Phase Behavior Of Reservoir Fluids Research Articles

Investigating phase dynamics of reservoir fluids in CO2 huff-n-puff enhanced oil recovery

This investigation delves into the dynamic phase behavior of reservoir fluids during CO2 huff-n-puff processes, a critical aspect of enhanced oil recovery. Utilizing numerical simulations, the study examines the formation and evolution of four key fluid phase zones, including a miscible-phase oil zone and two flanking miscible-phase condensate gas zones, shedding light on the intricate interactions between CO2 and reservoir fluids. The research methodically addresses the spatial and temporal dynamics of these zones, providing a framework for understanding their evolution. It delves into the complex interplay of fluid properties and phase states, revealing the fundamental role of component migration in influencing phase behavior. This exploration not only uncovers the mechanisms driving fluid dynamics in the CO2 huff-n-puff process but also emphasizes the broader implications for improving oil recovery strategies. By offering a comprehensive view of the factors governing phase behavior, the study contributes to the field's knowledge, suggesting avenues for future research and practical application in enhancing oil recovery efficiency.

Fluid phase behavior in multi-scale shale reservoirs with nano-confinement effect

Shale reservoirs are featured by widely distributed micro-scale fractures and nano-scale pores. The phase behavior of reservoir fluids in these complex environments remains uncertain. Hence, an efficient model is developed to investigate the fluid phase behavior in multi-scale shale reservoirs based on a pore-size-dependent equation of state. The porous space is discretized into specific sizes of nanopores and fractures regions. Phase equilibrium calculations for pure components, binary mixtures and multi-component shale oils show that adsorption and critical properties shifts display opposite effects on a fluid distribution, and the shifts in the critical properties are the main reason for more lighter components present in nanopores. The nano-confinement effect enhances the ability of CO2 to enter nanopores. An innovative multi-scale model of partial equilibrium is developed to explore changes in fluid properties during pressure depletion. The results reveal that gas appears in the fracture region, while the confined fluids within nanopores are always kept in the oil phase. Lighter components within nanopores are rapidly released as pressure drops. However, the content of heavier components within nanopores gradually decreases if the pressure stabilizes for a while, meaning that a slow pressure drop is more conducive to the recovery of shale oil from nanopores.

Research Progress on CO2 Capture, Utilization, and Storage (CCUS) Based on Micro-Nano Fluidics Technology

The research and application of CO2 storage and enhanced oil recovery (EOR) have gradually emerged in China. However, the vast unconventional oil and gas resources are stored in reservoir pores ranging from several nanometers to several hundred micrometers in size. Additionally, CO2 geological sequestration involves the migration of fluids in tight caprock and target layers, which directly alters the transport and phase behavior of reservoir fluids at different scales. Micro- and nanoscale fluidics technology, with their advantages of in situ visualization, high temperature and pressure resistance, and rapid response, have become a new technical approach to investigate gas–liquid interactions in confined domains and an effective supplement to traditional core displacement experiments. The research progress of micro–nano fluidics visualization technology in various aspects, such as CO2 capture, utilization, and storage, is summarized in this paper, and the future development trends and research directions of micro–nano fluidics technology in the field of carbon capture, utilization, and storage (CCUS) are predicted.

Predictive Modeling of Phase Behavior of Reservoir Fluids under Miscible Gas Injection Using the Peng-Robinson Equation of State and the Aromatic Ring Index.

Improved correlations among critical temperature, critical pressure, and acentric factor are developed for an extensive database of hydrocarbons. The correlations rely on measurements of molecular weight and refractive index at ambient conditions and utilize the concept of the aromatic ring index (ARI) recently developed by Abutaqiya et al. as a distinctive characterization factor for nonpolar hydrocarbons [Abutaqiya M. I. L.Aromatic Ring Index (ARI): A Characterization Factor for Nonpolar Hydrocarbons from Molecular Weight and Refractive Index. Energy Fuels2021, 35( (2), ), 1113-1119.]. The new correlations are then implemented for modeling the phase behavior of a variety of oils under miscible gas injection in a fully predictive manner using the Peng-Robinson equation of state (PR EOS). The results indicate that the proposed modeling framework yield accurate predictions for bubble pressure of oil/gas blends with an average absolute deviation of 6.4% for a wide variety of oils and injection gases including lean, rich, H2S, CO2, and N2. Additionally, an interesting crossover behavior in the phase envelope of live oils under CO2 injection is observed using PR EOS. This behavior has been previously reported in the literature for modeling results using PC-SAFT EOS and seems to be characteristic of CO2.

