N. Rochelle-Bates, G. Calvès, M. Huuse, S. Schröder
Prospect B is one of the largest Cretaceous sag-phase buildups yet identified along the outer high of Namibia’s Atlantic volcanic-rifted margin. These enigmatic buildups constitute a potential new carbonate play offshore Namibia and South Africa. However, no unambiguous carbonate geometries have been reported to date, and they sit atop a highly volcanic sedimentary sequence. In the absence of well data, it is thus prudent to examine these buildups carefully using all available data and analogues, to test their carbonate versus igneous origin and therefore their potential as hydrocarbon reservoirs.This study used three-dimensional seismic data to extract detailed depositional information for Prospect B. The analysis included assessment of the buildup’s external morphology and internal seismic facies, measuring the dip and dip direction of inclined reflectors, making horizon slices, mapping internal surfaces onto which seismic attributes were extracted (root mean square, amplitude, spectral decomposition), and creating thickness maps to show buildup evolution through time. These data were then evaluated against known and published observations made on volcanic and carbonate systems (continental and marine). Architectural elements like vents, igneous flows, and complex clinoform geometries suggest that a large part of the buildup is likely volcanic in origin. Though it has carbonate-like features, no definitive carbonate geometries were identified. Thus, Prospect B is more likely to be dominated by igneous materials such as hyaloclastites. Contrary to existing interpretations, Prospect B and its equivalents probably represent a late, waning phase of regional volcanism and are an important bathymetric record of the South Atlantic’s formation.
B 号探矿区是纳米比亚大西洋火山断裂边缘外高地带迄今发现的最大白垩纪矢状相堆积物之一。这些神秘的堆积物构成了纳米比亚和南非近海潜在的新碳酸盐岩区。然而，迄今为止还没有明确的碳酸盐岩几何形状的报告，而且它们位于高度火山沉积序列之上。因此，在缺乏油井数据的情况下，谨慎的做法是利用所有可用的数据和类比资料仔细研究这些堆积层，以检验其碳酸盐岩和火成岩的起源，从而检验其作为碳氢化合物储层的潜力。分析包括评估堆积物的外部形态和内部地震面，测量倾斜反射体的倾角和倾角方向，制作地层切片，绘制提取地震属性（均方根、振幅、频谱分解）的内部表面，以及绘制厚度图以显示堆积物随时间的演变。然后，根据对火山和碳酸盐系统（大陆和海洋）的已知和公开观测结果对这些数据进行评估。喷口、火成岩流和复杂的崖状几何形状等建筑元素表明，大部分堆积物可能源于火山。虽然它具有类似碳酸盐岩的特征，但没有确定的碳酸盐岩几何形态。因此，探矿面 B 更有可能以火成岩物质（如透辉石）为主。与现有的解释相反，探矿面 B 及其等同物可能代表了区域火山活动的晚期、衰退阶段，是南大西洋形成的重要测深记录。
{"title":"Carbonate platform or volcanic mound? Seismic characterization of a synrift buildup along the outer high of the Lüderitz Basin, Namibia","authors":"N. Rochelle-Bates, G. Calvès, M. Huuse, S. Schröder","doi":"10.1306/12202220205","DOIUrl":"https://doi.org/10.1306/12202220205","url":null,"abstract":"Prospect B is one of the largest Cretaceous sag-phase buildups yet identified along the outer high of Namibia’s Atlantic volcanic-rifted margin. These enigmatic buildups constitute a potential new carbonate play offshore Namibia and South Africa. However, no unambiguous carbonate geometries have been reported to date, and they sit atop a highly volcanic sedimentary sequence. In the absence of well data, it is thus prudent to examine these buildups carefully using all available data and analogues, to test their carbonate versus igneous origin and therefore their potential as hydrocarbon reservoirs.This study used three-dimensional seismic data to extract detailed depositional information for Prospect B. The analysis included assessment of the buildup’s external morphology and internal seismic facies, measuring the dip and dip direction of inclined reflectors, making horizon slices, mapping internal surfaces onto which seismic attributes were extracted (root mean square, amplitude, spectral decomposition), and creating thickness maps to show buildup evolution through time. These data were then evaluated against known and published observations made on volcanic and carbonate systems (continental and marine). Architectural elements like vents, igneous flows, and complex clinoform geometries suggest that a large part of the buildup is likely volcanic in origin. Though it has carbonate-like features, no definitive carbonate geometries were identified. Thus, Prospect B is more likely to be dominated by igneous materials such as hyaloclastites. Contrary to existing interpretations, Prospect B and its equivalents probably represent a late, waning phase of regional volcanism and are an important bathymetric record of the South Atlantic’s formation.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"34 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139483679","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hydrodynamic salinity gradients occur in aquifers where lateral salinity changes are caused by regional water flow. Hydrodynamic salinity gradients are highly favorable for oil entrapment in areas where less-saline waters flow downdip to replace more-saline waters because the “tilt amplification factor” increases in updip areas where the oil–water contact tilt may exceed the regional structural dip and induce basinward oil displacement. This can concentrate oil by downdip remigration. Downdip barriers, such as monoclines, may be the dominant structural control. Composite hydrodynamic accumulations consist of oil-productive areas that may not be interconnected but have a common, hydrodynamically tilted, free-water level. They form in regions where the oil–water contact tilt is similar in magnitude and direction to the regional dip. In the southwestern part of the Williston Basin, structurally modified, composite hydrodynamic accumulations that lie within brackish-water to saline-water hydrodynamic salinity gradients occur in the Mississippian Madison Group and Ordovician Red River Formation reservoirs. These oil accumulations have average oil–water contact tilts that range from 22 to 80 ft/mi (4 to 15 m/km) toward the northeast. Individual composite oil accumulations can cover areas larger than 300 mi2 (777 km2) and hold at least 1.6 billion bbl of oil-in-place.
