Crude Oil CO2 Research Articles

Application of adaptive neuro fuzzy interface system optimized with evolutionary algorithms for modeling CO2-crude oil minimum miscibility pressure

CO2 injection is known as one of the most reliable enhanced oil recovery techniques. The success of every gas injection process depends highly on the minimum miscibility pressure (MMP) needed for the injected gas and the oil to reach miscibility. Therefore, determination of the MMP between the two fluids is of great importance. In this study, a novel intelligent model based on adaptive neuro fuzzy interface system (ANFIS) was developed for predicting MMP values between pure/impure CO2 and reservoir oil at different reservoir conditions based on 270 experimental data points for pure and impure CO2, dead and live oils, reservoir temperature ranges from 293.72K to 388.73K, and experimental MMP values range from 6.54MPa to 31.30MPa. The ANFIS model was optimized by five different approaches; including Back Propagation (BP), Genetic Algorithm (GA), Particle Swarm Optimization (PSO), Ant Colony Optimization (ACO) and Differential Evolution (DE). A large number of data points from various sources of literature were gathered for model development and verification. In addition, various statistical and graphical error analyses were employed to evaluate the performance of the developed models as well as to compare them with major literature models for MMP prediction. The results showed that the ANFIS model optimized by PSO has the highest accuracy among all the models developed in this study as well as literature models, with an average absolute percent relative error of only 7.53%. In addition, all models developed in this study are more accurate than the existing models and their accuracy are as follows: ANFIS-PSO>ANFIS-GA>ANFIS-ACO>ANFIS-BP>ANFIS-DE. Lastly, the ANFIS models developed here can be inserted in any simulator to increase the accuracy of predicting pure and impure CO2-crude oil MMP.

Influence of injection pressure and injection volume of CO2 on asphaltene deposition

ABSTRACTTo 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.

Oil recovery performance and permeability reduction mechanisms in miscible CO2 water-alternative-gas (WAG) injection after continuous CO2 injection: An experimental investigation and modeling approach

Asphaltene deposition and inorganic deposition are a serious problem because it may lead to the clogging of the reservoir and the reducing of oil production during miscible CO2 water-alternative-gas (CO2-WAG) injection or continuous CO2 injection process. In this study, first of all, the minimum miscibility pressure (MMP) of the crude oil-CO2 system was measured by using the slim-tube apparatus and obtained to be 22.95MPa. Then, the composite long coreflood experiment was conducted under miscible condition (i.e., Pop>MMP) to determine the ultimate recovery factor (RF) and the permeability reduction caused by asphaltene deposition and inorganic deposition in a tight sandstone reservoir. The results of the experiment found that, after the CO2 breakthrough (BT) of continuous CO2 flooding, the ensuing miscible CO2–WAG injection is able to enhance effectively the ultimate RF from 51.97% to 73.15% under miscible condition. It was obtained that the permeability reduction of the reservoir core as a result of asphaltene deposition is represented an increased wave-like pattern along the flow direction in the CO2-WAG injectionafter continuous CO2 injection process, which is comparable to the predicted results calculated by the solubility model. In addition, the permeability reduction due to inorganic deposition is also shaped as a wave-like mode along the flow direction, which is corresponding to the results of the content change of mineral ions in brine. Moreover, it was also found that the permeability reduction due to asphaltene deposition is much larger than the permeability reduction as a result of inorganic deposition and mainly occurs in the middle and rear of the reservoir in the miscible CO2–WAG injection after the continuous CO2 injection. Thus, for the ensuing miscible CO2–WAG injection after the continuous CO2 injection, such as Jilin reservoir, the injection of chemical inhibitor into the middle and rear of the reservoir is recommended as an effective and economical means to reduce the risk of asphaltene deposition and then sustain the oil production.

