Journal of Petroleum Geology最新文献

{"title":"APPLICATION OF MUD GAS DATA AND LEAKAGE PHENOMENA TO EVALUATE SEAL INTEGRITY OF POTENTIAL CO2 STORAGE SITES: A STUDY OF CHALK STRUCTURES IN THE DANISH CENTRAL GRABEN, NORTH SEA","authors":"H.I. Petersen,&nbsp;F.W.H. Smit","doi":"10.1111/jpg.12830","DOIUrl":"10.1111/jpg.12830","url":null,"abstract":"<p>Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO₂ storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C₃–C₅, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C₁ (methane) and partly C₂ (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal &gt;30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane-derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe-out zones (gas chimneys), bright zones (gas-charged sediments or MDACs), and depressions (pockmarks). In general, potential CO₂ storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO₂ storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"47-75"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41421922","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 SYSTEMS ANALYSIS OF THE EASTERN ARABIAN PLATE: CHEMOMETRICS BASED ON A REVIEW OF THE GEOCHEMICAL CHARACTERISTICS OF OILS IN JURASSIC – CENOZOIC RESERVOIRS","authors":"Alireza Baniasad,&nbsp;Ralf Littke,&nbsp;Qusay Abeed","doi":"10.1111/jpg.12829","DOIUrl":"10.1111/jpg.12829","url":null,"abstract":"<p>This paper presents the results of an integrated geochemical study of oils in Jurassic – Cenozoic reservoirs in the eastern region of the Arabian Plate. The main objective was to analyze the active petroleum systems at a regional scale across the study area which extends from NE Iraq to SE Oman and includes the entire Persian Gulf. The dataset for the study consisted of more than 500 crude oil samples from 112 oil fields and 11 different reservoir units. This dataset was compiled from both the literature and re-evaluated geochemical and stable isotope analyses, augmented by new analytical studies.</p><p>The study documents regional variations and trends in the bulk and molecular properties and stable isotope ratios of the oil samples. Two overall clans and twelve genetic oil families and sub-families were distinguished using multivariate statistical analysis (chemometrics) based on biomarker parameters. The age, lithology, depositional setting and organic matter type of the respective source rocks for each family/sub-family was inferred from oil geochemical fingerprints.</p><p>The results provide insights into the key geological factors that control the number, size and geochemical character of oil fields in the eastern Arabian Plate. The geographical extent of the various oil families was assessed and used to evaluate charge access and to predict migration directions and migration pathways in the study area.</p><p>The results indicate the value of implementing multivariate statistical analysis on “big data” along with state-of-the-art geological petroleum systems analysis and interpretation of biomarker and oil composition data to investigate complex and extended petroleum systems.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"3-45"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49525906","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":"GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA-C OIL FIELD, MURZUQ BASIN, SOUTHWESTERN LIBYA","authors":"Ramadan Musbah M. Saheed,&nbsp;Tatjana Šolević Knudsen,&nbsp;Musbah Abduljalil M. Faraj,&nbsp;Hans Peter Nytoft,&nbsp;Branimir Jovančićević","doi":"10.1111/jpg.12832","DOIUrl":"10.1111/jpg.12832","url":null,"abstract":"<p>Crude oil samples from the Sharara-C oil field (Concession NC-115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC-MS), and gas chromatography – tandem mass spectrometry (GC-MS-MS) was used to analyse saturated biomarkers. The Sharara-C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age-specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation-related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation.</p><p>Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material.</p><p>The organic geochemical parameters determined for the Sharara-C crude oils were compared with published data on other crude oils from Concession NC-115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub-families in the Sharara oil field area which are genetically related but which have different maturities.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"103-123"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43958983","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":"QUARTZITIC SANDSTONES IN THE NAMURIAN AND LOWER WESTPHALIAN SUCCESSION OF THE SOUTHERN NORTH SEA: A NEW HIGH-PERMEABILITY CARBONIFEROUS RESERVOIR TYPE","authors":"G. A. Blackbourn,&nbsp;J. D. Collinson","doi":"10.1111/jpg.12824","DOIUrl":"10.1111/jpg.12824","url":null,"abstract":"<p>Most of the potential sandstone reservoirs within the Namurian and lower Westphalian succession of the Southern North Sea Basin are originally feldspathic sands in which the feldspar has mainly been altered to microporous kaolinite clays. The sandstones provide a moderate porosity (typically 8-15%, depending mainly on grain size), but permeability is severely limited owing to the microporous nature of much of the porosity. Permeability is typically 1 mD or less, rising to a few tens of millidarcies in occasional coarse- and very coarse-grained sands. Predicting the presence of higher-permeability reservoir zones is therefore a critical exploration problem in these successions.