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It is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir. [ABSTRACT FROM AUTHOR]

Most of oil reservoirs in the world have faced decrease in production and they are in the second half of their life cycle. Therefore, tertiary and enhanced oil recovery (EOR) techniques are needed for continuous production from these reservoirs. As choosing the most appropriate EOR methods for a reservoir is a challenging task for reservoir engineers, screening of EOR approaches is of high importance before any full field simulation and experiments. Enhanced oil recovery screening is a multiple criteria decision-making (MCDM) problem and hence, a systematic statistical algorithm based on MCDM can be used for this purpose. In this study, for the first time, a new EOR screening method is proposed by using VIKOR and Monte-Carlo algorithms. The approach used a large database of successful EOR projects around the world and was applied to 12 various EOR methods including a wide range of conditions and properties. Pre-processing was performed on the gathered database and then based on reservoir engineering analyses and using a pairwise comparison matrix, initial weights were considered for the parameters in each EOR method. Afterward, these weights were used in the proposed VIKOR MCDM calculation algorithm and the corresponding numerical values of EOR techniques for each reservoir were obtained. Finally, the EOR method with the highest corresponding value was selected as the most suitable method. Results demonstrated that by using the presented approach, a high classification accuracy of 98% was obtained for different cases, which shows the proficiency and robustness of the developed screening algorithm. In addition, the reliability of the developed method was validated using data obtained from 11 oil reservoirs in the southwest of Iran. Also, the results were compared with the results of previous studies and they were in a very good match. The developed approach is less expensive and faster than full field simulation method and can be used as an efficient EOR screening approach for reservoirs with different properties in the world. [ABSTRACT FROM AUTHOR]

This study proposes a multi-objective mathematical programming model to design an oil supply chain network at three levels: upstream, midstream and downstream. It includes oil wells, gas injection wells, production units, refineries, gas injection centers, distribution centers, export and import terminals. The proposed model optimizes all three economic, social and environmental goals at the same time. Drilling injection and production wells, transportation costs, production costs, gas injection center costs, as well as fixed and annual costs of refineries and distribution centers are all minimized in the economic dimension. The environmental dimension of sustainability reduces greenhouse gas emissions, while the social dimension of sustainability increases job opportunities. The optimization of associated petroleum gas injection operations into the reservoir is also taken into account in this study. The proposed model considers the uncertainty of critical parameters and employs a robust possibilistic hybrid approach to deal with it, as well as an interactive fuzzy approach to solve it. A case study in Iran is used to evaluate the suggested model's performance. In comparison to the single-objective economic model, the results of solving the model show that taking sustainability into account has reduced greenhouse gas emissions and increased job opportunities. The crude oil extraction potential increases in each period when gas injection optimization and reservoir pressure are taken into account. Furthermore, the cost of the supply chain grows as the amount of uncertainty in the suggested model rises. As a result, the uncertainty of system parameters must be considered. • A multi-objective sustainable model for designing an oil supply chain is proposed. • Gas injection optimization is considered to enhance oil recovery in the model. • To deal with parameter uncertainty, a robust probabilistic approach is applied. • To solve the multi-objective model, an interactive fuzzy approach is used. • Real data from Iran is used to validate the suggested model. [ABSTRACT FROM AUTHOR]

The need to determine permeability at different stages of evaluation, completion, optimization of Enhanced Oil Recovery (EOR) operations, and reservoir modeling and management is reflected. Therefore, various methods with distinct efficiency for the evaluation of permeability have been proposed by engineers and petroleum geologists. The oil industry uses acoustic and Nuclear Magnetic Resonance (NMR) loggings extensively to determine permeability quantitatively. However, because the number of available NMR logs is not enough and there is a significant difficulty in their interpreting and evaluation, the use of acoustic logs to determine the permeability has become very important. Direct, continuous, and in-reservoir condition estimation of permeability is a unique feature of the Stoneley waves analysis as an acoustic technique. In this study, five intelligent mathematical methods, including Adaptive Network-Based Fuzzy Inference System (ANFIS), Least-Square Support Vector Machine (LSSVM), Radial Basis Function Neural Network (RBFNN), Multi-Layer Perceptron Neural Network (MLPNN), and Committee Machine Intelligent System (CMIS), have been performed for calculating permeability in terms of Stoneley and shear waves travel-time, effective porosity, bulk density and lithological data in one of the naturally-fractured and low-porosity carbonate reservoirs located in the Southwest of Iran. Intelligent models have been improved with three popular optimization algorithms, including Coupled Simulated Annealing (CSA), Particle Swarm Optimization (PSO), and Genetic Algorithm (GA). Among the developed models, the CMIS is the most accurate intelligent model for permeability forecast as compared to the core permeability data with a determination coefficient (R2) of 0.87 and an average absolute deviation (AAD) of 3.7. Comparing the CMIS method with the NMR techniques (i.e., Timur-Coates and Schlumberger-Doll-Research (SDR)), the superiority of the Stoneley method is demonstrated. With this model, diverse types of fractures in carbonate formations can be easily identified. As a result, it can be claimed that the models presented in this study are of great value to petrophysicists and petroleum engineers working on reservoir simulation and well completion. [ABSTRACT FROM AUTHOR]

