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The clastic reservoir in Tarim Oilfield has entered the middle-to-late stage of development, and consequently, enhanced oil recovery (EOR) is becoming highly challenging. Gas flooding is the practical method for EOR from this type of reservoirs. In this study, taking Tazhong 402 CIII reservoir as an example, the micro-mechanism of EOR by gas injection is investigated by conducting slim-tube, long-core displacement, and micro-visual displacement experiments. A gas injection development plan is formulated based on reservoir characteristics, laboratory experiments, and numerical simulations. The results show that miscible flooding cannot be achieved by injecting natural gas under the current formation conditions; however, natural gas flooding after light hydrocarbon flooding can significantly improve oil recovery. The studied reservoir is divided into two series of development layers: CIII1–3 layers, for which light hydrocarbon alternating natural gas flooding is adopted, and CIII4–8 layers, for which light hydrocarbon combined with natural gas gravity-assisted composite flooding is employed. The findings of this study have guiding significance for gas injection development in deep clastic reservoir in Tarim Basin. [ABSTRACT FROM AUTHOR]

Adjusting injection and production parameters is an essential tool for studying the effect of reservoir heterogeneity on in-situ combustion (ISC) sweep and associated control strategies, as well as for achieving stable ISC. An asynchronous injection and production in-situ combustion (AIPISC) method through the coupling of the gas injector and producer in order to accomplish the balanced sweep of ISC. Using the Hongqian (HQ) ISC in Xinjiang as an example, numerical simulation was utilized to define the reservoir and investigate the sweep characteristics under various sedimentary models. The AIPISC technology was applied to several heterogeneous reservoirs, and the design scheme of AIPISC was created. Under the same heterogeneous reservoir circumstances as the conventional ISC approach, the oil saturation of the AIPISC wall increases from 0.65 to 0.72. The roundness of the combustion chamber was better, and balanced displacement can be achieved. Then the parameters of AIPISC were optimized to determine that the vertical permeability difference of the reservoir should be less than 15, the asynchronous time difference was 6 ∼ 8 months, and the gas injection amplitude was 1.5 ∼ 2.0. The results show that the experiment in HQ Oilfield was successful, and the usefulness of AIPISC was investigated using the electromagnetic approach. [ABSTRACT FROM AUTHOR]

Gas condensate reservoirs are generally a mixed system of hydrocarbon and water. This paper is aimed to investigate the phase behavior change influenced by water vapor during the development of depletion and CO2 injection. The Gnorth reservoir of Zhanazhol oilfield in Caspian Basin is taken as an example. Two-phase flash was based on QNSS\Newton method, and multiple contact calculations were performed through cell-to-cell method. The research results indicate that, for the remaining reservoir fluid of depletion development, water vapor has the largest effect on the content change of CH4, followed by C7+, and the smallest effect on C2 to C6. The presence of water vapor makes it easier for the condensate to drop out of the gas phase. For CO2 injection, water vapor is not beneficial to re-evaporation for the formation condensate. Further, the multiple contact miscibility of CO2 and condensate is less affected by water vapor. [ABSTRACT FROM AUTHOR]

CO2 displacement is a common technique for the enhanced oil recovery and simultaneously alleviates the greenhouse effect. However, the recent applications of CO2 displacement focus on the formations where the fluid and reservoir properties could not reach absolute miscibility. The reactions between CO2 and high pour point crude oil during the near-miscible displacement process would be far more complex. In this study, slim-tube and one-dimensional core (sand-filling model, splicing long core) displacement experiments were carried out. Group component analysis and saturated hydrocarbon analysis were applied during the process and the possibility of organic solid deposition and blockage was deduced. The indicator of permeability reduction rate of long core was introduced and used to evaluate the impact of the deposition of each short core on the permeability. Through analysis and comparison, deposition and blockage occurred in the front and middle of the long core, and the maximum permeability reduction rate reached about 0.04%. The results showed that although near-miscible displacement could improve the oil recovery, there was still the possibility of potential blockage which should be carefully considered in the design of the gas injection scheme. [ABSTRACT FROM AUTHOR]

Water control is an effective method to enhance the oil recovery in the high water-cut reservoir. It is proved that the water production can be reduced by the entrapped gas in the oil field. But the mechanism is not well studied. In this paper, the mechanism of enhanced oil recovery by entrapped gas is studied by experiments and numerical simulation. Based on the core flooding tests and simulation study, the increments of oil recovery caused by entrapped gas are 8% and 2%, respectively. After the gas is entrapped in the core sample, the water relative permeability is decreased by 10.5% and the oil relative permeability is only decreased by 3.5%, which proved that the entrapped gas has a dramatic effect on blocking water phase. The more gas is entrapped, the more oil is produced. Different methods to achieve entrapped gas are also discussed, simultaneous water, and gas injection is a preferred entrapped gas formation method than gas injection method and water alternating gas injection method. Under the immiscible condition, the entrapped methane has a better performance on enhancing oil recovery than the entrapped nitrogen. [ABSTRACT FROM AUTHOR]

