Pressure Volume Temperature Research Articles

Predictive Model for Pressure–Volume–Temperature Properties and Asphaltene Instability of Crude Oils under Gas Injection

A new approach based on the statistical associating fluid theory is presented here to model eight light crude oils, with the saturate, aromatic, resin, and asphaltene analysis as the only input for the model. Within the characterization procedure of Punnapala and Vargas ( Fuel 2013, 108, 417−429, 10.1016/j.fuel.2012.12.058), the aromaticity parameter and the asphaltene molecular weight were fixed to all crude oil samples, while the asphaltene aromaticity is the only fitted parameter of the model. A correlation for this parameter with the flashed gas molecular weight allows for full predictions of the phase behavior without the need of any asphaltene onset data. The predictive molecular model was used to study asphaltene instability as a function of injected CO2 and natural gas concentration. The model can also accurately reproduce routine pressure–volume–temperature experiments, such as constant composition expansion, differential vaporization, and multi-stage separation tests, performed on the crude oils...

An Experimental Study of Nonequilibrium Carbon Dioxide/Oil Interactions

SummaryIn this study, we use a custom-designed visual cell to investigate nonequilibrium carbon dioxide (CO2)/oil interactions under high-pressure/high-temperature conditions. We visualize the CO2/oil interface and measure the visual-cell pressure over time. We perform five sets of visualization tests. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with a Montney (MTN) oil sample. In the fourth test, to visualize the interactions in the bulk oil phase, we replace the opaque MTN oil with a translucent Duvernay (DUV) light oil (LO). Finally, we conduct an N2(sc)/oil test to compare the results with those of CO2(sc)/oil test. We also compare the results of nonequilibrium CO2/oil interactions with those obtained from conventional pressure/volume/temperature (PVT) tests.Results of the first three tests show that oil immediately expands upon injection of CO2 into the visual cell. CO2(sc) leads to the maximum oil expansion followed by CO2(l) and CO2(g). Furthermore, the rate of oil expansion in the CO2(sc)/oil test is higher than that in CO2(l)/oil and CO2(g)/oil tests. We also observe extracting and condensing flows at the CO2(l)/oil and CO2(sc)/oil interfaces. Moreover, we observe density-driven fingers inside the LO phase because of the local increase in the density of LO. The results of PVT tests show that the density of the CO2/oil mixture is higher than that of the CO2-free oil, explaining the density-driven natural convection during CO2(sc) injection into the visual cell. We do not observe either extracting/condensing flows or density-driven mixing for the N2(sc)/oil test, explaining the low expansion of oil in this test. The results suggest that the combination of density-driven natural convection and extracting/condensing flows enhances CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.

Reliability experiment on the calculation of natural gas hydrate saturation using acoustic wave data

In this paper, compression wave velocity, shear wave velocity and their change during the formation of natural gas hydrate in unconsolidated sand and mud sediments were measured through petrophysical experiments to discuss the reliability of calculating natural gas hydrate saturation by using acoustic velocity data. Then, a computation model of natural gas hydrate saturation during the experiments was established based on the material balance equation, combined with the PVT (pressure, volume, temperature) state equation and its test conditions. On this basis, the changing law of the acoustic velocity of the unconsolidated sediments with the increase of natural gas hydrate saturation was analyzed. Finally, natural gas hydrate saturation was calculated by using the modified Lee's weight sonic formula, and was compared with that measured in the experiments. And the following research results were obtained. First, the acoustic data can be used to calculate the natural gas hydrate saturation when the content of natural gas hydrate reaches a certain extent. Second, the compression and shear wave velocities of unconsolidated sand and mud sediments increase with the rise of their natural gas hydrate content, and they are in a good relationship of linear correlation. And third, the natural gas hydrate saturation calculated based on the acoustic data is close to that measured in the laboratory with much smaller errors. It is concluded that the research results provide a basis for the calculation of natural gas hydrate saturation using the actual acoustic logging data.

Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance

CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study.A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.

High-pressure dielectric studies on 1,6-anhydro-β-D-mannopyranose (plastic crystal) and 2,3,4-tri-O-acetyl-1,6-anhydro-β-D-glucopyranose (canonical glass).