Experimental Investigation of Phase Behavior of Condensate Gas and Crude Oil System in Underground Gas Storage

Abstract The phase behavior of reservoir fluids is crucial for the smooth operation of an underground gas storage (UGS). In this work, three experiments were conducted to investigate the phase behavior of condensate and crude oil systems within different development stages of gas storage in Bohai Bay Basin of eastern China. In stage 1, constant volume depletion (CVD) test was conducted to simulate the interaction of the original condensate gas-live oil system. In stage 2, the phase behavior of a series of mixtures of live oil with 47.5, 58.3, 69.9, and 77.4 mol% of condensate gas was studied by constant composition expansion (CCE) test. In stage 3, a new experiment was designed to study the mass transfer and phase behavior during cyclic injection-production process of the underground gas storage. The results from the CVD test describe the effect of each pressure stage on produced gas composition and equilibrium oil properties in the condensate crude oil system. The results of the CCE test indicate that condensate gas can expand the oil and improve the properties. The results of cyclic injection-production experiment demonstrate that the mass transfer in condensate gas and oil system is a dual mechanism of condensation and vaporization. With the increase of the cycle, the intermediate components of oil phase are enriched and the heavy components decreases. After four cycles, the oil and gas interphase mass transfer reaches dynamic equilibrium. In addition, test results show that multicycle operation is beneficial to improve the oil properties. This work is of great significance to understand the phase transition mechanism of underground gas storage, which provides a basis for other researchers to further update and improve the EOS model.

An Integrated Mass Balance Approach for Assessing Hydrocarbon Resources in a Liquid-Rich Shale Resource Play: An Example from Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin

Petroleum resource assessment using reservoir volumetric approach relies on porosity and oil/gas saturation characterization by laboratory tests. In liquid-rich resource plays, the pore fluids are subject to phase changes and mass loss when a drilled core is brought to the surface due to volume expansion and evaporation. Further, these two closely related volumetric parameters are usually estimated separately with gas saturation inferred by compositional complementary law, resulting in a distorted gas to oil ratio under the circumstances of liquid hydrocarbon loss from sample. When applied to liquid-rich shale resource play, this can lead to overall under-estimation of resource volume, distorted gas and oil ratio (GOR), and understated resource heterogeneity in the shale reservoir. This article proposes an integrated mass balance approach for resource calculation in liquid-rich shale plays. The proposed method integrates bulk rock geochemical data with production and reservoir parameters to overcome the problems associated with laboratory characterization of the volumetric parameters by restoring the gaseous and light hydrocarbon loss due to volume expansion and evaporation in the sample. The method is applied to a Duvernay production well (14-16-62-21W5) in the Western Canada Sedimentary Basin (WCSB) to demonstrate its use in resource evaluation for a liquid-rich play. The results show that (a) by considering the phase behavior of reservoir fluids, the proposed method can be used to infer the quantity of the lost gaseous and light hydrocarbons; (b) by taking into account the lost gaseous and light hydrocarbons, the method generates an unbiased and representative resource potential; and (c) using the corrected oil and gas mass for the analyzed samples, the method produces a GOR estimate close to compositional characteristics of the produced hydrocarbons from initial production in 14-16-62-21W5 well.

