Petroleum Science最新文献

{"title":"Systematic prediction of the gas content, fractures, and brittleness in fractured shale reservoirs with TTI medium","authors":"","doi":"10.1016/j.petsci.2024.04.015","DOIUrl":"10.1016/j.petsci.2024.04.015","url":null,"abstract":"<div><div>The main objective is to optimize the development of shale gas-rich areas by predicting seismic sweet spot parameters in shale reservoirs. We systematically assessed the fracture development, fracture gas content, and rock brittleness in fractured gas-bearing shale reservoirs. To better characterize gas-bearing shale reservoirs with tilted fractures, we optimized the petrophysical modeling based on the equivalent medium theory. Based on the advantages of shale petrophysical modeling, we not only considered the brittle mineral fraction but also the combined effect of shale porosity, gas saturation, and total organic carbon (TOC) when optimizing the brittleness index. Due to fractures generally functioning as essential channels for fluid storage and movement, fracture density and fracture fluid identification factors are critical geophysical parameters for fractured reservoir prediction. We defined a new fracture gas indication factor (<em>GFI</em>) to detect fracture-effective gas content. A new linear PP-wave reflection coefficient equation for a tilted transversely isotropic (TTI) medium was rederived, realizing the direct prediction of anisotropic fracture parameters and the isotropic elasticity parameters from offset vector tile (OVT)-domain seismic data. Synthetic seismic data experiments demonstrated that the inversion algorithm based on the L_P quasinorm sparsity constraint and the split-component inversion strategy exhibits high stability and noise resistance. Finally, we applied our new prediction method to evaluate fractured gas-bearing shale reservoirs in the Sichuan Basin of China, demonstrating its effectiveness.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141038986","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":"Model-based interpretation of bottomhole pressure records during matrix treatments in layered formations","authors":"","doi":"10.1016/j.petsci.2024.05.027","DOIUrl":"10.1016/j.petsci.2024.05.027","url":null,"abstract":"<div><div>During injection treatments, bottomhole pressure measurements may significantly mismatch modeling results. We devise a computationally effective technique for interpretation of fluid injection in a wellbore interval with multiple geological layers based on the bottomhole pressure measurements. The permeability, porosity and compressibility in each layer are initially setup, while the skin factor and partitioning of injected fluids among the zones during the injection are found as a solution of the problem. The problem takes into account Darcy flow and chemical interactions between the injected acids, diverter fluids and reservoir rock typical in modern matrix acidizing treatments. Using the synchronously recorded injection rate and bottomhole pressure, we evaluate skin factor changes in each layer and actual fluid placement into the reservoir during different pumping jobs: matrix acidizing, water control, sand control, scale squeezes and water flooding. The model is validated by comparison with a simulator used in industry. It gives opportunity to estimate efficiency of a matrix treatment job, role of every injection stage, and control fluid delivery to each layer in real time. The presented interpretation technique significantly improves accuracy of matrix treatments analysis by coupling the hydrodynamic model with records of pressure and injection rate during the treatment.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141277569","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":"Biological origin and depositional environment of crude oils in the Qiongdongnan Basin: Insights from molecular biomarkers and whole oil carbon isotope","authors":"","doi":"10.1016/j.petsci.2024.05.026","DOIUrl":"10.1016/j.petsci.2024.05.026","url":null,"abstract":"<div><div>Molecular biomarker and whole oil carbon isotope (<em>δ</em>¹³C_oil) analyses were conducted on eleven typical crude oils from the Qiongdongnan Basin to investigate their biological sources and depositional environments. Saturated hydrocarbon biomarkers in most samples are characterized by angiosperm-derived compounds, with aromatic compounds dominated by the naphthalene, phenanthrene, biphenyl, and fluorene series. The related source rocks of these oils were mainly deposited under oxic condition, but a subanoxic–suboxic and enclosed water column condition in the Central Depression during Oligocene. The identification of simonellite and related compounds in the aromatic fractions provides reliable evidence for the input of coniferous gymnosperms. Cadalene may also have a potential association with