| 1. |
- Aftab, A., et al.
(author)
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Novel zinc oxide nanoparticles deposited acrylamide composite used for enhancing the performance of water-based drilling fluids at elevated temperature conditions
- 2016
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In: Journal of Petroleum Science and Engineering. - : Elsevier. - 0920-4105 .- 1873-4715. ; 146, s. 1142-1157
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Journal article (peer-reviewed)abstract
- Multifunctional nano-micron composite compared to single nano-sphere materials revealed wide applications to enhance the physical and chemical stability of base fluids. Therefore, it can be a possible solution for the improvement of the rheological properties and shale inhibition characteristics of conventional water-based drilling fluid (WBDF). The primary goal of the study was to investigate the effects zinc oxide nanoparticles-acrylamide composite termed as ZnO-Am composite over rheological and shale swelling behavior of conventional WBDF. Herein, ZnO-Am composite was synthesized and successfully characterized by X-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR), thermalgravimeteric analysis (TGA), scanning electron microscope (SEM) and field emission electron microscope (FESEM). Results revealed that the rheological properties such as 10-min gel strength (10-min GS), apparent viscosity (AV), and plastic vicscocity (PV) were slightly increased and obtained within operating range at 150 degrees F by adding the synthesized composite in conventional WBDF. Lubricity was improved by 25% at 150 degrees F. API filtrate loss volume was reduced by 14%. Elevated temperature and pressure (ETP) filtrate loss volume (500 psi, 250 degrees F) was slightly minimized. Shale swelling was merely reduced from 16% to 9%. These findings will contribute to enhance the oil and gas well drilling operations.
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| 2. |
- Al-Marooqi, S.H, et al.
(author)
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Pore-Scale modelling of NMR relaxation for the characterization of wettability
- 2006
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105 .- 1873-4715. ; 52:1-4, s. 172-186
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Journal article (peer-reviewed)abstract
- Several research groups are currently investigating the determination of wettability usingNMR relaxation times. Although correlations with traditional wettability indices have been presented with some success, further effort is needed to relate the wettability atpore-scale to a core-scale measurement of NMR response. For example, a qualitative method using the arithmetic mean of relaxation times at various saturations has been presented [Guan, H., Brougham, D., Sorbie, K.S., Packer, K.J., 2002. Wettability effects in a sandstone reservoir and outcrop cores from NMR relaxation time distributions. J. Petroleum Sci. and Eng. 34, 35-54] and a wettability index that quantifies the amount of surface area that is wetted either by oil or by water, by using the T2 peak at four different saturations has been proposed [Fleury, M., Deflandre, F., 2003. Quantitative evaluation of porous media wettability using NMR relaxometry. Mag. Reson. Imaging 21, 385-387]. Our group at the Imperial College have previously shown experimentally that the T2 distribution provides valuable information about wettability and overall fluid distribution within thepore-space, which is lost if only a single value from the T2 distribution is considered [Al-Mahrooqi, S.H., Grattoni, C.A., Moss, A.K., Jing, X.D., 2003. An investigation of the effect ofwettability on NMR characteristics of sandstone rock and fluid systems. J. Petroleum Sci. and Eng. 39, 389-398]. In this paper we use a simple pore-scale model to understand the effect of wetting and its relationship with NMR relaxation times. The model uses triangular capillary pores with a given pore size distribution. The oil/water distribution within thepores is obtained as a function of capillary pressure and wettability. At a given capillary pressure, the volumes and surface areas of water and oil are calculated for each individual pore. This allows us to calculate the theoretical T2 distribution for that pore size distribution as a function of wettability and saturation. We have used the model to study the T2 distribution for a range of wettabilities and saturations. Results from the model confirmed previous observations from experiments regarding the effect of wettability onNMR T2 distributions. Based on these qualitative results, an improved index for characterising wettability from the T2 distribution has been proposed. We tested the proposed index using NMR T2 data from synthetic and real sandstone core plugs with different wettabilities, ranging from strongly water-wet to strongly oil-wet. Comparison between the proposed index and wettability for the synthetic samples and Amott-Harvey index for core plugs show good correlation.
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| 3. |
- Bergmann, Peter, et al.
