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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]

Acid gas injection operations function as the commercial equivalent of certain aspects within the realm of geological CO2 storage. Acid gas, composed of H2S and CO2, alongside minor quantities of hydrocarbon gases stemming from either petroleum production or processing, constitute the composition of acid gas. The primary aim of acid gas injection operations lies in the disposal of H2S. Nevertheless, substantial volumes of CO2 are concurrently injected due to the economic impracticality of segregating the two gases. This investigation delves into the comprehensive, step-by-step procedure that can be employed to determine the suitability of a field or formation for acid gas injection, utilizing all accessible data, including the literature and data from neighboring fields. This approach incorporates sensitivity analysis of various parameters to ascertain the feasibility of AGI while minimizing costs and time consumption. The focus of this study centers on evaluating the feasibility of Acid Gas Injection (AGI) in a saline aquifer offshore in Iran. The assessment encompasses the examination of reservoir properties, geomechanical aspects, caprock integrity, and gas plume dynamics. The Surmeh formation emerges as a promising candidate for AGI due to the presence of upper dolomite and lower carbonate within the rock formations. Geomechanical analysis reveals a pore pressure of 3800 psi and a fracture pressure of 6100 psi. Caprock integrity, particularly within the Hith formation, emerges as pivotal for both containment and long-term stability. Seismic mapping highlights variations in caprock thickness, influencing containment effectiveness. Capillary trapping emerges as a significant factor in short-term gas entrapment and plume distribution. Numerical simulations elucidate the impact of heterogeneous rock properties on capillary trapping and gas plume movement. The projection estimates approximately 2 TCF (Trillion Cubic Feet) of acid gas injection into the Surmeh formation. Based on the acid gas content and the gas in place at the source of injection, the recommended injection rate stands at 180 MMSCFD (million standard cubic feet per day). The formation's inherent tightness limits injectivity, allowing for a maximum achievable rate of 7 MMSCFD with a permeability of 1 mD (millidarcy). However, a higher porosity (12%) and a permeability of 100 mD enable more efficient injection without fracturing the formation. To achieve this, it becomes imperative to implement two injection wells, each with a capacity of 90 MMSCFD. [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 Asmari reservoir in Haftkel field is one of the most prolific naturally fractured reservoirs in the Zagros folded zone in the southwest of Iran. The primary production was commenced in 1928 and continued until 1976 with a plateau rate of 200,000 bbl/day for several years. There was an initial gas cap on the oil column. Gas injection was commenced in June 1976 and so far, 28% of the initial oil in place have been recovered. As far as we concerned, fracture network is a key factor in sustaining oil production; therefore, it needs to be characterized and results be deployed in designing new wells to sustain future production. Multidisciplinary fracture evaluation from well to reservoir scale is a great privilege to improve model's accuracy as well as enhancing reliability of future development plan in an efficient manner. Fracture identification and modeling usually establish at well scale and translate to reservoir using analytical or numerical algorithms with the limited tie-points between wells. Evaluating fracture network from production data can significantly improve conventional workflow where limited inter-well information is available. By incorporating those evidences, the fracture modeling workflow can be optimized further where lateral and vertical connectivity is a concern. This paper begins with the fracture characterization whereby all available data are evaluated to determine fracture patterns and extension of fracture network across the field. As results, a consistent correlation is obtained between the temperature gradient and productivity of wells, also convection phenomenon is confirmed. The findings of this section help us in better understanding fracture network, hydrodynamic communication and variation of temperature. Fracture modeling is the next step where characteristics of fractures are determined according to the structural geology and stress directions. Also, the fault's related fractures and density of fractures are determined. Meanwhile, the results of data evaluation are deployed into the fracture model to control distribution and characteristics of fracture network, thereby a better representation is obtained that can be used for evaluating production data and optimizing development plan. [ABSTRACT FROM AUTHOR]

