Petroleum Geoscience最新文献

{"title":"Applications of real-time chemical stratigraphy in support of the safe drilling of HPHT wells: examples from the Shearwater Field, Central North Sea, UK","authors":"D. Atkin, M. Vieira, B. Taylor","doi":"10.1144/petgeo2019-081","DOIUrl":"https://doi.org/10.1144/petgeo2019-081","url":null,"abstract":"X-ray fluorescence (XRF) data from a series of high-pressure–high-temperature (HPHT) wells drilled in the Shearwater Field, UK Continental Shelf (UKCS) are presented. These data comprise a total of 789 samples across a series of eight study wells. Chemical stratigraphy was utilized in conjunction with other geological data (i.e. well logs, ditch cutting descriptions and biostratigraphic analyses) to aid real-time stratigraphic placement. Systematic changes in geochemical composition were identified and used to build a chemostratigraphic zonation to aid delineation of lithostratigraphic boundaries. The application of chemical stratigraphy provided a valuable source of data, particularly through critical ‘drill-in-liner’ sections that are devoid of conventional logging while drilling (LWD) data. The identification of key geochemical zones and provision of a synthetic gamma-ray (Synth GR) profile were utilized in the placement of key casing points and identification of challenging top reservoir picks (Fulmar Formation). These data also served as a backup during LWD tool failure resulting from excessive temperatures. The successive addition of geochemical data accumulated with each well-site exercise permitted continued refinement of the zonation framework, with derived Synth GR profiles exhibiting an extremely close relationship with subsequent wireline logs. Chemical stratigraphic data are shown to be robust and repeatable within the Shearwater Field, enabling close stratigraphic control through critical sections, whilst also providing a low-cost backup in the event of conventional logging tool failures.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"27 1","pages":""},"PeriodicalIF":1.7,"publicationDate":"2020-02-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2019-081","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"64015973","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Definition of the Hercynian Unconformity in eastern Saudi Arabia using chemostratigraphy in conjunction with biostratigraphy, sedimentology and lithostratigraphy","authors":"N. Craigie","doi":"10.1144/petgeo2019-116","DOIUrl":"https://doi.org/10.1144/petgeo2019-116","url":null,"abstract":"The following chemostratigraphy study was conducted on Paleozoic sediments encountered in 14 wells in eastern Saudi Arabia. A total of 1500 samples were analysed by inductively coupled plasma optical emission spectrometry (ICP-OES) and inductively coupled plasma mass spectrometry (ICP-MS), with data acquired for 48 elements, ranging from Na to U in the periodic table. The aim was to utilize chemostratigraphy, in conjunction with existing biostratigraphic, lithostratigraphic and sedimentological data, to define the Hercynian Unconformity in each well and to recognize stratigraphic boundaries occurring above and below it. This was necessary as the unconformity eroded to different stratigraphic levels in each well, with Devonian, Silurian and Ordovician sediments found immediately below it in adjacent locations. In the absence of chemostratigraphic, biostratigraphic and sedimentological data, it is often very difficult to define this boundary and others using lithostratigraphy alone as many stratigraphic intervals yield similar gamma-ray (GR) log trends. For example, a low ‘blocky’ GR response is typical of both the Carboniferous Ghazal Member and the Ordovician Sarah Formation. Similarly, both the Silurian Sharawra Member and the Silurian–Devonian Tawil Formation produce a ‘ratty’ GR trend. Each stratigraphic member and formation was found to have distinctive chemostratigraphic, biostratigraphic, sedimentological and/or wireline log signatures.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"26 1","pages":"568 - 588"},"PeriodicalIF":1.7,"publicationDate":"2020-02-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49632056","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hierarchical parameterization and compression-based object modelling of high net:gross but poorly amalgamated deep-water lobe deposits","authors":"T. Manzocchi, L. Zhang, P. Haughton, A. Pontén","doi":"10.1144/petgeo2018-078","DOIUrl":"https://doi.org/10.1144/petgeo2018-078","url":null,"abstract":"Deep-water lobe deposits are arranged hierarchically and can be characterized by high net:gross ratios but poor sand connectivity due to thin, but laterally extensive, shale layers. This heterogeneity makes them difficult to represent in standard full-field object-based models, since the sands in an object-based model are not stacked compensationally and become connected at a low net:gross ratio. The compression algorithm allows the generation of low-connectivity object-based models at high net:gross ratios, by including the net:gross and amalgamation ratios as independent input parameters. Object-based modelling constrained by the compression algorithm has been included in a recursive workflow, permitting the generation of realistic models of hierarchical lobe deposits. Representative dimensional and stacking parameters collected at four different hierarchical levels have been used to constrain a 250 m-thick, 14 km2 model that includes hierarchical elements ranging from 20 cm-thick sand beds to more than 30 m-thick lobe complexes. Sand beds and the fine-grained units are represented explicitly in the model, and the characteristic facies associations often used to parameterize lobe deposits are emergent from the modelling process. The model is subsequently resampled without loss of accuracy for flow simulation, and results show clearly the influence of the hierarchical heterogeneity on drainage and sweep efficiency during a water-flood simulation.