Petroleum Research最新文献

{"title":"Digital twin in hydrocarbon industry","authors":"Anirbid Sircar,&nbsp;Abhishek Nair,&nbsp;Namrata Bist,&nbsp;Kriti Yadav","doi":"10.1016/j.ptlrs.2022.04.001","DOIUrl":"10.1016/j.ptlrs.2022.04.001","url":null,"abstract":"<div><p>The hydrocarbon industry is considering a range of digital technologies to improve productivity, efficiency, and safety of their operations while minimizing capital and operating costs, health and environmental risks, and variability in oil and gas project life cycles. Due to the emergence of industry 4.0 the improvement in performance, efficiency, and cost reduction, the hydrocarbon industry is gradually shifting towards solutions that are data-oriented. Understanding such complex systems involves the analysis of data from various sources at the same time. Digital Twin (DT) modelling is the foundation for the next generation of real-time production monitoring and optimization systems. It is a solution that boosts productivity by combining information, simulation, and visualization throughout the entire value chain of an operational firm, from subsurface equipment to central production plants. Oil and gas companies can majorly benefit from Hydrocarbon Exploration with the right use of such advanced technologies. This study focuses on the advancements in technology in the context of DT and how it has been used by the hydrocarbon industry. The study discusses about the emergence of the DT concept, various types, 5D representation, and tools for DT. Further, the study tries to implement fields of DT in hydrocarbon industry especially in the domains of exploration, drilling, and production. Challenges associated with DT strategy like accessibility, confidentiality integration, and maintenance are also discussed.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46877473","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":"Microfacies analysis and depositional environment of the Upper Devonian Dankovo-Lebedyansky sediments, Tatarstan, Volga-Ural Basin, Russia","authors":"Ibrahem Yousef,&nbsp;V. P Morozov,&nbsp;A. N Kolchugin,&nbsp;V. Sudakov,&nbsp;I. Idrisov,&nbsp;A. Leontev","doi":"10.1016/j.ptlrs.2022.07.003","DOIUrl":"10.1016/j.ptlrs.2022.07.003","url":null,"abstract":"<div><p>The Upper Devonian, Middle Famennian Dankovo-Lebedyansky sediments in Southeast Tatarstan territory are a carbonate sequence composed of limestone and dolomite, which is important hydrocarbon reservoir units, therefore, it is necessary to conduct in-depth study on its microfacies and depositional environment. In this study, a multidisciplinary approach that combines core observation with thin section examination is used. The limestone contains abundant skeletal grains (echinoderms, foraminifera, algae, gastropods, and calcispheres), as well as non-skeletal grains (intraclasts and peloids). On the basis of detailed petrographic investigations, six sedimentary microfacies can be identified, including (i) peloidal grainstone (MF 1), (ii) cemented bioclastic peloidal grainstone (MF 2), (iii) echinoderm-concentrated packstone (MF 3), (iv) algae packstone (MF 4), (v) bioclastic wackestone (MF 5), (vi) whole-fossil wackestone (MF 6), as well as dolomite or dolostone as diagenetic facies (MF 7). Based on microfacies analysis, the Dankovo-Lebedyansky sediments were deposited in three distinct sedimentary facies belts (shoal, lagoon and open marine environment). In order to reflect dispositional energy condition, the microfacies were grouped into facies associations: (i) low-energy microfacies associations including MF 5 and MF 6, (ii) moderate energy microfacies associations including MF 1, MF 2, MF 3, and MF 4. The dolomite, or diagenetic facies (MF 7), is the result of slightly to extensively dolomitization of limestone in the Dankovo-Lebedyansky sediments. Most of frequent dolostone types are euhedral planar-e and subhedral planar-s. According to petrographic characteristic of the dolostone, a seepage reflux model can be used to explain the dolomitization process of Dankovo-Lebedyansky sediments.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45648248","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":"Assessment of parameters effectiveness in the reserve estimation methods applicable to coal bed methane reservoirs","authors":"Farzain Ud Din Kirmani ,&nbsp;Arshad Raza ,&nbsp;Muhammad Sarfraz Akram ,&nbsp;Raoof Gholami","doi":"10.1016/j.ptlrs.2022.05.001","DOIUrl":"https://doi.org/10.1016/j.ptlrs.2022.05.001","url":null,"abstract":"<div><p>The reserve estimation of coal bed methane (CBM) reservoirs is ascertained through the analytical methods (volumetric method, material balance equation and decline curve analysis). However, the adoption of reserve estimation methods depends on exploration stage and availability of the required parameters. This study deals with the analytical assessment of parameters that participate in effecting the reserve estimation of CBM reservoirs through the analytical techniques. The accurate measurement challenges always exist for the parameters which participate in the reserve estimation of the conventional and unconventional reservoirs because of the inclusion of limitations while measurement. Therefore, the impact of that measurement challenge must be assessed. The study specifies the impact of parametric change on the reserve estimation of CBM reservoirs so that the degree of parametric effectiveness is analyzed. Uncertain values are adopted which are associated during the evaluation of input parameters for each method to determine the overall impact on potential of CBM reserves. Results reveal that change in specific parameters considering each method provide relatively more effect on estimation of reserves. Thus, the measurement of parameters must be done accurately for assessing reserves of CBM reservoirs based on available methods.