Broadband Dielectric Spectroscopy was applied to investigate molecular dynamics of two anhydrosaccharides, i.e., 1,6-anhydro-β-D-mannopyranose, anhMAN (hydrogen-bonded system) and 2,3,4-tri-O-acetyl-1,6-anhydro-β-D-glucopyranose, ac-anhGLU (van der Waals material), at different thermodynamic conditions. Moreover, the reported data were compared with those recently published for two other H-bonded systems, i.e., 1,6-anhydro-β-D-glucopyranose (anhGLU) and D-glucose (D-GLU). A direct comparison of the dynamical behavior of the materials with a similar chemical structure but significantly differing by the degrees of freedom, complexity, and intermolecular interactions made it possible to probe the impact of compression on the fragility, Temperature-Pressure Superpositioning and pressure coefficient of the glassy crystal/glass transition temperatures (dTgc/dp ; dTg/dp). Moreover, the correlation between dTgc/dp determined experimentally from the high-pressure dielectric data and the Ehrenfest equation has been tested for the plastic crystals (anhGLU and anhMAN) for the first time. Interestingly, a satisfactory agreement was found between both approaches. It is a quite intriguing finding which can be rationalized by the fact that the studied materials are characterized by the low complexity (lower degrees of freedom with respect to the molecular mobility) as well as ordered internal structure. Therefore, one can speculate that in contrast to the ordinary glasses the dynamics of the plastic crystals might be described with the use of a single order parameter. However, to confirm this thesis further, pressure-volume-temperature (PVT) experiments enabling calculations of the Prigogine Defay ratio are required.

Advancements in Annular-Pressure-Buildup Mitigation for Thunder Horse Wells

SummaryA wide variety of annular-pressure-buildup (APB) -mitigation techniques has been deployed in the past 2 decades. In the early 2000s, BP focused efforts on the development and implementation of rupture disks, nitrified foam spacers, syntactic-foam modules, and vacuum-insulated tubing (VIT). Initiatives to simplify operations while maintaining well integrity have led to innovative techniques that expand the APB-mitigation toolkit.BP's Gulf of Mexico (GOM) Thunder Horse drilling team recently pursued three APB-mitigation techniques. One method is to fully cement the annulus, thereby removing the fluid that is subject to thermal expansion in a trapped annulus. A second method uses a qualified port collar to equalize pressure across a casing string. The third method focuses on better acquisition and use of mud pressure/volume/temperature (PVT) data for a more precise prediction of the APB-design loads.These methods and techniques have led to the removal of syntactic foam from some wells in the Thunder Horse field. The design change reduces installation time and operational complexity during well construction and abandonment.This paper provides a description and technical details concerning the planning and job execution for the fully cemented annulus and the use of port collars for pressure equalization. It also discusses the motivation behind acquiring PVT data specific to a particular mud system, and provides interpretation of laboratory data. The work may be useful for other operators as they plan and execute wells subject to the potential for APB.

Determination of Pressure Dependence of Polymer Phase Transitions by pVT Analysis.

Glass transitions, melting, crystallization, and the isotropization of polymers are connected with changes in the density, respectively the specific volume (Vsp), which can be analyzed by dilatometric methods. Here, the pressure dependence of such transitions is determined by pressure volume temperature (pVT) analysis for different thermoplastic polymers in the pressure range of 10 to 200 MPa, and the temperature range from room temperature to 350 °C. The values for ambient pressure are extrapolated. It is shown that polymer transitions always increase with pressure, and that the melting temperature and glass transition temperature are nearly linearly dependent on pressure. This information, as well as the observed density changes with pressure and temperature, is very important for the processing of thermoplastics, including their simulation, as well as for the thermodynamic interpretations of the transition’s nature.

