مجله پژوهش نفت
پیاپی 122 (فروردین و اردیبهشت 1401)

ASP flooding aims to remove oil trapped due to capillary forces and improve mobility ratios. In this study, the effects of reservoir heterogeneities (i.e. high permeable channels) on waterflooding, polymer, AS + polymer, polymer + AS + polymer flooding have been studied. In particular, the role of the front, resistance factor,  the rate of injected fluids per volume of injected fluid and concentrations of injected fluids have been investigated. The simulation results showed that the P+AS+P gives higher recovery (20%) compared to the water flooding. Also, it was observed that the optimum slug size of each system such as water or polymer slugs or AS in P+AS+P flood and polymer in P+W+P flood can be determined. For heterogeneous models with permeable channels, channel aspect ratio and the direction of channels are observed to be the effective factors for oil recovery.

In the primary oil recovery, which is done using natural mechanisms in the reservoir, less than one third of the volume of petroleum is produced in the best cases for various reasons, including the process of reducing the pressure caused by production. In addition, by adopting secondary methods of oil recovery, such as water injection, despite the widespread use, due to the high mobility of water relative to oil, a large part of the resources will not be able to be produced. Therefore, in order to meet the demand for crude oil, which is constantly increasing, there is always a need to use EOR methods of overdraft to increase the recycling rate after the start of production. One of the efficient methods to increase the efficiency of the crude oil sweeping process is polymer injection (or flooding), which has been used as one of the chemical methods of oil recovery for many years. Since Case Study is a wide, in-depth, and detailed study of a particular case and thus accesses a wide range of knowledge for the analysis of complex systems, the assurance of case study research that all components have been examined is assured. In this study, after a comprehensive review of successful case studies, EOR by polymer flooding operations, the factors and conditions affecting each of the stages of polymer selection, injection operations and then its impact on the rate of increase in production rate and also the rate of reservoir oil recovery has been studied. The results of this operation in different oil fields show the addition of suitable polymer to water in the flooding process and in different conditions, the potential to reduce water production and also reduce the amount of oil saturation remaining in the reservoirs and thus increases oil recovery factor.

The process of injecting smart water into carbonate reservoirs has always faced many challenges. In this study, by examining one of the effective factors such as ionic compounds active in smart water, these ambiguities have been further investigated and analyzed. The reaction between three phases, oil, rock and saline, which leads to a change in wettability, requires the presence of ionic compounds active in smart water and active compounds in oil. The presence of these compounds in the desired concentrations is the driving force required to perform ion exchange reactions followed by a change in wettability. In fact, the optimal concentration of active ions leads to the formation of a stable water film and a change in the wettability of the rock. In this study, experiments measuring the contact angle and the spontaneous imbibition deferens process were performed on samples of limestone.  For this purpose, the cores with the same conditions are located in the vicinity of different compounds of active ions in smart water. In this regard, using the collected results, it is possible to interpret and study how to participate in the reaction and the effectiveness of the active compounds of smart water. It can also be concluded that cations in the presence of sulfate ions can have a positive performance at the minimum concentration in seawater and have acceptable efficiencies of about 41% in experimental conditions.