{"title":"Hydrocarbon trapping in hydrodynamic salinity gradients: Williston Basin case studies","authors":"David M. Petty","doi":"10.1306/02242322092","DOIUrl":"https://doi.org/10.1306/02242322092","url":null,"abstract":"Hydrodynamic salinity gradients occur in aquifers where lateral salinity changes are caused by regional water flow. Hydrodynamic salinity gradients are highly favorable for oil entrapment in areas where less-saline waters flow downdip to replace more-saline waters because the “tilt amplification factor” increases in updip areas where the oil–water contact tilt may exceed the regional structural dip and induce basinward oil displacement. This can concentrate oil by downdip remigration. Downdip barriers, such as monoclines, may be the dominant structural control. Composite hydrodynamic accumulations consist of oil-productive areas that may not be interconnected but have a common, hydrodynamically tilted, free-water level. They form in regions where the oil–water contact tilt is similar in magnitude and direction to the regional dip. In the southwestern part of the Williston Basin, structurally modified, composite hydrodynamic accumulations that lie within brackish-water to saline-water hydrodynamic salinity gradients occur in the Mississippian Madison Group and Ordovician Red River Formation reservoirs. These oil accumulations have average oil–water contact tilts that range from 22 to 80 ft/mi (4 to 15 m/km) toward the northeast. Individual composite oil accumulations can cover areas larger than 300 mi2 (777 km2) and hold at least 1.6 billion bbl of oil-in-place.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"33 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139507933","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Sebastian Ramiro-Ramirez, Athma R. Bhandari, Robert M. Reed, Peter B. Flemings
The drainage of low-permeability unconventional reservoirs is often interpreted to be controlled by hydraulic and natural fractures that drain a homogenous low-permeability mudstone. However, stratigraphic heterogeneity, which results in strong variations in permeability, may also play an important role. We demonstrate that thin dolomitized carbonate sediment gravity flow deposits are over 25 times more permeable on average than the volumetrically dominant mudstone that is the source of most of the oil in the upper Wolfcamp interval of the Delaware Basin. We conducted steady-state liquid (dodecane) permeability measurements in 30 horizontal core plugs from six upper Wolfcamp lithofacies. The dolomitized calcareous lithofacies have effective permeabilities to dodecane of up to 2000 nd, whereas the remaining mudstones, dolomudstones, and calcite-bearing lithofacies have permeabilities of less than 60 nd. We constructed a layered flow model to examine the role of high-permeability layers in drainage at the completion scale. Flow is focused through the permeable layer, resulting in upscaled permeabilities and production rates that are up to four times greater than a reservoir composed of only low-permeability strata. Our analysis shows the importance of understanding stratigraphy, permeability, and flow behavior at the thin-bed scale. This understanding can illuminate what landing zones will be economical, the optimal spacing of hydraulic fractures, and whether there will be significant interference between multiple wells during production. The flow focusing that we infer from the Wolfcamp is most likely a universal characteristic of unconventional reservoirs.The Wolfcamp operational unit in the Permian Basin region of western Texas and southeastern New Mexico is the most prolific low-permeability, liquid-hydrocarbon (i.e., crude oil and condensates) onshore producing interval in the United States (Energy Information Administration, 2022). In 2021, the average daily production in the Wolfcamp ranged between 1.8 and 2.4 million bbl, surpassing both the Eagle Ford (Texas) and the Bakken (North Dakota and Montana) Formations (Energy Information Administration, 2022). Hydrocarbons are produced at such economic rates from these low-permeability formations by combining horizontal drilling with multistage hydraulic fracturing techniques (Yu and Sepehrnoori, 2018; Zoback and Kohli, 2019). The long lateral lengths of horizontal wells and the artificial fracture network created in the rock increase the surface area of the reservoir exposed to the wellbore, resulting in economically viable production rates. In addition to operational factors, the stratigraphic architecture and consequent distribution of geological and petrophysical rock properties play a significant role in primary production from low-permeability reservoirs (Sagasti et al., 2014; Wilson et al., 2020; Euzen et al., 2021; Fraser and Pedersen, 2021).The matrix permeability describes the flow beha
我们的目标是测量近似原位饱和度的油相有效渗透率。因此，我们使用了十二烷作为测试流体，它可以与岩石中的任何残余液态碳氢化合物混溶。我们使用稳态法，因为这种方法可以直接解释测量结果。我们没有使用脉冲衰减法（Brace 等人，1968 年；Bhandari 等人，2019 年），因为该方法要求流体的可压缩性远高于岩石的可压缩性，以便进行直接解释（Brace 等人，1968 年）。如果孔隙流体为液体，则不可能做到这一点，因为岩体和流体的压缩性可能相似。其中，k 为渗透率（darcys），q 为流速（cm3/s），μ 为十二烷在孔隙压力 1000 psi 和温度 30°C 时的粘度（cp），ΔP 为岩心塞上下游之间的压差（atm），A 和 l 分别为岩心塞的横截面积（cm2）和长度（cm）。我们用场发射扫描电子显微镜（SEM）观察了样品的纹理和孔隙类型。我们从每个岩心塞中取出一个边长为 5 毫米的岩石立方体。我们获得了背散射电子扫描显微镜图像（Camp 和 Wawak，2013 年）和能量色散 X 射线光谱图（Huang 等人，2003 年；Curtis 等人，2010 年）。我们利用这些图像来解释矿物相（如白云石和石英），记录有机物的分布，并描述孔隙类型。我们将有机质作为一个通用术语，用于对岩相学上确定的任何有机化合物进行分类。我们没有区分有机物类型（如角质或块状物、沥青、固体沥青、油和火沥青）（Jarvie 等人，2007 年；Bernard 等人，2012a；Milliken 等人，2014 年），因为仅靠 SEM 岩石学并不总能做到这一点（Mastalerz 等人，2018 年）、其中，hms 和 hc 分别为泥岩和碳酸盐岩的相对厚度，ϕms 和 ϕc 分别为泥岩和碳酸盐岩的总孔隙度中值。硅质泥岩（图 6A）占沃尔夫坎普 A 和沃尔夫坎普 B 所研究岩心总厚度的 82%（Ramiro-Ramirez，2022 年）；因此，hms = 0.82，hc = 0.18。如上所述，泥岩和碳酸盐岩的总孔隙度中位数分别为 12.4% 和 3.5%。我们发现，硅质泥岩的孔隙体积占总孔隙体积的 94%（图 6B），碳酸盐岩的孔隙体积占总孔隙体积的 6%。这表明在这些样本中，90% 的孔隙流体为液体。这种岩性在线性测井中的电阻率也很低（Ramiro-Ramirez，2022 年），我们据此推断它的含水饱和度很高。Thompson等人（2018年）也在沃尔夫坎普B区类似的富含粘土的岩性中发现了高水饱和度。我们认为，液体流失量小是因为孔隙流体主要是水（因此蒸发量较小）、有效孔隙度小（水是不流动的）以及孔隙水的很大一部分是粘土结合水。富含有机质的硅质泥岩岩性中的核磁共振孔隙率为 60%（图 6B）。其电阻率远高于霰质泥岩（Ramiro-Ramirez，2022 年）。我们认为，这种岩性已被液态碳氢化合物和水所饱和。Thompson等人（2018年）和Zhang等人（2021年）的研究表明，沃尔夫坎普A单元和沃尔夫坎普B单元中富含有机质的硅质泥岩具有显著的石油饱和度。碳酸盐岩岩相的分馏核磁共振孔隙度为70%（图6B），表明它们也具有较高的液体饱和度。碳酸盐岩岩相（白云岩除外）的电阻率一般与富含有机质的硅质泥岩岩相的电阻率相似或更高（Ramiro-Ramirez，2022 年）。电阻率高的部分原因是孔隙率低和粘土含量少。不过，这种高电阻率也可能表明碳酸盐岩岩性的孔隙中有很大一部分被液态碳氢化合物所饱和。Thompson 等人（2018 年）发现，在沃尔夫坎普 A 和沃尔夫坎普 B 中，碳酸盐岩岩性的含水饱和度较低；Zhang 等人（2021 年）的研究表明，沃尔夫坎普 A 的碳酸盐岩岩性可能是邻近富含有机质的硅质泥岩排出石油的储层。
