Fluid properties at high pressures and temperatures: Experimental and modelling challenges

Thermophysical properties impact many aspects of the chemical process industries. Here three example areas, primarily in the energy sector, are highlighted to provide context for the experimental and modelling challenges associated with obtaining fluid property data at high pressures and temperatures (HPHT). These three areas include the recovery of petroleum reserves in ultra-deep reservoirs, the use of lubricants to reduce frictional losses in the automotive industries, and the use of high-pressure, common rail diesel fuel delivery to reduce soot emissions for greener environments. The accurate knowledge of thermodynamic and transport properties in these three focused areas minimizes associated operating uncertainties and accelerates safe, reliable, and robust process and product development

Measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems

Carbon dioxide injection has currently become a major gas injection process for improved oil recovery. Laboratory evaluations of gas-oil miscibility conditions play an important role in process design and economic success of field miscible gas injection projects. Hence, this study involves the measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems. A promising new vanishing interfacial tension (VIT) experimental technique has been further explored to determine fluid-fluid miscibility. Interfacial tension measurements have been carried out in three different fluid systems of known phase behavior characteristics using pendent drop shape analysis and capillary rise techniques. The quantities of fluids in the feed mixture have been varied during the experiments to investigate the compositional dependence of fluid-fluid miscibility. The miscibility conditions determined from the VIT technique agreed well with the reported miscibilities for all the three standard fluid systems used. This confirmed the sound conceptual basis of VIT technique for accurate, quick and cost-effective determination of fluid-fluid miscibility. As the fluid phases approached equilibrium, interfacial tension was unaffected by gas-oil ratio in the feed, indicating the compositional path independence of miscibility. Interfacial tension was found to correlate well with solubility in multicomponent hydrocarbon systems. The experiments as well as the use of existing computational models (equations of state and Parachor) indicated the importance of counter-directional mass transfer effects (combined vaporizing and condensing mass transfer mechanims) in fluid-fluid miscibility determination. A new mechanistic Parachor model has been developed to model dynamic gas-oil miscibility and to determine the governing mass transfer mechanism responsible for miscibility development in multicomponent hydrocarbon systems. The proposed model has been validated to predict dynamic gas-oil miscibility in several crude oil-gas systems. This study has related various types of developed miscibility in gas injection field projects with gas-oil interfacial tension and identified the multitude of roles played by interfacial tension in fluid-fluid phase equilibria. Thus, the significant contributions of this study are further validation of a new measurement technique and development of a new computational model for gas-oil interfacial tension and miscibility determination, both of which will have an impact in the optimization of field miscible gas injection projects

Interfacial tension of aqueous and hydrocarbon systems in the presence of carbon dioxide at elevated pressures and temperatures

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Interfacial tension of reservoir fluids : an integrated experimental and modelling investigation

Interfacial tension (IFT) is a property of paramount importance in many technical areas as it deals with the forces acting at the interface whenever two immiscible or partially miscible phases are in contact. With respect to petroleum engineering operations, it influences most, if not all, multiphase processes associated with the extraction and refining of Oil and Gas, from the optimisation of reservoir engineering strategies to the design of petrochemical facilities. This property is also of key importance for the development of successful and economical CO2 geological storage projects as it controls, to a large extent, the amount of CO2 that can be safely stored in a target reservoir. Therefore, an accurate knowledge of the IFT of reservoir fluids is needed. Aiming at filling the experimental gap found in literature and extending the measurement of this property to reservoir conditions, the present work contributes with fundamental IFT data of binary and multicomponent synthetic reservoir fluids. Two new setups have been developed, validated and used to study the impact of high pressures (up to 69 MPa) and high temperatures (up to 469 K) on the IFT of hydrocarbon systems including n-alkanes and main gas components such as CH4, CO2, and N2, as well as of the effect sparingly soluble gaseous impurities and NaCl on the IFT of water and CO2 systems. Saturated density data of the phases, required to determine pertinent IFT values, have also been measured with a vibrating U-tube densitometer. Results indicated a strong dependence of the IFT values with temperature, pressure, phase density and salt concentration, whereas changes on the IFT due to the presence of up to 10 mole% gaseous impurities (sparingly soluble in water) laid very close to experimental uncertainties. Additionally, the predictive capabilities of classical methods for computing IFT values have been compared to a more robust theoretical approach, the Density Gradient Theory (DGT), as well as to experimental data measured in this work and collected from literature. Results demonstrated the superior capabilities of the DGT for accurately predicting the IFT of synthetic hydrocarbon mixtures and of a real petroleum fluid with no further adjustable parameters for mixtures. In the case of aqueous systems, one binary interaction coefficient, estimated with the help of a single experimental data point, allowed the correct description of the IFT of binary and multicomponent systems in both two- and three-phase equilibria conditions, as well as the impact of salts with the DGT

