Near-miscible CO2 Research Articles

A new empirical correlation of MMP prediction for oil – impure CO2 systems

CO2 flooding is a widely-used technique for enhancing oil production, with miscible CO2 flooding exhibiting higher recovery potential compared to both immiscible and near-miscible CO2 flooding. However, the problem of insufficient CO2 supply is increasingly critical in many reservoirs. When faced with a shortage of gas supply, the key to the successful implementation of miscible CO2 flooding lies in accurately predicting the MMP of impure CO2. This study leverages MMP data derived from both experimental and simulation results, utilizing both linear and nonlinear regression methodologies to formulate empirical correlations for MMP prediction. In addition, ridge regression is used to solve collinearity problem.Compared with former investigations, the impure CO2 correlation proposed in this study integrates the ratio of the specific injection gas mole fraction to the crude oil mole fraction as novel independent variables. This inclusion reflects the actual interaction between the specific injection gas and crude oil during the miscibility process. Furthermore, the correlation can be linearized to the greatest extent through this way and such linearization illustrates the fundamental concepts more distinctly, offering a more practical and comprehensible approach. This formula combines the prediction of the minimum miscible pressure with the interaction mechanism of the miscible process, and the dominant factors in the miscible process can be determined. In terms of reducing the minimum miscible pressure, the interaction between C4 + C5 in the injected gas and C1 + N2 in the crude oil component is the strongest, while the interaction between N2 in the injected gas and C2-6 in the crude oil was most significant in increasing the minimum miscible pressure by comparison.The correlations presented for impure CO2 yield an average absolute deviation of 2.18 % and sustain a relative deviation within ± 10 %, surpassing previously published correlations. This study highlights the accuracy and effectiveness of the developed correlations for estimating MMP for impure CO2. The suggested MMP correlation offers a practical and efficient means of determining MMP for the implementation of impure CO2 miscible flooding in the field.

Near-miscible supercritical [formula omitted] injection in oil-wet carbonate: A pore-scale experimental investigation of wettability state and three-phase flow behavior

Near-miscible supercritical CO2 (scCO2) injection and its underlying pore-scale physics were experimentally investigated in an oil-wet carbonate rock at elevated temperature and pressure conditions using X-ray microtomography. The results of in situ contact angle measurements yielded direct evidence showing that the scCO2 injection triggered a wettability reversal process resulting in reduced oil-wetness. As the scCO2 injection progressed, we observed a distinct wettability state where the wetting preference of the solid to the scCO2, oil, and brine phases was similar due to the wettability reversal. Consequently, pore sizes neither dictated any preferential invasion order nor restricted the displacement efficiency of the injection process. Furthermore, we identified a type of spreading system where spreading oil layers formed but did not exist globally across the pore space between the scCO2 and brine phases. Gaussian curvature analysis showed that the scCO2 and oil phases were well-connected at the early stage of the scCO2 injection, whereas brine connectivity was relatively poor. As the injection continued, brine connectivity was improved due to the wettability reversal effect. Moreover, displacement events including double and multiple displacements were identified and discussed. They included a variety of events that had scCO2 as the first phase and oil and brine as the subsequent phases. The diversity and affordability of such displacements were much higher than those previously observed during N2 injection in oil-wet systems where mostly gas-to-oil-to-brine double displacements took place. The interplay of scCO2-oil miscibility, the distinctive wettability state, favorable fluid connectivity, and frequent double/multiple displacements resulted in an exceptional displacement efficiency during near-miscible scCO2 injection.

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.

Oil Reservoir on a Chip: Pore-Scale Study of Multiphase Flow During Near-Miscible CO2 EOR and Storage