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"50189072","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 new approach of CO2 separation by applying rapid expansion of supercritical CO2 rich natural gas","authors":"Saripudin ,&nbsp;Tutuka Ariadji ,&nbsp;Sanggono Adisasmito ,&nbsp;Leksono Mucharam ,&nbsp;Doddy Abdassah","doi":"10.1016/j.ptlrs.2022.03.005","DOIUrl":"10.1016/j.ptlrs.2022.03.005","url":null,"abstract":"<div><p>The previous methods for CO₂ separation from CO₂ rich natural gas led to expensive production costs. This work was implemented to overcome the problems utilizing a new approach economically. The cooling and rapid expansion processes were integrated for the CO₂ separation from CO₂ rich natural gas on the supercritical condition. The experimental apparatus was newly constructed to perform the experiments, and the results were simulated using a various equation of state. The result reveals that the inlet temperature of supercritical expansion diminished the outlet temperature and the gas condensed easily. The simulation indicated that the 70% CO₂ in natural gas was condensed easier than 45% CO₂. We found that the outlet temperature of −42 °C and the vapor fraction of 0.69 was attained at the CO₂ composition of 70%. Besides, the pressure drop change influences the vapor fraction at various CO₂ compositions. The vapor fraction under supercritical diminished significantly compared with the non-supercritical condition. The expansion coefficient determined utilizing the equation of state escalates by the enhancement of expansion inlet temperature based on CO₂ composition in natural gas. The acid gas equation of state was the perfect equation to estimate the expansion coefficient with the absolute average error of 4.83%. This work suggests that the CO₂ separation from CO₂ rich natural gas with the cooling and rapid expansion method promotes the new approach to overcome the disadvantages of previous methods.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43859022","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":"Predicting the effects of selected reservoir petrophysical properties on bottomhole pressure via three computational intelligence techniques","authors":"Emmanuel E. Okoro ,&nbsp;Samuel E. Sanni ,&nbsp;Tamunotonjo Obomanu ,&nbsp;Paul Igbinedion","doi":"10.1016/j.ptlrs.2022.07.001","DOIUrl":"10.1016/j.ptlrs.2022.07.001","url":null,"abstract":"<div><p>This study investigates the effects of selected petrophysical properties on predicting flowing well bottomhole pressure. To efficiently situate the essence of this investigation, genetic, imperialist competitive and whale optimization algorithms were used in predicting the bottomhole pressure of a reservoir using production data and some selected petrophysical properties as independent input variables. A total of 15,633 data sets were collected from Volvo field in Norway, and after screening the data, a total of 9161 data sets were used to develop apt computational intelligence models. The data were randomly divided into three different groups: training, validation, and testing data. Two case scenarios were considered in this study. The first scenario involved the prediction of flowing bottomhole pressure using only eleven independent variables, while the second scenario bothered on the prediction of the same flowing bottomhole pressure using the same independent variables and two selected petrophysical properties (porosity and permeability). Each of the two scenarios involved as implied in the first scenario, the use of three (3) heuristic search optimizers to determine optimal model architectures. The optimizers were allowed to choose the optimal number of layers (between 1 and 10), the optimal number of nodal points (between 10 and 100) for each layer and the optimal learning rate required per task/operation. the results, showed that the models were able to learn the problems well with the learning rate fixed from 0.001 to 0.0001, although this became successively slower as the leaning rate decreased. With the chosen model configuration, the results suggest that a moderate learning rate of 0.0001 results in good model performance on the trained and tested data sets. Comparing the three heuristic search optimizers based on minimum MSE, RMSE, MAE and highest coefficient of determination (R²) for the actual and predicted values, shows that the imperialist competitive algorithm optimizer predicted the flowing bottomhole pressure most accurately relative to the genetic and whale optimization algorithm optimizers.