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This paper employs computational fluid dynamics (CFD) simulations with an eddy dissipation concept model (EDC) and a skeletal reaction mechanism (SK17) to analyze the impact of hydrogen addition on the premixed combustion mode of producer gas (PG) fuel in a cyclonic flow combustion chamber. The results, validated against measured wall temperature data, demonstrate a minor discrepancy between simulation and experiment. The studied result showed that injection of hydrogen into PG fuel combustion elevates the temperature of the combustion process, which can be indicated by the average temperature across the combustion chamber, outlet temperature of exhaust gas, and reactive radical species. However, increasing H2 injection over 20% results in strongly increasing CO formations. Compared to a fixed thermal input case, hydrogen injection with a variable input power resulted in a higher combustion temperature and increased emissions of both CO and NO. The maximum CO emission reached approximately 1246 ppm, while NO peaked at around 75 ppm, both observed at a 30% hydrogen injection rate. The key finding of this study revealed that direct injection of hydrogen to the combustion under the condition of a given equivalence ratio is unfavorable due to insufficient oxygen for the reaction, leading to an increase in CO emissions. The optimal condition would be a hydrogen injection below 20%, which produces low CO and NO emissions. [ABSTRACT FROM AUTHOR]

Coal bed methane (CBM) is a gas resource associated with and symbiotic with coal, which refers to the hydrocarbon gas stored in the coal seam, with methane as the main component, which belongs to unconventional natural gas. The development and utilization of CBM has the effect of achieving multiple things in one fell swoop: clean energy, commercialization can produce huge economic benefits. At present, rod pump, screw pump and other lifting technologies commonly used in CBM drainage and production have poor adaptability, short pump inspection period, and it is difficult to enter horizontal section in horizontal well. Aiming at this problem, a new method of efficient CBM lifting is proposed by adopting dual-pipe gas lift technology. In this paper, the basic principle of double tube gas lift is analyzed, the optimization design of gas injection volume, coiled tubing size and coiled tubing running depth is carried out, and the field technology application of vertical and horizontal Wells is carried out. The results show that the dual tube gas lift technology has good adaptability in the deliquification of CBM, and the field application has achieved good production results. After the process modification, gas production of CBM Wells increases continuously, while water production decreases gradually, with the maximum gas rate exceeding 2400 m3/d. According to the latest production data, well L31 has been in steady production for more than 9 months, with an average gas rate of 1294.56 m3/d, which greatly exceeds the capacity before the transformation. Because there are no moving parts in the wellbore, the pump inspection period is greatly improved, and it has the potential to be widely applied in CBM. [ABSTRACT FROM AUTHOR]

Tight glutenite reservoir in Mahu area are usually put into production by volume fracturing of horizontal wells. In the process of production, there are some problems such as rapid production decline, low recovery factor, and so on. Therefore, experimental study of natural gas flooding to improve the recovery of tight glutenite reservoir was carried out. Using cores of different diameter sizes from the target interval of the target area, the whole development process of different gas injection speeds and different development methods is simulated by the core displacement devices with high temperature and high pressure resistance. The characteristics of exhaustion, displacement, development effect, and action mechanism were evaluated and analyzed systematically. The study shows that the better the physical properties of the tight glutenite, the higher the recovery degree of the exhaustion development. As the pressure is reduced from 55MPa to 10MPa, the recovery degree can reach about 6%. Natural gas flooding after exhaustion can greatly improve oil recovery. The results of laboratory experiments show that the recovery efficiency of natural gas flooding after depletion can be improved by 38%–62%. The higher the gas injection rate is, the lower the final recovery rate is. With the displacement velocity increasing from 0.02 ml/min to 0.1 ml/min in laboratory experiments, the corresponding ultimate recovery rate decreased from 67.03% to 44.67%. Therefore, field operations need to control the gas injection rate to ensure higher gas flooding recovery. According to the experimental results of natural gas flood-soaking-natural gas flooding, the final recovery is 38.54% under miscible condition. The recovery of gas flooding stage before soaking is 27.97%. Compared with natural gas flooding, the oil displacement efficiency can be improved by nearly 10% in the development mode of natural gas flooding-soaking-natural gas flooding, which is due to its mechanism including the following three stages. First is near-miscible flooding which plays a role in intergranular pores, micro-fractures, and pressure fractures in the gas flooding stage before soaking. Second is miscible dissolution replacement which plays a role in intergranular dissolved pores in the soaking stage. Third is gas carrying oil recovery which plays a role in pressure fractures in the gas flooding stage after soaking. Finally, the development mode of natural gas flooding-soaking-natural gas flooding can achieve enhanced tight glutenite recovery. [ABSTRACT FROM AUTHOR]

