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1.
Some of Iranian oil reservoirs suffer from operational problems due to asphaltene precipitation during natural depletion, so widely investigation on asphaltene precipitation is necessary for these reservoirs. In this study, a reservoir that is candidate for CO2 gas injection process is selected to investigate asphaltene precipitation with and without CO2 injection. In this case, asphaltene precipitation is monitored at various pressures and reservoir temperature. Then, a series of experiments are carried out to evaluate the amount of precipitated asphaltene by injection different molar concentrations (25%, 50%, and 75%) of CO2. The results show that during primary depletion the amount of precipitated asphaltene increases with pressure reduction until bubble point pressure. Below the bubble point the process is reversed (i.e., the amount of precipitated asphaltene at bubble point pressure is maximum). The behavior of asphaltene precipitation versus pressure for different concentrations of CO2 is similar to primary depletion. Asphaltene precipitation increases with CO2 concentration at each pressure step. In the modeling part, solid model and Peng-Robinson equation of state are employed which show a good match with experimental results.  相似文献   

2.
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 N2 gases 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.  相似文献   

3.
Abstract

Sudden changes in key parameters such as pressure, temperature, and fluid composition may result in asphaltene precipitation and deposition, consequently reducing permeability and porosity as well as well injectivity and productivity. Sandstone cores of an Iranian reservoir were studied under high pressure and temperature. Asphaltene deposition was studied in recycled gas injection, CO2 injection, and natural depletion experiments. The authors observed that these processes could be ranked for the deposition severity viewpoint in the aforementioned order. Qualitatively investigation of cores indicated nonuniform deposition of precipitated asphaltene along a flooded core and reducing deposition from entering core terminal to the core outlet.  相似文献   

4.
Abstract

Natural depletion of petroleum reservoirs as well as gas injection for enhance oil recovery, are unavoidable processes in the oil industry. Foremost, prediction of the problems due to these two processes is very necessary and important. So many field and experimental experiences have shown that heavy organic depositions, especially asphaltene deposition, are principal results during these processes. Results of laboratory simulation of asphaltene deposition during the natural depletion of petroleum reservoirs and also during gas injection and enhanced oil recovery (EOR) processes are reported here. This is achieved through the design of a new experimental setup for the investigation of pressure and composition effects on asphaltene deposition in petroleum fluids at high pressure and high temperature conditions. In this work, asphaltene deposition during decreasing pressure, from pressures greater than reservoir pressure to pressures below the bubble point pressure (natural depletion) and also asphaltene deposition during natural gas injection in reservoir conditions, are studied for three samples—one recombined sample and two bottomhole samples. All of the obtained results from this work conform to theoretical and other experimental works.  相似文献   

5.
Reservoir oil and gas content tends to rise up to the surface as long as their potential energy levels are sufficient. In order to amplify this energy, either during the time when oil is uprising on its inherent energy or since after, so as to facilitate the traveling of oil to the surface, enhanced oil recovery (EOR) methods come into play. Furthermore, the increasing demand for oil from one hand, and the shrinkage of producible reserves on the other hand, have made it unavoidable to undertake EOR techniques. Built in this research was a 10-element model of reservoir fluid to simulate its behavior. Furthermore, slim tube simulation was undertaken to determine minimum miscibility pressure for various gases. Then, different scenarios of natural depletion, CO2 injection, methane injection, and water injection were simulated by ECLIPSE 300 software package with the results of different scenarios compared. The results indicated water injection to be associated with higher recovery factor.  相似文献   

6.
Abstract

In this work, a thermodynamic approach is used for modeling the phase behavior of asphaltene precipitation. The precipitated asphaltene phase is represented by an improved solid model, and the oil and gas phases are modeled with an equation of state. The Peng-Robinson equation of state (PR-EOS) was used to perform flash calculations. Then, the onset point and the amount of precipitated asphaltene were predicted. A computer code based on the solid model was developed and used for predicting asphaltene precipitation data reported in the literature as well as the experimental data obtained from high-pressure, high-temperature asphaltene precipitation experiments performed on Sarvak reservoir crude, one of Iranian heavy oil reserves, under pressure depletion and CO2 injection conditions. The model parameters, obtained from sensitivity analysis, were applied in the thermodynamic model. It has been found that the solid model results describe the experimental data reasonably well under pressure depletion conditions. Also, a significant improvement has been observed in predicting the asphaltene precipitation data under gas injection conditions. In particular, for the maximum value of asphaltene precipitation and for the trend of the curve after the peak point, good agreement was observed, which could not be found in the available literature.  相似文献   

