Petroleum Research最新文献

{"title":"Modeling environmental sensitivity and risk assessment of PAHs in sediments along two marine coastal areas in Egypt","authors":"Muhammad A. El-Alfy","doi":"10.1016/j.ptlrs.2023.05.012","DOIUrl":"10.1016/j.ptlrs.2023.05.012","url":null,"abstract":"<div><p>Modeling the environmental sensitivity index (ESI) is vital in the planning and management processes, especially along the coastal areas. The main objectives of the study were to define the main sources of polycyclic aromatic hydrocarbons (PAHs), establish an ESI model, and measure the risk of PAHs on humans and the environment using various equations. The methodology of the research involved analyzing PAHs according to the EPA 550 methodology in sediments of the coastline in two important coastline areas in Egypt, namely the Gulf of Suez and the Mediterranean Sea, modeling the sensitivity of PAHs using ArcGIS 10.5 by integrating different physical, biological, and land use/cover factors, identifying the sources, and performing a risk assessment. Nine sediment samples were collected from each area. The produced sensitivity map could explain the highly sensitive areas along the Mediterranean Sea and Gulf of Suez coastlines (especially areas that were near drains' outlets, industrial sites, and sea ports). The highest mean PAH concentrations were Acenaphthylene and Fluorine in the Mediterranean Sea and Suez Gulf, respectively. It's obvious that the individual PAH concentrations were within the ERL, ERM, and PEL threshold limits, indicating no adverse biological impacts. The ratios of BaA/BaA + Chy, Flu/Flu + Py, and Ant/Ant + Phe gave an indication that most PAH sources were petrogenic (63.64%) and others (36.36%) were from petroleum combustion. The principle component analysis (PCA) indicated a diverse correlation among the isomer ratios and LU/LC activities. The carcinogenic risk values were in the very low category (&lt;10⁻⁶) for both children and adults. The most significant contributors to carcinogenicity were IP and BkFlu in the Mediterranean Sea and Suez Gulf, respectively. Increasing sources of carbon in seawater, especially with climatic change, may impact the aquatic environment and have impacts on organisms and coral reefs. So it is highly recommended to keep shorelines and seawater free of oil spillage activities along the coastal areas or take actions towards this.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"9 1","pages":"Pages 125-142"},"PeriodicalIF":0.0,"publicationDate":"2024-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000327/pdfft?md5=18505b09a7bceebd5bf8c122a793420b&pid=1-s2.0-S2096249523000327-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135255210","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Inhibition of asphaltene deposition by Al2O3 nanoparticles during CO2 injection","authors":"Ali Amraeiniya ,&nbsp;Alireza Rahimi ,&nbsp;Nadia Nikpour ,&nbsp;Siamand Salimi Baneh ,&nbsp;Farid Arabzadeh ,&nbsp;Mehdi Razavifar","doi":"10.1016/j.ptlrs.2023.03.001","DOIUrl":"10.1016/j.ptlrs.2023.03.001","url":null,"abstract":"<div><p>Carbon dioxide flooding is of interest due to its high oil-sweep efficiency for enhanced oil recovery and contribution to the reduction of greenhouse gas emissions. However, when CO₂ is injected into deep geological strata, asphaltene may precipitate. In this work, the effect of Al₂O₃ nanoparticles on the deposition of asphaltene was examined by assessing the variations of bond number and interfacial tension at different pressures and a temperature of 60 °C. The asphaltene onset point and intensity were characterized using the bond number, which proved a better indicator of changes in oil droplet shape and interfacial tension with gravity. Synthesized mixtures of toluene and <em>n</em>-heptane that contained two different kinds of asphaltenes were used as M and D oil samples. A 0.06 mass% addition of Al₂O₃ nanoparticles, which worked best for reduction of interfacial tension, was also applied at various pressures. Addition of nanoparticles to the oils prevented asphaltene precipitation in both synthetic samples by altering the slope of the plot of interfacial tension with pressure by 49.7% for the M sample and 9.0% for the D sample. The Al₂O₃ nanoparticles were found to be more effective at inhibiting asphaltene precipitation for the M oil sample due to its lower H/C ratio and higher nitrogen content.