Water production from unconventional reservoirs especially shale reservoirs has always been considered as the major challenges for petroleum industries that needs special requirements and facilities to treat the flow-back water and reinject to the reservoirs. The objective of this paper is to statistically measure the provided freshwater from treated water that is produced from reused water. The treated water is provided from different processes such as hydraulic fracturing, chemical enhanced oil recovery methods (such as polymer, surfactant, and foam flooding that are the main important techniques in recovery processes) from eight wells in Bangestan field in South of Iran. Moreover, photofenton-flotation separation methods are used in this field to treat the produced water from different processes. As a result, saving water percentage in the studied field for hydraulic fracturing processes is about 82% and therefore, the required fresh water is about 18%. Moreover, saving water percentage in the studied field for chemical recovery techniques is about 70% and therefore, the required fresh water is about 29%. The findings of this study can help for better understanding of the required fresh water for 1000 inhabitants can be saved through this system. [ABSTRACT FROM AUTHOR]

Interfacial tension (IFT) reduction and wettability alteration are major mechanisms to chemically enhanced oil recovery (CEOR) in carbonate reservoirs. The purpose of this research was to investigate the effects of different surfactants on IFT and wettability alteration. Four different surfactants including ionic liquids and zwitterionic surfactants, namely [C12mim]Cl, TR-880, NX-2760, and NX-1510, were used in this study. Reservoir core samples, formation brine and crude oil from the Karanj oil field, located in Iran were used. The results showed that the tested surfactants are capable of reducing IFT significantly, changing the wettability to greater hydrophilicity, thus potentially facilitating oil recovery. [ABSTRACT FROM AUTHOR]

Considering the low percentage of oil recovery in carbonate reservoirs, EOR methods receive more attention in these reservoirs, and smart water flooding shows some promising experimental results in carbonate rocks. Moreover, low operating cost and capital investment of water flooding compared to other chemical flooding methods, make this emerging technology more attractive for oil companies. In this study, the effect of concentration of influential ions of seawater on the wettability of dolomite rock is investigated. It started by contact angle measurements for determining the efficient concentration, followed by core flood experiments to study the effect of ion concentration on ultimate oil recovery. The novelty of this work is the optimization of injected water for enhanced oil recovery in one of Iran's oil fields. The results showed that increasing sulfate concentration in the presence of other ions up to a certain level causes more water-wetness of dolomite rock. Furthermore, seawater with no calcium ion showed the best effect on the wettability alteration of dolomite rock and consequently more oil recovery. The same results were also observed for seawater with no magnesium ion. [ABSTRACT FROM AUTHOR]

The Albian Mauddud Formation is a prolific reservoir in Kuwait and nearby countries such as Iraq and Iran but has received far less attention than the under‐ and overlying units (the Aptian Shu'aiba and Cenomanian Mishrif Formations). Detailed reservoir characterization studies of the formation are required to support field development and improved / enhanced oil recovery (EOR) programmes. In this study, 26 wells penetrating the Mauddud Formation within the Greater Burgan area of Kuwait (Burgan and neighbouring fields) were investigated, integrating the logging of 910 ft of core with petrographic investigations of 113 stained and impregnated thin sections. In the Greater Burgan area, the Mauddud Formation can be divided into a lower Clastic Member and an upper Carbonate Member which is the main focus of this paper. The primary objective of the study was to present a new characterization of this thin, heterogeneous carbonate reservoir by integrating facies analysis and sequence stratigraphy with a detailed petrographic investigation. A second objective was to identify the relative importance of depositional characteristics and diagenesis on the distribution of reservoir properties. Sandstones in the Clastic Member of the Mauddud Formation were deposited on a delta which passed laterally to the north and east into a carbonate platform. During subsequent regional flooding, increased carbonate production resulted in the development of a larger‐scale carbonate platform covering the entire study area. The Burgan field area was part of the proximal zone of this carbonate platform. A number of depositional environments were identified by integrating core and thin section data. These range from outer platform to mid‐ and inner platform, the latter including both high‐ and low‐energy settings (shoal, shoreline; and lagoonal respectively). Mud‐supported textures characteristic of low‐energy inner‐platform and mid‐ to outer‐platform settings are volumetrically dominant in the Mauddud Carbonate Member. Sequence stratigraphic analysis suggests that the Mauddud Carbonate Member is part of a major regressive phase (or highstand systems tract) of a third‐order sequence, with the regional‐scale K110 MFS positioned close to the transition with the underlying Clastic Member. Two 4th order transgressive – regressive (TR) cycles or sequences, M1 and M2, were identified within the Carbonate Member. The top‐Mauddud surface corresponds to a sequence boundary with long‐lasting subaerial exposure during the latest Albian and is characterized by both micro‐ and macroscopic karst features (calcite dissolution vugs and recrystallization in thin sections; and cavities in cores). This study demonstrates that the Burgan field area experienced significant uplift, with increased differential erosion and/or non‐deposition of the upper M2 TR cycle towards the southwest. Eogenetic marine and meteoric calcite cements partially fill macropores close to the tops of the TR cycles and remaining macropores were occluded by shallow‐burial calcite cements. Cementation by ferroan dolomite cement, which resulted from the increased overburden and associated chemical compaction, has almost entirely occluded residual macropores in the lower part of the Mauddud Carbonate Member, close to the underlying siliciclastic deposits of the Clastic Member. As a consequence, porosity is mostly preserved in the middle part of the Carbonate Member. The predominance of mud‐supported textures in these intervals together with the effects of diagenesis explain the widespread occurrence of microporosity within both micritic matrix and grains. In the Greater Burgan area, meteoric diagenesis associated with subaerial exposure(s) of the top‐Mauddud preserved and/or enhanced micrite microporosity. Plug porosity may reach 35% or more, but permeability does not exceed 100 mD. The Mauddud Carbonate Member in the Greater Burgan area is a thin, microporous reservoir, with a dual porosity component which is linked to karst alteration and not to tectonic fracturing. The distribution of reservoir properties results from a combination of primary depositional characteristics and a multiphase diagenetic overprint. This study will guide the future development of the Mauddud reservoir in the Greater Burgan area. It also demonstrates the importance of an integrated approach to constrain sub‐seismic heterogeneities in carbonate reservoirs. [ABSTRACT FROM AUTHOR]