Compositional effects on gas-oil interfacial tension and miscibility at reservoir conditions

Minimum miscibility pressure (MMP) is an important optimization parameter for an enhanced oil recovery process involving Carbon Dioxide or hydrocarbon gas injection. Therefore an accurate experimental measurement is required to determine the MMP. The MMP for a gas-oil system is directly related to the interfacial tension between the injected gas and the reservoir crude oil. When CO2 gas contacts the reservoir oil at reservoir temperature, the interfacial tension between the fluid-fluid phases reduces as the miscibility is approached and the interface between the fluid-fluid phases eventually disappears at miscibility i.e. the interfacial tension becomes zero. Hence, a pressure condition of zero interfacial tension at reservoir temperature is the minimum miscibility pressure for a CO2-reservoir crude oil system. The Vanishing Interfacial Technique (VIT) technique to determine MMP is based on this principle. Therefore, this research project involves the measurement of gas-oil interfacial tensions for a CO2-live reservoir oil system at reservoir conditions using the pendant drop and the capillary rise techniques to determine the minimum miscibility pressure through the VIT technique. Gas-oil interfacial tension, being a property of the interface between crude oil and gas, is strongly affected by the compositional changes induced by the counter-directional mass transfer (vaporizing, condensing or a combination of the two) of the various components taking place between the CO2 and reservoir oil. This study hence investigates the mass transfer mechanisms involved in these dynamic gas-oil interactions responsible for miscibility development by performing detailed compositional analyses, and density measurements. All the measurements were carried out at different ratios of fluid phases in the feed mixture (both molar and volumetric) for various pressures at the reservoir temperature in order to also study the effects of the initial feed composition on IFT and the phase compositions. This study has experimentally demonstrated that the gas-oil interfacial tension measured at varying feed compositions (i.e., initial gas-oil molar and gas-oil volume ratios) at reservoir temperature, although showing different relationships with pressure, converged to the same endpoint of zero-interfacial tension or similar minimum miscibility pressures. The effect of gas-oil molar ratios and gas- oil volume ratios on the compositions of the equilibrium phases for this CO2-reservoir fluid system proved that the mechanism involved in the mass transfer of hydrocarbon components between the fluid-fluid phases was a condensing gas drive mechanism. This study has demonstrated that the MMP determined from the VIT technique is independent of the compositional path followed by the fluids during their continuous interaction prior to attaining mass transfer equilibrium

Relevant properties and governing mechanisms for oil recovery and geological carbon dioxide storage applied to jordanian shale

