Petroleum Science最新文献

{"title":"Impact of temperature and salinity on fines detachment: AFM measurements and XDLVO theory","authors":"Wei-Feng Yuan ,&nbsp;Yu-Long Yang ,&nbsp;Lu Yuan ,&nbsp;Ji-Rui Hou","doi":"10.1016/j.petsci.2024.09.017","DOIUrl":"10.1016/j.petsci.2024.09.017","url":null,"abstract":"<div><div>Fine particle detachment and subsequent migration can lead to severe pore plugging and consequent permeability decline. Therefore, it is crucial to quantify the critical condition when fine particle detachment occurs. The frequently observed deviations or even contradictions between experimental results and theoretical predictions of fines detachment arise from an insufficient understanding of adhesion force that can be highly influenced by salinity and temperature. To clarify the intrinsic influence of salinity and temperature on fines detachment, adhesion forces between carboxyl microspheres and hydrophilic silica substrates in an aqueous medium were measured at various salinities and temperatures using atomic force microscopy (AFM). The AFM-measured adhesion force decreases with increasing salinity or temperature. Trends of mean measured adhesion forces with temperature and salinity were compared with the DLVO and XDLVO theories. DLVO theory captured the trend with temperature <em>via</em> the impact of temperature on electric double layer interactions, whereas XDLVO theory captured the observed trend with salinity <em>via</em> the impact of salinity on the repulsive hydration force. Our results highlight the significance of hydration force in accurately predicting the fate of fines in porous media.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 1","pages":"Pages 338-347"},"PeriodicalIF":6.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143137166","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Adsorption and retention of fracturing fluid and its impact on gas transport in tight sandstone with different clay minerals","authors":"Yi-Jun Wang ,&nbsp;Li-Jun You ,&nbsp;Jian Yang ,&nbsp;Yi-Li Kang ,&nbsp;Ming-Jun Chen ,&nbsp;Jia-Jia Bai ,&nbsp;Jian Tian","doi":"10.1016/j.petsci.2024.09.012","DOIUrl":"10.1016/j.petsci.2024.09.012","url":null,"abstract":"<div><div>To elucidate the adsorption characteristics and retention mechanisms of fracturing fluids in diverse clay minerals, we conducted on-line nuclear magnetic resonance (NMR) and atomic force microscopy (AFM) experiments. The depth and extent of solid phase damage are determined by the ratio between the size of fine fractions in fracturing fluid residue and the pore-throat size in experiments. Poor physical properties (<em>K</em> &lt; 0.5 mD) result in a more preferential flow pathway effect during flowback, and the stepwise incremental pressure differential proves to be more effective for the discharge of fracturing fluid in submicron pore throats. The permeability is significantly influenced by the differential distribution of retained fracturing fluid, as supported by direct experimental evidence. The presence of good physical properties (<em>K</em> &gt; 0.5 mD) combined with a scattered distribution of retained fracturing fluid is associated with high gas phase recovery permeability, whereas a continuous sheet-like distribution results in low recovery permeability. The expansive surface area and presence of filamentous illite minerals facilitate the multiple winding and adsorption of fracturing fluids, demonstrating strong hydrogen-bonding, multi-layering and multiple adsorption properties. The geological characteristics of the main gas formations exhibit significant variation, and the severity of damage caused by fracturing fluids occurs in diverse sequences. To address this issue, a differentiated strategy for optimizing fracturing fluids has been proposed.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 1","pages":"Pages 370-383"},"PeriodicalIF":6.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143137167","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Insights into microscopic oil occurrence characteristics in shales from the Paleogene Funing Formation in Subei Basin, China","authors":"Jun-Jie Wang ,&nbsp;Peng-Fei Zhang ,&nbsp;Shuang-Fang Lu ,&nbsp;Zi-Zhi Lin ,&nbsp;Wen-Biao Li ,&nbsp;Jun-Jian Zhang ,&nbsp;Wei-Zheng Gao ,&nbsp;Neng-Wu Zhou ,&nbsp;Guo-Hui Chen ,&nbsp;Ya-Jie Yin ,&nbsp;Han Wu","doi":"10.1016/j.petsci.2024.07.025","DOIUrl":"10.1016/j.petsci.2024.07.025","url":null,"abstract":"<div><div>The microscopic occurrence characteristics primarily constrain the enrichment and mobility of shale oil. This study collected the lacustrine shales from the Palaeogene Funing Formation in the Gaoyou Sag, Subei Basin. Conventional and multistage Rock-Eval, scanning electron microscopy, and nuclear magnetic resonance (NMR) <em>T</em>₁–<em>T</em>₂ were performed to analyze the contents and occurrence characteristics of shale oil. Low-temperature nitrogen adsorption-desorption (LTNA/D) experiments were conducted on the shales before and after extraction. The relationships between shale oil occurrence