Pressure Volume Temperature Research Articles

Static compression of B2 KCl to 230 GPa and its P-V-T equation of state

The pressure-volume-temperature (P-V-T) measurements of the B2 (CsCl-type) phase of KCl were performed at 9–61 GPa/1500–2600 K and up to 229 GPa at room temperature, based on synchrotron X‑ray diffraction measurements in a laser-heated diamond-anvil cell (DAC). The nonhydrostatic stress conditions inside the sample chamber were critically evaluated based on the platinum pressure marker. With thermal annealing by laser after each pressure increment, the deviatoric stress was reduced to less than 1% of the sample pressure even at the multi-megabar pressure range. The obtained P-V-T data were fitted to the Vinet equation of state with the Mie-Grüneisen-Debye model for thermal pressure. The thermal pressure of KCl was found to be as small as ~10 GPa even at 3000 K at any given volume, which is only half of that of common pressure markers (i.e. Pt, Au, or MgO). Such a low-thermal pressure validates the use of a KCl pressure medium as a pressure marker at high temperatures.

NEW DERIVED CORRELATIONS FOR LIBYAN CRUDE OIL TO ESTIMATE BUBBLE-POINT PRESSURE

The key factor of all petroleum engineering calculation is the knowledge of the PVT (Pressure, Volume, Temperature) parameters, such as determination of oil and gas flowing properties, predicting production performance in the future, production facilities designing and enhanced oil recovery planning methods. Those PVT properties are ideally determined experimentally in the laboratory. However, some of these experimental data is not always available; consequently, empirical correlations are used to estimate them. Many researchers have been focusing on models for predicting reservoir fluid properties from the available experimental PVT data, such as reservoir pressure, temperature, crude oil API gravity, gas oil ratio, formation volume factor, and gas gravity. The present study compares between some of the available empirical PVT correlations for estimating the bubble point pressure of some Libyan crude oils based on 35 data point samples from different Libyan oil fields. In the second part of this study, a new correlation has been derived to predict the bubble point pressure using Eviews software and compares the output results of this new correlation with some derived correlations found in the literature using statistical analysis such as the Average Absolute Error (AARE). The results showed an AARE as low as 8.7%, for bubble point pressure estimated by this new derived correlation. These results are valid to compare to other driven empirical correlations that have been evaluated.

Geochemical factors controlling the phase behavior of Eagle Ford Shale petroleum fluids

Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C7+ fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval Tmax release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.

An Evaluation of Steady-State-Based Pressure-Saturation Predictions in Gas-Condensate Reservoirs Under Various Reservoir and Well Operating Conditions

Summary The analysis of pressure-transient and rate-transient data in gas-condensate reservoirs (GCRs), operating below dewpoint pressure (Pdew) often requires using two-phase pseudovariables. These are used to handle the nonlinearities that arise in the governing partial-differential equation as a result of pressure-dependent saturation, mobility, and fluid-property changes. The incorporation of relative permeability (kr) data in the computation of such pseudovariables requires a priori knowledge of sufficiently representative pressure-saturation relationships. For this purpose, a number of analytical and semianalytical pressure-saturation prediction methods can be found in the literature. In this study, a pressure-saturation prediction method, which relates component weight fractions (in the gas phase, the condensate phase, and the reservoir fluid mixture) and gas fractional flow [or gas to total gas-plus-condensate flow rate (GTR)] to pressure, was used to compute pressure-saturation relationships for various reservoir fluids and two rock types. The computed pressure-saturation relationships were compared to the responses observed in the near-wellbore region of corresponding single-well 1D radial homogeneous compositional reservoir-simulation models operated at constant well flowing pressures (Pwf) lower than Pdew. Sensitivities were conducted to highlight the impact of gas-condensate fluid richness, kr characteristics, degree of reservoir undersaturation (Pi – Pdew), and Pwf on observed trends in the representativity of the predicted pressure-saturation relationships. Like other methods based on two-phase steady-state (SS) assumptions, the condensate saturations predicted by the GTR method generally matched those observed around the wellbore in the simulation models when Pi – Pdew was sufficiently high. For cases in which Pi – Pdew was not sufficiently high, an examination of radial pressure and saturation profiles from the simulation models showed that the trend of increased condensate saturation levels observed around the wellbore with increasing degrees of reservoir undersaturation, as reported in literature, represents one of three possible trends (i.e., increasing, decreasing, and almost-constant condensate-saturation levels). For cases in which the predicted GTR-based pressure-saturation curve showed lower (higher) condensate saturations than the pressure/volume/temperature (PVT) liquid-saturation curves at the given Pwf, increasing Pi – Pdew resulted in decreasing (increasing) condensate-saturation levels around the wellbore. The results indicate that at low Pi – Pdew values, trends in two-phase SS-based analysis techniques are affected by the gas-condensate fluid richness and the nature of the kr characteristics. It is also shown that for cases in which there is not much of a difference between PVT-based and SS-based pressure-saturation curves, variations in the Pi – Pdew do not affect the condensate-saturation levels around the wellbore.