Mit Blick auf den stetig wachsenden Energiebedarf und der damit im Zusammenhang stehenden dramatischen Zunahme der CO2-Konzentration in der Atmosphäre steht die Menschheit vor der Aufgabe, Antworten auf bislang beispiellose Herausforderungen zu finden. Trotz verstärkter Bemühungen, die sogenannte Energiewende voranzutreiben, geht der Großteil der Vorhersagen davon aus, dass die Grundlage zur Deckung des globalen Energiebedarfes weiterhin durch fossile Brennstoffe gesichert wird. Gleichzeitig ist eine deutliche Abnahme der Produktion aus konventionellen Ölreserven zu verzeichnen, sodass nicht-konventionelle Ressourcen in Zukunft eine größere Rolle übernehmen werden. Auf der anderen Seite werden die Bemühungen zur Abtrennung und Untertagespeicherung von CO2 als ein Bestandteil der Dekarbonisierung vorangetrieben. Erfahrungen mit der Injektion von CO2 existieren bereits seit den 1970er Jahren im Rahmen der sogenannten “CO2-enhanced oil recovery” (CO2-EOR) mit gutem Erfolg zur Steigerung der Förderraten aus konventionellen Lagerstätten. Daher erscheint es naheliegend, die beiden Prozesse im Sinne einer zügigen Umsetzung der Energiewende zu kombinieren und in der Folge auch für nicht-konventionelle Lagerstätten in Betracht zu ziehen. Über die mögliche Anwendung innovativer Methoden in diesen oft sehr komplexen Gesteinsformationen ist bislang wenig bekannt geworden. Daher befasst sich die aktuelle Dissertation mit einer Reihe an Phänomenen, die im Zusammenhang mit der Applikation von komprimiertem CO2 auf Schieferformationen relevant sind. Entscheidende Systemeigenschaften wurden in dieser Arbeit untersucht mit dem Ziel, Möglichkeiten zur Kombination einer CO2-gestützten Förderung von Kohlenwasserstoffen mit der Einspeicherung von CO2 in nicht-konventionellen Lagerstätten zu evaluieren. Jordanischer Ölschiefer (Sultani) dient hier als Beispiel mit einem erheblichen Potenzial aus wirtschaftlicher und umwelttechnischer Sicht. Es werden umfangreiche und systematische experimentelle Untersuchungen zum grundlegenden Phasen-, Grenzphasen- und Stofftransportverhalten in komplexen dichten Wasser- und Kohlenwasserstoffhaltigen Gesteinsformationen in Kontakt mit komprimiertem CO2 vorgestellt. In einem ersten Schritt wurde Sultani-Schiefer einer Extraktion mit überkritischem CO2 unterzogen. Dabei wurde der Einfluss unterschiedlicher Betriebsparameter auf die Ausbeute untersucht, die wiederum in direktem Zusammenhang mit der Löslichkeit unterschiedlicher im Ölschiefer enthaltener Komponenten in der CO2-Phase steht. Neben der Analyse des Mehrphasenverhaltens, zu dem die Bestimmung von Gemischdichten, die Löslichkeit von CO2 in Kohlenwasserstoffmischungen und die daraus folgende volumetrische Ausdehnung der Kohlenwasserstoffphase gehört, bestand ein Schwerpunkt der Arbeit in der experimentellen Betrachtung von Grenzphaseneigenschaften unter Lagerstättenbedingungen. Als eine maßgebliche Größe wurde die Grenzflächenspannung in mehrphasigen Multikomponentensystemen mittels der Methode des hängenden, stehenden bzw. liegenden Tropfens bestimmt. Die Benetzung an den inneren Porenwänden wird durch den Dreiphasen-Kontaktwinkel beschrieben, der sowohl im System CO2- Formationswasser-Schiefer als auch in dem System CO2-Kohlenwasserstoff-Formationswasser-Schiefer an liegenden Tropfen bestimmt wurde. Zur Erklärung der Abhängigkeit der Benetzung von der Zusammensetzung der wässerigen Phase wurden Messungen des Zeta – Potentials an in wässerigen Salzlösungen suspendierten Schieferpartikeln unternommen. Die Grenzfläche Feststoff-CO2 war hingegen Gegenstand von Messungen mittels einer gravimetrischen Methode, mittels derer die Adsorptionskapazität des Schiefers bestimmt wurde, die einerseits als eine der möglichen Speichermechanismen für CO2 gilt und andererseits in direkter Beziehung zum Benetzungsverhalten in Anwesenheit von wässerigen Salzlösungen steht. In Ergänzung zu dem Mehr- und Grenzphasenverhalten wurden Diffusionskoeffizienten von komprimiertem CO2 im Gestein bestimmt, die letzten Endes über die Zeitskala der im Fokus stehenden ablaufenden Prozesse entscheidet. Im Ergebnis führen die hohen Wechselwirkungen aller beteiligten Phasen mit überkritischem CO2 zu bedeutenden Änderungen in den Systemeigenschaften, die die Mobilisierung der Kohlenwasserstoffe generell fördern, während sich diese auch negativ auf eine GeoSpeicherung von CO2 etwa über die Herabsetzung des kapillaren Eindringdruckes auswirken können. Die Arbeit