{"title":"Permeability of upper Wolfcamp lithofacies in the Delaware Basin: The role of stratigraphic heterogeneity in the production of unconventional reservoirs","authors":"Sebastian Ramiro-Ramirez, Athma R. Bhandari, Robert M. Reed, Peter B. Flemings","doi":"10.1306/12202222033","DOIUrl":"https://doi.org/10.1306/12202222033","url":null,"abstract":"The drainage of low-permeability unconventional reservoirs is often interpreted to be controlled by hydraulic and natural fractures that drain a homogenous low-permeability mudstone. However, stratigraphic heterogeneity, which results in strong variations in permeability, may also play an important role. We demonstrate that thin dolomitized carbonate sediment gravity flow deposits are over 25 times more permeable on average than the volumetrically dominant mudstone that is the source of most of the oil in the upper Wolfcamp interval of the Delaware Basin. We conducted steady-state liquid (dodecane) permeability measurements in 30 horizontal core plugs from six upper Wolfcamp lithofacies. The dolomitized calcareous lithofacies have effective permeabilities to dodecane of up to 2000 nd, whereas the remaining mudstones, dolomudstones, and calcite-bearing lithofacies have permeabilities of less than 60 nd. We constructed a layered flow model to examine the role of high-permeability layers in drainage at the completion scale. Flow is focused through the permeable layer, resulting in upscaled permeabilities and production rates that are up to four times greater than a reservoir composed of only low-permeability strata. Our analysis shows the importance of understanding stratigraphy, permeability, and flow behavior at the thin-bed scale. This understanding can illuminate what landing zones will be economical, the optimal spacing of hydraulic fractures, and whether there will be significant interference between multiple wells during production. The flow focusing that we infer from the Wolfcamp is most likely a universal characteristic of unconventional reservoirs.The Wolfcamp operational unit in the Permian Basin region of western Texas and southeastern New Mexico is the most prolific low-permeability, liquid-hydrocarbon (i.e., crude oil and condensates) onshore producing interval in the United States (Energy Information Administration, 2022). In 2021, the average daily production in the Wolfcamp ranged between 1.8 and 2.4 million bbl, surpassing both the Eagle Ford (Texas) and the Bakken (North Dakota and Montana) Formations (Energy Information Administration, 2022). Hydrocarbons are produced at such economic rates from these low-permeability formations by combining horizontal drilling with multistage hydraulic fracturing techniques (Yu and Sepehrnoori, 2018; Zoback and Kohli, 2019). The long lateral lengths of horizontal wells and the artificial fracture network created in the rock increase the surface area of the reservoir exposed to the wellbore, resulting in economically viable production rates. In addition to operational factors, the stratigraphic architecture and consequent distribution of geological and petrophysical rock properties play a significant role in primary production from low-permeability reservoirs (Sagasti et al., 2014; Wilson et al., 2020; Euzen et al., 2021; Fraser and Pedersen, 2021).The matrix permeability describes the flow beha","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"57 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139495445","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Qian Zhang, Reinhard Fink, Bernhard M. Krooss, Zhijun Jin, Rukai Zhu, Zhazha Hu, Garri Gaus, Ralf Littke
High-pressure methane (CH4) sorption measurements at 30°C and up to 20 MPa have been conducted on four carbonaceous shales with total organic carbon contents ranging from 8.52 to 11.73 wt. % and different maturities (0.53%–1.45% vitrinite reflectance). Excess sorption isotherms were measured on all four samples in the “dry,” “solvent-extracted,” “hexane-equilibrated,” and “moisture-equilibrated” states. The isotherms of all samples, irrespective of thermal maturity, showed consistent effects of extraction, preadsorbed hexane, and moisture on methane sorption capacity. Removal of bitumen by solvent extraction generally increases the methane sorption capacity of the shales (at 1 MPa) by up to 63% compared to the dry state, most likely due to enhancing the accessibility of sorption sites. Moisture consistently reduces methane sorption capacity by approximately 23% to 48% as compared to the dry (unextracted) state. The effect of preadsorbed hexane on methane sorption capacity is strongly pressure dependent: At low pressures, its influence is negative and at high pressures positive. The significant increase of sorption capacity at high pressures is attributed to the almost linear increase of methane solubility in hexane with pressure, whereas methane adsorption on the organic and mineral surfaces reaches saturation. The preadsorbed hexane reduces methane sorption capacity by approximately 20% to 40% if solubility effects are excluded. In view of these findings, the methane adsorption capacity of shales at the “wet gas” maturity level should be reconsidered. Our observations contribute to a better understanding of natural gas occurrence and producibility in liquid-bearing unconventional petroleum systems and a more accurate estimation of gas-in-place of shale gas reservoirs.
