CO2 Injection Conditions Research Articles

Integrity Experiments for Geological Carbon Storage (GCS) in Depleted Hydrocarbon Reservoirs: Wellbore Components under Cyclic CO2 Injection Conditions

Integrity of wellbores and near wellbore processes are crucial issues in geological carbon storage (GCS) projects as they both define the confinement and injectivity of CO2. For the proper confinement of CO2, any flow of CO2 along the wellbore trajectory must be prevented using engineered barriers. The effect of cyclic stimuli on wellbore integrity, especially in the context of GCS projects, has been given less attention. In this study, the effect of pressure- and temperature-cycling on two types of wellbore composites (i.e., casing-cement and cement-caprock) have been investigated experimentally in small- and large-scale laboratory setups. The experiments have been carried out by measuring the effective permeability of the composites under pressure and thermal cyclic conditions. Furthermore, the permeability of individual samples (API class G and HMR+ cement and caprock) was measured and compared to the permeability of the composites. The results indicate that the permeability of API class G cement when exposed to CO2 is in the order of 10−20 m2 (10−5 mD) as a result of the chemical reaction between the cement and CO2. In addition, the tightness of the composite cement–rock has been confirmed, while the permeability of the composite casing–cement falls within the acceptable range for tight cement and the CO2 flow was identified to occur through or close to the interface casing–cement. Results from thermal cycling within the range −9 to 14 °C revealed no significant effect on the integrity of the bond casing–cement. In contrast, pressure cycling experiments showed that the effective pressure has a larger influence on the permeability. The potential creation of micro-cracks under pressure variations may require some time for complete closing. In conclusion, the pressure and temperature cycling from this study did not violate the integrity of the casing–cement composite sample as the permeability remained low and within the acceptable range for wellbore cement.

Effects of calcium carbide slag on properties and carbon sequestration efficiency of cement pastes mixed under direct CO2 injection conditions

CO2-mixing by directly injecting CO2 into fresh cement-based materials is a burgeoning technology to produce low-carbon cement products. The objective of this study is to investigate the influence of the calcium carbide slag (CCS) content on the properties and carbon sequestration efficiency of cement pastes mixed under direct CO2 injection conditions. The results indicate that the addition of CCS reduced the fluidity of the cement pastes, accelerated the setting process, increased volume shrinkage, and reduced compressive strength. Following the injection of CO2 into the cement pastes, calcium hydroxide (CH) was carbonated to form calcium carbonate (CC) particles which fill the voids in the cement pastes, thereby reducing volume shrinkage and increasing compressive strength. A lower CO2 inflow rate (2 L/min) was more beneficial to the workability of the cement pastes, while a high inflow rate (6 L/min) can lead to insufficient hydration and affect the development of strength. However, a higher CO2 inflow rate was favorable for improving carbon sequestration efficiency. The highest amountof carbon sequestration can be reached at 6.93 %, when the CCS content is 10 % and the CO2 inflow rate is 6 L/min.

The Influence of CO2 Physical Properties on Casing and Its Prediction Method

In order to reveal the physical properties of CO2 under actual formation conditions, this paper establishes a mathematical model of the temperature field and pressure field in the wellbore under CO2 injection conditions, optimizes the state equation of CO2 physical-property parameters, calculates the change trend of CO2 density, viscosity, and compression factor along the wellbore, and obtains the influence law of CO2 corrosion on the casing and interface. The viscosity showed a downward trend along the well depth; the compression factor showed an upward trend. The surfaces of the three casings were smooth and flat without obvious defects, the cement structure was dense, and there was no obvious pore structure. After corrosion, with the increase of Cr content, the change of interfacial corrosion decreases. The morphology of the Q125 and 3Cr interface is loose after corrosion, while there is no obvious change in the 13Cr interface. With the prolongation of corrosion time, low wellbore internal pressure easily causes casing yield, and high wellbore internal pressure easily causes cement-sheath compression failure. The circumferential stress of the casing increases with the corrosion time extension, and the radial stress of the casing and cement sheath decreases first and then increases with the corrosion time. The compressive strength of the cement sheath does not exceed the compressive strength.