CO2 injection into oil reservoirs is widely accepted as an effective enhanced oil recovery and CO2 storage technique. While oil recovery and CO2 storage potential of this technique have been studied extensively at the core-scale, complex multiphase flow and fluid–fluid interactions at the pore scale during near-miscible CO2 injection have not, and this area needs more study. To address this, a unique high-pressure microfluidic system was implemented which allows for the optical visualisation of the flow using optical microscopy. The results show that during tertiary near-miscible CO2 injection, when CO2 phase contacts the oil, the oil spreads as a layer between the CO2 phase and water preventing CO2 phase from contacting the water phase. This is attributed to the positive value of the spreading coefficient. Furthermore, due to the presence of pore-scale heterogeneity in the chip, an early breakthrough of CO2 was observed causing a large amount of oil to be bypassed. However, after CO2 breakthrough, CO2 gradually started to diffuse and flow inside the bypassed oil zones in the transverse directions which is a characteristic of capillary crossflow. The driving force for this capillary crossflow was the interfacial tension gradient formed by the diffusion of CO2 into the oil phase and the extraction of light to medium hydrocarbon components from the oil into the CO2 phase. The same mechanism led to the recovery of the bypassed oil trapped in dead-end pores. This unique mechanism produced the majority of the bypassed oil after CO2 breakthrough and significantly increased the oil recovery. In our three-phase flow water-wet system, CO2 flow displaced the water through a multiple displacement mechanism which is unique to three-phase flow. CO2 displaced the oil in oil-filled pores thorough bulk flow, and the spreading oil layers were gradually produced by layer flow.

Empirical correlations for prediction of minimum miscible pressure and near-miscible pressure interval for oil and CO2 systems

Although near-miscible CO2 flooding has recently received considerable attention, no criteria are available to predict its applicability to a specific reservoir. Evaluating the viability of near-miscible flooding requires experimental exploration of a specific region in pressure–temperature space. The near-miscible pressure field is bounded on one side in P, T space by the MMP (minimum miscible pressure). This paper provides robust empirical correlations to estimate the MMP for both pure and impure CO2 and for prediction of the near-miscible pressure region for CO2-oil. Many slim tube analyses, lacking high density data points, systematically underestimate the MMP, when the near miscible region is not accounted for. They are based on 147 published data sets that include: slim tube experimental determination of MMP; interfacial tension (IFT) between oil and CO2; concentration of solution gas; and purity of the CO2. This paper is the first to begin a systematic exploration of the pressure-temperature space within which near-miscible effects characterize CO2 floods. Our new correlations provide a basis for identifying and investigating the nature of near miscible effects associated with existing CO2 floods. For a case study of an offshore field we determined that lower and upper pressure boundaries for effective near-miscible flooding, are 0.87 MMP and 1.07 MMP at reservoir temperatures. The proposed model is the first empirical correlation for the prediction of near-miscible pressure region, it will provide the basis for both screening the relative potential of oil reservoirs for economically viable miscible or near-miscible CO2-flooding.

Detailed Assessment of Compositional and Interfacial Tension Effects on the Fluid Behaviour During Immiscible and Near-Miscible CO2 Continuous and WAG Displacements

This study seeks to improve numerical simulations of the key physics occurring in CO2 enhanced oil recovery (CO2-EOR) processes, with a particular focus on the transition from immiscible to miscible displacements. In the previous work, we have investigated interactions between compositional effects and the underlying heterogeneities of the flow field in near-miscible floods (Wang et al. in Transp Porous Media 129(3):743–759, 2019a). In this current study, we have further analysed the effects of reduction in interfacial tension (IFT) on the flow behaviour, as motivated by the study on the film-flow mechanism previously presented by Sorbie and van Dijke (SPE improved oil recovery symposium, Society of Petroleum Engineers, 2010). We identify two clear mechanisms of oil recovery that may occur in near-miscible CO2 (or other gas) injection processes, which we denote, MCE, as oil stripping or conventional compositional effects, and MIFT as lower IFT oil film-flow effects. The latter MIFT effects are described by an enhanced hydrocarbon relative permeability in the near-miscible three-phase relative permeabilities (3PRP). Various combinations between the MCE and MIFT mechanisms were tested by numerical simulations to evaluate the impact of each mechanism on the flow behaviour, i.e. their separate and joint effects on quantities such as the local oil displacement efficiency, phase flow vectors and the ultimate oil recovery. When acting in combination, the oil stripping and IFT effects can greatly improve the local displacement performance even when viscous fingering flow occurs. Viscous fingering is well known to lead to bypassed oil in the “non-preferential” flow paths between the main fingers. We show that the remaining oil in these non-preferential flow paths (i.e. bypassed oil) can be efficiently recovered by the combined MCE and MIFT mechanisms, but only with the application of water alternating gas (WAG). In contrast to oil stripping effects, the IFT effect is not dependent on continuous contact between oil and CO2. Instead, the remaining oil is mobilized by gas as the IFT is reduced and can be efficiently produced by subsequent water injection. This MIFT mechanism has much less impact in cases with continuous CO2 injection compared to its efficiency in WAG. This is because during continuous injection, gas fingers are dominant in the preferential flow paths, and therefore the local displacement efficiency is very good, but only in these preferential routes. On the other hand, WAG is able to make full use of the IFT effects because of its relatively stable displacing front, which allows the MIFT mechanism to contribute. In this study, the effects of using different three-phase relative permeability methods were investigated and, as expected, different methods yielded different results. However, an important observation is that when IFT effects (MIFT) were included, there was much less difference in the final oil recovery using the different 3PRP models; our analysis shows why this is the case.

