A New HLD-NAC Based EOS Approach to Predict Surfactant-Oil-Brine Phase Behavior for Live Oil at Reservoir Pressure and Temperature

2014 ◽  
Author(s):  
Soumyadeep Ghosh ◽  
Russell Taylor Johns
Keyword(s):  
Phase Behavior ◽  
Reservoir Pressure ◽  
Live Oil

Prediction of asphaltene phase behavior in live oil with CPA equation of state

Fuel ◽  
2012 ◽  
Vol 97 ◽  
pp. 89-96 ◽  
Author(s):  
Babak Shirani ◽  
Manouchehr Nikazar ◽  
Seyyed A. Mousavi-Dehghani
Keyword(s):  
Equation Of State ◽  
Phase Behavior ◽  
Live Oil

Modeling of Pressure and Solution Gas for Chemical Floods

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 428-439 ◽  
Author(s):  
M.. Roshanfekr ◽  
R.T.. T. Johns ◽  
M.. Delshad ◽  
G.A.. A. Pope
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Atmospheric Pressure ◽  
Carbon Number ◽  
Chemical Flooding ◽  
Reservoir Pressure ◽  
Optimal Salinity ◽  
Free Gas ◽  
Cubic Equation ◽  
Solution Gas

Summary The goal of surfactant/polymer (SP) flooding is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimal salinity and optimal solubilization ratios that correspond to ultralow IFT have recently been shown, in some cases, to be a strong function of the methane mole fraction in the oil at reservoir pressure. We incorporate a recently developed methodology to determine the optimal salinity and solubilization ratio at reservoir pressure into a chemical-flooding simulator (UTCHEM). The proposed method determines the optimal conditions on the basis of density estimates by use of a cubic equation of state (EOS) and measured phase-behavior data at atmospheric pressure. The microemulsion phase-behavior (Winsor I, II, and III) are adjusted on the basis of this predicted optimal salinity and solubilization ratio in the simulator. Parameters for the surfactant phase-behavior equation are modified to account for these changes, and the trend in the equivalent alkane carbon number (EACN) is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase-behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase-behavior model into a chemical-flooding simulator allows for a better design of SP floods and more-accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir; however, the SP-flood simulation when free gas is present is not the focus of this paper. We show that not accounting for the phase-behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of an SP flood can lead to production of more oil as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical-flooding simulator, which requires the phase-behavior data measured at atmospheric pressure.

Phase Behavior of CO2-Rich Live Oil Samples From High Pressure Reservoirs

2015 ◽  
Author(s):  
F. M. R. Cardoso ◽  
C. C. B. Viegas ◽  
F. P. Fleming ◽  
R. S. Freitas ◽  
A. J. M. Vieira ◽  
...  
Keyword(s):  
High Pressure ◽  
Phase Behavior ◽  
Live Oil

Simulation of the Effect of Pressure and Solution Gas on Oil Recovery From Surfactant/Polymer Floods

SPE Journal ◽  
2012 ◽  
Vol 17 (03) ◽  
pp. 705-716 ◽  
Author(s):  
M.. Roshanfekr ◽  
R.T.. T. Johns ◽  
G.. Pope ◽  
L.. Britton ◽  
H.. Linnemeyer ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Type Ii ◽  
Effect Of Pressure ◽  
Recovery Processes ◽  
Optimum Parameters ◽  
Secondary Recovery ◽  
And Shifts ◽  
Solution Gas ◽  
Live Oil

Summary Surfactant/polymer (SP) and alkali/surfactant/polymer flooding is of current interest because of the need to recover residual oil after primary and secondary recovery. If designed properly, these enhanced-oil-recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by performing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature, and the importance of those experimental results is conflicting. This paper investigates the effect of pressure and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type II+) to lower microemulsion (Winsor Type II—), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. Using a numerical simulator, we show that these changes in the optimum conditions can significantly impact oil recovery if not accounted for in the SP design.

