Slim Tube Test Research Articles

Impact of nanopore confinement on phase behavior and enriched gas minimum miscibility pressure in asphaltenic tight oil reservoirs

Miscible gas injection in tight/shale oil reservoirs presents a complex problem due to various factors, including the presence of a large number of nanopores in the rock structure and asphaltene and heavy components in crude oil. This method performs best when the gas injection pressure exceeds the minimum miscibility pressure (MMP). Accordingly, accurate calculation of the MMP is of special importance. A critical issue that needs to be considered is that the phase behavior of the fluid in confined nanopores is substantially different from that of conventional reservoirs. The confinement effect may significantly affect fluid properties, flow, and transport phenomena characteristics in pore space, e.g., considerably changing the critical properties and enhancing fluid adsorption on the pore wall. In this study, we have investigated the MMP between an asphaltenic crude oil and enriched natural gas using Peng-Robinson (PR) and cubic-plus-association (CPA) equations of state (EoSs) by considering the effect of confinement, adsorption, the shift of critical properties, and the presence of asphaltene. According to the best of our knowledge, this is the first time a model has been developed considering all these factors for use in porous media. We used the vanishing interfacial tension (VIT) method and slim tube test data to calculate the MMP and examined the effects of pore radius, type/composition of injected gas, and asphaltene type on the computed MMP. The results showed that the MMP increased with an increasing radius of up to 100 nm and then remained almost constant. This is while the gas enrichment reduced the MMP. Asphaltene presence changed the trend of IFT reduction and delayed the miscibility achievement so that it was about 61% different from the model without the asphaltene precipitation effect. However, the type of asphaltene had little impact on the MMP, and the controlling factor was the amount of asphaltene in the oil. Moreover, although cubic EoSs are particularly popular for their simplicity and accuracy in predicting the behavior of hydrocarbon fluids, the CPA EoS is more accurate for asphaltenic oils, especially when the operating pressure is within the asphaltene precipitation range.

Comprehensive Review of the Determination and Reduction of the Minimum Miscibility Pressure during CO2 Flooding.

With the increasing oil demand, more attention has been paid to enhancing oil recovery in old oil fields. CO2 flooding is popular due to its high oil displacement efficiency and ability to reduce greenhouse gas emissions. Laboratory experiments and on-site application cases have shown that the minimum miscibility pressure has a greater impact on CO2 flooding than other factors. If the reservoir pressure is below the minimum miscible pressure, then there is CO2 immiscible flooding. Both theoretical analysis and experimental results show that the recovery rate of CO2 miscible flooding is 2-5 times higher than that of immiscible flooding. If the reservoir pressure is increased by water flooding before CO2 injection, it is easily limited by the physical property parameters. Therefore, accurately determining and effectively reducing the minimum mixing pressure has become the focus of research. Currently, there are two types of methods for determining the minimum miscible pressure: experimental and theoretical methods. The experimental method is generally considered more accurate, including the slim tube test, rising bubble apparatus, and vanishing interfacial tension, etc. However, it is worth noting that the minimum miscibility pressure is dynamically changing, and there will be high economic costs if measured repeatedly through experimental methods during reservoir development. Therefore, it is recognized that the minimum mixing pressure can be determined at any time using theoretical calculation of initial data, which will reduce economic and time costs to a high degree. In this paper, the theoretical calculation method is divided into empirical correlation, state equation, and artificial intelligence algorithm. The techniques for reducing the minimum miscibility pressure can be classified into two categories: miscible solvents and surfactant methods. The miscible solvent method can be further divided into monocomponent and polycomponent methods. This paper compares the advantages and disadvantages of the existing techniques for measuring and reducing MMP and selects the best method.