Numerical study on heat storage efficiency of broken rock mass under different CO2 injection conditions

The application of energy storage technology can solve the problems of randomness and volatility in the development and use of renewable energy, such as wind and solar energy, and effectively improve energy utilization. Rock heat storage is one of the primary forms of sensible heat storage. The heat storage efficiency and heat storage capacity of rock packed bed are important indicators to measure the energy storage effect of a rock energy storage system. This paper takes CO2 as the heat-carrying medium and broken granite grains as the packed bed matrix of the energy storage system. It establishes a porous medium thermal-hydraulic-mechanical coupling model of the broken rock bed. The heat injection and production process of the large-sized rock bed heat storage system is simulated using the COMSOL finite element software, and the heat storage efficiency and heat storage capacity of the broken rock bed is analyzed under different fluid injection pressures and injection temperatures. The results show that: 1) With the increase of CO2 injection pressure, the heat storage and heat production speed of the heat storage system will increase, and the heat storage rate changes from two stages of “low rise - slow decline” to four stages of “rapid increase—stability—rapid decrease—stability”; 2) With the increase of CO2 injection temperature, the maximum heat storage capacity of the rock bed heat storage system will increase. Due to the increase in the temperature gradient between CO2 and the rock bed, the heat storage and the heat production time of the heat storage system will increase, and its speed will decrease.

IMPACT OF WATER AND CO2 ON THE MECHANICAL PROPERTIES OF LOW PERMEABLE ROCKS

This article features experiments on triaxial compression of low-permeable dolomite samples with different confining pressures (2-20 MPa), different pore fluids (dry air, water, CO2), and different temperatures (25-150 °C). The authors have studied the effect of confining pressure, pore fluid and temperature on the strength properties of the studied samples. The results show an increase in the strength with grwoing confining pressure. When the confining pressure increases from 2 to 20 MPa, the compressive strength increases from 86 to 370 MPa. Temperature has a significant effect on rock strength under low confining pressure conditions. With the increasing confining pressure reaching 15 MPa, increasing temperature has little effect on the strength of dolomite samples. Under an effective confining pressure of 5 MPa, the temperature weakening occurs on the dolomite specimens when the temperature exceeds 90 °C. During compression, liquid diffusion occurs in the specimens. Higher water viscosity can cause a temporary decrease in effective confining pressure, which can increase the strength of the rock. More prominent fractures are observed in the samples, and more fluid is injected under CO2 injection conditions, which may be useful for increasing the permeability of the geothermal reservoir. Two groups of experiments have been performed on the samples in this study: the first group of experiments investigated the effect of confining pressure on the fracture stress of core samples, without pore fluid injection; the second group of experiments investigated the effect of water or CO2 and temperature on the mechanical properties of core samples.

Pore-scale characterization of carbon dioxide storage at immiscible and near-miscible conditions in altered-wettability reservoir rocks

Carbon dioxide storage combined with enhanced oil recovery (CCS-EOR) is an important approach for reducing greenhouse gas emissions. We use pore-scale imaging to help understand CO2 storage and oil recovery during CCS-EOR at immiscible and near-miscible CO2 injection conditions. We study in situ immiscible CO2 flooding in an oil-wet reservoir rock at elevated temperature and pressure using X-ray micro-tomography. We observe the predicted, but hitherto unreported, three-phase wettability order in strongly oil-wet rocks, where water occupies the largest pores, oil the smallest, while CO2 occupies pores of intermediate size. We investigate the pore occupancy, existence of CO2 layers, recovery and CO2 trapping in the oil-wet rock at immiscible conditions and compare to the results obtained on the same rock type under slightly more weakly oil-wet near-miscible conditions, with the same wettability order. CO2 spreads in connected layers at near-miscible conditions, while it exists as disconnected ganglia in medium-sized pores at immiscible conditions. Hence, capillary trapping of CO2 by oil occurs at immiscible but not at near-miscible conditions. Moreover, capillary trapping of CO2 by water is not possible in both cases since CO2 is more wetting to the rock than water. The oil recovery by CO2 injection alone is reduced at immiscible conditions compared to near-miscible conditions, where low gas-oil capillary pressure improves microscopic displacement efficiency. Based on these results, to maximize the amount of oil recovered and CO2 stored at immiscible conditions, a water-alternating-gas injection strategy is suggested, while a strategy of continuous CO2 injection is recommended at near-miscible conditions.

