on the downthrown side of each arcuate fault segment that constitute a regional fault system are filled during the lowstands of sea level. Consequently, genetically similar but noncontemporaneous lowstand depositional systems filled each successive growth-faulted subbasin trend. The subbasin stratigraphy becomes younger basinward because the subbasin development and fill process extended the Frio shelf edge stepwise into the Oligocene Gulf of Mexico Basin, coinciding with relative third-order sea level cycles. The subbasins have been prolific petroleum targets for decades and are now the focus of prospecting for deep gas. Lowstand sandstones are principal reservoirs, and synsedimentary tectonics produced anticlinal and fault traps and associated stratigraphic pinch-out traps on the flanks of the structures. Understanding the origin of the faulted subbasins and their chronostratigraphic relationships and depositional processes provides a perspective that can improve deep gas exploration.",
    url = "https://doi.org/10.1306/07010404023",
    doi = "10.1306/07010404023",
    openalex = "W4254427364",
    references = "doi10102992jb01090, doi10102994jb03098, doi101126science23547931156, doi101306703c9af5170711d78645000102c1865d, doi101306703c9afa170711d78645000102c1865d, doi102110pec83060139, doi102110pec88010125, doi102110pec95040129, doi105724gcs85040263, doi105724gcs90110321"
}

Abstract We integrated well logs and three-dimensional seismic data to describe a wedge of deformed shallow Frio rocks lying above a major bed-parallel decollement within the upper Oligocene Frio Formation located between the Houston and Norias deltas on the south Texas Gulf Coast. Our analyses show that the identified deformed shallow Frio rocks can be divided into proximal clay-rich and low-permeability sandstones characterized by discontinuous, mounded, and chaotic seismic events; near-proximal, clay-poor, and high-permeability sandstones characterized by parallel to subparallel bedded seismic events; and distal sand-, silt-, and mudstones composed of a mix of proximal and near-proximal rocks. All of the deformed rocks are composed of acoustic-impedance materials that are lower than those of the undeformed shallow Frio and are underlain by low-velocity, overpressured, shale-rich rocks. The mechanism that triggered the collapse of the shallow Frio and subsequent development of mass-transport deposits is attributed to an uprising, overpressured, shale-rich high and the development of a shelf-edge listric fault. Proprietary biostratigraphic data show that the collapse of the shallow Frio in areas between the Houston and Norias deltas occurred between 27.5 and 25.3 Ma—approximately the same time as the Hackberry collapse in the Mississippi delta. In the proximal area, interpreted paleowater depths from biostratigraphic data based on benthic foraminifers range from 60 to 120 ft (20–40 m) in a shallow neritic environment. In contrast, the distal area lies in paleowater depths interpreted to be between 120 and 300 ft (40–90 m) in a middle neritic environment.

@article{doi10130609191110205,
    author = "Ogiesoba, Osareni C. and Hammes, Ursula",
    title = "Seismic interpretation of mass-transport deposits within the upper Oligocene Frio Formation, south Texas Gulf Coast",
    year = "2012",
    journal = "AAPG Bulletin",
    abstract = "Abstract We integrated well logs and three-dimensional seismic data to describe a wedge of deformed shallow Frio rocks lying above a major bed-parallel decollement within the upper Oligocene Frio Formation located between the Houston and Norias deltas on the south Texas Gulf Coast. Our analyses show that the identified deformed shallow Frio rocks can be divided into proximal clay-rich and low-permeability sandstones characterized by discontinuous, mounded, and chaotic seismic events; near-proximal, clay-poor, and high-permeability sandstones characterized by parallel to subparallel bedded seismic events; and distal sand-, silt-, and mudstones composed of a mix of proximal and near-proximal rocks. All of the deformed rocks are composed of acoustic-impedance materials that are lower than those of the undeformed shallow Frio and are underlain by low-velocity, overpressured, shale-rich rocks. The mechanism that triggered the collapse of the shallow Frio and subsequent development of mass-transport deposits is attributed to an uprising, overpressured, shale-rich high and the development of a shelf-edge listric fault. Proprietary biostratigraphic data show that the collapse of the shallow Frio in areas between the Houston and Norias deltas occurred between 27.5 and 25.3 Ma—approximately the same time as the Hackberry collapse in the Mississippi delta. In the proximal area, interpreted paleowater depths from biostratigraphic data based on benthic foraminifers range from 60 to 120 ft (20–40 m) in a shallow neritic environment. In contrast, the distal area lies in paleowater depths interpreted to be between 120 and 300 ft (40–90 m) in a middle neritic environment.",
    url = "https://doi.org/10.1306/09191110205",
    doi = "10.1306/09191110205",
    openalex = "W2160799835",
    references = "crossref1995cenozoic, doi101016002532278290086x, doi101111j13652117200700340x, doi10130602210605052, doi10130605150808014, doi10130607010404023, doi1013065d25c2d316c111d78645000102c1865d, doi1013068626c37f173b11d78645000102c1865d, doi101306bdff8876171811d78645000102c1865d, doi101306bdff8f88171811d78645000102c1865d, doi102110pec95040129, openalexw1910865362, paine1968stratigraphy"
}