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"26 1","pages":"545 - 567"},"PeriodicalIF":1.7,"publicationDate":"2020-01-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44766560","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The evolution of the Dowsing Graben System: implications for petroleum prospectivity in the UK Southern North Sea","authors":"Ross J. Grant, J. Underhill, Jaume Hernández-Casado, R. Jamieson, R. M. Williams","doi":"10.1144/petgeo2018-064","DOIUrl":"https://doi.org/10.1144/petgeo2018-064","url":null,"abstract":"Upper Permian (Zechstein Supergroup) evaporites have a major control on structural styles and prospectivity in the UK Southern North Sea (SNS). They form the regional super-seal for the main Rotliegend Group (Leman Sandstone Formation) reservoir play fairway immediately beneath. The evaporites have highly variable thicknesses due to the syndepositional basin architecture, differential loading and post-depositional deformation through diapirism and salt withdrawal. The halokinetic activity leads to touchdown (welding) of the supra-salt section onto the sub-salt strata and the development of narrow (up to 15 km-wide) graben systems. The interpretation and depth conversion of well-calibrated, high-quality, 3D post-stack time-migrated (PSTM) seismic data along the southwestern margin of the basin show that a NW–SE-striking elongate extensional Dowsing Graben System transects the area. The graben is defined by a series of large, overlapping, en echelon listric growth faults, with oblique secondary planar faults, which sole-out on two main (deep and shallow) décollement levels in the Zechstein Supergroup and the Middle Triassic Röt Halite Member. Whilst its initial formation was related to Mesozoic extension, the graben system also displays a contractional overprint resulting from regional compression and structural inversion during the Cenozoic. Detailed mapping of the Zechstein Supergroup has revealed that the evolution of the extensional system was influenced by the ESE–WNW-striking anhydrite–carbonate Zechstein shelf-margin. The occurrence of variable-thickness, low-velocity sediments within the graben impacts seismic imaging and depth conversion, leading to prospective structures being overlooked; something that has implications for prospectivity in the SNS and other evaporite basins where similar graben occur.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"27 1","pages":""},"PeriodicalIF":1.7,"publicationDate":"2019-12-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2018-064","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43292849","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Petroleum geochemical aspects of the Mandawa Basin, coastal Tanzania: the origin of migrated oil occurring today as partly biodegraded bitumen","authors":"T. B. Abay, K. Fossum, D. Karlsen, H. Dypvik, Lars Jonas Jørgensen Narvhus, M. Haid, W. Hudson","doi":"10.1144/petgeo2019-050","DOIUrl":"https://doi.org/10.1144/petgeo2019-050","url":null,"abstract":"The shallow-marine Upper Jurassic–Lower Cretaceous sedimentary successions of the Mandawa Basin, coastal Tanzania, are located about 80 km away from the offshore gas discoveries of Block 2, Tanzania. In this paper we present petroleum geochemical data, including bitumen extracted from outcrop samples which are relevant to the understanding of the onshore ‘Petroleum System’ and possibly also to the offshore basin. Despite some biodegradation and weathering, common to all outcrop samples, most bitumen samples analysed contain mature migrated oil. The maturity span of geomarkers (C13–C15 range) covers the entire oil and condensate/wet gas window (Rc = 0.7–2% Rc, where Rc is the calculated vitrinite reflectance), with the biomarkers generally indicating the oil window (Rc = 0.7–1.3% Rc). This suggests that the bitumen extracts represent several phases of migrated oil and condensate, which shows that the samples are part of an active or recently active migration regime or ‘Petroleum System’. The source-rock facies inferred for the bitumen is Type II/III kerogen of siliciclastic to carbonate facies. This is oil-prone kerogen, typical for a marine depositional system with an influx of proximal-derived terrigenous material blended in with in situ marine algal organic matter (OM). Application of age-specific biomarkers such as the C28/C29-steranes, extended tricyclic terpane ratio (ETR), nordiacholestanes and the aromatic steroids suggest that more than one source rock have contributed to the bitumen. Possible ages are limited to the Mesozoic (i.e. excluding the Late Paleozoic), with the most likely source rock belonging to the Early Jurassic. More geochemical and geological studies should be undertaken to further develop the general understanding of the petroleum system of the Mandawa Basin and its implications to the ‘Petroleum Systems’ both offshore and onshore. This paper also presents a reinterpretation of published gas composition and isotope data on the Pande, Temane and Inhassoro gas fields (Mozambique) with implications for possible oil discoveries in the gas-dominated region.