In order to determine the MMP using the slim test, the use of an appropriate criterion is inevitable. But there is no standard method or criterion for interpreting the data in this experiment to determine the MMP. However, various criteria such as linear intersection (LI), oil recovery factor (ORF), and break-over pressure (BOP) are currently used to ascertain MMP. However, these criteria are not perfect and need to be improved. In this paper, a slim test is first performed for a live-oil and methane. Then, the mentioned criteria have been modified. Modified ORF and BOP criteria are named MORF and MBOP, respectively. All the results from the various criteria are compared, and an interval for the MMP is determined. Finally, for the performed slim tube test, a pressure range of 6061.71-6258.94 psi has been determined. The novelty of this study is to provide more methods to determine the MMP interval, as well as criteria that can be used for a wider range of laboratory data. The application of the results of this study will be to determine a range for MMP, so that if the gas injection pressure is in this range, the injection conditions will be miscible. [ABSTRACT FROM AUTHOR]

The injected fluid can chemically react with reservoir rocks and fluids, which changes the properties of petroleum and rocks. Consequently, oil recovery rates are subject to change during the EOR process. Therefore, the study of chemical reactions during EOR process is important. During the CO2 injection, the deposition of asphaltene, and the change of minerals, dissolution and deposition can occur at the same time. Dissolution of rock minerals can increase permeability and effective porosity, but precipitation of asphalt and deposition of these minerals can have the opposite effect. This study investigates the CO2 flooding process in heavy oil reservoirs containing highly permeable sandstone and assesses the effect of orientation on oil recovery and rock-fluid interactions. The results show that due to the gravitational stability in the vertical configuration, there is more oil recovery, mineral solution, and asphaltene sedimentation in the vertical configuration compared to the horizontal configuration. The percentage of asphaltene in the sandpacket model was 1.92 weight percent vertically and 1.18 weight percent horizontally. The increase in porosity for vertical was 2.6% and 1.1% for horizontal infusion. From this it can be concluded that the dissolution of minerals is higher with vertical injection than with horizontal injection. [ABSTRACT FROM AUTHOR]

Gas injection is one of the most widely used enhanced oil recovery methods in hydrocarbon reservoirs that has been attracting considerable interest of the oil and gas industry over the years. With the rapid development of research areas involved in gas injection, understanding the evolutionary pattern and significant milestones of collective knowledge development has a newfound urgency. This study used a bibliometric approach to identify knowledge domains, intellectual milestones in the development of important research areas, evolutionary stages, the technical state of the art and emerging trends concerning gas injection. The document co-citation network offers an intuitive overview of the intellectual structure and the state of the art of this specialty. The bibliometric indicators provide quantitative analysis for identifying particularly impactful contributions within a specific field of research, such as the landmark works with the most citation counts, the structurally significant articles with the highest betweenness centrality, and the most active areas detected by the strongest citation bursts. The timeline visualization draws on Shneider's scientific evolution model to track the evolutionary stages of gas injection consisting of knowledge conceptualization, research instruments accumulation, and technology integration and application along historical and philosophical lines. Through structural variation analysis, we explored potentially transformative contributions and emerging trends which may boost the development and application within and among relevant fields. The methodological approach taken in this study provides a generic method for conducting a systematic review of a scientific discipline. [ABSTRACT FROM AUTHOR]

The objectives of this article it to present a water alternating gas (WAG) process evaluation methodology for a giant middle eastern carbonate reservoir. The methodology involves enhanced oil recovery through an immiscible hydrocarbon water alternating gas (WAG) injection method. Although water alternating gas injection is a proven enhance oil recovery technique and has been around for some time now, only a limited published literature is available on complete evaluation of immiscible WAG process in field application. This article aims to bridge the gap by presenting a detailed study of immiscible water alternating gas evaluation process. In this article a complete methodology for evaluating a water alternating gas injection recovery technique is presented. It includes optimization of WAG cycle length, WAG ratio, production constraints, injected gas compositions, WAG duration, and WAG slug size. The work presented in this article could aid oil field operators to understand the impact of different parameters on immiscible WAG injection process and potentially help them to optimize production from their fields. [ABSTRACT FROM AUTHOR]

