Parametric Review of Surfactant Flooding at Tertiary Stage to achieve the accuracy for proposing the Screening Criteria

2020 ◽  
Vol 13 ◽  
Author(s):  
Muhammad Usman Tahir ◽  
Liu Wei
Keyword(s):  
Oil Recovery ◽  
Critical Review ◽  
Fluid Viscosity ◽  
Recovery Efficiency ◽  
Surfactant Flooding ◽  
Screening Criteria ◽  
Reservoir Fluid ◽  
Tertiary Stage ◽  
Basic Parameters ◽  
Original Oil In Place

Abstract:: A critical review of previous studies is presented based on the contextual research background of surfactant flooding in this study. The parameters focused to achieve the analysis include permeability, salinity, temperature, and vis-cosity from different surfactant flooding operations. The principal theme of this review is to provide the regression analy-sis technique that may adopt to analyze the collected data and conduct contextual research. The set of analytical discus-sion is accomplished by extracting and plotting the basic parameters against recovery at Original Oil in Place (OOIP) and tertiary stages. Further, the success rate of such studies is compared to the grounds of oil recovery efficiency at different stages. Moreover, the failure of the surfactant flooding project can also be ensured by the outcomes of this study. It is revealed from this study that the recovery efficiency of surfactant flooding can be obtained maximum at lower per-meability ranges, however, other parameters such as salinity and temperature may possess some influence on recovery. In fact the fluid viscosity of reservoir fluid is inversely rated to recovery. The salinity, temperature and viscosity ranges for efficient surfactant flooding ranges may drop within the range from 1400 to 132606 ppm, 25 to 126 °C, and 1.9 to 150 cP respectively.

scholarly journals Optimisation of Smart Water to Enhance Oil Recovery Efficiency in a Part of Oil Field of Upper Assam Basin, India

2019 ◽  
Vol 9 (2) ◽  
pp. 3620-3626
Keyword(s):  
Oil Recovery ◽  
Ionic Composition ◽  
Oil Field ◽  
Water Flooding ◽  
Rock Surface ◽  
Recovery Efficiency ◽  
Smart Water ◽  
Original Oil In Place ◽  
Brine Salinity ◽  
Secondary Mode

Researchers have proved the significance of water injection by tuning its composition and salinity into the reservoir during smart water flooding. Once the smart water invades through the pore spaces, it destabilises crude oil-brine-rock (COBR) that leads to change in wettability of the reservoir rocks. During hydrocarbon accumulation and migration, polar organic compounds were being adsorbed on the rock surface making the reservoir oil/mixed wet in nature. Upon invasion of smart water, due to detachment of polar compounds from the rock surfaces, the wettability changes from oil/mixed wet to water wet thus enhances the oil recovery efficiency. The objective of this paper is to find optimum salinity and ionic composition of the synthetic brines at which maximum oil recovery would be observed. Three core flood studies have been conducted in the laboratory to investigate the effect of pH, composition and salinity of the injected brine over oil recovery. Every time, flooding has been conducted at reservoir formation brine salinity i.e at 1400 ppm followed by different salinities. Here, tertiary mode of flooding has been carried out for two core samples while secondary flooding for one. Results showed maximum oil recovery by 40.12% of original oil in place (OOIP) at 1050ppm brine salinity at secondary mode of flooding. So, optimized smart water has been proposed with 03 major salts, KCl, MgCl2 and CaCl2 in secondary mode of flooding that showed maximum oil recovery in terms of original oil in place.

scholarly journals Effect of Compositional Grading On reservoir Performance

1996 ◽  
Vol 1 (1) ◽  
pp. 37
Author(s):  
M. Al-Rumhy ◽  
A. Al-Bemani ◽  
F. Boukadi
Keyword(s):  
Oil Recovery ◽  
Simulation Analysis ◽  
Fluid Composition ◽  
Fluid Viscosity ◽  
Reservoir Performance ◽  
Reservoir Fluid ◽  
Stock Tank ◽  
Fluid Properties ◽  
Secondary Oil Recovery ◽  
Compositional Grading

In reservoirs with thickness exceeding fifty meters, compositional guiding has been found to cause significant variation in performance. Main fluid properties, governing the magnitude of reservoir performance, such as density; formation volume factor and fluid viscosity experience variation due to varying fluid composition along the hydrocarbon column. These variations cause erroneous estimation of stock-tank oil in place and may infer reservoir engineers to consider inappropriate secondary oil recovery methods, for example. In the presence of gravity segregation within the oil column, heavy ends will form a heavy oil blanket in the lower part of the reservoir. Such a scenario may result in poor displacement and an earlier breakthrough when water drive is the dominant fluid flow mechanism. In this paper reservoir performance due to varying reservoir fluid composition has been examined using  reservoir simulation analysis and recommendations for better characterization of reservoir fluid sampling are outlined.