Oil Recovery Performance and CO2 Storage Potential of CO2 Water-Alternating-Gas Injection after Continuous CO2 Injection in a Multilayer Formation

In this study, oil recovery performance and carbon dioxide (CO2) storage potential of a CO2 water-alternating-gas (CO2-WAG) injection after continuous CO2 injection process for multilayer formation were experimentally determined under immiscible and miscible conditions. First, a slim-tube apparatus was used to measure the minimum miscibility pressure (MMP) of a CO2–crude oil system (MMP = 22.79 MPa), which was applied as a guide for follow-on investigations. Afterward, the CO2-WAG injection after the continuous CO2 injection for a triple-layer system, horizontally placed and parallel-connected, was conducted to evaluate the capacity of enhanced oil recovery and CO2 storage potential of the multilayer formation at different operating pressures and a reservoir temperature of 98 °C. Results revealed that the oil recovery of the entire system was determined by the recovery of a layer with the highest permeability, which was more than 90% of the entire system recovery provided by the highest permeability layer...

Influence of produced natural gas on CO2-crude oil systems and the cyclic CO2 injection process

In cyclic CO2 injection practice, CO2 has always been recycled to improve CO2 utilization and reduce cost. To study the influence of produced natural gas on CO2-crude oil systems and the cyclic CO2 injection process, the extraction efficiency and solubility of a mixture of CO2 and natural gas were investigated by extraction and solubility experiments. Interfacial tension (IFT) was measured by using the axisymmetric drop shape analysis technique, and cyclic injection experiments were conducted to study the performance of gas injection with various compositions. The results showed that both the CO2 extraction capability and solubility in the crude oil can be reduced when adding the produced natural gas in the CO2 stream. The reduction of extraction efficiency and solubility increases with increasing pressure. The interfacial tension (IFT) between crude oil and CO2 linearly decreases with increasing pressure over two distinct ranges. The IFT generally increases as more natural gas is added to CO2. In the low pressure range, the interfacial tension increase is caused by the reduced solubility of CO2, while in the high pressure range, the weakened extraction efficiency of CO2 is responsible for the increase. Increased interfacial tension results in a rise of 71.1% of the minimum miscibility pressure and an increase of 92.4% of the first contact miscibility pressure. Recovery of the cyclic CO2 injection in the coreflooding is, therefore, lowered by 6.2% in the immiscible case and by 10.7% in the miscible case. The higher the injection pressure is, the more the recovery will be decreased.

Two new quantitative technical criteria for determining the minimum miscibility pressures (MMPs) from the vanishing interfacial tension (VIT) technique

In this paper, two new quantitative technical criteria are developed to determine the minimum miscibility pressures (MMPs) from the vanishing interfacial tension (VIT) technique: the linear correlation coefficient (LCC) criterion and the critical interfacial thickness (CIT) criterion. Six series of dynamic interfacial tension (IFT) tests for the dead and live light crude oil–CO2 systems are conducted under different test conditions. The MMP is determined when the LCC is smaller than 0.990 or the interfacial thickness is smaller than 1.0nm for the first time. The determined respective MMPs of 12.9MPa and 13.2MPa for the dead and live light crude oil–CO2 systems from the VIT technique agree well with the MMPs of 12.4–12.9MPa for the former system from the coreflood tests and fairly well with 15.2–15.4MPa for the latter system from the slim-tube tests. In addition, the specific effects of three experimental factors on the determined MMPs are studied by applying the two new quantitative technical criteria: (a) the initial vs. equilibrium IFTs; (b) the oil composition; and (c) the initial gas–oil ratio (GOR). The measured initial other than equilibrium IFTs are found to be sufficiently accurate to determine the MMP from the VIT technique. This is because the pendant oil drops used in the dynamic IFT tests are so small that they can be saturated with CO2 almost instantaneously. The live light crude oil pre-saturated with CH4-dominated hydrocarbons has a slightly higher MMP in comparison with the dead light crude oil. Moreover, the initial GOR effect on the MMP is found to be negligible in a lower GOR range (1:1–10:1 in volume) or in a large CO2 concentration range (31.76–94.69mol%). It becomes pronounced in a higher GOR range (200:1–4000:1 in volume) or in an extremely small range of high CO2 concentrations (98.79–99.99mol%).