{"title":"Effects of light hydrocarbons and extractable organic matter on the methane sorption capacity of shales","authors":"Qian Zhang, Reinhard Fink, Bernhard M. Krooss, Zhijun Jin, Rukai Zhu, Zhazha Hu, Garri Gaus, Ralf Littke","doi":"10.1306/05302322009","DOIUrl":"https://doi.org/10.1306/05302322009","url":null,"abstract":"High-pressure methane (CH4) sorption measurements at 30°C and up to 20 MPa have been conducted on four carbonaceous shales with total organic carbon contents ranging from 8.52 to 11.73 wt. % and different maturities (0.53%–1.45% vitrinite reflectance). Excess sorption isotherms were measured on all four samples in the “dry,” “solvent-extracted,” “hexane-equilibrated,” and “moisture-equilibrated” states. The isotherms of all samples, irrespective of thermal maturity, showed consistent effects of extraction, preadsorbed hexane, and moisture on methane sorption capacity. Removal of bitumen by solvent extraction generally increases the methane sorption capacity of the shales (at 1 MPa) by up to 63% compared to the dry state, most likely due to enhancing the accessibility of sorption sites. Moisture consistently reduces methane sorption capacity by approximately 23% to 48% as compared to the dry (unextracted) state. The effect of preadsorbed hexane on methane sorption capacity is strongly pressure dependent: At low pressures, its influence is negative and at high pressures positive. The significant increase of sorption capacity at high pressures is attributed to the almost linear increase of methane solubility in hexane with pressure, whereas methane adsorption on the organic and mineral surfaces reaches saturation. The preadsorbed hexane reduces methane sorption capacity by approximately 20% to 40% if solubility effects are excluded. In view of these findings, the methane adsorption capacity of shales at the “wet gas” maturity level should be reconsidered. Our observations contribute to a better understanding of natural gas occurrence and producibility in liquid-bearing unconventional petroleum systems and a more accurate estimation of gas-in-place of shale gas reservoirs.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"7 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139483516","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Lei Jiang, Anjiang Shen, Zhanfeng Qiao, Anping Hu, Zhaohui Xu, Heng Zhang, Bo Wan, Chunfang Cai
Enhanced hydrogeologic circulations promoted by tectonics are commonly linked to karstic cavity formation in carbonate rocks, providing superb reservoirs for hosting energy resources (i.e., hydrocarbon and geothermal) in sedimentary basins. Predicting such cavern reservoirs in the deep subsurface is difficult mainly due to uncertainties in timing the tectonics and characterizing their associated fluids, which hamper the related hydrocarbon exploration. By combining carbonate U-Pb chronology, geochemistry, and seismic data analyses of fracture and cave-filling carbonates in cavern reservoirs from the Ordovician units of the Tarim Basin, northwestern China, the current study sought new evidence for fluid activities related to tectonics. Crucially, carbonate U-Pb ages confirm that these karstification events were closely related to syn- and/or postmineralization faulting by local tectonics. Geochemistry signatures in the authigenic minerals of fractures further suggest that the episodically developed meteoric water mixed with deep basinal brine. The carbonate dissolution rate might have been markedly enhanced by active hydrologic circulation and fluids mixing or even the formation of sulfuric acid, thus promoting the formation of karstic cavities that was closely related to the deep-rooted fractures and faults. This study highlights the indispensable role of hypogenic karstification in the formation of cavern carbonate reservoirs in the Ordovician units of the Tarim Basin and the outcome from this new contribution may provide useful guidelines for hydrocarbon exploration in the basin and other global analogues.