CO2 injection and water-alternating-gas injection are EOR methods for improving oil recovery. This paper shows Water alternating gas (WAG) and continuous gas injection experiments with CO2 in secondary recovery. Experiments were performed in sand-packed-model. The continuous gas injection experiments were conducted at 3800, 4200, 4600 and 5000 psi, then two WAG experiments was completed at 3800 psi. Also temperature was 190 °F (the reservoir temperature) in all experiments. Six tests were conducted to investigate continuous CO2 and WAG injection under the reservoir condition. In the first test, 1.2 PV (pore volume) of CO2 was injected into sand-packed-model at pressure of 3800 psi and temperature of 190 °F. Amount 1.2 PV of CO2 was injected into sand-packed-model at 4200 psi in the test 2. In third one, 1.2 PV of CO2 was injected at 4600 psi and 1.2 of PV CO2 was injected at 5000 psi in forth one. Water alternating gas injection experiments with CO2 were including two tests. In the first one, 0.3 PV of CO2 and 0.9 PV of brine were injected consecutively into model. In the second one, 0.3 PV of CO2 and 0.3 PV of brine were injected respectively into model and this test was completed in two cycles. The results indicate that increase of injection pressure enhances oil recovery in continuous CO2 injection and increase of injected CO2 increases oil recovery in WAG process. Also WAG injection increases oil recovery more than CO2 continuous injection. [ABSTRACT FROM AUTHOR]

Nitrogen (N2) and carbon dioxide (CO2) gases injection yield substantially various recovery ways. Here, a one-dimensional mathematical model is applied comprising of mass balances for explaining gas sorption and flow, and a geomechanical relationship to describe the permeability changes during gas injection. That's why numerical simulations for investigating the performance of injecting flue gas mixture in enhanced coal bed methane (ECBM) recovery are represented. Significant intuitive features are found regarding the gas flow dynamics at the time of displacement and influences of sorption on ECBM operation. The study revealed that the injection of pure CO2 causes much reduction in cleat permeability, but pure N2 is injected to increase the permeability without any loss of injectivity. Therefore, pure CO2 causes more efficient displacement in terms of total CH4 recovery, while the addition of N2 to the mixture assists to make quicker the initial methane recovery. [ABSTRACT FROM AUTHOR]

In this work, the efficiency of CO2-foam injection for enhanced oil recovery (EOR) is investigated. Six floods were performed on sand pack columns. Pure water injection, WAG injection and simultaneous injection of CO2 and surfactant solution with various concentrations were conducted. Notable difference was observed between oil production in secondary surfactant assisted WAG and other injection scenarios. The experimental work in this research shows that increase in concentration of surfactant in the injection process results in mobilization of more oil that may not have been achievable by using water flooding and WAG flooding methods individually. [ABSTRACT FROM AUTHOR]

Due to the significant impacts of CO2-oil miscibility, reservoir heterogeneity, and injection pattern on oil production, a fascinating experimental investigation is provided. The outcomes express that CO2 consumption in homogeneous cores are lower than heterogeneous cores. A small amount of permeability heterogeneity as one of the indications of heterogeneity, can highly effect on the performance of miscible and immiscible injections. On the miscibility viewpoint, multi-contact miscible injections have better performance than immiscible injections in range of 7.2% − 16.4%. Also, the injection patterns comparisons express that best choice for pattern injection is water alternating gas injection. [ABSTRACT FROM AUTHOR]

Gas injection is one of the most common heavy oil recovery methods. In this study, effect of viscosity reduction of heavy oil on its recovery and production rate during gas injection were investigated. In this regard, governing equations such as continuity and stokes equations were solved using finite element method with assuming specified initial and boundary condition. Numerical results show that production rate for gas injected heavy oil is 50 times higher than that of heavy oil without considering gas injection. Also, simulation results demonstrate the location of high pressure drop zones in porous media. [ABSTRACT FROM AUTHOR]

Carbon dioxide flooding is a very complicated process, involving phase behavior that could increase oil recovery by means of swelling, evaporating, and lowering oil viscosity. The present investigation reports the results of extensive experimental and theoretical work to determine the viscosity and swelling factor changes of the live oil in the Cheshmeh Khoshk reservoir in southern part of Iran (Ilam District), and also minimum miscible pressure is determined. In this study, we want to study the potential of carbon dioxide injection application in improving oil recovery by simulating a slim-tube experiment. In order to get representative fluid samples of a reservoir, it was necessary that the right operation of mixing the separator oil and gas samples to match the bubble point pressure be carried out. The potential application of the study is that we could have a good estimate of the recovery improvement under carbon dioxide gas injection, which will be the basic input parameter for the economic feasibility study, and also a decision can then be made whether to implement or abandon the prospective project. [ABSTRACT FROM PUBLISHER]

Asphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. Therefore, predicting asphaltene phase behavior through thermodynamic modeling may help to control its precipitation and reduce the associated problems. In this work, a new modified cubic-plus-association (CPA) equation of state (EoS) was used to model asphaltene precipitation. This equation is based on a combination of a new physical part and an association term. The new physical part has an evolved cubic equation of state with a new attractive term in this work. The results of the new modification of CPA EoS were compared with the experimental data of two oil samples (oil samples 1 and 2) that belonged to Moradi et al. The results showed that this modified CPA EoS can predict asphaltene precipitation with good accuracy. [ABSTRACT FROM AUTHOR]