gymnosperms since it shows a strong positive correlation with simonellite. Evidence from density, n-alkanes, short-chain alkylbenzenes and secondary brine inclusions indicates that the unique crude oil B13-1 may have suffered from thermal alteration. These crude oils (excluding B13-1) can be classified into four types based on the <em>δ</em>¹³C_oil values and molecular biomarkers. Type A oil (solely S34-3) is characterized by non-angiosperm plants, with minor dinoflagellates and increasing contribution from conifer gymnosperms than others. Type B oils (L17-2, L18-1, L25-1, and L25-1W) show heavy <em>δ</em>¹³C_oil (−24 ‰ to −25 ‰) and mixed contributions from both angiosperms and marine algae, with the marine algae contribution increasing. Type C oils (L13-2 and B21-1) share similar biological sources with Type B, but the moderately <em>δ</em>¹³Coil (−25‰ to −26‰) and high level of terrestrial biomarkers suggesting a predominant contribution of angiosperms. Type D oils (Y13-1a, Y13-1b, and Y13-4) possess the lightest <em>δ</em>¹³C_oil (mainly below −26‰) and are primarily derived from angiosperms, with mangrove vegetation playing an important role. Spearman correlation analysis among 14 source biomarker parameters with <em>δ</em>¹³C_oil and geological setting of related source rocks implied that the marine algae should be responsible for the heavy <em>δ</em>¹³C_oil in the Type B. The contribution of marine algae in the Central Depression may have been neglected in the past, as it is usually covered by remarkable angiosperm biomarkers.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141281238","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":"Influence of glycol ether additive with low molecular weight on the interactions between CO2 and oil: Applications for enhanced shale oil recovery","authors":"","doi":"10.1016/j.petsci.2024.06.004","DOIUrl":"10.1016/j.petsci.2024.06.004","url":null,"abstract":"<div><div>The high-efficient development of shale oil is one of the urgent problems in the petroleum industry. The technology of CO₂ enhanced oil recovery (EOR) has shown significant effects in developing shale oil. The effects of several glycol ether additives with low molecular weight on the interactions between CO₂ and oil were investigated here. The solubility of glycol ether additive in CO₂ was firstly characterized. Then, the effects of glycol ether additives on the interfacial tension (IFT) between CO₂ and hexadecane and the volume expansion and extraction performance between CO₂ and hexadecane under different pressures was investigated. The experimental results show that diethylene glycol dimethyl ether (DEG), triethylene glycol dimethyl ether (TEG), and tetraethylene glycol dimethyl ether (TTEG) all have low cloud point pressure and high affinity with CO₂. Under the same mass fraction, DGE has the best effect to reduce the IFT between hexadecane and CO₂ by more than 30.0%, while an overall reduction of 20.0%–30.0% for TEG and 10.0%–20.0% for TTEG. A new method to measure the extraction and expansion rates has been established and can calculate the swelling factor accurately. After adding 1.0% DEG, the expansion and extraction amounts of CO₂ for hexadecane are respectively increased to 1.75 times and 2.25 times. The results show that glycol ether additives assisted CO₂ have potential application for EOR. This study can provide theoretical guidance for the optimization of CO₂ composite systems for oil displacement.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141403074","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":"Evolution, resilience and causes of global petroleum gas trade networks: 1995–2020","authors":"","doi":"10.1016/j.petsci.2024.05.021","DOIUrl":"10.1016/j.petsci.2024.05.021","url":null,"abstract":"<div><div>Based on the HS 4-digit code trade data in UNCOMTRADE from 1995 to 2020, this paper analyzes the characteristics of the evolution of the global PG trade network using the complex network approach and analyzes the changes in its resilience at the overall and country levels, respectively. The results illustrated that: (1) The scale of the global PG trade network tends to expand, and the connection is gradually tightened, experiencing a change from a “supply-oriented” to a “supply-and-demand” pattern, in which the U.S., Russia, Qatar, and Australia have gradually replaced Canada, Japan, and Russia to become the core trade status, while OPEC countries such as Qatar, Algeria, and Kuwait mainly rely on PG exports to occupy the core of the global supply, and the trade status of other countries has been dynamically alternating and evolving. (2) The resilience of the global PG trade network is lower than that of the random network and decreases non-linearly with more disrupted countries. Moreover, the impact of the U.S. is more significant than the rest of countries. Simulations using the exponential random graph model (ERGM) model revealed that national GDP, institutional quality, common border and RTA network are the determinants of PG trade network formation, and the positive impact of the four factors not only varies significantly across regions and stages, but also increases with national network status.