7.
Asphaltene precipitation is a major problem during primary oil production and enhanced oil recovery in the petroleum industry. In this work, a series of experiments was carried to determine the asphaltene precipitation of bottom hole live oil during gas injection and pressure depletion condition with Iranian bottom hole live oil sample, which is close to reservoir conditions using high pressure-high temperature equilibrium cell. In the majority of previous works, the mixture of recombined oil (mixture dead oil and associated gas) was used which is far from reservoir conditions. The used pressure ranges in this work covers wide ranges from 3 to 35 MPa for natural depletion processes and 24–45 MPa for gas injection processes. Also, a new approach based on the artificial neural network (ANN) method has been developed to account the asphaltene precipitation under pressure depletion/gas injection conditions and the proposed model was verified using experimental data reported in the literature and in this work. A three-layer feed-forward ANN by using the Levenberg-Marquardt back-propagation optimization algorithm for network training has been used in proposed artificial neural network model. The maximum mean square error of 0.001191 has been found. In order to compare the performance of the proposed model based on artificial neural network method, the asphaltene precipitation experimental data under pressure depletion/gas injection conditions were correlated using Solid and Flory-Huggins models. The results show that the proposed model based on artificial neural network method predicts more accurately the asphaltene precipitation experimental data in comparison to other models with deviation of less than 5%. Also, the number of parameters required for the ANN model is less than the studied thermodynamic models. It should be noted that the Flory and solid models can correlate accurately the asphaltene precipitation during methane injection in comparison with CO2 injection.  相似文献   

8.
Abstract

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.  相似文献   

9.
Miscible CO2 injection process has become widely used technique for the enhanced oil recovery in low permeability reservoirs. Core flooding experiments and field test of CO2 miscible flooding in low permeability sandstone reservoirs and its influence on crude oil properties was studied. The results showed that CO2 miscible flooding in low permeability sandstone reservoirs can enhance oil recovery both in laboratory study and field test. The permeability of sandstone reservoirs decreased during CO2 miscible flooding due to the precipitation of asphaltene of crude oil. The precipitation of asphaltene lead to a reduction of asphaltene content and the apparent viscosity of crude oil. A further study on inhibitors and removers for asphaltene deposits from crude oil should be investigated to prevent and remove asphaltene deposits in low permeability sandstone reservoirs.  相似文献   

10.
Abstract

Among all enhanced oil recovery (EOR) scenarios, gas injection seems to be promising for implementation in naturally fractured reservoirs. The use of CO2 has received considerable interest as a method of EOR but a major drawback is its availability and increasing cost. Therefore, an alternative gas like CH4 or N2 must be considered to meet the economic considerations. To investigate the efficiency of oil recovery by CO2, N2, and CH4 injection in fractured carbonate rock, a series of experiments was designed. Both miscible and immiscible schemes for gas injection were carried out on a low-permeable outcrop carbonate rock that was surrounded by fracture, established with a novel experimental method. The experiments aimed to investigate the potential of oil recovery by secondary and tertiary gas injection under high-temperature conditions. The matrix block was saturated using a recombined mixture of Iranian live oil, and by pumping water into the annular space, the space between rubber sleeve and outer jacket, high overburden pressure was exerted to obtain the desired homogeneous saturation. Using a back-pressure regulator, the pressure was kept above the bubble point pressure. The inlet was attached to a constant pressure pump injecting gas or water above the bubble point pressure, and the overburden pressure was removed gradually and the inlet fluid inflated the rubber sleeve. The amount of produced water from the annular space was recorded to estimate the distance between the rubber sleeve and sand face. This distance creates the fracture surrounding the core. Gas was injected into the fracture at pressures above the bubble point of the oil. Oil recovery as a function of time was monitored during the experiments. Results from both secondary and tertiary gas injection experiments indicate that CO2 injection at elevated pressure and temperature is more efficient than N2 and CH4 injection.  相似文献   