Mineral Carbonation of CO2 in Mafic Plutonic Rocks, II—Laboratory Experiments on Early-Phase Supercritical CO2‒Brine‒Rock Interactions

The potential for mineral carbonation of CO2 in plutonic mafic rocks is addressed through a set of laboratory experiments on cumulate gabbro and gabbro-diorite specimens from the Sines Massif (Portugal). The experiments were conducted in an autoclave, for a maximum of 64 days, using a CO2 supersaturated brine under pressure and temperature conditions similar to those expected around an injection well during early-phase CO2 injection. Multiple techniques for mineralogical and geochemical characterization were applied ante- and post-carbonation experiments. New mineralogical phases (smectite, halite and gypsum), roughness increase and material loss were observed after exposure to the CO2 supersaturated brine. The chemical analysis shows consistent changes in the brine and rock specimens: (i) increases in iron (Fe) and magnesium (Mg) in the aqueous phase and decreases in Fe2O3 and MgO in the specimens; (ii) a decrease in aqueous calcium (Ca) and an increase in CaO in the cumulate gabbro, whereas in the gabbro-diorite aqueous Ca increased and afterwards remained constant, whereas CaO decreased. The geochemical model using the CrunchFlow code was able to reproduce the experimental observations and simulate the chemical behavior for longer times. Overall, the study indicates that the early-stage CO2 injection conditions adopted induce mainly a dissolution phase with mineralogical/textural readjustments on the external area of the samples studied.

Effects of Water and scCO2 Injection on the Mechanical Properties of Granite at High Temperatures

Geothermal energy is an important resource to substitute for traditional fossil fuels. The mechanical properties of reservoir rock under the conditions of water and scCO2 injection at different temperatures are crucial for the safety of Enhanced Geothermal Systems. However, the effects of working fluid on the mechanical properties of granite at in situ temperatures are still rarely reported. To reveal the impact mechanisms, conventional triaxial compression experiments were conducted on granite specimens with different confining pressures (2–20 MPa), different pore fluid (10 MPa water or CO2), and different temperatures (25–150°C) in the present study. SEM analyses were applied to the specimens to determine failure surface morphologies after the experiments. The experimental results show that the effective confining pressure, pore fluid, and temperature have significant effects on the strength of granite specimens. The strength of granite increases with the increase of effective confining pressure, with similar granite strength under the same effective confining pressure (dry, water, and CO2). Temperature strengthening of granite is limited by high confining pressure (∼15 MPa). Under the effective confining pressure of 5 MPa, temperature weakening occurs on granite specimens when temperature is higher than 90°C. There is fluid diffusion in the specimens during compression. The higher viscosity of water may cause a temporary decrease in effective confining pressure, which may increase the strength of granite. The growth or formation of cracks is mainly observed in quartz and feldspar grains without short‐term chemical effects. More visible cracks are observed on the specimens and more volume of fluid is injected under CO2 injection conditions, which may be beneficial to increase the permeability of geothermal reservoir.

김치용기에서의 이산화탄소 농도 제어를 위한 주입 프로그램 조건 설정

Kimchi is a refreshing sour food which gives sour and carbonic acid taste of carbon dioxide produced during the fermentation process. So, carbon dioxide injection was tried to raise carbonic acid taste of kimchi stored in the airtight container. First, carbon dioxide injection times of a given gas supply system were determined experimentally to attain initial concentration of 80% for different solid/liquid ratios. Since carbon dioxide is dissolved in kimchi to decrease its concentration during storage, periodical carbon dioxide injection conditions were needed and determined to keep the CO2 concentration above 70%. For the initial flushing to 80% CO2 concentration in model system filled with water, the injection time ranged from 40 to 89 seconds for free volumes of 2-8 L. CO2 injection conditions for the under-ripened storage at 10oC consisted of longer time at more frequent cycles for watery kimchi than for Chinese cabbage kimchi. At 0oC of subsequent ripened stage storage of watery kimchi, the periodical injection at 3 hour interval was required because of continuous dissolution of carbon dioxide. However, Chinese cabbage kimchi did not require subsequent CO2 injection during the ripened state storage and needed only flushing to 80% CO2 at time of the container opening and closing. These results can be used as basic information for the programmed control of CO2 injection in the kimchi container system.