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44232194","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":"Physicochemical assessment and treatment of produced water: A case study in Niger delta Nigeria","authors":"Kingsley Tamunokuro Amakiri ,&nbsp;Naomi Amoni Ogolo ,&nbsp;Athanasios Angelis-Dimakis ,&nbsp;Oshienemen Albert","doi":"10.1016/j.ptlrs.2022.05.003","DOIUrl":"10.1016/j.ptlrs.2022.05.003","url":null,"abstract":"<div><p>The most important waste stream created during oil and gas production is oilfield-produced water. When discharged without treatment, it poses a significant risk of pollution of marine ecosystems. While adequate treatment before disposal is acceptable, achieving authorized discharge criteria continues to be a problem for the petroleum sector. This research examined the physicochemical characteristics of produced water at various month intervals before and after treatment. Heavy metal and organic component concentrations in water samples were determined using atomic absorption spectroscopy and gas chromatography. The results indicate that produced water from a certain Niger Delta oilfield contains significant amounts of heavy metals and some organic compounds after treatment. The present laws, as well as the measurement of dispersed oil and grease content, have been in place for a long period of time without considerable change, even though most dangerous components in produced water are dissolved. It is recommendable for the prospective field developers/operators to consider the dissolved components of produced water and consider the economic consequences of adopting tertiary produced water polishing technologies.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48658791","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":"Numerical simulation investigations of the applicability of THAI in situ combustion process in heavy oil reservoirs underlain by bottom water","authors":"Muhammad Rabiu Ado ,&nbsp;Malcolm Greaves ,&nbsp;Sean P. Rigby","doi":"10.1016/j.ptlrs.2022.06.001","DOIUrl":"10.1016/j.ptlrs.2022.06.001","url":null,"abstract":"<div><p>The presence of a bottom water (BW) layer in heavy oil reservoirs can present substantial problems for efficient oil recovery for all recovery techniques. Hence, it is necessary to know how particular production processes are affected by different BW layer thicknesses, and how standard production procedures can be adapted to handle such reservoirs. Toe-to-heel air injection (THAI) is a thermally efficient process, generating in situ energy in the reservoir by burning a fraction of the oil-in-place as coke and has the potential to economically and environmentally friendly work in reservoirs with BW layer. However, to ascertain that, studies are needed first. These are conducted via numerical simulations using commercial reservoir thermal simulator, CMG STARS. This work has shown that the shape of the combustion zone in THAI remains forward-leaning even in the presence of a BW layer, indicating that the process is stable, and that there is no oxygen bypassing of the combustion front. However, the oil recovery rate is highly negatively affected by how large the thickness of the BW zone is, and the severity of such effect is determined to be proportional to the thickness of the BW layer. This study also shows that there is a period of low oil production rate which corresponds to mobilised oil displacement into the BW zone which in turn causes a surge in water production rate. The practical implication of this is that prolonged period of low oil production rates will expose companies and/or investors to higher risk due to the oil market volatility. In this study, it is also revealed that the height of the mobilised oil that is displaced into the BW zone equates to that of the displaced and replaced water thereby implying that when the BW layer thickness is 50% that of the oil layer (OL), less than 50% of the mobilised oil will be recovered when the entire reservoir is swept by the combustion front. Therefore, conclusively, applying the THAI process in its conventional form in reservoirs containing bottom water is not recommended, and as a result, a new strategy is needed to enhance process economics by improving the oil production and hence recovery rates.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41265044","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":"Effect of heterogeneity and injection rates on the recovery of oil from conventional sand packs: A simulation approach","authors":"Anurag Pandey ,&nbsp;Himanshu Kesarwani ,&nbsp;Amit Saxena ,&nbsp;Reza Azin ,&nbsp;Shivanjali Sharma","doi":"10.1016/j.ptlrs.2022.05.005","DOIUrl":"10.1016/j.ptlrs.2022.05.005","url":null,"abstract":"<div><p>The study of flow through porous media has been of cardinal gravity in oil and gas applications like enhanced oil recovery (EOR), acidizing, fracturing, etc. One of the most anticipated apprehensions is that the core flooding and simulation have become prevalent to understand the flow through porous media. This study aims at simulating and analyzing the effect of alkaline surfactant flooding through heterogeneous permeability conditions in the lab-scale methods. The conventional methods of core flood deal with the effective permeability of the system without considering the effect of heterogeneity within the core. The heterogeneous studies are conducted by simulating a finely meshed 2-D axisymmetric model of the sand pack. The novel Karanj oil surfactant extracted from <em>Pongamia Pinnata</em>, and partially hydrolyzed polyacryl amide polymer are considered for the physicochemical properties of displacing fluid used in the simulations. Different heterogeneity combinations and displacing fluid injection flow rates are introduced for a single absolute permeability system. Results indicate a trend of oil recovery upright with increasing vertical permeability. A lower areal sweep efficiency and early breakthrough are observed in models with high horizontal permeabilities. Further, the effect of heterogeneity on oil recovery is reduced with the increase in injection flow rates of displacing fluid. The present work utilizes computational fluid dynamics to model multiphase flow through a heterogeneous permeability media and its effect on oil recovery.