Near-miscible Displacements Research Articles

The potential blockage during CO2 displacement in the high pour point oil reservoir

CO2 displacement is a common technique for the enhanced oil recovery and simultaneously alleviates the greenhouse effect. However, the recent applications of CO2 displacement focus on the formations where the fluid and reservoir properties could not reach absolute miscibility. The reactions between CO2 and high pour point crude oil during the near-miscible displacement process would be far more complex. In this study, slim-tube and one-dimensional core (sand-filling model, splicing long core) displacement experiments were carried out. Group component analysis and saturated hydrocarbon analysis were applied during the process and the possibility of organic solid deposition and blockage was deduced. The indicator of permeability reduction rate of long core was introduced and used to evaluate the impact of the deposition of each short core on the permeability. Through analysis and comparison, deposition and blockage occurred in the front and middle of the long core, and the maximum permeability reduction rate reached about 0.04%. The results showed that although near-miscible displacement could improve the oil recovery, there was still the possibility of potential blockage which should be carefully considered in the design of the gas injection scheme.

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.

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).

Relative Permeability of Near-Miscible Fluids in Compositional Simulators

Miscible gas injection is one of the most effective enhanced oil recovery techniques. There are several challenges in accurately modeling this process, which occurs in the near-miscible region. The adjustment of relative permeability for near-miscible processes is the main focus of this work. The dependence of relative permeability on phase identification can lead to significant complications while simulating near-miscible displacements. We present an analysis of how existing methods incorporate compositional dependence in relative permeability functions. The sensitivity of the different methods to the choice of reference points is presented with guidelines to limit the modification of the relative permeabilities to physically reasonable values. We distinguish between the two objectives of reflecting near-miscible behavior and ensuring smooth transitions across phase changes. We highlight an important link that combines the two objectives in a more general framework. We make use of Gibbs free energy as a compositional indicator in the generalized framework. The new approach was implemented in an automatic differentiation general purpose research simulator and tested on a set of near-miscible gas-injection problems. We show that including compositional dependencies in the relative permeability near the critical point impacts the simulation results with significant improvements in nonlinear convergence.

Equation of State for Relative Permeability, Including Hysteresis and Wettability Alteration

SummaryCommercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation.This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.

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.

An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

A Laboratory and Numerical-Simulation Study of Co-Optimizing CO2 Storage and CO2 Enhanced Oil Recovery

Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.

Phase Behaviour, Fluid Properties and Recovery Efficiency of Immiscible and Miscible Condensate Displacements by SCCO2 Injection: Experimental Investigation

This paper presents a quantitative investigation of the interfacial tension dependent relative permeability (IFT-DRP) and displacement efficiency of supercritical CO2 injection into gas-condensate reservoirs. A high-pressure high-temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores at a constant reservoir temperature of 95°C and displacement velocity of 10 cm/h. This investigation covers immiscible displacements (1100 and 2100 psi), near-miscible displacement (3000 psi) and miscible displacements (4500 and 5900 psi). The coreflooding results demonstrated that displacement pressure is a key factor governing the attainment of optimum sweep efficiency. The ultimate condensate recovery increased by almost threefold when CO2 was injected at near-miscible conditions (i.e., 23.40% ultimate recovery at 1100 psi compared to 69.70% at 3000 psi). Miscible flooding was found to give the optimum condensate recovery (9% extra ultimate recovery compared to near-miscible injection). Besides improving the ultimate recovery, miscible floods provided better mobility ratios and delayed gas breakthrough (0.62 PV BT at 5900 psi compared to 0.21 PV BT at 1100 psi). In addition to the elimination of IFT forces in miscible displacements, favourable ratios of fluid properties and phase behaviour relationships between the SCCO2 and condensate were believed to be the driving force for the improved recovery as they provided a stabilising effect on the displacement front and stimulated swelling of the condensate volume. This paper incorporates the theoretical aspects of phase behaviour and fluid properties that largely affect the microscopic displacement efficiency and serves as a practical guideline for operators to aid their project designs and enhance their recovery capabilities.

Evaluation of the Miscibility and Contribution of Flue Gas to Oil Recovery Under High Pressure Air Injection

Abstract The improvement in the recovery of light oil by high pressure air injection (HPAI) involves a combination of complex processes, each contributing to the overall recovery. One of these processes is the spontaneous ignition of the air-oil mixture with complete oxygen utilization. This process generates flue gases, which are in contact with the reservoir oil at the displacement front. An experimental study was carried out to investigate the mechanism and contribution of miscible displacement, by in situ generated flue gases, to the recovery of light oil in reservoirs undergoing HPAI. The flue gas displacements were carried out on recombined reservoir oil in a slim tube apparatus at a reservoir temperature of 116 º C and pressures ranging from 27.77 MPa (4,028 psi) to 46.06 MPa (6,680 psi). Results show that miscibility could not be achieved between the test oil and flue gases under the test conditions. Experiments conducted between 41.28 MPa (5,987 psi) and 45.04 MPa (6,532 psi), however, gave an indication of near-miscible displacement of the test oil. The flue gases displaced the oil in a forward contacting extraction process, resembling a combined vapourizing/condensing multi-contact gas drive mechanism. The relatively high recovery, high extraction of oil components, and the pattern of flow behind the displacement front, exhibited at high pressures, demonstrate that near-miscible displacement by in situ generated flue gases could significantly contribute to oil recovery in light oil reservoirs undergoing HPAI. Introduction Air injection into high pressure reservoirs is an emerging technology for the enhanced recovery of light oils. It is probably the best hope for improved recovery from the world's ever declining reserves of conventional oil and, in particular, the profitable enhanced recovery of the enormous quantities of residual oil trapped in depleted and mature waterflooded light oil reservoirs(1, 2). Air is the most inexpensive, available gas that can be used to accelerate oil recovery. Air injection is especially applicable in low porosity and low permeability reservoirs where water injectivity is extremely low(3). Apart from providing a better interfacial tension (IFT) response(4), air injectivity is about ten times that of water in terms of reservoir volume(5), making air injection more advantageous than water injection in deep, tight, high pressure reservoirs. A number of successful high pressure air injection projects in light oil reservoirs have been documented in the literature(5–11). Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: reservoir pressurization, oil swelling, immiscible gas displacement, and superextraction when operating above the critical point of water. In addition to this, spontaneous oil ignition with complete oxygen utilization(2, 12, 13) and near-miscibility/miscibility of the in situ generated flue gases with the reservoir oil(13) are possible and advantageous processes. Apart from reservoir pressurization, oil swelling, and immiscible gas displacement, the mechanism by which the other processes occur in the reservoir and their contribution to oil recovery have not been discussed in clear terms in the technical literature(14).