Geochemical modelling of processes in near-wellbore zone under CO2 injection conditions

In the conditions of sequestration of acid gases to the rock formation between rocks, reservoir fluids, injected gases, wellbore cement and the casing, the complex geochemical changes occur. Although these processes have been the subject of some research in recent decades, their mechanisms are still not sufficiently recognized, and especially the impact of these processes on the preservation of leak-tightness of boreholes, which is a key element for the success of the sequestration process.The computer simulation accurately reflects the direction of changes taking place during real experiments, additionally providing detailed information on the mineral phases involved in the mineral transformation process within rock and wellbore cement. In the acidic environment created in the analyzed system, the dissolution of portlandite and C-S-H phases, as well as the crystallization of calcite, vaterite and silica, takes place. During the time taken into account in the simulation, the volume of minerals crystallizing in the cement is greater than the volume of dissolved components, but on the other hand, micro-voids may appear in the contact zone. In the case of penetration of pore waters, coming from rocks into the cement, the most intense transformations occur in the cement to a depth of 3 cm from the contact zone with the rock.

The coupled effect of salt precipitation and fines mobilization on CO2 injectivity in sandstone

AbstractAppreciable CO2 injectivity is required to inject large volumes of CO2 through a minimum number of wells. In situ geochemical CO2‐brine‐rock reactions may dissolve sandstone rock minerals, and consequently release fine particles into the pore fluid. If the fine particles (‘fines’) are mobilized during CO2 injection, well injectivity could be severely impaired. The transport of fines under CO2 injection conditions involves the complex multiphase flow of dry supercritical CO2, saline formation brine, and fine particles. While transported fines could plug narrow pore channels, the saline pore water could be vaporized by supercritical CO2 to precipitate solid salt into the pores. To understand the impact of mineral dissolution on CO2 injectivity, it is important to consider the coupled effect of fine particle mobilization and salt precipitation. We conducted core‐flood experiments and theoretical modelling to investigate the coupled effect of the fines mobilization and salt precipitation on CO2 injectivity. We found that salt precipitation could increase CO2 injectivity impairment induced by the fines mobilization. The deposited salt reduces the flow area, making the pores more susceptible to particle entrapment. Injectivity impairment increased with decreasing initial rock permeability and increasing saturating brine salinity. Irreducible brine saturation and pore size distribution were identified as parameters that strongly determine the contribution of salt precipitation during the transport of fines. Injectivity impairment was also slightly higher when the rock was first exposed to salt precipitation, before the entrapment of fines. The current findings highlight the complexity and uniqueness of fines transportation under CO2 injection conditions and the impact of mineral dissolution on CO2 injectivity. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Movement compensation during carbon dioxide coronary angiography: In-vitro validation

The aim of this in vitro study was to evaluate the feasibility of movement compensation for CO2 coronary angiography. The use of CO2 as a contrast medium for coronary angiography in a routine clinical setting is still premature. Nonetheless, the gas can solve most of the problems related to iodine contrast-induced nephropathy and can be safely used for patients with renal insufficiency. In a previous work [I. Corazza et al., AIP Adv. 8(1), 015225 (2018)], we demonstrated that an adequate setting of the CO2 injection parameters (pressures and volumes) allows gas injection into the coronaries, avoiding reflux into the aorta and cerebral circulation. A mechanical mock simulating coronary circulation and movement was used to simulate different CO2 injection conditions. Simultaneous acquisition of ECG and optical images allowed synchronous frame extraction for post-processing analysis, like masking and stacking processes. A single test with a radiological apparatus was done to demonstrate the feasibility of the technique. By injecting CO2 at a pressure between the dicrotic notch and diastolic value, no reflux into the aorta was observed and the new software yielded final optical images of clinical quality after about 8 seconds of injection. The feasibility test under the X-ray apparatus gave promising results. CO2 coronary angiography is still far from becoming a clinical standard, but our bench evaluation demonstrates that if the injection parameters are well-controlled and physiological values known, CO2 can be used as a contrast agent not only for the lower part of the body, but also for the coronary arteries, respecting basic safety standards.