Experimental measurement of the specific mass of drilling fluids at high pressure and high temperature

The knowledge of specific mass of drilling fluids are of great importance in defining the characteristics of them during drilling wells. In the present work, the specific mass of distilled water was carried out in a PVT (Pressure-Volume-Temperature) cell using the Constant Composition Expansion procedure under high pressure and high temperature. Results showed a good agreement with literature valures.

Effect of surfactant HLB value on Methane hydrate formation in non-ionic surfactant-oil water emulsions systems

The methane hydrate formulation in emulsion is an important factor affecting the blockage of the subsea oil and gas transportation pipeline. In this study, to understanding the behavior of methane hydrate in different emulsion and the influence of surface active components, emulsions with the different hydrophilic lipophilic balance (HLB) value of surfactant mixture were prepared with mineral oil, deionized water and two kinds of non-ionic surfactant (Span80 and Tween80) with different rat io. And the format ion kinetics of methane hydrate in different emulsion was measured using pressure-volume-temperature (PVT) method. The experimental results demonstrate that the surfactant HLB value has a great influence on methane hydrate formulation in non-ionic surfactant-oil water emulsions systems. It could be divided into three parts. When the HLB value is below8, the emulsion is water-in-oil emulsion, and the hydrate is easy to form with the hydrophilic increasing. And methane hydrates are most likely to generated with the HLB value range from 8 to 10. And when the HLB value above 10, the emulsion is oil-in-water, and the methane hydrate is hard to form in the emulsion with 30vol% water as the continuous phase.

Study on multiple‐contact phase behavior in natural gas injection for enhanced oil recovery in Tarim Basin, China

AbstractThe crude oil samples used in the study was from high‐pressure and high‐temperature (HPHT) reservoirs of Donghetang Oilfield in Tarim Basin in northwestern China. Crude oil–hydrocarbon gas multiple‐contact test and swelling tests are conducted to study the characteristics of phase behavior after hydrocarbon gas is injected into in the formation crude oil. The effect of different amounts of the injected hydrocarbon gas on saturation pressures of reservoir fluid is analyzed. The experimental results are regressed through PVTsim software. The authors use a state‐of‐the‐art HPHT pressure–volume–temperature (PVT) system to conduct the first contact miscibility pressure and swelling tests. Study results show that the multiple‐contact miscibility pressure is on the curve of saturation pressure of reservoir fluid versus the amount of injected gas. Furthermore, the first contact miscibility pressure is at the point of the curve where the tangent is zero. Multiple‐contact experiment is an important method for studying the mechanisms of miscible hydrocarbon gas flooding.