</p><p>Quartzitic sands have been discovered in places, especially for example in the Trent field (block 43/24), where physical reworking of sands during the transgressions that preceded the deposition of marine bands removed much of the feldspar, so that less clay was formed during burial diagenesis. Although these sandstones display moderately elevated permeabilities, commonly several to several tens of millidarcies, they are usually fine-grained, which limits their reservoir potential.</p><p>A particular type of quartzitic sandstone reservoir has been identified quite widely within the Namurian and lower Westphalian succession of the Southern North Sea. This type is indistinguishable in terms of sedimentology and inferred detrital composition from the originally feldspathic facies which now form the widespread kaolinite-rich, low-permeability sandstones. However, it has a very low kaolinite content (commonly 1-2%, compared with a more usual 5-20%) so that these sandstones display permeabilities of the order of several hundred millidarcies.</p><p>Wireline log data from nineteen wells within UK Quadrants 43 and 44 have been examined, and all relevant core logged in order to compare the depositional settings of the quartzitic and non-quartzitic sandstones. Existing data from over 500 petrographic thin sections from the area have been reviewed and 78 new thin sections analysed to determine the petrographic controls on reservoir quality in both sandstone types. The diagenetic histories of each type have been interpreted. The dissolution of feldspars during diagenesis of the quartzitic sandstones, without a substantial residue of kaolinite or other aluminium-rich mineral, is attributed to the mobilisation of aluminium within organic complexes. This is thought to require the presence of certain organic acids.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"363-393"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48430927","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 AGE, ORIGIN AND CONTEXT OF RESERVOIR SANDSTONES UNDERLYING THE LOWERMOST SILURIAN “HOT” SHALES IN THE WEST OF THE SULTANATE OF OMAN","authors":"A.S.M. Al Ghafri,&nbsp;A.P. Heward,&nbsp;G.A. Booth,&nbsp;I.A. Abbasi","doi":"10.1111/jpg.12823","DOIUrl":"10.1111/jpg.12823","url":null,"abstract":"<p>The age and origin of reservoir sandstones which underlie the lowermost Silurian “hot” shales of the Sahmah Formation in the west of Oman is controversial. Here we describe one such sandstone which was cored and interpreted based on geological well evidence, and which then had to be re-interpreted when definitive palynological results became available. The findings are enhanced when interpreted along with other deep wells in the area which have consistent palynological data.</p><p>The western part of the Sultanate of Oman is a tectonically stable intra-basinal high with low regional dips. In this area, the relief on the base-Silurian unconformity of &gt;250 m appears to be greater than that beneath the Permo-Carboniferous unconformity which is well known for being highly erosive. The sandstones preserved beneath the base-Silurian unconformity vary in depositional environment and reservoir quality from well to well, depending on their age, degree of erosion and differences in regional subsidence.</p><p>There has been little evidence for the presence of Hirnantian-aged deposits in Oman to date. However, some of the erosion and deep incisions which affect deposits of the Upper Ordovician Hasirah Formation are almost certainly related to falling sea levels accompanying the Hirnantian glaciation, just as the presence of the “hot shale” source rocks in the overlying Sahmah Formation are likely to be related to rising sea-levels and anoxic conditions during the later deglaciation. Deformed strata in the Upper Ordovician deposits may reflect the instability of valley-sides cut into weakly-consolidated strata exposed during changes in sea-level.</p><p>The Sahmah oil play underlying the basal Silurian “hot” shales in Oman carries significant risks relating to the presence or absence of closures and reservoir, and the character, continuity and cementation of reservoir sandstones.