The coal body's gas environment transforms during the CO2 fire prevention procedure from an oxygenated ambience to a CO2 gas ambience, which in turn prevents the coal body from continuously oxidizing. To investigate the effect of sudden changes in the gas environment to which the coal body is exposed on the microscopic group reactions, the free radical parameters such as ESR in situ spectra, line widths, g-factors, and free radical concentrations of the coal bodies during the gas atmosphere transition at different temperature moments were measured. The findings are as follows: as the injection temperature point for CO2 rises, the spectral peak height increases, and the paramagnetic center of coal shifts at lower temperature in CO2 atmosphere than in dry air atmosphere. After the abrupt change of gas environment, free radical levels first decrease and subsequently rise. Furthermore, the general development rate of free radicals can be slowed down by injecting CO2 at lower temperatures. Meanwhile, at lower temperatures, the higher the temperature point of the minimum g value is, the smaller the maximum g value is. Changes in a gas atmosphere, sudden decrease in line width of ESR spectra of coal bodies, and the line width finally stabilizes around 0.45. CO2 injection at 70°C has the best inhibitory effect on free radicals. [ABSTRACT FROM AUTHOR]

During lean gas reinjection after depletion in high-pressure and low-permeability reservoirs, the fluid composition in the formation changes greatly, the microscopic interaction process among fluids is complex, and the microscopic mechanism of lean gas flooding is not clear to us. In this article, the microscopic experiments were carried out in high-temperature and high-pressure micro-visualization experiment apparatus of independent research and development. The microscopic interaction process between lean gas and formation fluid before and after depletion was studied on the porous models made of glass by etching. The flow law of lean gas after depletion and the mechanism of microscopic oil displacement were discussed. The results from experiments conclude that lean gas flooding should alleviate the Jamin effect caused by gas separated from oil during depleted production. Under the reservoir conditions, the oil is produced by lean gas displacement force primarily, by lean gas extraction for auxiliary. The water barrier prevents the contact between lean gas and residual oil. In unswept areas of lean gas, the residual oil is difficult to be produced as the poor diffusion of lean gas through water barrier into residual oil. While in swept area, lean gas can peel off water film gradually, then contact with residual oil directly, and then drive out oil by dissolving and extracting. Lean gas flooding in high-pressure and low-permeability reservoirs can enhance oil recovery further after depleted production. [ABSTRACT FROM AUTHOR]

During the cyclic gas injection of gas condensate reservoir with bottom or edge water, complicate phase changes and energy conversion take place. A new calculation model for condensate oil saturation is established based on the principle of volume conservation. Moreover, the calculation model considers the influencing factors such as retrograde condensation, connate water evaporation, elastic expansion of reservoir rocks, and external dynamic water invasion. Combining the reservoir fluid property and dynamic production data, this model can calculate the condensate oil saturation under different reservoir pressures quickly. The Case study shows that the condensate oil saturation obtained by this model coincides with the indoor depletion experiment and reservoir numerical simulation. Meanwhile, the sensitivity evaluation of the above influencing factors is carried out. Furthermore, the factors impacting the calculated results from high to low are external dynamic water invasion, elastic expansion of reservoir rocks and connate water evaporation. [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]

