Research Paper
Chemical Engineering
Bahman Behzadi; Maziar Noei; Alireza Azimi; Masoume Mirzaei; Hossien Anaraki Ardakani
Abstract
Water can contain microorganisms and cause deposition and corrosion in cooling tower systems. Therefore, the water treatment of cooling towers is essential. Various biocides are used to remove bacteria and disinfect the water of cooling towers, and the most commonly used are sodium hypochlorite and chlorine ...
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Water can contain microorganisms and cause deposition and corrosion in cooling tower systems. Therefore, the water treatment of cooling towers is essential. Various biocides are used to remove bacteria and disinfect the water of cooling towers, and the most commonly used are sodium hypochlorite and chlorine compounds. This work examined two chlorinated water, namely hypochlorous acid and sodium hypochlorite, in two pilot and industrial cooling towers. The results of the experiments on the pilot tower showed that the performance of hypochlorous acid in the disinfection and removal of bacteria and microorganisms was excellent. The total bacterial count decreased from 10000 to less than 800 (cfu/mL) compared to sodium hypochlorite. The experiments were performed on the industrial cooling tower of an acetic acid unit for six months, in which pH, free chlorine, total bacterial count (TBC), and sulfate-reducing bacteria (SRB) were measured. The very high disinfection power of hypochlorous acid compared to sodium hypochlorite and its relatively lower pH level led to a significant reduction in the use of chemicals in the cooling tower. The experiments and TBC and SRB tests showed outstanding performance in using hypochlorous acid.
Research Paper
Petroleum Engineering – Drilling
Afshar Alihosseini; Ali Hassan Zadeh; Majid Monajjemi; Mahdi Nazary Sarem
Abstract
Wellbore stability is one of the challenges in the drilling industry. Shale formation is one of the most problematic rocks during drilling because the rock has very low permeability and tiny pores (nanometers). This study assesses the viability of the alumina nanoparticles (Al2O3) in water-based mud. ...
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Wellbore stability is one of the challenges in the drilling industry. Shale formation is one of the most problematic rocks during drilling because the rock has very low permeability and tiny pores (nanometers). This study assesses the viability of the alumina nanoparticles (Al2O3) in water-based mud. The effectiveness of alumina nanoparticles as a mud additive in improving the rheological properties in water-based drilling mud is investigated. The alumina nanoparticles have specific chemical and physical properties, such as high compressive strength, high hardness, and high thermal conductivity. These properties improve the properties of water-based drilling mud, reduce filtration loss, and meet environmental regulations. The results of experimental data show that alumina nanoparticle improves rheological properties such as yield point gel strength (GEL 10 s, Gel 10 min) of water-based drilling that can be utilized to enhance the significant feature of drilling mud, particularly in rheology and filtration. Preliminary data demonstrated that alumina nanoparticles, a nano additive, possess proper properties like thermal stability, rheology enhancement, fluid loss control, and lubrication. It is likely to encounter shale formation plug and significant improvement formation pressure. In addition, alumina nanoparticles reduced 60% API/HPHT fluid loss by 60% compared to the blank sample. The most striking feature is that nanofluid improved shale integrity between 60% and 70% compared to the blank sample. Further, the experimental data of the CT scan show that the mud cakes formed by each of fluid samples, including nanoparticles containing alpha- and gamma-alumina base are more cohesive and cause an integrated filter cake on the well.
Research Paper
Petroleum Engineering – Exploration
Samuel Getnet Tsegaye
Abstract
The lithofacies and environments of deposition interpretations of the Calub–Hilala field toward the central trough of Ogaden Basin were analyzed, and geophysical well logs from three deep exploration wells, namely Calub-1, Bodle-1, and Hilala-2, were used. A methodology was piloted in establishing ...
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The lithofacies and environments of deposition interpretations of the Calub–Hilala field toward the central trough of Ogaden Basin were analyzed, and geophysical well logs from three deep exploration wells, namely Calub-1, Bodle-1, and Hilala-2, were used. A methodology was piloted in establishing the sedimentary facies, their successions, and environments of deposition. Gamma-ray, neutron, sonic, and resistivity logs were used for lithologic and depositional environment identification. An attempt was also made to identify formation tops and well-to-well lithostratigraphic correlation basing gamma-ray log trends and correlate with the cored interval of the wells for lithological comparisons. Lithofacies interpretation was carried out with Schlumberger’s Petrel software, version 2009. Correlation techniques were conducted to delineate the subsurface trends of these facies with electrofacies to compare facies interpretation results that were implied using the wireline log signatures.Ten formations, namely Calub, Bokh, Gumburo, Adigrat, Transition, Hamanlei (Lower, Middle, and Upper), Urandab, Gebredare, Gorrahei, Mustahil, and five log facies, namely a cylindrical-shaped log trend representing aeolian, i.e., braded fluvial, a funnel-shaped facies representing a crevasse splay, a carbonate, shallowing upward sequence and shallow marine sheet sand, a bell-shaped facies representing transgressive marine shelf, a symmetrical-shaped facies representing sandy offshore, and an irregular shaped facies representing fluvial floodplain, were recognized. The environments of deposition delineated for the study area are alluvial and transgressive–regressive marine.
Research Paper
Chemical Engineering – Gas Processing and Transmission
Alireza Afsharpour
Abstract
In current work, perturbed chain-statistical associating fluid theory (PC-SAFT) equation of state (EoS) together with the reaction equilibrium thermodynamic model (RETM) was employed to correlate H2S solubility in three carboxylate ionic liquids including [emim][Ace], [bmim][Ace], and [hmim][Ace]. The ...