Integrating support vector regression with genetic algorithm for CO2-oil minimum miscibility pressure (MMP) in pure and impure CO2 streams

Accurate knowledge of the minimum miscibility pressure (MMP) is essential in successful design of any miscible gas injection process, particularly in CO2 flooding. It is however well-acknowledged that experimental measurements are expensive, time-consuming, and cumbersome. As a direct consequence, a support vector regression model combined with genetic algorithm (GA-SVR) was proposed to predict pure and impure CO2-crude oil MMP. The accuracy and reliability of the proposed model were evaluated through 150 data sets collected in the open literature and compared with approaches commonly used to estimate the MMP (Lee correlation, Shokir correlation, Orr-Jensen correlation, Yellig-Metcalfe correlation, Alston correlation, Emera-Sarma correlation, Cronquist correlation, Kamari et al. correlation, and Fathinasab-Ayatollahi correlation). The results showed that the proposed model for predicting the MMP is in excellent agreement with experimental data and outperforms all the existing methods considered in this work in prediction of pure and impure CO2-oil MMP. Furthermore, outlier diagnosis was performed on the whole data sets to identify the applicable range of all models investigated in this work by detecting the probable doubtful MMP data.

New qualitative and quantitative technical criteria for determining the minimum miscibility pressures (MMPs) with the rising-bubble apparatus (RBA)

In this paper, one novel qualitative criterion, the bubble break-up (BBU), and two new quantitative criteria, the bubble-rising height (BRH) and bubble-rising velocity (BRV), are proposed and studied to determine the minimum miscibility pressures (MMPs) with the rising-bubble apparatus (RBA). Two respective series of pure and impure CO2-bubble tests in a light crude oil are conducted at six different test pressures and the actual reservoir temperature of Tres=53.0°C. First, the MMPs of the light crude oil–pure and impure CO2 systems are estimated and compared by using four existing (i.e., the bubble shape, size, colour, and rising height) and BBU qualitative criteria. Second, the BRH and BRV quantitative criteria are used to determine the MMPs of the light crude oil–pure CO2 system, in comparison with those from the coreflood tests and vanishing interfacial tension (VIT) technique. Third, these two new quantitative criteria are also applied to determine the MMPs of the light crude oil–impure CO2 (74.87mol.% CO2+25.13mol.% CH4) system and compare them with that from the VIT technique. It is found that the BBU criterion is consistent with the four existing qualitative criteria for estimating the MMPs. By means of the BRH and BRV criteria, two respective MMP ranges of the light crude oil–pure and impure CO2 systems are found to be 11.7–12.4MPa and 23.4–23.5MPa at Tres=53.0°C. Such determined MMPs with the RBA are slightly lower than those from the coreflood tests for the light crude oil–pure CO2 system but relatively higher than those from the VIT technique for the two respective light crude oil–CO2 systems. The newly developed BRH and BRV quantitative technical criteria, plus the novel BBU qualitative technical criterion, can be used to objectively and accurately determine the MMPs with the RBA.

On the determination of CO2–crude oil minimum miscibility pressure using genetic programming combined with constrained multivariable search methods