11.
During CO2 flooding, the crude oil is treated with CO2, and meanwhile it is displaced by CO2. Based on the two processes, the influence of pressure and CO2 content on the asphaltene precipitation and oil recovery efficiency are systematically investigated by indoor simulation experiment. With the increase of the pressure or CO2 content during CO2 treatment, the amount of asphaltene precipitation can be increased to a certain value. Correspondingly, the degrees of the changes of oil-water interface, the compositions of crude oil, and reservoir permeability are positively correlated with the amount of asphaltene precipitation. However, during the process, the oil recovery has an optimal value due to the combined action of asphaltene precipitation and the improvement of flow performance of the crude oil. These conclusions can provide a basis for high efficiency development of low permeability oil reservoirs by CO2 flooding.  相似文献   

12.
Natural depletion of petroleum reservoirs as well as gas injection for enhance oil recovery, are unavoidable processes in the oil industry. Foremost, prediction of the problems due to these two processes is very necessary and important. So many field and experimental experiences have shown that heavy organic depositions, especially asphaltene deposition, are principal results during these processes. Results of laboratory simulation of asphaltene deposition during the natural depletion of petroleum reservoirs and also during gas injection and enhanced oil recovery (EOR) processes are reported here. This is achieved through the design of a new experimental setup for the investigation of pressure and composition effects on asphaltene deposition in petroleum fluids at high pressure and high temperature conditions. In this work, asphaltene deposition during decreasing pressure, from pressures greater than reservoir pressure to pressures below the bubble point pressure (natural depletion) and also asphaltene deposition during natural gas injection in reservoir conditions, are studied for three samples—one recombined sample and two bottomhole samples. All of the obtained results from this work conform to theoretical and other experimental works.  相似文献   

13.
Abstract

The authors quantitatively investigates the recovery efficiency, pattern behavior, and relative permeability of (a) condensate following supercritical carbon dioxide (CO2) injection, methane (CH4) injection, and the injection of their mixtures; and (b) natural gas of various compositions following pure supercritical CO2 injection. A high-pressure high-temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores. This work is part of an integrated enhanced natural gas and condensate recovery project conducted for a local reservoir in Western Australia. This data will help the operators develop operational and design strategies for their present and future EOR projects.  相似文献   

14.
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.  相似文献   

15.
CO2 flooding is an effective way in the tertiary oil recovery. While asphaltene often precipitates from the crude oil during the CO2 flooding, and the mechanisms of blockage resulting from asphaltene precipitation is still unclear in different CO2 flooding schemes. In this work, pure-CO2 flooding, water-alternating-CO2 flooding (WAG), and CO2-foam flooding were applied to conduct the core-flooding experiments. Then, as for each flooding scheme, we quantitatively investigated the blockage degree in different pores due to asphaltene precipitation with nuclear magnetic resonance (NMR) technique. Tests results show that CO2-foam flooding has a relatively higher blockage degree both in the smaller pores and the larger pores than WAG and pure-CO2 flooding. Although pure-CO2 flooding has the least asphaltene precipitation and blockage degree among three flooding schemes, its oil recovery degree is far less than the other two flooding schemes. Compared with pure-CO2 flooding and CO2-foam flooding, WAG flooding has the highest oil recovery and an acceptable asphaltene precipitation.  相似文献   

16.
Abstract

This work concerns observing the pressure as well as CO2 mole percentage effects on asphaltene molecular weight distributions at reservoir conditions. A high-pressure, high-temperature asphaltene measurement setup was applied, and the amount of precipitated asphaltene at different pressures as well as CO2 mole percentage in an Iranian heavy crude oil was measured. Moreover, the asphaltene molecular weight distributions during titration of crude oil with different n-alkanes were investigated. The gel permeation chromatography (GPC) apparatus was used for characterization of asphaltene molecular weight under different conditions. It has been observed that some thermodynamic changes such as pressure depletion above the bubble point increase the average molecular weight of asphaltene and cause the asphaltene molecular weight distributions changes from a bimodal curve with two maxima to a single maxima curve. One the other hand, below the bubble point, pressure reduction causes a decrease in the average molecular weight of asphaltene and also causes the shape of asphaltene molecular weight distributions to restore, which might be due to dissolution of asphaltene aggregates. An interesting result is that asphaltene molecular weight distribution at the final step of pressure reduction tests, ambient condition, shows approximately the same trend as the distribution of asphaltene molecular weight obtained at reservoir condition. This behavior explains the reversibility of the asphaltene precipitation process under pressure depletion conditions. In the case of CO2 injection, the graphs of asphaltene molecular weight distributions always show a single modal trend and shift toward larger molecular weight values when CO2 mole percentage increases. The results of this work can be imported to thermodynamic models that use polydisperse data of heavy organic fractions to enhance their performance at reservoir conditions. The distributions obtained by this method are good indicators of asphaltene structures at reservoir conditions.  相似文献   