Pore-scale study of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR and storage in oil reservoirs

SummaryCO2 injection in oil reservoirs has been widely accepted as an effective EOR and CO2 storage technique. While oil recovery and CO2 storage potential of this technique at the core scale has been widely studied, complex fluids flow and fluid-fluid interactions at the pore-scale during nearmiscible CO2 injection require further study. For this aim, a unique high-pressure and high-temperature microfluidic system was used to conduct experiments at 2,500 psi and 40°C using live reservoir crude oil.According to results, during tertiary CO2 injection, due to the positive value of spreading coefficient, CO2 flowed only inside the oil and oil spread over CO2 and prevented CO2 contact the water. Due to unfavourable mobility ratios and permeability heterogeneities, displacement during tertiary CO2 flooding was unstable and viscous fingering occurred which led to an early breakthrough of CO2 and bypassing of a large amount of oil. However, after CO2 breakthrough, CO2 gradually started to flow inside the bypassed oil zones in the transverse/backward directions which is a characteristic of capillary fingering. Due to the gradual diffusion of CO2 into the bypassed oil, IFT between oil and CO2 decreased which led to a reduction of threshold capillary pressure, thus CO2 (non-wetting phase) entered the bypassed oil-filled pores. As a result of this unique mechanism, oil recovery after CO2 breakthrough significantly increased and almost all the bypassed oil was produced. The extent of this oil recovery mechanism depends on the extent of CO2-oil IFT reduction which depends on injection pressure.During CO2 flow in pores, CO2 displaced the water through multiple displacement mechanism. CO2 displaced the oil in the open-end pores thorough bulk flow, and the spreading oil layers were gradually produced by film flow. Uniquely, CO2 produced the oil in dead-end pores through a mix of bulk flow and film flow.The outcomes of this study provide an in-depth understanding of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR-storage.

In situ pore-scale analysis of oil recovery during three-phase near-miscible CO2 injection in a water-wet carbonate rock

We study in situ three-phase near-miscible CO2 injection in a water-wet carbonate rock at elevated temperature and pressure using X-ray microtomography. We examine the recovery mechanisms, presence or absence of oil layers, pore occupancy and interfacial areas during a secondary gas injection process. In contrast to an equivalent immiscible system, we did not observe layers of oil sandwiched between gas in the centre of the pore space and water in the corners. At near-miscible conditions, the measured contact angle between oil and gas was approximately 73°, indicating only weak oil wettability in the presence of gas. Oil flows in the centres of large pores, rather than in layers for immiscible injection, when displaced by gas. This allows for a rapid production of oil since it is no longer confined to movement in thin layers. A significant recovery factor of 80% was obtained and the residual oil saturation existed as disconnected blobs in the corners of the pore space. At equilibrium, gas occupied the biggest pores, while oil and water occupied pores of varying sizes (small, medium and large). Again, this was different from an immiscible system, where water occupied only the smallest pores. We suggest that a double displacement mechanism, where gas displaces water that displaces oil is responsible for shuffling water into larger pores than that seen after initial oil injection. This is only possible since, in the absence of oil layers, gas can contact water directly. The gas-oil and oil-water interfacial areas are lower than in the immiscible case, since there are no oil layers and even water layers in the macro-pore space become disconnected; in contrast, there is a larger direct contact of oil to the solid. These results could serve as benchmarks for developing near-miscible pore-scale modelling tools.