In addition to reducing carbon dioxide (CO2) emission, the high oil recovery efficiency achieved by CO2 injection processes makes CO2 injection a desirable enhance oil recovery (EOR) technique. Minimum miscibility pressure (MMP) is an important parameter in successful designation of any miscible gas injection process such as CO2 flooding; therefore, its accurate determination is of great importance. The current experimental techniques for determining MMP are expensive and time-consuming. In this study, multi-gene genetic programming has been combined with constrained multivariable search methods, and a simple empirical model has been developed which provides a reliable estimation of MMP in a wide range of reservoirs, injection gases and crude oil systems. The experimental data for developing the proposed correlation consists of 270 data points from twenty-six authenticated literature sources. This model utilizes reservoir temperature, molecular weight of C5+, volatile (N2 and C1) to intermediate (H2S, CO2, C2, C3, C4) ratio and pseudo critical temperature of the injection gas as input parameters. Both statistical and graphical error analyses have been employed to evaluate the accuracy and validity of the proposed model compared to the pre-existing correlations. The results showed that the new model provides an average absolute relative error of 11.76%. Moreover, the relevancy factor indicated that the reservoir temperature has the greatest impact on the minimum miscibility pressure.

Two different technical criteria for determining the minimum miscibility pressures (MMPs) from the slim-tube and coreflood tests

In this paper, two different technical criteria, i.e., the oil recovery factor (ORF) and break-over pressure (BOP), are studied and compared to determine the minimum miscibility pressures (MMPs) of two light crude oil–CO2 systems. More specifically, five slim-tube tests with the live light crude oil–CO2 system and five coreflood tests with the dead light crude oil–CO2 system are conducted to measure the ORFs at different injection pressures and the actual reservoir temperature of Tres=53.0°C. The linear and quadratic extrapolation methods as well as the linear intersection method are applied by using the ORF criterion. Three different high threshold ORFs of 88% for the slim-tube tests or 87% for the coreflood tests, 90% and 95% are chosen to determine the MMPs by means of the linear and quadratic extrapolation methods. On the other hand, the linear intersection method is used to determine the MMP by finding a sudden slope change point in the measured ORF versus injection pressure curve for the slim-tube or coreflood tests. Moreover, the BOP criterion is based on the cubic regression of the measured ORF versus injection pressure data and used to determine the MMPs, which correspond to four different low threshold slopes or incremental ORFs per incremental injection pressure increase of 5, 3, 2, and 1%/MPa. It is found that different MMP ranges can be obtained from the same measured ORF versus injection pressure data if different MMP criteria, regression methods, and threshold values or numerical options are adopted. The determined MMP is better given in a small pressure range than specified as a definitive pressure value. Two MMP ranges of the live and dead light crude oil–CO2 systems are determined to be 15.2–15.4MPa and 12.4–12.9MPa at Tres=53.0°C, respectively.

Economic evaluation on CO2-EOR of onshore oil fields in China

Carbon dioxide enhanced oil recovery (CO2-EOR) and sequestration in depleted oil reservoirs is a plausible option for utilizing anthropogenic CO2 to increase oil production while storing CO2 underground. Evaluation of the storage resources and cost of potential CO2-EOR projects is an essential step before the commencement of large-scale deployment of such activities. In this paper, a hybrid techno-economic evaluation method, including a performance model and cost model for onshore CO2-EOR projects, has been developed based on previous studies. Total 296 onshore oil fields, accounting for about 70% of total mature onshore oil fields in China, were evaluated by the techno-economic method. The key findings of this study are summarized as follows: (1) deterministic analysis shows there are approximately 1.1 billion tons (7.7 billion barrels) of incremental crude oil and 2.2 billion tons CO2 storage resource for onshore CO2-EOR at net positive revenue within the Chinese oil fields reviewed under the given operating strategy and economic assumptions. (2) Sensitivity study highlights that the cumulative oil production and cumulative CO2 storage resource are very sensitive to crude oil price, CO2 cost, project lifetime, discount rate and tax policy. High oil price, short project lifetime, low discount rate, low CO2 cost, and low tax policy can greatly increase the net income of the oil enterprise, incremental oil recovery and CO2 storage resource. (3) From this techno-economic evaluation, the major barriers to large-scale deployment of CO2-EOR include complex geological conditions, low API of crude oil, high tax policy, and lack of incentives for the CO2-EOR project.

