مجله پژوهش نفت
پیاپی 114 (آذر و دی 1399)

Calculating water saturation is one of the most important reservoir parameters for determining the volume of hydrocarbons in place, which it must be calculated with high accuracy. In this study, after the necessary corrections were made on the Water-base-core in Kangan and Dalan formations, the core water saturation was calculated by the Dean-Stark test method. After electrical measurements and determination of Archie coefficients on the core, water saturation values were calculated from Archie electrical models, Waxman Smith, Dual Water, and Archie-Dual Water in Geolog7 software. To generalize water saturation to other wells in this field, three facies models were produced by Multi-Resolution Graph-based Clustering (MRGC) and applied in one of the fields in the Central Persian Gulf. Afterwards, in the whole well, the difference between the average water saturation of the Dean-Stark test method and the electrical models was measured in 3 facies models. The results showed that in all three facies models created, the average values of water saturation calculated from the equations were higher than the water saturation calculated from the Dean-Stark test method. By making a comparison between facies models, it is obvious that the facies models based on input logs, including electrical resistance, sonic, neutron, and density, showed the least difference between the average water saturation of the Dean-Stark test and the electrical models. Comparing the average water saturation in the Dean-Stark method and the electrical models between the electrical facies of a model based on its input logs, it was concluded that the petrophysical parameters including porosity, sonic wave transit time, shale volume and density, as opposed to electrical resistance, are directly related to the reduction of the average water saturation difference. But lithology has less effect on the difference in average water saturation between the Dean-Stark method and electrical models. Therefore, to select the sample for determining the coefficients of Archie, it is appropriate to use this method of determining the electrical facies.

The purpose of this research is initially to model the pressure and temperature profiles along with other properties of the reservoir production fluid such as density, viscosity, and different in situ useful parameters in the well using the Beggs and Brill method as well as the marching algorithm. As a result, we can be aware of scale formations anywhere in the well at any time without the use of particular physical and inside of the well tools without spending a lot of economic costs. After estimating the thermodynamic and physical conditions of the well fluid, the physicochemical state of the producing fluid in saturated, supersaturated, and undersaturated states forms problematic scale deposits using calculations of concentration changes and saturation index using Oddo and Tomson method. Finally, using mathematical models, we investigate and record the potential for deposition, critical depths, and prone to scale deposition. Although deposits that stop the production of wells may be in porous media, this study was performed only inside the well and the tubing. The results of modeling on one of the oil wells under the supervision of the national company for southern oilfields as a case study showed that with an increase in depth from the surface, the saturation indexes for hemihydrate calcium and strontium sulfate scales along the well in almost all the depths are negative. As a result, it can be said that there is no possibility of the formation of these scales at different depths of the well. The same is true for the scale formation of hydrated calcium sulfate (gypsum). In addition, near the surface, the saturation index of this scale is positive and slightly larger than zero, which indicates the possibility of gypsum deposition in this depth range. Finally, the saturation index for anhydrous calcium sulfate (anhydrite), barium sulfate, and calcium carbonate (calcite) scales have always been positive, which indicates the probability of the formation of these scales in the well.

In this research, catalytic hydrodeoxygenation process of anisole derived from lignin is investigated over Pt/Al2O3 catalyst at 573-673 K, 8-14 bar and space velocity of 3-20 (ganisole/gcatalyst*h), in the presence of hydrogen as one of the reactants, using a fixed-bed tubular reactor. The main reaction classes during catalytic conversion of anisole are hydrogenolysis, hydrodeoxygenation, dehydration and transalkylation. During this process, anisole initially converts to phenol through hydrogenolysis reaction. Afterwards, phenol derivatives including: 2-methyl phenol, 2,4-di methyl phenol, 2,3,5,6-tetra methyl phenol are generated via alkylation and trans-alkylation reactions. Benzene is formed through hydrodeoxygenation (HDO) reaction. More over hexa-methylbenzene is formed via alkylation and HDO reactions. Reactions network and kinetic constants are determined using products selectivity and anisole conversion data. According to achieved results, phenol, 2-methyl phenol and benzene are primary products of HDO process. Furthermore, based on kinetic calculations, formation of benzene is not a first-order reaction. Formation of phenol, 2,4,6-tri methyl phenol, 2,6-di methyl phenol, 2-methyl phenol, hexamethyl benzene and 2,3,5,6-tetra methyl phenol are first-order reactions, and the activation energy for their formation are 25.3 kJ/mol, 40.2 kJ/mol, 43.4 kJ/mol, 55.4 kJ/mol, 70.1 kJ/mol and 93.6 kJ/mol respectively.

