One of the important issues in oil industry is related to asphaltene precipitation during different stages, and using nanoparticles is known as a common method for solving this problems. Although nickel oxide and zeolite have been addressed in previous researches for solving asphaltene precipitation problem, Using NiO/Na-ZSm-5 (the main goal of this study) has not been developed for solving relevant asphaltene precipitation problem. The crystalline structure and morphology of the synthesized nanoparticles have been analyzed with the help of XRD, SEM, FTIR and EDX. Results show that the nanoparticles were well synthesized and after synthesis with a diameter of 13.6 nm. The EDX analyses also approved that an amount of asphaltene was adsorbed by the sorbent. Asphaltene adsorption experiments were carried out at various asphaltene concentrations and different temperatures and the effect of different variables of initial asphaltene concentrations, temperature and ratio of heptane to toluene were evaluated on asphaltene adsorption rate. The results indicate that with an increase in the initial asphaltene concentration from 25 to 2000 ppm, the asphaltene adsorption rate in zeolite increases. In concentrations less than 500 ppm, a rise in temperature results in reduced asphaltene adsorption, while at concentrations higher than 500 ppm, with a rise in temperature from 25°C to 55°C, asphaltene adsorption capacity on zeolite increases. Also greater adsorption has been observed for Heptane/Toluene=0.4 with q=25.17 mg/g. For determining the kinetic mechanism of this process, the experimental data were adapted according to Lagrangian pseudo-first and second-order models. The Langmuir and Freundlich adsorption isotherms were evaluated, in which the isotherms resulting from the Langmuir isotherm model were of adequate conformity. This indicates that adsorption at the homogenous level occurred with single-layered coating. In the final step, after evaluating the thermodynamic conditions, the spontaneity of the asphaltene adsorption process was proven.
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 about the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. For doing so, a transport approach utilizing kinetic Langmuir model is developed and validated using experimental data. Thereafter, the effect of reservoir rock type and its properties (clay content and grain size), salinity of injected fluid, and reservoir temperature on the transport and retention of nanoparticles in porous media in relation to enhanced oil recovery methods is investigated. Since the amount 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. It was also found that the brine salinity has the greatest impact on the amount of nanoparticles deposited on the rock surface. The surface covered by NPs increased from 10 to 82 % after changing salinity from 3 weight percent NaCl to API brine.
The lithofacies and environments of deposition interpretations of the Calub-Hilala field towards central trough of Ogaden Basin have been carried out. Geophysical well logs from three deep exploration wells; 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 respectively. An attempt were also made to identify formation tops and well to well lithostratigraphic correlation basing gamma ray log trends and correlating with cored interval of the wells for Lithological comparisons. Lithofacies interpretation was carried out with Schlumberger’s Petrel 2009TMsoftware. Correlation techniques were conducted to delineate the subsurface trends of these facies with electrafacies to compare facies interpretation results that were implied using the wire line log signatures.Ten (10) formations; Calub, Bokh, Gumburo, Adigrat, Transition, Hamanlei (Lower, Middle and Upper), Urandab, Gebredare, Gorrahei, Mustahil and Five (5) log facies; a cylindrical-shaped log trends representing aeolian, braded fluvial; a funnel-shaped facies representing a crevasse splay; a carbonate shallowing upward sequence and shallow marine sheet sand; 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.
In current work, Perturbed Chain- Statistical Associating Fluid Theory (PC-SAFT) 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 IL (B) and H2S (A) in the liquid phase. Moreover PC-SAFT EoS contributes for VLE calculations. All the H2S and the investigated ILs, as self-associating components, assumed to follow 2B association scheme.Five adjustable variables of PC- SAFT EoS for pure components were calculated using experimental data of liquid density and vapor pressure. Afterwards, the binary systems were investigated applying RETM. Indeed, two nested loops calculate the liquid phase, total pressure and vapor phase concentrations, respectively. For these systems, AAD% equal to 2.29, 3.09 and 7.65 were obtained for all ILs respectively.