In this Study, the biosurfactant production potential of Enterobacter Cloacae and Enterobacter Hormaechei microorganisms that were isolated from one of the oil reservoir formation water located in the southwest of Iran was explored. The produced biosurfactant caused substantial surface tension reduction of the growth medium and interfacial tension reduction between oil and brine to 31 and 3.2 mN/m from the original value of 72 and 29 mN/m respectively. In addition, the impact of other parameters such as temperature and salinity were investigated by performing appropriate experiments. The results show that the wettability alteration toward neutrally wet conditions could be the dominant mechanism on the improvement of oil recovery and the adsorption of bacteria cells and forming biofilm was the main contributor to this wettability alteration. [ABSTRACT FROM AUTHOR]

Reservoir fluid characterization is one of the most important steps in hydrocarbon reservoir engineering calculations and studies. The reservoir fluid composition is not constant along the entire hydrocarbon column and varies along the vertical and horizontal directions. In most cases, such variations have been observed along the vertical direction. This is known as compositional grading phenomenon and has a strong impact on the calculation of original hydrocarbon in place, reservoir development, and oil recovery factor. In this paper, a simulation study was carried out to investigate the effects of compositional grading on reservoir fluid properties and the injection of various gases such as carbon dioxide (CO2), nitrogen (N2), associated petroleum gas (APG), N2–CO2 mixture, and water-alternating-CO2 injection into different depths of a conventional black oil reservoir in the southwest of Iran in order to detect the best injection depth and achieve the highest oil recovery factor. Due to increase in minimum miscibility pressure (MMP) with depth in compositionally grading reservoirs, MMP variations with depth is one of the main challenges in determining the optimal gas injection depth in such reservoirs. The results showed that N2, APG and N2–CO2 mixture were immiscibly injected into all depths of the reservoir due to their high miscibility pressures. The occurrence of gas override and channelling phenomena during the course of immiscible gas injection significantly reduced oil displacement efficiency. On the other hand, CO2 was miscibly injected to all reservoir layers and revealed a higher efficiency in comparison with the injection of N2, APG and N2–CO2 mixture. In fact, better miscibility development was observed in upper reservoir parts, as compared to the lower parts. Through completing injection wells at upper reservoir parts and then injecting gas into these parts, one can thus further enhance oil recovery and extend production plateau. Moreover, the results confirmed that water-alternating-CO2 injection into all reservoir depths, compared to other gas injection scenarios, was associated with increased macroscopic sweep efficiency as well as enhanced oil recovery factor. [ABSTRACT FROM AUTHOR]

• Genetic algorithm in combination with discretized variables is applied for optimization. • Using discretized variables prevents trapping at the local minimum. • The objective function was obtained using response surface methodology method. • Effective parameters on optimization of Fast-SAGD technique are discussed. Thermal recovery is one of the most common enhanced oil recovery (EOR) techniques in heavy oil reservoirs. Fast-SAGD method is a novel SAGD approach in which offset wells are drilled for periodic injection and production. This reduces the costs of SAGD pair injection-production wells and results in more production in a shorter time. Since production from heavy oil reservoirs is becoming more and more important, this study focused on thermal recovery of Mond field as one of the heavy oil fields in Iran. In this study, effective parameters of Fast-SAGD process including injection pressure and rate, injection, production, and offset well heights, offset well pressure and its injection and production periods were studied. The main purpose of this research was solving the problem of Fast-SAGD process optimization in terms of time and accuracy, as similar studies were not systematically studied on optimization of this process. In previous studies, effective parameters on the objective function were considered independently for obtaining the optimum conditions. Genetic algorithm was applied for optimization. The objective function was selected as a combination of recovery factor (RF) and cumulative steam to oil ratio (CSOR). To speed-up the optimization, effective variables were converted to discrete values. Optimization results using discrete and continuous variables were compared to each other. Moreover, results were compared to previously optimization technique applied in this field by Hemmati et al. (2013). Another point in this study was sensitivity analysis application. This showed that reservoir parameters are dependent on each other and traditional methods are inefficient for optimization of complex heavy oil reservoirs and thermal EOR processes. These points led to better results in terms of time and accuracy in this model. Results indicated 3% increase in RF and 4.7% decrease in CSOR for one injection cycle approach in comparison to two-cycle case. Response surface methodology (RSM) was introduced to setup a mathematical basis for effective variables and their interactions. Optimization results using analysis of variance (ANOVA) denoted that the injected steam and RF were 10% and 6% less in comparison to the results of genetic algorithm, respectively. [ABSTRACT FROM AUTHOR]