{"title":"Hypogenic karstic cavities formed by tectonic-driven fluid mixing in the Ordovician carbonates from the Tarim Basin, northwestern China","authors":"Lei Jiang, Anjiang Shen, Zhanfeng Qiao, Anping Hu, Zhaohui Xu, Heng Zhang, Bo Wan, Chunfang Cai","doi":"10.1306/08022321011","DOIUrl":"https://doi.org/10.1306/08022321011","url":null,"abstract":"Enhanced hydrogeologic circulations promoted by tectonics are commonly linked to karstic cavity formation in carbonate rocks, providing superb reservoirs for hosting energy resources (i.e., hydrocarbon and geothermal) in sedimentary basins. Predicting such cavern reservoirs in the deep subsurface is difficult mainly due to uncertainties in timing the tectonics and characterizing their associated fluids, which hamper the related hydrocarbon exploration. By combining carbonate U-Pb chronology, geochemistry, and seismic data analyses of fracture and cave-filling carbonates in cavern reservoirs from the Ordovician units of the Tarim Basin, northwestern China, the current study sought new evidence for fluid activities related to tectonics. Crucially, carbonate U-Pb ages confirm that these karstification events were closely related to syn- and/or postmineralization faulting by local tectonics. Geochemistry signatures in the authigenic minerals of fractures further suggest that the episodically developed meteoric water mixed with deep basinal brine. The carbonate dissolution rate might have been markedly enhanced by active hydrologic circulation and fluids mixing or even the formation of sulfuric acid, thus promoting the formation of karstic cavities that was closely related to the deep-rooted fractures and faults. This study highlights the indispensable role of hypogenic karstification in the formation of cavern carbonate reservoirs in the Ordovician units of the Tarim Basin and the outcome from this new contribution may provide useful guidelines for hydrocarbon exploration in the basin and other global analogues.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"205 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139053483","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wardana Saputra, Wissem Kirati, David Hughes, Tadeusz W. Patzek
We apply a hybrid data-driven and physics-based method to predict the most likely futures of gas production from the largest mudrock formation in North America, the Marcellus Shale play. We first divide the ≥100,000 mi2 of the Marcellus Shale into four regions with different reservoir qualities: the northeastern and southwestern cores and the noncore and outer areas. Second, we define four temporal well cohorts per region, with the well completion dates that reflect modern completion methods. Third, for each cohort, we use generalized extreme value statistics to obtain historical well prototypes of average gas production. Fourth, cumulative production from each well prototype is matched with a physics-based scaling model and extrapolated for two more decades. The resulting well prototypes are exceptionally robust. If we replace production rates from all of the wells in a given cohort with their corresponding well prototype, time shift the prototype well according to the date of first production from each well, and sum up the production, then this summation matches rather remarkably the historical gas field rate. The summation of production from the existing wells yields a base or do-nothing forecast. Fifth, we schedule the likely future drilling programs to forecast infill scenarios. The Marcellus Shale is predicted to produce 85 trillion SCF (TSCF) of gas from 12,406 existing wells. By drilling ∼3700 and ∼7800 new wells in the core and noncore areas, the estimated ultimate recovery is poised to increase to ∼180 TSCF. In contrast to data from the Energy Information Administration, we show that drilling in the Marcellus outer area is uneconomic.Natural gas plays an essential role in the possible transitions to clean energy. Today, natural gas fulfills one-fourth of the global primary power demand (BP, 2020), and its importance to the global power supply mix is predicted to only increase in the next two decades. In the United States, natural gas provides one-third of the total primary power demand (Energy Information Administration, 2020b). In mid-2020, the United States produced nearly 110 BCF of natural gas per day, which is almost twice the production rate of 15 yr ago (Enverus, 2021). This significant increase in natural gas output in the United States has only been possible with the “unconventional resource revolution” over the last two decades, during which operators have learned how to produce gas from the extremely low-permeability—unconventional—mudrock or so-called shale formations by advancing horizontal drilling and hydraulic fracturing technologies. Today, the eight major shale plays in the United States are responsible for nearly 70% of the total natural gas output. The Marcellus Shale, the largest gas shale play in North America, contributes one-third of the total United States shale gas production, producing more than 25 BCF of natural gas per day. As of the writing of this paper, the Marcellus has produced 50 trillion SCF (TSCF) of
我们综合考虑了页岩区地质、完井技术的发展、水平水力压裂井天然气生产的物理原理以及钻井项目的经济性，为马塞勒斯页岩提供了最优的整个页岩区评估。使用这些原型，我们能够很好地匹配整个马塞勒斯页岩的历史天然气产量。由于马塞勒斯地层更成熟、更厚，马塞勒斯东北部和西南部的两个核心区域都能产出最高的EUR和最赚钱的井。然而，在储层质量较差的地区，这些完井技术的进步也无济于事。最终，马塞勒斯现有的 12406 口油井预计到 2040 年将生产 85 TSCF 的天然气。如果在核心区和非核心区分别再增加 3864 口和 7896 口潜在油井，最终的采收率有望分别提高到 150 TSCF 和 180 TSCF。我们认为，数据驱动和基于物理的混合方法是所有页岩区产量预测和储量估算的未来。我们认为，数据驱动和基于物理的混合方法是所有页岩油气区产量预测和储量估算的未来。这些方法对可能的未来进行了最小二乘法意义上的最佳预测，不存在偏差，并避免了储量的大幅高估或低估。作者感谢 KAUST 通过对 Tadeusz Patzek 的基线研究资助来支持这项工作。KAUST 的计算机、电气和数学科学与工程部门为 Wissem Kirati 提供了支持。我们还要感谢《AAPG Bulletin》的技术编辑 Andrea Sharrer 和所有四位审稿人，感谢他们详尽、翔实和富有建设性的审稿意见，帮助我们大幅改进了手稿。我们尤其要感谢编辑和第 4 位审稿人，他们的评论详尽而富有洞察力，让我们受益匪浅。在线辅助材料 1-3 的电子版可在 AAPG 网站 (www.aapg.org/datashare) 上查阅，网址为 Datashare 173。Wardana Saputra 是德克萨斯大学奥斯汀分校希尔德布兰德石油与地质系统工程系的助理研究员。他于 2015 年获得印度尼西亚万隆理工学院石油工程理学学士学位。2017 年和 2021 年，他分别从沙特阿拉伯图瓦勒的阿卜杜拉国王科技大学获得地球科学与工程理学硕士学位和能源资源与石油工程博士学位。在攻读博士学位期间，他分析了美国所有主要石油盆地中≥50万口页岩密闭油气井的庞大数据集，创建了一种基于物理学的数据驱动页岩产量预测新方法。Wissem Kirati曾在沙特阿拉伯图瓦尔的KAUST的Ali I. Al-Naimi石油工程研究中心担任研究工程师。他在全球石油和天然气领域拥有多年工作经验。他还参与过大型石油公司在钻井、储层和研发领域的咨询研究。大卫-休斯（David Hughes）是一位地球科学家，研究加拿大和美国的能源资源长达四十多年，其中在加拿大地质调查局担任科学家和研究经理长达 32 年。他是全球可持续发展研究公司（Global Sustainability Research）的总裁，该公司对加拿大和美国的非常规油气田的地质基础和生产潜力进行了分析。他在北美和国际上就能源和可持续发展问题广泛发表文章和演讲。他还是后碳研究所（Post Carbon Institute）的研究员，健康能源医生、科学家和工程师协会（Physicians, Scientists, and Engineers for Healthy Energy）的董事会成员，以及加拿大替代政策中心（Canadian Centre for Policy Alternatives）的研究助理。来卡亚科技大学之前，他是德克萨斯大学奥斯汀分校石油与地质系统工程系主任、Lois K. and Richard D. Folger 领导力教授。他还担任过 11 号 Cockrell Regents 讲座教授。1990 年至 2008 年间，他在加州大学伯克利分校担任地质工程学教授。