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In current work, perturbed chain-statistical associating fluid theory (PC-SAFT) equation of state (EoS) together with the reaction equilibrium thermodynamic model (RETM) was employed to correlate H2S solubility in three carboxylate ionic liquids including [emim][Ace], [bmim][Ace], and [hmim][Ace]. The RETM proposes a chemical reaction approach between ionic liquid (IL) (B) and H2S (A) in the liquid phase. Moreover, PC-SAFT EoS contributes to VLE calculations. All the H2S and the investigated ILs, as self-associating components, are assumed to follow the 2B association scheme. Five adjustable variables of PC-SAFT EoS for pure components were calculated using experimental data of liquid density and vapor pressure. Afterward, the binary systems were investigated by applying RETM. Indeed, two nested loops calculate the liquid phase, total pressure, and vapor phase concentrations, respectively. For these systems, an AAD% of 2.29%, 3.09%, and 7.65% was obtained for H2S–[emim][Ace], H2S–[bmim][Ace], and H2S–[hmim][Ace] systems, respectively.
Research Paper
Petroleum Engineering
Mohsen Mansouri; Mehdi Parhiz; Behrouz Bayati; Yaser Ahmadi
Abstract
One of the critical issues in the oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a standard method for solving this problem. Although nickel oxide and zeolite have been addressed in previous research to solve the asphaltene precipitation ...
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One of the critical issues in the oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a standard method for solving this problem. Although nickel oxide and zeolite have been addressed in previous research to solve the asphaltene precipitation problem, using NiO/Na-ZSm-5 (the primary goal of this study) has not been developed to solve relevant asphaltene precipitation problems. The crystalline structure and morphology of the synthesized nanoparticles were analyzed with the help of X-ray diffraction spectrometry (XRD), scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FTIR), and energy-dispersive X-ray spectroscopy (EDXS). The results show that the nanoparticles were well synthesized and preserved their crystalline structure with a diameter of 13.6 nm after synthesis. The EDXS analyses also proved that the sorbent adsorbed an amount of asphaltene. In the next step, asphaltene adsorption experiments were carried out at various concentrations of asphaltene and temperatures, and the effect of different variables, including the initial concentration of asphaltene, temperature, and the ratio of heptane to toluene, on the asphaltene adsorption rate was evaluated. The results indicate that with an increase in the initial asphaltene concentration from 25 to 2000 ppm, the asphaltene adsorption rate in zeolite increases. At concentrations less than 500 ppm, a rise in the temperature reduces the asphaltene adsorption, while at concentrations higher than 500 ppm, raising the temperature from 25 to 55 °C increases asphaltene adsorption capacity on zeolite. Further, more significant adsorption is observed at a heptane-to-toluene ratio of 0.4 with q = 25.17 mg/g. Evaluating the effects of kinetic adsorption molecules of asphaltene on these nanoparticles shows that the adsorption process reaches equilibrium in less than 2 h. The experimental data were adapted according to Lagrangian pseudo-first-order and pseudo-second-order models to determine the kinetic mechanism of this process. The Langmuir and Freundlich adsorption isotherms were evaluated, and the isotherms resulting from the Langmuir isotherm model were of good conformity, indicating that adsorption at the homogenous level occurred with a single-layered coating. In the final step, after evaluating the thermodynamic conditions, the spontaneity of the asphaltene adsorption process was proved.
Research Paper
Petroleum Engineering
Mehdi Rezaei Abiz; Saeid Norouzi Apourvari; Saeed Jafari; Mahin Schaffie
Abstract
Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability ...
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Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention, and blocking the pore throats. This study strengthens our understanding of the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. To this end, a transport approach utilizing the kinetic Langmuir model is developed and validated using experimental data. After that, the effects of reservoir rock type and its properties (clay content and grain size), the salinity of injected fluid, and the reservoir temperature on the transport and retention of nanoparticles in porous media concerning enhanced oil recovery methods are investigated. Since the concentration of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. Brine salinity also has the most significant impact on the amount of nanoparticles deposited on the rock surface. The surface covered by nanoparticles increased from 10% to 82% after changing salinity from 3 wt % NaCl to the API brine.
Research Paper
Petroleum Engineering – Production
Behzad Orangii; Mohammad Ali Riahi
Abstract
This paper investigates the role of the adequate thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Adequate thickness is a term that includes the total gross thickness of rocks by lithofacies for a selected wellbore. The lithology of the Asmari ...
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This paper investigates the role of the adequate thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Adequate thickness is a term that includes the total gross thickness of rocks by lithofacies for a selected wellbore. The lithology of the Asmari formation in the studied area consists of dolomite, sandstone, lime, dolomitic-lime, sandstone-shale, and shale limestone dolomites. Based on the existing well-logs, the average shale volume, the effective arithmetic means of porosity in the gross intervals, and average water saturation or hydrocarbon-bearing increments of the studied field are calculated using well-logs. In wellbore #A, a depth interval of 2214 to 2296 m shows 9.6% average shale volume, 27.2% average water saturation, and 20.9% average porosity. A depth interval of 2213 to 2280 m, in wellbore #B, shows 6% average shale volume, 21.25% average water saturation, and 28.5% average porosity. Based on our petrophysical assessments, we divide the Asmari reservoir in the studied field into eight zones. Zone 1 is made of carbonate (calcareous and dolomitic), and zones 2–5 are mainly sandstone; zones 7 and 8 are calcareous and shale, and zone 6 is a mixture of all the rocks mentioned above. Among these eight zones, there are two primary hydrocarbon productive zones. The numerical calculation of in situ oil volume showed that zone 2 contains 65% of oil volume in this reservoir. With more than 80% sand, this zone has the highest net hydrocarbon column.