Severe slugging in risers hinders the steady production of oil, and it may also damage the equipment. Thus, finding a proper way to prevent such a phenomenon is of great importance. The aim of this study was to provide a mathematical model to investigate the three-phase flow of oil, water and gas in a riser-pipeline system. To do so, a bulk model was chosen to simulate the pipeline under two scenarios. In the first scenario, gas can penetrate the riser and flow upward whereas, in the second scenario, liquid holdup limits the gas flow in the riser. Moreover, the riser system was modeled with the assumption of a distribution parameter system that used dynamic nodes to evaluate the local conditions. Mass transfer between the oil and gas phase was also estimated by the black-oil approximation. After modeling the riser-pipeline system, gas injection at the riser base was simulated to stabilize the flow and prevent the upcoming issues. In addition, a criterion to determine the amount of the injected gas was proposed. Finally, results obtained from modeling were compared with the results of the OLGA simulation software which showed good agreement.

Water flooding is one of the most important enhanced oil recovery (EOR) methods in the world. It has been successfully implemented in many oilfields. Low salinity water flooding (LSWF) has been recognized as one of the promising methods for enhanced oil recovery of clay-rich sandstone reservoirs. Many studies have shown that LSWF has an important role in formations with sufficient amount of clay. However, different hypotheses that have been proposed for oil recovery due to LSWF mechanisms are not completely accepted, and they need more investigation due to controversial response to LSWF. Thus, there is not a general agreement for mechanisms behind low salinity effects and associated problems such as fines migration and formation damage. In this study, 2-D glass micromodels (clean and clay-coated) and crude oil from an Iranian oilfields were used to visualize the effect of lowering injected water salinity (30000 ppm, 4000 ppm, 2000 ppm and DI water) on fines migration and improved oil recovery. In addition, single phase flow test was performed to evaluate possible fines migration with the same salinities. Results indicate an increase in recovery for both clay-coated and clay-free systems while additional oil recovery during LSWF in clay-coated micromodel was more significant (3.07%) comparing to that for clay-free micromodel (1.89%). Fines migration was observed during both single- and two-phase flow experiments.

Dispersed water-in-oil as a stable emulsion causes numerous problems in extraction, transportation and refining of the crude oil. In the most desalting units, high voltage electrical field is utilized to separate water and ionic components from the crude oil. The efficiency of desalting units depends on operational conditions and hence in this study the result of several parameters on salt content of output crude oil in a desalting unit was considered for both theoretical and experimental studies. For this goal, optimized artificial neural network (ANN) using cuckoo optimization algorithm was applied to simulate the process. The optimum temperature, water  injection rate, retention time, differential pressure of mixing valves and injection rate of demulsifier were predicted by the consequences of simulation as the optimum value for each of the parameters was respectively equal to 79 ppm, 3.25%, 8.5 bar and 90 ppm. Then, because of the significant effect of the demulsifiers, the variation of each parameter was evaluated in the presence of four types of demulsifier separately. The results showed that an increase in the basic sediment and water content (BS&W) and specific gravity of crude oil has adverse effects on desalting process efficiency.

Determination of porosity type, microfacies and rock types are important tools in diagnostic of distribution of reservoir characteristics. The main aim of the present paper is to study these parameters in Bangestan reservoir of the Gachsaran oilfield which is located in Dezful embayment, SW Iran. The porosity types and microfacies were scrutinized by using 200 thin sections of three wells of Bangestan reservoir, and thus 4 microfacies were identified. The Hydraulic Flow Units (HFU) method was used to analyze the reservoir quality and distinguish reservoir and non-reservoir units. Determination of flow units was done based on Stratigraphic Modified Lorenz Plot (SMLP) and Flow Zone Indicator (FZI) methods. Four flow units were identified by SLMP method. In addition, four flow units were identified by flow zone indicator and Discrete Rock Types (DRT) methods which each of them were distinguished based on the petrophysical properties. The reservoir properties improve from DRT0 to DRT3 which permeability increases.