A comprehensive reservoir simulation study was performed on an oil field that had a wide fracture network and could be considered a typical example of highly fractured reservoirs in Iran. This field is located in southwest of Iran in Zagros sedimentary basin among several neighborhood fields with relatively considerable fractured networks. In this reservoir, the pressure drops below the saturation pressure and causes the formation of a secondary gas cap. This can help to better assess the gravity drainage phenomenon. We decided to investigate and track the effect of gravity drainage mechanism on the recovery factor of oil production in this field. In this study, after/before the implementation of gas injection scenarios with different discharges, the contribution of gravity drainage mechanism to the recovery factor was found more than 50%. Considering that a relatively large number of studies have been conducted on this field simultaneously with the growth of information from different aspects and this study is the last and most comprehensive study and also the results are extracted from real field data using existing reservoir simulators, it is of special importance and can be used by researchers. [ABSTRACT FROM AUTHOR]

According to the studies, increasing the injection pressure at the surface will not have much effect on increasing the production flow of the well therefore, taking into account the economic cost, making changes to increase the injection gas pressure is not justified. Increasing the injection gas flow rate will cause a significant increase in the production flow. Therefore, it is recommended that control valves cannot be installed in order to control the injection flow gas due to the operational limitations, by installing appropriate reducers in the injection flow gas path to increase the oil flow. In order to investigate the effect of increasing injection gas flow rate on production from one well, one injection of gas with flow was performed at about 12000000 SCF / DAY and again injection rate was increased to 15000000 SCF / DAY and then the results were compared. [ABSTRACT FROM AUTHOR]

One of the main problems related to mature oilfields is the decreased pore pressure due to hydrocarbon production. Therefore, to maintain the production rate of a reservoir, the lost pressure must be compensated. A very traditional method to increase the pressure is to inject natural gas into the reservoir. This technique is widely used in SW Iranian reservoirs because of the readily available supply of this type of gas. Reactivation of pre-existing faults and inducing new fractures into the reservoir and cap rock are some of the potential risks regarding gas injection. In this article, using data such as well logs, pore pressure estimates, and rock mechanical test results, the geomechanical simulation of the Asmari reservoir in the Gachsaran oilfield, SW Iran has been carried out. For this purpose, the current stress field was determined using elastic moduli of reservoir rocks and formation integrity test (FIT) results. Then, by applying analytical methods such as Mohr diagrams and slip tendency, the reactivation possibility of four faults in the field was analyzed, and the maximum sustainable pore pressures were estimated. In the next step, numerical simulations were conducted using ABAQUS software to investigate the injected gas flow path, leakage potential through the cap rock, possible fault reactivation due to gas injection, and shear stress build-up and plastic strain development in different parts of the reservoir. Results of Mohr diagrams and slip tendency showed that all the faults are stable in the current stress state, and fault F2 has the potential to sustain a maximum pore pressure of 55 MPa in the field. On the other hand, fault F3 has the proper conditions (i.e., strike and dip referring to σHmax orientation) for reactivation. Results of numerical simulations suggested that an injection pressure of 30 MPa would not induce any new fracture or fault slip within 5 years of injection. In this period, the injected gas plume moves upward through the damage zone and reaches the shallower parts of the cap rock. It was also shown that by applying an injection pressure of 60 MPa, slip would occur on fault F4 after 10 days of injection. [ABSTRACT FROM AUTHOR]

