Petroleum Research最新文献

{"title":"Pilot test of polymer microsphere alternate surfactant flood (PMAS) with mixtures of anionic-cationic surfactants under harsh conditions in a sandstone reservoir","authors":"Yingcheng Li ,&nbsp;Jun Jin ,&nbsp;Zhiqing Su ,&nbsp;Weidong Zhang ,&nbsp;Xinning Bao ,&nbsp;Baolun Niu ,&nbsp;Changhua Yang ,&nbsp;Xinyue Wu ,&nbsp;Xiaodong Zhai ,&nbsp;Li Zhang ,&nbsp;Rong Guo ,&nbsp;Yong Meng ,&nbsp;Xiujuan He ,&nbsp;Zhiqin Shen ,&nbsp;Hui Zhang ,&nbsp;Ou Sha","doi":"10.1016/j.ptlrs.2023.01.001","DOIUrl":"10.1016/j.ptlrs.2023.01.001","url":null,"abstract":"<div><p>The first pilot test of polyacrylamide microsphere alternate surfactant flood (PMAS) with mixtures of anionic-cationic surfactants (S_a/c) was carried out for a high-temperature, high-salinity, and high-hardness sandstone reservoir to demonstrate the potential of this novel technique to improve oil recovery. A critical micelle concentration (CMC) of 4.82 mg/L, an ultralow interfacial tension (IFT) of 8 × 10⁻⁴ mN/m, and a high oil solubilization of 22 were obtained. Static and dynamic adsorptions of S_a/c on natural core containing 15 wt% clay were reduced to about 2.20 and 0.30 mg/g-core, respectively, with the addition of adsorption inhibitor (AI). Since June 2014, the pilot test of PMAS was carried out in a Sinopec reservoir with a temperature of 87 °C, a salinity of 260,393 mg/L, and a hardness of 6,401 mg/L. Twelve cycles of alternative injection of 0.0125 PV S_a/c with a concentration of 0.1% and 0.0125 PV polyacrylamide microsphere with a concentration of 0.2% were conducted at an injection rate of 0.1 PV/yr, for a total of 0.3 PV chemical injection. As a result, the net daily oil production increased from 0 t to 6.5 t, and the water cut decreased from 96.3% to 93.8%, leading to an ultimate improved oil recovery of 6.3% original oil-in-place.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 291-300"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42840740","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Statistical distribution of geomechanical properties and ‘Sweet Spots’ identification in part of the upper Bakken","authors":"Nelson R.K. Tatsipie,&nbsp;James J. Sheng","doi":"10.1016/j.ptlrs.2022.10.005","DOIUrl":"10.1016/j.ptlrs.2022.10.005","url":null,"abstract":"<div><p>Completions and Reservoir Quality are two key attributes that are used to characterize nonconventional hydrocarbon assets. This is because, for optimum exploitation of these unconventional assets, horizontal wells need to be drilled in “Sweet Spots” (i.e., regions where Completions and Reservoir Quality are both superior). One way to quantify these qualities is to use reservoir and geomechanical properties. These properties can be estimated on a location basis from well logs, and then mapped over terrain using geostatistical modeling. This study presents a ‘Sweet Spots’ identification workflow based on three performance indexes (Storage Potential Index, Brittleness Index, and Horizontal Stress Index) that can be used to quantify CQ and RQ. The performance indexes are computed from petrophysical property volumes (of Young's Modulus, Bulk Modulus, Shear Modulus, Poisson's Ratio, Minimum Horizontal Stress, Volume of Shale, Total Organic Carbon, Thickness, and Porosity) which are in turn computed from well logs and geostatistical simulation. In the end, the study offers a method to compare the predicted “Sweet Spots” against available production data via their correlation coefficient. The resulting reasonable formation property maps, the successful identification of ‘Sweet Spots’, and a correlation coefficient of 0.88 (between the predicted “Sweet Spots” and well production data) point to the potential of the proposed effort.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 301-308"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45843791","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An artificial neural network visible mathematical model for real-time prediction of multiphase flowing bottom-hole pressure in wellbores","authors":"Chibuzo Cosmas Nwanwe ,&nbsp;Ugochukwu Ilozurike Duru ,&nbsp;Charley Anyadiegwu ,&nbsp;Azunna I.B. Ekejuba","doi":"10.1016/j.ptlrs.2022.10.004","DOIUrl":"10.1016/j.ptlrs.2022.10.004","url":null,"abstract":"<div><p>Accurate prediction of multiphase flowing bottom-hole pressure (FBHP) in wellbores is an important factor required for optimal tubing design and production optimization. Existing empirical correlations and mechanistic models provide inaccurate FBHP predictions when applied to real-time field datasets because they were developed with laboratory-dependent parameters. Most machine learning (ML) models for FBHP prediction are developed with real-time field data but presented as black-box models. In addition, these ML models cannot be reproduced by other users because the dataset used for training the machine learning algorithm is not open source. These make using the ML models on new datasets difficult. This study presents an artificial neural network (ANN) visible mathematical model for real-time multiphase FBHP prediction in wellbores. A total of 1001 normalized real-time field data points were first used in developing an ANN black-box model. The data points were randomly divided into three different sets; 70% for training, 15% for validation, and the remaining 