An Improved CO2-Crude Oil Minimum Miscibility Pressure Correlation

Minimum miscibility pressure (MMP), which plays an important role in miscible flooding, is a key parameter in determining whether crude oil and gas are completely miscible. On the basis of 210 groups of CO2-crude oil system minimum miscibility pressure data, an improved CO2-crude oil system minimum miscibility pressure correlation was built by modified conjugate gradient method and global optimizing method. The new correlation is a uniform empirical correlation to calculate the MMP for both thin oil and heavy oil and is expressed as a function of reservoir temperature, C7+molecular weight of crude oil, and mole fractions of volatile components (CH4and N2) and intermediate components (CO2, H2S, and C2~C6) of crude oil. Compared to the eleven most popular and relatively high-accuracy CO2-oil system MMP correlations in the previous literature by other nine groups of CO2-oil MMP experimental data, which have not been used to develop the new correlation, it is found that the new empirical correlation provides the best reproduction of the nine groups of CO2-oil MMP experimental data with a percentage average absolute relative error (%AARE) of 8% and a percentage maximum absolute relative error (%MARE) of 21%, respectively.

Experimental investigation of CO2-foam stability improvement by alkaline in the presence of crude oil

Dissolution of CO2 in heavy crude oil results in a significant reduction in the oil viscosity. However, CO2 injection in viscous oil reservoirs lacks acceptable sweep efficiency due to the high mobility of CO2. Co-injection of CO2 and an appropriate surfactant can generate CO2-foam in situ providings a means of controlling CO2 mobility and hence, improving sweep efficiency and oil recovery. Foam injection has been studied in the past but in the majority of these studies, foam has been investigated in the absence of crude oil. It is known that the stability of foam is adversely affected by crude oil and this problem has been a major obstacle for the application of foam injection for enhanced oil recovery (EOR).In this paper we present the results of a comprehensive series of visual experiments on foam stability in the presence of different heavy crude oil samples. Through these experiments, we have evaluated and compared the performance of a number of surfactants for foam generation. We have also tested the impact of three different alkalis (NaOH, Na2CO3, and Borate) on foam stability. The effect of gas type (CO2 versus N2) has also been investigated experimentally.The results show that while addition of NaOH drastically decreases the stability of CO2-foam, Na2CO3 and, in particular, Borate can significantly increase the stability of CO2-foam. For these alkalis, there is an optimum concentration which corresponds to maximum foam stability. The results also reveal that higher oil viscosity increases the stability of CO2-foam. Anionic surfactants with smaller carbon number produce better foam stability compared to non-anionic surfactants. As expected, foam stability increased with increasing surfactant concentration but there was an optimum surfactant concentration corresponding to maximum foam stability beyond which foam stability decreased. The results also revealed that N2-foam was more stable compared to CO2-foam.

Source term modeling for evaluating the potential impacts to groundwater of fluids escaping from a depleted oil reservoir used for carbon sequestration

