Effect of a Partial Pressure Tool on Improving the Heterogeneous Oil Recovery and Polymer Solution Microstructure

Bin Huang; Xinyu Hu; Cheng Fu; Weisen Zhang; Li Wang

doi:10.1021/acsomega.0c00362

Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽

10.3390/polym11020319 ◽

2019 ◽

Vol 11 (2) ◽

pp. 319 ◽

Cited By ~ 8

Author(s):

Bin Huang ◽

Xiaohui Li ◽

Cheng Fu ◽

Ying Wang ◽

Haoran Cheng

Keyword(s):

Molecular Weight ◽

Polymer Solution ◽

Oil Recovery ◽

Injection Pressure ◽

Injection Rate ◽

Injection Velocity ◽

Structural Parameter ◽

Local Perturbation ◽

Polymer Injection ◽

Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

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Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Polymers ◽

10.3390/polym10111225 ◽

2018 ◽

Vol 10 (11) ◽

pp. 1225 ◽

Cited By ~ 3

Author(s):

Xiankang Xin ◽

Gaoming Yu ◽

Zhangxin Chen ◽

Keliu Wu ◽

Xiaohu Dong ◽

...

Keyword(s):

Porous Media ◽

Polymer Solution ◽

Oil Recovery ◽

Heavy Oil ◽

Flow Behavior ◽

Polymer Flooding ◽

Oil Reservoirs ◽

Flow In Porous Media ◽

Newtonian Flow ◽

Heavy Oil Reservoirs

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

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Effect of pressure variation on polymer flooding

10.32920/ryerson.14663814 ◽

2021 ◽

Author(s):

Ahmad Ali Manzoor

Keyword(s):

Polymer Solution ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Heavy Oil ◽

Constant Pressure ◽

Maximum Pressure ◽

Core Flooding ◽

Sweep Efficiency ◽

Black Oil Model ◽

Original Oil In Place

Chemical-based enhanced oil recovery (EOR) techniques utilize the injection of chemicals, such as solutions of polymers, alkali, and surfactants, into oil reservoirs for incremental recovery. The injection of a polymer increases the viscosity of the injected fluid and alters the water-to-oil mobility ratio which in turn improves the volumetric sweep efficiency. This research study aims to investigate strategies that would help intensify oil recovery with the polymer solution injection. For that purpose, we utilize a lab-scale, cylindrical heavy oil reservoir model. Furthermore, a dynamic mathematical black oil model is developed based on cylindrical physical model of homogeneous porous medium. The experiments are carried out by injecting classic and novel partially hydrolyzed polyacrylamide solutions (concentration: 0.1-0.5 wt %) with 1 wt % brine into the reservoir at pressures in the range, 1.03-3.44 MPa for enhanced oil recovery. The concentration of the polymer solution remains constant throughout the core flooding experiment and is varied for other subsequent experimental setup. Periodic pressure variations between 2.41 and 3.44 MPa during injection are found to increase the heavy oil recovery by 80% original-oil-in-place (OOIP). This improvement is approximately 100% more than that with constant pressure injection at the maximum pressure of 3.44 MPa. The experimental oil recoveries are in fair agreement with the model calculated oil production with a RMS% error in the range of 5-10% at a maximum constant pressure of 3.44 MPa.

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Optimization of Surfactant and Polymer for SP Flooding of Zahra Oil

Applied Mechanics and Materials ◽

10.4028/www.scientific.net/amm.535.701 ◽

2014 ◽

Vol 535 ◽

pp. 701-704 ◽

Cited By ~ 1

Author(s):

Peng Lv ◽

Ming Yuan Li ◽

Mei Qin Lin

Keyword(s):

Interfacial Tension ◽

Polymer Solution ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

High Viscosity ◽

Oil Field ◽

Interfacial Tensions

Producing ultra-low interfacial tensions and maintaining high viscosity is the most important mechanism relating to SP flooding for enhanced oil recovery. The interfacial tension between surfactant (PJZ-2 and BE)/polymer solution and Zahra oil was evaluated in the work. Based on the evaluatiojn of interfacial tension, the polymer FP6040s/surfactant BE system was selected as the SP flooding system for Zahra oil field.