Maintaining the flow of multiphase fluid from the reservoir to the surface has been an important issue with wide economic importance for the petroleum industry. Asphaltene precipitation due to change in temperature, pressure, and composition of oil can adversely affect the oil flow to the surface by reducing the available diameter of the tubing. In this study, the precipitation of asphaltene from an Iranian crude oil was investigated. To do our study, through information about asphaltene instability in the live oil during both natural depletion and gas injection conditions about oil sample from Iranian oil field was gathered. Then, the solid model and scaling model were utilized to predict the weight percent of precipitated asphaltene at a wide range of the pressure and temperature. Results of the work revealed that both models predict the increase in weight percent of precipitated asphaltene when lean gas injected to the live oil at the maximum point of asphaltene instability. In addition, the study showed that both models are capable of predicting the experimental data of asphaltene precipitation; while scaling modeling is more reliable when the gas is injected to the oil. [ABSTRACT FROM PUBLISHER]

In this study a laboratory study was carried out with the purposes of estimating the effectiveness of the gas cycling process during gas-condensate reservoir development. Specific laboratory equipment was constructed to carry out an experimental investigation by modelling the gas injection and reservoir depletion process. Volumetric properties, fog up, liquid drop-out condition, and retrograde dew point pressures of gas-condensate fluids were investigated. The reservoir fluid was recombined based on samples from Azerbaijan natural gas-condensate reservoir. Results are describing gas injection effect on condensate/gas ratio and condensate recovery in each pressure step. These have provided an understanding on the influence of the retrograde dew point pressure on optimum gas injection stage. The analyses also assure that as condensate/gas ratio decreases continually during the gas injection process, which causes the reservoir fluid PVT characteristics to be changed accordingly furthermore the reservoir pressure can be depleted in order to vaporize the liquid phase and to maintain the reservoir fluid to be in a single phase state during the reservoir exploitation. It was seen to be closely related with retrograde dew point pressure and fog up pressures. Therefore, in terms of incorporating colloidal systems into the subject focusing more on the region between fogging up and retrograde condensation gave interesting results. [ABSTRACT FROM AUTHOR]

In gas condensate reservoirs, when the bottom hole pressure falls below the dew point pressure condensates are formed. This causes hydrocarbon liquid saturation around the well bore region. This phenomenon is called condensate blockage or condensate banking. Condensate recovery reduction due to condensate banking near the well bore region is an important problem in gas condensate reservoirs. The common method to prevent the condensate banking is gas cycling (reinjection of produced dry gas) into the reservoir that can contribute to the condensate vaporization, thus increasing the condensate recovery factor. The objective of this study was to find a suitable replacement for gas cycling. For this purpose, an investigation on the effects of injection of different types of gases (CO2, N2, and C1) on enhance condensate recovery factor and pressure maintenance were performed. This research was done on one of the Iranian gas condensate reservoirs through a compositional simulator. The two-parameter Peng-Robinson equation of state (EOS) and Lohrenz-Bray-Clark correlation were used to model reservoir fluid properties through regression on the pressure-volume-temperature (PVT) experimental data. A fracture network was distributed over the reservoir, so a dual porosity/dual permeability model was selected for better evaluation of the fracture system. Then, various scenarios of natural depletion and CO2, N2, C1, and gas cycling injection were studied. The results showed that CO2injection scenario being associated with the highest efficiency compared to that of other gases. [ABSTRACT FROM PUBLISHER]

Misciblegas injection is a promising technique to enhance the oil recovery from petroleum reservoirs. Natural gas is usually injected because of consistency between the gas and reservoir fluid composition and accessibility of the injected fluid. In this work a new correlation is presented for accurate prediction of the required minimum miscibility pressure (MMP) for multicontact miscible displacement of reservoir petroleum by hydrocarbon gas injection. Accurate estimation of the MMP is required for optimal design of recovery systems and optimization of the production economics. It is shown that the presented correlation is very accurate and reliable for predicting the MMP over wide ranges of oil and gas compositions. Comparison of the suggested correlation with the most important existing correlations shows that the presented correlation outperforms the other alternatives both in accuracy and generality. [ABSTRACT FROM PUBLISHER]

In this study, produced natural gas reinjection process is proposed to form renewed foamy oil for heavy oil recovery. A new experimental procedure was developed to prove that an in situ foamy oil could be formed during the gas injection process. A field scale numerical study was performed to further analyze foamy oil behavior and its influential mechanisms. The study showed that natural gas huff-n-puff process could increase heavy oil recovery by inducing foamy oil. The findings of this study could be useful to solve the problem of disappearance of foamy oil mechanism. [ABSTRACT FROM PUBLISHER]