Reseaching the PVT properties and gradient energy coefficient with different parameters of Polystyrene (PS910)

The Gradient energy coefficient ( ) in polymers and oligomers are playing an important role in polymer as well as understanding of many processes especially in innovation of new polymer with classification of materials.. As a result, the main reason in this study appear which has how the gradient energy coefficient changes from bulk to surface., has been establishing the new chemical potential equation as well helped us to extract the correlation between gradient energy coefficient and different parameters. The gradient energy coefficient has been related with hole fractions, temperature and density. Both Simha-Somcynsky (SS) and Cahn-Hilliard (CH) models are employed together to calculate the thermodynamic properties of polystyren.,These studies are written in a code program (Mathematica). At first pressure-volume-temperature (PVT) data for the SS theory, are calculated from the modified cell model (MCL) starting atmospheric pressure to 150 Mpa and temperature range from 313 to 473 K, as well. The PVT characteristic parameters of the SS theory are calculated using the data, with the average and maximum value of percentage deviation of specific volume are reported below 0.117 and 0.415 respectively.

Precambrian temperature and pressure system of Gaoshiti-Moxi block in the central paleo-uplift of Sichuan Basin, southwest China

Recently, trillions of cubic meters gas resources have been found in Sinian reservoirs of Gaoshiti-Moxi region in the central uplift of Sichuan Basin, which is the first commercial discovery of primary gas field in Precambrian anywhere in the world. To obtain a great breakthrough in Precambrian hydrocarbon exploration, it is necessary to find out the evolution process of temperature and pressure. Reconstructing the thermal history and pore pressure evolution in carbonate reservoirs are challenging problems, especially in deep-old layers without available samples and methods. To study the temperature and pressure system, we conducted a comprehensive analysis combining the paleo-thermal indicators and inclusions Pressure-Volume-Temperature (PVT) simulation with basin modeling. The results showed that the thermal history of the Gaoshiti-Moxi area could be divided into three stages. From the Late Sinian to Late Paleozoic, the thermal regime was stable with low heat flow value (<65 mW/m2). During the Early Paleozoic, the heat flow increased rapidly to the peak value (75–100 mW/m2). From Mesozoic to present, the thermal subsidence occurred in the basin with the heat flow decreasing to the present value (60–70 mW/m2). With the boundary condition of above thermal history, the simulated pressure of Dengying Formation in Gaoshiti-Moxi area could be divided into four stages. The excess pressure began to form during the Triassic. From the end of Triassic to Middle Jurassic, the excess pressure increased steadily and slowly. From Middle Jurassic to the end of Early Cretaceous, the strata subsided rapidly while the excess pressure increased significantly. Since the Late Cretaceous, the Dengying Formation suffered from rapid uplifting and gas lateral migrating with the excess pressure decreasing, until the Late Neogene, the excess pressure in reservoirs declined to zero.

Enhancing Sodium Bis(2-ethylhexyl) Sulfosuccinate Injectivity for CO2 Foam Formation in Low-Permeability Cores: Dissolving in CO2 with Ethanol

The utilization of conventional water-soluble surfactants for the stabilization of CO2 foams has been limited by the low injectability of low-permeability reservoirs. In this study, the anionic surfactant sodium bis(2-ethylhexyl) sulfosuccinate (AOT) was used as the CO2-soluble surfactant to stabilize CO2 foams in the presence of ethanol. The phase equilibrium relationships of the AOT/ethanol/CO2 system and the partition coefficient of AOT between supercritical CO2 (SC-CO2) and water were measured through a fully visible pressure–volume–temperature (PVT) cell. In addition, the effects of the ethanol content on the partition coefficient and interfacial tension (IFT) were studied. Furthermore, a laboratory apparatus was developed to measure the viscosity and injection performance of AOT dissolved in an aqueous or SC-CO2 solution and SC-CO2 foams. The experimental data show that addition of ethanol can significantly improve the solubility of AOT in SC-CO2 and increase the partition coefficient of AOT. The IF...

Characterization, Pressure–Volume–Temperature Properties, and Phase Behavior of a Condensate Gas and Crude Oil

The oil reservoirs are underground and have the oil and gas contained in the porous rock at high temperatures and pressures. Only 5–20% of the oil is withdrawn in primary production. Further recovery can be achieved by injecting carbon dioxide (CO2) that displaces and dissolves part of the remaining oil; this process is called enhanced oil recovery. Although the characterization and fractionation of petroleum are well-known and studied, each oil sample represents a unique multicomponent system; therefore, an individual study of the sample is required. Real samples of condensate gas (CG) and light crude oil (LCO) were collected and analyzed for density, viscosity, atmospheric distillation and fractionation, and aiming characterization. Synthetic visual and non-visual methods for high pressure were successfully applied for bubble point measurements of the systems composed of supercritical CO2 and CG or LCO. Phase envelope calculations were developed on the basis of pseudo-components obtained by atmospheric ...