Experimental and theoretical study of phase behavior for live oil during CO2 EOR process

2017 ◽  
Vol 35 (5) ◽  
pp. 451-456 ◽  
Author(s):  
Ali Kia ◽  
Amir Reza Sarlak ◽  
Amir Hossein Tabari ◽  
Saeed Bazr Afkan ◽  
Marzyeh Keshavarz ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Theoretical Study ◽  
Co2 Eor ◽  
Live Oil

Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1046-1063 ◽  
Author(s):  
Nithiwat Siripatrachai ◽  
Turgay Ertekin ◽  
Russell T. Johns
Keyword(s):  
Phase Equilibria ◽  
Phase Behavior ◽  
Capillary Pressure ◽  
Oil And Gas ◽  
Oil Production ◽  
Reservoir Pressure ◽  
Compositional Simulation ◽  
Eagle Ford ◽  
Fluid Properties ◽  
Tight Reservoirs

Summary Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs. In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated. Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.

scholarly journals An evaluation on phase behaviors of gas condensate reservoir in cyclic gas injection

2020 ◽  
Vol 75 ◽  
pp. 4
Author(s):  
Angang Zhang ◽  
Zifei Fan ◽  
Lun Zhao ◽  
Anzhu Xu
Keyword(s):  
Phase Behavior ◽  
Gas Injection ◽  
Gas Condensate ◽  
Reservoir Pressure ◽  
Retrograde Condensation ◽  
Condensate Reservoir ◽  
Gas Drive ◽  
Phase Behaviors ◽  
Equilibrium Calculations ◽  
Better Than

Maintaining the reservoir pressure by gas injection is frequently adopted in the development of gas condensate reservoir. The aim of this work is to investigate the phase behavior of condensate oil and remaining condensate gas in the formation under gas injection. The DZT gas condensate reservoir in East China is taken as an example. The multiple contact calculation based on cell-to-cell method and phase equilibrium calculations based on PR Equation of State (EOS) were utilized to evaluate the displacement mechanism and phase behavior change. The research results show that different pure gas has different miscible mechanism in the displacement of condensate oil: vaporizing gas drive for N2 and CH4; condensing gas drive for CO2 and C2H6. Meanwhile, there is a vaporing gas drive rather than a condensing gas drive for injecting produced gas. When the condensate oil is mixed with 0.44 mole fraction of produced gas, the phase behavior of the petroleum mixture reverses, and the condensate oil is converted to condensate gas. About the reinjection of produced gas, the enrichment ability of hydrocarbons is better than that of no-hydrocarbons. After injecting produced gas, retrograde condensation is more difficult to occur, and the remaining condensate gas develops toward dry gas.

Effect of Live Crude on Alkaline/Surfactant Polymer Formulations: Implications for Final Formulation Design

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 352-361 ◽  
Author(s):  
Jeffrey G. Southwick ◽  
Yi Svec ◽  
Greg Chilek ◽  
Gordon T. Shahin
Keyword(s):  
Phase Behavior ◽  
Control Experiment ◽  
Screening Tests ◽  
Reservoir Pressure ◽  
Low Interfacial Tension ◽  
Equilibrium Amount ◽  
Paraffinic Crude ◽  
Surfactant Systems ◽  
Crude Emulsion ◽  
Solution Gas

Summary Phase-behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension (IFT) with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion-screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1,100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus, a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase-behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead-crude corefloods with a live-crude coreflood. A control experiment pressurizing oil with nitrogen at the same condition, 1,100 psi, did not show enhanced relative surfactant solubility in the oil phase.

Phase behavior of cationic and anionic surfactants at low concentrations

1992 ◽  
Vol 50 (1) ◽  
pp. 694-695
Author(s):  
E. Naranjo
Keyword(s):  
Phase Behavior ◽  
Structural Characterization ◽  
Dynamic Systems ◽  
Anionic Surfactants ◽  
Intermolecular Forces ◽  
Stable Form ◽  
Surfactant Mixtures ◽  
Low Concentrations ◽  
Cationic And Anionic Surfactants ◽  
General Method

Equilibrium vesicles, those which are the stable form of aggregation and form spontaneously on mixing surfactant with water, have never been demonstrated in single component bilayers and only rarely in lipid or surfactant mixtures. Designing a simple and general method for producing spontaneous and stable vesicles depends on a better understanding of the thermodynamics of aggregation, the interplay of intermolecular forces in surfactants, and an efficient way of doing structural characterization in dynamic systems.

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