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Temperature Dependence of the Shear-Thinning Behavior o Partially Hydrolyzed Polyacrylamide Solution for Enhanced Oil Recovery

Journal of Energy Resources Technology ◽

10.1115/1.4048592 ◽

2020 ◽

Vol 143 (6) ◽

Author(s):

Pan-Sang Kang ◽

Jong-Se Lim ◽

Chun Huh

Keyword(s):

Temperature Dependence ◽

Polymer Solution ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Polymer Concentration ◽

Shear Thinning ◽

Temperature Model ◽

Polyacrylamide Solution ◽

Partially Hydrolyzed Polyacrylamide ◽

Hydrolyzed Polyacrylamide

Abstract The viscosity of injection fluid is a critical parameter that should be considered for the design and evaluation of polymer flood, which is an effective and popular technique for enhanced oil recovery (EOR). It is known that the shear-thinning behavior of EOR polymer solutions is affected by temperature. In this study, temperature dependence (25–70 °C) of the viscosity of a partially hydrolyzed polyacrylamide solution, the most widely used EOR polymer for oil field applications, was measured under varying conditions of the polymer solution (polymer concentration: 500–3000 ppm, NaCl salinity: 1000–10,000 ppm). Under all conditions of the polymer solution, it was observed that the viscosity decreases with increasing temperature. The degree of temperature dependence, however, varies with the conditions of the polymer solution. Martin model and Lee correlations were used to estimate the dependence of the viscosity of the polymer solution on the polymer concentration and salinity. In this study, we proposed a new empirical model to better elucidate the temperature dependence of intrinsic viscosity. Analysis of the measured viscosities shows that the accuracy of the proposed temperature model is higher than that of the existing temperature model.

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Differences of microscopic seepage mechanisms of water flooding and polymer flooding and prediction models of final oil recovery for conglomerate reservoir

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2018086 ◽

2019 ◽

Vol 74 ◽

pp. 13

Author(s):

Fengqi Tan ◽

Changfu Xu ◽

Yuliang Zhang ◽

Gang Luo ◽

Yukun Chen ◽

...

Keyword(s):

Pore Structure ◽

Polymer Solution ◽

Oil Recovery ◽

Particle Surface ◽

Polymer Flooding ◽

Water Flooding ◽

Residual Oil ◽

Displacement Efficiency ◽

Oil Saturation ◽

Oil Displacement Efficiency

The special sedimentary environments of conglomerate reservoir lead to pore structure characteristics of complex modal, and the reservoir seepage system is mainly in the “sparse reticular-non reticular” flow pattern. As a result, the study on microscopic seepage mechanism of water flooding and polymer flooding and their differences becomes the complex part and key to enhance oil recovery. In this paper, the actual core samples from conglomerate reservoir in Karamay oilfield are selected as research objects to explore microscopic seepage mechanisms of water flooding and polymer flooding for hydrophilic rock as well as lipophilic rock by applying the Computed Tomography (CT) scanning technology. After that, the final oil recovery models of conglomerate reservoir are established in two displacement methods based on the influence analysis of oil displacement efficiency. Experimental results show that the seepage mechanisms of water flooding and polymer flooding for hydrophilic rock are all mainly “crawling” displacement along the rock surface while the weak lipophilic rocks are all mainly “inrushing” displacement along pore central. Due to the different seepage mechanisms among the water flooding and the polymer flooding, the residual oil remains in hydrophilic rock after water flooding process is mainly distributed in fine throats and pore interchange. These residual oil are cut into small droplets under the influence of polymer solution with stronger shearing drag effect. Then, those small droplets pass well through narrow throats and move forward along with the polymer solution flow, which makes enhancing oil recovery to be possible. The residual oil in weak lipophilic rock after water flooding mainly distributed on the rock particle surface and formed oil film and fine pore-throat. The polymer solution with stronger shear stress makes these oil films to carry away from particle surface in two ways such as bridge connection and forming oil silk. Because of the essential attributes differences between polymer solution and injection water solution, the impact of Complex Modal Pore Structure (CMPS) on the polymer solution displacement and seepage is much smaller than on water flooding solution. Therefore, for the two types of conglomerate rocks with different wettability, the pore structure is the main controlling factor of water flooding efficiency, while reservoir properties oil saturation, and other factors have smaller influence on flooding efficiency although the polymer flooding efficiency has a good correlation with remaining oil saturation after water flooding. Based on the analysis on oil displacement efficiency factors, the parameters of water flooding index and remaining oil saturation after water flooding are used to establish respectively calculation models of oil recovery in water flooding stage and polymer flooding stage for conglomerate reservoir. These models are able to calculate the oil recovery values of this area controlled by single well control, and further to determine the oil recovery of whole reservoir in different displacement stages by leveraging interpolation simulation methods, thereby providing more accurate geological parameters for the fine design of displacement oil program.