The methane from two coal seams are usually produced in the same production well, and the commingled production process is of low efficiency. In order to enhance the methane recovery from the two coalbeds, a 'multi-branch U-shaped' well is introduced to double-coal seams. This well structure can perform a single layer or commingled production. There are at least 10 production methods for the new well: (1) Drainage gas recovery of upper coal seam, (2) gas injection huff and puff of upper coal seam, (3) gas injection displacement of upper coal seam (including continuous gas injection or intermittent gas injection), (4) drainage gas recovery of lower coal seam,(5) gas injection huff and puff of lower coal seam, (6) gas injection displacement of lower coal seam (including continuous gas injection or intermittent gas injection), (7) drainage gas recovery of both coal seams, (8) gas injection huff and puff of upper coal seam and drainage gas recovery of lower coal seam, (9) gas injection huff and puff of lower coal seam and drainage gas recovery of upper coal seam, and (10) gas injection displacement of both coal seams. Meanwhile, five production strategies are investigated by simulations with reference to the special well structure. Combined with the coalbed methane field operation, the well is conducive to carbon dioxide huff and puff, the optimized production strategy is: water drainage in the early period, and carbon dioxide huff and puff at middle-late stages of development. The new well structure can greatly improve CBM recovery. [ABSTRACT FROM AUTHOR]

In the soft coal seam with ultra-low permeability, the effect of permeability enhancement by hydraulic fracturing or stress relief methods is not ideal due to the closure of fractures. Injecting foreign gas into the coal seam can replace part of the gas adsorbed in the coal matrix and drive the coal seam gas to the drainage borehole, so as to achieve the purpose of promoting gas drainage. In this paper, we established a fluid-geomechanics coupling model for the high-pressure air injection promoting gas drainage. This mathematical model contains governing equations of ternary gases competitive sorption and transport, and deformation response of coal material, reflecting the interactions among gas mixtures and coal seam. The model is solved by the finite element method to simulate the high-pressure air injection promoting coal seam gas drainage through floor roadway drillings in studied Coal Mine. The gas pressure of CH4, N2 and O2 is comparatively analyzed, and the effective drainage area is obtained. It is confirmed that the air injection can enhance gas drainage by the competitive adsorption and pushing effect. Meanwhile, numerical simulations are carried out to optimize the borehole arrangement. When the operation continues 120 days, the effective areas in studied case are 10.1, 11.23, 11.35, and 6.23 × 103 m3 for borehole spacing of 6 m, 8 m, 10 m and 12 m respectively. The borehole spacing of 10 m is the optimal arrangement in the studied case, owing to its greater effective drainage volume and fewer boreholes. These provide a foundation for guiding the operation of air injection promoting coal seam gas drainage in the field. [ABSTRACT FROM AUTHOR]

Gas injection is an effective way to enhance methane drainage in a low permeability coal seam, and the reasonable distance between injection holes and drainage holes depends on effective influence distance of injection gas in a coal seam. For anisotropic permeability of coal seam, the variation of the gas-flow rate from a test hole in the anisotropic coal seam is measured as nitrogen is injected into the injection hole near the test hole. The effective distance regularity is revealed by nitrogen injection in an anisotropic coal seam, and the model of nitrogen injection is established to numerically analyze the aging characteristic of effective influence distance in the anisotropic coal seam. The results show that the permeability in coal seam reduced exponentially with the increase in gas pressure, and it is larger in the direction of parallel to bedding than that in the direction of perpendicular to bedding. The effective distance with nitrogen injection increased exponentially in the direction of parallel/perpendicular to bedding, and the effective distance in the direction of parallel to bedding is bigger than that in the direction of perpendicular to bedding. The optimum distances between injection hole and test hole, with 0.5 MPa of injection gas pressure and 8.36 h of injection gas time, are 2.05 m in parallel to bedding direction, and 1.53 m in perpendicular to bedding direction. This study will have important theoretical and practical significance for a reasonable layout of injection-drainage holes during injecting gas to enhance methane drainage. [ABSTRACT FROM AUTHOR]