Effect of Nanoscale Pore-Size Distribution on Fluid Phase Behavior of Gas-Improved Oil Recovery in Shale Reservoirs

SummaryThe improved oil recovery (IOR) of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as carbon dioxide (CO2) and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low-permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of a gas-injection operation. Shale reservoirs typically have macroscale to nanoscale pore-size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores, the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain.In this study, we investigate the nanoscale pore-size-distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs. A case of Anadarko Basin shale oil is used. The pore-size distribution is discretized as a multiscale system with pores of specific diameters. The phase equilibria of methane injection into the multiscale system are calculated. The constant-composition expansions are simulated for oil mixed with various fractions of injected gas. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure to less than the bubblepoint turns it into the subcritical state. The bubblepoint is generally lower than the bulk and the degree of deviation depends on the amount of injected gas. The modeling of confined-fluid swelling shows that fluid swelled from nanopores is predicted to contain more oil than the swelled fluid at bulk state.

Прогнозирование термодинамических свойств и фазового поведения пластовых флюидов для проектирования разработки месторождений нефти и газа

Прогнозирование термодинамических свойств и фазового поведения пластовых флюидов для проектирования разработки месторождений нефти и газа

A novel MLP-ANN approach to predict solution gas-oil ratio

The better understanding and estimation of reservoir fluids properties have straight effects on accuracy of different processes such as simulation, well testing, and material balance calculations, so importance of accurate estimation of PVT properties such as solution gas-oil ratio is obvious. To this end, in the present paper, multilayer perceptron artificial neural network (MLP-ANN) is used as a novel predictive tool to estimate solution gas-oil ratio in terms of temperature, bubble point pressure, oil American Petroleum Institute gravity API, and gas specific gravity. Therefore, a total number of 1,137 experimental solution gas-oil ratios has been gathered from reliable databank for evaluation of model outputs. The different graphical and statistical analyses such as determination of average absolute relative deviation (AARD), the coefficient of determination (R2) and root mean square error (RMSE) were used to evaluate the performance of MLP-ANN algorithm. The comparisons show that MLP-ANN algorithm has great accuracy in prediction of solution gas-oil ratio, so it can be used as a simple tool to predict phase behavior of reservoir fluids.

Experimental study of the phase behavior of methane and crude oil mixtures

Phase behavior of reservoir fluids is crucial for an efficient production development project. In this paper, a new dataset of phase transitions of Brazilian pre-salt crude oil mixed with methane systems is presented and phase behavior discussed under different analytical technics. A series of mixtures of a dead crude (API 28.0, 0.68 wt% of asphaltenes) with 65.0, 67.5, 70.0, 72.5, and 75.0 mol% of methane were studied by constant mass expansion in a PVT cell, coupled with a high-pressure microscopy (HPM). Pressure-volume data shows slight phase transition, with a not evident break due to difference on compressibility, specially by increasing methane molar content. For this reason, beside of visual observation, a near-infrared (NIR) transmittance was used for a proper identification of bubble point pressure. NIR transmittance also allow the detection of phase transitions above bubble point, that was confirmed by intermediate of by HPM analysis. A dispersion of fine particles was detected, and it was associated with asphaltenes onset, for the systems with high content of gas (72.5 and 75.0 mol% of methane). NIR transmittance along with micrographs taken during system pressurization confirm a low asphaltene hysteresis redissolution, with no flocs and mayor aggregates formation and rapid redissolution after system pressurization. This phenomenon could be related to the low content of asphaltenes on the crude oil sample.

Molecular simulation of the constant composition expansion experiment in shale multi-scale systems

The phase behavior of hydrocarbons in shale reservoirs has garnered increasing attention in the petroleum industry. Significant differences in the phase behavior of petroleum fluids between conventional reservoirs and shale reservoirs have been observed. Because of the existence of nano-scale porous media in shale reservoirs, there are substantial surface fluid interactions that can lead to a heterogeneous distribution of molecules and an alteration of the fluid phase behavior. In this work, for the first time, we use molecular simulations to investigate the confinement effect on the phase behavior of reservoir fluids in a multi-scale (nano-scale + macro-scale) media. The model has a confined region that mimics the nano-scale porous media and a bulk region that represents the macro-scale porous media (macropores and fractures) in shale reservoirs. For the first time, we use the Gibbs ensemble Monte Carlo (GEMC) simulation at imposed pressures to simulate the constant composition expansion (CCE) experiment for multi-component hydrocarbon mixtures in a multi-scale porous media. Our results show that because of the confinement effect, the composition of the bulk and the confined regions differ significantly. In our molecular simulations, the composition of the lighter components in the bulk region increases, while heavier components are mainly trapped in the confined region. These changes in the composition cause a significant shift or disappearance of the saturation pressure in the bulk region of the multi-component multi-scale hydrocarbon systems.