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"345-362"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45648914","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":"ELECTROFACIES DEFINITION AND ZONATION OF THE LOWER CRETACEOUS BARRA VELHA FORMATION CARBONATE RESERVOIR IN THE PRE-SALT SEQUENCE OF THE SANTOS BASIN, SE BRAZIL","authors":"M. Molina Camargo,&nbsp;G. F. Chinelatto,&nbsp;M. Basso,&nbsp;A. C. Vidal","doi":"10.1111/jpg.12827","DOIUrl":"10.1111/jpg.12827","url":null,"abstract":"<p>Lower Cretaceous carbonates in the pre-salt succession in the Santos Basin, eastern Brazil, are highly heterogeneous in terms of their reservoir characteristics as a result of depositional and diagenetic factors. Electrofacies have widely been used for reservoir zonation and, when allied with computer-based methods such as neural networks, may help with the study of such complex reservoir rocks and with the identification of high-quality reservoir zones. In this work, an unsupervised artificial neural network known as a self-organizing map (SOM) was used to carry out a zonation of the pre-salt carbonates in the Aptian Barra Velha Formation, the main reservoir unit in the Santos Basin. Available data included gramma-ray, neutron porosity, resistivity deep, sonic, density, photoelectric factor, total porosity and effective porosity profiles from 21 wells together with mineralogical models. Core descriptions and thin section images were used as additional data for the lithological characterization of the electrofacies and consequently for reservoir zonation. A total of four electrofacies were defined from the SOM application, and five reservoir zones were identified.</p><p>The characterization of the reservoir zones also considered the structural locations of the wells based on the relative depth to top- Barra Velha Formation; well locations were classified as structurally high, intermediate or low. Based on the reservoir zone characteristics, the results could be correlated with zonations in previous studies. A general tendency was noted for there to be an increase of finer-grained sediments in the formation in wells located in structural lows; packstone and mudstone facies were prevalent in these wells and were in general characterized as poor-quality reservoir rocks. By contrast, the shrubstones and grainstones which were more frequent in structurally high wells comprised higher quality reservoir rocks.</p><p>The basal reservoir zone showed wide lithological variation compared to the overlying reservoir zones. Grainstone-dominated facies were identified in the middle of the formation, and the uppermost reservoir zones were characterized by an upward increase in shrubstones and reworked grainstones which in general pointed to better quality reservoirs.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"439-459"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49660597","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":"SOURCE ROCK POTENTIAL OF THE UPPER TRIASSIC CHANG 7 MEMBER IN THE WESTERN ORDOS BASIN, CHINA","authors":"Guo Chen,&nbsp;Ning Wang,&nbsp;Shuai Yang,&nbsp;Xiaofeng Li,&nbsp;Pengfei Zhang,&nbsp;Yanqing Su","doi":"10.1111/jpg.12825","DOIUrl":"10.1111/jpg.12825","url":null,"abstract":"<p>The Chang 7 member of the Upper Triassic Yanchang Formation is an important source rock in the Ordos Basin, NW China. Previous studies of the unit have in general focused on the relatively deep-water (∼25 m) anoxic, OM-rich lacustrine mudstones which form the main Mesozoic source rock at fields in the south of the basin. However, this paper presents an integrated geochemical investigation of the relatively shallow-water Chang 7 facies in a study area around Jiyuan field in the western part of the basin in order to evaluate its source rock potential. The results show that the Chang 7 source rock in the study area has a high content of Type II OM, and is interpreted to have been deposited in a suboxic-anoxic lacustrine setting with a mixed input of aquatic and terrigenous organic matter. The results of 1D modelling of a well in the study area showed that the Chang 7 member entered the oil generation window from the Middle Jurassic. Oil-oil correlations based on hierarchical cluster analysis and correspondence analysis showed that crude oils generated by deep-water Chang 7 source rocks from wells in the south of the basin can be distinguished from Soxhlet-extracted petroleum from reservoir sandstones in the study area. The compositional differences are inferred to be due to variations in source rock facies compositions. An oil – source rock correlation study showed that the shallower-water Chang 7 source rock in the western part of the basin generated the hydrocarbons in core extracts of reservoir sandstones from wells in this area. The shallow-water Chang 7 facies may therefore constitute an effective oil-prone source rock in the western Ordos Basin.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"395-415"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45362239","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":"GEOCHEMICAL ANALYSES OF SEEP OILS IN THE SOUTHERN GAFSA BASIN, SW TUNISIA: REASSESSMENT OF REGIONAL HYDROCARBON POTENTIAL","authors":"Kamel Dadi,&nbsp;Riadh Ahmadi,&nbsp;Anis Belhaj Mohamed,&nbsp;Chaouki Khalfi,&nbsp;Najwa Mbarki,&nbsp;Jamel Abdennaceur Ouali","doi":"10.1111/jpg.12826","DOIUrl":"10.1111/jpg.12826","url":null,"abstract":"<p>The recent discovery of surface oil seeps in the Tamerza area in the west-central Gafsa Basin (southern Tunisia) has prompted a re-evaluation of the hydrocarbon potential of the region. In this paper, we report the results of analyses of seep oils by Rock-Eval pyrolysis (n = 6) and gas chromatography – mass spectrometry (n = 4). The goals of the study were to assess the composition of the seep oils, to investigate the relationship between the seep oils and potential source rocks, and to highlight the significance of the seep oils for oil exploration in the region.