Challenges on rock absolute permeability prediction from tiny sample when laboratory apparatus is not applicable and without pore network modelling is remarkable. This prediction using the characterization of micro-computed tomography images have been studied in this paper. Twenty series of 2D micro computed tomography rock binary images have been collected, each of them was considered as a 3D binary image. Their geometric measures in 2D and 3D for measuring image properties have been considered using Minkowski functionals and available functions, developing a regression model, absolute permeabilities have been evaluated. Some 2D and 3D geometric properties are considered. The area, the perimeter and the 2D Euler number are 2D binary images properties. The volume, the surface area, the mean breadth also known as integral of the mean curvature, and the 3D Euler Number are 3D binary images properties. Porosity and number of objects also have been considered as parameters of a regression model.To perform linear regression, twenty-four parameters were evaluated and some of them were chosen to be used. An equation is proposed based on the extensive study conducted which can predict rock permeability. This equation has two sets of parameter coefficients, one set predicts high permeability rocks (above two Darcy) and the other for low and medium permeability (less than two Darcy) which can be used for carbonated rock. Average absolute relative error for conducted cases is 0.06.
Formation damage is being reported during the secondary and tertiary stages of reservoir lifespan. One of the unpleasant sequences of formation damage caused by fine particles is permeability reduction due to pore plugging and bridging. The fine particles might exist initially in a porous medium, or be introduced by the external sources. In addition, there is a variety of particle types and sizes. The current research focuses on the effects of non-swelling clay minerals motions, such as the laminar ones found in Iranian sandstone reservoirs, on permeability. For this purpose, sand packs in a variety of glass bead sizes and containing aluminium oxide as fine particles were designed to scrutinize the motion of fine particles under various pressure differences, flow rates, and fine concentrations. It was concluded that for each of the three sand packs considered as the porous media in this study and composed of fine glass beads with different sizes, there is a critical flow rate which is a function of glass bead size. For the flow rates less than critical flow rate, bridges form stably and lead to the highest formation damage. After reaching the critical flow rate, the bridges weaken and then break; thereafter, relative permeability would be independent of flow rate. All in all, it was deduced that permeability reduction and formation damage are directly proportional to particle concentration, and inversely proportional to glass bead size. The reason for using solid glass spheres in this study is their flow ability, great strength, chemical stability, low thermal expansion.Keywords: Fine migration, Permeability reduction, Formation damage, Critical flow rate
This paper investigates the role of the effective thickness of the Asmari reservoir formation zones on oil production in one of the Iranian carbonate oil fields. Effective 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 is calculated from well-logs. The depth interval of 2214 to 2296, in wellbore #A shows 9.6% average shale volume, 27.2% average water saturation, and 20.9% average porosity. The depth interval of 2213 to 2280, 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), zones 2 to 5 are mainly sandstone, zones 7 and 8 are calcareous and shale and zone 6 is a mixture of all the above-mentioned rocks. Among these eight zones, there are two main hydrocarbon productive zones. The numerical calculation of in situ oil volume showed that zone two contains 65% of oil volume in this reservoir. This zone with more than 80% of sand has the highest net hydrocarbon column.
The Rock-Eval pyrolysis is a thermal method that is widely used by the petroleum geologist for evaluation of source rock characteristics and obtain geochemistry parameters. However, there are misconceptions and misuse in exceptional cases which could lead to erroneous conclusions in using Rock-Eval pyrolysis to evaluate properties of the organic matter, a cross-plot of S2 (petroleum potential) versus TOC (total organic carbon) is an usable tool which can facilitate better interpretations. The graph can apply as a criterion accuracy of geochemistry parameters, and provides the correction for S2, HI (hydrogen index), kerogen type, and measuring the adsorption of hydrocarbon by the mineral matrix. In addition, this article demonstrates a manner based on the graph to detect bitumen or hydrocarbon contaminations. Based on our knowledge about the Garau Formation as a possible source rock in petroleum geology of Iran, a geochemical study using Rock-Eval VI pyrolysis and Leco Carbon Analyzer has been conducted on samples from different outcrop sections in Lurestan province, Aligudarz region, from South-West of Iran, High Zagros. Plotting the data on a cross plot of S2 versus TOC, and determining the regression equation is the best method for determining the real values of S2 and HI parameters and measuring the contamination by bitumen or hydrocarbon. Hydrocarbon contaminations makes geochemistry data unreliable, as unrealistically increase S2 and HI, lower Tmax values, and reduce the thermal maturity level of organic matters or kerogen of source rock samples in two study locations. For skipping the effect of contamination and obtaining the real geochemistry parameters, the y-intercept of the graphs must be removed. The cause of contamination in organic rich facies of the Garau Formation is the adhesion of heavy bitumen to organic facies which is due to the covalent bonds between carbon and hydrogen ions.
