Phase Behavior Of Fluids Research Articles

Automated Equations of State Tuning Workflow Using Global Optimization and Physical Constraints

A computational model that can accurately describe the thermodynamics of a hydrocarbon system and its properties under various conditions is a prerequisite for running reservoir and pipeline simulations. Cubic Equations of State (EoS) are mathematical tools used to model the phase and volumetric behavior of reservoir fluids when compositional effects need to be considered. To anticipate uncertainty and enhance the quality of their predictions, EoS models must be adjusted to adequately match the available lab-measured PVT values. This task is challenging given that there are many potential tuning parameters, thus leading to various tuning results of questionable validity. In this paper, we present an automated EoS tuning workflow that employs a Generalized Pattern Search (GPS) optimizer for efficient tuning of a cubic EoS model. Specifically, we focus on the Peng–Robinson (PR) model, which is the oil and gas industry standard, to accurately capture the behavior of diverse multicomponent, complex hydrocarbon mixtures encountered in subsurface reservoirs. This approach surpasses the limitations of conventional gradient-based (GB) methods, which are susceptible to getting trapped in local optima. The proposed technique also allows physical constraints to be imposed on the optimization procedure. A gas condensate and an H2S-rich oil were used to demonstrate the effectiveness of the GPS algorithm in finding an optimized solution for high-dimensional search spaces, and its superiority over conventional gradient-based optimization was confirmed by automatically tracking globally optimal and physically sound solutions.

Investigation on the Extent of Retrograde Condensation of Qianshao Gas Condensate Reservoir Using PVT Experiments and Compositional Reservoir Simulation

In the development of the Qianshao (QS) gas condensate reservoir, it is crucial to consider the phenomenon of retrograde condensation. Understanding the condensate saturation distribution with respect to time and space within the reservoir is essential for planning and implementing effective strategies for the future development of the QS gas condensate reservoir. In this paper, various PVT experiments (including reservoir oil recombination, flash separation, constant composition expansion, and constant volume depletion) were conducted to study the PVT properties and phase behavior of QS gas condensate fluid. Based on experimental data, our in-house PVT computation package was used to determine the appropriate EOS model parameters for the QS gas condensate. A four-step reservoir fluid characterization procedure and workflow for gas condensate reservoirs was developed. Furthermore, by analyzing the pressure-temperature phase envelope, the maximum possible condensate saturation in the QS well area was estimated to be around 3%. Numerical reservoir simulation models were developed using both the EOS model and actual reservoir engineering data. These simulation models were specifically designed to replicate the retrograde condensation process that occurs during production, taking into account both vertical and horizontal wells. By simulating the production process, these single-well reservoir simulation models enable us to quantitatively evaluate the condensate saturation and its distribution over space and time within a specific control area around a single well. Reservoir simulation results show that the condensate build-up around vertical and horizontal wells is quite different. For a vertical well, the maximum condensate oil saturation (30%) around the wellbore is located approximately 5 to 6 m from the well’s center. In contrast, the horizontal well model demonstrates a maximum condensate saturation of no more than 1.5%. This information is crucial for making informed decisions regarding the effective development and management of the QS gas condensate reservoir.

A multi-mechanism numerical simulation model for CO2-EOR and storage in fractured shale oil reservoirs

Under the policy background and advocacy of carbon capture, utilization, and storage (CCUS), CO2-EOR has become a promising direction in the shale oil reservoir industry. The multi-scale pore structure distribution and fracture structure lead to complex multiphase flow, comprehensively considering multiple mechanisms is crucial for development and CO2 storage in fractured shale reservoirs. In this paper, a multi-mechanism coupled model is developed by MATLAB. Compared to the traditional Eclipse 300 and MATLAB Reservoir Simulation Toolbox (MRST), this model considers the impact of pore structure on fluid phase behavior by the modified Peng–Robinson equation of state (PR-EOS), and the effect simultaneously radiate to Maxwell–Stefan (M–S) diffusion, stress sensitivity, the nano-confinement (N-C) effect. Moreover, a modified embedded discrete fracture model (EDFM) is used to model the complex fractures, which optimizes connection types and half-transmissibility calculation approaches between non-neighboring connections (NNCs). The full implicit equation adopts the finite volume method (FVM) and Newton–Raphson iteration for discretization and solution. The model verification with the Eclipse 300 and MRST is satisfactory. The results show that the interaction between the mechanisms significantly affects the production performance and storage characteristics. The effect of molecular diffusion may be overestimated in oil-dominated (liquid-dominated) shale reservoirs. The well spacing and injection gas rate are the most crucial factors affecting the production by sensitivity analysis. Moreover, the potential gas invasion risk is mentioned. This model provides a reliable theoretical basis for CO2-EOR and sequestration in shale oil reservoirs.