New empirical correlations for predicting Minimum Miscibility Pressure (MMP) during CO2 injection; implementing the Group Method of Data Handling (GMDH) algorithm and Pitzer’s acentric factor

Miscible injection of carbon dioxide (CO2) with ability to increase oil displacement as well as to reduce greenhouse effect has become one of the pioneering methods in Enhanced Oil Recovery (EOR). Minimum Miscibility Pressure (MMP) is known as a key indicator to ensure complete miscibility of two phases and maximum efficiency of injection process. There are various experimental and computational methods to calculate this key parameter. Experimental methods provide the most accurate and valid results. However, such methods are time consuming and expensive leading researchers to use mathematical methods. Among computational methods, empirical correlations are the most straight-forward and simple tools to precisely estimate MMP, especially for gases with impurities. Furthermore, in predicting the miscibility state of oil–gas system, phase behavior is a vital issue which should be taken into account to achieve reliable results. In this regard, equations of state have an indisputable role in predicting the phase behavior of reservoir fluids. Remarkable improvements have been introduced to elevate performance of equations of state, based on Pitzer’s acentric factor. Hereupon, this study aims to enumerate acentric factor of injected gas (impure CO2) as a correlating parameter alongside conventional parameters including reservoir temperature, oil constituents (molecular weight of C5+, ratio of volatiles to intermediates) and critical properties of injected gas (pseudo-critical pressure & temperature). Thus, in this study an effective empirical correlation is created, implementing the Group Method of Data Handling (GMDH) algorithm along with including the acentric factor of injected gas, which eventuated to precise predictions of MMP for impure CO2 injection. The GMDH is one of the most robust mathematical modeling methods for predicting physical parameters using linear equations. A comparison with well-known correlations, demonstrated at least 2% improvement in average absolute error with enumerating the acentric factor and the final error was equal to 12.89%.

Multiscale Fluid-Phase-Behavior Simulation in Shale Reservoirs Using a Pore-Size-Dependent Equation of State

Summary The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. The uncertainty in phase behavior is currently one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macroscale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nanoscale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood. In this paper, we present a study on the effect of pore-size distribution on the phase behavior of shale-reservoir fluids in a multiscale-pore system. The global fluid-phase equilibria among different sizes of pores are simulated. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid/pore-wall surface interaction are determined by experimental results from differential-scanning calorimetry (DSC) and isothermal adsorption of species C1–14. The multiscale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant-composition expansions (CCEs) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed “apparent” bubblepoint pressure. Below the bubblepoint, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multistage expansions. In the end, large amounts of intermediate-to-heavy hydrocarbons are retained in nanopores, implying a significant oil-recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scale nanopores (<5 nm).

A New Three-Phase Flash Algorithm Considering Capillary Pressure in a Confined Space