• The underlying mechanisms of oil recovery following N2 injection into fractured reservoirs are investigated. • We illuminate the impacts of pressure and fractures induced to assess the displacement behavior. • The impact of fractures is more pronounced in lower differential pressures. • Our results attest to the role of molecular discussion across fracture-matrix interface as the main recovery mechanism. Nitrogen has emerged as a suitable alternative to carbon dioxide for injection into hydrocarbon reservoirs worldwide to enhance the recovery of subsurface energy. Nitrogen typically costs less than CO 2 and natural gas, and has the added benefit of being widely available and non-corrosive. However, the underlying mechanisms of recovery following N 2 injection into fractured reservoirs that make up a large portion of the world's oil and gas reserves are not well understood. Here we present the laboratory results of N 2 injection into carbonate rocks acquired from a newly developed oil reservoir in Iran with a huge N 2 -containing natural gas reservoir nearby. We investigate the effectiveness of N 2 injection for enhanced oil recovery in immiscible conditions before and after gas breakthrough under a low and high differential pressures across the core. In addition to the effects of pressure, we further illuminate the impacts of fractures—induced on the cores—to assess the displacement behavior and oil recovery factor. Our findings show that an ultimate oil recovery factor of more than 40% can be achieved by N 2 injection in non-fractured cores even at immiscible conditions. The ultimate recovery and the onset times for oil production and gas breakthrough are found to be lowered by increasing differential pressures as well as inducing fractures (e.g., 17% reduction in ultimate recovery due to fracturing). However, at a given time when gas-oil interface has not yet reached the production zone (outlet), both increasing differential pressures and fractures transiently enhance the recovery efficiency. As a result, the impact of fractures is more pronounced in lower differential pressures, while the impact of differential pressures is stronger in the absence of fractures. Interestingly, our results attest to the role of molecular diffusion across fracture-matrix interface as the main recovery mechanism in fractured media, which controls the system dynamics before and after breakthroughs. The results not only provide a new perspective into how differential pressures and fractures fundamentally control the effectiveness of N 2 flooding but also further show the promising prospects of N 2 injection for EOR even at immiscible conditions. [ABSTRACT FROM AUTHOR]

Knowing the current condition of the faults and fractures in a reservoir is crucial for production and injection activities. A good estimation of the fault reactivation potential in the current stress field is a useful tool for locating the appropriate spot to drill injection wells and to calculate the maximum sustainable pore pressure in enhanced oil recovery and geosequestration projects. In this study, after specifying the current stress state in the Gachsaran oilfield based on Anderson's faulting theory, the reactivation tendency of four faults (F1, F2, F3, and F4) in the Asmari reservoir is analyzed using 3D Mohr diagrams and slip tendency factors. Results showed that all the faults are stable in the current stress state, and F2 has the potential to undergo the highest pore pressure build-up in the field. On the other hand, F3 has the proper conditions (i.e., strike and dip referring to σHmax orientation) for reactivation. Stress polygons were also applied to show the effect of the pore pressure increase on fault stability, in a graphical manner. According to the results, the best location for drilling a new injection well in this part of the field is the NW side of F2, due to the lower risk of reactivation. It was found that both methods of 3D Mohr diagrams and slip tendency factors predict similar results, and with the lack of image logs for stress orientation determination, the slip tendency method can be applied. The results of such studies can also be used for locating safe injection points and determining the injection pressure prior to numerical modeling in further geomechanical studies. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) methods assisted by gravity drainage mechanism and application of sophisticated horizontal wells bring new hope for heavy oil extraction. Variety of thermal and non-thermal EOR techniques inject an external source of energy and materials such as steam, solvent vapor, or gas through a horizontal well at the top of the reservoir to reduce in-situ heavy oil viscosity. So, the diluted oil becomes mobile and flows downwards by gravity drainage to a horizontal producer located at the bottom of the reservoir. In this paper, a sector model of an Iranian fractured carbonate heavy oil reservoir was provided to simulate and evaluate capability of some EOR techniques such as Vapor Extraction (VAPEX), Steam Assisted Gravity Drainage (SAGD), Combustion Assisted Gravity Drainage (CAGD), and Toe to Heel Air Injection (THAI) at its reservoir conditions and fluid properties. The simulation results demonstrated that wet CAGD in comparison with other nominated methods could improve heavy oil recovery factor to around 19% much more than each of SAGD, THAI, and VAPEX techniques. It could also reduce the total energy to produced oil ratio index up to 82% with respect to SAGD process in a year. Although lower oil recovery has been gained by VAPEX process, but using a proper vaporized solvent could produce a kind of de-asphalted and upgraded oil with increased API gravity up to 29°API with no considerable solvent loss. [ABSTRACT FROM PUBLISHER]

Polymer flooding is the most important enhanced oil recovery (EOR) process, improving the water–oil mobility ratio. Polymers act basically increasing the viscosity of the injected water and reducing the swept zone permeability, allowing an increase in the vertical and areal sweep efficiency of the water injection, and, consequently, increasing oil recovery. In this study, initially based on experimental work the polymer properties were enhanced using the amount of Nano clay to fixed concentration of polymer. Then the polymer flooding was simulated and comparisons were made between obtained results of polymer flooding simulated with water natural depletion and water flooding process in different scenarios. This study shows the optimum concentration of Nano clay could improve polymer properties. Results also show that the polymer flooding scenario has higher oil recovery in comparison to other displacement methods such as natural depletion and water flooding. [ABSTRACT FROM AUTHOR]

Microbial enhanced oil recovery (MEOR) is a useful technique to improve oil recovery from depleted oil reservoirs beyond primary and secondary recovery operations using bacteria and their metabolites. In the present study, the biosurfactant production potential ofBacillus licheniformismicroorganisms that were isolated from oil samples of Zilaei reservoir in the southwest of Iran was explored under extreme conditions. Growth media with different temperatures of 40, 50, 60, and 70°C; salinities of 1, 3, 5, and 7 wt%; and yeast extract concentrations of 0.5, 1, 1.5, and 2 g/L were used to find the optimum growth conditions. The results demonstrated that bacteria grown in a mineral salt solution with temperature of 50°C, salinity of 1 wt% and yeast extract concentration of 1 g/L has the highest growth rate and therefore, these conditions are the optimum conditions for growing the introduced bacterium. This isolate was selected as the higher biosurfactant producer. The obtained biosurfactants by bacteria isolated in a medium with these conditions could reduce the interfacial tension of crude oil/water system from 36.8 to 0.93 mN/m and surface tension of water from 72 to 23.8 mN/m. The results of the core flooding tests showed that the tertiary oil recovery efficiency due to the injection of microorganisms was 13.7% of original oil in place and bacteria could reduce the oil viscosity by 41.242% at optimum conditions. Based on these results, the isolated microorganism is a promising candidate for the development of microbial oil recovery processes. [ABSTRACT FROM AUTHOR]