with organic matter and pore structures were then discussed. Predominantly, the shale oil in the Funing Formation is found within fractures, with secondary occurrences in interparticle pores linked to brittle minerals and sizeable intraparticle pores associated with clay minerals. The selected shales can be categorized into two types based on the nitrogen isotherms. Type A shales are characterized by high contents of felsic and calcareous minerals but low clay minerals, with larger TOC and shale oil values. Conversely, Type B shales are marked by abundant clay minerals but diminished TOC and shale oil contents. The lower BET specific surface area (SSA), larger average pore diameter, and simpler pore surfaces and pore structures lead to the Type A shales being more conducive to shale oil enrichment and mobility. Shale oil content is predominantly governed by the abundance of organic matter, while an overabundance of organic matter typically equates to a reduced ratio of free oil and diminished fluidity. The BET SSA, volumes of pores less than 25 and 100 nm at extracted state all correlate negatively with total and adsorbed oil contents but display no correlation with free oil, while they have positive relationships with capillary-bound water. Consequently, pore water is mainly saturated in micropores (&lt;25 nm) and minipores (25–100 nm), as well as adsorbed oil, while free oil, i.e., bound and movable oil, primarily exists in mesopores (100–1000 nm) and macropores (&gt;1000 nm). These findings may enhance the understanding of the microscopic occurrence characteristics of shale oil and will contribute to guide resource estimation and shale oil sweet spot exploitation in the Gaoyou Sag, Subei Basin.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 1","pages":"Pages 55-75"},"PeriodicalIF":6.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143137218","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrating well logs, 3D seismic, and earthquake data for comprehensive prediction of 3D in-situ stress orientations: A case study from the Weiyuan area in the Sichuan Basin, China","authors":"Huan Cao ,&nbsp;Yang Zhao ,&nbsp;Hai-Chao Chen ,&nbsp;Le-Le Zhang ,&nbsp;Cheng-Gang Xian ,&nbsp;Ji-Dong Yang ,&nbsp;Lu Liu","doi":"10.1016/j.petsci.2024.07.015","DOIUrl":"10.1016/j.petsci.2024.07.015","url":null,"abstract":"<div><div>Determining the orientation of in-situ stresses is crucial for various geoscience and engineering applications. Conventional methods for estimating these stress orientations often depend on focal mechanism solutions (FMSs) derived from earthquake data and formation micro-imager (FMI) data from well logs. However, these techniques can be costly, depth-inaccurate, and may lack spatial coverage. To address this issue, we introduce the use of three-dimensional (3D) seismic data (active sources) as a lateral constraint to approximate the 3D stress orientation field. Recognizing that both stress and fracture patterns are closely related to seismic velocity anisotropy, we derive the orientation of azimuthal anisotropy from multi-azimuth 3D seismic data to compensate for the lack of spatial stress orientation information. We apply our proposed workflow to a case study in the Weiyuan area of the Sichuan Basin, China, a region targeted for shale gas production. By integrating diverse datasets, including 3D seismic, earthquakes, and well logs, we develop a comprehensive 3D model of in-situ stress (orientations and magnitudes). Our results demonstrate that the estimated anisotropy orientations from 3D seismic data are consistent with the direction of maximum horizontal principal stress (SHmax) obtained from FMIs. We analyzed 12 earthquakes (magnitude &gt; 3) recorded between 2016 and 2020 for their FMSs and compressional axis (P-axis) orientations. The derived SHmax direction from our 3D stress model is 110° ES (East-South), which shows excellent agreement with the FMSs (within 3.96°). This close alignment validates the reliability and precision of our integrated method for predicting 3D SHmax orientations.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 1","pages":"Pages 210-221"},"PeriodicalIF":6.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141850181","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mesoporous SiO2 nanoparticles with low surface energy and multi-level roughness as shale wellbore stabilizers in oil-based drilling fluid","authors":"Hong-Yan Du ,&nbsp;Kai-He Lv ,&nbsp;Jin-Sheng Sun ,&nbsp;Mei-Chun Li ,&nbsp;Yuan Geng ,&nbsp;Xian-Bin Huang ,&nbsp;Hao-Kun Shen ,&nbsp;Muhammad Arqam Khan","doi":"10.1016/j.petsci.2024.12.006","DOIUrl":"10.1016/j.petsci.2024.12.006","url":null,"abstract":"<div><div>Oil-based drilling fluids possess excellent properties such as shale inhibition, cuttings suspension, and superior lubrication, making them essential in the development of unconventional oil and gas reservoirs. However, wellbore instability, caused by the invasion of drilling fluids into shale formations, remains a significant challenge for the safe and