Development of an artificial neural network model for prediction of bubble point pressure of crude oils

Abstract Bubble point pressure is one of the most important pressure–volume–temperature properties of crude oil, and it plays an important role in reservoir and production engineering calculations. It can be precisely determined experimentally. Although, experimental methods present valid and reliable results, they are expensive, time-consuming, and require much care when taking test samples. Some equations of state and empirical correlations can be used as alternative methods to estimate reservoir fluid properties (e.g., bubble point pressure); however, these methods have a number of limitations. In the present study, a novel numerical model based on artificial neural network (ANN) is proposed for the prediction of bubble point pressure as a function of solution gas–oil ratio, reservoir temperature, oil gravity (API), and gas specific gravity in petroleum systems. The model was developed and evaluated using 760 experimental data sets gathered from oil fields around the world. An optimization process was performed on networks with different structures. Based on the obtained results, a network with one hidden layer and six neurons was observed to be associated with the highest efficiency for predicting bubble point pressure. The obtained ANN model was found to be reliable for the prediction of bubble point pressure of crude oils with solution gas–oil ratios in the range of 8.61–3298.66 SCF/STB, temperatures between 74 and 341.6 °F, oil gravity values of 6–56.8 API and gas gravity values between 0.521 and 3.444. The performance of the developed model was compared against those of several well-known predictive empirical correlations using statistical and graphical error analyses. The results showed that the proposed ANN model outperforms all of the studied empirical correlations significantly and provides predictions in acceptable agreement with experimental data.

RELATIONS BETWEEN THE DIFFERENCES OF DIFFERENT PROPERTIES OF FREONES ON THE SATURATION LINES UPON LIQUID-VAPOR PHASE TRANSITION

To construct a generalized dependency, a scale for the unknown quantities and variables must be selected. The states of points are located in P-V-T (pressure-volume-temperature) space. The scale for the construction of generalized dependences of the studied properties and variables of the problem must be sustainable. In order to find a sustainable transition from liquid to vapor the behavior of the characteristic function of free energy is investigated. Since the phase transition occurs at a constant temperature, free energy is equal to expansion work. In the analysis of the liquid-vapor transition, the curve of the temperature dependence of expansion work for all investigated substances has a maximum. The temperature corresponding to the maximum expansion work is denoted by Tm. It was noted that temperature Tm associated with Tc (critical) with the simple relation Tm =0.76Tс with a spread of 2%. Naturally, this state corresponds to the free energy minimum value, and in accordance with the principle of minimality of characteristic functions of this process is stable. Therefore, the parameters of this process were chosen as the bringing scale in the construction of dimensionless dependencies. In this paper we use the method of constructing generalized dependencies in the reduced form, based on the characteristic functions minimality principle. Approximating formulas were obtained for calculating reduced heat of evaporation from reduced density, entropy, and freons surface tension. The reduction scale is considered on the liquid and vapor saturation line under substances consideration. The characteristic functions minimality principle is used. In the course of the analysis, calculation formulas were derived for pure freons both individually and in a combined form. The interrelation between the differences of these thermodynamic properties on the saturation line during a liquid-vapor phase transition is shown. This makes it possible to determine some properties using other methods by calculation.

A New Approach to Combined Sulfide- and Carbonate-Scale Predictions Applied to Different Field Scenarios