Gas flooding in fractured reservoirs may not be an effective avenue for improving oil recovery because the injected fluids could break-through to production wells via the fracture network. A cyclic injection scheme is one way to solve this problem. In this study, the authors propose to use cyclic gas injection to improve hydraulically fractured shale oil recovery. They used a simulation approach to evaluate the enhanced oil recovery (EOR) potential from cyclic gas injection. The simulation results indicate that total oil recovery can be increased up to 29% by cyclic gas injection, compared with the 6.5% recovery from the primary depletion. If a higher pressure is used to reach fully miscibility with reservoir oil and more cycles are employed, more oil recovery is expected. [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]

This research comprises natural depletion, associate, and CO2 gas injection with regard to asphaltene precipitation and permeability reduction. For the sake of achievement these goals experiments were undertaken by core flood and asphaltene static apparatus. Natural depletion was performed at 4500, 3050, 2250, 1450, and 900 Psig and it has been seen maximum amount of asphaltene precipitation located at saturation pressure. The results demonstrate that asphaltene precipitation during natural depletion was higher than CO2 and associate gas injection. Also it was seen asphaltene precipitation rate during CO2 and associate gas injection was lower than natural depletion. Based on results, amount of asphaltene precipitation was differing according to type of gas. The results of the study indicate asphaltene precipitation during CO2 injection was more than associate gas injection. Finally it was seen the permeability reduction during associate was less than CO2 and natural depletion for this kind of Iranian carbonate sample. [ABSTRACT FROM PUBLISHER]

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]

A fast simulator is presented to forecast quickly the performance of oil reservoirs during gas (miscible and immiscible) injection based on transfer functions (TF). In this method, it is assumed a reservoir consists of a combination of TFs. The order and arrangement of TFs are chosen based on the physical conditions of the reservoir that are ascertained by examining several cases. The selected arrangement and orders can be extended. The only required data of this method is production and injection history that are easily accessible. Injection and production rates act as input and output signals to these TFs, respectively. By analyzing input and output signals, matching parameters are calculated for each case study. The outcomes of the method are compared with those obtained by a grid-based simulator. The comparison indicates a good agreement. [ABSTRACT FROM PUBLISHER]

Gas injection into reservoirs can be used to increase oil recovery. However, reservoir heterogeneity and high gas mobility reduce sweep efficiency and decrease recovery. Using foam can reduce gas mobility and therefore increase sweep efficiency. Foam is thermodynamically unstable, so it is important to predict the foam stability. In order to understand the influence of oil presence on foam stability, static experiments performed on foam by varying the type and amount of added oil and molecular weight of added alkane. Also static foam properties have been investigated by varying the surfactant concentration, ionic strength, composition of different salts in the sample, and addition of polymer. [ABSTRACT FROM PUBLISHER]

Asphaltene precipitation problems manifest themselves in different stages of oil reservoirs production. Experimental and modeling investigations are, therefore, employed as promising tools to assist in predictions of asphaltene precipitation problems and selection of proper production facilities. This study concerns experimental and modeling investigations of asphaltene precipitation during natural production and gas injection operations for a heavy Iranian crude oil at reservoir conditions. First, with design and performance of high pressure–high temperature experiments, asphaltene precipitation behavior is comprehensively investigated; the effects of pressure and temperature are fully studied during pressure depletion tests and the role of injection gas composition on precipitation is described in gas injection experiments. In the next stage, the obtained experimental results are fed into a commercial simulator to develop the asphaltene precipitation model. The results for the pressure depletion experiments indicate that the maximum amount of asphaltene precipitation takes place at fluid bubble point pressure. Increase in the temperature, as seen, causes to reduce the amount of precipitation for the entire range of pressures. For gas injection experiments, the onset of precipitation for CO2, associated, and N2gases takes place at around 0.20, 0.28, and 0.50 gas to mixture mole ratios, respectively. Carbon dioxide shows the highest asphaltene precipitation values and nitrogen has the lowest amounts for the whole range of gas mole fractions. Finally, the results for modeling indicate successful asphaltene precipitation predictions for both pressure depletion and gas injection processes. [ABSTRACT FROM PUBLISHER]

The nature and behavior of asphaltene in crude oils is complex and changes in temperature, pressure, and composition of crude oils during production can result in precipitation of asphaltene components. Potential solutions for these problems include physical removal of deposits, solvent washes, and treatment with dispersant agents. The authors summarize the results obtained on the inhibition effect of one commercial inhibitor namely IR95 and five non-commercial inhibitors namely benzoic acid, nonylphenol, phenanthrene, phthalic acid, and salicylic acid. The results revealed distinct mechanisms for asphaltene solubilization/dispersion and inhibition of asphaltene precipitation in crude oil and show that IR95 have the best efficiency on precipitation reduction this crude. [ABSTRACT FROM AUTHOR]