Productivity of wells in South-West Iran has decreased due to completion and production problems in recent decades. This is a large risk against sustainable production from the fields. To allow stable production, an important measure is completion and production optimization including artificial lift methods. This was investigated using simulations validated by pilot field tests. Several case studies were considered in terms of their completion and production. Five scenarios were investigated: natural production through annulus and tubing (scenario-1 and 2), artificial gas lift production through annulus (scenario-3), through tubing using non-standard gas lift (scenario-4) and using standard gas lift (scenario-5). Scenario-1 is currently the case in most wells of the field. To find the optimal scenario and completion/production parameters, simulations of 11 wells of an oilfield in the region were carried out using nodal and sensitivity analysis. The optimized parameters include wellhead pressures (WHPs), tubing dimensions, maximum tolerable water cuts and gas oil ratios and artificial gas injection rate. Simulation results were validated by pilot field tests. In addition, appropriately selected wellhead and Christmas trees for all scenarios were depicted. Simulations confirmed by field pilot tests showed that optimization of completion and production mode and parameters can contribute largely to production improvement. The results showed that the current scenario-1 is the worst of all. However, production through tubing (scenario-2) is optimal for wells which can produce with natural reservoir pressure, with an increase of 800 STB/Day rate per well compared with scenario-1. However, for wells requiring artificial gas lift, the average production rate increase (per well) from the annulus to tubing production was 1185 STB/Day. Next, using the standard gas lift (scenario-5) was found to be the optimal mode of gas lifting and is strongly recommended. WHPs in scenario-5 were the greatest of all, whereas scenario-1 gave the lowest WHPs. The optimal tubing diameter and length were determined. The greatest maximum tolerable water cut was obtained using scenario-5, whereas the lowest was with scenario-1. The maximum tolerable GOR was around 1900 scf/STB. Changing of scenarios did not have significant effect on maximum tolerable GOR. The optimal artificial gas injection rates were found. This validated simulation work proved that completion and production optimization of mode and parameters had considerable contribution to production improvement in South-West Iran. This sequential comprehensive work can be applied in any other field or region. [ABSTRACT FROM AUTHOR]

The study aims to predict the physical properties of Iran crude oils using modified pressure-volume-temperature (PVT) equation of state. The modification was theoretically developed and then performed by using data of 30 black oil samples representing all active oil producing areas of Iran. The equation enables to predict the bubble-point pressure, oil formation volume factor, gas–oil ratio, oil density, crude oil gravity, gas gravity, and gas formation volume factor of black oils with average relative errors ranging from 0.01% to 10.713%. Calculation sensitivity of the proposed Peng-Robinson is determined by testing four oil samples collected from different locations in Iran and comparing the measured PVT properties with those calculated from Peng-Robinson. These evaluations show an excellent agreement between the measured properties and calculated ones. The estimation of reservoir liquid and gas properties from Peng-Robinson is often needed when detailed laboratory PVT data are not available. [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]

Extracting reservoir properties from a 3D seismic cube is an extremely sensitive job. While the inversion procedure for obtaining the inverted seismic data is itself an important step, most of such sensitivity contributes with applying multi-attribute transforms on an inverted cube to obtain a cube of reservoir property. A multi-attribute transform was applied on a 3D seismic data of a gentle anticline located southwest of Iran. Few well logs from the full sets were missing which were estimated using neural networks with sufficiently large correlations. An extended study was performed to extract the most suitable wavelet from the seismic data. The 3D cube was inverted using the model-based inversion method. The inverted cube along with other extracted cubes of seismic attributes was used as inputs to neural networks to estimate reservoir properties. Various attribute lists and estimation methods were applied and studied, and the best set of attributes and the best method of estimation were introduced. Porosity distribution was responsible for pressure difference across the reservoir; pressure communication between two upper zones was approved; results demonstrated a new potential hydrocarbon-bearing layer separated from the above producing layer by a nonporous layer. The existence of such a potential was approved by drilling a new well. The extent of reservoir flooded by the injected gas was demonstrated. [ABSTRACT FROM AUTHOR]