Summary Unlike other types of inorganic scales, carbonate and sulfide scales are directly correlated to the in-situ concentration of acid gases such as carbon dioxide (CO2) and hydrogen sulfide (H2S), which influence the local pH and availability of reactive species. The common approach to sulfide- and carbonate-scale prediction often does not account for three-phase CO2 and H2S partitioning at different temperatures and pressures throughout the system. This leads to the use of inaccurate compositions and pH values for the mineral-scaling calculations. In this paper, we apply a rigorous work flow (step-by-step procedure) derived from a compositional pressure/volume/temperature (PVT) model to calculate molecular CO2 and H2S distribution, three-phase relative volume changes, compositional changes, and scale-precipitation trends from the reservoir to the wellhead-separation stage using commonly available surface field data, a full PVT software package, and scale-prediction software of the user's choice. A simplified version of the work flow was previously applied to high-CO2 and -H2S gas/condensate wells with production of condensed water only (Verri et al. 2017b). This paper focuses on the field application of our “Rigorous General Work Flow” (Verri et al. 2017a) to North Sea oil wells with high water-cut and medium H2S levels (approximately 2,200 ppmv in the separator-gas phase) to provide sulfide- and carbonate-scale-prediction profiles from reservoir to separator. The combination of reservoir-, production-, and chemical-engineering models using specific iterative processes (within the work flow) has provided a new and rigorous step-by-step procedure for the prediction of combined sulfide and carbonate scales in oil and gas wells, which can be implemented by anyone using any PVT and scale-prediction software.

Experimental and Numerical Analysis of Injection Molding of Ti-6Al-4V Powders for High-Performance Titanium Parts

Both experimental and numerical analysis of powder injection molding (PIM) of Ti-6Al-4V alloy were performed to prepare a defect-free high-performance Ti-6Al-4V part with low carbon/oxygen contents. The prepared feedstock was characterized with specific experiments to identify its viscosity, pressure–volume–temperature and thermal properties to simulate its injection molding process. A finite-element-based numerical scheme was employed to simulate the thermomechanical process during the injection molding. In addition, the injection molding, debinding, sintering and hot isostatic pressing processes were performed in sequence to prepare the PIMed parts. With optimized processing conditions, the PIMed Ti-6Al-4V part exhibits excellent physical and mechanical properties, showing a final density of 99.8%, tensile strength of 973 MPa and elongation of 16%.

Well-Performance Study Integrates Empirical Time/Rate and Time/Rate/Pressure Analysis

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179119, “A Well-Performance Study of Eagle Ford Gas Shale Wells Integrating Empirical Time/Rate and Analytical Time/Rate/Pressure Analysis,” by A.S. Davis and T.A. Blasingame, Texas A&amp;M University, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed. The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale. The authors use modern time/rate (decline-curve) analysis and time/rate/pressure (model-based) analysis methods to analyze, interpret, and diagnose gas-condensate well-production data. Reservoir and completion properties are estimated; these results are then correlated with known completion variables. The time/rate and time/rate/pressure analyses are used to forecast future production and to estimate ultimate recovery. Production-Analysis Work Flow The data required for the completion of the proposed methodology include well-history files, daily-rate and flowing-pressure measurements, and laboratory pressure/volume/temperature (PVT) and fluid-analysis reports. The following diagnostic plots are used to identify potential errors or abnormalities in the production data: Rate/pressure/time plot (semilog) Productivity-index/time plot (semilog) Productivity-index/time plot (log-log) Rate/cumulative-production/time plot (log-log) Pressure/rate correlation plot (Cartesian) Rate/pressure/cumulative-production plot (semilog) In addition to checking the integrity and correlation of production data, the authors also use the following diagnostic plots to establish the reservoir model and flow regimes: Log-log plot Blasingame plot (log-log) Productivity-index/normalized-cumulative-gas-production plot (log-log) Note that, for the diagnostic plots, an incorrect estimate of the initial reservoir pressure will yield plots that show skewed trends or clumping or scattering of data points, particularly at early production times. On the basis of the information gathered from the diagnostic plots and well-history files, nonrepresentative production data points that are likely the result of nonreservoir effects or operational changes such as well-cleanup effects, liquid loading, well recompletions, well workovers, or choke changes are filtered. The diagnostic plots are prepared with the filtered production data to identify the flow regimes experienced by a given well. It is of primary importance to recognize if the well is still in transient flow or has already entered boundary- dominated flow because it allows determination of which of the time/rate relation models is appropriate for the given production data.

