AAPG Bulletin最新文献

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}

{"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}