15% for testing. Statistical analysis showed that using the Levenberg-Marquardt training optimization algorithm (trainlm), hyperbolic tangent activation function (tansig), and three hidden layers with 20, 15 and 15 neurons in the first, second and third hidden layers respectively achieved the best performance. The trained ANN model was then translated into an ANN visible mathematical model by extracting the tuned weights and biases. Trend analysis shows that the new model produced the expected effects of physical attributes on FBHP. Furthermore, statistical and graphical error analysis results show that the new model outperformed existing empirical correlations, mechanistic models, and an ANN white-box model. Training of the ANN on a larger dataset containing new data points covering a wider range of each input parameter can broaden the applicability domain of the proposed ANN visible mathematical model.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 370-385"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47821036","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A review on the mechanisms of low salinity water/surfactant/nanoparticles and the potential synergistic application for c-EOR","authors":"Stanley Sim Sze Lim ,&nbsp;Henry Elochukwu ,&nbsp;Jobrun Nandong ,&nbsp;Ziad Bennour ,&nbsp;Mohamed Ali Hamid","doi":"10.1016/j.ptlrs.2023.02.001","DOIUrl":"10.1016/j.ptlrs.2023.02.001","url":null,"abstract":"<div><p>Chemical enhanced oil recovery (c-EOR) is a conventional and promising strategy to recover oil from reservoir techniques such as low salinity water flooding (LSWF), surfactant flooding, alkaline flooding, polymers flooding, and nanofluid flooding. The use of various types of chemical materials for c-EOR method has recently attracted the attention of the oil and gas industry. The primary objective of this review work is to explore the synergy of low salinity water/surfactant/nanoparticle flooding for effective c-EOR method and investigate the mechanism behind these methods. The advantages of combining these chemical materials for c-EOR methods is also reviewed. Challenges and limitations of this synergy and their economic feasibility for additional oil recovery and potential return on investment are reviewed. Nanoparticles have been successfully used in various applications in several industries and have also shown good application for EOR in terms of wettability alteration. LSWF contributes to wettability alteration, while surfactant contributes to wettability alteration and interfacial tension (IFT) reduction. However, fines migration caused by LSWF and nanoparticle agglomeration can cause formation damage, while excessive surfactant adsorption can lead to cost overrun on surfactant use. Understanding the characteristics of reservoir formation mineralogy and appropriate nanoparticle type, size, and concentration can be used to resolve this challenges. The synergy of LSWF and nanoparticles in alkaline medium can serve as sacrificial agent to reduce excessive surfactant loss. Therefore, the appropriate synergistic formulation of LSFW/surfactant/nanoparticle can improve additional oil recovery and support return on investment for c-EOR projects.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 324-337"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43241921","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mineral analysis of sandstone formation using chelating agents during sandstone matrix acidizing","authors":"Mian Umer Shafiq ,&nbsp;Hisham Ben Mahmud ,&nbsp;Lei Wang ,&nbsp;Momna Khan ,&nbsp;Ning Qi ,&nbsp;Khizar Abid ,&nbsp;Sophia Nawaz Gishkori","doi":"10.1016/j.ptlrs.2022.10.008","DOIUrl":"10.1016/j.ptlrs.2022.10.008","url":null,"abstract":"<div><p>For many years, the most common acid practice for sandstone acidizing is based on mud acid and dolomite formations using hydrochloric acid. During various stages of sandstone acidizing, different acids react with different minerals, and interactions of minerals with acids are an origin for precipitation reactions, which can be possibly deleterious as they may reduce reservoir permeability. During this research, the effects of chelates on pore size distribution, mineralogy, and grain size distribution have been investigated. Various chelates (GLDA, HEDTA, EDTA) were examined to react with different Berea Sandstone samples at a temperature of 180 °F and under 1000 psi confining pressure. Experimental techniques and analysis like Tescan Integrated Mineral Analysis (TIMA), were implemented in this research to understand the effect of chelates on Berea Sandstone. These results are related to elemental mass, element deportment, mineral mass, mineral locking, grain size distribution, and particle size distribution of the core samples reacted with different chelating agents. It has been found that all the chelating agents are effective in increasing the porosity and dissolving the cations from the Berea sandstone core sample. HEDTA proved to be more effective in dissolving quartz as compared to other chelates. GLDA proved to be more effective in the dissolution of rutile and zircon minerals. The significance of this research is the application of environment-friendly chelating agents to sandstone formation. Moreover, the detailed mineral analysis revealed that the most number of particles were dissolved by HEDTA.