{"title":"Forecast of economic gas production in the Marcellus Shale","authors":"Wardana Saputra, Wissem Kirati, David Hughes, Tadeusz W. Patzek","doi":"10.1306/10242221078","DOIUrl":"https://doi.org/10.1306/10242221078","url":null,"abstract":"We apply a hybrid data-driven and physics-based method to predict the most likely futures of gas production from the largest mudrock formation in North America, the Marcellus Shale play. We first divide the ≥100,000 mi2 of the Marcellus Shale into four regions with different reservoir qualities: the northeastern and southwestern cores and the noncore and outer areas. Second, we define four temporal well cohorts per region, with the well completion dates that reflect modern completion methods. Third, for each cohort, we use generalized extreme value statistics to obtain historical well prototypes of average gas production. Fourth, cumulative production from each well prototype is matched with a physics-based scaling model and extrapolated for two more decades. The resulting well prototypes are exceptionally robust. If we replace production rates from all of the wells in a given cohort with their corresponding well prototype, time shift the prototype well according to the date of first production from each well, and sum up the production, then this summation matches rather remarkably the historical gas field rate. The summation of production from the existing wells yields a base or do-nothing forecast. Fifth, we schedule the likely future drilling programs to forecast infill scenarios. The Marcellus Shale is predicted to produce 85 trillion SCF (TSCF) of gas from 12,406 existing wells. By drilling ∼3700 and ∼7800 new wells in the core and noncore areas, the estimated ultimate recovery is poised to increase to ∼180 TSCF. In contrast to data from the Energy Information Administration, we show that drilling in the Marcellus outer area is uneconomic.Natural gas plays an essential role in the possible transitions to clean energy. Today, natural gas fulfills one-fourth of the global primary power demand (BP, 2020), and its importance to the global power supply mix is predicted to only increase in the next two decades. In the United States, natural gas provides one-third of the total primary power demand (Energy Information Administration, 2020b). In mid-2020, the United States produced nearly 110 BCF of natural gas per day, which is almost twice the production rate of 15 yr ago (Enverus, 2021). This significant increase in natural gas output in the United States has only been possible with the “unconventional resource revolution” over the last two decades, during which operators have learned how to produce gas from the extremely low-permeability—unconventional—mudrock or so-called shale formations by advancing horizontal drilling and hydraulic fracturing technologies. Today, the eight major shale plays in the United States are responsible for nearly 70% of the total natural gas output. The Marcellus Shale, the largest gas shale play in North America, contributes one-third of the total United States shale gas production, producing more than 25 BCF of natural gas per day. As of the writing of this paper, the Marcellus has produced 50 trillion SCF (TSCF) of","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"33 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139053581","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Justin Nagle, David J. W. Piper, E. Marfisi, Georgia Pe-Piper, F. Saint-Ange
The Mesozoic–Cenozoic Scotian Basin terminates southwestward at the Yarmouth transfer fault zone. That part of the basin, the western Shelburne subbasin, shows a different geological evolution from the main Scotian Basin. It is the most prospective part of the basin for oil, but it remains underexplored. This study investigates the role of the transfer fault zone in sediment dispersion and deep-water clastic reservoir location by using forward stratigraphic modeling. DionisosFlowTM software was used to simulate the distribution of Callovian–Tithonian (Jurassic) clastic and carbonate strata. Sensitivity to the uncertain parameters in the model was analyzed with CougarFlowTM software. The Yarmouth transfer fault zone created ramps and topographic lows in the basin, which influenced sediment distribution and also focused long-distance river supply at the Shelburne delta. In the Late Jurassic, humid climate led to high sediment discharge, resulting in clastic progradation even during times of rising sea levels and widespread carbonate accumulation. Away from the delta, modeling suggests that deeper initial bathymetry accounts for the observed stable shelf-edge reef growth better than a shallower ramp bathymetry. Sensitivity analysis indicates that clastic sediments from the Shelburne delta prograded into deep water, even if water discharge and sand diffusion coefficients were low. Where the upper slope was steep, it was bypassed by sandy sediment that accumulated in basin-floor fans, predicted by modeling and confirmed by seismic interpretation of a channel-levee system in small areas undisturbed by salt tectonics. Forward stratigraphic modeling is thus an important tool for understanding petroleum geology in such underexplored areas.