The concentrations of trace metals in crude oil samples obtained from eight producing fields from Niger Delta Nigeria were analyzed using a 700 model Perkin Elmer Atomic Absorption Spectrophotometer. Results showed the following ranges for the trace metals, Cu (0.01- 0.04 mg/kg); Fe (0.05 – 5.90 mg/kg); Ni (0.09 – 0.72 mg/kg); V (0.008 – 1.05 mg/kg). Pb and Zn were < 0.01 mg/kg. Trace metal ratios such as V/Ni; V/Fe and V/V + Ni were used to unravel the genetic correlation among the oils. Results showed that all the crude samples except sample from Nembe South-2 have a V/N ratio < 1 indicating the organic material that produced the petroleum source rock. A cross plot of V/Ni revealed two genetic families for the crude oils, derived from a terrestrial and marine origin. This was confirmed by the Ternary plot of V, Ni and Fe which discriminated the crude oils from the producing fields into two distinct groups. The V/(Ni+V) of < 0.5 shows that most of crude oil were deposited in an oxic environment. A cross-plot of V/(Ni+V) and V/Fe showed a weak correlation which suggests that it cannot be used as a substitute for the V/Ni ratio in determining the origin and depositional environment of crude oil samples. Therefore, in-depth knowledge of the concentration of trace metals especially vanadium and nickel within an environment during oil exploration is very essential in developing new oil locations.
Using nanoparticles for adsorbing asphaltene was known as one of efficient methods among researchers for upgrading of real oil samples in comparison to other expensive mechanical treatments or even solvents (such as n-pentane and n-heptane) and surfactants. In this study, Nickel zeolite oxide nanoparticles have been used for asphaltene adsorption and solving asphaltene precipitation problems. Although Nickel zeolite oxide nanoparticle used in previous studies as an asphaltene adsorbent, observing relation between asphaltene adsorption on its surface and asphaltene precipitation in the presence of nanoparticles was not covered. Series of experiments include FTIR, CO2-oil IFT tests, Langmuir and Freundlich isotherm models, and natural depletion tests were performed in the presence of Nickel zeolite oxide nanoparticles. Adsorption data was fitted well with the Langmuir model in comparison to the Freundlich model which shows that the adsorption occurs in a homogeneous surface with monolayer coverage. Based on the CO2-oil IFT results, there are two different slope forms in IFT readings as pressure increase from 150 Psi to 1650 Psi. Second slope (900 Psi-1650 Psi) is slower than the first one (150 Psi-900 Psi) which was due to aggregation of asphaltene. Three pressures of 1350 Psi, 1500 Psi, 1650 Psi and Nickel zeolite oxide nanoparticles at concentration of 30 ppm were selected for performing natural depletion tests and the basis of selection was high efficiency of adsorption in these points. As pressure decrease from 1650 Psi to 1350 Psi, asphaltene precipitation changes from 8.25 wt % to 10.52 wt % in the base case and it was 5.17 wt % to 7.54 wt % in the presence of Nickel zeolite oxide 30 ppm. Accordingly, Nickel zeolite oxide nanoparticles adsorbed asphaltene on its surface in proper way and the amount of asphaltene precipitation was decreased in the presence of Nickel zeolite oxide nanoparticles.
Water can contain microorganisms and cause deposition and corrosion in cooling tower systems.Therefore, treatment of thewater of cooling towers is important and essential.Various biocides are used to remove bacteria and disinfect the water of cooling towers,the most commonly used of whichare sodium hypochlorite and chlorine compounds. Two chlorinated water,(hypochlorous acid) and (sodium hypochlorite) were tested in this studyon two pilot and industrial cooling towers.The results of experiments on the pilot tower showed that the performance of hypochlorous acid in disinfection and removal of bacteria and microorganisms has a high capability.The total bacterial count decreased from 10000 (cfu/ml) to less than 800 (cfu/ml) compared to sodium hypochlorite.Experiments and researches were performed on the industrial cooling tower of the Petrochemical Acetic Acid Unit for six months, in which pH, Free Chlorine, TBC and SRB were measured.Very high disinfection power of hypochlorous acid compared to sodium hypochloriteand also low pH of hypochlorous acid compared to sodium hypochlorite led to a significant reduction in the use of chemicals in the cooling tower.The results of Experiments and TBC and SRB tests showed very good performance of using hypochlorous acid
Rapid development of technologies, their increasing complexity and variety, together with limited organizational resources and efforts for survival in industrial competitions have made the task of appropriate technology selection a major challenge. The present research is aimed at the formulation of technology strategy related to oil production in one of the west Karoon oil fields in Iran. At the first, the processes and challenges of production in the studied oil field are recognized by the experts’ survey. Then, the priority of the challenges is evaluated and four key challenges of the considered field are recognized by using a paired comparison questionnaire and Chang Fuzzy AHP. In the next step, the existing and new technologies of oil production in the four recognized key challenges are determined. For each of the recognized technologies, the attractiveness assessment and capability assessment questionnaire are designed based on Jolly indexes and distribute in a sample composed of production engineering experts. Sampling is done by the non-random and purposive-judgmental method. Based on the results of the questionnaires, the attractiveness-capability matrix is designed by Morin’s model, and then based on the obtained technology portfolio, the strategies of each of the four areas are formulated and discussed.