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A New Empirical Model for Viscosity of Sulfonated Polyacrylamide Polymers

Polymers ◽

10.3390/polym11061046 ◽

2019 ◽

Vol 11 (6) ◽

pp. 1046 ◽

Cited By ~ 4

Author(s):

Saeed Akbari ◽

Syed Mohammad Mahmood ◽

Hosein Ghaedi ◽

Sameer Al-Hajri

Keyword(s):

Polymer Solution ◽

Oil Recovery ◽

Empirical Model ◽

Linear Regression Analysis ◽

Polymer Concentration ◽

Polymer Flooding ◽

Solution Viscosity ◽

Operational Variables ◽

Reservoir Conditions ◽

Sulfonated Polyacrylamide

Copolymers of acrylamide with the sodium salt of 2-acrylamido-2-methylpropane sulfonic acid—known as sulfonated polyacrylamide polymers—had been shown to produce very promising results in the enhancement of oil recovery, particularly in polymer flooding. The aim of this work is to develop an empirical model through the use of a design of experiments (DOE) approach for bulk viscosity of these copolymers as a function of polymer characteristics (i.e., sulfonation degree and molecular weight), oil reservoir conditions (i.e., temperature, formation brine salinity and hardness) and field operational variables (i.e., polymer concentration, shear rate and aging time). The data required for the non-linear regression analysis were generated from 120 planned experimental runs, which had used the Box-Behnken construct from the typical Response Surface Methodology (RSM) design. The data were collected during rheological experiments and the model that was constructed had been proven to be acceptable with the Adjusted R-Squared value of 0.9624. Apart from showing the polymer concentration as being the most important factor in the determination of polymer solution viscosity, the evaluation of the model terms as well as the Sobol sensitivity analysis had also shown a considerable interaction between the process parameters. As such, the proposed viscosity model can be suitably applied to the optimization of the polymer solution properties for the polymer flooding process and the prediction of the rheological data required for polymer flood simulators.

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Oxidation of Crude Oil in Porous Media

Society of Petroleum Engineers Journal ◽

10.2118/1937-pa ◽

1968 ◽

Vol 8 (02) ◽

pp. 137-148 ◽

Cited By ~ 57

Author(s):

I.S. Bousaid ◽

H.J. Ramey

Keyword(s):

Oxygen Partial Pressure ◽

Crude Oil ◽

Partial Pressure ◽

Reaction Kinetics ◽

Oil Recovery ◽

Carbon Concentration ◽

Combustion Process ◽

Order Reaction ◽

First Order ◽

Catalyst Pellets

Abstract Experimental results on the oxidation reaction kinetics in the forward combustion oil recovery process are presented. A total of 48 runs were made wherein a stationary thin layer of coked, unconsolidated sand was burned isothermally in a combustion cell. Individual runs were made at various temperature levels to permit determination of the effect of temperature upon the reaction. An expression was obtained for the burning rate of carbon as a function of carbon concentration, combustion temperature and oxygen partial pressure. The carbon burning rate for two types of crude oil indicated a first order reaction with respect to both carbon concentration and oxygen partial pressure. The effect of combustion temperature on the reaction rate constant matched the Arrhenius equation. The activation energy was similar for the two crude oils examined. The activation energy decreased for a porous media containing clay. The rate of oxidation of crude oil at reservoir temperature was found to be significant. Other significant findings included information on hydrogen-carbon content of fuel residues, fuel reactivity and the products of combustion. Introduction The production of crude oil by underground combustion has been studied in the laboratory by many investigators. Results of laboratory and field experiments have been reported in the literature describing the forward combustion process. But as yet, no qualitative or quantitative study of the kinetics of fuel combustion involved in this process has been reported. The fuel concentration and the rate at which fuel is burned at the front are important factors governing the air requirement in a forward combustion operation. Although the fuel is essentially unrecoverable crude, the air required to burn the fuel is an important economic factor in this process. Because fuel is burned, the heat transport associated with forward combustion is a key and unique feature of this new oil recovery method. Many investigators have presented information on the heat transmission and fluid mechanics involved in forward combustion. Berry and Parrish demonstrated the utility of considering reaction kinetics in reverse burning. From differential thermal analysis, Tadema presented a qualitative discussion of the nature of reactions between oil and oxygen in combustion oil recovery. Although little quantitative work has been done on be reaction kinetics involved in forward combustion oil recovery, an extensive literature does exist on combustion of carbons and oils, and carbonaceous residues from cracking catalyst pellets. Dart, et al., studied the combustion rate for oxidation of carbonaceous residues on clay catalyst pellets, and found the reaction to be second-order with respect to carbon concentration, and first-order with respect to oxygen partial pressure for carbon concentrations less than 2 weight percent of the catalyst weight. The reaction appeared to be first-order with respect to carbon concentration for concentrations greater than 2 percent. Metcalfe noted that other workers had found that aging of the fuel during the combustion process was responsible for changing coke properties, and A accounted for the apparent second-order carbon concentration effect found by Dart, et al. It appears that burning of residues from cracking pellets is first-order with respect to both carbon concentration and oxygen partial pressure. Dart, et al., also observed that hydrogen in the hydrocarbon residue appeared to react faster than the carbon. Lewis, et al., studied oxidation of charcoal, coke and graphite in a fluidized bed. Gas velocities were high enough to partially lift and circulate the carbon particles. Their results indicated first-order reaction dependency with respect to both carbon concentration and oxygen partial pressure. SPEJ P. 137ˆ

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