In petroleum reservoirs, estimation of the rate of mass transfer caused by molecular diffusion is necessary for determining the amount of gas diffusing into oil in gas injection projects. The key parameter for calculating the mass transfer rate is diffusion coefficient of gas into oil. Hence, in enhanced oil recovery projects, the knowledge of this key parameter for designing the injection projects is essential. Oil swelling is a common phenomenon that is observed in gas injection projects and should be taken into consideration for modeling of diffusion process in enhanced oil recovery projects. Mathematical modeling is a good tool, which may help in predicting this parameter. In this study, an attempt has been made to develop a mathematical model for predicting the gas diffusion coefficient for the system in which the gas is injected into oil through a water-blocking film. The model equation has been solved with appropriate initial and boundary conditions to obtain a series of type curves similar to those that are used in well testing. The results are classified in two groups, oil and water phases, and are presented in dimensionless form. The effect of swelling varies with the variation of the Peclet number. It may be concluded that, by increasing the Peclet number, the role of convection mechanism is more prominent. [ABSTRACT FROM PUBLISHER]

Continuous gas injection (CGI) in the conventional horizontal flooding patterns leads to severe gravity segregation and poor reservoir contact (sweep) volumes. To improve the sweep efficiency, the Water-Alternating-Gas (WAG) process has been widely practiced in the industry. However, the WAG process has not measured up to expectations, as evidenced by the low recoveries observed in several field cases. The Gas-Assisted Gravity Drainage (GAGD) process is designed and practiced based on gravity drainage idea and uses the advantage of density difference between injected gas and reservoir oil to overcome the drawbacks of the WAG process. In this study, a comparison of enhanced heavy-oil recovery by three methods (CGI, WAG, and GAGD) is conducted by a commercial numerical simulator in a sector model of an Iranian offshore field. For this purpose, different production scenarios are designed. Moreover, the effect of several parameters such as injection fluid (CO2, hydrocarbon gas), in situ oil viscosity (heavy or extremely heavy oil), rate and volume of injection, and also three different WAG ratios are studied. The results show that the GAGD method is not suitable for this field as the thickness of pay zone is low for vertical sweep efficiency and causes early breakthrough of injected gas. Also, CGI leads to lower recoveries compared to the WAG process, due to its unfavorable mobility ratio. Injection of CO2instead of hydrocarbon gas results in higher sweep efficiency because of its viscosity reduction and swelling effects. In case of extremely heavy-oil recovery, with decreasing well spacing, the oil recovery factor increases as the drainage radius of wells reduces substantially due to high-viscosity oil. [ABSTRACT FROM AUTHOR]

Asphaltene deposition is one of the problems that oil industries face during oil production, processing, transport, and refining. Deposition of asphaltene flocculation on reservoir rock can plug pore spaces and cause permeability impairment. Carbonate rock, which has low permeability, tend to adsorb asphaltene causing more loss of permeability. In this study, three miscible CO2injection core tests were conducted at reservoir conditions and the effects of asphaltene content on the amount of formation damage in carbonate cores with low permeability were investigated. High asphaltene content oil has been used in the experiments. Results show that permeability reduction was more than porosity losses. An empirical model for permeability impairment was derived based on experimental data by considering the activation of the two mechanisms simultaneously. The results may be useful for understanding permeability impairment mechanisms during gas injection in low-permeability carbonate cores. [ABSTRACT FROM PUBLISHER]

The study of asphaltene deposition under actual field conditions is impossible. Therefore, many models have been derived based on experimental data. All models have some matching parameters, which are estimated along with numerical solving or simulation to match experimental and simulation data, so it is possible that these were estimated as required (tuning factor). In this study, two miscible CO2injection dynamic tests in porous media were performed. In these tests, CO2and live oil were injected into the core simultaneously. The CO2concentration was more than the onset concentration for asphaltene precipitation. The main objective of this work was to determine the deposition coefficients from the experimental data, so these were predicted by using basic equations using the material balance. Also, by mathematical methods, the relation between these parameters was determined. Results from this work imply that the deposition parameters can be estimated from the experimental data and these parameters are not constant during modeling and simulation. [ABSTRACT FROM PUBLISHER]