Viability of Gas-Injection EOR in Eagle Ford Shale Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191673, “Dynamic Data Analysis With New Automated Work Flows for Enhanced Formation Evaluation,” by Safian Atan, SPE, Arashi Ajayi, Matt Honarpour, Edward Turek, SPE, Eric Dillenbeck, and Cheryl Mock, BHP, and Mahmood Ahmadi and Carlos Pereira, MI3 Petroleum Engineering, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Gas-injection huff ’n’ puff enhanced-oil-recovery (EOR) techniques have the potential to improve liquid hydrocarbon recovery in ultratight, unconventional reservoirs. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. Reservoir-Analysis Work Flow Model Description. A compositional, fine-scale, dual-porosity, dual-permeability, symmetry-element numerical model was used in this study to model the current primary depletion and the EOR huff ’n’ puff process. In this study, the element of symmetry, which represents the bottom half of a cluster within a fracturing stage, is being extended to include three wells to allow the investigation of the effect of interference and containment on pad-level cyclic-gas-injection deployment. Production and injection of the entire well come from all active stages in each well, with equal weighting. The production and the injection for each cluster in every well are calculated proportionally by use of these assumptions. Model Input. The complete paper describes the critical input for the numerical model, including fracture half-length and fracture height, shape factor, absolute and relative permeability, and pressure/volume/temperature (PVT). History-Matching Work Flow. Because the history-matching solution is known to be highly nonunique, a comprehensive probabilistic approach was used to identify the realistic solution space. To facilitate this process, the authors used a three-step approach: Identify the solution space through parametric study. Perform combinatorial analysis of predetermined variables and understand available solutions within the solution space. Fine-tune history matching to identify the correct combination of parameters for probable solutions. Characterizing the Performance of Cyclic Natural-Gas Injection The compositional fluid-flow analysis of the combined sample of the separator liquid and gas at reservoir conditions indicated a volatile oil in the reservoir. To evaluate the phase behavior of the mixture, the original oil and the gas supplied for injection purposes were mixed at different ratios. For each mixture, the calibrated equation of state (EOS) is used to evaluate the resulting phase diagram and fluid properties by modeling a constant-composition-expansion experiment at reservoir conditions. The 1979 Peng-Robinson EOS with nine components was used to model the PVT changes resulting from the composition changes related to each injection ratio. As the composition changes, the phase behavior and the fluid properties also change. The fluid system in the reservoir gradually changed from a volatile oil to a gas condensate. Results show that when injected-gas makeup is 20% or greater, the phase behavior changes from volatile oil to gas condensate. When the mixture consists of more than 70% injected gas, at any pressure below 6,000 psi, there is a possibility that condensation can occur.

Model Simulates Gas Kicks in Nonaqueous Drilling Fluids

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189606, “Gas Kicks in Nonaqueous Drilling Fluids: A Well-Control Challenge,” by Z. Ma, A. Karimi Vajargah, D. Chen, and E. Van Oort, SPE, The University of Texas at Austin, and R. May, J.D. MacPherson, SPE, G. Becker, SPE, and D. Curry, SPE, Baker Hughes, a GE Company, prepared for the 2018 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed. Nonaqueous drilling fluids, such as synthetic-based and oil-based mud (SBM and OBM, respectively), are used frequently to drill one or more sections of a well to reduce drilling problems such as shale sloughing, wellbore stability, and stuck pipe. However, solubility of formation gas in such fluids makes early gas detection, and the well-control process, very challenging. This is of particular concern in deep offshore wells. This paper presents a novel and comprehensive hydraulic model to simulate a gas kick in nonaqueous drilling fluids. Introduction Early kick detection becomes cumbersome when a nonaqueous drilling fluid is used. This is because of dissolution of gas in the nonpolar base fluid. Although gas entrance into the well still will result in increased flow-out on surface, the flow signature will be less pronounced in comparison with a similar gas kick in water-based mud (WBM). Moreover, the emergence of gas from the solution may often only begin when the gas/drilling-fluid mixture is relatively close to the surface, which leaves the crew only a short period to react before gas reaches the surface. Constant-bottomhole-pressure/managed-pressure drilling (CBHP-MPD) offers the benefit of delaying the bubblepoint until the kick has passed the choke, thereby not allowing the kick to come out of solution in the actual well. Background Gas-Kick-Simulation Multiphase-Flow Modeling. The drift-flux model (DFM) used in this work is a mechanistic model consisting of separate mass-balance equations and a combined momentum-balance equation, together with several closure algebraic equations and a slip law. To obtain the velocity of each phase, the slip law is used in conjunction with the combined momentum-balance equation. Solubility in oil-based drilling fluids is directly proportional to pressure, gas specific gravity, and base-oil volume in the drilling fluid and is inversely proportional to temperature, drilling-fluid solids content, and brine and emulsifier volumes in the drilling fluid. For a given drilling-fluid volume, the relative volumes of base oil, brine, and emulsifier in the drilling fluid can be determined from a standard retort analysis. However, the most-reliable method to determine this crucial simulation parameter is to conduct pressure/volume/temperature (PVT) testing for each mixture under downhole conditions. DFM Formulation. Mathematical modeling of a proposed 1D DFM to describe the multiphase-flow dynamics for non-aqueous drilling fluids is discussed in detail in the complete paper. The current formulation takes into account the mass transfer between the liquid (drilling fluid) and formation/injected gas. The model consists of two sets of partial differential equations for two different cases: when gas is completely dissolved in the liquid (no free gas) and when dissolved and free gas coexist in the system.