Exploration of the Difference in Molecular Structure of n-C7 and CO2 Induced Asphaltenes

Determination of the molecular structure of asphaltenes, especially in their native environment, is a formidable challenge in petroleum chemistry. Here we demonstrate that a combination of different spectroscopy and imaging based experimental techniques can be utilized to determine structures of asphaltenes, which have precipitated out of a crude oil, in an environment similar to real field conditions. A high pressure–high temperature quartz crystal microbalance (HPHT-QCM) setup can be used to detect asphaltene onset at oil production conditions. HPHT-QCM can also simulate CO2 injection conditions mimicking gas injection methods used to enhance oil recovery from depleted oil reservoirs. In this paper, we present the first compositional and structural research study on the QCM asphaltene deposits under gas injection conditions and compare it to n-C7 asphaltenes from the same crude oil precipitated in the laboratory. This study combines the use of Fourier transform infrared (FTIR) spectroscopy, nuclear magn...

An Analytical Model for the Corrosion Risk of Water Alternating Gas Injection Wells in CO2 Enhanced Oil Recovery

AbstractAn analytical model is proposed to describe the corrosion risk profile of a well tube in water alternating gas (WAG) CO2 injection conditions based on the assumption that the drying process of the water layer on the inner wall of the well tube plays a crucial role in controlling corrosion. In this model, the fluid properties, the thermodynamic equilibrium of CO2 and water steam, and an empirical CO2 corrosion equation are systematically considered. The description by this model reasonably indicates that fast injection can decrease the corrosion risk and push the highest risk region to a deeper zone, while a longer drying time for a thicker water layer left on the well inner wall can lead to higher corrosion risk. It can also be deduced that the offshore WAG case is more aggressive than the onshore case and some mitigation strategies are suggested for reducing the corrosion risk. These should be helpful for corrosion management and leakage monitoring in the practical WAG CO2 injection.

Flow dependence of steel corrosion in supercritical CO2 environments with different water concentrations

The corrosion behavior of mild steel in water contaminated supercritical CO2 fluids was investigated by weight-loss measurements and surface morphology observations. It is found that a higher flow rate induces a higher corrosion rate in various water containing conditions, which becomes much obvious with increasing the water concentration. By a detailed comparison of the surface corrosion morphologies formed in different supercritical CO2 fluids, the flow dependence is attributed to a mechanism of water droplet entrainment and its impact on steel surfaces. This observation is helpful for the understanding and the control of steel corrosion in CO2 transportation and injection conditions.

An experimental investigation of applicability of CO2 enhanced coal bed methane recovery to low rank coal

Previous studies have shown that carbon dioxide (CO2) injection can enhance CH4 production (CO2-ECBM) compared to traditionally-used methods, mainly due to the higher adsorptive capability of CO2 in coal, which desorbs the CH4 with higher sweep efficiency. Many studies have been conducted to date on the CO2-ECBM technique for high rank coals. However, there have been very few studies on low rank coal. Therefore, this study uses Victorian brown coal samples to investigate the CO2-ECBM potential of low rank coal. A series of CO2 core flooding tests was conducted on CH4 saturated meso-scale brown coal samples for various CO2 injection conditions, phases and pressures.According to the experimental findings, compared to natural recovery, CO2 flooding enhances CH4 production by creating higher production rates, and higher CO2 pressures can drive the CH4 towards the production end with almost 100% sweep efficiency. Furthermore, the rapid CO2 breakthroughs observed under higher CO2 pressures are found to be significant for super-critical CO2. Tests results show that the superior competence of super-critical CO2 in CH4 recovery is independent of coal rank or maturity. However, the greater volumetric strain created by higher CO2 pressures may, have a negative influence on long-term gas productivity with the reduction of flow ability through the seam.

Experimental Investigation and Modeling of Permeability Impairment Mechanisms Due to Asphaltene Precipitation Under CO2 Injection Conditions

The injection of hydrocarbon gases/CO2 for enhanced oil recovery can promote asphaltene precipitation and consequently reservoir impairment, of which its impact is tremendous. In this work, the results of flow dynamic tests performed on sandstone as well as carbonate rocks were presented. The permeability reduction mechanisms were investigated during simultaneously injection of CO2 and recombined oil into core samples through a static mixer at reservoir conditions. The permeability impairment data was monitored from analysis of recorded pressure and online viscosity measurements during the experiments. Analysis of obtained results revealed that for both sandstone and carbonate rocks, surface deposition and pore plugging mechanisms participate simultaneously in reduction of permeability in primary injected pore volumes. Therefore, a new permeability reduction model is proposed that considers a combination of surface deposition and pore plugging mechanisms. The results of the new model are in good agreement with the obtained experimental data. The results of this work can be helpful for modeling of asphaltene deposition due to CO2 injection in petroleum reservoirs.