@article{doi101016jmarpetgeo201309009,
    author = "Olariu, Mariana I. and Hammes, Ursula and Ambrose, William A.",
    title = "Depositional architecture of growth-fault related wave-dominated shelf edge deltas of the Oligocene Frio Formation in Corpus Christi Bay, Texas",
    year = "2013",
    journal = "Marine and Petroleum Geology",
    url = "https://doi.org/10.1016/j.marpetgeo.2013.09.009",
    doi = "10.1016/j.marpetgeo.2013.09.009",
    openalex = "W2066721347",
    references = "doi10130607010404023"
}

The Oligocene Frio and Anahuac Formations were assessed as part of the 2007 U.S. Geological Survey (USGS) assessment of Tertiary strata of the U.S. Gulf of Mexico Basin onshore and State waters. The Frio Formation, which consists of sand-rich fluvio-deltaic systems, has been one of the largest hydrocarbon producers from the Paleogene in the Gulf of Mexico. The Anahuac Formation, an extensive transgressive marine shale overlying the Frio Formation, contains deltaic and slope sandstones in Louisiana and Texas and carbonate rocks in the eastern Gulf of Mexico. In downdip areas of the Frio and Anahuac Formations, traps associated with faulted, rollover anticlines are common. Structural traps commonly occur in combination with stratigraphic traps. Faulted salt domes in the Frio and Anahuac Formations are present in the Houston embayment of Texas and in south Louisiana. In the Frio Formation, stratigraphic traps are found in fluvial, deltaic, barrier-bar, shelf, and strandplain systems. The USGS Tertiary Assessment Team defined a single, Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) for the Gulf Coast basin, based on previous studies and geochemical analysis of oils in the Gulf Coast basin. The primary source rocks for oil and gas within Cenozoic petroleum systems, including Frio Formation reservoirs, in the northern, onshore Gulf Coastal region consist of coal and shale rich in organic matter within the Wilcox Group (Paleocene–Eocene), with some contributions from the Sparta Sand of the Claiborne Group (Eocene). The Jurassic Smackover Formation and Cretaceous Eagle Ford Formation also may have contributed substantial petroleum to Cenozoic reservoirs. Modeling studies of thermal maturity by the USGS Tertiary Assessment Team indicate that downdip portions of the basal Wilcox Group reached sufficient thermal maturity to generate hydrocarbons by early Eocene; this early maturation is the result of rapid sediment accumulation in the early Tertiary, combined with the reaction kinetic parameters used in the models. A number of studies indicate that the migration of oil and gas in the Cenozoic Gulf of Mexico basin is primarily vertical, occurring along abundant growth faults associated with sediment deposition or along faults associated with salt domes. The USGS Tertiary assessment team developed a geologic model based on recurring regional-scale structural and depositional features in Paleogene strata to define assessment units (AUs). Three general areas, as described in the model, are found in each of the Paleogene stratigraphic intervals assessed: "Stable Shelf," "Expanded Fault," and "Slope and Basin Floor" zones. On the basis of this model, three AUs for the Frio Formation were defined: (1) the Frio Stable Shelf Oil and Gas AU, containing reservoirs with a mean depth of about 4,800 feet in normally pressured intervals; (2) the Frio Expanded Fault Zone Oil and Gas AU, containing reservoirs with a mean depth of about 9,000 feet in primarily overpressured intervals; and (3) the Frio Slope and Basin Floor Gas AU, which currently has no production but has potential for deep gas resources (>15,000 feet). AUs also were defined for the Hackberry trend, which consists of a slope facies stratigraphically in the middle part of the Frio Formation, and the Anahuac Formation. The Frio Basin Margin AU, an assessment unit extending to the outcrop of the Frio (or basal Miocene), was not quantitatively assessed because of its low potential for production. Two proprietary, commercially available databases containing field and well production information were used in the assessment. Estimates of undiscovered resources for the five AUs were based on a total of 1,734 reservoirs and 586,500 wells producing from the Frio and Anahuac Formations. Estimated total mean values of technically recoverable, undiscovered resources are 172 million barrels of oil (MMBO), 9.4 trillion cubic feet of natural gas (TCFG), and 542 million barrels of natural gas liquids for all of the Frio and Anahuac AUs. Of the five units assessed, the Frio Slope and Basin Floor Gas AU has the greatest potential for undiscovered gas resources, having an estimated mean of 5.6 TCFG. The Hackberry Oil and Gas AU shows the second highest potential for gas of the five units assessed, having an estimated mean of 1.8 TCFG. The largest undiscovered, conventional crude oil resource was estimated for the Frio Slope and Basin Floor Gas AU; the estimated mean for oil in this AU is 110 MMBO.