(author)
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Review on geophysical monitoring of CO2 injection at Ketzin, Germany
- 2016
-
In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105. ; 139, s. 112-136
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Journal article (peer-reviewed)abstract
- Geophysical monitoring activities were an important component of the CO2 injection program at the Ketzin site, Germany. Here we report on the seismic and electrical resistivity tomography (ERT) measurements performed during the period of the site development and CO2 injection. Details on the site geology, the history of the CO2 injection operation, and petrophysical models relevant for the interpretation of the geophysical data are presented. The seismic measurements comprise 2D and 3D surface seismic surveys, vertical seismic profilings, and crosshole measurements. Apart from the measurements, results from advanced processing methods, such as impedance inversion and full-waveform inversion are also presented. In addition, results from crosshole ERT and surface-downhole ERT are presented. If operational efforts are taken into consideration we conclude that a combination of several geophysical methods is preferable given the demands of a spatiotemporally comprehensive monitoring program. We base this conclusion on that the different imaging characteristics and petrophysical sensitivities of different methods can complement each other. An important finding is, based on signal quality and reduced operational costs, that the use of permanent installations is promising. Generally, specific monitoring layouts will depend on site-specific characteristics, such as reservoir depth, availability of wells, petrophysical characteristics, and accessibility of surface locations. Given the comprehensive range of methods applied, the reported results are not only relevant to the operation of CO2 storage sites, but are also of interest to other monitoring projects dealing with fluid injection or production.
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| 4. |
- Figueiredo, Bruno, et al.
(author)
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Study of hydraulic fracturing processes in shale formations with complex geological settings
- 2017
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105 .- 1873-4715. ; 152, s. 361-374
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Journal article (peer-reviewed)abstract
- Hydraulic fracturing has been applied to extract gas from shale-gas reservoirs. Complicated geological settings,such as spatial variability of the rock mass properties, local heterogeneities, complex in situ stress field, and preexistingbedding planes and faults, could make hydraulic fracturing a challenging task. In order to effectivelyand economically recover gas from such reservoirs, it is crucial to explore how hydraulic fracturing performs insuch complex geological settings. For this purpose, numerical modelling plays an important role because suchconditions cannot be reproduced by laboratory experiments. This paper focuses on the analysis of the influenceof confining formations and pre-existing bedding planes and faults on the hydraulically-induced propagation ofa vertical fracture, which will be called injection fracture, in a shale-gas reservoir. An elastic-brittle model basedon material property degradation was implemented in a 2D finite-difference scheme and used for rock elementssubjected to tension and shear failure. A base case is considered, in which the ratio SR between the magnitudesof the horizontal and vertical stresses, the permeability kc of the confining formations, the elastic modulus Epand initial permeability kp of the bedding plane and the initial fault permeability kF are fixed at reasonablevalues. In addition, the influence of multiple bedding planes, is investigated. Changes in pore pressure andpermeability due to high pressure injection lasting 2 h were analysed. Results show that in our case during theinjection period the fracture reaches the confining formations and if the permeability of those layers issignificantly larger than that of the shale, the pore pressure at the extended fracture tip decreases and fracturepropagation becomes slower. After shut-in, the pore pressure decreases more and the fracture does notpropagate any more. For bedding planes oriented perpendicular to the maximum principal stress direction andwith the same elastic properties as the shale formation, results were found not to be influenced by theirpresence. In such a scenario, the impact of multiple bedding planes on fracture propagation is negligible. On theother hand, a bedding plane softer than the surrounding shale formation leads to a fracture propagationasymmetrical vertically with respect to the centre of the injection fracture with a more limited upward fracturepropagation. A pre-existing fault leads to a decrease in fracture propagation because of fault reactivation withshear failure. This results in a smaller increase in injection fracture permeability and a slight higher injectionpressure than that observed without the fault. Overall, results of a sensitivity analysis show that fracturepropagation is influenced by the stress ratio SR, the permeability kc of the confining formations and the initialpermeability kp of the bedding plane more than the other major parameters.
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| 5. |
- Gholami, A., et al.
(author)
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Porosity prediction from pre-stack seismic data via committee machine with optimized parameters
- 2022
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105. ; 210
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Journal article (peer-reviewed)abstract
- Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.
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| 6. |
- Grattoni, C.A, et al.