The Western North Slope of Alaska is an oil-rich zone located in the Colville river unit close to the Eastern boundary of National Petroleum Reserve Alaska. With an objective to find better enhanced oil recovery solutions and improve recoveries, four reservoirs from the Western North Slope were screened for different enhanced oil recovery methods to find the most suitable option. Based on the initial screening, gas injection was found to be the preferred method. This was followed by the determination of optimum injection gas compositions for Western North Slope reservoirs and their rank, thereby developing a new ranking methodology for gas flooding projects. The work was accomplished via a combination of two custom developed Excel spreadsheets for the determination of minimum miscibility pressure and enrichment respectively and several numerical experiments carried out using a compositional reservoir simulator, the results of which were applied for parametric ranking of the four Western North Slope reservoirs. [ABSTRACT FROM PUBLISHER]

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]

Gas condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottom-hole pressure declines below the dew point pressure. Pressure maintenance and gas cycling are the common practices used in the oil and gas field to alleviate this problem and develop gas condensate reservoirs. The injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point. This article investigates the situation of one of the reservoirs located in southern Iran in Zagros area. First, based on the reservoir composition, the phase diagram has been plotted. Peng–Robinson equation of state for the equilibrium calculations and Lee–Kesler characterization of heavy fractions are used in this software. After that the effect of nitrogen, pure methane, a composition of ethane and methane, and carbon dioxide injections on reservoir recovery has been investigated and compared to a natural depletion scheme. The full system, including two separators and a stock tank, are simulated simultaneously and the effect of each type of injection on the liquid and gas production is investigated. Full mixing has been assumed in all of the injections studied. By comparing between the results it is concluded that in an injection process, required injection rate to maintain reservoir pressure above dew point pressure and avoid liquid formation in the reservoir for pure methane, a composition of ethane and methane, pure nitrogen and carbon dioxide, and liquid recovery in all cases are investigated. According to the results, with increasing ethane mole percent in the injecting gas a lower injecting rate for the same liquid recovery is needed. Because with increasing heavy components mole percent in injecting gas, average molecular weight of injecting gas, and reservoir gas becomes closer and there will be a better mixing between them and, therefore, liquid recovery will be improved. Thus, a composition of ethane and methane with more ethane mole percent is better than others. [ABSTRACT FROM PUBLISHER]

An attempt is made to model a gas lift allocation problem as a nonlinear optimization form with a wide range of constraints covering deficiencies carried out by past studies. In this article, a rigorous nonlinear ‎programming approach is used to maximize daily cash flow of a group of production wells under ‎gas lift operation. First, an appropriate model is prepared for gas lift performance curve of each well by use of nonlinear logarithmic and polynomial regression. Afterward, a model is constructed and solved for daily cash flow under capacity and pressure constraints. Results show a significant increase in cash flow for an optimized case compared with the current gas allocation plan. Moreover, sensitivity analysis was performed for different variables showing that oil price and compressing cost must be considered in long-term gas lift allocation optimization. [ABSTRACT FROM PUBLISHER]

In this article a series of experiments were performed to demonstrate the effect of carbon dioxide injection pressure on a huff and puff process. The experimental data are used in a lab-scale model simulated with a commercial simulator to investigate the effect of soaking time, injection pore volume, and rate of injection on the heavy oil recovery. The result of experiments showed that a huff and puff process under miscible pressure conditions gives the most recovery. Simulation results illustrated that there is an optimum value for soaking time, which, for soaking times less than this value, recovery increases and for values greater than optimum the recovery decreases. The simulation study demonstrated that oil recovery increases with increasing volume of injected miscible fluid and recovery decreases with injection rate increase. [ABSTRACT FROM AUTHOR]