Phase Behavior of Hydrocarbon Fluids in Shale Reservoirs, Considering Pore Geometries, Adsorption, and Water Film.

Phase behavior of hydrocarbon fluids in nanopores is different from that observed in a PVT cell due to the confinement effect. While scholars have established various models for studying the phase behavior in nanopores, the authors often ignore the effect of pore geometries, which can significantly affect the critical fluid properties in shale nanopores. In this study, we extend the Soave-Redlich-Kwong equation of state (SRK EOS) using potential theory and establish models of critical property shift, considering pore geometries, adsorption, and water film. Our research shows that the critical property shifts, considering fluid adsorption, begin at rp ≤ 10 nm and are seriously strengthened with nanopore radius reduction. The extended SRK EOS is applied to compute phase diagrams of the 50% C1-50% nC10 mixture at different pore sizes and find that the thickness of adsorption and water film causes a depression in the P-T diagram and that the bubble point pressure is lower in cylindrical pores. At pressures above 6 MPa, the irreducible water saturation and pore geometries greatly impact the vapor-liquid ratio. This study is significant for evaluating residual oil distribution and studying fluid flow laws in shale reservoirs.

The effect of confinement on the phase behavior of propane in nanoporous media: an experimental study probing capillary condensation, evaporation, and hysteresis at varying pore sizes and temperatures.

Fundamental understanding of the phase behavior and properties of fluids under confinement is of great significance for multiple fields of engineering and science, as well as for many practical industrial applications. In particular, unconventional geological systems, such as shale reservoirs, possess nanometer-scale pores, which impose nanoconfinement on the fluid molecules. In large pores, the bulk phase behavior of fluids can be modeled by the well-established methods, such as equation of state (EOS) approaches. However, under confinement the thermodynamic properties of fluids deviate significantly from those in the bulk, thus rendering the traditional EOS methods ineffective in predicting the phase behavior of confined fluids. Recently, the PC-SAFT/Laplace EOS has been developed to better represent the fluid phase equilibria in nanopores, which incorporates a new parameter that needs to be determined from experimental data. In this study, a new dataset is presented to reflect the phase properties of propane confined within the MCM-41 pores, with the aim to improve both the general understanding of the phase behavior of hydrocarbons under confinement and to parameterize the PC-SAFT/Laplace EOS for the nanoconfined propane. For this purpose, propane adsorption and desorption isotherms are determined experimentally for a wide range of temperatures (-27 to 20 °C) in MCM-41 of three different pore sizes (nominal pore diameters of 60, 80, and 100 Å). The effects of temperature and pore diameter on the capillary condensation and evaporation pressures are discussed in detail. Furthermore, the adsorption-desorption hysteresis behavior and its progression for different pore sizes were discussed. The experimental data are modeled using the parameterized PC-SAFT/Laplace EOS, which accurately captured the effects of confinement on the capillary condensation of propane in MCM-41. In addition, this study enriches the field of nanoconfinement research by providing a new dataset exemplifying the thermodynamic characteristics of hydrocarbons in nanopores.

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.

Investigation of the confinement effect on fluid-phase behavior in shale oil reservoirs during CO2 injection process

AbstractDue to the confinement effect of nanopores, the fluid-phase behavior of shale oil reservoirs is much different from that of conventional reservoirs. The accurate description of the phase change characteristics of fluid in nanopores is the basis to design development plan, production system, and EOR methods of shale oil reservoirs. In this study, molecular dynamics simulation was employed to analyze the phase behavior of single-component system and hydrocarbon–CO2 mixture system in organic nanopores. The results show that the confinement effect on the phase change pressure of the single-component system is influenced by the distribution of the electron cloud. The phase change pressure of hydrocarbons with even distribution of the electron cloud would be increased, while that of CO2 would be decreased due to the instantaneous dipole moment. In addition, as the length of carbon chains increases, the confinement effect on hydrocarbons becomes stronger. When the temperature increases, the confinement effect becomes weaker. In the hydrocarbon–CO2 mixture system, when the occurrence condition changes from bulk to the nanopore of 5 nm, the bubble point pressure decreases by 39.21–68.85%, and the critical temperature and pressure decrease by 75.98% and 7.13%, respectively. On the whole, the P–T phase envelope is shrunken under the confinement effect. CO2 is much easier to be miscible with shale oil in nanopores. Moreover, full mixing and keeping in single liquid phase of CO2–hydrocarbons mixture system can reduce the adsorption of hydrocarbons on organic pore walls. Therefore, CO2 injection could be a feasible method to enhance oil recovery in the matrix of shale oil reservoirs.