efficient extraction of shale oil and gas. This work reports the preparation of mesoporous SiO₂ nanoparticles with low surface energy, utilized as multifunctional agents to enhance the performance of oil-based drilling fluids aimed at improving wellbore stability. The results indicate that the coating prepared from these nanoparticles exhibit excellent hydrophobicity and antifouling properties, increasing the water contact angle from 32° to 146° and oil contact angle from 24° to 134.8°. Additionally, these nanoparticles exhibit exceptional chemical stability and thermal resistance. Incorporating these nanoparticles into oil-based drilling fluids reduced the surface energy of the mud cake from 34.99 to 8.17 mJ·m⁻² and increased the roughness of shale from 0.26 to 2.39 μm. These modifications rendered the mud cake and shale surfaces amphiphobic, effectively mitigating capillary infiltration and delaying the long-term strength degradation of shale in oil-based drilling fluids. After 28 days of immersion in oil-based drilling fluid, shale cores treated with MF-SiO₂ exhibited a 30.5% increase in compressive strength compared to untreated cores. Additionally, these nanoparticles demonstrated the ability to penetrate and seal rock pores, reducing the API filtration volume of the drilling fluid from 11.2 to 7.6 mL. This study introduces a novel approach to enhance the development of shale gas and oil resources, offering a promising strategy for wellbore stabilization in oil-based drilling fluid systems.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"22 1","pages":"Pages 384-397"},"PeriodicalIF":6.0,"publicationDate":"2025-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143137186","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"OFC","authors":"","doi":"10.1016/S1995-8226(24)00318-2","DOIUrl":"10.1016/S1995-8226(24)00318-2","url":null,"abstract":"","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 6","pages":"Page OFC"},"PeriodicalIF":6.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143313680","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Sandstone breaking performances and mechanisms of swirling abrasive waterjet during radial jet drilling process","authors":"Huan Li,&nbsp;Jing-Bin Li,&nbsp;Chen-Rui Guo,&nbsp;Hao Wang,&nbsp;Rui Li,&nbsp;Zhong-Wei Huang","doi":"10.1016/j.petsci.2024.05.028","DOIUrl":"10.1016/j.petsci.2024.05.028","url":null,"abstract":"<div><div>Radial jet drilling (RJD) is one of the emerging hydrocarbon drilling technologies. And, the swirling abrasive waterjet (SAWJ) is expected to drill larger diameter laterals during RJD. Here, the performances and mechanisms of SAWJ breaking sandstone were studied by laboratory experiments. Results showed that the SAWJ could drill a smooth (surface roughness was 0.043 mm) &amp; large (diameter was in 52.0–73.0 mm) circular hole on sandstone. The hole depth/volume increased as the jetting pressure, abrasive mass concentration and exposure time increased. Conversely, they decreased as the standoff distance increased. The optimal parameter combination under our experimental conditions was 30 MPa, 0 mm, 12% and 1 min. The SAWJ sandstone breaking mechanism were the erosion of cements, the integrally peeled off and broken of crystal grain. Failure mode of sandstone was mainly the tensile fracture. The key findings will provide guidance for the application of SAWJ in RJD technology.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 6","pages":"Pages 4298-4310"},"PeriodicalIF":6.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141274385","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Statistical assessment of the financial performance of shale-gas wells coupling stochastic and numerical simulation","authors":"Andres Soage ,&nbsp;Luis Ramirez ,&nbsp;Ruben Juanes ,&nbsp;Luis Cueto-Felgueroso ,&nbsp;Ignasi Colominas","doi":"10.1016/j.petsci.2024.07.018","DOIUrl":"10.1016/j.petsci.2024.07.018","url":null,"abstract":"<div><div>We present a new methodology to statistically determine the net present value (NPV) and internal rate of return (IRR) as financial estimators of shale gas investments. Our method allows us to forecast, in a fully probabilistic setting, financial performance risk and to understand the importance of the different factors that impact investment. The methodology developed in this study combines, through Monte Carlo simulation, the computational modeling of gas production from shale gas wells with a stochastic simulation of gas price as a geometric Brownian motion (GMB). To illustrate the methodology's validity, we apply it to an analysis of investments in shale gas wells. Our results show that gas price volatility is a key variable in the performance of an investment of this type, in such a way that at high volatilities, the potential return on an investment in shale gas increases significantly, but so do the risks of economic loss. This finding is consistent with the history of shale gas operations in which huge investment successes coexist with unexpected investment failures.