A Self-Adaptive Artificial Intelligence Technique to Predict Oil Pressure Volume Temperature Properties

Reservoir fluid properties such as bubble point pressure (Pb) and gas solubility (Rs) play a vital role in reservoir management and reservoir simulation. In addition, they affect the design of the production system. Pb and Rs can be obtained from laboratory experiments by taking a sample at the wellhead or from the reservoir under downhole conditions. However, this process is time-consuming and very costly. To overcome these challenges, empirical correlations and artificial intelligence (AI) models can be applied to obtain these properties. The objective of this paper is to introduce new empirical correlations to estimate Pb and Rs based on three input parameters—reservoir temperature and oil and gas gravities. 760 data points were collected from different sources to build new AI models for Pb and Rs. The new empirical correlations were developed by integrating artificial neural network (ANN) with a modified self-adaptive differential evolution algorithm to introduce a hybrid self-adaptive artificial neural network (SaDE-ANN) model. The results obtained confirmed the accuracy of the developed SaDE-ANN models to predict the Pb and Rs of crude oils. This is the first technique that can be used to predict Rs and Pb based on three input parameters only. The developed empirical correlation for Pb predicts the Pb with a correlation coefficient (CC) of 0.99 and an average absolute percentage error (AAPE) of 6%. The same results were obtained for Rs, where the new empirical correlation predicts the Rs with a coefficient of determination (R2) of 0.99 and an AAPE of less than 6%. The developed technique will help reservoir and production engineers to better understand and manage reservoirs. No additional or special software is required to run the developed technique.

Implementation of multilayer perceptron (MLP) and radial basis function (RBF) neural networks to predict solution gas-oil ratio of crude oil systems

Abstract Exact determination of pressure-volume-temperature (PVT) properties of the reservoir oils is necessary for reservoir calculations, reservoir performance prediction, and the design of optimal production conditions. The objective of this study is to develop intelligent and reliable models based on multilayer perceptron (MLP) and radial basis function (RBF) neural networks for estimating the solution gas–oil ratio as a function of bubble point pressure, reservoir temperature, oil gravity (API), and gas specific gravity. These models were developed and tested using a total of 710 experimental data sets representing the samples of crude oil from various geographical locations around the world. Performance of the developed MLP and RBF models were evaluated and investigated against a number of well-known empirical correlations using statistical and graphical error analyses. The results indicated that the proposed models outperform the considered empirical correlations, providing a strong agreement between predicted and experimental values, However, the developed RBF exhibited higher accuracy and efficiency compared to the proposed MLP model.

PVC/PBA random copolymers obtained by SET–DTLRP: Pressure effect on glass transition, rheology, and processing

A study of the effect of pressure on the glass transition and viscosity of poly(vinyl chloride) (PVC)–poly(butyl acrylate) random copolymers prepared by Single Electron Transfer–Degenerative Chain Transfer Living Radical Polymerization and able to act as self‐plasticized PVCs, is presented. The research has a dual purpose, as it focuses on polymer physics, as well as on applied polymer processing. Results of dynamic mechanical thermal analysis, pressure–volume–temperature (PVT), and extrusion capillary tests were combined, to analyze the additivity of the free volume and the effect of frequency and pressure on the glass transition of the copolymers, Tg. Free volume additivity, which is on the basis of self‐plasticization, was revealed by Tg and activation energy of flow, Ea, results. dTg/dP results were linked to the number of segments involved in the glass transition temperature. Using an ad hoc model, which involves parameters obtained by PVT and the activation energy of flow, the pressure‐viscosity coefficient was determined. This allowed estimating the viscosity as a function of the shear rate, the temperature and the pressure, offering suitable data to be employed in virtual injection molding. J. VINYL ADDIT. TECHNOL., 25:76–84, 2019. © 2018 Society of Plastics Engineers