Development of methodological solutions for the efficient development of gas condensate deposits in low-permeability reservoirs with complex phase behavior of reservoir fluid

Efficient production of gas and condensate from deep deposits requires the solution of a set of scientific and methodological problems, including the assessment of distribution of the initial fluid composition and properties within the deposit; predicting the complex phase behavior of the reservoir fluid at near-critical conditions and under the influence of the porous medium; modeling the formation of condensate banks in multiphase flows, taking into account velocity effects, variable interfacial tension, non-equilibrium phase transitions and complex well completions; etc. The paper presents the developments of Oil and Gas Research Institute of the Russian Academy of Sciences in this area, with an emphasis on recovery of the unique hydrocarbon reserves of the Achimov deposits of the Urengoy oil and gas condensate field.

Simulations and integral-equationtheories for dipolar density interacting disks.

Integral equationtheories (IETs) based on the Ornstein-Zernike (OZ) relation can be used as an analytical tool to predict structural and thermodynamic properties and phase behavior of fluids with low numerical cost. However, there are no studies of the IETs for the dipolar density interaction potential in two-dimensional systems, a relevant interdomain interaction in lipid monolayers with phase coexistence. This repulsive interaction arises due to the excess dipole density of the domains, which are aligned perpendicular to the interface. This work studies the performance of three closures of the OZ equationfor this novel system: Rogers-Young (RY), modified hypernetted chain (MHNC), and variational modified hypernetted chain (VMHNC). For the last two closures the bridge function of a reference system is required, with the hard disk being the most convenient reference system. Given that in two dimensions there is no analytical expressions for the hard disk correlation functions, two different approximations are proposed: one based on the Percus-Yevick (PY) approximation, and the other based on an extension of the hard spheres Verlet-Weis-Henderson-Grundke (LB) parametrization. The accuracy of the five approaches is evaluated by comparison of the pair correlation function and the structure factor with Monte Carlo simulation data. The results show that RY closure is satisfactory only for low-structured regimes. MHNC and VMHNC closures perform globally well, and there are no significant differences between them. However, the reference system in some cases affects their performance; when the pair correlation function serves as the measure, the LB-based closures quantitatively outperform the PY ones. From the point of view of its applicability, LB-based closures do not have a solution for all studied interaction strength parameters, and, in general, PY-based closures are numerically preferable.

Molecular simulation of the dynamic distribution of complex oil components in shale nanopores during CO2-EOR

Due to the high clay content of shale reservoirs, developing shale oil by water flooding is difficult. CO2 is easier to inject into formations than water, significantly increasing shale oil production by reducing the viscosity of shale oil and increasing the gas-oil ratio. Moreover, CO2 flooding can also effectively reduce emissions. However, CO2 flooding changes the formation fluid's phase behavior and composition. This causes the fluid to redistribute in the nanopore. Based on the field data, it can be seen that the changes of formation fluid components are obvious in the three stages of CO2 injection, the initial state of production and depressurization production. Therefore, this paper uses the molecular dynamics method to study the changes in adsorption layer thickness, adsorption ratio of components, interaction energy, and self-diffusion coefficient of fluids in organic and inorganic pores under these three stages. The results show that the adsorption layer thickness gradually increases during CO2 flooding. After CO2 injection, the fluid components in kerogen are significantly desorbed. The desorption of the components in the small pore size of illite, feldspar, and calcite is insignificant; the desorption of the components in the large pore size is significant, and the desorption of the components in quartz is insignificant. The interaction energy between fluid and pores decreases first and then increases during CO2 flooding, and the types of interaction energy between pores and fluids differ. The results show that CO2 injection can increase shale oil production. New ways to enhance oil recovery are needed to increase shale oil production in the later stage of depressurization production.

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.