Flaring of gas often having high heating value results in considerable economic and energy losses in addition to significant environmental impacts. Power generation through combined gas and steam turbine cycles may be considered as a suitable flare gas recovery process. Thermal sea-water desalination is a process that requires a considerable amount of heat; hence it may be used in downstream of power generation cycles. Energy is the largest section of the water generation cost of all desalination processes. The energy cost of thermal distillation sea-water plants is close to 50-60% of water generation costs. In the current study, the generation of power and desalinated water through the gas turbine cycle, steam cycle, and multistage flash (MSF) method using flare gas of cheshmeh khosh are investigated. The economic parameters related to the different scenarios considered for the production of power and water are evaluated in the current research. According to the economic evaluation carried out, the most economically profitable scenarios for the investigated co-generation plant is generating as much as possible power in the steam turbine and using the remaining heat in the low-pressure outlet steam in the MSF desalination process. The results show that by increasing steam turbine outlet pressure from 3 bar to 78 bar, power and water generation is changed from 697 to 581 MW and 1557 to 2109 m3/h, respectively. Also, by increasing the outlet pressure of the steam turbine from 3 to 78 bar, the total capital cost is changed from 1177 to 1192 MUSD, and the operating cost is changed from 117.85 to 117 MUSD/year. Finally, operating profit will decrease from 300 to 50 MUSD/year, and payback time will change from 3.92 to 4.75 years.
One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.
Gasoline obtained from the fractionation of indigenous natural gas condensate has low octane number (78) and is therefore of limited uses. Lead-based octane boosting and catalytic reforming are not the viable methods for many fractionation plants. This study was therefore aimed to develop an inexpensive conceptual alternative method for boosting the octane number of gasoline. Natural gas concentrated in methane having high octane number (more than 100) was absorbed in the gasoline to boost the octane number partially (86). Selective additives i.e. ethanol, tert-butyl alcohol, methylcyclopentane, toluene, iso-octane and xylene were blended first with the gasoline to aid the absorption of natural gas molecules. The loss of absorbed gas molecules from gasoline with the increase in temperature was also observed. It is therefore required to try for avoiding any increase in temperature in the finished gasoline. The developed conceptual method is promising. The findings of this simulation study would be useful for more studies towards the development of an affordable alternative method for fractionation plants for boosting the octane number of gasoline derived from natural gas condensate.
In Iran, power plants use liquid fuels such as heavy fuel oil (HFO) or mazut to prevent disruption in power generation. The high percentage of sulfur compounds in HFO and the lack of efforts to remove it, causing significant damage to the environment. The purpose of this research is performing a techno-economic analysis on the Hydrodesulfurization (HDS) process of HFO. The results showed that for removing 85% of sulfur compounds from HFO with a volume flow rate of 250 m3/h that includes 3.5% wt sulfur compounds, the total capital investment and the net production cost are 308.9 million US$ and 114.5 million US$/year, respectively. Besides, the sensitivity analysis indicates that with a 100% increase in the catalyst loading, the mass percentage of sulfur compounds in the HFO will be decreased by 15% more. Also, 6.4% and 32% will add to the total capital investment and net production cost, respectively. With a 100% increase in the gas to oil ratio, the mass percentage of sulfur compounds in the HFO will be decreased by 15.3% more. Also, 43.8% and 6% will be added to the total capital investment and net production cost, respectively. With a 100% increase in the pressure of the HDS process, the mass percentage of sulfur compounds in the HFO will be reduced by 20.75% more. Also, 43% and 6.75% will be added to the total capital investment and net production cost, respectively. Ultimately, with a 100% increase in the inlet temperature of beds, the mass percentage of sulfur compounds in the HFO will be reduced by 5% more. Among the effective operational parameters, hydrogen consumption has the greatest impact on net production cost and payback period, and the pressure of the Hydrodesulfurization process has the greatest impact on increasing the total capital investment of the process.