Recent studies have shown that oilfield harbours diverse microbial communities. Water-flooding is believed to be the main contaminating factor of oil reservoirs, however, less attempts have been made to study the effect of natural gas injection on microbial community of oilfields. Molecular methods were used to evaluate the microbial diversity of Haftkel (HK) and Lali (LA) petroleum reservoirs in the south of Iran. The HK oilfield has been injected with natural gas for long duration, but LA oilfield had no enhanced oil recovery (EOR) process. Next generation sequencing (NGS) of 16S rRNA archaeal genes indicated that the genus Methanofollis was observed with high presence in 89.7% and 92.6% frequency in the HK and LA oilfields, respectively. Most abundant phyla in HK oilfield were Synergistes (58.1%), Firmicutes (17%), Proteobacteria (Betaproteobacteria) 12.8% and unclassified bacteria (5.2%), while Thermotogae (78%), Firmicutes (10.8%), Synergistes (4%) and unclassified bacteria (3.8%) were observed in LA oilfield. The comparison of the results indicated that the injection of natural gas could increase bacterial diversity and most probable cause to increase frequency of bacterial genus Anaerobaculum belonging to the Synergistes. [ABSTRACT FROM AUTHOR]

Core flood experiments on gas injection behavior have been conducted for one of the Iranian oil fields. Different gas injection experiments in horizontal and vertical situations are designed to study the effects of type of injected fluid and gravity force on oil recovery. A sand pack from the sands of Asmari formation of one of the Iranian oil fields is prepared and is saturated with the live oil of that field. To study the effect of gravity force, methane is then injected into the prepared sand pack in the horizontal and vertical positions. The results show that a vertical injection has a stronger effect on oil recovery due to gravity force effects. Then different gases, including nitrogen, methane, and carbon dioxide, are vertically injected in the sand pack. The maximum recovery is obtained for methane injection. When CO2is injected some signs indicate that asphaltene is precipitated. [ABSTRACT FROM PUBLISHER]

In gas condensate reservoirs, after a decrease in pressure below the dew point pressure, condensate formation would occur. One of the common and practical methods for prohibiting the rapid pressure drop in the reservoir and reduction of liquid dropout is gas injection. In this study, experimental measurement, the full field reservoir model and an economical evaluation have been performed to investigate the effect of nitrogen injection on an Iranian Southwestern gas condensate reservoir. At first, swelling and CVD tests were carried out to determine the swelling factor and changing the saturation pressure by nitrogen. Then, the full field simulation (history matching and prediction) was performed and finally an economical evaluation has been made. The results show that injecting more volumes of nitrogen cause to decrease the liquid dropout, increase the dew point pressure, and condensate ultimate recovery, but this process is not an economical project. [ABSTRACT FROM AUTHOR]

M-Reservoir is a dual porosity fractured reservoir having active aquifer and heterogenous production zones. It had had only a total oil recovery of 8.4% with the total production of 240 MMSTB up to 2008. By simulation of slime tube experiment using Eclipse 300 software, minimum miscibility pressure of 3700 psia was obtained, which was below its average pressure. Production optimization and final recovery increment were performed via analyzing and matching of fluid reservoir, history matching of past reservoir performance, and investigating on different location of gas injected well. The best location of injected well was selected based on the recovery coefficient and gas injection method of miscible and immiscible at various rates and were compared with natural depletion in selected locations. The results represent that the miscible gas injection has more recovery coefficient than natural depletion and there is somewhat recovery coefficient in comparison with immiscible gas injection. [ABSTRACT FROM PUBLISHER]

Miscibility is controlled by physical dispersion during miscible processes that comprise two parameters: diffusion and mechanical dispersion. Testing different dispersivities on one synthetic model then on a field case shows the existence of three regions at which each component of physical dispersion controls the miscible CO2 injection. Unfortunately, this parameter is usually ignored during simulating the miscible processes, but this study shows neglecting physical dispersion will highly affect the breakthrough time of displacing fluid. The results show the highest recovery for the process controlled by physical dispersion which could be an important result in designing a miscible process. [ABSTRACT FROM AUTHOR]

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]