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 6","pages":"Pages 4497-4511"},"PeriodicalIF":6.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141853956","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The evolution of clay mineral and its indication of hydrocarbons under overpressure: An example from the shale of the Qingshankou formation in the Gulong Sag","authors":"Yuan Kang ,&nbsp;Kou-Qi Liu ,&nbsp;Ru-Kai Zhu ,&nbsp;Ge-Ge Yin ,&nbsp;Jing-Ya Zhang ,&nbsp;Su-Rong Zhang","doi":"10.1016/j.petsci.2024.07.007","DOIUrl":"10.1016/j.petsci.2024.07.007","url":null,"abstract":"<div><div>The enrichment and development of shale oil are significantly influenced by the evolution of clay minerals. In this paper, the mineralogy and clay mineral crystallinity of shale samples from Wells X1, X2 and X3 in the Gulong Sag are characterized by X-ray diffraction analysis (XRD) and field emission scanning electron microscopy (FE-SEM). Geochemical parameters, including total organic carbon (TOC) and rock-eval pyrolysis, were also evaluated. The results reveal that illite in the shale primarily exists in the matrix, originating mainly from the transformation of smectite and I/S mixed layer. Chlorite in pores is predominantly formed through fluid precipitation and crystallization. The study area exhibits abnormal evolution of illite and I/S mixed layers, as well as the phenomenon of rapid chlorite growth under overpressure condition. The abnormal evolution of illite and I/S mixed layer may attribute to the inhibition of the conversion reaction from I/S mixed layer to illite. Chlorite's rapid growth occurs through the nucleation mechanism. Furthermore, through the analysis of clay and organic matter correlation, coupled with overpressure and hydrocarbon-rich section considerations, it is observed that chlorite may play a significant role in the storage and generation of S₁. This study contributes to a better understanding of the relationship between clay mineral evolution and shale reservoir overpressure, offering valuable insights for the accurate assessment of shale oil.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 6","pages":"Pages 3867-3883"},"PeriodicalIF":6.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141698950","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental deformation of shales at elevated temperature and pressure: Pore-crack system evolution and its effects on shale gas reservoirs","authors":"Yi-Wen Ju ,&nbsp;Xin-Gao Hou ,&nbsp;Kui Han ,&nbsp;Yu Song ,&nbsp;Lei Xiao ,&nbsp;Cheng Huang ,&nbsp;Hong-Jian Zhu ,&nbsp;Li-Ru Tao","doi":"10.1016/j.petsci.2024.07.003","DOIUrl":"10.1016/j.petsci.2024.07.003","url":null,"abstract":"<div><div>Although many studies based on naturally deformed samples have been carried out to investigate the pore-crack characteristics of shales, studies based on high temperature (<em>T</em>) and high pressure (<em>P</em>) deformation experiments, which can exclude sample heterogeneity factors, simulate deep <em>T-P</em> conditions, and generate a continuous deformation sequence, are still rare. In this study, shales with different deformation levels are generated by triaxial compression experiments, and methods including scanning electron microscopy, mercury injection, and gas sorption are utilized to characterize their influence factors and pore-crack characteristics. Results indicate that <em>T</em> is the primary factor influencing shale deformation when <em>P</em> is low, while <em>P</em> is dominant under high <em>P</em> conditions. At <em>T</em> &lt; 90 °C and <em>P</em> &lt; 60 MPa, shales undergo brittle deformation and their macropores decrease due to the compaction of primary pores, while mesopores increase because of the interconnection of micropores. At 90 °C &lt; <em>T</em> &lt; 200 °C and 60 MPa &lt; <em>P</em> &lt; 110 MPa, shales experience brittle-ductile transitional deformation, and their macro- and micropores increase because of the extension of open cracks and the plastic deformation of clay flakes respectively, while mesopores decrease dramatically. At <em>T</em> &gt; 200 °C and <em>P</em> &gt; 110 MPa, shales are subjected to ductile deformation, and their micro- and mesopores drop significantly due to the intense compaction in the matrix while macropores continuously increase with crack expansion. The permeability of shale increases with the degree of deformation and ductile material contents are predicted to be a key factor determining whether open microcracks can be preserved after ductile deformation. To account for these experimental results, an ideal model of micro pore-crack system evolution in deformed shales is further proposed, which can provide guidance for the exploration of shale gas resources in the deep or structurally complex zones.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":"21 6","pages":"Pages 3754-3773"},"PeriodicalIF":6.0,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141712464","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":1,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}