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The research on the operation mode and parameter selection method of large-scale water injection pipeline network
Springer Science and Business Media LLC - Tập 11 - Trang 4175-4184 - 2021
Due to the complexity of the large-scale water injection pipe network system and the difficulty of manual analysis, it is impossible to guarantee the optimal operation mode scheme selected. At present, there are still gaps in the research on the judgment of its optimal operation mode. Through the calculation and evaluation of a large amount of water injection system data, the selection method of the optimal operation mode of the water injection system is determined, and it is found that the selection of the optimal operation mode is closely related to the pressure distribution characteristics of the individual wells of the entire water injection system, and five discriminant rules for the optimal operation mode of the water injection system are formed based on these characteristics; the mathematical model for determining the mode and the optimal method of operating parameters is given, and the pipeline network simulation system automatically generates the pipe network topology diagram; the optimal operation mode of the water injection system is developed; Intelligent judgment software can modify its operating parameters according to needs, change operating modes, easily simulate the energy consumption in various modes of operation, adjust and find the optimal operation plan of the water injection pipe network. Application examples show that the judgment rules of the optimal operation mode of the water injection system and the optimization method of operating parameters can be used as an effective means for selecting the optimal operation plan for a large-scale water injection pipeline network.
Delineating deep basement discontinuities of Qarun Lake Area, Egypt
Springer Science and Business Media LLC - Tập 1 - Trang 51-64 - 2011
The current study is mainly concerned with the description and analysis of the available aeromagnetic anomalies using different methodologies. Some structural elements could be deduced from the qualitative interpretation of such magnetic anomalies. The analysis of the worked magnetic maps, which included the total intensity magnetic map, reduced to-pole map, upward-continued maps, downward-continued maps, anomaly separation based on their wavelengths, or anomaly widths and enhanced horizontal gradient filtering aided in divulging the structural regime of the basement rocks, as well as the shallower features. As a result of the investigation, a basement tectonic map of the study area was constructed. This map shows that the area is portrayed by the presence of several major alternating basement swells and troughs in belts trending ENE–WSW, N–S, NE–SW and E–W. These major trends with the other minor trends dissected the basement surface into several tilted fault blocks forming anticlinal and synclinal zones with various depths and directions. These structural elements are shown in the basement tectonic map, and named Camel Pass-Abu Roash high, El-Sagha high, El Faras-El faiym high and Qattrani-El Gindi low trends.
Novel hybrid machine learning optimizer algorithms to prediction of fracture density by petrophysical data
Springer Science and Business Media LLC - Tập 11 - Trang 4375-4397 - 2021
One of the challenges in reservoir management is determining the fracture density (FVDC) in reservoir rock. Given the high cost of coring operations and image logs, the ability to predict FVDC from various petrophysical input variables using a supervised learning basis calibrated to the standard well is extremely useful. In this study, a novel machine learning approach is developed to predict FVDC from 12-input variable well-log based on feature selection. To predict the FVDC, combination of two networks of multiple extreme learning machines (MELM) and multi-layer perceptron (MLP) hybrid algorithm with a combination of genetic algorithm (GA) and particle swarm optimizer (PSO) has been used. We use a novel MELM-PSO/GA combination that has never been used before, and the best comparison result between MELM-PSO-related models with performance test data is RMSE = 0.0047 1/m; R2 = 0.9931. According to the performance accuracy analysis, the models are MLP-PSO < MLP-GA < MELM-GA < MELM-PSO. This method can be used in other fields, but it must be recalibrated with at least one well. Furthermore, the developed method provides insights for the use of machine learning to reduce errors and avoid data overfitting in order to create the best possible prediction performance for FVDC prediction.