An important factor in the design of gas injection projects is the minimum miscibility pressure (MMP). A new genetic algorithm (GA)–based correlation and two neural network models (one of them is trained by back propagation [BP] algorithm and another is trained by particle swarm optimization algorithm) have been developed to estimate the CO2–oil MMP. The correlation and models use the following key input parameters: reservoir temperature, molecular weight of C+5, and mole percentage of the volatiles and intermediate components (for the first time, the mole percentages are used as independent variables). Then results are validated against experimental data and finally compared with commonly used correlations reported in the literature. The results show that the neural network model trained by BP algorithm and the correlation that has been developed by GA can be applied effectively and afford high accuracy and dependability for MMP forecasting. [ABSTRACT FROM AUTHOR]

Gas condensate reservoirs have complicated fluid flow and thermodynamic processes. As reservoir pressure decreased, the gas condensate system exhibits a dew point. As pressure is reduced, liquid condenses from the gas to form free liquid in the reservoir. This liquid phase develops with pressure reduction and the composition of gas phase is changing due to pressure reduction. The condensate is deposited at such low liquid saturation that is usually trapped by surface tension forces, is therefore immobile, and cannot be produced. Condensate liquid builds up near wellbore causing a reduction in gas permeability and gas productivity. In order to prevent the condensate formation in reservoir, different scenarios have been proposed in which the most important method is gas injection to maintain the pressure or to revaporize the condensed liquid. In other words, the injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point. This study prepared a comparison between gas injection scenarios in cells (PVT studies) and a synthetic model of the reservoir. The main goal of this work is to investigate the lean gas recycling into the PVT cell and the synthetic model to enhance condensate recovery. In this work, these subjects were studied: the effect of CO2, separator gas, and N2on condensate recovery enhancement and comparison of these scenarios with CO2, separator gas, and N2injection and discussion on why the results are different in these two approaches. This study shows that when CO2, separator gas, and N2are injected in PVT cell, deduction of condensed liquid during the pressure reduction of simulated constant volume depletion test at different injection volumes related to CO2is more than separator gas and separator gas scenario is more than N2. In other words CO2is the most effective and N2is the least effective scenarios in reduction of condensate in the simulated constant volume depletion. But in the synthetic model, the results are completely different with the simulated PVT cell. In the synthetic model, deduction of condensed liquid during the different injection volumes related to N2is more than separator gas and separator gas scenario is more than CO2. In other words N2is the most effective and CO2is the least effective scenarios in reduction of condensate in the synthetic model. Based on the type of condensate deduction mechanism, the three mentioned gases presented different results. N2acts as the best gas when the decrease of liquid dropout is aimed to evaporate existing since at the same injection rate for all injected gases, N2has increased the reservoir pressure more than the other gases and this reservoir pressure increase causes more re-vaporization at the synthetic model. In fact, the injection gas affects the decrease of liquid dropout formation indirectly. But if the injection gas affects directly on the reservoir fluid, CO2acts as the best injection gas regarding the reservoir composition change. In this mechanism, the injection gas affects the liquid dropout formation directly. [ABSTRACT FROM PUBLISHER]

Recycle-gas injection scheme is a promising recovery process to improve oil and gas production. This method uses continues injection of the produced gas at economical rates to keep the reservoir energy up and using viscous force as driving force. There are numerous studies in the availabale literatures done on recycle-gas injection in conventional reservoirs; however, little is known about implementation of this method in fractured reservoirs. The authors investigate the immiscible recycle-gas injection process in one of the Iranian carbonate naturally fractured reservoirs on a field scale. The real heterogeneous model was constructed and simulated by Eclipse-100 module as a dual porosity/dual permeability model. The effects of operational parameters, such as number and location of injection/production wells, production/injection rate, and completion interva,l on immiscible gas injection performance were evaluated and the result were compared with natural depletion method. It was found that in sensitivity with number of the wells, one injection-two production wells were the most efficient case. Also, oil well production rate of 200 SM3/day and well bottom-hole pressure of 75 bar provided higher oil recovery. Completing the production wells in matrix and injection wells in fracture has a better field oil efficiency in comparison to the other cases. The results showed that the substantial secondary oil recovery can be achieved using optimum conditions for immiscible recycle-gas injection in this reservoir. [ABSTRACT FROM AUTHOR]

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]