Analysis of Compositional Effects on Global Flow Regimes in CO2 Near-Miscible Displacements in Heterogeneous Systems

This study investigates the interaction of compositional effects with the flow behaviour during near-miscible (and immiscible) CO2–oil displacements in heterogeneous systems. A series of numerical simulations modelling 1D slim-tube and 2D areal systems were simulated using a fully compositional simulator. A number of grid resolutions for a slim-tube model were simulated to choose the proper level of numerical dispersion to mimic the actual physical dispersion. The corresponding 2D cases are based on a small heterogeneous sector model of dimensions 50 m × 10 m, in order that the fine-scale displacement physics can be modelled accurately. We investigated various flow regimes ranging from viscous fingering to channelling displacements within heterogeneous random correlated fields. We found that the reduced recovery is the result of a combination of differences in sweep efficiency associated with the viscous fingering and possible differences in local mixing that affect composition path. At the same time, the unstable phase flow determined by the underlying heterogeneity slows the flow in the unswept area and leads to unequal displacement performance between preferential and non-preferential routes. Specifically, lighter components have moved preferentially in high gas saturation zones, and leaving the heavier components behind in slower flow zones. In the case of channelling flow, compositional effects were less important since the permeability channel dominated the displacement. Both the ultimate oil recovery and component recovery are significantly and about equally reduced, when the underlying heterogeneity is of dominant influence. To summarise, compositional effects can have a very significant impact on the prediction of near-miscible CO2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channelling during CO2 near-miscible displacement can lead to behaviour that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. The complete dataset and results of this study are available online as a model case example for compositional flows in heterogeneous systems (Wang et al. in "The analysis of compositional effects on global flow regimes in CO2 near-miscible displacements in heterogeneous systems” dataset for paper SPE-190273, 2018. https://doi.org/10.17861/fc1c90bb-9d3f-4a6c-9170-7b7fe10ec7b9).

CO2 storage potential during CO2 enhanced oil recovery in sandstone reservoirs

CO2 can be sequestered in hydrocarbon reservoirs when it is injected for enhanced oil recovery (EOR) purpose. This study aims to experimentally evaluate the CO2 sequestration potential in sandstone reservoirs during CO2-EOR projects with a focus on the effect of active forces in the reservoir. To do so, a series of core flooding experiments at reservoir conditions were conducted using horizontal and vertical systems. A real light crude oil sample together with two native sandstone cores used here that were taken from a Malaysian oil field. The experiments were performed at near-miscible condition. Four secondary CO2 flooding tests were conducted through a composite core arrangement at various flow rates in a horizontal system to investigate the effect of viscous forces on the oil recovery and also the CO2 storage. Additionally, the gravity force effect was studied by conducting a gas (CO2) assisted gravity drainage (GAGD) test in a vertical system. The results showed that the highest oil recovery at all stages of CO2 flooding was obtained during the GAGD test. Considering flooding in the horizontal system, the ultimate recovery factor (RF) was significantly improved by increasing the CO2 injection rate. Furthermore, by investigating the interplay between the governing forces during CO2 injection, it was found that a higher oil RF was obtained at a lower capillary number at early stages of the test, while the CO2 injection rate (viscous forces) should be increased after breakthrough to overcome the capillary forces and recover more oil. In terms of CO2 storage, it was useful to quantify CO2 storage efficiency and CO2 trapping mechanisms which was mainly solubility trapping. Therefore, CO2 solubility in crude oil was also measured at various pressures. The gravitational effect in the GAGD test resulted in the highest CO2 storage percentage. While in the horizontal system, the storage efficiency of CO2 decreased with increasing the injection rate. Furthermore, a dimensionless number was proposed to investigate the combined effect of active forces in addition to CO2 diffusion during CO2 flooding operations. Finally, two correlations based on the combined dimensionless number were introduced to predict oil RF and CO2 storage efficiency for near-miscible CO2 flooding processes.