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 404-412"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47544165","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Impact of microfacies and diagenesis on the reservoir quality of Upper Devonian carbonates in Southeast Tatarstan, Volga-Ural Basin, Russia","authors":"Ibrahem Yousef,&nbsp;V.P. Morozov,&nbsp;A.N. Kolchugin,&nbsp;A. Leontev","doi":"10.1016/j.ptlrs.2022.10.006","DOIUrl":"10.1016/j.ptlrs.2022.10.006","url":null,"abstract":"<div><p>The results of integrated sedimentology, petrography, and petrophysical study of the Upper Devonian (Middle Famennian) Dankovo-Lebedyansky carbonates from Southeast Tatarstan of the Volga-Ural Basin revealed a variety of microfacies and diagenetic events that impacted the reservoir quality. Although our earlier study documented microfacies analysis and depositional environments, none of the studies focused on diagenesis, microfacies interaction, and their controls on the studied sediment's reservoir quality. Based on petrographic and microfacies analyses, the seven identified microfacies types are peloidal grainstone MF 1, cemented bioclastic peloidal grainstone MF 2, echinoderm-concentrated packstone MF 3, algae packstone MF 4, bioclastic wackestone MF 5, whole-fossil wackestone MF 6, and dolomite MF 7. For the investigated sediments, a gently deepening carbonate ramp depositional model with an inner, middle, and outer ramp setting is proposed. The observed diagenetic events in this study include micritization, calcite cementation (six cement types), dolomitization (six dolomite types), dissolution (fabric and non-fabric-selective dissolution), compaction, and microfracturing. The identified microfacies were classified into three distinct classes based on their petrophysical characteristics. MF 1 and MF 7 are microfacies types with the best reservoir quality. MF 3 and MF 4 are microfacies types of moderate reservoir quality. MF 2, MF 5, and MF 6 are microfacies types with poor or non-reservoir quality. Calcite cementation, micritization, and compaction are the primary diagenetic modifications responsible for porosity reduction. Moldic pores created by dissolution are a significant porosity-improving process. Porosity is locally enhanced by stylolite and microfractures. Dolomitization improved reservoir quality by creating intercrystalline and vuggy porosity. Understanding the impact of microfacies and diagenesis on reservoir quality is crucial for understanding reservoir properties in nearby fields with similar settings.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 386-403"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42993573","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Measurement-While-Milling (MWM): An innovative approach for increasing the casing milling efficiency in deep drilling operations","authors":"Mohammed A. Namuq ,&nbsp;Mouhammed Jandal Berro ,&nbsp;Matthias Reich","doi":"10.1016/j.ptlrs.2022.09.003","DOIUrl":"10.1016/j.ptlrs.2022.09.003","url":null,"abstract":"<div><p>Deep boreholes are secured by steel tubes (casings) which are run in the hole and cemented in place. In most cases, these casings are considered a permanent installation. However, sometimes they have to be removed in order to repair or abandon the well. As the casing is cemented in place, it cannot be pulled, but needs to be milled to small chips which are flushed out of the borehole by the drilling mud. One of the main challenges in casing milling operations is continuous and complete chip removal. If the metal chips are too long, chip nests will grow around the milling string. As a result, this will restrict the annulus flow area and affect the chip removal in boreholes. The obvious solution in such condition is to do round tripping and clean the chip nest which is associated with the risk of injuries, as well as, increasing the none-productive time. In the worst case, the poor cleaning and circulation of chips can even end up with the milling string stucking problem in boreholes, consequently long-time fishing job. According to the available literatures, hardly any study for identifying the chip shapes and accordingly adapting the operation parameters to the casing milling process environment downhole to keep milling within desired generated chip shapes and sizes could be found. This paper presents an encouraging idea to monitor the milling process in real time by utilizing the acoustic emission signals (vibration modes) accompanied with the milling process to identify the desired chip shape and size range. Initial laboratory tests have been carried out to investigate and study the acoustic emission signals accompanying the casing milling process to identify the chip shapes and sizes. The preliminary test results show very good correlation and agreement between the chip length formed during those specific tests and the observed burst events in the measured signals. The study results have demonstrated the functionality of the new concept, and thus confirmed that it is a very promising idea towards developing a practical real time downhole monitoring system for milling operations. Adapting the milling operation parameters downhole in real time to keep the milling process within the desired generated chip shapes and sizes will offer better cleaning and removal of the chips and will prevent the development of chip nest around the drill string and its consequences such as round tripping, risk of drilling crew injury, none-productive time and even milling string stucking problems.