{"title":"Jurassic deep-water reservoirs at a transfer-transform offset: Modeling the mixed carbonate-siliciclastic Shelburne subbasin, southeastern Canadian margin","authors":"Justin Nagle, David J. W. Piper, E. Marfisi, Georgia Pe-Piper, F. Saint-Ange","doi":"10.1306/01172320041","DOIUrl":"https://doi.org/10.1306/01172320041","url":null,"abstract":"The Mesozoic–Cenozoic Scotian Basin terminates southwestward at the Yarmouth transfer fault zone. That part of the basin, the western Shelburne subbasin, shows a different geological evolution from the main Scotian Basin. It is the most prospective part of the basin for oil, but it remains underexplored. This study investigates the role of the transfer fault zone in sediment dispersion and deep-water clastic reservoir location by using forward stratigraphic modeling. DionisosFlowTM software was used to simulate the distribution of Callovian–Tithonian (Jurassic) clastic and carbonate strata. Sensitivity to the uncertain parameters in the model was analyzed with CougarFlowTM software. The Yarmouth transfer fault zone created ramps and topographic lows in the basin, which influenced sediment distribution and also focused long-distance river supply at the Shelburne delta. In the Late Jurassic, humid climate led to high sediment discharge, resulting in clastic progradation even during times of rising sea levels and widespread carbonate accumulation. Away from the delta, modeling suggests that deeper initial bathymetry accounts for the observed stable shelf-edge reef growth better than a shallower ramp bathymetry. Sensitivity analysis indicates that clastic sediments from the Shelburne delta prograded into deep water, even if water discharge and sand diffusion coefficients were low. Where the upper slope was steep, it was bypassed by sandy sediment that accumulated in basin-floor fans, predicted by modeling and confirmed by seismic interpretation of a channel-levee system in small areas undisturbed by salt tectonics. Forward stratigraphic modeling is thus an important tool for understanding petroleum geology in such underexplored areas.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"11 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139053491","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Dave Larue, Jon Allen, Cecile Audinet, Kathy Miller, Jesse Thompson
The Temblor Formation reservoirs in the densely drilled West Coalinga field were primarily deposited in various tidal settings and have an abundance of reservoir complexity types and heterogeneities that can be interpreted within a sequence stratigraphic framework. Characterization of the Temblor reservoirs is presented in three parts: the first part focuses on techniques of recognizing functional rock types using available logs, the second part focuses on interpreting depositional facies and stacking patterns in a sequence stratigraphic framework using available core, and the third part investigates two complex cases of reservoir continuity. As described in part I, the task of characterizing lithologies in the reservoir is a challenge because only the resistivity and porosity logs provide consistently useable information, and even then, with a number of caveats.As described in parts II and III, incised valley fills, associated with lowstand systems tract deposition above sequence boundaries, represent the dimensionally largest stratigraphic heterogeneities, are excellent completion targets, and can be imaged in three-dimensional seismic data as well as recognized in well sections. Incised valley fills typically consist of multistory tidal channel complex deposits. Mudstone intervals, locally diatomaceous, represent transgressive systems tract (TST) deposits and form vertical compartments in the reservoir. Highstand systems tract (HST) deposits include tidal bar and tidal channel deposits. Odd wedge-shaped bodies at a scale similar to that of incised valleys are also present in the upper Temblor reservoirs and represent deposition by backstepping (TST) and prograding (HST) systems tracts.At the bedset scale, thin mudstone beds, mudstone drapes, and mudstone clast conglomerates represent finer scales of heterogeneity. Localized carbonate-cemented zones can be mapped and represent important diagenetic heterogeneities that locally reduce net pay at the facies level. These well-documented different heterogeneity types can be used to address potential concerns in other tidal reservoirs being considered for development or in the early stages of production.
密集钻探的 West Coalinga 油田的 Temblor Formation 储层主要沉积于各种潮汐环境中，具有丰富的储层复杂类型和异质性，可以在层序地层框架内进行解释。Temblor 油藏的特征描述分为三部分：第一部分重点介绍利用现有测井记录识别功能岩石类型的技术；第二部分重点介绍利用现有岩心解释层序地层框架中的沉积面和堆积模式；第三部分研究两个复杂的油藏连续性案例。如第一部分所述，确定储层岩性特征的任务是一项挑战，因为只有电阻率和孔隙度测井提供了持续可用的信息，即使如此，也有许多注意事项。如第二和第三部分所述，与层序边界之上的低台系统道沉积有关的切谷充填代表了尺寸最大的地层异质性，是极好的完井目标，可以在三维地震数据中成像，也可以在井剖面中识别。裂谷充填物通常由多层潮汐河道复合沉积物组成。泥岩层段（局部为硅藻土）代表了横向系统道（TST）沉积，并在储层中形成垂直分区。高位系沉积包括潮间带和潮汐河道沉积。上腾博会登录储层中还存在规模类似于切入谷的奇特楔形体，代表了后退（TST）和渐进（HST）系统道的沉积。在层集规模上，薄泥岩层、泥岩垂带和泥岩碎屑砾岩代表了更细的异质性规模。可以绘制局部的碳酸盐加固带，它们代表了重要的成岩异质性，在局部减少了岩层的净付积。这些记录详实的不同异质性类型可用于解决考虑开发或处于生产早期阶段的其他潮汐储层的潜在问题。
{"title":"Complex multiscale reservoir heterogeneity in a tidal depositional environment, Temblor Formation, West Coalinga field, California","authors":"Dave Larue, Jon Allen, Cecile Audinet, Kathy Miller, Jesse Thompson","doi":"10.1306/01172320199","DOIUrl":"https://doi.org/10.1306/01172320199","url":null,"abstract":"The Temblor Formation reservoirs in the densely drilled West Coalinga field were primarily deposited in various tidal settings and have an abundance of reservoir complexity types and heterogeneities that can be interpreted within a sequence stratigraphic framework. Characterization of the Temblor reservoirs is presented in three parts: the first part focuses on techniques of recognizing functional rock types using available logs, the second part focuses on interpreting depositional facies and stacking patterns in a sequence stratigraphic framework using available core, and the third part investigates two complex cases of reservoir continuity. As described in part I, the task of characterizing lithologies in the reservoir is a challenge because only the resistivity and porosity logs provide consistently useable information, and even then, with a number of caveats.As described in parts II and III, incised valley fills, associated with lowstand systems tract deposition above sequence boundaries, represent the dimensionally largest stratigraphic heterogeneities, are excellent completion targets, and can be imaged in three-dimensional seismic data as well as recognized in well sections. Incised valley fills typically consist of multistory tidal channel complex deposits. Mudstone intervals, locally diatomaceous, represent transgressive systems tract (TST) deposits and form vertical compartments in the reservoir. Highstand systems tract (HST) deposits include tidal bar and tidal channel deposits. Odd wedge-shaped bodies at a scale similar to that of incised valleys are also present in the upper Temblor reservoirs and represent deposition by backstepping (TST) and prograding (HST) systems tracts.At the bedset scale, thin mudstone beds, mudstone drapes, and mudstone clast conglomerates represent finer scales of heterogeneity. Localized carbonate-cemented zones can be mapped and represent important diagenetic heterogeneities that locally reduce net pay at the facies level. These well-documented different heterogeneity types can be used to address potential concerns in other tidal reservoirs being considered for development or in the early stages of production.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"87 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139053748","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hugo Tamoto, André Luiz Silva Pestilho, Anelize Manuela Bahniuk Rumbelsperger
The presalt carbonate reservoirs located at the marginal basins of Brazil are one the most important hydrocarbon provinces worldwide. These reservoirs are responsible for approximately 75% of the Brazilian offshore oil production. Despite the presalt reservoirs’ present good petrophysical qualities (porosity >15% and permeability >100 md), there are still challenges related to the lack of understanding of the petrophysical controls resulting from a complex depositional and diagenetic history. To address such problems, an overall evaluation of the carbonate reservoir was provided on the Aptian Barra Velha Formation in the Sapinhoá field, Santos Basin. This research used an extensive data set of well logs, petrophysics, and x-ray diffraction, which identified facies heterogeneities, variated petrophysical distribution, and five hydraulic flow units. Overall, the best petrophysical intervals with highest porosity and permeability are found in the wells located at the structural high comprising the flow units 4 and 5 and mostly consisting of shrub and grain-supported facies followed by an intermediary flow unit 3 found in all wells. Moreover, among all units, flow units 1 and 2 presented the lowest petrophysical values, mainly found at the basinward wells. Finally, results indicate that key diagenetic features such as dissolution of clay minerals, dissolution of calcite fabric, and dolomitization processes are notable elements that commonly enhanced petrophysical properties. Additionally, the pervasive silicification process decreases the reservoir quality. These processes are commonly found in the wells located in the structural high and basinward areas of the field. Lastly, a multiscale characterization allows a broad comprehension of the key diagenetic impacts into carbonates’ petrophysical properties.
