The Effect of Redox Potential and Metal Solubility on Oxidative Polymer Degradation

2011 ◽  
Vol 14 (03) ◽  
pp. 287-298 ◽  
Author(s):  
David B. Levitt ◽  
Will Slaughter ◽  
Gary A. Pope ◽  
Stephane Jouenne
Keyword(s):  
Sodium Carbonate ◽  
Oil Recovery ◽  
Oxidative Degradation ◽  
Sodium Dithionite ◽  
Field Application ◽  
Iron Solubility ◽  
Oxidative Polymer ◽  
Subsequent Degradation ◽  
Reduced State ◽  
Polymer Hydration

Summary Oxidative degradation of polymers is a serious concern in their field application for enhanced oil recovery (EOR). This study is an attempt to resolve some of the discrepancies in the literature regarding the occurrence and extent of this degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is caused by their effect on iron solubility. Brines containing iron in the reduced state are often obtained from aquifers for use in polymer hydration. These brines are shown to be prone to causing immediate degradation if exposed to air during or after polymer hydration because of the oxidation of soluble iron. If this cannot be avoided, preaeration may be a feasible strategy to minimize degradation during hydration. However, care must be taken to ensure subsequent degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. For instance, sodium dithionite can be added downstream of the last exposure to oxygen. The use of sodium carbonate may also mitigate degradation caused by the oxidation of iron (II) during polymer hydration.

scholarly journals Low-tension gas process in high-salinity and low-permeability reservoirs

2020 ◽  
Vol 17 (5) ◽  
pp. 1329-1344
Author(s):  
Alolika Das ◽  
Nhut Nguyen ◽  
Quoc P. Nguyen
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Oxidative Degradation ◽  
Qualitative Assessment ◽  
Low Permeability ◽  
Displacement Efficiency ◽  
Fractional Flow ◽  
Hydrocarbon Gases ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

Studies on the S-State Distribution in Euglena gracilis

1983 ◽  
Vol 38 (1-2) ◽  
pp. 60-66 ◽  
Author(s):  
Georg H. Schmid ◽  
Pierre Thibault
Keyword(s):  
Oxygen Evolution ◽  
Euglena Gracilis ◽  
Sodium Dithionite ◽  
Fluorescence Induction ◽  
State Distribution ◽  
Flash Sequence ◽  
Evolution Pattern ◽  
Damped Oscillation ◽  
Synthetic Sequence ◽  
Reduced State

When Euglena gracilis is dark adapted for 10 min or more, oxygen evolution as the consequence of short (5 μsec) saturating light flashes does not show the picture of a damped oscillation with a periodicity of 4, as known from the literature. The overall picture of this flash pattern is given by the fact that O2-evolution in the first two flashes is practically zero and rises from there onward in a continuous manner to the steady state with barely any visible oscillation at all. However, a second flash sequence fired one to two minutes after this first sequence induces an oxygen evolution pattern which is barely distinguishable from the well known usual Chlorella vulgaris pattern. The phenomenon is not influenced by changes in the oxygen tension nor do additions of chemicals like CCCP, sodium azide, or reducing agents like hydroxylamine or hydrogen peroxide substantially alter the described behavior. Deactivation experiments give the overall impression that the deactivation of the S-states is slower than with Chlorella. Hydroxylamine strongly accelerates the deactivation. The analysis of the S-state distribution in a four and five state Kok-model suggests that dark adapted Euglena is in a more reduced condition than dark adapted Chlorella. It looks as if dark adapted Euglena were in a condition which would correspond to 60 percent S-1, 30 percent S0 and 10 percent S1. The experimental flash sequence of such dark adapted cells fits best a synthetic sequence when the misses are in the region of 20-25 percent, with double hitting playing practically no role at all (the first two flashes are zero!). The impression that dark adapted Euglena starts its oxygen evolution from a more reduced state is strengthened by the analysis of room temperature fluorescence induction (Kautsky effect). It can be shown that the fluorescence induction curve of Euglena corresponds to that of Chlorella cells provided the latter have been briefly treated with a strong reductant such as sodium dithionite.