Experimental and numerical evaluation of CO2 huff-n-puff processes in Bakken formation

Experimental and numerical techniques have been developed to evaluate performance of CO2 huff-n-puff processes for unlocking resources from the Bakken tight oil formations. Experimentally, a series of coreflooding tests have been conducted by using core samples collected from the Bakken tight formation with a permeability range of 0.27–0.83mD. The performance of four recovery schemes (i.e., waterflooding, immiscible CO2 huff-n-puff, near-miscible CO2 huff-n-puff, and miscible CO2 huff-n-puff processes) has been comparatively evaluated. Theoretically, numerical simulation is performed to match the experimental measurements and then extended for evaluating field-scale CO2 huff-n-puff performance in the Bakken formation. Once the history matching on either the experimental measurements or the field geological model is completed, the tuned numerical model is then employed to optimize the injection pressure, soaking time, and production pressure, respectively. It is experimentally found that the waterflooding process leads to a higher oil recovery factor of 51.5% in comparison with the immiscible CO2 huff-n-puff process, while both the near-miscible and miscible CO2 huff-n-puff processes result in a higher recovery efficiency with the final recovery factors of 63.0% and 61.0% of OOIP, respectively. As for the history matched reservoir geological model, either a higher injection pressure or a lower production pressure usually results in better recovery performance but lower than the corresponding experimental measurements, while recovery factor can be optimized if soaking time of 15days is applied in this study.

Performance evaluation and mechanisms study of near-miscible CO2 flooding in a tight oil reservoir of Jilin Oilfield China

Jilin Oilfield has been conducting a large-scale demonstration project on CO2 EOR and storage in China. CO2 separated from a nearby natural gas reservoir (15–30 vol% CO2) has been injected into the northern part of H-59 oil block with the permeability of 3.0 mD and porosity of 12.7%. After six years of operation, nearly 0.26 million ton of CO2 (0.32 Hydrocarbon Pore Volume) has been injected under a miscible or near-miscible flooding mode with CO2 utilization efficiency of 6.3 MScf/bbl, and an expected enhanced oil recovery of over 10% would be achieved. A systematic and thorough reservoir surveillance program has been conducted to facilitate efficient operation and evaluation. Casing annulus gas composition was analyzed to monitor gas breakthrough in production wells as well as the gas tracer to detect CO2 flow across the reservoir. Bottom hole pressure (BHP) survey of producers and fluid sampling were combined to evaluate the miscibility effect in conjunction with the injection-production data analysis. It is revealed that the designed miscible flooding is best described as near-miscible due to the large pressure difference between injector and producer, and the gas channeling and fractures/heterogeneities cause the miscibility instability. Gravity-stabilized displacement may develop in the downdip part of the reservoir during the flooding process. The vaporization and condensation effects have been observed and confirmed through laboratory core flooding and field produced oil compositions analysis. A key insight from the evaluation study is that CO2 near-miscible flooding is more flexible and easily realizable relative to miscible, particularly in the tight oil reservoir. Further study would be necessary to optimize the reservoir development program under the near-miscible flooding design.

A simulation research on evaluation of development in shale oil reservoirs by near-miscible CO2 flooding

Shale oil is a key resource that could mitigate the impending energy shortage in the future. Despite its abundance in China, studies on shale oil are still at the preliminary stage. Shale oil development through CO2 flooding has been successfully implemented in the United States. Therefore, the mechanics of CO2 flooding in shale oil reservoirs should be investigated. This study applies a simulation method to evaluate the development efficiency of CO2 flooding in shale oil reservoirs. Near-miscible CO2 flooding can effectively develop shale oil. After 20 years, recovery could improve by up to 9.56% as a result of depletion development under near-miscible CO2 flooding with 0.5% pore volume gas injection. Horizontal well injection is better than vertical well injection in terms of sweep efficiency and recovery. Cyclic gas injection is superior to continuous gas injection because the former reduces gas channelling. Thus, the use of horizontal wells with near-miscible cyclic gas injections has the potential to effectively develop shale oil reservoirs.