(author)
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Polymers as relative permeability modifiers : adsorption and the dynamic formation of thick polyacrylamide layers
- 2004
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105 .- 1873-4715. ; 45:3-4, s. 233-245
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Journal article (peer-reviewed)abstract
- Water production from oil and gas reservoirs is increasing worldwide. as more reservoirs are becoming mature. In order to control water production, polymers and gels are often injected into the formation to reduce the water permeability. These systems are known as relative permeability modifiers. Although these methods sometimes lead to significant cost savings, and many successful treatments have been reported, a wider application is hindered by the lack of understanding of the basic mechanisms of permeability modification by polymers. This paper presents some pore-level and basic studies on polymers, with the aim of providing a better understanding of these systems. Experiments have been performed in micro-scale glass flow models, and atomic force microscopy was used to validate the flow observations. The role of adsorption and flow of polyacrylamides in the formation of thick layers is described. The size of statically adsorbed polyacrylamide layers depends on the polymer characteristics (molecular weight, degree of hydrolysis, salinity, etc.), but is less than 250 nm for all the systems studied. On the other hand, dynamically formed polymer layers can reach several thousands of nanometres. The existence of these thick polymer layers is shown here, to our knowledge for the first time, through flow experiments and AFM measurements. While mechanical retention cannot occur under our experimental conditions, the mechanism of adsorption-entanglement gives a reasonable mechanistic description of the dynamic formation of thick layers. The implications of these mechanisms in the modelling of the flow and selection of polymer systems are discussed.
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| 7. |
- Hillier, Stephen
(author)
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Multi-technique approach to the petrophysical characterization of Berea sandstone core plugs (Cleveland Quarries, USA)
- 2017
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105. ; 149, s. 436-455
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Journal article (peer-reviewed)abstract
- Berea sandstone has been used by the petroleum industry as a representative model siliciclastic rock for a number of years. However, only incomplete data has been reported in the literature regarding its petrographic, geochemical, and petrophysical properties. In particular knowledge of the mineral distribution along the pore walls is particularly scarce, despite the fact that mineral exposed in the pore space will be crucial in determining the rock-fluid interactions that occur during core-flooding experiments. In this paper, four Berea sandstone samples (with 4 different permeability ranges from < 50 mD, 50-100 mD. 100-200 mD, and 500-1000 mD) were subjected to a multi-technique characterization with an emphasis on determining the mineral composition, and distribution at the pore surface as well as pore structure and connectivity analysis. The mineral distribution was measured in two-dimensions by chemical mapping using energy dispersive X-ray spectroscopy -scanning electron microscopy (SEM-EDX). The bulk composition of the Berea sandstones was also measured by X-ray diffraction and micro-X-ray computed tomography. From this, it was found that authigenic minerals, especially clay minerals, make up a small portion of the bulk rock volume (3.3-8%) but are overrepresented at the pore surfaces and in pore spaces compared to the other major mineral constituents of the rock (quartz and feldspar). The effective mineralogy, from the standpoint of rock-fluid interactions, is the mineralogy that predominates at pore surfaces. For the Berea sandstone samples studied, the effective mineralogy is represented, mainly, by kaolinite, illite, and chlorite. For 3 of the four permeability ranges studied, kaolinite is the predominant pore lining mineral observed. In the remaining sample (50-100 mD), illite is the predominant mineral. In addition to SEM, we used atomic force microscopy to show that the nano-sized particles with the shape and size of clay crystals are observed on the surface of recrystallised quartz grains in a Berea sample. Regardless of their origin and identity, the presence of these particles shows that the quartz grain surfaces in Berea sandstone are more heterogeneous than previously assumed. Carbonate cement was somewhat localized throughout two of the Berea sandstone specimens, however, quartz cement is common in all of the Berea cores studied and include both microcrystalline quartz and amorphous silica phases. The pore structure within the four different Berea samples was studied using a combination of X-ray computed tomography, mercury injection porosimetry and high resolution scanning electron microscopy. Results show that two Berea sandstone permeability ranges have a bimodal pore-throat-size distribution whereas the other two were dominated by a unimodal pore-throat size distribution. SEM imaging of the pore network showed that permeability is mainly controlled by pore connectivity in the clay mineral matrix. Next to the pore connectivity, three-dimensional pore space showing both pore-to-pore and pore-to-pore-throat-to-pore relationships are also important.
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| 8. |
- Huang, Ruijie, et al.
(author)
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Well performance prediction based on Long Short-Term Memory (LSTM) neural network
- 2022
-
In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105 .- 1873-4715. ; 208
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Journal article (peer-reviewed)abstract
- Fast and accurate prediction of well performance continues to play an increasingly important role in development adjustment and optimization. It is now possible to predict performance more accurately using neural networks thanks to the advancement of artificial intelligence. In this study, A Long Short-Term Memory (LSTM) neural network model which considered gas injection effect was established to forecast the production performance of a carbonate reservoir in the Middle East. Over 12 years of surveillance data from 17 producers and 11 injectors were selected as the dataset. A correlation analysis was performed to determine the input and output variables of the model before establishing the model. Using historical data from the first 4000 days, the model is trained and validated before it is used to predict the performance of the next 500 days. After that, the calculation results of this model and traditional reservoir numerical simulation (RNS) were compared under the same conditions. The results show that the average error of the LSTM method is 43.75% lower than that of traditional RNS. Moreover, the total CPU time and comprehensive computing power consumption of LSTM method only account for 10.43% and 36.46% of RNS's, respectively. Thus, it is clear that the LSTM approach has a significant advantage when it comes to calculating. In the end, we categorized all 17 producers into three groups based on GOR predictions for the next 500 days, and proposed optimization and adjustment techniques for each type. This study provides a new direction for the application of artificial intelligence in oil and gas development.