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 360-369"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45820064","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrate inter–well connectivity data with static reservoir models based on Bayesian formalism","authors":"Yupeng Li ,&nbsp;Rashid S. Mohammad","doi":"10.1016/j.ptlrs.2023.01.003","DOIUrl":"10.1016/j.ptlrs.2023.01.003","url":null,"abstract":"<div><p>The inter-well connectivity calculated from reservoir dynamic production data reflects formation heterogeneity quantitatively. Currently, the calculated inter-well connectivity between pair wells is mainly used as a tool for water flood management but not for quantitative reservoir characterization. This study proposes an innovative, dynamic data integration workflow that can integrate inter-well connectivity with a static reservoir model. In the workflow, the first step is calculating the inter-well connectivity vectors from the reservoir pairwise injector and producer wells. The second step covers interpolation in the domain of interest. The third step is to update the permeability model based on the Bayesian updating method. The result of this study shows that integrating the calculated inter-well connectivity with the static models enhances model reliability and it also provides an insight to deeper geological understanding reflected from dynamic data integration in reservoir modeling.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 433-438"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42164860","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Design and construction of a continuous pilot flotation facility: A case study for water-based oil sand extraction","authors":"Feng Lin","doi":"10.1016/j.ptlrs.2022.11.001","DOIUrl":"10.1016/j.ptlrs.2022.11.001","url":null,"abstract":"<div><p>In this work, the design and construction of a continuous and pilot-scale flotation facility are demonstrated. The performance of the new facility was evaluated from series of pilot flotation tests, carried out using oil sands slurry to extract bitumen—an extra-heavy form of petroleum. Results indicated that bitumen recoveries of the new pilot plant for an identical ore and water chemistry were largely dependent on air injection method, slurry conditioning time, flotation residence time, and slurry temperature. Importantly, when compared with those of bitumen extraction tests using a bench-scale Batch Extraction Unit (BEU) operated at the most optimal conditions, it was suggested that the new pilot plant produced flotation recoveries of bitumen and froth qualities at a level as good as, or even higher than, the level accomplished using the BEU at an identical ore, water chemistry and operating temperature. This continuous, pilot flotation plant could potentially serve as a pre-commercial production system that verifies a new processing aid, or as an alternative extraction technology for oil sand, coal, and mineral processing.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 309-315"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47492642","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental investigation of the influence of carbonated water on sandstone and carbonate rock properties","authors":"Hisham Ben Mahmud ,&nbsp;Mohamed Khalifa ,&nbsp;Mian Shafiq ,&nbsp;Ausama Giwelli","doi":"10.1016/j.ptlrs.2022.10.007","DOIUrl":"10.1016/j.ptlrs.2022.10.007","url":null,"abstract":"<div><p>Laboratory measurements using nuclear magnetic resonance, scanning electron microscopy, and gas porosity and permeability analysis were conducted to acquire a petrophysical interpretation of the Carbon Tan Sandstone and Savonnieres Carbonate for potential carbon dioxide storage in subsurface formations. The relationships between pore structures, such as pore-size distribution, pore geometry, and porosity/permeability, were investigated near and far from the wellbore. At operating pressures of 2500psi (17.24 MPa) and temperatures of 176 °F (50 °C), carbonated water was injected into a composite core constructed of two similar core samples bounded by a compact disc located between them. The current results showed that a strong calcite dissolution took place near the injection position of both rock samples and led to improvements in the primary intergranular permeability and porosity, while the carbonate sample showed significant improvement compared to sandstone. The durable heterogeneous dissolution of calcite grains also led to the creation of new pores as intra-granular micro-pores. While at deeper depths from the injection position, it noticed an insignificant development in pore structure and its populations as well as rock hydraulic properties of both rock samples. In conclusion, the study revealed that the injected carbonated brine had a valuable impact on fluid-formation interactive, which improved rock's inlet properties compared with outlet.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"8 3","pages":"Pages 316-323"},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41417649","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}