Phase Behavior of Heavy-Oil/Propane Mixtures

Summary The phase behavior of heavy-oil/propane mixtures was mapped from temperatures ranging from 20 to 180°C and pressures up to 10 MPa. Both vapor/liquid (VL1) and liquid/liquid (L1L2) regions were observed. Saturation pressures (VL1 boundary) were measured in a Jefri 100-cm3 pressure/volume/temperature (PVT) -cell and blind-cell apparatus. The propane content at which a light propane-rich phase and a heavy bitumen-rich (or pitch) phase formed (L1/L1L2 boundary) was visually determined with a high-pressure microscope (HPM) while titrating propane into the bitumen. High-pressure and high-temperature yield data were measured using a blind-cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure propane-rich-phase and pitch-phase compositions in a PVT cell. Pressure/temperature and pressure/composition phase diagrams were constructed from the saturation-pressure and pitch-phase-onset data. High-pressure micrographs demonstrated that, at lower temperatures and propane contents, the pitch phase appeared as glassy particles, whereas at higher propane contents and temperatures, it appeared as a liquid phase. Ternary diagrams were also constructed to present phase-composition data. The ability of a volume-translated Peng-Robinson cubic equation of state (CEOS) (Peng and Robinson 1976) to match the experimental measurements was explored. Two sets of binary-interaction parameters were tested: temperature-dependent binary-interaction parameters (SvdW) and composition-dependent binary-interaction parameters (CDvdW). Models derived from both types of binary-interaction parameters matched the saturation pressures and the L1L2 boundaries at one pressure but could not match the pressure dependency of the L1L2 boundary or the measured L1L2 phase compositions. The SvdW model could not match the yield data, whereas the CDvdW model matched yields at temperatures up to 90°C.

Quantification of Mutual Mass Transfer of CO2/N2–Light Oil Systems by Dynamic Volume Analysis

A novel and pragmatic method has been developed to quantify mutual mass transfer between a gas (e.g., CO2 and N2) and light oil by dynamic volume analysis. Experimentally, diffusion experiments for pure CO2/N2-light oil systems are conducted at a constant pressure and temperature with a pressure/volume/temperature (PVT) system. During the diffusion experiments, the diluted volume of oil phase is continuously monitored and recorded, while gas samples are collected at the end of the diffusion tests to measure gas compositions by performing gas chromatography (GC) analysis. Theoretically, the mass transfer from light oil to gas phase and the solubility of a gas into the light oil is quantified by combining the GC analysis and Fick’s second law, while the Peng–Robinson equation of state is employed to determine the concentration of each gas component in the oil phase by imposing the quasi-equilibrium boundary condition at the gas–oil interface. The diffusion coefficient of each component can be determined onc...

An Experimental and Modeling Study of Carbon Dioxide/Bitumen and C4/Bitumen Phase Behavior at Elevated Temperatures Using Cold Lake Bitumen

Summary The coinjection of carbon dioxide (CO2) or light hydrocarbons with steam in the steam-assisted-gravity-drainage (SAGD) process might enhance bitumen mobility and reduce the steam/oil ratio (SOR). Understanding and modeling the phase behavior of solvent/bitumen systems are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen/CO2 and bitumen/C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater Formation. Constant-composition-expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2/bitumen mixture, and C4/bitumen mixture. The Peng and Robinson (1978) equation of state (EOS) (PR-EOS) is calibrated using the measured data and is used for pressure/volume/temperature (PVT) modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 393.2 to 453.2 K. The potential of asphaltene precipitation for CO2/bitumen and C4/bitumen mixtures is also investigated using three screening criteria. According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than does CO2 at operating pressure of 3997.9 kPa and temperature between 393.2 and 453.2 K (393.2 K < T < 453.2 K). During the CCE tests, coexistence of three equilibrium phases is observed for the C4/bitumen system with high C4 concentration. The three phases consist of a heavy oleic phase (L1), gaseous phase (V), and a light (solvent-rich) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into the L2 phase and preserve the heavy components in the L1 phase. Also, the L2 phase becomes darker by increasing the pressure, suggesting the extraction of heavier hydrocarbon components at higher pressures. Similar tests on the CO2/bitumen system show only two effective phases over a similar temperature range. The two phases consist of a heavy oleic phase (L1) and a gaseous phase (V). Phase-equilibrium regions are predicted using the regressed EOS model in the compositional space for the solvent/bitumen system. EOS predictions indicate two types of two-phase regions in the composition space for the C4/bitumen system (i.e., L1/L2 when 393.2 K < T < 421.2 K and L1/V when 421.2 K < T < 453.2 K). However, only one type of two-phase region (i.e., L1/V) exists in a similar temperature range for a CO2/bitumen system. The EOS predictions show that 1.8 wt% CO2 can reduce bitumen viscosity by up to 1.4 times, and 16.3 wt% C4 can reduce bitumen viscosity by up to 20 times when 393.2 K < T < 453.2 K. Viscosity calculations indicate that oil dilution by CO2 and C4 dissolution is more effective at lower temperatures, especially for C4. This shows the potential of injecting hot hydrocarbon solvents for bitumen recovery. The results show that asphaltene might precipitate in a system of C4/bitumen with high C4 concentration.