Fitting Foam-Simulation-Model Parameters to Data: II. Surfactant-Alternating-Gas Foam Applications

2014 ◽  
Vol 18 (02) ◽  
pp. 273-283 ◽  
Author(s):  
W. R. Rossen ◽  
C. S. Boeije
Keyword(s):  
Steady State ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Water Saturation ◽  
Field Application ◽  
Model Parameters ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Water Fraction ◽  
Foam Model

Summary Foam improves sweep in miscible and immiscible gas-injection enhanced-oil-recovery processes. Surfactant-alternating-gas (SAG) foam processes offer many advantages over coinjection of foam for both operational and sweep-efficiency reasons. The success of a foam SAG process depends on foam behavior at very low injected-water fraction (high foam quality). This means that fitting data to a typical scan of foam behavior as a function of foam quality can miss conditions essential to the success of an SAG process. The result can be inaccurate scaleup of results to field application. We illustrate how to fit foam-model parameters to steady-state foam data for application to injection of a gas slug in an SAG foam process. Dynamic SAG corefloods can be unreliable for several reasons. These include failure to reach local steady state (because of slow foam generation), the increased effect of dispersion at the core scale, and the capillary end effect. For current foam models, the behavior of foam in SAG depends on three parameters: the mobility of full-strength foam, the capillary pressure or water saturation at which foam collapses, and the parameter governing the abruptness of this collapse. We illustrate the fitting of these model parameters to coreflood data, and the challenges that can arise in the fitting process, with the published foam data of Persoff et al. (1991) and Ma et al. (2013). For illustration, we use the foam model in the widely used STARS (Cheng et al. 2000) simulator. Accurate water-saturation data are essential to making a reliable fit to the data. Model fits to a given experiment may result in inaccurate extrapolation to mobility at the wellbore and, therefore, inaccurate predicted injectivity: for instance, a model fit in which foam does not collapse even at extremely large capillary pressure at the wellbore. We show how the insights of fractional-flow theory can guide the model-fitting process and give quick estimates of foam-propagation rate, mobility, and injectivity at the field scale.

scholarly journals Application of a physics-based lumped parameter model to evaluate reservoir parameters during CO2 storage

2020 ◽  
Vol 10 (8) ◽  
pp. 3925-3935
Author(s):  
Samin Raziperchikolaee ◽  
Srikanta Mishra
Keyword(s):  
Oil Recovery ◽  
Co2 Storage ◽  
Field Application ◽  
Oil Field ◽  
Lumped Parameter Model ◽  
Linear Regression Method ◽  
Oil Reservoir ◽  
Michigan Basin ◽  
Reservoir Properties ◽  
Lumped Parameter

Abstract Evaluating reservoir performance could be challenging, especially when available data are only limited to pressures and rates from oil field production and/or injection wells. Numerical simulation is a typical approach to estimate reservoir properties using the history match process by reconciling field observations and model predictions. Performing numerical simulations can be computationally expensive by considering a large number of grids required to capture the spatial variation in geological properties, detailed structural complexity of the reservoir, and numerical time steps to cover different periods of oil recovery. In this work, a simplified physics-based model is used to estimate specific reservoir parameters during CO2 storage into a depleted oil reservoir. The governing equation is based on the integrated capacitance resistance model algorithm. A multivariate linear regression method is used for estimating reservoir parameters (injectivity index and compressibility). Synthetic scenarios were generated using a multiphase flow numerical simulator. Then, the results of the simplified physics-based model in terms of the estimated fluid compressibility were compared against the simulation results. CO2 injection data including bottom hole pressure and injection rate were also gathered from a depleted oil reef in Michigan Basin. A field application of the simplified physics-based model was presented to estimate above-mentioned parameters for the case of CO2 storage in a depleted oil reservoir in Michigan Basin. The results of this work show that this simple lumped parameter model can be used for a quick estimation of the specific reservoir parameters and its changes over the CO2 injection period.