@article{doi103133ofr20131257,
    author = "Swanson, Sharon M. and Karlsen, Alexander W. and Valentine, Brett J.",
    title = "Geologic assessment of undiscovered oil and gas resources: Oligocene Frio and Anahuac Formations, United States Gulf of Mexico coastal plain and State waters",
    year = "2013",
    journal = "Antarctica A Keystone in a Changing World",
    abstract = {The Oligocene Frio and Anahuac Formations were assessed as part of the 2007 U.S. Geological Survey (USGS) assessment of Tertiary strata of the U.S. Gulf of Mexico Basin onshore and State waters. The Frio Formation, which consists of sand-rich fluvio-deltaic systems, has been one of the largest hydrocarbon producers from the Paleogene in the Gulf of Mexico. The Anahuac Formation, an extensive transgressive marine shale overlying the Frio Formation, contains deltaic and slope sandstones in Louisiana and Texas and carbonate rocks in the eastern Gulf of Mexico. In downdip areas of the Frio and Anahuac Formations, traps associated with faulted, rollover anticlines are common. Structural traps commonly occur in combination with stratigraphic traps. Faulted salt domes in the Frio and Anahuac Formations are present in the Houston embayment of Texas and in south Louisiana. In the Frio Formation, stratigraphic traps are found in fluvial, deltaic, barrier-bar, shelf, and strandplain systems. The USGS Tertiary Assessment Team defined a single, Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) for the Gulf Coast basin, based on previous studies and geochemical analysis of oils in the Gulf Coast basin. The primary source rocks for oil and gas within Cenozoic petroleum systems, including Frio Formation reservoirs, in the northern, onshore Gulf Coastal region consist of coal and shale rich in organic matter within the Wilcox Group (Paleocene–Eocene), with some contributions from the Sparta Sand of the Claiborne Group (Eocene). The Jurassic Smackover Formation and Cretaceous Eagle Ford Formation also may have contributed substantial petroleum to Cenozoic reservoirs. Modeling studies of thermal maturity by the USGS Tertiary Assessment Team indicate that downdip portions of the basal Wilcox Group reached sufficient thermal maturity to generate hydrocarbons by early Eocene; this early maturation is the result of rapid sediment accumulation in the early Tertiary, combined with the reaction kinetic parameters used in the models. A number of studies indicate that the migration of oil and gas in the Cenozoic Gulf of Mexico basin is primarily vertical, occurring along abundant growth faults associated with sediment deposition or along faults associated with salt domes. The USGS Tertiary assessment team developed a geologic model based on recurring regional-scale structural and depositional features in Paleogene strata to define assessment units (AUs). Three general areas, as described in the model, are found in each of the Paleogene stratigraphic intervals assessed: "Stable Shelf," "Expanded Fault," and "Slope and Basin Floor" zones. On the basis of this model, three AUs for the Frio Formation were defined: (1) the Frio Stable Shelf Oil and Gas AU, containing reservoirs with a mean depth of about 4,800 feet in normally pressured intervals; (2) the Frio Expanded Fault Zone Oil and Gas AU, containing reservoirs with a mean depth of about 9,000 feet in primarily overpressured intervals; and (3) the Frio Slope and Basin Floor Gas AU, which currently has no production but has potential for deep gas resources (>15,000 feet). AUs also were defined for the Hackberry trend, which consists of a slope facies stratigraphically in the middle part of the Frio Formation, and the Anahuac Formation. The Frio Basin Margin AU, an assessment unit extending to the outcrop of the Frio (or basal Miocene), was not quantitatively assessed because of its low potential for production. Two proprietary, commercially available databases containing field and well production information were used in the assessment. Estimates of undiscovered resources for the five AUs were based on a total of 1,734 reservoirs and 586,500 wells producing from the Frio and Anahuac Formations. Estimated total mean values of technically recoverable, undiscovered resources are 172 million barrels of oil (MMBO), 9.4 trillion cubic feet of natural gas (TCFG), and 542 million barrels of natural gas liquids for all of the Frio and Anahuac AUs. Of the five units assessed, the Frio Slope and Basin Floor Gas AU has the greatest potential for undiscovered gas resources, having an estimated mean of 5.6 TCFG. The Hackberry Oil and Gas AU shows the second highest potential for gas of the five units assessed, having an estimated mean of 1.8 TCFG. The largest undiscovered, conventional crude oil resource was estimated for the Frio Slope and Basin Floor Gas AU; the estimated mean for oil in this AU is 110 MMBO.},
    url = "https://doi.org/10.3133/ofr20131257",
    doi = "10.3133/ofr20131257",
    openalex = "W1528120486",
    references = "doi1010079783642878138, doi10130603b5a2f516d111d78645000102c1865d, doi10130607010404023, doi1013060bda5c2a16bd11d78645000102c1865d, doi101306703c803d170711d78645000102c1865d, doi1013068626c37f173b11d78645000102c1865d, doi101306bdff8876171811d78645000102c1865d, doi101306bdff8f88171811d78645000102c1865d, doi101306m60585, doi101306m60585c1, openalexw1565983386, openalexw1910865362, openalexw2271041924, openalexw2601390057"
}