Experimental and theoretical investigation of CO2 mass transfer enhancement of silica nanoparticles in water

Nanofluids have novel characteristics that make them potentially useful for different applications. Realizing modest mass transfer enhancement in conventional nanofluids, in this study, mass-transfer of carbon dioxide in pure water and water-based nanofluids dispersed with silica nanoparticles at different initial pressures up to 15 MPa and at temperatures of 35 °C and 45 °C was investigated. Deionized water and two nanofluids at different concentrations with volume of 150 cm3 were used for this purpose. CO2 was brought in contact with each solution in a pressure-volume-temperature (PVT) cell with no mixer. Additionally, carbon dioxide diffusion coefficients at different pressures were estimated based on Fick's law. The obtained results demonstrated that water/silica nanofluid with 0.5 wt% and 0.1 wt% increased the carbon dioxide diffusion coefficient up to 39.2% and 11.9% compared to that in pure distilled water, respectively. Moreover, it was observed that the measured diffusion coefficient of carbon dioxide in water increased with temperature rise from 35 °C to 45 °C at constant pressure. However, it could be seen that, the diffusion coefficient decreased with pressure at constant temperature. It was concluded that among the enhancement mechanisms of nanoparticles, (i.e. grazing effect and Brownian motion), Brownian motion would play the main role in mass transfer enhancement.

Thermodynamic modeling of hydrogen solubility in a series of ionic liquids

In this study, the Perturbed Hard Sphere Chain Equation of State (PHSC EoS) has been employed to predict the hydrogen solubility in a series of ionic liquids. As ionic liquids have no vapor pressure and no critical parameters and as hydrogen is a light molecule which behaves like a perfect gas, simple cubic equations of state cannot be used for modeling of H2 + ionic liquid mixture. Three main parameters of non-cubic PHSC EoS, i.e. (r) the number of segments per molecule, (σ) the distance between two molecules at zero potential and (ε) well-depth of potential between two non-bonded units have been calculated by regression of the experimental Pressure-Volume-Temperature (PVT) data points. The hydrogen solubility decreases with increasing temperature in [BMIM][BF4], [BMIM][C8SO4], [EMIM][EtSO4], [MDEA][Cl], and [N4,1,1,1][Tf2N], but inverse temperature effect is observed in [BMIM], [BMPY], [EMIM] and [HMIM][Tf2N] as well as [BMIM][MeSO4]. The binary interaction parameter which has been obtained from fitting of the equation of state with experimental hydrogen absorption data shows both the usual and the opposite trend of temperature effect as well.

Thermodynamic Behavior of Olefin/Methane Mixtures Applied to Synthetic-Drilling-Fluid Well Control

Summary The presalt hydrocarbon discoveries in Brazilian deep water have been a challenging environment for drilling operations as a result of the technical demands and restrictions and the environmental regulations driving scientific and technological development. In this drilling context, an accurate estimation of the downhole pressure is mandatory to avoid drilling problems such as kicks, lost circulation, and wellbore instability. When considering kick prevention and control, understanding of the mixture behavior (drilling fluid and formation gas) is essential to improve the estimation of the downhole pressure, which would support efficient, safe, and economic drilling operations. The widespread application of synthetic-based drilling fluids in the Brazilian presalt polygon is justified by the technical performance offered by this kind of drilling fluid, such as reduced drilling time compared with water-based drilling fluids, increased lubricity in directional and horizontal wells, and shale-swelling inhibition. In addition, this is an environmentally friendly alternative to oil-based drilling fluids. However, those fluids are more sensitive to pressure and temperature variations than water-based drilling fluids. To obtain a better understanding of the behavior of one specific kind of synthetic-based drilling fluid, the olefin experimental research was conducted and the results and findings are presented in this technical article. The work involved pressure/volume/temperature (PVT) measurements for olefin/methane mixtures to investigate the effect of pressure, temperature, and mixture composition on thermodynamic properties such as density, formation volume factor (FVF), gas-solubility ratio, and saturation pressure. Those properties are important for knowledge of the mixture volumetric behavior at downhole conditions, especially when gas enters the wellbore. The experiments were conducted at isothermal conditions, and a gas-enrichment experimental procedure was applied. The temperature range was from 25 to 80°C (77 to 176°F), the gas molar fraction (GMF) ranged from 30 to 50%, and pressure was up to 69 MPa (10,000 psi). In addition, the measured data were compared with an existing database (Silva et al. 2004; Atolini 2008) for methane/n-paraffin mixtures, as well as for methane/ester mixtures (Kim et al. 2015). Pit-gain analyses were also performed according to the procedure of Monteiro et al. (2010), and a comparison of the results with other base fluids showed interesting findings.