One of the most commonly used artificial lift methods in the petroleum industry is continuous gas lift. In continuous gas lift, gas at suitable pressure is injected in an appropriate depth into the tubing to gasify the oil column and, thus, facilitate the production. In gas lift, by increasing the gas injection rate into the well, the oil production rate enhances. At a point that is an optimal point of the well, by increasing gas injection rate, the oil production rate declines. At this point, the well produces the most oil. If there is no limitation in the total amount of available gas, a sufficient amount of gas could be injected into each well to get the maximum amount of production. However, often the total amount of available gas is insufficient to inject enough gas to an optimal point of each well and to reach the maximum oil production for each well. Therefore, allocating an optimum amount of gas to each well to obtain the field maximum oil production rate is necessary. In this work, a hybrid genetic algorithm was used to allocate the optimum amount of gas to a group of wells for three fields with a different number of wells. Based upon the fields' oil total production rate resulted from the gas allocation to the wells, the hybrid genetic algorithm shows better gas allocation to the wells in comparison with previous works with other methods. [ABSTRACT FROM PUBLISHER]

A series of reservoir condition experimental studies are presented that investigate the effects of oil production by water drive on the success of subsequent oil production by gas-oil gravity drainage in a fractured laboratory model. The experiments were performed using low permeable, oil-wet carbonate core samples. During this work, injection of N2gas followed by steam into the fracture was studied using two different scenarios: initial oil place at connate water saturation condition utilized for secondary oil recovery, and water flooded cores at residual oil saturation for tertiary oil recovery. The result showed that the water invasion into the fractures reduces oil production potential, and it is shown that the ultimate recovery for secondary gas injection is considerably higher than tertiary gas-oil gravity drainage for both isothermal and non-isothermal tests. Steam injection into the fractured model leads to twice more oil recovery than the preceding isothermal recovery. The results confirmed that the key oil production mechanism during non-isothermal gas-oil gravity drainage that initiates the main phase of oil production is heat transfer into the matrix blocks and viscosity reduction. In addition, results of contact angle measurements showed that wettability of the oil wet rocks after steam flooding was shifted to neutral wet condition that increase gravity drainage performance. [ABSTRACT FROM AUTHOR]

When the reservoir energy is too low for the well to flow, or the production rate desired is greater than the reservoir energy can deliver, using some kind of artificial lift method to provide the energy to bring the fluid to the surface, seems to be necessary. Continuous flow gas lift is one of the most common artificial lift methods widely used in the oil industry during which, at appropriate pressure, gas is injected in a suitable depth into the tubing to gasify the oil column, and thus assist the production. Each well has an optimal point at which it will produce the most oil. In ideal conditions, at which there is no limitation in the total amount of available gas, a sufficient amount of gas could be injected into each well to get the maximum amount of production. However, often the total amount of available gas is insufficient to reach the maximum oil production for each well. Therefore, allocating an optimum amount of gas to each well to obtain field maximum oil production rate is necessary. In this work, a continuous ant colony optimization algorithm was used to allocate the optimum amount of gas to a group of wells for three fields with a different number of wells. Based upon the total production rates of the studied oil fields resulting from the gas allocation to the wells, the continuous ant colony optimization algorithm shows better gas allocation to the wells in comparison with the previous works with other optimization methods. [ABSTRACT FROM PUBLISHER]

This article presents a method for optimizing and controlling an oil production system using a natural gas lift concept. Ever increasing development of Smart Well technology and various applications of down-hole monitoring and controlling instruments along with new methods of data acquisition/transmission make it possible for the natural gas lift system to be controlled and optimized more effectively and faster than before. With this technology it is possible to monitor the down-hole conditions of gas and oil zones and to control the inflow valves in gas and oil zones. In this work, a proportional integral differential feedback controller has been used to smartly control the entrance of gas from the gas zone to the oil well. The optimizer determines the optimal values of gas injection setpoint for the controller to manipulate the inflow of gas to the oil reservoir. The problem will be more complex when the available gas in the gas zone is limited. The optimization of this process has been done by a Differential Evolution method. [ABSTRACT FROM PUBLISHER]