In recent years depleted oil reservoirs have received special interest as carbon storage reservoirs because of their potential to offset costs through collaboration with enhanced oil recovery projects. Modeling is currently being conducted to evaluate potential risks to groundwater associated with leakage of fluids from depleted oil reservoirs used for storage of CO2. Modeling results reported here focused on understanding how toxic organic compounds found in oil will distribute between the various phases (oil, vapor, and brine) within a storage reservoir after introduction of CO2, understanding the migration potential of these compounds, and assessing potential groundwater impacts should leakage occur. Three model scenarios were conducted to evaluate how organic components in oil will distribute among the phases of interest (oil, CO2, and brine). The three cases were 50wt.% oil and 50wt.% water, 90wt.% CO2 and 10wt.% oil, and 90wt.% CO2, 5wt.% oil, and 5% wt.% water. Several key organic compounds were considered in this study based upon their occurrence in oil at significant concentrations, relative toxicity, or because they can serve as surrogate compounds for other more highly toxic compounds for which required input data are not available. The organic contaminants of interest (COI) selected for this study were benzene, toluene, naphthalene, phenanthrene, and anthracene.Partitioning of organic compounds between crude oil and supercritical CO2 was modeled using the Peng–Robinson equation of state over temperature and pressure conditions that represent the entire subsurface system of the scenario under investigation (from those relevant to deep geologic carbon storage environments to near surface conditions). Results indicate that for the modeled oil reservoir conditions (75°C, and 21,520kPa) negligible amounts of the COI dissolve into the aqueous phase. When CO2 is introduced into the reservoir such that the final composition of the reservoir is 90wt.% CO2 and 10wt.% oil, a significant fraction of the oil dissolves into the vapor phase. As the vapor phase moves up through the stratigraphic column, pressures and temperatures decrease, resulting in significant condensation of oil components. The heaviest organic components condense early in this process (at higher pressures and temperatures), while the lighter components tend to remain in the vapor phase until much lower pressures and temperatures are reached. Based on the model assumptions, the final concentrations of COI to reach an aquifer at 1520kPa and 25°C were quite significant for benzene and toluene, whereas the concentrations of polynuclear aromatic hydrocarbons that reach the aquifer were very small. This work demonstrates a methodology that can provide COI source term concentrations in CO2 leaking from a reservoir and entering an overlying aquifer for use in risk assessments.

Determination of Minimum Miscibility Pressure of Crude Oil–CO2 System by Oil Swelling/Extraction Test

AbstractThe minimum miscibility pressure (MMP) of crude oil–CO2 systems was determined through analyzing the experimental data of swelling/extraction tests. First, the oil swelling factor (SF) as a result of CO2 dissolution in a crude oil sample was determined at four different temperatures in the range of T=21–40 °C. In addition, three sets of swelling/extraction data of previous studies were collected and included so that more conclusive and satisfactory results can be obtained. The results demonstrated that the oil swelling factor increases with the equilibrium pressure (Peq), reaches the maximum value at light hydrocarbon extraction pressure (Pext), and then reduces with further increase in equilibrium pressure. It was found that the reduction behavior of oil swelling factor occurs in two distinct regions. In the upper extraction phase (UEP), the oil swelling factor decreased sharply at pressures just over extraction pressure and then declined gradually in what is called the lower extraction phase (LEP). Finally, the MMP of the crude oil–CO2 system at a specific temperature was estimated by finding the intersection of the linear regression correlation corresponding to each of the aforementioned regions (i.e., UEP and LEP). The crude oil–CO2 MMP was also determined by employing the vanishing interfacial tension (VIT) technique and a series of CO2 injection tests. Comparing the MMP values of the crude oil–CO2 systems determined by three methods revealed that the MMP values estimated by swelling/extraction data are in approximate agreement with those determined by the two other methods.

On the CO2 storage potential of cyclic CO2 injection process for enhanced oil recovery

In this study, the potential of cyclic CO2 injection process was examined for CO2 storage and enhanced oil recovery. For this purpose, a detailed phase behavior study on the light crude oil–CO2 and brine–CO2 systems was conducted. CO2 solubility in the oil and brine samples as well as oil swelling factor as a result of CO2 dissolution were experimentally measured. The equilibrium interfacial tension of the crude oil–CO2 system was also determined by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Furthermore, the minimum miscibility pressure (MMP) of CO2 with crude oil was calculated by means of vanishing interfacial tension (VIT) technique and found to be MMP=9.18MPa. Thereafter, series of cyclic CO2 injection tests were designed and carried out at constant temperature of T=30°C and various operating pressures in the range of Pop=5.38–10.34MPa to cover immiscible and miscible conditions. The results showed that 40–50% of the injected CO2 was stored in the porous medium mainly through residual and solubility trappings’ mechanisms. It was found that during immiscible injection condition (i.e., Pop<MMP), higher amount of CO2 can be stored in the porous medium at higher operating pressures. The results also revealed that optimum potential of CO2 storage is almost at operating pressures near the MMP, while beyond that pressure, the CO2 storage capacity was not substantially increased. From the enhanced oil recovery point of view, the oil recovery factor was significantly improved when operating pressure increased and reached its maximum value at miscible condition (i.e., Pop⩾MMP). During the immiscible injection scenario, mechanisms involved in oil production were mainly oil swelling and reduction of interfacial tension. However, the light component extraction was the major production mechanism contributing to the oil recovery during miscible injection process.