The authors present a new empirically derived correlation for estimating the minimum miscibility pressure (MMP) required for multicontact miscible (MCM) displacement of reservoir petroleum by hydrocarbon gas flooding. Only few empirical correlations exist for determining the MMP. These correlations are often used to estimate the MMP without considering the composition of the injected gas. On the other hand these correlations are based on a limited set of experimental data, which are not quite applicable. In addition, in such correlations the complex condensing/vaporizing displacement process is not regarded. In this study, however, the derived correlation investigates the influence of the vaporizing/condensing drive mechanism and oil and gas composition on gas miscibility pressure. MMP has been correlated with temperature, oil composition, and injection gas composition. Their effect on hydrocarbon gas MMP has been documented by using sensitivity analysis by slim tube experimental data. The new correlation is based on regression of widely experimentally measured MMP data in literature and data derived from slim tube experiment in this study. By comparing the calculated MMPs from the improved correlation data with currently used correlations and experimentally measured data, it was found that the new correlation is significantly more accurate than other correlations. [ABSTRACT FROM AUTHOR]

Gas-assisted gravity drainage (GAGD), solving the problem of low volume sweep coefficient for continuous gas injection (CGI) or water-alternating-gas injection (WAG) and increasing the ultimate recovery to a great extent, is a latest method for enhancing oil recovery. However, no effective predicting methods of oil recovery for GAGD exists. The oil recovery is determined by a set of parameters, such as heterogeneity of the formation, wettability, oil and gas density, oil and gas viscosity, viscous force, capillary force, gravity, gas injection rate, and other controllable parameters. Based on the research of producing mechanism of GAGD and dimensional analysis method, the authors analyzed four dimensionless varies, capillary number, bond number, gravity number, and gravity drainage number, and evaluated its influence on oil recovery. Considering the effect of wettability, viscosity ratio, and the difference between oil density and gas density, gravity number and gravity drainage number are modified. Relationship of gravity drainage number with recovery is re-established by experiments and case data. Finally a new predicting method of oil recovery for GAGD is set up. Application shows that this method is far more suitable for GAGD and its predictive result is more reasonable. [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]

A simple and applicable scaling equation as a function of pressure, temperature, molecular weight, dilution ratio (solvent), and weight percent of precipitated asphaltene has been developed. This equation can be used to determine the weight percent of precipitated asphaltene in the presence of difference precipitants (solvents) and the amount of solvent at onset point. Since increasing the pressure of crude oil decreases the amount of asphaltene precipitation, the effect of reservoir pressure has been taken into account in developing this equation. The results obtained by using this equation are substantially different and more accurate from other developed scaling equations for asphaltene precipitation. By considering the effect of reservoir pressure in developing the scaling equation and application of a genetic algorithm, the unknown parameters of the scaling equation are simultaneously and without any reservation obtained. The most important application of this unique equation is in the determination of critical point of asphaltene precipitation, known as onset point, and asphaltene precipitation in gas injection operations for enhanced oil recovery. The results predicted using the scaling equations are compared with the authors' experimental and literature precipitation data and it is shown that they are in good agreement with our experimental data. The scaling equation can be used in the design of gas-injected reservoir to prevent precipitation of the asphaltene aggregates in the reservoir. [ABSTRACT FROM AUTHOR]

With the nature ultra-low permeable cores from Changqing Oilfield, the simulated experiments of nitrogen drive after water flooding have been accomplished for the ultra–low-permeability reservoir. The injection pattern of nitrogen includes direct gas injection, water/gas alternating injection and pulse gas injection. The results show that direct injection could not develop the ability that nitrogen enters into the local tight area to improve the microsweep efficiency, because the good mobility generates gas channeling in some local high-permeable zone. Subsequent direct nitrogen injection after water drive only enhances the oil recovery ratio by 3.65%. The dispersion degree of oil, water, and gas is much higher for water/gas alternating injection after water injection, and the capillary force is the main resistance to suppress the rapid gas flow validly in local high-permeable zone. Nitrogen is enforced to drive the residual oil in local tight area or micro pore system. Water/gas alternating injection after water flooding enhances oil recovery ratio by 16.37%. Pulsing injection can take advantage of the elastic energy of the high-pressure nitrogen and pressure disturbance effect, which makes pressure redistribution and fluid deallocation between local high-permeability zone and local compact area. With pulse injection, oil in local tight region also can be driven by nitrogen, and the recovery ratio is enhanced by 15.94%. [ABSTRACT FROM AUTHOR]

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]

Miscible gas injection has been considered one of the most important enhanced oil recovery techniques. Minimum miscibility pressure (MMP) is a key parameter in the design of an efficient miscible gas injection project. This parameter is usually determined using a slimtube apparatus in the laboratory. However, many attempts have been made to introduce MMP predicting correlations. In this study an adaptive neuro-fuzzy inference system (ANFIS)–based correlation has been developed to estimate the MMP values. In this model, the MMP of reservoir fluid is correlated with 27 variables containing concentrations of different components in reservoir oil and injecting gas, molecular weight and specific gravity of C7+in reservoir oil and also reservoir temperature. This correlation can be applied to predict the effect of each individual parameter on the MMP values. [ABSTRACT FROM PUBLISHER]