A new analysis of pressure dependence of the equilibrium interfacial tensions of different light crude oil–CO2 systems

In this paper, the equilibrium two-phase compositions are predicted and analyzed to elucidate the pressure dependence of the equilibrium interfacial tensions (IFTs) of three different light crude oil–CO2 systems. First, three series of the dynamic IFT tests for a dead light crude oil–pure CO2 system, a live light crude oil–pure CO2 system, and a dead light crude oil–impure CO2 system at different equilibrium pressures from the literature are used. Second, the modified Peng–Robinson equation of state (PR-EOS) is tuned by using measured pressure–volume–temperature (PVT) data to predict the equilibrium two-phase compositions of the three light crude oil–CO2 systems. Such tuned PR-EOS together with the parachor model is applied to predict the equilibrium IFTs, which are compared with and validated by the measured IFT data. Third, the pressure dependence of the equilibrium IFTs, the initial oil and gas composition effects, and the initial gas fraction effect are examined. The density difference between the light crude oil and gas phase is found to be a key factor in the parachor model for the IFT predictions. The equilibrium IFT vs. pressure curve is found to have three different pressure ranges, which correspond well to those for the density difference. Moreover, the initial oil and gas compositions affect the equilibrium two-phase compositions and IFTs to different extents. The live light crude oil–pure CO2 equilibrium IFT is reduced with an increased initial gas fraction. For the dead light crude oil–pure/impure CO2 system, the miscibility with zero IFT can be achieved only if the initial gas phase has more than 0.70 mol fraction. Otherwise, it is the complete gas dissolution into the light crude oil that leads to zero IFT.

A review of the application of non-intrusive infrared sensing for gas–liquid flow characterization

This paper reviews the use of non-intrusive optical infrared sensing for gas–liquid flow characterisation in pipes. The application of signal analysis techniques to infrared-derived temporal signal outputs enables the objective determination of flow characteristics such as flow regimes, phase fractions and total pressure drops. Key considerations for improving the performance of infrared sensors are discussed. These include global and local measurements, ray divergence, effects of ambient light and temperature variations. Most experimental studies have reported consistent and excellent results for flow regime identifications and phase fraction estimation but with a few validating total pressures drop from correlations and direct pressure measurements. Other gaps in research were highlighted; these include the use of pipes sizes greater than 0.005 m for experimentation under high superficial velocities conditions greater than 10 m/s. The capabilities of infrared sensing as a standalone measurement for flow metering were considered a possibility via an inferential approach for phase volumetric rates. More so, the derived infrared sensing flow characteristics could be combined with available pressure–volume–temperature correlations in estimating mass flow rates of each phase. As a future development, a conceptual modification to surface installations using a transparent opaque coupling is suggested to overcome the accessibility limitation of infrared light penetration for opaque pipes.

Determining the volume expansion of the CO2 + octane mixture using a fused silica capillary cell with in-situ Raman spectroscopy

Accurate expansion data for CO2 in petroleum model compounds (e.g., alkanes, cycloalkanes and aromatics) are fundamental information for CO2 sequestration and enhanced oil recovery in oil reservoir. In this study, the volume expansion of the CO2 + octane mixture was measured using a fused silica capillary cell with in situ Raman spectroscopy. A section of water was loaded between octane and CO2 in the fused capillary tube to seal the octane whilst allowing the diffusion of CO2 into the octane. Raman spectroscopy was applied during our experiments to verify that the CO2 + octane mixture reached phase equilibrium. Moreover, a good quadratic relationship was observed between the Raman peak intensity ratio and volume expansion factor. It was verified that this method can be used not only just to obtain more accurate experimental data, but also to protract additional volume expansion factor curves or curved surfaces from measured Raman peak intensity ratio using this equation. Over an extended temperature and pressure range, this method was thus shown to be more efficient and accurate than the traditional pressure–volume–temperature methods.

Current Approaches in Prediction of PVT Properties of Reservoir Oils

PVT (pressure-volume-temperature) properties of reservoir fluids in the oil and gas industry constitute an integral part of the required data for a thorough study of the reservoir, optimally compilation of oil production and operation schemes. In the absence of PVT data that measured in laboratory conditions, empirical correlation is used to evaluate these properties. These correlations cannot be applied universally due to the differences of crude oil composition, the working condition of geographical and oil environment. In the article widespread correlations and models was investigated in the field of prediction of PVT properties of reservoir oil from different regions. Their accuracy and productivity was thoroughly analyzed too.