Flaring of gas from oil wells is one of the most critical resources of greenhouse gas emissions to the atmosphere in Iran. In addition to environmental impacts, burning flare gases having high heating value results in considerable economic losses. In the current study, flare gas recovery technology assessment was employed, and its downstream installation's reliability was investigated. Using the Markov approach to consider the system's reliability, a new model was created to assess eleven technologies. Technical, economic, and environmental investigation of these eleven technologies was done. Finally, by considering two objective functions, i.e., the return payback period and the carbon dioxide emission reduction, the best technology was selected using TOPSIS decision-making method. It was indicated that the system's reliability could affect the optimal selected flare gas recovery system. Accordingly, a combination of a natural gas liquid plant and an enhanced oil recovery system at the cost of investment of 119.43 M$ and a profit of 112.16 M$ per year, with a return payback period of 1.12 years, was chosen as the final technology. Accordingly, this selected technology could reduce 1.3 million tons of carbon dioxide in the sample oil field. • A comprehensive assessment of different flare gas recovery technologies was given. • The assessment was performed by E3 (Energy, Economic, and Environmental) criteria. • A reliability model was used to evaluate the system more realistic. • Eleven FGR technologies were assessed, and enhanced oil recovery was the best. • TOPSIS decision-making was employed to find the superior FGR technology. [ABSTRACT FROM AUTHOR]

The article presents a case study of oil reservoirs in Iran for application of enhanced oil recovery (EOR) mechanisms. It mentions that various screening criteria and algorithm were used to select a suitable reservoir and EOR technique. EOR method have various steps including screening, estimation of recovery factor and full field reservoir simulation. It highlights that perfusion of miscible carbon dioxide and hydrocarbon gas are most suitable methods for oil recovery from reservoir.

Abstract: The continuous rise in CO2 and global warming is a major issue facing the world today. Iran with annual CO2 production of 532.4 million tons in 2010 has been reported to be the 9th country in the world. Shortage, low efficiency, losses, subsidies and unsuitable consumption pattern in sub-sectors challenge Iran׳s energy sector. Country׳s energy supply is intensively dependent on oil and gas, which lead to produce more greenhouse-gas emission. Therefore, Iran should establish some policies to control its environmental pollutions and place carbon-mitigation strategy within the government agenda as soon as possible. Efficient use of energy, progress of renewable energy and enhancing CO2 sequestration to mitigate more CO2 can be alternatives for reduction of greenhouse-gas emissions. Regarding major geological formations such as the second largest natural-gas reservoir and the third-greatest oil reservoir in the world and the second largest basin in the Middle East, storage of carbon and enhanced oil recovery seem to be a suitable choice for carbon capture and storage. Moreover, in Iran due to a vast land area, presence of various saline lakes which containing different species of microalgae and opportunity of establishing microalgae culture ponds, the capture unit and microalgal culture can be located close to carbon sources, which are scattered and far from geological formations. Besides CO2 mitigation, microalgae cultures can also produce valuable products and cause carbon capture more efficient. This article with the aim of anthropogenic CO2 reduction, reviews programs in the field of energy management and sustainable energy development to control emission. Then carbon sources and the potentials to capture and sequester CO2 are explored. In the end, potentials of microalgae in Iran to mitigate CO2 are described. This review is designed to investigate abilities in Iran to utilize or minimize CO2 and deploy biological carbon sequestration in the context of Iran׳s policy environment. [Copyright &y& Elsevier]

In recent years there has been an increasing interest in water alternating gas (WAG) processes, both miscible and immiscible. Microscopic oil displacement and sweep efficiency of waterflooding and continuous gas injection can be improved by WAG injection. In this work, by designing various scenarios of water and gas injection, WAG injection and simultaneously water and gas injection, the recovery and residual oil saturation obtained by implementing these methods are compared to choose the appropriate method of injection. The results showed that simultaneously the water and gas injection method has the highest recovery but from economic view, WAG process is the best enhanced oil recovery method to increase the recovery. In WAG method, the values of gas oil ratio and water cut are the smallest, so in this case, operational and process facilities problems and their costs are the minimum. [ABSTRACT FROM AUTHOR]

The use of carbon dioxide (CO2) in enhanced oil recovery is a mature well-practiced technology; however, enhancing gas recovery (EGR) through the injection of CO2is yet to be tested in the field. Depleted natural gas or gas condensate reservoirs are becoming important targets for CO2injection. The study of injection of CO2for EGR needs accurate fluid modeling of CO2behavior in the gas reservoir conditions; especially the interaction of CO2and reservoir fluid should be taken into account to obtain the best conditions for injection (Oldenburg and Benson, 2001). The purpose of this study is to evaluate the efficiency of CO2injection in one of Iranian gas condensate reservoirs by modeling of reservoir fluid properties and different behaviors of its mixture with CO2to have a proper estimation of injection condition and possibility of problems such as gravity segregation, viscous fingering, and liquid drop out at reservoir conditions. PVTi module of Eclipse software was used to perform modeling based on laboratory pressure-volume-temperature analysis of well number X of one of Iranian gas condensate reservoirs. [ABSTRACT FROM PUBLISHER]