{"title":"Impacts of diagenetic processes on petrophysical characteristics of the Aptian presalt carbonates of the Santos Basin, Brazil","authors":"Hugo Tamoto, André Luiz Silva Pestilho, Anelize Manuela Bahniuk Rumbelsperger","doi":"10.1306/05302322046","DOIUrl":"https://doi.org/10.1306/05302322046","url":null,"abstract":"The presalt carbonate reservoirs located at the marginal basins of Brazil are one the most important hydrocarbon provinces worldwide. These reservoirs are responsible for approximately 75% of the Brazilian offshore oil production. Despite the presalt reservoirs’ present good petrophysical qualities (porosity >15% and permeability >100 md), there are still challenges related to the lack of understanding of the petrophysical controls resulting from a complex depositional and diagenetic history. To address such problems, an overall evaluation of the carbonate reservoir was provided on the Aptian Barra Velha Formation in the Sapinhoá field, Santos Basin. This research used an extensive data set of well logs, petrophysics, and x-ray diffraction, which identified facies heterogeneities, variated petrophysical distribution, and five hydraulic flow units. Overall, the best petrophysical intervals with highest porosity and permeability are found in the wells located at the structural high comprising the flow units 4 and 5 and mostly consisting of shrub and grain-supported facies followed by an intermediary flow unit 3 found in all wells. Moreover, among all units, flow units 1 and 2 presented the lowest petrophysical values, mainly found at the basinward wells. Finally, results indicate that key diagenetic features such as dissolution of clay minerals, dissolution of calcite fabric, and dolomitization processes are notable elements that commonly enhanced petrophysical properties. Additionally, the pervasive silicification process decreases the reservoir quality. These processes are commonly found in the wells located in the structural high and basinward areas of the field. Lastly, a multiscale characterization allows a broad comprehension of the key diagenetic impacts into carbonates’ petrophysical properties.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"9 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139051772","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Existing descriptions and mapping techniques of hydrodynamic effects on subsurface fluid contacts are generally restricted to relatively thick, continuous reservoirs. These concepts do not readily apply to stratigraphic traps in thin reservoirs that pinch out laterally in some directions yet are normally pressured. Spatial variation in reservoir pinch-out trends, geological depth structure, and hydrodynamic head gives rise to many scenarios of hydrodynamically modified stratigraphic traps. Further complexity arises where stratigraphic traps are developed in unstructured or low relief areas, where a slight tilt angle of a fluid contact can translate into a significant deviation from structural conformance in map view. Hydraulic gradient azimuth relative to structural dip azimuth is a key factor. Where these are parallel, hydraulic gradients have little effect on stratigraphic trapping potential. The closer the hydraulic gradient azimuth is to the structural strike direction, the greater the potential impact of fluid contact tilt in that stratigraphic trap. These results are not predicted by the usual method of revealing hydrodynamic traps via hydraulic head transformations of structural maps. Instead, a modified workflow for hydrodynamic stratigraphic traps combines structure, porosity, and hydraulic gradient maps.
{"title":"Hydrodynamic effects on low-dip stratigraphic traps","authors":"S. A. Stewart","doi":"10.1306/05302322081","DOIUrl":"https://doi.org/10.1306/05302322081","url":null,"abstract":"Existing descriptions and mapping techniques of hydrodynamic effects on subsurface fluid contacts are generally restricted to relatively thick, continuous reservoirs. These concepts do not readily apply to stratigraphic traps in thin reservoirs that pinch out laterally in some directions yet are normally pressured. Spatial variation in reservoir pinch-out trends, geological depth structure, and hydrodynamic head gives rise to many scenarios of hydrodynamically modified stratigraphic traps. Further complexity arises where stratigraphic traps are developed in unstructured or low relief areas, where a slight tilt angle of a fluid contact can translate into a significant deviation from structural conformance in map view. Hydraulic gradient azimuth relative to structural dip azimuth is a key factor. Where these are parallel, hydraulic gradients have little effect on stratigraphic trapping potential. The closer the hydraulic gradient azimuth is to the structural strike direction, the greater the potential impact of fluid contact tilt in that stratigraphic trap. These results are not predicted by the usual method of revealing hydrodynamic traps via hydraulic head transformations of structural maps. Instead, a modified workflow for hydrodynamic stratigraphic traps combines structure, porosity, and hydraulic gradient maps.","PeriodicalId":7124,"journal":{"name":"AAPG Bulletin","volume":"8 1","pages":""},"PeriodicalIF":3.5,"publicationDate":"2024-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139053846","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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