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 499-504"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000145/pdfft?md5=4dc952eaa5700e72c5d511ddc9d725ee&pid=1-s2.0-S2096249523000145-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42650599","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geochemical assessment of upper Cretaceous crude oils from the Iranian part of the Persian Gulf Basin: Implications for thermal maturity, potential source rocks, and depositional setting","authors":"Faramarz Talaie ,&nbsp;Ali Kadkhodaie ,&nbsp;Mehran Arian ,&nbsp;Mohsen Aleali","doi":"10.1016/j.ptlrs.2023.01.002","DOIUrl":"10.1016/j.ptlrs.2023.01.002","url":null,"abstract":"<div><p>The Upper Cretaceous carbonate successions of the Sarvak Formation host giant oil reservoirs in the Persian Gulf. In this research, a total of 28 oil samples from nine oilfields located in the western, central and eastern parts of the Persian Gulf region were studied to determine the genetic relationships of oils, depositional setting of possible source rocks, thermal maturity, and source-rock ages in the Persian Gulf basin. According to the measured geochemical data, the source rocks facies vary from marine carbonates and marl/carbonates in the central and eastern oilfields to shale/carbonates in the western oilfields. The Pr/Ph ratio, steranes and terpanes suggest anoxic to dysoxic conditions of the depositional environments. The depositional environments experienced both low water stratification/low salinity and normal salinity/unstratified conditions. Evaluation of the saturated and aromatic biomarkers shows that all oil samples are mature and most of the source rocks lie within the beginning of the oil-generation window. The thermal maturity of the central oilfields is higher than that of the other samples, and has gone beyond the oil-generation stage. The C₂₈/C₂₉ steranes ratio suggest that the central oilfields of the Persian Gulf have Paleozoic and Jurassic source rocks, whereas the Sarvak reservoir in other parts of this region is sourced from Cretaceous carbonate rocks.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 455-468"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000029/pdfft?md5=7e5f9c55393f1baa1fe4bcd0341498ae&pid=1-s2.0-S2096249523000029-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44185011","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental study on modification of water-based filtercake to improve the bonding strength at the wellbore cement-formation interface","authors":"Kevin Nsolloh Lichinga","doi":"10.1016/j.ptlrs.2022.10.002","DOIUrl":"10.1016/j.ptlrs.2022.10.002","url":null,"abstract":"<div><p>The objective of this experimental study is to improve the cementing bond quality of sandstone oil-gas well along the wellbore cement-formation interface (WCFI), so as to ensure long-term zonal isolation throughout the lifecycle of the well by using NSO solution as filtercake modifier which was developed in the laboratory. According to designed experimental method and API RP 10, the effectiveness of filtercake modifier (NSO) on the bonding strength at the WCFI was assessed by using designed simulated wellbore as sandstone formation. The experimental results indicated that the samples which were treated with NSO solution had higher bond strength over untreated samples. The strength generally increased with curing period as for treated samples, 0.198, 0.374, 0.433 and 0.473 MPa for 3, 7, 15, and 30 days respectively while for the untreated samples the bond strength were 0.050, 0.070, 0.81 and 0.100 MPa for the same period. The water-based filtercake modification techniques had significantly enhanced the bonding strength of WCFI by increasing rates above 296%. Improvement of bond strength to the treated sample was due to filtercake modification as a result of formation of cementitious material as revealed in FTIR spectral such as Calcium-Silicate-Hydrate (C–S–H) and other geopolymers like Calcium-Aluminium-Silicate-Hydrate (C-A-S-H) and Sodium-Aluminium-Silicate-Hydrate (N-A-S-H)) along the interface which filled the existed pores hence reducing porosity hence high strength of bond. The low transmittance value for the NSO treated samples revealed that there were more cementitious materials existing at the WCFI which led to improvement of bonding strength as compared to the untreated samples. The lower/poor bond strength for the untreated samples is due to existence of untreated, thick water-based filtercake films at WCFI, which prevented the complete hydration process between rock grains and cement slurry components to make chemical binder of cement slurry material and formation.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 531-540"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249522000667/pdfft?md5=581f8ebaa157869b2590e11c90172853&pid=1-s2.0-S2096249522000667-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43571396","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigating tight oil reservoir production performance: Influence of geomechanical parameters and their distribution","authors":"Sameera M. Hamd-Allah,&nbsp;Nagham Jasim Al-Ameri","doi":"10.1016/j.ptlrs.2023.05.002","DOIUrl":"10.1016/j.ptlrs.2023.05.002","url":null,"abstract":"<div><p>Geomechanical properties have a prominent influence on reservoir stresses, which consequently reduce permeability and porosity with pressure depletion. These properties significantly affect the accuracy of reservoir modeling and recovery calculation, but have not been fully studied; therefore, more work is needed. Full field data and laboratory measurements are included in the study. The work involves deriving an equation by combining experimental data for permeability and porosity reduction