Proper Use of Equations of State for Compositional Reservoir Simulation

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized to be experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Summary Equation-of-state (EOS) compositional reservoir simulation is an accurate and powerful means to model complicated phase and flow behavior involved in the displacement of oil and gas in porous media. The use of EOS simulation becomes even more effective when the process involves solvent injection for miscible or near-miscible displacement of crude oil in reservoirs. The current trend of combining the simulation of reservoirs and surface facilities increases the demand for the use of EOS compositional models. One key to proper use of compositional simulators is development of an EOS for describing the phase behavior of the fluids. This paper is a summary of experiences and developments in the use of EOS's for compositional reservoir simulation studies. The reader is referred to the recent monograph by Whitson and Brulé1 for a more complete treatment of the volumetric and phase behavior of petroleum fluids and the use of EOS's to model these fluids. Introduction When the displacement process depends on pressure and fluid composition, an EOS should be used to simulate the equilibrium mass transfer between phases and the pressure/volume/temperature (PVT) behavior of the fluids. PVT laboratory measurements are made on only a small portion of the composition path encountered throughout the displacement, whereas an EOS can be used to predict behavior for the entire composition path and pressure range of the process. Many field development projects have strong composition dependence, such as production from gas/condensate reservoirs, miscible and near-miscible gas injection, or water-alternating-gas injection for enhanced oil recovery. Until very recently, industry practice was to use a black-oil model and/or its modified versions2,3 or a limited-composition reservoir simulator4,5 to approximate the complicated phase behavior. These simplified approaches require less computer time and memory and can provide a quick preliminary evaluation of reservoir performance. However, efforts by industry and universities have led to rapid advancements in parallel-computer hardware and software during the last several years, which have increased simulation efficiency considerably6–9 and now make compositional simulation practical. Also, most of the commercially available EOS compositional simulators and in-house models have been improved significantly in terms of robustness, efficiency, and features. More frequent use of EOS compositional simulators should be expected in the future. However, uncertainties still exist that are associated with the use of an EOS to model petroleum reservoir fluids because of the complicated nature of such fluids and limitations of the most commonly used EOS's. Tuning the adjustable EOS parameters to match experimental fluid PVT data is a common practice. The proper use of EOS models for reservoir applications has been an active research topic since the 1970's. Although significant progress in this area has been made, engineers still face several challenging questions: How many fluid components should be used? How much experimental data and what kind of data are needed to tune an EOS? How good is the predictive power of an EOS that matches all of the experimental data available? What are limitations of the commonly used EOS's for hydrocarbons when the gas or oil contains significant concentrations of components other than hydrocarbons? Which EOS should be used when more than one option is available in a reservoir simulator? Representative-Sample Collection The accuracy of any EOS model depends on the quality of the laboratory PVT data and procedures used to obtain the EOS parameters. The value of the PVT data depends on the quality of the fluid samples. They must be representative of the reservoir fluid. Three common methods are used to sample the reservoir fluid. Downhole Sampling. A sample collector with a capacity of several hundred cubic centimeters is used to obtain a fluid sample from within the wellbore. The downhole flowing pressure at the sampling point must be greater than the saturation pressure of the fluid so that the sample is a single phase. At least three fluid samples should be collected to determine the appropriate fluid sample for the PVT measurements. Wellhead Sampling. A fluid sample can be collected directly from the wellhead. The fluid needs to be in the single-phase region at wellhead flowing conditions. Normally, the sample needs to be taken at a pressure of at least 100 psi greater than the bubblepoint to be valid. Again, taking multiple samples is recommended.

Effect of Injectant Composition and Pressure on Displacement of Oil by Enriched Hydrocarbon Gases

SummaryReservoir-condition phase-behavior and tertiary-gasflood studies have been conducted in the laboratory to investigate the effect of hydrocarbon-injectant composition and pressure on oil-displacement efficiency. Lower oil-recovery efficiencies and lower injectant mobilities have been observed at lower enrichment levels and/or at lower pressures. Coreflood oil recoveries, however, remained high for gas injectants that are below multiple-contact miscible (MCM) with the oil. These results suggest that near-miscible hydrocarbon-gas-injection processes show promise and that there may be a tradeoff between local oil-displacement efficiency and gas-sweep efficiency in near-miscible displacements in the field.