Insights into CO2 huff-n-puff mechanisms from laboratory experiment and single-well pilot test in the Lucaogou tight oil reservoir, Jimsar sag, China

CO2 huff-n-puff has been accepted as an effective technique to improve oil recovery in tight oil reservoirs. Even though CO2 EOR mechanisms were extensively investigated from laboratory experiments, the links of experimental results to field-scale performance have not been widely investigated as few pilot tests were conducted. In this study, laboratory experiments and CO2-huff-n-puff pilot test were performed. First, phase behaviors of the Lucaogou crude oil and oil-CO2 mixtures were investigated via Pressure-Volume-Temperature (PVT) tests including flash evaporation, constant composition extension (CCE), and CO2 injection and slim tube tests, respectively. Experimental results showed that due to the higher concentration of the intermediate components, the saturation pressure of the Lucaogou crude oil is 6.18 MPa, which is much smaller than the initial and current formation pressures. The oil viscosity decreased from 24.8 mPa s to 3.0 mPa s and swelling factor increased to 1.848 after about 85 mol% CO2 dissolved. Moreover, slim tube test showed the minimum miscible pressure of the Lucaogou crude oil is 24.28 MPa, which is smaller than the current formation pressure, indicating multi-contact miscibility could be reached easily. Second, fracturing fluid imbibition and CO2 huff-n-puff experiments were carried out to evaluate the performance of CO2 EOR after fracturing. The oil recovery factor increased after imbibition time and the number of huff-n-puff cycles, and was impacted by petrophysical properties, like porosity and pore structure. In addition, performance of CO2 huff-n-puff pilot test in the J30 well was reported. Approximately 1.9% of original oil in place was recovered after one huff-n-puff cycle, showing a significant potential of CO2 EOR in the Lucaogou tight formation. Analysis of oil production rate, composition and density of produced oil shows the dominant EOR mechanisms in the early production stage were miscibility and CO2 vaporization, then viscosity reduction. Findings from this study will provide insights on CO2 EOR in tight oil reservoirs.

Minimum CO2 Miscibility Pressure Evaluation using Interfacial Tension (IFT) and Slim-tube Hybrid Tests.

The effectiveness of CO2-enhanced oil recovery (EOR) is strongly dependent on the CO2-oil minimum miscible pressure (MMP) value, which can be estimated using various methods. In this study, interfacial tension (IFT) and slim-tube tests were used to estimate the MMP value. Experimental results indicated that the IFT test had a higher MMP value than the slim-tube test. Particularly, the outcomes of IFT and the slim-tube tests differed slightly, i.e., 0.7% and 4.3% at 60 and 66 °C, respectively. Furthermore, the current work also compares MMP data gathered using visual observation and equation of state (EOS) simulation. The MMP estimated by EOS is higher but close to the IFT and slim-tube recovery factor method, where all results are within the 1650-1700 psi and 1700-1800 psi visual observation ranges at 60 and 66 °C, respectively. However, MMP deviations concerning the slim-tube test and EOS were consistent at different temperatures. This study offers an alternative to estimate and evaluate CO2-oil MMP for EOR applications accurately and efficiently.

Prediction of minimum miscibility pressure (MMP) of the crude oil-CO2 systems within a unified and consistent machine learning framework

In this study, considering the differences of minimum miscibility pressure (MMP) measured with the slim-tube and rising bubble apparatus (RBA) methods and taking each individual compound and the parameter representing the source of MMP measurement as the input, a new machine learning model has been proposed and validated to determine MMPs of the crude oil-CO2 systems by use of the one-dimensional convolutional neural network (1D-CNN). Then, the differences of the aforementioned two MMP measurement methods and each individual factor on the predicted MMP are analyzed by using the SHapley Additive exPlanations (SHAP). Compared to the existing models that ignore the differences of MMPs obtained from different experiments and taking the pseudocomponents as the input, the newly proposed model not only has the lowest mean absolute percentage error (MAPE) of 7.29%, lowest mean square error (MSE) of 3.7916, and highest R2 of 0.9458 on the slim-tube test dataset, but also can be used to accurately reflect the relationship between the MMP and each of its influential factor. Furthermore, it is observed that there is a very good correlation between the MMP measured with the slim-tube and the RBA methods to capture the corresponding physics in such two experiments within a unified, consistent, and efficient framework.