Enhanced oil recovery (EOR) strategies for development of heavy oil reservoirs is a very complex process because it involves a great amount of money and parameters and it is necessary to consider the risk associated with geological, economical, and technological uncertainties. On the other hand the wrong strategies risk time and national capital, especially in Iran. Therefore, it is very important to choose the proper strategy to improve the quality of the results and to accelerate the process. The authors applied the analytic hierarchy process to evaluate five alternatives for EOR of a heavy oil reservoir in one Iran's heavy oil fields. This method helps reservoir management team to structure the fundamental hierarchy model, which is suited for the Ferdowsi reservoir in Iran's situation. [ABSTRACT FROM AUTHOR]

The objective of this study was to experimentally investigate the performance of water-alternating gas (WAG) injection in one of Iran's oil reservoirs that encountered a severe pressure drop in recent years. Because one of the most appropriate studies to evaluate the reservoir occurs generally on rock cores taken from the reservoir, core samples drilled out of the reservoir's rock matrix were used for alternating injection of water and gas. In the experiments, the fluid system consisted of reservoir dead oil, live oil, CO2, and synthetic brine; the porous media were a number of carbonate cores chosen from the oilfield from which the oil samples had been taken. All coreflood experiments were conducted using live (recombined) oil at 1,700 psi and reservoir temperature of 115°F. A total of four displacement experiments were performed in the core, including two experiments on secondary WAG injection and others on the tertiary water and gas invaded zones WAG injections. Prior to each test porosity and permeability of dried cores were calculated then 100% water-saturated cores were oil-flooded to obtain connate water saturation. Therefore, all coreflooding tests started with the samples at irreducible water saturation. Parameters such as oil recovery factor, water cut, and gas-oil ratio and production pressure of the core were recorded for each test. The most similar experimental work with the main reservoir condition, indicated that approximately 64% oil were recovered after 1 pore volume of WAG process at 136,000 ppm brine salinity. Although tests show ultimate recovery of 79% and 55% for secondary and tertiary injection in gas and water invaded zones, respectively, immiscible WAG injection efficiency in the gas and water invaded zones will not be proper. In the similar test to field properties, the average pressure difference about 70 Psig was observed, which shows stable front displacement. These experiments showed that there was significant improvement in the oil recovery for alternating injection of water and CO2, especially in the secondary recovery process. Water breakthrough time in almost all of the tests shows frontal displacement of injected fluid in cores and produced gas-oil ratio changes a little whenever the injection is miscible and increases rapidly in immiscible processes. [ABSTRACT FROM AUTHOR]

In this research, experimental investigations of foam-assisted water alternating gas and water alternating gas processes in carbonate cores are studied in order to estimate the increases in the oil recovery in the gas and water invaded zones. Core flooding experiments were performed for low-temperature fractured carbonate cores, chosen from one of the Iranian carbonate oil reservoirs, under tertiary recovery conditions. The experiments were conducted on 1.5-in. diameter carbonate cores, using live oil and synthetic/field brine (with 5,000 ppm of salts) as the water formation and also sodium lauryl sulfate as an anionic surfactant along with pure CO2 as the injection gas. The samples were initially saturated with live oil and connate water and then flooded with brine to reach residual oil saturation at reservoir conditions (115°F and 1,700 psia) to imitate the water invaded zone in the core. In addition to that, since the reservoir has a secondary gas cap, the same procedure was used to provide the gas invaded zone with methane as well. After performing water and gas flooding processes, several cycles of foam-assisted water alternating gas and water alternating gas were injected into the core. The experimental results indicated that a better swept efficiency and, consequently, a higher improved oil recovery can be achieved by the foam-assisted water alternating gas process. The recoveries are shown to be 19.2 and 28.7% of the residual oil in place for gas and water invaded zones, respectively. Furthermore, the results indicate that in the foam-assisted water alternating gas process, the produced free gas decreases due to foam generation inside the core. [ABSTRACT FROM PUBLISHER]

Naturally fractured reservoirs contain a significant amount of world oil reserves. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Black oil and compositional reservoir simulators have been used to determine the reservoir management and production strategies to increase the oil recovery from a low-porosity, low-permeability fractured carbonate reservoir, with an average matrix permeability of 0.8 md, average fracture permeability of 500 md, and an average matrix porosity of 10%. This reservoir is a candidate for an enhanced oil recovery (EOR) process, because the reservoir production rate has been declined due to increasing the water cut as a result of rising the water oil contact. The injection techniques that have been considered in this study for black oil model include (a) gas injection, (b) water injection, and (c) simultaneous water alternating gas injection and for the compositional model include (a) dry gas injection, (b) CO2 injection, and (c) N2 injection. Simulation results show that CO2 injection has the maximum oil recovery between the EOR scenarios. [ABSTRACT FROM AUTHOR]

Many heavy oil reservoirs contain discontinuous shales which act as barriers or baffles to flow. However, there is a lack of fundamental understanding about how the shale geometrical characteristics affect the reservoir performance, especially during polymer flooding of heavy oils. In this study, a series of polymer injection processes have been performed on five-spot glass micromodels with different shale geometrical characteristics that are initially saturated with the heavy oil. The available geological characteristics from one of the Iranian oilfields were considered for the construction of the flow patterns by using a controlled-laser technology. Oil recoveries as a function of pore volumes of injected fluid were determined from analysis of continuously recorded images during the experiments. We observed a clear bypassing of displacing fluid which results in premature breakthrough of injected fluid due to the shale streaks. Moreover, the results showed a decrease of oil recovery when shales' orientation, length, spacing, distance of the shale from production well, and density of shales increased. In contrast, an increase of shale discontinuity or distance of the shale streak from the injection well increased oil recovery. The obtained experimental data have also been used for developing and validating a numerical model where good matching performance has been observed between our experimental observations and simulation results. Finally, the role of connate water saturation during polymer flooding in systems containing flow barriers has been illustrated using pore level visualizations. The microscopic observations confirmed that besides the effect of shale streaks as heterogeneity in porous medium, when connate water is present, the trapped water demonstrates another source of disturbance and causes additional perturbations to the displacement interface leading to more irregular fingering patterns especially behind the shale streaks and also causes a reduction of ultimate oil recovery. This study reveals the application of glass micromodel experiments for studying the effects of barriers on oil recovery and flow patterns during EOR processes and also may provide a set of benchmark data for recovery of oil by immiscible polymer flood around discontinuous shales. [ABSTRACT FROM AUTHOR]