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":" ","pages":""},"PeriodicalIF":1.7,"publicationDate":"2019-12-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2019-050","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47722968","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir modelling notional CO2 injection into the Precipice Sandstone and Evergreen Formation in the Surat Basin, Australia","authors":"A. L. La Croix, Ahmed Harfoush, I. Rodger, S. González, J. Undershultz, P. Hayes, A. Garnett","doi":"10.1144/petgeo2019-058","DOIUrl":"https://doi.org/10.1144/petgeo2019-058","url":null,"abstract":"The Lower Jurassic Precipice Sandstone and Evergreen Formation are an important prospective reservoir–seal pair for CO2 storage in the Surat Basin, Australia. However, there is little seismic and well data to constrain reservoir modelling in the best notional injection area. To test the likely storage performance, three contrasting sector-scale static reservoir models were built to capture the range of geological uncertainty in facies distribution and reservoir properties. These considered sectors of the Surat Basin with different palaeogeographical arrangements. The models were focused on capturing detail at the interface between the top of the Precipice Sandstone (Blocky Sandstone Reservoir: BSR) and the overlying basal portions of the Evergreen Formation (Transition Zone: TZ), a critical area for understanding CO2 injection. Object modelling was used for the BSR and lower TZ. Stochastic modelling was implemented for the upper TZ and the Ultimate Seal because these zones were less sensitive to facies distributions. Porosity was modelled stochastically, and permeability calculated using porosity–permeability transformation functions. Dynamic simulation showed the TZ has the capacity to arrest CO2 flow out of the BSR given appropriate CO2 injection conditions. This study shows a method of capturing uncertainty in geological heterogeneity when data are sparse or absent. The promising initial modelling results of CO2 injection into the Surat Basin suggests that it presents a real option for carbon storage at a climate mitigation scale. Further investigation should focus on assessing other major risks associated with carbon storage such as fault seals, reactive fluid transport and the impact of legacy wells. This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"26 1","pages":"127 - 140"},"PeriodicalIF":1.7,"publicationDate":"2019-11-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49542086","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Multiscale fracture length analysis in carbonate reservoir units, Kurdistan, NE Iraq","authors":"J. Long, Richard R. Jones, D. Oxlade, S. Daniels, S. Gilment","doi":"10.1144/petgeo2018-168","DOIUrl":"https://doi.org/10.1144/petgeo2018-168","url":null,"abstract":"Fracture scaling parameters are an important input for modelling of naturally fractured reservoirs, but are very difficult to derive from subsurface data. Extensive areas of exposure in the northern Kurdistan Region of Iraq provide useful outcrop analogues for nearby producing and potential hydrocarbon fields. A variety of data acquisition methods are used to analyse fracture systems in carbonates of the Upper Cretaceous Aqra–Bekhme Formation across a wide range of scales. When plotted on length–intensity graphs, the collated data lie below an upper envelope that follows a power-law distribution over five orders of magnitude between 0.1 and 3000 m, and which defines the maximum likely intensity of background fracturing across the region. Contouring the length–intensity data shows the distribution of intensities below the upper envelope, and allows modal and minimum likely intensities to be estimated. Likely causes for the observed variation in fracture intensities include the domainal nature of deformation, the proximity to high strain zones including faults, second-order effects such as ladder fractures, and variations in the thickness of mechanical layering. Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"25 1","pages":"429 - 442"},"PeriodicalIF":1.7,"publicationDate":"2019-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2018-168","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41682201","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A new look into the prediction of static Young's modulus and unconfined compressive strength of carbonate using artificial intelligence tools","authors":"Zeeshan Tariq, A. Abdulraheem, M. Mahmoud, S. Elkatatny, Abdulwahab Ali, Dhafer Al-Shehri, M. Belayneh","doi":"10.1144/petgeo2018-126","DOIUrl":"https://doi.org/10.1144/petgeo2018-126","url":null,"abstract":"Accurate estimation of rock elastic and failure parameters plays a vital role in petroleum, civil and geotechnical engineering applications. During drilling operations, continuous logs of rock elastic and failure parameters are considered very helpful in optimizing geomechanical earth models. Commonly, rock elastic and failure parameters are estimated using well logs and empirical correlations. These are calibrated with rock mechanics laboratory experiments conducted on core samples. However, since these samples are expensive to get and time-consuming to test, artificial intelligence (AI) models based on available petrophysical well logs such as bulk density, compressional wave and shear wave travel times are utilized to predict the static Young's modulus (Estatic) and the unconfined compressive strength (UCS) – with an emphasis on carbonate rocks. We present two AI techniques in this study: an artificial neural network (ANN) and an adaptive neuro-fuzzy inference system (ANFIS). The dataset used in this study contains 120 data points obtained from a Middle Eastern carbonate reservoir from which we develop an empirically correlated ANN model to predict Estatic and an ANFIS model to predict the UCS. A comparison between the UCS, predicted by the proposed ANFIS model, and the published correlations show that the ANFIS model predicted the UCS with less error and with a high coefficient of determination. The error obtained from the ANFIS model was 4.5%, while other correlations resulted in up to 30% error on a published dataset. On the basis of the results obtained, we can say that the developed models will help geomechanical engineers to predict Estatic and the UCS using well logs without the need to measure them in the laboratory. Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"25 1","pages":"389 - 399"},"PeriodicalIF":1.7,"publicationDate":"2019-10-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2018-126","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42325387","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Influence of fracture nucleation and propagation rates on fracture geometry: insights from geomechanical modelling","authors":"M. Welch, M. Luthje, A. C. Glad","doi":"10.1144/petgeo2018-161","DOIUrl":"https://doi.org/10.1144/petgeo2018-161","url":null,"abstract":"We combine a power-law microfracture size distribution function with an expression for fracture propagation rate derived from subcritical fracture propagation theory and linear elastic fracture mechanics, to derive a geomechanically based deterministic model for the growth of a network of layer-bound fractures. This model also simulates fracture termination due to intersection with perpendicular fractures or stress-shadow interaction. We use this model to examine key controls on the emergent geometry of the fracture network. First, we examine the effect of fracture propagation rates. We show that at subcritical fracture propagation rates, the fracture nucleation rate increases with time; this generates a very dense network of very small fractures, similar to the deformation bands generated by compaction in unconsolidated sediments. By contrast, at critical propagation rates, the fracture nucleation rate decreases with time; this generates fewer but much larger fractures, similar to the brittle open fractures generated by tectonic deformation in lithified sediments. We then examine the controls on the rate of growth of the fracture network. A fracture set will start to grow when the stress acting on it reaches a threshold value, and it will continue to grow until all the fractures have stopped propagating and no new fractures can nucleate. The relative timing and rate of growth of the different fracture sets will control the anisotropy of the resulting fracture network: if the sets start to grow at the same time and rate, the result is a fully isotropic fracture network; if the primary fracture set stops growing before the secondary set starts growing, the result is a fully anisotropic fracture network; and if there is some overlap but the secondary set grows more slowly than the primary set, the result is a partially anisotropic fracture network. Although the applied horizontal strain rates are the key control on the relative growth rates of the two fracture sets, we show that the vertical effective stress, the initial horizontal stress, the elastic properties of the rock and the inelastic deformation processes, such as creep, grain sliding and pressure solution, all exert a control on the fracture growth rates, and that more isotropic fracture networks will tend to develop if the vertical effective stress is low or if the fractures are critically stressed prior to the onset of deformation. Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"25 1","pages":"470 - 489"},"PeriodicalIF":1.7,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2018-161","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44438771","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Key controls on hydrocarbon retention and leakage from structural traps in the Hammerfest Basin, SW Barents Sea: implications for prospect analysis and risk assessment","authors":"I. Edmundson, A. Rotevatn, R. Davies, G. Yielding, K. Broberg","doi":"10.1144/petgeo2019-094","DOIUrl":"https://doi.org/10.1144/petgeo2019-094","url":null,"abstract":"Evidence of hydrocarbon leakage has been well documented across the SW Barents Sea and is commonly associated with exhumation in the Cenozoic. While fault leakage is thought to be the most likely cause, other mechanisms are possible and should be considered. Further study is required to understand what specific mechanism(s) facilitate such leakage, and why this occurs in some locations and not others. In a case study of the Snøhvit Field, we use seismic and well data to quantify fault- and top-seal strength based on mechanical and capillary threshold pressure properties of fault and cap rocks. Magnitude and timing of fault slip are measured to acknowledge the role that faults play in controlling fluid flow over time. Results based on theoretical and in situ hydrocarbon column heights strongly indicate that across-fault and top-seal breach by capillary threshold pressure, and top-seal breach by mechanical failure are highly unlikely to have caused hydrocarbon leakage. Instead, top-seal breach caused by tectonic reactivation of identified faults is likely to have facilitated hydrocarbon leakage from structural traps. The results of this case study acknowledge the different mechanisms by which hydrocarbons can leak from a structural trap. Employing both a holistic and quantitative approach to assessing different seal capacities reduces the likelihood that a particular cause of hydrocarbon leakage is overlooked. This is particularly relevant for the Snøhvit Field in its dual capacity as a producing gas field and as a carbon sequestration site since both systems rely on a thorough understanding of seal capacity and leakage potential.","PeriodicalId":49704,"journal":{"name":"Petroleum Geoscience","volume":"26 1","pages":"589 - 606"},"PeriodicalIF":1.7,"publicationDate":"2019-09-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1144/petgeo2019-094","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47964025","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}