Integrated geochemical study of Chichali Formation from Kohat sub-basin, Khyber Pakhtunkhwa, PakistanAbstract
Springer Science and Business Media LLC - - 2020
An integrated geochemical study was performed for the assessment of the hydrocarbon potential, environment of deposition, thermal maturity and the organic matter’s source of the Chichali Formation in the Kohat sub-basin of Pakistan. The analytical techniques used included the total organic carbon (TOC), Rock–Eval (RE), organic petrography, column chromatography (CC) and gas chromatography mass spectrometry (GC–MS). The quantity of the organic matter (i.e., TOC), Rock–Eval parameters (such as the original hydrogen index, oxygen index and
Pore pressure prediction using seismic acoustic impedance in an overpressure carbonate reservoir
Springer Science and Business Media LLC - Tập 12 - Trang 3311-3323 - 2022
The drilling engineers favor a quantifiable understanding of the subsurface overpressure zones to avoid drilling hazards. The conventional pore pressure estimation techniques in carbonate reservoirs are prone to uncertainties that affect the calculated pore pressure model resolution and are still far from satisfactory. Basically, in carbonate reservoirs, the effect of chemical process and cementation on porosity is more important than the mechanical compaction, so the conventional pore pressure prediction methods based on the normal compaction trend mostly do not provide acceptable results. Using the conventional methods for carbonate reservoirs can yield large errors, even suggesting a reduction in abnormal pressure in overpressure zones where considerable attention must be paid. Conventional methods need to model density and velocity to calculate the effective and overburden pressures. Converting acoustic impedance to density and velocity is always associated with errors and generally provides low resolution, which adds substantial uncertainties to the pressure prediction. Although pore pressure measurements are usually associated with low resolution, additional error-prone steps can be dropped if used directly. This research outlines the pore pressure estimation of a famous Iranian carbonate reservoir using direct acoustic impedance without inverting it to density and velocity. Finally, this method gives acceptable results in carbonate formations compared to the results of the Repeat Formation Test (RFT) in this region. The results show a zone of overpressure between the two low-pressure intervals of the carbonate reservoir. This result can be of great help in determining reservoir boundaries as well as in planning for drilling trajectory for new wells. Furthermore, the pore pressure estimation results also show pressure reduction in the central part of the seismic section. The proposed approach is a viable alternative to the conventional method and is in line with the geological field report, where the ratio of hydrocarbon potential of total rock on the reservoir sides is higher than its middle part. In this study, we want to emphasize that the calibrated function obtained in our area can be used in similar basins with carbonate reservoirs.
Numerical modeling of robust production scenarios from shared oil reservoirs
Springer Science and Business Media LLC - Tập 5 - Trang 55-71 - 2014
A reservoir that has formed through millions of years of sedimentation almost never conforms to the established borderlines that define political entities or legal jurisdictions of neighboring countries. The term shared reservoir is given to such hydrocarbon deposits. After the discovery of shared reservoirs, the neighboring countries could jointly develop a cross-border hydrocarbon deposit or disagree on any framework for unitizing or jointly developing the reservoir. Furthermore, in order for any negotiation to take place, the contending sides need to settle on an unbiased agreement. This can only be done after the term “unbiased” is defined quantitatively in technical terms. Although defining a reservoir before thorough exploration is challenging and rather unreliable, understanding the behavior of shared reservoirs is highly valued since many reservoirs around the globe, including the world’s largest condensate gas reservoir, in under such collaborative ownership. It is evident that optimized production from such reservoirs will benefit their rightful possessors and the rest of the world. This study investigates all main factors that influence production from a shared oil reservoir and demonstrates how each neighboring country is affected by variations of each of these factors. Displays of simulated reservoir at potential production conditions complement our quantitative analysis throughout this study.
Accelerated optimization of CO2-miscible water-alternating-gas injection in carbonate reservoirs using production data-based parameterization
Springer Science and Business Media LLC - Tập 13 - Trang 1833-1846 - 2023
Enhancing oil recovery in reservoirs with light oil and high gas content relies on optimizing the miscible water alternating gas (WAG) injection profile. However, this can be costly and time-consuming due to computationally demanding compositional simulation models and numerous other well control variables. This study introduces WAGeq, a novel approach that expedites the convergence of the optimization algorithm for miscible water alternating gas (WAG) injection in carbonate reservoirs. The WAGeq leverages production data to create flexible solutions that maximize the net present value (NPV) of the field, while providing practical implementation of individual WAG profiles for each injector. The WAGeq utilizes an injection priority index to rank the wells and determine which should inject water or gas at each time interval. The index is built using a parametric equation that considers factors such as producer and injector relationship, water cut (WCUT), gas–oil ratio (GOR), and wells cumulative gas production, to induce desirable effects on production and WAG profile. To evaluate WAGeq’s effectiveness, two other approaches were compared: a benchmark solution named WAGbm, in which the injected fluid is optimized for each well over time, and a traditional baseline strategy with fixed 6-month WAG cycles. The procedures were applied to a synthetic simulation case (SEC1_2022) with characteristics of a Brazilian pre-salt carbonate field with karstic formations and high CO2 content. The WAGeq outperformed the baseline procedure, improving the NPV by 6.7% or 511 USD million. Moreover, WAGeq required fewer simulations (less than 350) than WAGbm (up to 2000), while delivering a slightly higher NPV. The terms of the equation were also found to be essential for producing a WAG profile with regular patterns on each injector, resulting in a more practical solution. In conclusion, WAGeq significantly reduces computational requirements while creating consistent patterns across injectors, which are crucial factors to consider when planning a practical WAG strategy.