Marangoni flow: An unknown mechanism for oil recovery during near-miscible CO2 injection

Abstract Previously, we investigated the effect of interfacial tension gradient induced convective fluxes – Marangoni flow – on the recovery of bypassed oil during near-miscible and immiscible CO 2 injection in a 1D-matrix/fracture model. In the current study, the impact of Marangoni flow on oil recovery is studied during CO 2 injection into a matrix (flooding) using experimental results combined with analytical calculations. CO 2 injection is conducted at different pressures below the critical point where the oil/gas interface exists. The ternary system of CO 2 /C10/C3 was compared with a binary system of CO 2 /C10 as the zero level of the Marangoni flow. In this manner, the influence of other conventional recovery mechanisms can be simultaneously eliminated. The results show that there is good agreement between the recovery differences of these two systems and the Marangoni number derived from analytical estimations. Therefore, in the multi-component systems of hydrocarbons, where IFT increases with CO 2 concentration, Marangoni flow improves oil recovery by about 35%. During CO 2 flooding, it postpones the breakthrough time by conducting the oil towards the gas channel and guaranteeing the continuity of recovery. The level of recovery enhancement in the ternary system is proportional to the Marangoni number, and is maximized at a near-critical state, but vanishes towards the critical point. In far from critical region, the Marangoni effect is relatively weak.

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.

Effect of Marangoni flow on recovery of bypassed oil during CO2 injection

We have experimentally investigated the effect of interfacial tension gradient induced convective fluxes – Marangoni flow – on the recovery of bypassed oil during near-miscible and immiscible CO2 injection in a 1D-matrix/fracture model. Hydrocarbon systems of components were designed such that the existence of Marangoni flow and its direction with respect to fracture could be managed. The results show reasonable agreement between recovery changes and Marangoni number, indicating the significant impact of Marangoni flow on the recovery of bypassed oil in porous media under high-pressure high-temperature conditions. The results of our experiments introduce the so-far neglected Marangoni phenomenon as a considerable mechanism of oil recovery in near-critical conditions.

Physicochemical Characterization of Produced Oils and Gases in Immiscible and Miscible CO2 Flooding Processes

In this paper, the oil and gas samples produced from tight sandstone reservoir core plugs in immiscible, near-miscible, and miscible CO2 flooding processes at the reservoir temperature are experimentally characterized. First, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) of the light crude oil–CO2 system. Second, a total of five CO2-coreflood tests are conducted under immiscible, near-miscible, and miscible conditions to thoroughly study the characteristics of the produced oils and gases during each CO2 flooding process. In the immiscible case (Pinj < MMP), the produced oil becomes heavier and heavier during CO2 injection in terms of its density, viscosity, molecular weight, and hydrocarbons (HCs). The produced gas contains up to 84–96 mol % HCs (dominantly C4–7) extracted from the light crude oil by CO2 at the beginning and 85–100 mol % CO2 at the end of CO2 injection. In the near-miscible case (Pinj ≈ MMP), the heaviest oil is produced at 0.4 pore volume (PV) of the injected CO2, which is followed by a relatively lighter produced oil from CO2 breakthrough (BT) at 0.6 PV to the end of CO2 injection. The produced gas has 40–60 mol % HCs (dominantly C5–8) at the beginning and then consists of almost 100% CO2 after CO2 BT. In the miscible case (Pinj > MMP), the produced oil becomes much lighter and lighter with the injected PV. The produced gas contains 20–75 mol % HCs (mainly C5–8) at the very beginning and quickly becomes almost 100% CO2 after CO2 BT. In summary, this laboratory study provides the comprehensive characterization of the produced fluids in three distinct CO2 flooding processes. These new experimental data will help to better evaluate the field-scale CO2-enhanced oil recovery (EOR) processes and design the future CO2-EOR projects as well.