A novel experimental-theoretical method to improve MMP estimation using VIT technique

In the gas injection process for enhanced oil recovery (EOR), the interfacial tension (IFT) and the minimum miscibility pressure (MMP) are two key parameters for evaluating the miscibility condition. The vanishing interfacial tension (VIT) method is an efficient method for measuring the interfacial tension of oil and gas versus pressure and can estimate the minimum miscibility pressure. A problem in the VIT test of a hydrocarbon system is that during this test, oil and gas densities vary due to the composition variation of both phases. But in the conventional interfacial measurement, this issue is ignored, and the initial and non-equilibrium densities are utilized for estimating the interfacial tension. In this study, it is tried to nominate a novel method for estimating the most accurate value of IFT. Hence, for this purpose, first a VIT test has been performed for a hydrocarbon gas and a live oil system and using the axisymmetric drop shape analysis (ADSA), the oil droplet has been analyzed, and the geometry factor, which has been defined in this paper, was calculated. After that, the volume of oil droplet and the gas have been measured and were used for vapor-liquid-equilibrium (VLE) or flash calculation using Peng-Robinson equation of state (PR-EOS). By VLE calculation fulfillment, the final composition of two phases is determined. Eventually, the densities of two phases have been calculated for VIT modification. Finally, the IFT results were plotted versus the pressure steps, and the MMP were estimated. Furthermore, to evaluate the results of VIT test and its modification, slim tube displacement (STD) test, which is known as the most reliable laboratory method for measuring the MMP in the oil industry, has been performed. The results show that the values obtained for MMP values for the VIT test with the corrected densities which are lower than the values obtained for the VIT test for not-corrected densities and the suggested experimental-theoretical method has been estimated the MMP more accurately. The MMP obtained by VIT test and modified VIT method was equal to 3858.72 and 3722.0 psi, respectively. Meanwhile, the slim tube test has measured the MMP equal to 3667.13 psi.

Experimental investigation of carbon dioxide flooding in heavy oil reservoirs for enhanced oil recovery

With the attention paid to greenhouse gas emission reduction all over the world, CO2 capture, utilization and storage technology has developed rapidly. Predecessors have done a lot of work on the effect of CO2 on properties of the oil, the changes of parameters after CO2 injection are different. Through PVT, slim tube test and phase state simulation, this work studied the influence law of CO2 injection on the properties of heavy oil in offshore reservoirs in eastern China. It defines the adaptability and oil displacement mechanism of CO2 flooding in the reservoirs. In this work, 12 oil displacement experiments were carried out to quantify the effect of injection sequence, slug size, gas injection rate, and soaking time on oil recovery in the hydrogen carbon reservoir. These experimental results have indicated the influence of different factors on oil displacement effect. It provides strong evidence for the efficient development and enhanced oil recovery of the oilfield. The results indicate that the gas–water alternative injection is better than continuous water flooding or continuous CO2 flooding by improving the ultimate recovery at 8.9% and 12.7% respectively. A larger CO2 slug is beneficial to improve the ultimate oil recovery and the injection rate of CO2 slightly affects the ultimate oil recovery factor. Longer soaking time can improve the ultimate recovery either. The ultimate recovery increases rapidly with the soaking time when it less than 24 h, but the ultimate oil recovery hardly increases when the soaking time is longer than 24 h.

Estimating the minimum miscibility pressure (MMP) of methane-live oil using the slim tube test, by modified oil recovery factor (MORF) and break-over pressure (MBOP) criteria

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

Measuerment of CO2-crude oil minimum miscible pressure in YC Oilfield by core displacement method

Aiming at the defect of measuring the CO2-crude oil MMP(minimum miscible pressure) by the slim tube test, the core displacement method is established based on indoor physical simulation and homogeneous rectangular core in the low permeability block of YC oilfield. For comparison, the MMP is measured by the slim tube test in the same block. Experimental results show that the method has good repeatability and can simulate porous media and reservoir water content, which is more consistent with the actual reservoir conditions. The MMP in the target block of YC oilfield was 19.85MPa, which was 1.87MPa lower than that measured by traditional slim tube test.

How Is Ultrasonic-Assisted CO2 EOR to Unlock Oils from Unconventional Reservoirs?