17.
Mutual interactions between oil and gas are critical factors affecting the gas enhancing oil recovery (EOR) process. Focusing on CO2/oil and natural gas/oil systems, their interactions are researched and compared by extraction capacity and solubility measurement experiments. Core flood tests are also implemented to determine the effects of interactions on oil recovery. Results show that CO2 can extract more light oil from the original and its extraction efficiency can reach 59.3% at 46 MPa, whereas that of natural gas is only 7.3%. However, heavy components content and viscosity of the residual oil processed by CO2 increases significantly because of extraction, while natural gas does not affect the composition of the residual so remarkably. With increased pressure, solubility of CO2 and natural gas in a light oil present a linear growth trend with similar rate, but the former is greater than the latter by about 130m3/m3. Core flood tests show that, for the continuous gas injection in the secondary oil recovery process, recovery of CO2 flood is about 20% higher than that of natural gas due to the late breakthrough of CO2, as most of the crude oil is produced before breakthrough.  相似文献   

18.
To further improve the oil displacement effect by CO2 flooding, the trends and conditions of asphaltene deposition under different injection pressures and injection volumes of CO2 were studied by SDS solid phase deposition testing system, high temperature and high pressure microscope, and P-X phase diagram. When the mole fraction of CO2 in crude oil increases to a certain value, asphaltene deposition appears. The lower the pressure, the lower the mole fraction of CO2 in crude oil causing the asphaltene deposition there is. After the onset of asphaltene deposition, the degree of deposition increases with an increase in pressure. The amount of the deposited asphaltene under miscible displacement is the highest, under near-miscible displacement is the second highest, and under immiscible displacement is the lowest. When the dissolution of CO2 in crude oil reaches the saturation point, the asphaltene deposition becomes slow. Besides, it is feasible to prevent or reduce the asphaltene deposition by adjusting the thermodynamic parameters according to the phase behaviors of the CO2-crude oil system. The experimental results can provide theoretical basis for optimization design of the parameters of CO2 flooding.  相似文献   

19.
This paper focus on the main influence factors (temperature, pressure, and mass fraction of CO2) on the state of asphaltene in the crude oil during CO2 flooding by using high temperature and high pressure microanalysis system of solid precipitation. For the simulated oil sample – CO2 system, the state of asphaltene is not affected by temperature within this range of 50°C to 100°C, the particle size of the asphaltene has an increase with the increase of the pressure from 8MPa to 40 MPa. When the mass fraction of CO2 is less than 35%, the state of the asphaltene has not changed and the asphaltene particles are in a suspension state. When the mass fraction of CO2 increases to 40%, the aggregation of the asphaltenes occurs and then form precipitation. With the further increase of the mass fraction of CO2, the particle of the asphaltene aggregates has a significant increase. For the field development project design of CO2 flooding, the influence of the temperature can be ignored, the appropriate mass fraction of CO2 is below 35% and the gas injection pressure should maintain a relatively low value. The results can provide a theoretical basis to avoid the asphaltene precipitation during CO2 flooding.  相似文献   

20.
Carbon dioxide (CO2) flooding is one of the most important methods for enhanced oil recovery (EOR) because it not only increases oil recovery efficiency but also causes a reduction of greenhouse gas emissions. It is a very complex system, involving phase behavior that could increase the recovery of oil by means of swelling, evaporation and decreasing viscosity of the oil. In this study, a reservoir modeling approach was used to evaluate immiscible and miscible CO2 flooding in a fractured oil field. To reduce simulation time, we grouped fluid components into 10 pseudo-components. The 3-parameter, Peng–Robinson Equation of State (EOS) was used to match PVT experimental data by using the PVTi software. A one-dimensional slim-tube model was defined using ECLIPSE 300 software to determine the minimum miscibility pressure (MMP) for injection of CO2. We used FloGrid software for making a reservoir static model and the reservoir model was calibrated using manual and assisted history matching methods. Then various scenarios of natural depletion, immiscible and miscible CO2 injection have been simulated by ECLIPSE 300 software and then the simulation results of scenarios have been compared. Investigation of simulation results shows that the oil recovery factor in miscible CO2 injection scenario is more than other methods.  相似文献   

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