Oil Recovery Performance of Immiscible and Miscible CO2 Huff-and-Puff Processes

The recovery performance of immiscible and miscible CO2 huff-and-puff processes for enhanced oil recovery (EOR) in a light crude oil sample was experimentally investigated. The minimum miscibility pressure (MMP) of the original light crude oil–CO2 system was determined by means of the vanishing interfacial tension technique and found to be MMP = 9.18 MPa. Then, the solubility of the CO2 in the light crude oil and oil swelling factor due to the CO2 dissolution in the oil phase were determined at T = 30 °C and various equilibrium pressures ranging from atmospheric pressure to Peq = 12.55 MPa. Later, series of immiscible and miscible CO2 huff-and-puff tests were designed and carried out at various operating pressures (i.e., Pop = 5.38–10.34 MPa). The results of the experiments showed that for secondary CO2 huff-and-puff tests performed at the operating pressures below the MMP, the ultimate oil recovery factor is quite low. It was also found that in immiscible CO2 huff-and-puff (i.e., Pop < MMP) scenarios, the oil recovery factor substantially increased as the operating pressure approached near-miscible conditions. The oil recovery factor almost reached its maximum value at operating pressure near MMP (i.e., miscible condition), and further increase of operating pressure beyond MMP did not improve the recovery factor at all. The tertiary mode of miscible CO2 huff-and-puff was also examined, and it was revealed that the oil recovery is significantly improved after a waterflooding process. The oil recovery mechanisms during the CO2 huff-and-puff were mainly recognized to be interfacial tension reduction, oil swelling, and extraction of lighter components by CO2, especially during miscible CO2 injections. In addition, the average asphaltene content of produced oil and the permeability reduction of the porous medium as a result of asphaltene precipitation were measured in each test. It was found that the amount of precipitated asphaltene in the porous medium as well as permeability reduction are considerably higher in near-miscible and miscible CO2 huff-and-puff tests compared to those in immiscible cases. The compositional analysis of remaining oil from CO2 huff-and-puff tests at immiscible and miscible conditions also showed that lighter components of oil are extracted by CO2, leading the remaining oil to become heavier with greater amounts of heavy hydrocarbons (i.e., C30+). However, it was observed that the extraction of lighter components during miscible injection processes is more predominant than that during immiscible injections, resulting in the production of higher quality oil.

Temperature effects on the phase behaviour, mutual interactions and oil recovery of a light crude oil–CO2 system

In this paper, the temperature effects on the phase behaviour, mutual interactions, and oil recovery of a light crude oil–CO2 system are experimentally studied. First, six PVT tests are performed to measure the saturation pressures and the oil-swelling factors of three light crude oil–CO2 systems with different CO2 concentrations. Second, a series of saturation tests are conducted to determine the onset pressure (Pasp) of asphaltene precipitation from the light crude oil–CO2 system. Third, the minimum miscibility pressure (MMP) and the first-contact miscibility pressure (Pmax) of the light crude oil–CO2 system are determined by applying the vanishing interfacial tension (VIT) technique. Meanwhile, the oil-swelling effect, the initial quick and subsequent slow light-hydrocarbons extraction phenomena are observed during the dynamic interfacial tension (IFT) measurements. In particular, the onset pressure (Pext) for the initial quick light-hydrocarbons extraction by CO2 is noted. Finally, a total of eleven CO2-coreflood tests are undertaken to examine the temperature effect on the CO2-based oil recovery. All the above-mentioned experiments are conducted at a laboratory temperature of Tlab=27.0°C and at the actual reservoir temperature of Tres=53.0°C, respectively. It is found that the test temperature has a strong effect on the saturation pressure but a marginal influence on the oil-swelling factor of a given light crude oil–CO2 system. It is also found that the four onset pressures are in the order of magnitude: Pasp<Pext<MMP<Pmax. Furthermore, Pasp and Pext increase slightly but the MMP and Pmax increase significantly with the test temperature. Lastly, a higher test temperature leads to a higher oil recovery factor as long as the CO2 flooding is miscible.