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141512038","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":"Origin of facies-controlled dolomite and exploration significance of the Middle Permian Qixia Formation in central Sichuan Basin, Western China","authors":"Xiao-Liang Bai ,&nbsp;Long Wen ,&nbsp;Yong-Mei Zhang ,&nbsp;Xi-Hua Zhang ,&nbsp;Jing Wang ,&nbsp;Yan-Gui Chen ,&nbsp;Si-Qiao Peng ,&nbsp;Wei Wang ,&nbsp;Jia-Yi Zhong ,&nbsp;Ya Li ,&nbsp;Ping Gao","doi":"10.1016/j.petsci.2024.08.007","DOIUrl":"10.1016/j.petsci.2024.08.007","url":null,"abstract":"<div><div>The intraplatform shoal dolomite of the Middle Permian Qixia Formation is currently considered the key target of hydrocarbon exploration in the central Sichuan Basin. To systematically investigate the origin of the stratabound facies-controlled porous dolomites of the Qixia Formation, integrated petrography, logging and seismic analysis were carried out in this work. The results are as following: (1) the dolomite reservoir is universal in the central Sichuan Basin, and its distribution is controlled by intraplatform shoals, with multilayer superposition vertically. Thick massive dolostone may also develop along with the fault. (2) Three replaced dolomites and one dolomite cement were identified: very finely to finely crystalline, anhedral to subhedral dolomite (Rd1); finely to medium crystalline, anhedral to subhedral dolomite (Rd2); coarsely crystalline, subhedral to euhedral dolomite (Rd3) and coarsely crystalline saddle dolomite cement (Sd). Rd2 and Rd3 are partly fabric-retentive, and preserve the original bioclastic ghosts. Sd shows wavy extinction, filled in the breccia veins. (3) The U-Pb dating and homogenization temperatures results indicate that the dolomite and Sd cement are associated with hydrothermal event during the Emeishan large igneous province. The δ¹³C, ⁸⁷Sr/⁸⁶Sr, and seawater-like REEY patterns suggest that the dolomitization and Sd precipitation fluids originate from connate seawater heated by elevated heat-flow. (4) The ELIP triggered large scale thermal anomalies in the basin during the Dongwu movement period. The increased temperature and pressure drove the formation water in the intra-platform shoal facies and overcame the binding effect of Mg²⁺ hydrate. Moreover, the deep hydrothermal fluid preferentially penetrated into the porous strata of shoal facies along the faults and fractures, mixed with formation water to some extent, and extensive dolomitization occurred. The facies-controlled dolomite reservoir and the underlying Cambrian source rock form a good source-reservoir assemblage, which can be a key replacement option.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142593686","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":"A new method for fluid identification and saturation calculation of low contrast tight sandstone reservoir","authors":"Shuai Wang,&nbsp;Ran-Hong Xie,&nbsp;Guo-Wen Jin,&nbsp;Jiang-Feng Guo,&nbsp;Li-Zhi Xiao","doi":"10.1016/j.petsci.2024.07.005","DOIUrl":"10.1016/j.petsci.2024.07.005","url":null,"abstract":"<div><div>The resistivity difference between oil and gas layers and the water layers in low contrast tight sandstone reservoirs is subtle. Fluid identification and saturation calculation based on conventional logging methods are facing challenges in such reservoirs. In this paper, a new method is proposed for fluid identification and saturation calculation in low contrast tight sandstone reservoirs. First, a model for calculating apparent formation water resistivity is constructed, which takes into account the influence of shale on the resistivity calculation and avoids apparent formation water resistivity abnormal values. Based on the distribution of the apparent formation water resistivity obtained by the new model, the water spectrum is determined for fluid identification in low contrast tight sandstone reservoirs. Following this, according to the average, standard deviation, and endpoints of the water spectrum, a new four-parameter model for calculating reservoir oil and gas saturation is built. The methods proposed in this paper are applied to the low contrast tight sandstone reservoirs in the Q4 formation of the X53 block and X70 block in the south of Songliao Basin, China. The results show that the water spectrum method can effectively distinguish oil-water layers and water layers in the study area. The standard deviation of the water spectrum in the oil-water layer is generally greater than that in the water layer. The new four-parameter model yields more accurate oil and gas saturation. These findings verify the effectiveness of the proposed methods.