CO2 enhanced oil recovery (EOR) has proven its capability to explore unconventional tight oil reservoirs and the potential for geological carbon storage. Meanwhile, the extremely low permeability pores increase the difficulty of CO2 EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate oil–gas miscibility development and finally contributes to excavating more tight oils. Firstly, the physical properties of crude oil with and without ultrasonic treatments were experimentally analyzed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Secondly, the oil–gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Thirdly, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40 KHz and 200 W for 8 h) was found to substantially change the oil properties, with viscosity (at 60 °C) reduced from 4.1 to 2.8 mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum showed that the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from the ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9 MPa from the slim-tube test and the oil recovery factor increased by an additional 11.7%. This study reveals the mechanisms of ultrasonic-assisted CO2 miscible EOR in producing tight oils.

Influence of permeability on the minimum miscibility pressure between CO2 and crude oil

The slim tube test is the industry standard for measuring the minimum miscibility pressure at present. However, there is a huge gap between the pore parameters of the slim tube model and the actual reservoir, especially the influence of permeability on MMP is not considered. The previous studies have shown that the minimum miscibility pressure is related to the pore structure and permeability of the reservoir. It is believed that there are some theoretical defects in the MMP measured by the slim tube test. This paper aims at the defect of slim tube test, core displacement experiment is carried out by using natural core to measure the minimum miscibility pressure under different permeability, and to reveal the law of the influence of permeability on the minimum miscibility pressure.

Micro-Slimtube Shrinks EOR Screening From Months to a Week

Oilfield testing firm Interface Fluidics says it is one step closer to reinventing the industry’s pressure-volume-temperature (PVT) testing portfolio after the development of a smaller, faster version of yet another laboratory stalwart. Representing the newest alternative to the slimtube test is the micro-slimtube test. A conventional slimtube test involves flowing gas through a sand- or glass-bead-packed metal coil that may be 1 to 4 mm wide and some 40 to 80 ft long to see how it mixes and mobilizes oil with samples also inside the tube. The test and subsequent analysis usually take a few months to complete. For a generation, this has been considered time well spent by anyone preparing to invest millions of dollars to prop up an aged asset through gas-injection-based enhanced oil recovery (EOR). But the times are changing. Interface Fluidics’ innovation, which it developed in close partnership with Equinor, measures only about 1.5 in long and generates results in about a week - about 95% sooner than the conventional bench method. The new test also reduces costs by around 75% while using a reservoir fluid sample that’s 99% smaller (10 ml vs. 1 liter). “It’s the same story over and over again - we’re miniaturizing the big stuff and putting it on a chip,” said Stuart Kinnear, CEO of Interface Fluidics. Founded in 2016, the Calgary-based firm helped introduce microfluidic technology to the oil industry with glass and silicon chips that it calls “reservoir analogues.” A well-established enabler in the healthcare industry, microfluidic devices of various stripes are routinely used to rapidly screen new drugs or to study how blood cells move through tiny veins and capillaries. In the upstream industry, Interface Fluidics is part of much smaller group of specialists proving that the devices are also ideal for screening production-enhancing chemicals and to study how oil moves about the tiny pathways of a reservoir rock (SPE 188895). The firm first showed how this works by replicating reservoir rock samples onto its chips as an alternative to core flood experiments. For oil and gas producers and their chemical providers alike (SPE 189780), the lower-cost devices made it affordable to run dozens of tests to determine how various chemistries affect flow behavior in specific geologies.

Determination of Minimum Miscibility Pressure (MMP) using PVTi Software, Eclipse 300 and Empirical Correlations

One of the most important factors through the miscible gas injection process is to determine the Minimum Miscibility Pressure. According to the definition, the minimum miscibility pressure is the minimum pressure at which, at a constant temperature, the oil and gas injected can dissolve together to form a single phase. This pressure is typically abbreviated as MMP. Among the available methods for determining the minimum miscibility pressure, laboratory methods including slim tube test and ascending bubble apparatus test are more widely utilized. Although the mentioned tests have high measurement accuracy, they are very time consuming and expensive. Therefore, the determination of the minimum miscibility pressure is usually done using computational and simulation approaches that also have high accuracy. Conducting PVT tests and determining their MMP using slim tube method was previously performed. In this study, the minimum miscibility pressure of reservoirs was determined by applying three methods of simulation with PVTi software, simulation with Eclipse 300 software and using Empirical Correlations. By comparing the obtained results and the laboratory results, it was revealed that the simulation by Eclipse 300 is regarded as the fastest and most accurate approach.