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| 9. |
- Karimpouli, Sadegh, et al.
(author)
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Neuro-Bayesian facies inversion of prestack seismic data from a carbonate reservoir in Iran
- 2015
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In: Journal of Petroleum Science and Engineering. - : Elsevier BV. - 0920-4105 .- 1873-4715. ; 131, s. 11-17
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Journal article (peer-reviewed)abstract
- Facies study is a powerful tool to better understand complexities of carbonate reservoirs. Porosity, frame flexibility factor and bulk modulus of fluid are believed to be the most proper rock physical parameters to define desired facies in carbonate rocks. Bayesian inversion is a natural choice to invert the desired facies from seismic data. The inversion method then often includes (1) Bayesian inversion of elastic parameters from seismic data, (2) Bayesian inversion of rock physical parameters from elastic parameters by considering an appropriate up-scaling method and (3) Bayesian classification of fades from inverted rock physical parameters. Neuro-Bayesian inversion method has been introduced in this study, which is a combination of an artificial neural network (ANN) classifier and Bayesian inversion of rock physical parameters that allows an improved facies prediction. Comparison between Bayesian and neuro-Bayesian methods is performed to illustrate the accuracy of predicting the facies, improved from 67% to 73% in the final results. Moreover, the Bayesian method predicted just two of the three fades where Neuro-Bayesian method predicted all the three facies successfully.
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| 10. |
- Khormali, Azizollah, et al.
(author)
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Development of a new chemical solvent package for increasing the asphaltene removal performance under static and dynamic conditions
- 2021
-
In: Journal of Petroleum Science and Engineering. - : Elsevier. - 0920-4105 .- 1873-4715. ; 206
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Journal article (peer-reviewed)abstract
- In this work, a new solvent package (named TPMDS) for asphaltene removal under static and dynamic conditions was developed through a set of experiments. TPMDS consists of toluene, pyridine, methanol, surfactant dodecylbenzenesulfonic and sodium hydroxide. The optimum concentrations of TPMDS components were determined based on the efficiency evaluation of the chemical reagents to eliminate the asphaltene precipitation under static conditions. The highest effectiveness of the developed solvent package under static conditions was found to be 98%, which was observed at a soaking time of 6 h and a mass concentration of 1%. TPMDS had high performance (more than 97.5%) for asphaltene removal in four different oil samples containing various asphaltene concentrations. The results of the turbidity and dissolution rate experiments of asphaltene in the presence of TPMDS and toluene showed that the performance of TPMDS for asphaltene removal is significantly better than toluene. In addition, core flood tests were carried out with the use of TPMDS and toluene. Pressure drop due to asphaltene precipitation in the carbonate core samples was reduced eight times using the developed solvent package. The damaged permeability due to asphaltene deposition was 51% of the initial rock permeability before injection of any solvent. The results of core flood tests showed that the rock permeability has reached about 94% and 71% of the initial permeability after injection of TPMDS and toluene, respectively. Despite the increase in the amount of asphaltene precipitation in the core samples by increasing injection rate, the efficiency of the developed solvent was not decreased by changing the injection rate since the performance of the TPMDS was improved by the appearance of a synergistic effect for asphaltene dissolution. Furthermore, oil viscosity reduction with the use of TPMDS was more significant than with the use of toluene. The corrosion rate of the metal samples in the presence of the developed solvent package solution was less than 0.08 mm/year in a temperature range from 25 degrees C to 100 degrees C, which is less than an acceptable threshold corrosion rate of 0.1 mm/year. Moreover, the results of field analysis showed that the oil production rate could be enhanced by 3.3 times after treatment by TPMDS. Asphaltene removal effectiveness in the production wells using the industrial reagent and TPMDS has reached 84 and 96%, respectively. The rock permeability after treatment by TPMDS was increased by about 290%. TPMDS can be used for asphaltene removal in the near-wellbore region, production equipment, and tubing.
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