In recent years, the use of natural surfactants as surface active agents in chemical methods of oil recovery over chemical surfactants has been under consideration due to the absence of environmental problems. In this study, a new plant, Albizia julibressin (Albizia), was introduced as a natural surfactant. Our novelty resides in a unified approach that deals with the introduction of Albizia julibressin (Albizia) as a new natural surfactant, interpretation of the chemical EOR objectives, interface reactions, and the induced optimization to improve oil recovery. For this purpose, the plant was extracted using Soxhlet extraction method, aqueous base solutions and interfacial tension between natural surfactant aqueous solutions and kerosene as an oil phase were measured by pendant drop method. The critical micelle concentration structures formed by this material has been determined by interfacial tension tests and confirmed by electrical conductivity tests. The results show that Albizia extract at 3.5 wt% begins to form micelles structures, which is the critical concentration of Albizia plant micelles. At this concentration, the interfacial tension between the deionized water and the oil phase is reduced from 34 mN /m to 10 mN/m, which indicates a significant decrease in interfacial tension by this plant. Carbonate rock was employed to core flooding experiments in order to investigate the effect of Albizia extract (AE) on oil recovery. Also based on results, by using AE, wettability of oil-wet carbonate rocks, was altered from about 165.02◦ to 86.59◦. Finally, AE enhanced ultimate oil recovery about 11.6% of original oil in place in tertiary recovery for a carbonate rock.
Seismic well tying is a crucial part of the interpretation phase in exploration seismology. Tying wells usually involves forward modeling a synthetic seismogram from sonic and density logs and then matching the obtained synthetic seismogram to the seismic reflection data. A huge amount of time is required to deal with it, yet the outcome signal may not be satisfying and may be suffering a low cross correlation between the seismic signal and the synthetic one; it also requires a high quality synthetic trace. Another problem with the so-called manual tying is that the tying process is not repeatable, indicating that one can rarely obtain the same stretched and squeezed signal if the tying procedure is repeated. In recent years, some researchers have used the dynamic time warping (DTW) method to address well tying problems. They have obtained good results according to the correlation between the seismic signal and the warped synthetic signal. This research demonstrates that the result will be better if filtering is applied before tying, and then the warped signal is smoothed. We also propose a simpler algorithm for extracting a warped signal from the warping curve and the original synthetic trace, which gives rise to better performance for well tying.
Since the development bloom in unconventional reservoirs in North America, total organic carbon (TOC) has become a more essential parameter, as the indicator of the efficiency of these reservoirs. In this paper, by using conventional well logs and NMR log data, the TOC content of an unconventional reservoir in West Africa is estimated. Passy’s, Issler’s, and Schmoker’s methods were used as indirect wireline methods to estimate TOC content, along the well paths. Afterward, NMR log data, as a direct method, was used to provide more precise calculations of TOC. Both methods showed almost similar trends, with the NMR method indicating lower values for the TOC. Then, an adjusted Schmoker equation was proposed, which showed the best fit between NMR and conventional well logs results. By using the equation, the TOC content was calculated in three other wells, where NMR data were unavailable. The results were then used to prepare a 3D model of the TOC distribution, within the reservoir.
The separation of naphthenic acids from crude oil is difficult, and the presence of such materials in crude oil reduces its value. In this work, using catalytic esterification with methanol, naphthenic acids of crude oil were removed to reduce their harmful effects. SnO2/γ-Al2O3 nanocatalyst was synthesized and used to convert naphthenic acids of crude oil in a fixed bed catalytic reactor. The nanocatalyst was characterized by the X-ray diffraction (XRD), field emission scanning electron microscopy (FESEM), and Brunauer–Emmett–Teller (BET) surface area techniques. The XRD revealed the formation of rutile SnO2 on alumina, and the FESEM approved that the catalyst is comprised of nanoparticles with a diameter in the range of 50 to 90 nm. The BET indicated that the catalyst has a mesopore structure with a surface area of 213.4 m2·g–1. The optimal conditions for the catalytic esterification process of naphthenic oil were determined. The temperature of the reduction of the total acid number (TAN) of crude oil ranged from 250 to 360 °C, and the TAN was reduced to less than 0.5 mg KOH/g in this temperature range. A methanol-to-oil ratio (M/O) of 2 wt %, a velocity space of 2.5 h–1, a reaction temperature of 300 °C, and atmospheric pressure were selected as the optimal conditions for the removal of naphthenic acids. Under these conditions, 83% of naphthenic acids was removed. The study indicated that SnO2/γ-Al2O3 could be a promising nanocatalyst for the reduction of total acid of crude oil under mild conditions.