ABSTRACT The Eagle Ford Formation has attracted considerable industry attention as a self-sourced unconventional shale reservoir. The productive interval in the Eagle Ford Formation is the transgressive systems tract, which contains parasequences whose lithologic content varies upward with increasing proportions of limestones. Optimum success in both exploration and production depends on the adequate characterization of fracture systems as a function of lithology. The outcrops present along US Highway 90 in Val Verde and Terrell Counties, Texas, provide considerable insight into the regional natural fracture system of the Eagle Ford Formation. Fracture-orientation analysis reveals two sets of conjugate hybrid shear fractures and two sets of regional fractures. Abutting relationships suggest that hybrid shear fractures formed first, followed by the thoroughgoing northeast-striking fracture set, and finally by a northwest-striking set, which tends to be confined to individual mechanical units. The orientation of these fractures suggests that they formed during post-Laramide stress relaxation and progressive exhumation. Spacing-frequency distribution analysis of the fracture population reveals a mature hypersaturated fracture system that likely formed at depth by overburden load and/or fluid pressure near maximum burial. Our results indicate that the Eagle Ford Formation displays a well-developed fracture network regionally distributed in the Val Verde Basin, and likely present in the productive Eagle Ford play. These observations provide evidence for pathways and vertical connectivity for potential fluid pathways throughout the Eagle Ford Formation.

@article{doi10130603151817323,
    author = "Gottardi, Raphaël and Mason, Shanna L.",
    title = "Characterization of the natural fracture system of the Eagle Ford Formation (Val Verde County, Texas)",
    year = "2018",
    journal = "AAPG Bulletin",
    abstract = "ABSTRACT The Eagle Ford Formation has attracted considerable industry attention as a self-sourced unconventional shale reservoir. The productive interval in the Eagle Ford Formation is the transgressive systems tract, which contains parasequences whose lithologic content varies upward with increasing proportions of limestones. Optimum success in both exploration and production depends on the adequate characterization of fracture systems as a function of lithology. The outcrops present along US Highway 90 in Val Verde and Terrell Counties, Texas, provide considerable insight into the regional natural fracture system of the Eagle Ford Formation. Fracture-orientation analysis reveals two sets of conjugate hybrid shear fractures and two sets of regional fractures. Abutting relationships suggest that hybrid shear fractures formed first, followed by the thoroughgoing northeast-striking fracture set, and finally by a northwest-striking set, which tends to be confined to individual mechanical units. The orientation of these fractures suggests that they formed during post-Laramide stress relaxation and progressive exhumation. Spacing-frequency distribution analysis of the fracture population reveals a mature hypersaturated fracture system that likely formed at depth by overburden load and/or fluid pressure near maximum burial. Our results indicate that the Eagle Ford Formation displays a well-developed fracture network regionally distributed in the Val Verde Basin, and likely present in the productive Eagle Ford play. These observations provide evidence for pathways and vertical connectivity for potential fluid pathways throughout the Eagle Ford Formation.",
    url = "https://doi.org/10.1306/03151817323",
    doi = "10.1306/03151817323",
    openalex = "W2793765921",
    references = "doi1013065d25c58f16c111d78645000102c1865d"
}