The use of water-alternating-gas injection can potentially lead to improved oil recovery from the fields; simultaneous water and gas injection is a form of water-alternating-gas injection. However, there is still an incomplete understanding of these processes and the need for comparative work is inevitable. Core flood experiments and compositional simulations of water-alternating-gas and simultaneous water and gas processes are presented. Immiscible, near miscible, and miscible modes of injection are covered. Matching process is done and optimization of design parameters (injection rate, slug size, water-alternating-gas ratio, and injection gas) is performed. Experimental data demonstrate that simultaneous water and gas injection accelerate oil production as compared to water-alternating-gas injection in all modes of injection, and miscible simultaneous water and gas injection with CO2produces more than 74% of original oil in place. The simulation results indicate that with different water-alternating-gas ratios (water/gas volumetric) the ultimate oil recovery during simultaneous water and gas injection in operational range (water-alternating-gas ratios between 0 and 2) is almost independent of water-alternating-gas ratio. [ABSTRACT FROM PUBLISHER]

In this article, using the high-temperature and high-pressure pressure, volume, and temperature experimental equipment to simulate the CO2extraction process of the crude oil, the effects of pressure and gas injection volume on extraction, and the extraction effects on oil properties were studied by measuring the CO2volume extraction ratio as well as the composition and viscosity of the oil. The experimental results show that the CO2extraction ratio increases with the increase of the pressure and the CO2can enhance the oil recovery by 59.3% through the extraction under the pressure of 46 MPa. At the same pressure, the CO2extraction ratio is 5–10 times as large as that of the hydrocarbon gas. The heavy component content and viscosity of both extracted oil and residual oil after the extraction increase as the pressure increases, meanwhile the extracted oil viscosity is smaller than that of the original oil, and the residual oil viscosity can reach 10 times as large as that of the original oil. Within the experiments, as the CO2injection volume increases, the extraction ratio of the oil increases slightly, and the composition and viscosity of the extracted oil remains basically unchanged, but the heavy component content and viscosity of the residual oil increase greatly. The viscosity can reach 8.3 times as large as that of the original oil. Thus, it can be seen that when the CO2injection volume is bigger than that of the oil, the increase of it has a very limited effect on the extraction ratio, but can make the residual oil viscosity increase greatly. [ABSTRACT FROM PUBLISHER]

Due to the lack of any significant primary recovery mechanism in one of the Iranian oil reservoirs, enhanced oil recovery methods are considered for early stage application because it has been depleted rapidly about 200 Psig by primary recovery. Therefore, the objective of this study was to experimentally investigate the performance of water alternating gas injection of this field. Core samples were drilled out of reservoirs' rock matrix and were cut approximately 11–15 cm long and 3.28 cm in diameter. The live oil used in the experiments has been made by recombination of the stock tank oil with a synthetic gas mixture. All coreflood experiments were conducted using live (recombined) oil at 1,700 psig and a reservoir temperature of 115°F. A total number of four displacement experiments were performed on the cores, including two experiments on secondary wag alternation gas injection and others on tertiary water and gas invaded zones wag alternation gas injections. Prior to each test porosity and permeability of dried core were calculated then 100% water-saturated core was oil flooded to obtain connate water saturation. Therefore, all coreflooding tests started with the samples at irreducible water saturation. These experiments showed that there was significant improvement in the oil recovery for alternating injection of water and CO2. Thus, this method could be suggested as one of the enhanced oil recovery methods for this field with consideration of the economical studies. This laboratory study investigates the potential effectiveness of wag alternation gas injection for recovering hydrocarbons from target reservoir as it would exist in one of these conditions: after naturally depleted as secondary recovery, after waterflooding and gasflooding as tertiary recovery. All of the experiments were conducted at 115°F and 1,700 psig, which represents a low-temperature and low-pressured reservoir with 5,000 ppm brine salinity. The most similar experimental work with the main reservoir condition indicated that approximately 64% oil was recovered after 1 pore volume of wag alternation gas process at 136,000 ppm brine salinity. Tertiary oil recovery efficiency resulting from wag alternation gas injection was significant, leading to final pore volume injected, 50 and 36 for gas and water invaded zones, respectively. [ABSTRACT FROM PUBLISHER]