Abstract: A Bacillus mojavensis strain (PTCC 1696) which was isolated from an Iranian oil field was used to produce a lipopeptidic biosurfactant. The surface activity measurement with De Nouy ring detachment method showed that this biosurfactant is able to reduce the surface tension of the media and interfacial tension between aqueous phase and n-hexadecane to 26.7 and 0.1mN/m respectively. The core flooding tests were carried out to evaluate oil recovery from carbonate reservoirs by this lipopeptidic biosurfactant. These tests were conducted at reservoir conditions using low permeability dolomite cores, live crude oil and reservoir formation brine. The experiments showed that the biosurfactant-assisted waterflooding method can be considered as a technique for oil recovery from carbonate formations. The results obtained in this study showed the potential of the biosurfactant produced by Bacillus strains for enhanced oil recovery even from low-permeability carbonate reservoirs. [Copyright &y& Elsevier]

It is essential that precipitation of asphaltenes is recognized early in the planning stage of any CO2 enhanced oil recovery (EOR) project so that appropriate testing can be performed to evaluate whether there will be a negative impact on reservoir performance. This article presents detailed evaluations of slim tube data that were obtained during CO2 injection using a medium-gravity Iranian crude oil. A crude oil from Bangestan reservoir of Ahwaz oilfield containing 18.2% asphaltenes with ~31.5 °API gravity was flooded by purified CO2 (>96% CO2) in a slim tube apparatus under 2,700 psi at 110°C. We were going to determine the minimum miscibility pressure (MMP) of the sample oil under injection of CO2 flood, but when a CO2 slim tube test was performed for this oil at 2,700 psi, less than half of the saturated oil in the tube was recovered, which implied that the displacement process was immiscible. At this pressure, the asphaltene deposition in the slim tube apparatus was so severe that even a pressure gradient of 6,200 lb/in2 was not able to displace any fluid through the capillary tube. Therefore, we abandoned MMP determination with this sample and investigated the problem. Due to the high percentage of asphaltenes in the sample, using the slim tube MMP as an apparatus for determining minimum miscibility pressure of CO2 and sample oil can be misleading. [ABSTRACT FROM AUTHOR]

A polymer flooding technique is developed to reduce the amount of residual oil saturation that cannot be recovered through waterflooding or gas injection processes. Using polymer flooding in the case of high-viscosity oil has been successful due to reducing mobility ratio (M), whereas there is conflict in efficiency of polymer flooding in the case of low-viscosity oil. In this study, to investigate the behavior of polymer flooding in low-viscosity oil, the transparent materials (glass) were used to construct a micromodel and to study various aspects of micro-displacement. By using a micromodel, the displacement of the fluid and menisci was observed and investigated with the aid of images captured by a camera. In this work, two kinds of quarter five-spot glass micromodel patterns were designed and developed and considered as pores medium. These patterns were saturated with light and low-viscosity oil samples from an Iranian fractured reservoir and then flooded by a polymer slug in low-pressure and low-temperature conditions. Three polymer types, hydrolyzed polyacrylamide (HPAM 25%), very low hydrolyzed polyacrylamide (<5%; PA) and xanthan, were utilized to inspect the effects of polymer type, concentration, injection rate, pore structure, and presence of connate water on recovery of low-viscosity oil. The results of experiments illustrated that recovery from HPAM is higher than both xanthan and very low hydrolyzed polyacrylamide. Rate sensitivity tests showed that increasing rate injection induced a decrease in recovery. Flooding in two different micromodel patterns demonstrated that higher permeability leads to lower recovery. In addition, experiments indicated that the presence of connate water caused a reduction in recovery. Finally, compared with waterflooding, polymer flooding resulted in a considerable growth in ultimate oil recovery. [ABSTRACT FROM AUTHOR]

Abstract: In this work, biosurfactant production by Bacillus subtilis, Pseudomonas aeruginosa, and Bacillus cereus has been compared. These microorganisms were isolated from agricultural and oil polluted area of Iran. Maximum biosurfactant production reached to about 1.6g/l and liquid surface tension decreased from 72 to 25mN/m using B. subtilis. All screened bacteria exhibited a good ability to emulsify the crude oil. Biosurfactant of B. subtilis attained an emulsion index of 75% for crude oil which was significantly greater than other strains. Stability studies were carried out under the extreme environmental conditions as find normally in the oil reservoir such as high temperature, pH and salinity. Results showed an excellent resistance of all produced biosurfactants to retain their surface-active properties at extreme conditions. It was found that the biosurfactants show a good stability around pH of 4 but at lower pH, they will harmfully be affected. Lesser precipitation has been observed at low pH for biosurfactant produced by B. subtilis. It has also been observed that biosurfactants from three isolated bacteria were able to support the condition up to 25g/l salinity. B. cereus biosurfactant was even stable at the higher salinity. Regarding temperature, all produced biosurfactants demonstrated a good stability in the temperature up to 120°C. Oil displacement experiments in micromodel with kerosene showed around 25% recovery of residual oil after water flooding when the biosurfactant of B. subtilis was added. These results suggest that biosurfactants of these indigenous isolated strains are appropriate candidates for enhanced oil recovery with a preference to biosurfactant of B. subtilis. [ABSTRACT FROM AUTHOR]