Abstract: The remarkable consequence of carbonated water injection (CWI) is not only in lowering a green-house gas that is otherwise released into the atmosphere, but in its notable ability in increasing oil recovery from hydrocarbon reservoirs. This type of carbon dioxide (CO2) sequestration method requires amounts of CO2 that can be recovered from sources available near hydrocarbon fields. Thus cost of transportation, storage, pressurizing (obtained CO2 from such sources is already high pressured) and compression (hydrostatic pressure of water in injection well makes injection easier) is lowered. Furthermore, carbonated water forms carbonic acid that reacts with rocks and improves permeability (i.e. injectibility) while CO2 dissolves in oil, causes oil expansion, lowers oil viscosity and improves recovery. In this work, different production scenarios have been studied in one of Iran's southern reservoirs. CWI has been evaluated against natural depletion and water injection based on its performance in enhancing production and ability to safely sequestrate CO2. Finally, experimental CWI in core scale reported in literature has been implemented to determine dominant forces in CWI and dependency of CWI performance on viscosity of crude oil samples and injection flow rates. [Copyright &y& Elsevier]

The effect of salinity of injected water and reservoir water in water alternating gas injection in one of an Iranian reservoir was investigated. Usually in simulation works water salinity of reservoir or salinity of injected water may be ignored. Without applying salinity effect, it would cause estimated overall oil recovery to be different with real. Salinity of water phase would increase the viscosity of injected water also obviously the mobility ratio of oil. Because of this improvement in water mobility, more oil would be displaced toward production wells. The problem of increasing salinity of injected water is that too much salt may harm pump equipments. Over time, salt deposits in pumping devices may cause reduction in pumps efficiency and corrosion of pipes, thus injecting salty water would cause corrosion problems and pump failures. Since the salinity of the reservoir water in the study was not available so it was chosen in two modes: reservoir water without salt (Cs = 0) and with concentration of 140 kg/m3(Cs = 140). In this work 0.8 reservoir pore volume WAG was injected. Salinity of injected water was varied from zero to 4,800 kg/m3; by increasing salinity of injected water, because of mobility ratio increment between water and oil, production efficiency would be increased. The economic dimension of this view must be examined. By considering reservoir water salinity, recovery would be increased in WAG injection. [ABSTRACT FROM AUTHOR]

The effect of using foam in water alternating gas injection method as an enhanced oil recovery method in one of Iranian oil reservoirs was investigated. The model of under investigation has high vertical permeability in vertical direction, so injected gas front would be breakthrough early times of injection periods. Foam implemented in injected gas phase of water alternating gas injection by decreasing the mobility of the gas phase and improving sweep efficiency of gas phase dominates this problem. In this work foam agent was added in water alternating gas injection method in two manners, with water phase and with gas phase. It was seen higher recovery for adding foam to gas phase in water alternating gas injection method. The results showed that foam increases the resistance of gas phase to flow through high permeable zone. By increasing the concentration of foam agent, total recovery would be increased but the rate of recovery incremental would be reduced after critical foam concentration. To reduce the costs, critical foam concentration must be found. [ABSTRACT FROM AUTHOR]

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]

Increasing demand for energy has forced oil companies to resort to secondary and tertiary methods to increase the recovery from the existing reservoirs. The author investigated enhancing the recovery factor of one Iranian reservoir, which is a naturally fractured reservoir. For this reservoir, it is estimated that 96.5% of oil is contained in the matrix and 3.5% in the fractures. The field is an undersaturated reservoir with no active gas cap and no strong water aquifer. Injections of water, gas, water-alternating gas (WAG), and infill wells on this field were investigated to increase the recovery factor. Eclipse100 was employed to simulate the reservoir. The simulated results showed that gas, water, and WAG injections had nonsignificant improvements on oil recovery. However, it was found that infill wells contribute an appreciable increase in recovery. The amount of increase for drilling 8 infill wells was around 5%. Since development of existing resources contributes a major role on the supply of oil for the future oil market (around 45% by 2030), these results are used to screen the various methods for increasing the recovery of such reservoirs. [ABSTRACT FROM AUTHOR]