during a change in stress with the poroelastic stress equation to investigate the impact of Poisson's ratio and Young's modulus on the reduction of permeability and porosity with pressure depletion. Most simulation studies assume constant geomechanical properties across the entire reservoir or for each individual reservoir layer. In this study, three approaches were considered for the Poisson's ratio and Young's modulus in the reservoir model: 1) constant average values assigned to the entire reservoir, 2) constant average values assigned to each layer, and 3) constant values assigned to each grid block. The validity of the model results was checked by history matching with production and pressure data. For the studied tight reservoir, the Poisson's ratio and Young's modulus significantly affected the permeability and porosity reduction with pressure depletion. The impact of Young's modulus was more pronounced than Poisson's ratio. The simulation results for oil rate, cumulative oil production, and water cut for the reservoir and a selected well showed that applying the three suggested geomechanical approaches resulted in a substantial discrepancy in the model outcome. In general, the coupled model with the mapped geomechanical properties resulted in lower oil and water production. This is attributed to the large values of mapped Young's modulus in parts of the reservoir which resulted in large permeability reduction and subsequently lower oil and water production is expected. In contrast lower Young's modulus per layer was obtained due to averaging process. Poisson's ratio effect on fluid production is much less significant due to its small effect on permeability reduction with depletion. Similarly, the adoption of different geomechanical property values for each layer yielded a relatively lower production outcome than when using a constant value for the entire reservoir. The study indicates the importance of considering the detailed description of the reservoir geomechanical properties to obtain reliable simulation results.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 490-498"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000212/pdfft?md5=fc4e4e7a1173526dfd78d28fcf14a557&pid=1-s2.0-S2096249523000212-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42071672","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Uncertainty quantification in the Permian Basin using conventional and modified bootstrap methodology","authors":"Chukwuemeka O. Okoli ,&nbsp;Scott D. Goddard ,&nbsp;Obadare O. Awoleke","doi":"10.1016/j.ptlrs.2023.06.001","DOIUrl":"10.1016/j.ptlrs.2023.06.001","url":null,"abstract":"<div><p>Various uncertainty quantification methodologies are presented using a combination of several deterministic decline curve analysis models and two bootstrapping algorithms. These probabilistic models are applied to 126 sample wells from the Permian basin. Results are presented for 12–72 months of production hindcast given an average well production history of 103 months. Based on the coverage rate and the forecast error (with the coverage rate being more significant in our choice of the best probabilistic models) and using up to one-half of the available production history for a group of sample wells from the Permian Basin, we find that the CBM-SEPD combination is the best probabilistic model for the Central Basin Platform, the MBM-Arps combination is the best probabilistic model for the Delaware Basin, the CBM-Arps is the best probabilistic model for the Midland Basin, and the best probabilistic model for the overall Permian Basin is the CBM-Arps when early time data is used as hindcast and CBM-SEPD for when one-quarter to one-half of the data is used as hindcast. When three-quarters or more of the available production history is used for analysis, the MBM-SEPD probabilistic model is the best combination in terms of both coverage rate and forecast error for all the sub-basins in the Permian. The novelty of this work lies in its extension of bootstrapping methods to other decline curve analysis models. This work also offers the engineer guidance on the best choice of probabilistic model whilst attempting to forecast production from the Permian Basin.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 439-454"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000340/pdfft?md5=b3656898eaccba3d028a4388cf082890&pid=1-s2.0-S2096249523000340-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48338809","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Understanding pore characteristics through core-based petrographic and petrophysical analysis in a heterogeneous carbonate reservoir: A case study from the Mumbai Offshore Basin, India","authors":"Ilius Mondal,&nbsp;Kumar Hemant Singh","doi":"10.1016/j.ptlrs.2023.04.001","DOIUrl":"10.1016/j.ptlrs.2023.04.001","url":null,"abstract":"<div><p>Carbonate rocks exhibit complex and heterogeneous pore structures; such heterogeneity is manifested by the occurrence of a wide variety of pore types with different sizes and geometries as a result of depositional