A machine learning model for predicting the minimum miscibility pressure of CO2 and crude oil system based on a support vector machine algorithm approach

CO2 enhanced oil recovery (EOR) is a potential way for carbon capture, utilization and storage (CCUS). However, the effect of CO2 injection is greatly influenced by the reservoir conditions. Typically, Minimum miscible pressure (MMP) is selected as one of the key parameters for the screening and evaluation of prospective CO2 flooding. Conventional slim tube test is both accurate and widely accepted but it is inefficient. Existing empirical formulas for MMPs are easy to be used but have been proved inaccurate and unreliable. Machine learning-based methods have great advantages in predicting MMP. However, only predication accuracy is discussed for most models without the screening of the main control factors and further validation of the model reliability. In this paper, a new prediction model based on support vector machine (SVM) was developed for pure/impure CO2 and crude oil system. This study was based on 147 sets of MMP data from the literature with full information on reservoir temperature, oil composition and gas composition. The main control factors were screened by several statistical methods. Unlike the conventional prediction models that verified by only prediction accuracy, learning curve and single factor control variable analysis are further validated to obtain the optimum model.

Tree 101 block CO2 Minimum miscibility pressure slim tube test

Determining the minimum miscibility pressure is the main research content of CO2 mixed phase displacement. It is a key indicator of whether the formation fluid can reach the miscible phase. There are many ways to determine the minimum miscibility pressure. At present, the laboratory test measures the minimum miscibility pressure of CO2-crude oil. The accepted industry standard is the slim tube test. This paper is aimed at the reservoir profile of Tree 101 block in Yushulin Oilfield. Carry out a slim tube test to determine the minimum miscibility pressure of 32.43MPa.

Determination of CO2 volume injection effect to reservoir fluid characteristic in miscible CO2 displacement

Carbon dioxide (CO2) miscible flooding is one of the Enhanced Oil Recovery (EOR) methods that has been recognized as a promising method to improve of oil recovery before abandonment. In addition, many issues related to global warming or greenhouse effect due to CO2. By using CO2 as either miscible or immiscible flooding to enhance oil recovery injected into reservoir, it may help reduce environmental problems. Carbon dioxide (CO2) is able to improve of oil recovery effectively by important key parameter: minimum miscibility pressure (MMP), viscosity, and density. This paper aims to determine the effect of CO2 volume injection to reservoir fluid characteristic in order to CO2 miscible flooding for displacing the oil production. This research was carried out by some series of laboratory experiment that involve PVT test, slim tube test, and swelling test. The result from laboratory experiments were used to observe the use of CO2 and its effect on reservoir fluid characteristics such as viscosity, solubility, and swelling factor. MMP obtained from slim tube test is 2805 Psi. Based on the results, all trend of parameters: viscosity, solubility, and swelling factor showed the positive impact of CO2 have on liquid recovery.

Effect of gas contamination and well depth on pressure interval of CO2 near-miscible flooding

Minimum miscible pressure (MMP) of a representative oil sample is always taken as a leading indicator for screening the application of CO2 flooding in the targeted oilfield. However, a growing amount of evidence shows that in the vicinity of the conventional MMP, there exists an area (namely near-miscible region) which is significantly different from both miscible region and immiscible region. It can obtain comparable oil recovery as miscible flooding due to the improvement of sweep efficiency. In this paper, oil samples from two discovery oil wells (four well intervals) and gas samples from two discovery gas wells were obtained in QHD 29-2E oilfield, which is a newly discovered low permeability offshore reservoir of China. In view of the thick oil layer and varying CO2 contents of the gas layer, study on the determination of near-miscible pressure interval, the effect of injection gas contamination on the pressure region, and the variation of the specific pressure area with the change of well depth were conducted successively. To begin with, both slim tube test and slim tube simulation with denser test points were conducted to obtain the relationship of oil recovery and interfacial tension (IFT) with pressure. On this basis, near-miscible pressure regions under different CO2 contents were obtained. The lower limits of CO2 content for implementing near-miscible flooding can be determined by comparing with the reservoir pressure at a certain well depth. It is found that the lower limits vary from 34% to 64% for the four well intervals. Composition and location differences of the reservoir fluids are the main reasons for the pressure interval variation. It indicates that MMP and near-miscible pressure region which determined by just one set of oil and gas sample cannot represent the targeted well, and certainly not the whole oilfield with the oil layers of over 150 m. It is concluded that the deeper the well, the lower the CO2 content is needed to achieve near-miscible flooding for QHD 29-2E oilfield. Finally, several potential measures help to achieve near-miscible flooding and suggesting area for further study are presented.