Abstract: The structure and analysis of naturally fractured reservoirs (NFRs) is more complicated than the conventional reservoirs because of their double medium nature containing matrix (high porosity and low permeability) and fracture network (low porosity and high permeability). There is an essential need for more study and further understanding of fractured reservoirs characteristics due to the fact that the majority of the world''s petroleum reserves, particularly in the Middle East, are in NFRs. The situation is more complicated in gas condensate reservoirs in which the liquid drop-out and condensate blockage phenomena typically occur. In a retrograde gas condensate reservoir, the condensate accumulation in the fractures prevents the fractures to maintain their fundamental role as the most permeable conduit for the gas flow. This article deals mainly with the specific phenomena that occur in the gas condensate fractured reservoirs related to condensate banking and the existence of double porosity media for instance decrease of Gas Oil Ratio (GOR), lower horizontal pressure, uniform condensate properties throughout the reservoir, significant difference in production history, and elimination of transition zones. The results of this study demonstrate the importance of double porosity/dual permeability model in the simulation of gas condensate fractured reservoirs. Also, the physical properties of fractures such as capillary pressure and relative permeability are of great importance in simulation studies such that the use of linear relative permeability curves inside fracture could lead into wrong predictions. [Copyright &y& Elsevier]

The authors' purpose was twofold: (a) to study optimum capillary number for acquiring maximum oil recovery in vertical gas-oil displacement using carbonate and sandstone cores, and (b) to investigate the influence of capillary end effect on optimum capillary number extracted from experimental data. Two sets of forced gravity drainage experiments were performed on carbonate and sandstone cores. The first set of experiments comprised seven vertical nitrogen injection tests using carbonate core, which had been saturated by kerosene in ambient laboratory condition. The second set consisted of six vertical nitrogen injection tests using sandstone core that had been saturated by live oil under reservoir temperature and pressure conditions. In each set of experiments, in constant bond number, one optimum capillary number (optimum flow rate) was recorded in which the maximum oil recovery was achieved. When capillary end effect was negligible, optimum capillary number was compatible with critical capillary number, which was calculated in critical gravity drainage velocity while in considerable end effect, optimum capillary number was higher than the calculated critical capillary number. In addition, the residual oil saturation in carbonate rock showed a declining trend when capillary number increased, whereas the minimum of residual oil saturation in sandstone core has been observed in optimum capillary number. [ABSTRACT FROM AUTHOR]

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]

Production or injection of fluids from/in an underground storage site causes variations of pore pressure and stress states. These fluctuations significantly affect implications for hydraulic fracturing, wellbore integrity, top surface subsidence and heave, fault-reactivation, and stability of reservoir and caprock. Therefore, in order to keep optimal conditions during the process of gas injection and production, it is of paramount importance to have accurate estimates of the pore pressure. In this investigation, coupled fluid flow and geomechanical simulations, as well as rock mechanical tests, are performed on the Sarajeh field, Iran to investigate the geomechanical behavior of the Sarajeh reservoir during gas injection and production as well as estimate the caprock and reservoir integrity and evaluate the risk of fault reactivation. The results show up to −16 cm subsidence due to the production and 6 cm heave due to the injection. The critical pressures for the reservoir rock's failure and activation of the faults are 11,283 psi and 9986 psi, respectively, which make the operator able to store gas up to 2.2 and 1.9 times higher than the maximum reservoir pressure. Hydro-mechanical evaluation of the Sarajeh field determines essential information about the effect of gas injection and production for safe and successful seasonal gas storage. • The subsidence and heave of the reservoir were investigated during a seasonal gas storage operation. • The integrity of the reservoir and its caprock was studied by evaluating the experienced stress path by the reservoir. • Fault activation analysis was done to estimate maximum allowable injection/production pressure. [ABSTRACT FROM AUTHOR]