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141712346","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 study of hydraulic fracture propagation with multi-cluster in-plane perforations in a horizontal well","authors":"","doi":"10.1016/j.petsci.2024.04.006","DOIUrl":"10.1016/j.petsci.2024.04.006","url":null,"abstract":"<div><div>Tri-axial fracturing studies were carried out to understand the impact of lateral mechanical parameters on fracture propagation from multiple in-plane perforations in horizontal wells. Additionally, the discussion covered the effects of geology, treatment, and perforation characteristics on the non-planar propagation behavior. According to experimental findings, two parallel transverse fractures can be successfully initiated from in-plane perforation clusters in the horizontal well because of the in-plane perforation, the guide nonuniform fishbone structure fracture propagation still can be exhibited. The emergence of transverse fractures and axial fractures combined as complex fractures under low horizontal principal stress difference and large pump rate conditions. The injection pressure was also investigated, and the largest breakdown pressure can be also found for samples under these conditions. The increase in perforation number or decrease in the cluster spacing could provide more chances to increase the complexity of the target stimulated zone, thus affecting the pressure fluctuation. In a contrast, the increase in fracturing fluid viscosity can reduce the multiple fracture complexity. The fracture propagation is significantly affected by the change in the rock mechanical properties. The fracture geometry in the high brittle zone seems to be complicated and tends to induce fracture reorientation from the weak-brittle zone. The stress shadow effect can be used to explain the fracture attraction, branch, connection, and repulsion in the multiple perforation clusters for the horizontal well. The increase in the rock heterogeneity can enhance the stress shadow effect, resulting in more complex fracture geometry. In addition, the variable density perforation and temporary plugging fracturing were also conducted, demonstrating higher likelihood for non-uniform multiple fracture propagation. Thus, to increase the perforation efficiency along the horizontal well, it is necessary to consider the lateral fracability of the horizontal well on target formation.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140783630","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":"Extraction of reflected waves from acoustic logging data using variation mode decomposition and curvelet transform","authors":"","doi":"10.1016/j.petsci.2024.05.017","DOIUrl":"10.1016/j.petsci.2024.05.017","url":null,"abstract":"<div><div>Remote reflection waves, essential for acquiring high-resolution images of geological structures beyond boreholes, often suffer contamination from strong direct mode waves propagating along the borehole. Consequently, the extraction of weak reflected waves becomes pivotal for optimizing migration image quality. This paper introduces a novel approach to extracting reflected waves by sequentially operating in the spatial frequency and curvelet domains. Using variation mode decomposition (VMD), single-channel spatial domain signals within the common offset gather are iteratively decomposed into high-wavenumber and low-wavenumber intrinsic mode functions (IMFs). The low-wavenumber IMF is then subtracted from the overall waveform to attenuate direct mode waves. Subsequently, the curvelet transform is employed to segregate upgoing and downgoing reflected waves within the filtered curvelet domain. As a result, direct mode waves are substantially suppressed, while the integrity of reflected waves is fully preserved. The efficacy of this approach is validated through processing synthetic and field data, underscoring its potential as a robust extraction technique.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141140812","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":"Transportation and sealing pattern of the temporary plugging ball at the spiral perforation in the horizontal well section","authors":"Qing-Hai Hu ,&nbsp;Wan Cheng ,&nbsp;Zun-Cha Wang ,&nbsp;Yu-Zhao Shi ,&nbsp;Guang-Liang Jia","doi":"10.1016/j.petsci.2024.06.016","DOIUrl":"10.1016/j.petsci.2024.06.016","url":null,"abstract":"<div><div>Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing.</div></div>","PeriodicalId":19938,"journal":{"name":"Petroleum Science","volume":null,"pages":null},"PeriodicalIF":6.0,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141781418","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}