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2021 ◽  
Author(s):  
Taha Okasha ◽  
Mohammed Al Hamad ◽  
Bastian Sauerer ◽  
Wael Abdallah

Abstract Current reservoir simulators use interfacial tension (IFT) values derived from dead oil measurements at ambient conditions or predicted from literature correlations. IFT is highly dependent on temperature, pressure and fluid composition. Therefore, knowledge of the IFT value at reservoir conditions is essential for accurate reservoir fluid characterization. This study compares IFT values from dead and live oil measurements and the results of literature predicted values, thereby clearly showing the weakness of existing correlations when trying to predict crude oil IFT. A total of ten live oils was sampled for this study. Using the pendent drop technique, IFT was measured for each oil at different conditions: in the under-saturated region at reservoir pressure and temperature, in the saturated region at reservoir temperature, and for dead oil at ambient conditions. Basic PVT properties such as gas to oil ratio (GOR), gas and liquid composition, density, viscosity and molecular weight were also measured. The bubble point for each oil was identified to define the pressure step in the saturated region for extra IFT measurement. The equilibrium IFT values for the live oils were generally higher than for the corresponding dead oils. For oils where this general trend was not observed, contaminations were found in the crude samples. The use of current literature correlations does not allow to predict correct reservoir IFT. Therefore, this study provides accurate live IFT values for a variety of reservoir fluids and conditions in combination with live oil properties, highly beneficial to reservoir engineers, allowing better oil production planning.


2021 ◽  
Author(s):  
Jyun-Syung Tsau ◽  
Qinwen Fu ◽  
Reza Ghahfarokhi Barati ◽  
J. Zaghloul ◽  
A. Baldwin ◽  
...  

Abstract The hydrocarbon gas huff and puff (HnP) technique has been used to improve oil production in unconventional oil reservoirs where excess capacity of produced gas is available and hydrocarbon prices are in a range to result in an economically viable case. Eagle Ford (EF) is one of the largest unconventional oil plays in the United State where HnP has been applied for enhanced oil recovery (EOR) at reservoirs within various oil windows. Our previously published Huff-n-puff results on dead oil with produced gas from Eagle Ford (EF) showed the recovery factor of hydrocarbon varying from 40 to 58%. The objective of this paper is to extend the experiments to live oil with EF core plugs to investigate the mechanisms of HnP which are affected by the composition of injected gas and resident oil, injection and soaking time as well as injection/depletion pressure gradient. Eagle Ford live oil and natural gas produced from the target area were used for HnP tests. Four representative core plugs were used with the tests conducted at reservoir conditions (125 °C and 3,500 psi). The live oil experiments with four reservoir core plugs showed an improvement in oil recovery with recovery factor (RF) varying from 19.5 to 33 % in six cycles of HnP, whereas the primary depletion on the same core plug showed RF below 11 %. A lower recovery factor of HnP from live oil saturated core in this study was observed as compared to dead oil saturated core reported in a previous publication. It is attributed to a lesser diffusion effect on mass transfer between injected gas and resident oil when the core is saturated with live oil. This behavior is displayed by the pressure decline curve during the first soaking period. A sharper diffusion pressure decline occurred in the dead oil saturated core plug where a higher concentration gradient between injected gas and resident oil drives a faster gas transport into the oil due to the molecular diffusion during the soaking period.


2021 ◽  
Author(s):  
Yibo Yang ◽  
Teresa Regueira ◽  
Hilario Martin Rodriguez ◽  
Alexander Shapiro ◽  
Erling Halfdan Stenby ◽  
...  

Abstract Molecular diffusion plays a critical role in gas injection in tight reservoirs such as liquid-rich shale. Despite recent efforts on measuring diffusion coefficients at high pressures, there is a general lack of the diffusion coefficients in live oil systems at reservoir conditions relevant to the development of these tight reservoirs. The reported diffusion coefficients often differ in orders of magnitude, and there is no consensus on the reliability of the common correlations for liquid phase diffusion coefficients, such as the extended Sigmund correlation. We employed the constant volume diffusion method to measure the high-pressure diffusion coefficients in a newly designed high-pressure tube. The experimental method was first validated using methane + hexadecane and methane + decane, and then used to measure the methane diffusion coefficients in two live oils at reservoir conditions. The obtained data were processed by compositional simulation to determine the diffusion coefficients. The diffusion coefficients measured for methane + hexadecane and methane + decane are in agreement with the existing literature data. For methane + live oil systems, however, the diffusion coefficients estimated by the extended Sigmund correlation are much lower than the measured results. An over ten times adjustment is needed to best fit the pressure decay curves. A further check reveals that for live oil systems, the reduced densities are often in the extrapolated region of the original Sigmund model. The curve in this region of the extended Sigmund correlation has a weak experimental basis, which may be the reason for its large deviation. The estimates from other correlations like Wilke-Chang and Hayduk-Minhas also give very different results. We compared the diffusion coefficients in high-pressure oils reported in the literature, showing a large variation in the reported values. All these indicate the necessity for further study on accurate determination of high-pressure diffusion coefficients in live oils of relevance to shale and other tight reservoirs.


SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Lei Li ◽  
Zheng Chen ◽  
Yu-Liang Su ◽  
Li-Yao Fan ◽  
Mei-Rong Tang ◽  
...  

Summary Fracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential. In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressurechamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2slug. The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper. In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.


2021 ◽  
Author(s):  
Hadil Abukhalifeh

Vapex (vapor extraction) is a solvent-based non-thermal in-situ heavy oil recovery process. In Vapex process, a vaporized hydrocarbon solvent is injected into an upper horizontal well where the solvent mixes with the heavy oil and reduces its viscosity. The diluted oil drains under gravity to a bottom production well. Two mechanisms control the production rates of heavy oil in Vapex: mass transfer of solvent into heavy oil, and gravity drainage. Both are governed by dispersion, which is composed of molecular diffusion, convection, and other mechanisms that enhance mixing in porous medium. The accurate determination of solvent dispersion in Vapex is essential to predict effectively the amount and time scale of oil recovery as well to optimize the field operations. Motivated by limited dispersion data in the literature, a novel technique is developed to determine experimentally the concentration-dependent dispersion coefficient of propane in Vapex process, The technique employs live oil production rates obtained from Vapex experiments at 21ºC and 0.790 MPa. The salient feature of this technique is that it does not impose any functional form on dispersion as a function of concentration, but allows its natural and realistic determination. The technique could be applied to determine other solvents dispersion coefficient used in the in-situ recovery of heavy oil. Propane dispersion coefficient is determined by the minimization of the difference in experimental and calculated cumulative live oil produced. The necessary conditions for the minimum are fundamentally derived, utilizing the theory of optimal control. A computational algorithm is formulated to calculate the propane dispersion function simultaneously with propane-heavy oil interface mass fraction. Physical models of glass beads of different permeabilities (204-51 Darcy) and drainage heights (25-45 cm) were used to conduct the Vapex experiments. The results show that dispersion of propane is a unimodal function of its concentration in heavy oil, and lies in the range, 0.5x10⁻⁵- 7.933x10⁻⁵ m²/s. Convectional mixing is promoted by higher model drainage heights and lower permeability. Finally, propane dispersion is correlated as a function of propane mass fraction in heavy oil and the packed medium permeability, as well as the drainage height.


2021 ◽  
Author(s):  
Hadil Abukhalifeh

Vapex (vapor extraction) is a solvent-based non-thermal in-situ heavy oil recovery process. In Vapex process, a vaporized hydrocarbon solvent is injected into an upper horizontal well where the solvent mixes with the heavy oil and reduces its viscosity. The diluted oil drains under gravity to a bottom production well. Two mechanisms control the production rates of heavy oil in Vapex: mass transfer of solvent into heavy oil, and gravity drainage. Both are governed by dispersion, which is composed of molecular diffusion, convection, and other mechanisms that enhance mixing in porous medium. The accurate determination of solvent dispersion in Vapex is essential to predict effectively the amount and time scale of oil recovery as well to optimize the field operations. Motivated by limited dispersion data in the literature, a novel technique is developed to determine experimentally the concentration-dependent dispersion coefficient of propane in Vapex process, The technique employs live oil production rates obtained from Vapex experiments at 21ºC and 0.790 MPa. The salient feature of this technique is that it does not impose any functional form on dispersion as a function of concentration, but allows its natural and realistic determination. The technique could be applied to determine other solvents dispersion coefficient used in the in-situ recovery of heavy oil. Propane dispersion coefficient is determined by the minimization of the difference in experimental and calculated cumulative live oil produced. The necessary conditions for the minimum are fundamentally derived, utilizing the theory of optimal control. A computational algorithm is formulated to calculate the propane dispersion function simultaneously with propane-heavy oil interface mass fraction. Physical models of glass beads of different permeabilities (204-51 Darcy) and drainage heights (25-45 cm) were used to conduct the Vapex experiments. The results show that dispersion of propane is a unimodal function of its concentration in heavy oil, and lies in the range, 0.5x10⁻⁵- 7.933x10⁻⁵ m²/s. Convectional mixing is promoted by higher model drainage heights and lower permeability. Finally, propane dispersion is correlated as a function of propane mass fraction in heavy oil and the packed medium permeability, as well as the drainage height.


Fuel ◽  
2021 ◽  
Vol 283 ◽  
pp. 119121
Author(s):  
Guangfeng Liu ◽  
Tenghuan Zhang ◽  
Qichao Xie ◽  
Wantao Liu ◽  
Lianhe Wang ◽  
...  

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