Rock and fluid interactions play an important role in many aspects of formation evaluation and reservoir characterization studies. Chemical reaction of the injected fluids with reservoir rock and fluid affects the efficiency of EOR processes due to alteration of oil and rock petrophysical properties. Hence, it is necessary to investigate these interactions during EOR operations. In this study, the effect of gas injection velocity and pressure, and injection orientation on rock and fluid interaction are investigated during CO2 injection, as tertiary recovery mechanism, into a high-permeable heavy oil sandstone reservoir. The oil and sand samples have been taken from an Iranian southern oil reservoir. The results of the orientation effect of the sandpack model show that due to the gravitational stability of the vertical injection, the dissolution of the minerals as well as the asphaltene precipitation is more than the horizontal injection mode. Also, the results indicate that as the injection pressure increases, the dissolution of minerals and asphaltene precipitation also increases. This is due to the fact that by increasing pressure, more CO2 is dissolved in crude oil and water. In addition, as the injection velocity decreases, the contact time between the formed acid and the rock as well as CO2 and crude oil increases. Therefore, the possibility of dissolution of minerals and asphaltene precipitation increases.

The presence of natural fractures in fractured reservoirs plays an important role in determining the stress state that is affected by tectonic stresses and local perturbation. Fracture orientation, well stability and permeability anisotropy are all factors associated with local stress variations. Nowadays, to better understand the geomechanical behavior of reservoirs, most mechanical and hydraulic behavior modelings are coupled with stress variations. In this study, in order to investigate the correlation between fracture density (as one of the geometric properties of fracture network) and oblique loading of tectonic stress, with the variability of stress and shear strain, a discrete fracture network (DFN) was generated using the stochastic approach. Afterwards, considering the tensorial nature of the stress, the stress field under different conditions of tectonic stresses was determined using FLAC2D software as a finite-difference method. Finally, stress data were analyzed using tensor-based mathematical equations. Then, the effect of four parameters of (1) rock tensile strength, (2) rock cohesion, (3) fracture normal stiffness, and (4) fracture dilation angle on stress dispersion in loading at different angles were evaluated. The results showed that the stress perturbation and the effective variance, which indicate the dispersion of the stress distribution, have a direct relationship with the fracture density, which is defined as the number of fractures per area unit utilizing the window sampling approach. Moreover, the loading orientation is effective in total stress variability, and the effective variance is highest at loading angle of 50° and lowest at 170°. Among the parameters, it was found out that normal stiffness had the greatest effect on stress distribution, and the effects of the rock parameters were negligible. Overall, it can be said that the stress distribution and dispersion, in a dense fracture network with a normal stiffness of 500 GPa/m and a loading angle of 50°, have the maximum value.

Asphaltene not only increases the viscosity of crude oil, but it can block oil extraction, transportation, and separation equipment. In the present study, effects of frequency and addition of n-heptane on rheological behavior of two oil samples (i.e., 23 and 71) from Mansouri oil reservoir (Iran) are investigated. Variation of viscosity is used as a criterion for amount of asphaltene separation, and loss factor is employed for distinguish the viscos as well as elastic (liquid or gel-like) behavior of the oil samples. Both viscosity and frequency tests have been conducted at different concentrations of n-heptane. The viscosity tests revealed that addition of n-heptane to the oil samples results in separation of high amount of their asphaltene. Moreover, viscosity of the oil samples continuously decreases by increasing the concentration of n-heptane. Afterwards, the numerical values of loss factor for the oil samples having different concentrations of n-heptane are measured using the frequency test. It’s simply possible to understand liquid or gel-like behavior of oil using this factor.  Finally, by focusing on viscosity decrease as well as liquid-like behavior of oil, the optimum range for frequency and concentration of n-heptane are determined. The results revealed that by adding 75 volume percent of n-heptane to oil sample of 23 in frequency of higher than 33.6 rad.s-1, the liquid-like behavior is seen, and viscosity decreased more than 97%. Moreover, the best results for the oil sample of 71 is obtained during adding 75 volume percent of n-heptane in frequency of higher than 23.4 rad.s-1. The oil sample experiences more than 96% decrease in its viscosity, and it also shows a liquid-like behavior in this condition.