Stability of Partially Hydrolyzed Polyacrylamides at Elevated Temperatures in the Absence of Divalent Cations

SPE Journal ◽  
2009 ◽  
Vol 15 (02) ◽  
pp. 341-348 ◽  
Author(s):  
R.S.. S. Seright ◽  
A.R.. R. Campbell ◽  
P.S.. S. Mozley ◽  
Peihui Han
Keyword(s):  
Dissolved Oxygen ◽  
Oil Recovery ◽  
Elevated Temperatures ◽  
Divalent Cations ◽  
Oxidative Degradation ◽  
Reservoir Rock ◽  
Oxygen Scavengers ◽  
Polymer Backbone ◽  
Polymer Injection ◽  
The Stability

Summary At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAMs) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and for approximately 2 years at 120°C. Within our experimental error, HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer [with 25% 2-acrylamido-2-methylpropane sulphonic acid (AMPS)] showed similar stability to that for HPAM. Stability results were similar in brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl plus 0.1% NaHCO3. At temperatures of 160°C and greater, the polymers were more stable in brine with 2% NaCl plus 1% NaHCO3 than in the other brines. Even though no chemical oxygen scavengers or antioxidants were used in our study, we observed the highest level of thermal stability reported to date for these polymers. Our results provide considerable hope for the use of HPAM polymers in enhanced oil recovery (EOR) at temperatures up to 120°C if contact with dissolved oxygen and divalent cations can be minimized. Calculations performed considering oxygen reaction with oil and pyrite revealed that dissolved oxygen will be removed quickly from injected waters and will not propagate very far into porous reservoir rock. These findings have two positive implications with respect to polymer floods in high-temperature reservoirs. First, dissolved oxygen that entered the reservoir before polymer injection will have been consumed and will not aggravate polymer degradation. Second, if an oxygen leak (in the surface facilities or piping) develops during the course of polymer injection, that oxygen will not compromise the stability of the polymer that was injected before the leak developed or the polymer that is injected after the leak is fixed. Of course, the polymer that is injected while the leak is active will be susceptible to oxidative degradation. Maintaining dissolved oxygen at undetectable levels is necessary to maximize polymer stability. This can be accomplished readily without the use of chemical oxygen scavengers or antioxidants.

scholarly journals Laboratory Study on EOR in Offshore Oilfields by Variable Concentrations Polymer Flooding

2017 ◽  
Vol 10 (1) ◽  
pp. 94-107 ◽  
Author(s):  
Kaoping Song ◽  
Ning Sun ◽  
Yanfu Pi
Keyword(s):  
Oil Recovery ◽  
Field Application ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Displacement Efficiency ◽  
Constant Concentration ◽  
Sweep Efficiency ◽  
Displacement Effect ◽  
Fracture Pressure ◽  
Recovery Technique

Background: Polymer flooding is the most commonly applied chemical enhanced-oil-recovery technique in offshore oilfields. However, there are challenges and risks in applying the technology of polymer flooding to offshore heavy oil development. Objective: This paper compared the spread law and the displacement effect of different injection modes and validated the feasibility of enhancing oil recovery by variable concentrations polymer flooding. Method: Two types of laboratory experiments were designed by using micro etching glass models and heterogeneous artificial cores. Furthermore, in order to determine a better polymer flooding mode, the displacement results, displacement characteristic curves and oil saturation distribution of heterogeneous artificial cores were also compared, respectively. Results: The experimental results showed that the recovery of variable concentrations polymer flooding was higher than that of constant concentration polymer flooding, under conditions of same total amount of polymer and similar water flooding recovery. Its sweep efficiency and displacement efficiency were also significantly higher than those of constant concentration polymer flooding. Moreover, variable concentrations polymer flooding had lower peak pressure and was at lower risk for reaching the formation fracture pressure. Conclusion: As a consequence, variable concentrations polymer flooding has certain feasibility for heterogeneous reservoir in offshore oilfields, and can improve interlayer heterogeneity to further tapping remaining oil in medium and low permeability layer. Conclusions of this paper can provide reference for the field application of polymer flooding in offshore oilfields.

Very High Temperatures Steam Foam Additives

2021 ◽  
Author(s):  
Céleste Odier ◽  
Margaux Kerdraon ◽  
Emie Lacombe ◽  
Eric Delamaide
Keyword(s):  
High Temperature ◽  
Ambient Temperature ◽  
Oil Recovery ◽  
Foam Stability ◽  
Steam Injection ◽  
Field Application ◽  
High Pressure Cell ◽  
Sweep Efficiency ◽  
Foaming Agents ◽  
Very High

Abstract In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found. In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature. Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C. Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application. In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature. To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.

Non-Edible Oil Based Surfactant For Enhanced Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Ijoma Onyemaechi
Keyword(s):  
Methyl Ester ◽  
Sodium Hydroxide ◽  
Sodium Carbonate ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Incremental Oil Recovery ◽  
Increasing Demand

Abstract After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

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