and diagenetic processes. These complications substantially increase the uncertainty of predicted rock hydraulic parameters because samples with comparable porosities might have very different permeability values. In this study, small-scale characterisation of porosity and permeability in heterogeneous Eocene limestone samples from the Bassein Formation of the B-X structure of the MK Field in Mumbai Offshore Basin, India, was carried out, employing an integrated framework that incorporates thin-section petrography, routine core analysis, mercury injection capillary pressure and nuclear magnetic resonance data. The pore characteristics of these carbonates range from poor to excellent. The studied samples exhibited large ranges of porosity, permeability and other associated petrophysical attributes. The pore types, as well as their orientations and connectivity, are the primary factors causing the heterogeneity. Because of the complexity of the pore networks, a simple lithofacies classification alone would have been insufficient to link porosity and permeability. The reservoir characteristics in the study area are strongly linked to the development and/or destruction of reservoir porosity–permeability during different phases of diagenesis. Twenty-four carbonate core samples from the limestone unit were studied and classified into microfacies and pore type classes, producing an accurate assessment of reservoir attributes. The comprehensive workflow incorporates the pore volume distributions and pore throat attributes for each rock type. Three carbonate microfacies were identified by petrographic analysis and their petrophysical characteristics, such as porosity, permeability, pore throat size, pore volume and fluid flow factors, were measured. The study demonstrates how macroporosity, mesoporosity and microporosity are associated with various rock types and how they affect permeability and cementation exponents. The results of this study provide a comprehensive experimental framework for geological and geophysical interpretation that can be applied to identify potential reservoir facies and strengthen our understanding of heterogeneous carbonates. The framework can also be used to guide reservoir evaluation of similar heterogeneous formations in other areas.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 469-480"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000182/pdfft?md5=82202cb3f5759abb218ffcdadfe2d531&pid=1-s2.0-S2096249523000182-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44948564","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Rheology and lubricity characteristics study at different temperatures using synthesized SnO2 nanoparticles in KCl free bentonite water base mud","authors":"A.B.M. Ariful Bari Khandaker ,&nbsp;Nayem Ahmed ,&nbsp;Md Saiful Alam","doi":"10.1016/j.ptlrs.2023.03.003","DOIUrl":"10.1016/j.ptlrs.2023.03.003","url":null,"abstract":"<div><p>Drilling mud is a major concerning element due to its high operational and economic impact on the drilling process. Various additives are introduced to enhance the efficiency of drilling fluid, but none of them could perfectly achieve their proposed efficacy in drilling operations. Researchers conceived several nanoparticles (NPs) in drilling fluid to dissolve this issue. In a singular instance, commercial tin oxide (SnO₂) nanoparticles were utilized to analyze the influence of NPs on the rheological and filtration properties of inorganic KCl salt-based drilling fluid. However, the effect of SnO₂ NPs on mud lubricity characteristics is not studied previously. However, due to the hazardous behavior of KCl, its use is very limited. Thus, we consider a KCl-free bentonite water-based mud to avoid any environmental damages from drilling operations. We also use SnO₂ NPs that is synthesized in our laboratory by co-precipitation method. In addition to rheological and filtration properties, we also investigate the effect of NPs on mud's lubricity that was not considered in the previous study. Drilling fluid properties are measured at five different NPs concentrations of 0.10, 0.25, 0.50, 0.75 &amp; 1.0 wt%, and at six different temperatures of 30, 40, 50, 60, 70, and 80 °C, while filtration properties are measured using API low-pressure low temperature (LPLT) condition. The addition of 0.1 wt% SnO₂ NPs increases plastic viscosity, yield point, 10 s gel strength, and 10 min gel strength by 10%, 63%, 20%, and 14%, respectively. The maximum reduction in lubricity coefficient is found to be 14% at NPs concentration of 1.0 wt%. The NPs concentration of 0.5 wt% yielded a reduction in fluid loss and mud cake thickness by 8.1% and 34%, respectively. The study suggests that SnO₂ NPs can be employed as an additive to improve the rheology, lubricity, and filtration properties of KCl-free bentonite water-based drilling mud.