The Effect of Live Crude on Phase Behavior and Oil-Recovery Efficiency of Surfactant Flooding Systems

1983 ◽  
Vol 23 (03) ◽  
pp. 501-510 ◽  
Author(s):  
Richard C. Nelson
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Potential Problem ◽  
Average Molecular Weight ◽  
Carbon Number ◽  
Recovery Efficiency ◽  
Surfactant Flooding ◽  
Type Iii ◽  
Stock Tank ◽  
Relative Solubility

Abstract Neither pressure alone nor pressurizing with methane affects phase behavior of a particular surfactant/ brine/stock-tank-oil system. Oil-recovery efficiency in corefloods is not significantly different whether the stock-tank oil is pressurized with methane or diluted with iso-octane to the viscosity of the live crude. In contrast, phase behavior and oil-recovery efficiency do change phase behavior and oil-recovery efficiency do change upon methane pressurization when a lower-molar-volume synthetic oil is substituted for the stock-tank oil. Some thermodynamic insight regarding the different behavior of the two oils is offered. Introduction Refs. 1 through 29 are a representative selection from the many papers published on phase behavior of surfactant flooding systems. From many of the papers in that group it is apparent that the type of microemulsion (lower, middle, or upper phase) that forms when surfactant, brine, and oil are mixed is related to the relative solubility of the surfactant in the brine and in the oil. It is apparent also that surfactant systems most active in displacing oil establish a middle phase or, more precisely, a Type III Microemulsion at some point in the precisely, a Type III Microemulsion at some point in the surfactant bank. Hence, relative solubility of the surfactant in the brine and in the oil plays an important role in surfactant flooding. For phase-behavior studies and corefloods in the laboratory, the reservoir brine usually can be duplicated easily, and the extent to which the composition of that brine will change because of ion exchange can be calculated. The oil, however, presents the following potential problem. potential problem. Although phase studies and corefloods are more convenient and more precise when conducted with stock-tank oil under atmospheric pressure, many in-place crude oils contain a substantial quantity of dissolved gas that is absent from the stock-tank oil. Hence, serious errors in formulating a surfactant-flooding system are plausible if the in-place, live crude should exhibit a plausible if the in-place, live crude should exhibit a solvency for the surfactant different from the stock-tank oil. Even the common practice of diluting the stock-tank oil with hydrocarbon solvents to approximately the viscosity of the live crude does not ensure that the diluted stock-tank oil has the same solvency as the live crude for the surfactant. Alkane Carbon Number (ACN) This concern over different solvency for the surfactant between live crude and its stock-tank oil is illustrated vividly in terms of ACN. Fig. 1 is a typical plot of interfacial tension (IFT) vs. Equivalent Alkane Carbon Number (EACN) of the oil. The figure shows that ultralow IFT for a particular surfactant/brine system at a given temperature is obtained over a rather narrow range of EACN's--e.g., 7.0 to 8.2 in this illustration. If methane should behave as an alkane of carbon-number unity (e.g., if the EACN of methane equals its ACN) and if the mole-fraction-weighting rule applicable to the C5 through C 16 alkanes holds for methane, then pressurizing a stock-tank oil of 318 average molecular pressurizing a stock-tank oil of 318 average molecular weight and 7.6 EACN with 33 mol% (only 2.4 wt%) methane would shift the EACN of the oil to 5.4. SPEJ P. 501

scholarly journals Research progress of viscoelastic surfactants for enhanced oil recovery

2021 ◽  
pp. 014459872098020
Author(s):  
Ruizhi Hu ◽  
Shanfa Tang ◽  
Musa Mpelwa ◽  
Zhaowen Jiang ◽  
Shuyun Feng
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Efficiency ◽  
Research Progress ◽  
Surfactant Flooding ◽  
Sweep Efficiency ◽  
The World ◽  
Washing Efficiency ◽  
Viscoelastic Surfactants ◽  
Viscoelastic Surfactant

Although new energy has been widely used in our lives, oil is still one of the main energy sources in the world. After the application of traditional oil recovery methods, there are still a large number of oil layers that have not been exploited, and there is still a need to further increase oil recovery to meet the urgent need for oil in the world economic development. Chemically enhanced oil recovery (CEOR) is considered to be a kind of effective enhanced oil recovery technology, which has achieved good results in the field, but these technologies cannot simultaneously effectively improve oil sweep efficiency, oil washing efficiency, good injectability, and reservoir environment adaptability. Viscoelastic surfactants (VES) have unique micelle structure and aggregation behavior, high efficiency in reducing the interfacial tension of oil and water, and the most important and unique viscoelasticity, etc., which has attracted the attention of academics and field experts and introduced into the technical research of enhanced oil recovery. In this paper, the mechanism and research status of viscoelastic surfactant flooding are discussed in detail and focused, and the results of viscoelastic surfactant flooding experiments under different conditions are summarized. Finally, the problems to be solved by viscoelastic surfactant flooding are introduced, and the countermeasures to solve the problems are put forward. This overview presents extensive information about viscoelastic surfactant flooding used for EOR, and is intended to help researchers and professionals in this field understand the current situation.