Abstract: Iran, with a record of over one century of oil production, is currently one of the major oil producing countries of the world. Several of the old fields have been depleted to an uneconomical level of production which requires significant amount of natural gas for re-injection so that currently over 100 million cubic meters of natural gas is reinjected daily to maintain or enhance oil production to an economical level. It is estimated that in order to maintain oil production, over 200 million cubic meters of natural gas will be needed daily by 2015. However, due to the increased level of domestic and export demands for natural gas, EOR with natural gas is prohibitive and therefore portions of this amount of natural gas can be substituted by carbon dioxide. At the same time over 100 million tons of carbon dioxide is emitted from thermal power plants of Iran with annual consumption of approximately 35000 million cubic meters of natural gas among other fuels. The amount of CO2 which is produced in power plants in the vicinity of oil fields with relatively short pipelines for CO2 transport, however, provides only approximately 12.5% of the gas required for injection. It is expected that the power production will have an annual rate of increase of about 11% during the next 10 years which will produce more greenhouse gas and consumes more natural gas. Considering the estimated oil reserves of Iran, even one per cent of EOR is equivalent to approximately 5 billion barrels of enhanced oil recovery. Depending on the oil well structure and the pressure of operation, it is estimated that with one ton of CO2 injection, there will be from 2 to 8 barrels of oil enhance oil recovered. With the increasing price of oil and the possibility of utilizing the Clean Development Mechanism (CDM) of the Kyoto Protocol, the economy of EOR with CO2 becomes more favourable. [Copyright &y& Elsevier]

Although carbon dioxide (CO2) injection is one of the most common enhanced-oil recovery methods that is widely used in many reservoirs, it may change the reservoir-fluid properties and cause problems such as asphaltene precipitation that will result in reduction of injectivity and productivity of oil wells and plugging of wellbores and production facilities. This paper describes the effect of a miscible CO2 flood on asphaltene precipitation in the Bangestan reservoir of the Kupal field in southwest Iran. The amount of asphaltene precipitation in the mixture of oil and CO2 gas was measured by means of a PVT (pressure/volume/temperature) test, and the mechanism of precipitation under reservoir conditions was obtained by a high-pressure coreflood test. Then, the experimental results were compared with those obtained from available asphaltene-precipitation models. [ABSTRACT FROM AUTHOR]

In this study two cationic surfactants, dodecyltriethylammoniumbromide (C 12 TEAB) and hexadecyltriethylammoniumbromide (C 16 TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C 12 TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C 16 TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C 12 TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C 16 TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 °C, then the IFT increases with increasing temperature. For C 12 TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C 16 TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C 12 TEAB surfactant, the contact angle varied from 96.4° to 54.5°. In similar study using C 16 TEAB surfactant the contact angle changed from 92° to 46.1°. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs. [Display omitted] n• Investigating synthesized cationic surfactants on carbonate petroleum reservoirs oil-producing mechanisms. • Quaternary ammonium salt, synthesized surfactants could achieve lower CMC than known cationic surfactant (CTAB). • Optimization of synthesized surfactants CMC evaluated by conductometry, surface tension, and interfacial tension measurement experiments. • Optimized synthesized surfactants Wettability alteration evaluated by contact angle measurement experiment. • Lower IFT was achieved by synthesized cationic surfactants in brine solutions under reservoir harsh conditions. [ABSTRACT FROM AUTHOR]

Mechanical behavior of rocks would have substantial implications for different operations from fluid injection and hydraulic fracturing in hydrocarbon reservoirs to underground carbon dioxide storage in the crust of the earth. In all of these operations, restricting the undesired seismicity events and preserving the integrity of formations is a crucial subject that enforces engineers to evaluate the mechanical behaviors of constituent rocks and predict the formation response. Tensile strength is an important factor for maintaining caprock and reservoir formation from induced tensile cracking which can be influenced by the pore fluid. This paper focuses on the tensile strength of carbonate rock, as an important reservoir rock, in the presence of seawater, as a common injection fluid candidate for enhanced oil recovery objectives. For this purpose, twelve dolomite samples from the Asmari-Jahrum Formation outcrop in Fars province, Iran, were prepared for performing tensile tests. Also for a thorough comparison, sample properties, fluid contents, digital image correlation measurements, and a finite element simulation have been investigated. The experimental results showed a noticeable reduction in the tensile strength of dolomite samples in the presence of distilled water and seawater. In comparison with a dry sample though, a reduction of 16% tensile strength for a seawater saturated sample was observed for similar samples. Among the various mechanisms, which are reported in the open literature, the hydration force seems to be the main reason for the tensile strength reduction and this conclusion was examined by measuring the mass of vaporized adsorbed water on the powder of the same dolomite sample. In addition by testing flooded samples, the impact of flow on the tensile strength was examined. For both cases of seawater and distilled water flooding, the samples which were placed in the outlet zone during the flooding showed lower tensile strength. Moreover, simulation results confirmed the similarity of the weakening trend and impact of seawater. • Impact of pore fluid on the tensile strength of dolomite rocks. • Combining the Brazilian test with the digital image correlation technique. • Hydration force impact on the mass of vaporized adsorbed water. • Simulation of the indirect tensile test using the extended finite element. • Effluent components of dolomite flooded samples. [ABSTRACT FROM AUTHOR]