Tight/shale reservoirs are extensively containing nanopores, and the confined space in nanopores can greatly alter the phase behavior of reservoir fluids due to the strong capillarity effect. Many researches have been recently conducted to investigate the effect of capillary pressure in nanopores on altering the oleic-vapor two-phase equilibria. Few attempts have been made to describe the effect of capillarity on the aqueous-oleic-vapor three-phase equilibria. This work proposes a new algorithm for performing three-phase pressure-temperature (P-T) flash coupled with capillary effect. This algorithm considers two capillary pressures that exist across the two interfaces dividing the three phases in a nanopore. When describing the three-phase equilibria, two types of reservoir wettability are considered: water-wet formation and oil-wet formation. In each case, distribution of the three phases in a nanopore is determined based on the spreading coefficient which refers to the spreading ability of an oleic phase over the spreading ability of an aqueous phase. Example calculations are conducted to show the robustness of the new algorithm as well as to study the effect of capillarity on the three-phase equilibria. Computation results show that the three-phase P-T envelope for a given hydrocarbons/water mixture in a nanopore can be significantly altered by capillary pressure, but how the envelope moves will depend on the wettability of the nanopore and the spreading coefficient. The general trend is that both the upper branch (i.e., the oleic-aqueous/vapor-oleic-aqueous boundary) and the lower branch (i.e., the liquid-vapor/liquid-liquid-vapor boundary) of the three-phase envelope tend to move downward. Compared to the water-wet case, the oil-wet nanopore will shift the three-phase boundaries in a much larger degree. In addition to the alteration of the three-phase envelope, the presence of capillarity will also lead to the alteration of the phase fractions and phase compositions in the nanopore. Nanofluidic experiments should be conducted in the future to verify the findings obtained from the calculations.

Phase behavior modeling for gas condensate fluids with PC-SAFT and an improved binary interaction coefficient model

The accurate reservoir fluid phase behavior prediction in the gas condensate samples is still a challenging problem. The binary interaction coefficients are among the effective parameters in the phase behavior calculations. The binary interaction coefficients (BICs) are different for different equations of state. This work provides a solution to this problem with a modified version of Hudson-McCoubrey (HM) equation to determine the BICs of PC-SAFT, over a number of real gas condensate samples.The modeling procedure in this work includes two separate steps; in the first step, the proposed binary interaction estimation models parameters are regressed and in the second step, the prepared models are used, to evaluate the performance under phase behavior prediction feedback with different binary mixtures and real gas condensate samples. The modeling results are presented for PC-SAFT with the new BICs models and original HM in comparison to the experimental data and Peng-Robinson equation of state (with a common interaction coefficients set). The experimental data for the liquid dropouts and dew point pressures for different real gas condensate fluids are used from published data in the literature.The average absolute deviations percent (AAD%) for the dew point pressure prediction over the evaluation samples data, by PR is 20.8, by PC-SAFT with HM BICs, AAD% is 18.0 and for PC-SAFT with the proposed BICs model, AAD% is 9.6. All of these results are taken over the same samples when the EOS are used in prediction mode (after BIC model development). Beside this, the predictions of the liquid dropout are relatively improved in the case of PC-SAFT respect to Peng Robinson with the proposed set of binary interaction coefficients.

Developing a new model for the determination of petroleum fraction PC-SAFT parameters to model reservoir fluids

In this work, PC-SAFT, an equation of state based on perturbation theory, is applied to predict the reservoir fluids phase behavior. PC-SAFT parameters for pure components have previously been assessed, but they cannot be determined for petroleum fractions with unspecified components and composition. In order to remove this difficulty and making use of PC-SAFT model in the reservoir fluids simulations, a new approach is studied which leads to appearing generalized correlations for the estimation of PC-SAFT parameters for petroleum cuts and plus fractions using only their molecular weight and specific gravity, without the essential need for the characterization of petroleum fractions in different homologous hydrocarbon families. The proposed technique is then validated with the reliable experimental PVT data of reservoir fluids, including saturation pressure and differential liberation test (oil formation volume factor, soluble gas oil ratio, and liquid phase density) for 10 oil samples. Subsequently, available experimental data are compared to results calculated by PC-SAFT model for all existing samples. Afterwards, a comparison between PC-SAFT model and two widely used cubic equations of state (PR and SRK EOS) was also conducted. The results demonstrated PC-SAFT model estimation capabilities and ease of use as an effective tool for describing the phase behavior of reservoir fluids in a wide range of scales and applications. Moreover, the effect of parameter tuning process on reduction of error values was investigated and acceptable results were obtained.