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43152480","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":"Polymer flooding and its effects on enhanced oil recovery special reference to Upper Assam Basin","authors":"Kalpajit Hazarika ,&nbsp;Subrata Borgohain Gogoi ,&nbsp;Amit Kumar","doi":"10.1016/j.ptlrs.2022.03.003","DOIUrl":"10.1016/j.ptlrs.2022.03.003","url":null,"abstract":"<div><p>Chemical Enhance oil Recovery (CEOR) technology is getting more attention since energy crises are getting worse and frightened. Successful application of polymer flooding depends on the evaluation of rheological and solution properties of injected slug at reservoir conditions, which is function of polymer concentration, salinity, temperature and shear rate. Poly acryl amide (PAM) is commonly used polymer in polymer flooding technique. However, comparative study with other polymers such as xanthan gum (XG) is required while selection of appropriate polymer for CEOR. In present study, the recovery efficiency of PAM and XG as a polymer has been evaluated for application as chemical EOR agent for tertiary phase polymer flooding in Upper Assam basin. The comparative study between PAM and XG has been done in terms of rheological properties. Core flooding experiment of polymer flooding has also been tested to determine the recovery efficiency of the PAM and XG polymer solutions. The results showed that these polymers exhibit favorable salt tolerance, temperature resistance, and recoverable viscosity after shearing, reasonable thickening behavior and improved viscosity enhancement properties due to presence of hydrophobic association in the polymer main chains. Core flooding experiment of polymer flooding has also been tested to determine the recovery efficiency of the PAM and XG polymer solutions. Results show that macroscopic sweep efficiency is the dominant factor during recovery. While an injection of hydrogel polymer to the reservoir is to increase a viscosity of fluid containing water so that the fluid is more difficult to flow than the oil, and as a result, the oil production increases. Shear thinning behavior was observed in case of PAM indicating predominance of the frontal advance theory. As PAM seems to be following both piston like movement and frontal advance theory it can be efficiently enhancing the macroscopic sweep efficiency as well as microscopic displacement efficiency. The overall recovery efficiency of 53% of OOIP was determined for PAM flooding. The overall recovery efficiency by XG polymer flooding was found to be 45%, signifying its lesser efficiency in comparison to PAM. Success of the projects also depends on cost analysis. Simulation by Computer Modelling Group (CMG) study has also been carried out to validate the experimental findings.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45368187","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":"Investigation of trend between porosity and drilling parameters in one of the Iranian undeveloped major gas fields","authors":"Abbas Ayatizadeh Tanha ,&nbsp;Amirhossein Parizad ,&nbsp;Khalil Shahbazi ,&nbsp;Hassan Bagheri","doi":"10.1016/j.ptlrs.2022.03.001","DOIUrl":"10.1016/j.ptlrs.2022.03.001","url":null,"abstract":"<div><p>Porosity is one of the main parameters that should be considered when a gas or an oil field is assessed. Hence, the availability of porosity is crucial in any rock and formation analysis. However, this parameter is not always available and direct measurement is scarce and usually is confined to appraisal phase of a field. Therefore, in this study it is aimed to find a relationship in order to estimate porosity in afterward phases. The data of 5 appraisal wells of an undeveloped gas field has been gathered to perform this purpose. The full set wireline logging data and drilling data were available. ‏The data inherit high level of fluctuation which is normal with respect to real direct measured data. The smoothed curving was utilized and as a result, the fluctuation was diminished considerably and the feasibility of carrying out the investigation was being established, accordingly. To normalize and gather drilling data in a parameter in order to have a better view and investigation, sigmalog method was employed. It was observed that there is a clear exponential relationship between porosity and drilling data and curve fitting was utilized to conduct a numerical relationship. The curve fitting was established with R² = 0.83 and a trustworthy fitting resulted. The results demonstrate the possibility of porosity estimation by using drilling data. Furthermore, a numerical relationship is given for a specific field. The porosity estimation can lead to better analysis of newly drilled rocks and formations leading to more efficient field development strategies.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41800081","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}