</p><p>In the Tamerza area, surface oil seeps have been recorded in numerous formations ranging between the Upper Cretaceous Abiod Limestone Formation and the lower Miocene Sehib Siltstone Formation. The results of this study showed that all the seep oil samples analysed in general had a similar geochemical fingerprint: for example, Pr/Ph values are lower than 1; a plot of Pr/n-C₁₇ (0.27- 0.36) versus Ph/n-C₁₈ (0.3-0.8) indicates a marine source rock deposited under reducing anoxic conditions; and Ts/(Ts+Tm) ratios indicate that the source rock was thermally mature. Correlation studies suggest that the oils originated from Cenomanian-Turonian shales corresponding to the informally-named Bahloul equivalent formation. Oil expulsion from this source rock at the seep locations is inferred to have ended by middle Miocene time. However the main phase of folding occurred here in the Pliocene – early Quaternary, and the resulting anticlinal folds are not therefore prospective structural traps for hydrocarbons because they developed after migration had already ceased. Stratigraphic traps and salt structures in the region may be of greater exploration interest.</p><p>A surface oil seep sample was also recovered from the Quaternary upper Segui Formation at Jebel Orbata in the east of the Gafsa Basin. Analysis of this oil sample showed that it has similar geochemical characteristics to the seep oils from the Tamerza area, but that it appears to have had a much more recent migration history. In the eastern Gafsa Basin, Pliocene – early Quaternary anticlinal structures could therefore constitute effective structural traps charged by the same Bahloul equivalent formation source rock.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"417-437"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43222112","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":"Index of editorial contents, JPG vol. 45, 2022","authors":"","doi":"10.1111/jpg.12828","DOIUrl":"10.1111/jpg.12828","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"462-465"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44823591","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":"Inferior Liver Transplant Outcomes during early COVID-19 pandemic in United States.","authors":"Kenji Okumura, Seigo Nishida, Hiroshi Sogawa, Gregory Veillette, Roxana Bodin, David C Wolf, Abhay Dhand","doi":"10.1016/j.liver.2022.100099","DOIUrl":"10.1016/j.liver.2022.100099","url":null,"abstract":"<p><strong>Background: </strong>: Since its declaration as a global pandemic on March11^th 2020, COVID-19 has had a significant effect on solid-organ transplantation. The aim of this study was to analyze the impact of COVID-19 on Liver transplantation (LT) in United States.</p><p><strong>Methods: </strong>: We retrospectively analyzed the United Network for Organ Sharing database regarding characteristics of donors, adult-LT recipients, and transplant outcomes during early-COVID period (March 11- September 11, 2020) and compared them to pre-COVID period (March 11 - September 11, 2019).</p><p><strong>Results: </strong>: Overall, 4% fewer LTs were performed during early-COVID period (4107 vs 4277). Compared to pre-COVID period, transplants performed in early-COVID period were associated with: increase in alcoholic liver disease as most common primary diagnosis (1315 vs 1187, <i>P</i>< 0.01), higher MELD score in the recipients (25 vs 23, <i>P</i><0.01), lower time on wait-list (52 vs 84 days, <i>P</i><0.01), higher need for hemodialysis at transplant (9.4 vs 11.1%, <i>P</i>=0.012), longer distance from recipient hospital (131 vs 64 miles, <i>P</i><0.01) and higher donor risk index (1.65 vs 1.55, <i>P</i><0.01). Early-COVID period saw increase in rejection episodes before discharge (4.6 vs 3.4%, <i>P</i>=0.023) and lower 90-day graft/patient survival (90.2 vs 95.1 %, <i>P</i><0.01; 92.2 vs 96.5 %, <i>P</i><0.01). In multivariable cox-regression analysis, early-COVID period was the independent risk factor for graft failure at 90-days post-transplant (Hazard Ratio 1.77, <i>P</i><0.01).</p><p><strong>Conclusions: </strong>: During early-COVID period in United States, overall LT decreased, alcoholic liver disease was primary diagnosis for LT, rate of rejection episodes before discharge was higher and 90-days post-transplant graft survival was lower.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"19 1","pages":"100099"},"PeriodicalIF":0.0,"publicationDate":"2022-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.ncbi.nlm.nih.gov/pmc/articles/PMC9110062/pdf/","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85322470","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}