Effects of Four Important Factors on the Measured Minimum Miscibility Pressure and First-Contact Miscibility Pressure

The vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressures (MMPs) and first-contact miscibility pressures (Pmax) of five light crude oil–CO2 systems from the measured equilibrium interfacial tensions (IFTs) at different equilibrium pressures. The equilibrium IFTs are measured under various experimental conditions by applying the axisymmetric drop shape analysis technique for the pendant drop case. It is found that in each IFT test, the measured equilibrium IFT is reduced almost linearly with the equilibrium pressure in two pressure ranges. The MMP of each light crude oil–CO2 system is thus determined from the measured equilibrium IFTs in range I by applying the VIT technique. The first-contact miscibility pressure (Pmax) of each light crude oil–CO2 system is extrapolated from the measured equilibrium IFTs in range II. Moreover, the test temperature, crude oil composition (dead/live oil), gas composition (pure/impure CO2), and initial gas–oil ratio (GOR) are studied to examine their specific effects. The experimental data show that the measured MMPs and Pmax values of five light crude oil–CO2 systems increase linearly with the temperature. The presence of CH4 in the CO2 phase results in substantially higher MMP and Pmax. An increased initial GOR leads to marginally higher MMP and Pmax.

Tracing the evolution of seep fluids from authigenic carbonates: Green Canyon, northern Gulf of Mexico

Authigenic carbonates from hydrocarbon seeps are unique long-term archives of past fluid flow. The studied samples were collected from Green Canyon block 140 at a water depth of 260 m in the Gulf of Mexico. Petrography, X-ray diffraction, stable isotopes and 14C dating were applied to assess the evolution of seep activity and potential driving forces. The carbonates are dominated by high-Mg calcite (HMC) and aragonite, with a minor amount of low-Mg calcite (LMC) and dolomite. Petrographically, peloids, clotted microfabric, acicular aragonite and a variable content of bioclasts were observed. Three types of carbonates are recognized. Structure I carbonates, with 14C ages from 46.5 ka to 25.8 ka BP, are characterized by δ13C values from −23.2‰ to 5.1‰, suggesting multiple carbon sources that include thermogenic methane, biodegraded crude oil, seawater and residual CO2 from methanogenesis at greater depth. In contrast, Structure II carbonates formed between 17.6 ka and 11.7 ka BP and have δ13C values varying from −22.2‰ to −8.8‰, suggesting carbon sources similar to those of Structure I carbonates but with a negligible influence of residual CO2 from methanogenesis. In addition, the presence of LMC in this type of carbonate may be associated with brine seepage. Structure III carbonates among the youngest of the samples analyzed with 14C ages of 1.2 ka BP. These carbonates have the most negative δ13C values ranging from −36.1‰ to −26.8‰, suggesting that thermogenic methane is the primary carbon source. The majority carbonates of both Structure I and II are slightly 18O-enriched, which is most likely related to the incorporation of water from dehydration of clay minerals. The considerable range of mineralogical and isotopic variations of the studied carbonates highlights the local control of the seepage flux. It is proposed that factors affecting the activity of hydrocarbon seeps are sea level changes and salt movement. The combination of petrography, stable isotopes, and dating approach used here, highlights that these are valuable tools to assess the variability of past fluid flow at hydrocarbon seeps.