Presenting a new predictive viscosity model based on virial-like equations of state for monatomic fluids

ABSTRACTWe present a new model using virial-like equations of state (EOSs) to calculate the viscosity of pure monatomic fluids that are applicable to liquid, gas, and supercritical regions. The viscosity model has been constructed according to the similarity between P–V–T (pressure–volume–temperature) and T–μ–P (temperature–viscosity–pressure) relationship. Over an extensive pressure and temperature ranges, the obtained results are comparable with the experimental data. The average range of application of this model is for reduced temperatures between 0.5 and 43.5 and for reduced pressures between 0.1 and 78.4. The obtained results are consistent with the experimental data, except in the vicinity of the critical point, the average absolute deviation percent is 2.5 compared with the experimental data. Using the temperature and pressure, calculation of fluid viscosity is straightly possible by applying this model. Based on the findings of this paper, prediction of high-pressure liquid and far-supercritical viscosities of a fluid using low-pressure liquid and gaseous EOSs is possible.

Correlation Approach Predicts Viscosity of Crude-Oil Systems Offshore Norway

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191296, “An Improved Correlation Approach To Predict Viscosity of Crude-Oil Systems on the NCS,” by Jørgen Bergsagel Møller, SPE, Knut Kristian Meisingset, SPE, and Ibnu Hafidz Arief, Equinor, prepared for the 2018 SPE Norway One Day Seminar, Bergen, Norway, 18 April. The paper has not been peer reviewed. An accurate estimation of viscosity values is imperative for optimal production and transport design of hydrocarbon fluids. Consequently, precise and robust empirical correlation models are highly desired. While the literature contains numerous correlation models, most of these are inadequate for predicting accurate oil viscosity with unbiased data. This paper aims to develop new and improved empirical viscosity correlations through available field measurements on the Norwegian Continental Shelf (NCS). Introduction The most-accurate viscosity correlation method makes use of the material balance of compositional information, which implies that a comprehensive pressure/volume/temperature (PVT) report is required. Such PVT reports usually include oil viscosity, which makes the correlation model redundant in many cases. Often, the only information available related to the fluid property is the solution gas/oil ratio (GOR), temperature, American Petroleum Institute (API) gravity, and pressure. Literature Review The empirical correlations in the literature have established categories to correlate oil viscosity for dead, gas-saturated, and undersaturated oil. The dead-oil correlations are used to predict the viscosity at standard conditions, when no gas is left in solution. All correlations from the literature ex press dead-oil viscosity as a function of API gravity and temperature. The second category is defined as a function of dead-oil viscosity and solution GOR and is applied when the fluid is at, or below, the saturation pressure. The latter correlation is normally expressed as a function of saturated oil viscosity, bubblepoint pressure, and reservoir pressure. The undersaturated-oil-viscosity correlations are applied when the reservoir pressure increases beyond the saturation pressure. This study investigates the statistical performance of 10 dead-oil, eight saturated, and five undersaturated oil-viscosity correlations. Methodology Traditionally, the correlation models present an explicit mathematical expression based on field measurements to predict viscosity, while this paper presents three different correlation methods. Two methods are recognized as surrogate models to predict the viscosity properties, called the radial basis function network (RBFN) and kriging. In contrast to the traditional correlation models, these techniques do not present a mathematical correlation, because the models make use of a statistical approach with more consideration of the variation in input variables to predict the output. The kriging method demonstrated results superior to those of the empirical correlations. The third and last approach is an optimization algorithm called particle-swarm optimization (PSO). The technique recalculates the coefficients of the discussed correlations from the literature while maintaining the functional form of the expressions.