This work has used a novel method for injection efficiency optimization following water flooding management. This method is based on individual streamline simulation ability to describe well allocation factor for injection and production wells. In addition, the well allocation factor can provide the amount of attributed fluid to each injector-producer pair and water loss amount, so it is possible to define injection efficiency. Optimization of injection efficiency is based on increasing the injection rates in efficient injectors and decreasing them in inefficient injectors. In this study, we used streamline simulation for injection efficiency and water loss optimization with the aim of increasing oil recovery. The current study includes two parts. Firstly, we identify well injection rates based on mathematical relationships and, secondly, we increase injection efficiency and oil recovery by decreasing water loss to the aquifer. By using this method and with the same amount of injected water, in the first and second part injection efficiency increased from 46 to 53% and 53 to 57%, respectively, in a 3-year simulation. It was determined that this method is suitable to identify and optimize injection rates, reduce water loss to the aquifer, and subsequently increase oil recovery. [ABSTRACT FROM PUBLISHER]

In this article, a coupled system model of differential equations was derived in radial form to predict the pressure, temperature of formation, and temperature of wellbore in high-temperature–high-pressure gas wells. In the model, the thermal effect of formation was simplified as heat conduction, both the steady heat transmission model in the gas wellbore and the unsteady heat conduction model in the formation were considered, and the pressure effect due to variations in temperature was considered according to the gas equation of state, which links the temperature with the pressure. The finite difference method was used to simulate the solutions of the coupled models. The basic data for X Well (high-temperature–high-pressure gas well, 7,100 m deep) in China were used for case history calculations and a sensitivity analysis was performed for the models. Graphs of the curves for gas pressure and temperature along the depth of the well were plotted with different gradients, injection volumes, and the characteristic of heat transfer in the formation. The results provide technical reliability in well test design in high-temperature–high-pressure gas wells and the dynamic analysis of production. [ABSTRACT FROM PUBLISHER]

Condensate loss is one of the major challenges in the gas condensate reservoirs. It results in a reduction of gas permeability and gas productivity. Different methods have been proposed to mitigate the condensate dropout and increase gas and condensate productivity. One of these techniques is gas recycling. Moreover, dry gases such as methane, nitrogen, and carbon dioxide are good candidates for this purpose. The authors investigate the effect of gas recycling and gas injection on an Iranian gas condensate reservoir. First, a literature review of the subject matter was carried out, followed by an introduction of the field. Afterward, steps performed for construction of dynamic model were described. Then, specified production scenario for development plan of the field was presented. A sensitivity analysis was carried out to determine the optimum number of additional wells to meet the target rate of the field. Consequently, injection scenarios including gas recycling, methane injection, nitrogen injection, and CO2injection at different injection rates were studied. Results indicated that nitrogen injection and gas recycling can improve recovery factor and plateau time rather than other cases. At high injection rates, gas recycling showed the highest condensate recovery (47%) among these scenarios. [ABSTRACT FROM PUBLISHER]

CO2injection is a potentially viable method of enhanced oil recovery for medium oil reservoirs. The authors compare the effect of gas injection strategy (simultaneous water-alternating gas [SWAG], water-alternating gas [WAG], and continuous gas injection [CGI]) on recovery in immiscible, near-miscible, and miscible modes of injection. It has been proved that CGI is not the most efficient injection scenario in oil-wet reservoirs. Miscible and near-miscible core flood tests demonstrated high oil recoveries in all injection strategies due to high capillary numbers achieved as a result of miscibility. The fluid mechanics of floods were discussed using pressure drop data, different mechanics was observed for SWAG, WAG, and CGI and better mobility control of SWAG was proven. Results show that tapering postponed gas breakthrough and less amount of gas was injected using this technique, making tapering favorable economically and operationally. Experiments with different gas–water ratios were performed and the results show that the ultimate oil recovery during SWAG injection is almost independent of gas–water ratio. This makes SWAG injection a promising recovery process especially for reservoirs where continuous and high-rate gas injection is not possible. [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]

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]

Asphaltene deposition is a serious problem that can cause fouling in the reservoir, well, pipeline, and the oil production and processing facilities. An association equation of state (AEOS) is one of the most useful models used to predict asphaltene phase behavior and asphaltene deposition conditions. For an AEOS, it is assumed that the total compressibility factor consists of physical and chemical parts. The authors apply the conventional form of compressibility factor developed by G. Soave (1972) to the physical compressibility factor. However, for the chemical compressibility factor a new form is proposed. The total compressibility factor obtained is then used to calculate the asphaltene and resin deposits. The amounts of deposited asphaltenes calculated through the proposed model along with the experimental results are used to calculate resin deposit. A comparison with the experimental results shows that the new proposed model can be used to predict the amounts of deposited resins and asphaltenes within an acceptable range of accuracy. [ABSTRACT FROM PUBLISHER]

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]