Comparative evaluation of immiscible, near miscible and miscible CO2 huff-n-puff to enhance oil recovery from a single matrix–fracture system (experimental and simulation studies)

In this paper, the performance and efficiency of improved oil recovery in fractured porous media utilizing the cyclic CO2 injection process (otherwise known as CO2 huff-n-puff) are examined for immiscible, near-miscible and miscible pressure conditions. The main approach involved the comparison of simulation results to experimental data obtained from a laboratory CO2 huff-n-puff model. Previous experimental studies performed showed promising results for CO2 huff-n-puff process in a fractured model saturated with light oil. In order to upscale the experimental results and perform further studies, fully compositional simulation software was utilized to simulate the cyclic CO2 injection experiments. Prior to this, the phase behavior of a mixture of CO2 and decane (nC10) was studied and minimum miscibility pressure (MMP) of CO2–nC10 was found to be 1058psi, which was in good agreement with experimental results obtained by rising bubble apparatus (RBA) and visual tests [9,10]. The results of six sets of huff-n-puff experiments performed under constant temperature of 35°C and a wide range of pressures from 250 to 1500psi were simulated. Simulation results were in good agreement with those obtained experimentally. Throughout these studies, it has been found that near-miscible CO2 huff-n-puff process can improve the recovery factor from the light oil saturated experimental model by a factor of two. It was also discovered that the injection of CO2 at pressures much higher than the MMP was not significantly beneficial to recovery factor and may require further economical analysis. Also, cyclic CO2 performance improved greatly when conditions transitioned from immiscible to near-miscible (i.e. operating and injection pressures were increased to 1000psi) as indicated by a sharp increase in oil production.

A Laboratory Study on Near-Miscible CO2 Injection in Steelman Reservoir

Abstract Miscible flooding is considered unsuitable for some reservoirs in southeast Saskatchewan because of high C)2 minimum miscibility pressure or operating pressure constraints. Therefore, the effectiveness of near-miscible C)2 injection was assessed for the Steelman reservoir in a laboratory study. The minimum miscibility pressures (MMP) were estimated for Steelman reservoir fluids with pure C)2 and C)2-hydrocarbon gas mixtures, the partially flashed reservoir fluids and the dead oils with pure C)2. The results of MMP studies demonstrated (1) addition of ethane or propane can reduce C)2 MMP greatly; and (2) achieving a miscible C)2 flood in the Steelman reservoir could be possible at a lower operating pressure than the measured C)2 MMP, by partially depleting the reservoir. Asphaltene flocculation tests showed that, after the onset point, flocculation increased linearly with gas concentration, but that the presence of brine had a negligible effect. Three tertiary C)2 coreflood tests were conducted with Steelman reservoir fluids at the reservoir temperature. These results showed that the microscopic displacement efficiency during the C)2 injection stage improved with the operating pressure in the near-miscible region, but no dramatic change in oil recovery was observed with a change in operating pressure. Introduction The Steelman pool, located about 200 km southeast of Regina, Saskatchewan, was discovered in 1954. Covering approximately 370 km2, the field was estimated to contain over 134 million m3 of light oil in the Frobisher and Midale beds located at a depth of about 1,400 m. Most of the reservoirs in the Midale beds, which contain about 83﹪ of the reserves of the pool, have been under waterflood for over 20 years and have nearly reached the estimated production limit by primary and waterflood(1). For achieving additional oil recovery and consequent financial benefits, the development of tertiary enhanced oil recovery (EOR) techniques, such as C)2 flooding, is essential. Miscible C)2 flooding is a proven enhanced oil recovery technique(2). Over the last decade, C)2 injection has become the leading EOR process for light oil(3). In Canada, the industry interest in C)2 flooding is evidenced by Shell Canada's C)2 pilot tests(4, 5), a miscible C)2 flood at Joffre field in Alberta(6), and the implementation of PanCanadian's Weyburn C)2 injection project(7). Additional field applications are expected to be initiated in southeast Saskatchewan and other regions when C)2 sources are available. Miscible C)2 displacement offers the greatest oil recovery potential, but it can only be achieved at a pressure greater than a certain minimum referred to as the minimum miscibility pressure (MMP). The effect of solution gas on the development of miscibility is not well understood, as is reflected by the lack of a consensus in the literature. Rathmell et al.(8) found that C)2 MMP is related to the volatile and intermediate fractions of the oil. Yelling and Metcalfe(9) found from their experimental study that, for a saturated reservoir oil, areal variation in gas-oil ratio (GOR) will result in an areal variation in the C)2 MMP. They pointed out that the C)2 MMP determined for a pilot area may not apply to the rest of the field.