Importance of critical point for the phase behavior of a reservoir fluid

It is a fundamental assumption behind a cubic equation of state that the phase behavior of a pure component can be expressed in terms of its critical temperature and pressure. This paper shows that the location of the critical point also for multicomponent reservoir fluids influences the phase behavior throughout the gas and liquid region. An equation of state model that matches the critical point and the saturation pressure at the reservoir temperature is likely to provide a good match of the phase behavior of a reservoir fluid at all conditions experienced during oil and gas production. An experimental critical point is seldom available for a reservoir fluid but the critical point can be estimated from correlations in the molar ratio of C7+ and lighter hydrocarbons. When PVT data exists, such estimated critical point can be used as an extra datapoint when assigning critical properties to an equation of state model. This is particularly useful as a constraint when the equation of state is to be used for gas injection enhanced oil recovery calculations. When the available PVT data is limited to a saturation point at the reservoir temperature, a reliable equation of state model can be developed by only tuning to the saturation pressure and the estimated critical point. The presented method is applicable to reservoir oils and gas condensates with a C7+ mole% of at least 10.

Correction to “Comparison of CP-PC-SAFT and CS-SAFT-VR-Mie in Predicting Fluid Phase Behavior in Systems of Phenolic Compounds, Aromatic Amines, Acetophenone, and Benzaldehyde”

Correction to “Comparison of CP-PC-SAFT and CS-SAFT-VR-Mie in Predicting Fluid Phase Behavior in Systems of Phenolic Compounds, Aromatic Amines, Acetophenone, and Benzaldehyde”

CFD-DEM Approach to Study the Proppant Transport and Placement under Different Perforation Conditions in Tortuous Hydraulic Fractures

Summary Hydraulic fracturing technology is widely used to extract unconventional and conventional gas/oil reservoirs. However, the distribution and packing pattern of the proppant remain as significant concerns in hydraulic fracturing, because they help enhance unconventional reservoir production by optimizing operational parameters. Previous studies focused on the proppant transport mechanism with critical factors, such as the perforation condition (perforation properties), in a straight fracture model, but the simplified fracture shape cannot generate enough actual results because the fracture is tortuous after shear displacement. As a result, there is a need to further study the effect of perforation conditions on proppant transport and distribution in tortuous fractures. The aim of this study is to present a combined numerical approach using computational fluid dynamics (CFD) and discrete element method (DEM) to simulate the fluid phase and proppant behavior, respectively. The CFD-DEM model was validated against the experimental results and found to be suitable for predicting proppant transport and distribution with different perforation conditions. The main conclusions are summarized as follows: (1) In various degrees of the tortuous fracture model, the final proppant packing shape was overall quadrilateral under the top- and middle-perforation injection modes. On the contrary, the proppant packing shape was triangular under bottom-perforation injection mode, resulting in a low dune height near the perforation. Furthermore, the final packing patterns changed from double-peaked stack to sole-peaked stack due to the injection mode changing to multiple-perforation injection mode. (2) In the tortuous fracture model, the bottom-perforation injection and multiple-perforation injection mode strategies should be applied first to improve the proppant transport efficiency.

Phase behavior and hydrocarbons distribution in shale oil during EOR with nano-confinement effect

The pore structure of shale reservoirs leads to the complex phase behavior of shale reservoir fluids, which is aggravated due to changes in fluid composition during reservoir development. Effective prediction of changes in the phase behavior of fluids in shale reservoirs is important. This paper proposes a pore-size-dependent Peng-Robinson equation of state (PR-EOS) to describe phase behavior in nanopores. The approach considers the shift of critical parameters and the gas-liquid capillary pressure and compiles by MATLAB. The verification of the model is satisfying by matching the result with Tnavigator PVTi using the published date. The results show that fluids in nanoscale pores are more likely to exhibit near-critical or condensate states. We also compare the changes in phase behavior when fluids dissolve CO2 and CH4 and observe the phase transition (from gaseous to liquid phase) of the lighter crude oil sample that dissolved more gas during the differential liberation experiment (DL). Finally, we use CO2 pre-pad energized fracturing of a shale oil reservoir in northern China as an example to explain abnormal production performances, such as a majority of light hydrocarbons in the produced fluid of the well during the flow back stage, single gas phase production in the early production stage, and stable gas/oil ratio (GOR) in the process of development. Our novel methodology and phase behavior change mechanism can enhance our understanding of the phase behavior of fluids in shale oil reservoirs during enhanced oil recovery.

Comparison of CP-PC-SAFT and CS-SAFT-VR-Mie in Predicting Fluid Phase Behavior in Systems of Phenolic Compounds, Aromatic Amines, Acetophenone, and Benzaldehyde

Comparison of CP-PC-SAFT and CS-SAFT-VR-Mie in Predicting Fluid Phase Behavior in Systems of Phenolic Compounds, Aromatic Amines, Acetophenone, and Benzaldehyde

Fluid phase equilibria of Brazilian presalt crude oil – CO2 systems at high pressure and high temperature

This paper aims to conduct an experimental investigation of the fluid phase behavior of a highly opaque Brazilian pre-salt crude oil-CO2 system, specifically focusing on the occurrence of highly dispersed liquid-liquid transitions. The study involves examining the phase behavior of five global mole compositions [zCO2= (37.9, 50.0, 76.6, 80.6, and 84.2) mol%] by using conventional PVT techniques as light scattering, pressure-volume curve, and direct fluid observation through sapphire windows. When other techniques were ineffective, a high-pressure microscope coupled with a short-wave infrared apparatus (SWIR camera and light source) was used for complex fluid inspection.