A methodology for quantifying risk and likelihood of failure for carbon dioxide injection into deep saline reservoirs

Tectonically stable deep saline reservoirs are considered to be the most abundant carbon dioxide (CO2) sequestration sites. Pressure, temperature, salinity and other characteristics of these geologic formations vary at each injection site. It is essential to understand the roles of geologic and engineering factors to optimize the CO2 injection conditions and to quantify the associated risks. Factors such as the magnitude of injection-induced reservoir pressure, quantity of supercritical phase CO2 that comes in contact with caprock, and the amount of residually trapped CO2 govern the fate of CO2, and provide quantitative assessment of the storage integrity.A streamlined protocol was developed using response surface methodology to quantify the risks related to CO2 injection. The proposed methodology includes the design of simulation scenarios, selection and screening of parameters, multiple-linear regression of outcomes, and the development of probability density functions (PDF) of various potential risk factors. Multiphase numerical simulations were performed to understand the behavior of the injected CO2 and associated parameters in deep saline reservoirs with prescribed geometries and petrophysical properties. Formation thickness, formation depth, porosity, horizontal permeability, brine density, and the end-point residual CO2 saturation were the six critical parameters identified that affected important outcomes. A six-factor Box–Behnken experimental design procedure was used to establish an understanding of the sensitivity of the parameters on the important factors, and for subsequently establishing response surfaces. Closed boundary domains with different operational constraints were employed. A stepwise, sequential regression method was used to determine statistically significant coefficients of a response surface model. Monte Carlo simulations with logical distributions of input parameters were performed using the response surface coefficients. Uncorrelated and correlated porosity-permeability distributions were used to generate two types of probability density functions (PDF). PDFs of CO2 plume extent under the caprock and average reservoir overpressure after injection were generated given all of the variability in the input parameters. These results will allow initial screening of a large number of potential injection sites without detailed simulations of each.

Phase Behavior Modeling of Asphaltene Precipitation for Heavy Crudes: A Promising Tool Along with Experimental Data

Thermodynamic modeling is known as a promising tool for phase behavior modeling of asphaltene precipitation under different conditions such as pressure depletion and CO2 injection. 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, while the oil and gas phases are modeled with an equation of state. The 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 an improved solid model has been developed and used for predicting asphaltene precipitation data for one of Iranian heavy crudes, under pressure depletion and CO2 injection conditions. A significant improvement has been observed in predicting the asphaltene precipitation data under gas injection conditions. Especially for the maximum value of asphaltene precipitation and for the trend of the curve after the peak point, good agreement was observed. For gas injection conditions, comparison of the thermodynamic micellization model and the improved solid model showed that the thermodynamic micellization model cannot predict the maximum of precipitation as well as the improved solid model. The non-isothermal improved solid model has been used for predicting asphaltene precipitation data under pressure depletion conditions. The pressure depletion tests were done at different levels of temperature and pressure, and the parameters of a non-isothermal model were tuned using three onset pressures at three different temperatures for the considered crude. The results showed that the model is highly sensitive to the amount of solid molar volume along with the interaction coefficient parameter between the asphaltene component and light hydrocarbon components. Using a non-isothermal improved solid model, the asphaltene phase envelope was developed. It has been revealed that at high temperatures, an increase in the temperature results in a lower amount of asphaltene precipitation and also it causes the convergence of lower and upper boundaries of the asphaltene phase envelope. This work illustrates successful application of a non-isothermal improved solid model for developing the asphaltene phase envelope of heavy crude which can be helpful for monitoring and controlling of asphaltene precipitation through the wellbore and surface facilities during heavy oil production.

Prediction of Asphaltene Precipitation during Pressure Depletion and CO2 Injection for Heavy Crude

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.