Matrix acidizing is a method for improving well inflow performance. In this operation, acidic solution is injected into the carbonate formation to increase near wellbore permeability by rapid creation of irregularly shaped channels named “wormholes”. Other common carbonate stimulation techniques include: hydraulic fracturing, acid fracturing, hydro-blasting and combination of acidizing and cased-hole perforation. In this research, we aim to calculate wormhole propagation in a horizontal carbonate later (bed dip=0) during acidizing a directionally drilled well which is open-hole or cased-hole and thus modeling skin factor evolution with time. For this purpose, Buijse-Glasbergen semi-empirical field scale wormhole propagation model based on regression with acid efficiency curve, a model for unsteady-state pressure distribution in the formation caused by a directionally drilled well and a model for single phase Newtonian fluid flow in the wellbore considering inflow/outflow from wellbore wall are coupled which by solving them simultaneously, wormhole propagation in each time step can be calculated. Based on the obtained results, wormhole propagation decreases with reservoir layer depth due to the fact that by starting acidizing job, permeability of the upper portions of the layer will increase more than the lower parts as a result of the sooner contact of the acid with them. Thus, these parts will receive larger volumes of acid and greater wormhole penetration depths. Also, wormhole propagation radius will be increased in a cased-hole completion in comparison with the open-hole and thus  carbonate reservoirs acidizing results will be improved. It is required to consider optimum number of sublayers used in simulation based on reasonable precision and runtime to obtain accurate results. Increasing wellbore inclination causes wormhole propagation to be increased to a specific depth, but it does not necessarily improve overall acidizing results and reducing skin factor. Minimum skin factor occurs in a specific inclination which must be considered in planning directional wells which their reservoirs will require acidizing certainly.

Porosity and permeability of reservoir rocks increase due to the significant pressure drop at surface condition, accordingly this leads to overestimation of volume of hydrocarbons in place. In this study, the effect of overburden pressures on the porosity changes of Kangan and Dalan carbonate formations in the central part of the Persian Gulf has been investigated. Porosity and permeability of 111 plug samples were measured at pressures of 14.7, 2200, 3700, 5000 and 5700 psi. Porosity decreases up to 2 % by increasing up to maximum pressure. Samples react to pressure changes differently; and therefore, they justified into various groups. To evaluate the effect of heterogeneity and complete understanding of these reactions, the most acceptable methods of Winland, flow zone indicator, Lucia, porosity and permeability ranges have been used. The changes in porosity against pressure were plotted for each sample and the equation of decreasing the porosity by increasing pressure was defined. The purpose of this study is considering the changes in porosity by increasing the pressures; and therefore, the resulting line slope was considered as an index of changes, and samples with the same slope were considered as similar samples. In other words, if the rate of porosity change versus pressure is similar, the samples have been assumed as similar ones. Afterwards, the coefficient of variation was calculated as the index of line slopes’ dispersion. The results of various rock typing methods indicated that the best methods for evaluating the heterogeneity of porosity change with pressure, are flow zone index, permeability range, Winland and Lucia, respectively.

The loss of surfactants and polymers in the injection process in reservoirs is considered the most crucial issue in the chemical injection process›s Feasibility. Simultaneous injection of polymers and surfactants causes interaction between surfactant and polymer and a significant reduction in performance. The best solution for solving this problem is using a new material called polymeric surfactant that can be an exciting alternative for currently available methods. These new materials can have the effect of polymer and surfactant like increase of water viscosity, reduction of interfacial tension between water and oil, and change in reservoir rock wettability simultaneously; thus, these new materials will further increase oil production relative to traditional methods. One of the fundamental problems of chemical injection is the adsorption of these substances on the reservoir rock. Because of limited research regarding the analysis of the adsorption rate of polymeric surfactant on reservoir rocks and comparing them with the adsorption rate of conventional polymers, in this study, the adsorption rate of this substance has been studied in different temperatures. First, in this research, A HPAM and HMZPAM As a polymeric surfactant synthesized using a Zwitterion hydrophobic group, and the effect of these two polymers was measured in concentrations between 50 to 1000 mg/L at temperatures between 25 to 80 oC on adsorption of surface in carbonate rock. The results show that the adsorption of HPAM and HMZPAM on reservoir rock, which made of dolomite, increases with the increase in polymer›s concentration. Generally, the main factor in the adsorption of polymers are electrostatic forces which because HMZPAM compared to HPAM, in addition to COO- group also has SO3- group that these negative groups adsorbed more to the positive charge of the rock surface in which as a result increases the amount of adsorption of polymeric surfactant compared to HPAM.