PH-Responsive Viscoelastic Fluids of a C22-Tailed Surfactant Induced by Trivalent Metal Ions.

pH-responsive viscoelastic fluids are often achieved by adding hydrotropes into surfactant solutions. However, the use of metal salts to prepare pH-responsive viscoelastic fluids has been less documented. Herein, a pH-responsive viscoelastic fluid was developed by blending an ultra-long-chain tertiary amine, N-erucamidopropyl-N, N-dimethylamine (UC22AMPM), with metal salts (i.e., AlCl3, CrCl3, and FeCl3). The effects of the surfactant/metal salt mixing ratio and the type of metal ions on the viscoelasticity and phase behavior of fluids were systematically examined by appearance observation and rheometry. To elucidate the role of metal ions, the rheological properties between AlCl3- and HCl-UC22AMPM systems were compared. Results showed the above metal salt evoked the low-viscosity UC22AMPM dispersions to form viscoelastic solutions. Similar to HCl, AlCl3 could also protonate the UC22AMPM into a cationic surfactant, forming wormlike micelles (WLMs). Notably, much stronger viscoelastic behavior was evidenced in the UC22AMPM-AlCl3 systems because the Al3+ as metal chelators coordinated with WLMs, promoting the increment of viscosity. By tuning the pH, the macroscopic appearance of the UC22AMPM-AlCl3 system switched between transparent solutions and milky dispersion, concomitant with a viscosity variation of one order of magnitude. Importantly, the UC22AMPM-AlCl3 systems showed a constant viscosity of 40 mPa·s at 80 °C and 170 s-1 for 120 min, indicative of good heat and shear resistances. The metal-containing viscoelastic fluids are expected to be good candidates for high-temperature reservoir hydraulic fracturing.

Programmable phase behavior in fluids with designable interactions.

We introduce a method for solving the "inverse" phase equilibria problem: How should the interactions among a collection of molecular species be designed in order to achieve a target phase diagram? Using techniques from convex optimization theory, we show how to solve this problem for phase diagrams containing a large number of components and many coexisting phases with prescribed compositions. We apply our approach to commonly used mean-field models of multicomponent fluids and then use molecular simulations to verify that the designed interactions result in the target phase diagrams. Our approach enables the rational design of "programmable" fluids, such as biopolymer and colloidal mixtures, with complex phase behavior.

Key theoretical and technical issues and countermeasures for effective development of Gulong shale oil, Daqing Oilfield, NE China

Aiming at the four issues of underground storage state, exploitation mechanism, crude oil flow and efficient recovery, the key theoretical and technical issues and countermeasures for effective development of Gulong shale oil are put forward. Through key exploration and research on fluid occurrence, fluid phase change, exploitation mechanism, oil start-up mechanism, flow regime/pattern, exploitation mode and enhanced oil recovery (EOR) of shale reservoirs with different storage spaces, multi-scale occurrence states of shale oil and phase behavior of fluid in nano confined space were provided, the multi-phase, multi-scale flow mode and production mechanism with hydraulic fracture-shale bedding fracture-matrix infiltration as the core was clarified, and a multi-scale flow mathematical model and recoverable reserves evaluation method were preliminarily established. The feasibility of development mode with early energy replenishment and recovery factor of 30% was discussed. Based on these, the researches of key theories and technologies for effective development of Gulong shale oil are proposed to focus on: (1) in-situ sampling and non-destructive testing of core and fluid; (2) high-temperature, high-pressure, nano-scale laboratory simulation experiment; (3) fusion of multi-scale multi-flow regime numerical simulation technology and large-scale application software; (4) waterless (CO2) fracturing technique and the fracturing technique for increasing the vertical fracture height; (5) early energy replenishment to enhance oil recovery; (6) lifecycle technical and economic evaluation. Moreover, a series of exploitation tests should be performed on site as soon as possible to verify the theoretical understanding, optimize the exploitation mode, form supporting technologies, and provide a generalizable development model, thereby supporting and guiding the effective development and production of Gulong shale oil.