liefert einen wertvollen Einblick in Mechanismen, Systemeigenschaften sowie kritische Faktoren, die für eine erfolgreiche Umsetzung einer CO2-gestützten Ölförderung und der CO2-Speicherung bzw. einer Kombination beider Prozesse in nicht-konventionellen Gesteinsformationen relevant sindIn light of the ever-growing energy demand and the increasing atmospheric concentrations of carbon dioxide, the necessity of finding a panacea to these global challenges is unprecedented. In spite of several attempts to accelerate the energy transition, future outlooks indicate that fossil fuels will remain the foundation that supports the livelihood and economic prosperity of global societies. Owing to the declining rates of conventional oil production and the inevitable depletion of conventional reserves, it is predicted that unconventional resources will play a significant role in reshaping future energy markets, implying that the climate change dilemma associated with fossil fuels will linger on. On the other hand, Carbon Capture and Storage (CCS) has emerged as a pathway to decarbonization, whereas enhanced oil recovery using carbon dioxide (CO2-EOR) has already demonstrated great success in boosting oil production of existing oil fields since the 1970s. Accordingly, the combination of CCS and CO2-EOR is proposed as a solution to the energy-climate predicament. This approach is also being currently considered in shales, however, little is still known about its applicability in these formations. Accordingly, the current work aims to investigate a series of phenomena that contribute to oil recovery from shale using supercritical CO2. Additionally, within the context of geological carbon storage (GCS), several decisive interfacial and phase properties are examined, with the objective of combining the use of CO2 for oil recovery with its own storage. Jordanian oil shale (Sultani) is used as an example in the current work for the potential economic and environmental interest on the one hand, and for the acquired knowledge that can be generalized and transferred to any oil-bearing unconventional reservoir on the other. The presented work is a comprehensive experimental study on the principal phase, interfacial and transport properties taking place when complex oil and water-bearing shale formations are contacted with compressed CO2. As an initial step in this investigation, Sultani shale is subject to supercritical fluid extraction using CO2 as solvent. The impact of several parameters on the yield, which is related to the solubility of various compounds in the supercritical phase, is examined. Apart from the phase behavior that also includes mixture densities, volumetric expansion and gas solubility in hydrocarbons, interfacial properties are the principal focus of this work. Interfacial tension in binary and multicomponent systems at reservoir conditions, i.e. at elevated pressures, is measured using the pendant drop and the rising bubble methods, respectively. The contact angle, a measure of wettability, is determined using the sessile drop in CO2- brine-shale systems. The captive bubble method is employed to assess the contact angle in the multicomponent system comprising CO2, brine, oil and shale. Zeta potential is determined for “shale in water/brine” suspensions to investigate the evolution of the charge at the water/brine-shale interface in pursuit of explaining the wettability alteration in response to changing the aqueous phase composition. With respect to the fluid-solid interface, the CO2 adsorption capacity of shale is measured at pressures and temperatures relevant to gas storage using a gravimetric method, and its relation to the wetting behavior in presence of brines representative of formation water is elucidated. Complementing the interfacial properties and the phase behavior, CO2 diffusivity within shale formations is quantified. All in all, it is found that the strong interactions of supercritical CO2 with all coexisting phases alter the system properties significantly, mainly in an advantageous way regarding oil recovery. In terms of GCS, supercritical CO2 is found to alter system properties in both favorable and unfavorable ways, depending on the gas storage mechanism in question. The findings of the current work give valuable insight into mechanisms, properties, and critical factors which are necessary for the design and implementation of successful oil recovery and CO2 storage processe