Experimental Study on Ethanolamine/Surfactant Flooding for Enhanced Oil Recovery

2014 ◽  
Vol 28 (3) ◽  
pp. 1829-1837 ◽  
Author(s):  
Yingrui Bai ◽  
Chunming Xiong ◽  
Xiaosen Shang ◽  
Yanyong Xin
Keyword(s):  
Experimental Study ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Surfactant Flooding

Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

2021 ◽  
Author(s):  
Olaitan Akinyele ◽  
Karl D. Stephen
Keyword(s):  
Interfacial Tension ◽  
Cell Size ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Numerical Dispersion ◽  
Sharp Change ◽  
Surfactant Flooding ◽  
Fractional Flow ◽  
Time Step ◽  
Scale Models

Abstract Numerical simulation of surfactant flooding using conventional reservoir simulation models can lead to unreliable forecasts and bad decisions due to the appearance of numerical effects. The simulations give approximate solutions to systems of nonlinear partial differential equations describing the physical behavior of surfactant flooding by combining multiphase flow in porous media with surfactant transport. The approximations are made by discretization of time and space which can lead to spurious pulses or deviations in the model outcome. In this work, the black oil model was simulated using the decoupled implicit method for various conditions of reservoir scale models to investigate behaviour in comparison with the analytical solution obtained from fractional flow theory. We investigated changes to cell size and time step as well as the properties of the surfactant and how it affects miscibility and flow. The main aim of this study was to understand pulse like behavior that has been observed in the water bank to identify cause and associated conditions. We report for the first time that the pulses occur in association with the simulated surfactant water flood front and are induced by a sharp change in relative permeability as the interfacial tension changes. Pulses are diminished when the adsorption rate was within the value of 0.0002kg/kg to 0.0005kg/kg. The pulses are absent for high resolution model of 5000 cells in x direction with a typical cell size as used in well-scale models. The growth or damping of these pulses may vary from case to case but in this instance was a result of the combined impact of relative mobility, numerical dispersion, interfacial tension and miscibility. Oil recovery under the numerical problems reduced the performance of the flood, due to large amounts of pulses produced. Thus, it is important to improve existing models and use appropriate guidelines to stop oscillations and remove errors.

Microwave Synthesis of ZnO Nanoparticles for Enhanced Oil Recovery

2014 ◽  
Vol 1024 ◽  
pp. 83-86 ◽  
Author(s):  
Mohamad Sahban Alnarabiji ◽  
Noorhana Yahya ◽  
Sharifa Bee Abd Hamid ◽  
Khairun Azizi Azizli ◽  
Afza Shafie ◽  
...  
Keyword(s):  
Zinc Oxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Zno Nanoparticles ◽  
Sol Gel ◽  
Zinc Nitrate ◽  
Nitrate Hexahydrate ◽  
Zno Nps ◽  
Nanoparticle Morphology ◽  
Original Oil In Place

Synthesising zinc oxide nanoparticles to get certain specific characteristics to be applied in Enhanced oil recovery (EOR) is still challenging to date. In this work, zinc oxide (ZnO) nanoparticles were synthesised using the sol-gel method by dissolving zinc nitrate hexahydrate in nitric acid. The ZnO crystal and particles morphology and structure were determined using X-ray Diffractometer (XRD) and Field Emission Scanning Electron Microscope (FESEM). In this study, a microwave oven was used for annealing ZnO without insulating a sample in any casket. The results show that 30 and 40 minutes of annealing and stirring for 1 hour influenced the morphology and size of zinc oxide particles in nanoscale. These parameters could be tailored to generate a range of nanoparticle morphology (agglomerated nanoparticles in a corn-like morphology), a crystal size with the mean size of 70.5 and 74.9 nm and a main growth at the peak [10. EOR experiment were conducted by dispersing 0.10 wt% ZnO NPs in distilled water to form a ZnO nanofluid. Then the fluid was injected into the medium in the 3rd stage of the oil recovery to present EOR stage. It was found that ZnO nanofluid has the ability to extract 8% of the original oil in place (OOIP).

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