Geochemical evaluation of Khami Group oils in the South Dezful Embayment, Iran
Springer Science and Business Media LLC - Tập 10 - Trang 3241-3254 - 2020
An integrated geochemical study, including GC, GC–MS and stable carbon isotope analyses, was conducted on a suite of oil samples from the Khami Group reservoirs to provide new insights into the Upper Jurassic–Lower Cretaceous petroleum system in the South Dezful Embayment. Possible source rocks were also characterized using Rock–Eval pyrolysis to address the likely potential source rocks. The oil samples representing four major reservoirs (Surmeh, Fahliyan, Gadvan and Dariyan) constitute a single genetic oil family according to bulk and biomarker parameters. High API (> 38°), highly saturated hydrocarbons (Sat > 65%), very low asphaltene content (Asp < 2%) and raised saturates/aromatics ratio (Sat/Aro > 2) are the bulk diagnostic characteristics of the studied oils implying more dominant terrigenous nature of the precursor organic matter. The predominance of C29 regular steranes (~ 40%), presence of C29Ts as well as very low gammacerane (< 10%) and moderate C35/C34 homohopane (< 1) are consistent with the mixed marine–terrigenous dysoxic organic matter input. The oils are assumed to be originated from Early Cretaceous source rocks at the peak of the oil generation window in a kitchen area located to the south of the studied region (i.e., the Binak–Borazjan Trough). The hydrocarbons were migrated from this kitchen to the structurally shallow-seated reservoirs in the center and west of the Kharg-Mish local paleo-high. The Khami Group reservoirs are not effectively sealed by the thin Hith anhydrites, and the Kazhdumi Formation finally trapped the migrated hydrocarbons. This study improves our knowledge regarding one of the active petroleum systems in the South Dezful Embayment, enhancing petroleum exploration success by navigating further drillings into the more prosperous targets.
Determining the domain of in situ stress around Marun Oil Field’s failed wells, SW IranAbstract
Springer Science and Business Media LLC - Tập 10 Số 4 - Trang 1317-1326 - 2020
Accurate determination of the in situ stress domain in oil fields is of paramount importance in drilling, completion, and maintenance of wells and in petroleum geomechanics. Determination of the magnitude and direction of stresses induced by drilling around the wellbores is the first step in geomechanical studies and wellbore stability analyses. Regarding the importance of casing collapse problems in Marun Oil Field, as the first step of this investigation, geomechanical studies were conducted to determine the in situ stress domain in the failed wellbores. Using density measurements, the vertical stress (
Simulation of two-phase flow by injecting water and surfactant into porous media containing oil and investigation of trapped oil areas
Springer Science and Business Media LLC - Tập 11 - Trang 1353-1362 - 2021
Nowadays, as the oil reservoirs reaching their half-life, using enhanced oil recovery methods is more necessary and more common. Simulations are the synthetic process of real systems. In this study, simulation of water and surfactant injection into a porous media containing oil (two-phase) was performed using the computational fluid dynamics method on the image of a real micro-model. Also, the selected anionic surfactant is sodium dodecyl sulfate, which is more effective in sand reservoirs. The effect of using surfactant depends on its concentration. This dependence on concentration in using injection compounds is referred to as critical micelle concentration (CMC). In this study, an injection concentration (inlet boundary) of 1000 ppm was considered as a concentration less than the CMC point (2365 ppm). This range of surfactant concentrations after 4.5 ms increased the porous media recovery factor by 2.21%. Surfactant injection results showed the wettability alteration and IFT finally increases the recovery factor in comparison with water injection. Also, in wide channels, saturation front, and narrow channels, the concentration front has a great effect on the main flowing.
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