Characterization of Rock/Fluids Interactions at Reservoir Conditions

In this study, interfacial phenomena of spreading, wettability, and rock/oil adhesion interactions in complex rock/oil/water systems were characterized at reservoir conditions of elevated pressures and temperatures. Capabilities of both ambient and reservoir condition optical cells were used for measuring the oil/water interfacial tension and dynamic (the water-receding and the water-advancing) contact angles for various complex rock/oil/water systems. Well known sessile oil drop volume alteration method was successfully used in this study for evaluating the applicability of the modified Young’s equation for characterizing the line tension in complex rock/oil/water systems at reservoir conditions. This appears to be first time when rock/fluids interactions in complex rock/oil/water systems of petroleum engineering interest have been characterized in terms of the measured oil/water interfacial tension (IFT), wettability, line tension, and the work of adhesion at elevated pressures (up to 14,000 psi) and temperatures (up to 250°F) using representative reservoir fluids and common reservoir rock minerals surfaces (glass, quartz, dolomite or calcite). Different oil (recombined live oil and stock-tank oil) and aqueous (deionized water, synthetic reservoir brines, synthetic sea water, and 35,000 ppm NaCl solution) phases were used to study the effects of fluids composition and experimental conditions on the oil/water IFT and the wetting characteristics of complex rock/oil/water systems of petroleum engineering interest. The effect of rock mineralogy was investigated by conducting the experiments with different mineral surfaces (quartz and calcite). A new equation was developed using the concepts of the line tension and the work of adhesion to estimate the adhesion energy per unit volume correlatable to maximum disjoining pressure in complex rock/oil/water systems. This equation uses the measured data of the oil/water interfacial tension (IFT) and dynamic contact angles, and an assumed thickness of the aqueous wetting films. The experimentally estimated adhesion energy per unit volume values for two glass/recombined live oil/synthetic reservoir brine systems using this new equation were compared with the maximum disjoining pressure values derived from the published reservoir condition disjoining pressure isotherms for the glass/Yates crude oil/Yates brine systems. The experimentally estimated values were found to be one order of magnitude higher than the theoretical values

Interfacial properties of reservoir fluids and carbon dioxide with impurities

Interfacial tension measurements of the binary systems (N2 + H2O), (Ar + H2O), and (H2 + H2O), and ternary systems (CO2 + N2 + H2O), (CO2 + Ar + H2O) and (CO2 + H2 + H2O), are reported at pressures of (0.5 to 50.0) MPa, and temperatures of (298.15 to 473.15) K. The design of a custom-built Interfacial Properties Rig was detailed. The pendant drop method was used. The expanded uncertainties at 95 % confidence are 0.05 K for temperature; 0.07 MPa for pressure; 0.019•γ for interfacial tension in the (N2 + H2O) system; 0.016•γ for interfacial tension in the (Ar + H2O) system; 0.017•γ for interfacial tension in the (H2 + H2O) system; 0.032•γ for interfacial tension in the (CO2 + N2 + H2O) system; 0.018•γ for interfacial tension in the (CO2 + Ar + H2O) system; and 0.017•γ for interfacial tension in the (CO2 + H2 + H2O) system. The interfacial tensions of all systems were found to decrease with increasing pressure. The use of SGT + SAFT-VR Mie to model interfacial tensions of the binary and ternary systems was reported, for systems involving CO2, N2 and Ar. The binary systems (N2 + H2O) and (Ar + H2O), and ternary systems (CO2 + N2 + H2O) and (CO2 + Ar + H2O), were modelled with average absolute relative deviations of 1.5 %, 1.8 %, 3.6 % and 7.9 % respectively. For the (CO2 + Ar + H2O) system, the agreement is satisfactory at the higher temperatures, but differs significantly at the lower temperatures. Contact angles of (CO2 + brine) and (CO2 + N2 + brine) systems on calcite surfaces have also been measured, at 333 K and 7 pressures, from (2 to 50) MPa, for a 1 mol•kg-1 NaHCO3 brine solution, using the static method on captive bubbles.Open Acces