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 541-549"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000169/pdfft?md5=24b8b9380e7731bd858949b9ab5c41ea&pid=1-s2.0-S2096249523000169-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"54962249","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Combining indicators analysis and chemometrics to trace the geographical origin of crude oil","authors":"Tong Li,&nbsp;Detian Yan,&nbsp;Wenjie Liang,&nbsp;Xiaosong Wei","doi":"10.1016/j.ptlrs.2023.05.001","DOIUrl":"https://doi.org/10.1016/j.ptlrs.2023.05.001","url":null,"abstract":"<div><p>Geographic traceability is crucial to global oil trade security. This study discusses the possibility of using multivariate statistical methods combined with multi-indicator analysis to identify samples of crude oil imports from five major countries to China. The physicochemical properties and trace elements of crude oil were detected by Petroleum product standards and inductively coupled plasma atomic emission spectrometry (ICP-AES). Eight indexes (moisture, density, sulfur content, acid value, organochlorine, carbon residual, V, and Ni) were analyzed. Principal component analysis (PCA), hierarchical clustering analysis (HCA), Orthogonal projections to lateen structures-discriminant analysis (OPLS-DA), and other multivariate data analysis methods were used to determine the geographical origin of crude oil samples. Satisfying results have been obtained using PCA to reduce the dimensions of the indicators of crude oil from different origins. It allows the reduction of 8 variables to 3 principal components and accounts for 80.06% of the total variance. The HCA shows five clusters corresponding to five sources of crude oil. This will help to improve the utilization rate of crude oil with different characteristics, improve the quality of crude oil trade, and ensure the high quality of crude oil trade. For the sample set used for modeling, the model's accuracy was 97.19% after OPLS-DA optimization. These results show that the combination of multi-index analysis and stoichiometry is an effective tool for identifying crude oil origin, which fills the technical gap in the rapid identification of crude oil origin.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 524-530"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000200/pdfft?md5=a742d26475649bb8de0d532a13c100ab&pid=1-s2.0-S2096249523000200-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138656126","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermal oil recovery factors from sandpacks of variable mineralogy","authors":"Viacheslau Y. Kudrashou ,&nbsp;Hisham A. Nasr-El-Din","doi":"10.1016/j.ptlrs.2023.06.002","DOIUrl":"10.1016/j.ptlrs.2023.06.002","url":null,"abstract":"<div><p>Steam injection is commonly used for production of viscous crude oil. Reservoir rock often contains clay minerals. Reactive nature of steam and clay minerals may lead to formation damage. This work investigates oil recovery and changes in petrophysical properties as a function of the mineralogy. Sandpacks with quartz, calcite, feldspar, kaolinite, smectite, and illite were prepared for steam injection experiments. Permeability of the steamed sandpacks was determined using coreflood experiments. Chemical composition of the produced aqueous samples was determined using ICP-OES (inductively coupled plasma-optical emission spectroscopy). Morphology of the rock samples was studied using SEM-EDS (scanning electron microscope-energy dispersive X-ray spectroscopy). Mineralogy and elemental content of the solid samples were determined using XRD (X-ray diffraction) analysis and XRF (X-ray fluorescence) respectively. It was found that aqueous phase samples produced from clay-rich sandpacks tend to have higher pH than samples produced from samples without clay minerals. Oil recovery factors for 100% quartz case was determined to be 65 wt%. Calcite- and feldspar-rich sandpacks produced 56 and 61 wt% of oil respectively. Sandpacks with clay fractions have shown the lowest oil recovery – 39, 29, and 28 wt% for kaolinite-, smectite-, and illite-rich samples respectively. Mineral dissolution and precipitation were the dominant damaging mechanism for quartz and calcite cases. Feldspar-rich sandpack demonstrated signs of structural destruction of the mineral and fines release. Kaolinite's effect on oil recovery was found to be associated with fines migration. Smectite hydration and swelling in presence of steam was the dominant formation damage effect on the oil production. Steam interaction with illite-rich sandpack caused formation of amorphous silica. This paper presents oil recovery factors as a function of injected pore volume (PV) of steam for sandpacks of different mineralogy. Obtained results characterize petrophysical changes caused by steam interaction with minerals in presence of oil. This data provides insights into effects of steam on minerals with different structures and properties.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 4","pages":"Pages 481-489"},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249523000479/pdfft?md5=31dba2f37a4fb1bd4a65abad11fbb5c6&pid=1-s2.0-S2096249523000479-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47021609","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}