Blocking Behavior of Organic Solid Phase in the Carbon Dioxide Multiphase and Multicomponent Displacement Process

Better dealing with carbon issues can support the management of current greenhouse gas emissions while achieving energy economic diversification and energy security. Carbon dioxide displacement has become the most acknowledged and practical method in enhanced oil recovery system. This is because of its oil sweep efficiency and ability to reduce the level of greenhouse gas emission. Nevertheless, it would lead to the organic solid phase deposition, which causes the changes of the wettability and the damages of wellbores and reservoirs. In this study, we used slim tube test and component test to research the dynamic characteristics of displacement process. In addition, the mechanism of porous media blockage was also investigated. Results show that when the displacement pressure closed to the minimum miscibility pressure, reservoir blockage in pore throat could happen. Component test characterizes that during near miscible displacement process, the components of oil sample varied obviously, the variation range of peak component carbon marks fluctuated strongly. Crude oil component differentiation could happen after carbon dioxide fully contacted with oil. Besides, the rapid extraction mechanism of aromatic hydrocarbons played a significant role in this process under such condition. The reason is that the solubility of saturated hydrocarbons to asphaltene and non-hydrocarbons is obviously weaker than aromatic hydrocarbons. Controlling the pressure is considered as an important link to prevent the occurrence of blocking in the carbon dioxide multiphase and multicomponent displacement process.

Determination and evaluation of minimum miscibility pressure using various methods: experimental, visual observation, and simulation

This research proposes a simultaneous technique using various methods to yield the most reliable Minimum Miscibility Pressure (MMP) value. Several methods have been utilized in this study including slim tube test, swelling test, vanishing interfacial tension test, visual observation during swelling test and vanishing interfacial tension test, and simulation. The proposed method may reduce the uncertainty and avoid doubtful MMP. The method can also demonstrate discrepancies among the results. There were two samples used in this study namely Crude Oil AB-5 and Crude Oil AB-4. It showed that for Crude Oil AB-5 the discrepancies among the results from that of the slim tube test were between 3.9% and 10.4% and 0% and 5.9% for the temperature of 60 °C and 66 °C, respectively. The highest discrepancy was shown by the results from the visual observation during vanishing interfacial tension test and the lowest discrepancy was shown by the results from the swelling test. The vanishing interfacial tension test was found to be the fastest method for predicting the MMP. The method also consumed a smaller amount of oil and gas samples for the experiment. The simultaneous method proposed in this study is considered as more proper and exhibits a valuable method for predicting the MMP. This technique has never been found to be performed by previous researchers and accordingly it becomes the strong point of this study to contribute to the global research in the area of MMP determination.

Experimental Investigation on CO2 Injection in Block M

The purpose of this report was to perform an experimental evaluation of enhanced oil recovery (EOR) using CO2 injection. A slim tube test and PVT experiment are used to determine the minimum miscibility pressure as well as a few related physical properties. Combined with a long core displacement experiment and nuclear magnetic resonance, CO2 flooding and CO2-water alternate flooding are simulated, and the displacement efficiency of different types of pores is evaluated. The results indicate that the minimum miscibility pressure is 32.6 MPa, and the CO2 flooding is at near-miscible conditions at the current formation pressure. The CO2 solubility of crude oil is large, and the crude oil has a strong expansion ability after the CO2 injection, which is beneficial for improving the recovery of CO2. The EOR of CO2-water alternate flooding is 3.97% higher than that of continuous CO2 flooding, and the EOR in the small and middle pores in the CO2-water alternate flooding is clearly higher. These results will be relevant for the future development of Block M.