Recent advances in hydrocarbon exploration have been made in the Member Deng-2 marginal microbial mound-bank complex reservoirs of the Dengying Formation in the western Sichuan Basin, SW China, where the depositional process is regarded confusing. The microfacies, construction types, and depositional model of the Member Deng-2 marginal microbial mound-bank complex have been investigated using unmanned aerial vehicle photography, outcrop section investigation, thin section identification, and seismic reflections in the southwestern Sichuan Basin. The microbialite lithologic textures in this region include thrombolite, dendrolite, stromatolite, fenestral stromatolite, spongiostromata stone, oncolite, aggregated grainstone, and botryoidal grapestone. Based on the comprehensive analysis of “depositional fabrics–lithology–microfacies”, an association between a fore mound, mound framework, and back mound subfacies has been proposed based on water depth, current direction, energy level and lithologic assemblages. The microfacies of the mound base, mound core, mound flank, mound cap, and mound flat could be recognized among the mound framework subfacies. Two construction types of marginal microbial mound-bank complex have been determined based on deposition location, mound scale, migration direction, and sedimentary facies association. Type Jinkouhe microbial mound constructions (TJMMCs) develop along the windward margin owing to their proximity to the seaward subfacies fore mound, with a northeastwardly migrated microbial mound on top of the mud mound, exhibiting the characteristics of large-sized mounds and small-sized banks in the surrounding area. Type E'bian microbial mound constructions (TEMMCs) primarily occur on the leeward margin, resulting from the presence of onshore back mound subfacies, with the smaller southwestward migrated microbial mounds existing on a thicker microbial flat. The platform margin microbial mound depositional model can be correlated with certain lateral comparison profile and seismic reflection structures in the 2D seismic section, which can provide references for future worldwide exploration. Microbial mounds with larger buildups and thicker vertical reservoirs are typically targeted on the windward margin, while small-sized microbial mounds and flats with better lateral connections are typically focused on the leeward margin.

@article{doi101016jpetsci202312005,
    author = "Song, Jinmin and Jin, Xin and Luo, Zhong and Liu, Shugen and Liu, Shaobo and Ma, Xingzhi and Li, Zhiwu and Lu, Xuesong and Zhao, Lingli and Li, Keran and Ren, Jiaxin and Tian, Li-Zhou and Deng, Hao-Shuang",
    title = "Depositional model of the Member Deng-2 marginal microbial mound-bank complex of the Dengying Formation in the southwestern Sichuan Basin, SW China: Implications for the Ediacaran microbial mound construction and hydrocarbon exploration",
    year = "2023",
    journal = "Petroleum Science",
    abstract = "Recent advances in hydrocarbon exploration have been made in the Member Deng-2 marginal microbial mound-bank complex reservoirs of the Dengying Formation in the western Sichuan Basin, SW China, where the depositional process is regarded confusing. The microfacies, construction types, and depositional model of the Member Deng-2 marginal microbial mound-bank complex have been investigated using unmanned aerial vehicle photography, outcrop section investigation, thin section identification, and seismic reflections in the southwestern Sichuan Basin. The microbialite lithologic textures in this region include thrombolite, dendrolite, stromatolite, fenestral stromatolite, spongiostromata stone, oncolite, aggregated grainstone, and botryoidal grapestone. Based on the comprehensive analysis of “depositional fabrics–lithology–microfacies”, an association between a fore mound, mound framework, and back mound subfacies has been proposed based on water depth, current direction, energy level and lithologic assemblages. The microfacies of the mound base, mound core, mound flank, mound cap, and mound flat could be recognized among the mound framework subfacies. Two construction types of marginal microbial mound-bank complex have been determined based on deposition location, mound scale, migration direction, and sedimentary facies association. Type Jinkouhe microbial mound constructions (TJMMCs) develop along the windward margin owing to their proximity to the seaward subfacies fore mound, with a northeastwardly migrated microbial mound on top of the mud mound, exhibiting the characteristics of large-sized mounds and small-sized banks in the surrounding area. Type E'bian microbial mound constructions (TEMMCs) primarily occur on the leeward margin, resulting from the presence of onshore back mound subfacies, with the smaller southwestward migrated microbial mounds existing on a thicker microbial flat. The platform margin microbial mound depositional model can be correlated with certain lateral comparison profile and seismic reflection structures in the 2D seismic section, which can provide references for future worldwide exploration. Microbial mounds with larger buildups and thicker vertical reservoirs are typically targeted on the windward margin, while small-sized microbial mounds and flats with better lateral connections are typically focused on the leeward margin.",
    url = "https://doi.org/10.1016/j.petsci.2023.12.005",
    doi = "10.1016/j.petsci.2023.12.005",
    openalex = "W4389609682",
    references = "doi10130609092020054"
}