Hydrogen is one of the most important sources of renewable energy, but in most refineries, along with the production of hydrogen by fossil fuels, a significant amount of CO2 is also produced. This paper presents a mathematical model for CO2 emission from each unit in the hydrogen network as well as multi-objective optimization. This model includes linear mathematical programming (LP), which illustrates the relationship between CO2 emissions and feed input to the fuel system and the output product of the hydrogen generating unit. The model constant parameters are obtained from the experimental data from the hydrogen network of Bandar Abbas Oil refinery. The objective function is based on the multi-objective function, which simultaneously reducing CO2 emissions and also reducing total annual cost of hydrogen network. The results of optimized network indicated that total annual cost and CO2 emissions have been decreased by 29.1% and 22.4%, respectively. Furthermore, hydrogen within the fuel system was recovered to use in hydrogen network by purifications units. The amount of hydrogen recovery from fuel gas, which has been sent to purification units, is 16200 m3/h.

In recent years, research activities on smart water flooding in oil industry have been increased significantly. Smart water injection, by optimizing the ionic composition and salinity of the injected water, is a promising technique to increase oil recovery. Studies over the past two decades have shown the benefits of smart water flooding over other oil recovery methods. So far, several mechanisms have been proposed to describe the performance of smart water process in literature. However, due to the complex chemical and physical reactions, the contribution of each mechanism in increasing oil recovery factor has not been determined; therefore, it is difficult to predict the performance of reservoirs behavior under smart water flooding. In this paper, smart water injection in carbonate and sandstone reservoirs has been comprehensively investigated. This study includes a review of effective mechanisms, laboratory and field observation and the challenge of smart water flooding in both carbonate and sandstone reservoirs. Finally, the screening criteria of candidate reservoirs for smart water injection are presented and based on that, smart water injection in carbonate reservoirs in southwestern Iran has been assessed.

In this research, the gasoline produced by the refinery viscosity reduction unit has been investigated. The gasoline in this unit contains large amounts of sulfur compounds. The presence of sulfur and di-olefin compounds in this unit›s gasoline due to its high reactivity causes the production of a large amount of gum that will cause many adverse effects. In this research, a method based on alkylation is investigated; Initially, AlCl3 solid catalyst was made based on silica gel, and the effect of various parameters such as catalyst manufacturing method, catalyst mixing temperature with gasoline sample, temperature effects of catalyst bonding, catalyst mass ratio and catalyst active component on the removal of sulfur compounds were investigated. The results showed that the amount of total sulfur in the prototype decreased by 53.27%.

Oil contamination is often inevitable in exploitation, refining, and processing units. The emission of these compounds into the environment causes adverse effects on human health and other living organisms hence, it is necessary to use efficient methods to remove them. Bioremediation by microorganisms is a cost-effective and environmental-friendly method for remediation of oil contamination from the environment which its success depends on microorganisms that are capable to remove of aromatic and aliphatic hydrocarbons. Therefore, it is important to isolation and characterization indigenous-degrading bacteria that are able to tolerance contaminants at a high loading rate. In this study, four bacterial isolates (Arthrobacter citreus, Staphylococcus gallinarum, Bacillus thuringiensis, Paenarthrobacter nitroguajacolicus), which was previously isolated from petroleum-contaminated soils of Naft-Shahr, were used for bioremediation of naphthalene and hexadecane. The result showed although all four strains could utilize naphthalene and hexadecane as only carbon source, whoever B. thuringiensis strain had shown the best efficiency in removal of both compounds. This strain could remove 90.31% of naphthalene (initial concentration of 200 mg L-1) and 78.89% of hexadecane (initial concentration of 1000 mg L-1) with a specific rate of 99.25 mg gcell-1 day-1 and 231.43 mg gcell-1 day-1 during 7 days respectively. Based on these results, this biosurfactant-producing bacterium had shown high potential in bioremediation of environment contaminated with aliphatic and aromatic petroleum hydrocarbons.