PC-SAFT modeling of petroleum reservoir fluid phase behavior using new correlations for petroleum cuts and plus fractions

Parameters of the PC-SAFT Equation of State (EoS) for pure components are generally determined by matching the saturation pressure and liquid density experimental data. These experimental data are unavailable for petroleum cuts and plus fractions of the petroleum reservoir fluids. In this work, new correlations as functions of specific gravity and molecular weight were developed to estimate the PC-SAFT parameters of petroleum cuts with unknown composition. It was shown that the proposed correlations accurately estimate the PC-SAFT parameters of the pure components published in the literature. Then, the obtained correlations were used and the PVT experimental data for various real reservoir fluids was modeled using the PC-SAFT EoS and the results were compared to the modeled results using the Peng-Robinson EoS. The obtained results showed that the PC-SAFT EoS along with the proposed correlations presents acceptable results for phase behavior modeling of the reservoir petroleum fluids.

Phase Behavior and Minimum Miscibility Pressure in Nanopores

Summary Numerous studies indicate that the pressure/volume/temperature (PVT) phase behavior of fluids in large pores (designated “unconfined” space) deviates from phase behavior in nanopores (designated “confined” space). The deviation in confined space has been attributed to the increase in capillary force, electrostatic interactions, van der Waals forces, and fluid structural changes. In this paper, conventional vapor/liquid equilibrium (VLE) calculations are modified to account for the capillary pressure and the critical-pressure and -temperature shifts in nanopores. The modified VLE is used to study the phase behavior of reservoir fluids in unconventional reservoirs. The multiple-mixing-cell (MMC) algorithm and the modified VLE procedure were used to determine the minimal miscibility pressure (MMP) of a synthetic oil and Bakken oil with carbon dioxide (CO2) and mixtures of CO2 and methane gas. We show that the bubblepoint pressure, gas/oil interfacial tension (IFT), and MMP are decreased with confinement (nanopores), whereas the upper dewpoint pressure increases and the lower dewpoint pressure decreases.

Experimental Investigation and Thermodynamic Modeling of the Phase Behavior of Reservoir Fluids

An experimental study and thermodynamic modeling was conducted to quantify the phase behavior and physical properties of an Iranian crude oil sample. The oil sample was compositionally characterized by the distillation technique. Also, differential liberation tests and flash were conducted on an oil sample. Experiment results for phase behavior and reservoir fluid properties were used to evaluate the reliabilities of three cubic equations of state, including Peng-Robinson, Pate-Teja, and Soave-Redlich-Kwong for predicting flash calculation, and differential liberation test simulation of Iranian crude oil. Results show that heavy components in the petroleum mixtures based on the comparisons with the experimental data have the strongest effect on the characteristics of the fluids. It is obvious that Pate-Teja equation is superior in the calculations composition gas phase in higher pressure. Also, flash calculations based on Pate-Teja equation in the case of lumping is more accurate than results obtained by Peng-Robinson and Soave-Redlich-Kwong equations. Comparison of predicted oil specific gravity, gas oil ratio, relative volume, and compressibility factor of the liberated gas based on Pate-Teja equation to experimental data shows a better agreement than other equations. It should be noted that modeling of the gas oil ratio and relative volume has better agreement with experimental data in higher pressure.

Phase behavior of reservoir fluids: Comparisons of PC-SAFT and cubic EOS simulations

Cubic Equations of State (EOS) is an industry standard for simulating the phase behavior of reservoir fluids. Especially the Soave–Redlich–Kwong and the Peng–Robinson equations are widely used. Applied with volume correction, these models can generally capture the phase behavior of reservoir fluids in terms of saturation points and gas–liquid ratios. However for gas compressibility factors and oil compressibilities, cubic EOS do not fully meet today's requirements to accuracy. This paper will investigate whether the PC-SAFT EOS can provide an alternative to the cubic EOS that will improve simulation accuracy within the problem areas and still provide the same reliability as the cubic equations with respect to phase equilibrium calculations. The paper will further analyze whether it is a problem for simulating EOR gas injection processes that the PC-SAFT equation unlike a cubic equation is not bound to match the pure component critical point.