UNIVERSIDADE ESTADUAL DE CAMPINAS
FACULDADE DE ENGENHARIA MECÂNICA
E INSTITUTO DE GEOCIÊNCIAS
JUAN CARLOS LIZCANO NIÑO
EVALUATION OF THE EFFECT OF A SACRIFICE
BANK ON POLYMER RETENTION IN SANDSTONES
CORES
AVALIAÇÃO DO EFEITO DE UM BANCO DE
SACRIFÍCIO NA RETENÇÃO DE POLÍMEROS EM
AMOSTRAS DE ARENITOS
CAMPINAS
2018
EVALUATION OF THE EFFECT OF A SACRIFICE BANK
ON POLYMER RETENTION IN SANDSTONES CORES
AVALIAÇÃO DO EFEITO DE UM BANCO DE SACRÍFICIO
NA RETENÇÃO DE POLÍMEROS EM AMOSTRAS DE
ARENITOS
Dissertation presented to the Mechanical Engineering Faculty and Geosciences Institute of the University of Campinas in partial fulfillment of the requirements for the degree of Master in Petroleum Sciences and Engineering in the area of Reservoirs and Management.
Dissertação apresentada à Faculdade de Engenharia Mecânica e Instituto de Geociências da Universidade Estadual de Campinas como parte dos requisitos exigidos para a obtenção do título de Mestre em Ciências e Engenharia de Petróleo na área de Reservatórios e Gestão.
Orientadora: Profa. Dra. Rosângela Barros Zanoni Lopes Moreno
Este exemplar corresponde à versão final da Dissertação defendida pelo aluno Juan Carlos Lizcano Niño e orientada pelo Profa. Dra. Rosângela Barros Zanoni Lopes Moreno. ________________________________
Assinatura do Orientador
CAMPINAS
2018
Ficha catalográfica
Universidade Estadual de Campinas Biblioteca da Área de Engenharia e Arquitetura
Luciana Pietrosanto Milla - CRB 8/8129
Lizcano Niño, Juan Carlos,
1992-L768e LizEvaluation of the effect of a sacrifice bank on polymer retention in sandstones / Juan Carlos Lizcano Niño. – Campinas, SP : [s.n.], 2018.
LizOrientador: Rosângela Barros Zanoni Lopes Moreno.
LizDissertação (mestrado) – Universidade Estadual de Campinas, Faculdadede Engenharia Mecânica.
Liz1. Retenção. 2. Reservatórios. 3. Arenitos. 4. Polímeros. 5. Meios porosos. I. Moreno, Rosângela Barros Zanoni Lopes, 1966-. II. Universidade Estadual de Campinas. Faculdade de Engenharia Mecânica. III. Título.
Informações para Biblioteca Digital
Título em outro idioma: Avaliação do efeito de um banco de sacríficio na retenção
de polímeros em amostras de arenitos
Palavras-chave em inglês: Retention Reserviors Sandstones Polymers Porous media
Área de concentração: Reservatórios e Gestão Titulação: Mestre em Ciências e Engenharia de
Petróleo Banca examinadora:
Rosângela Barros Zanoni Lopes Moreno [Orientador] Denis José Schiozer
Rosangela de Carvalho Balaban
Data de defesa: 21-02-2018
FACULDADE DE ENGENHARIA MECÂNICA
E INSTITUTO DE GEOCIÊNCIAS
DISSERTAÇÃO DE MESTRADO ACADÊMICO
EVALUATION OF THE EFFECT OF A
SACRIFICE BANK ON POLYMER RETENTION
IN SANDSTONES CORES
Autor: Juan Carlos Lizcano Niño
Orientador: Profa. Dra. Rosângela Barros Zanoni Lopes Moreno
A Banca Examinadora composta pelos membros abaixo aprovou esta Dissertação:
____________________________________________________ Profa. Dra. Rosângela Barros Zanoni Lopes Moreno, Presidente DE / FEM / UNICAMP
____________________________________________________ Prof. Dr. Denis José Schiozer
DE / FEM / UNICAMP
____________________________________________________ Profa. Dr. Rosangela de Carvalho Balaban
IQ / UFRN
A Ata da defesa com as respectivas assinaturas dos membros encontra-se no processo de vida acadêmica do aluno.
DEDICATION
This dissertation is dedicated to my parents Luis Carlos and Martha, especially to my mom who always supported me during the difficult moments and is my greatest strength and the reason to continue fighting every day. Also, to my friends in Colombia (“Go o que friends”), which were a constant support to keep me calm and serene in different situations in these two years. Finally, to Clarice for the unbelievable moments that we have spent together.
ACKNOWLEDGMENT
First, I would like to thank God for always guiding me and helping me to show me the best way in the different stages of my life.
To my parents, family and friends for the support and encouragement to continue with my academic and personal formation.
To the professor Rosângela for her affection and dedication in the execution of this project as my advisor.
To my girlfriend Clarice, for her fellowship, dedication, and compression.
To the Laboratory of Oil Reservoirs at Unicamp (LABORE), the Energy Department at School of Mechanical Engineering (FEM), Coordination for the Improvement of Higher Education Personnel (CAPES) and Organization of American States (OAS) and the Coimbra Group of Brazilian Universities (GCUB) for their financial support.
RESUMO
A retenção de polímero em meios porosos durante processos de injeção é um fenômeno inevitável. O desenvolvimento de técnicas para minimizar a retenção é benéfico para ampliar a sua aplicação em métodos de Recuperação Avançada de Petróleo (EOR). Este trabalho avalia experimentalmente esquemas de injeção para minimizar a retenção de polímero em meios porosos. A abordagem consiste na injeção inicial de um banco de sacrifício de baixa concentração de polímero e, posteriormente, no deslocamento do banco de polímero projetado com obejtivo de recuperar mais óleo. Com o objetivo de medir a retenção de polímero irreversível, dois bancos idênticos de 20 volumes porosos foram injetados e separados por 30 volumes porosos de salmoura a uma vazão constante de 1 ml/min. Dois esquemas de injeção foram definidos variando-se a concentração de polímero: diminuiu-se a concentração de polímero dos bancos no primeiro esquema e, no segundo, aumentou-se a concentração. Comparando os resultados desses dois esquemas, foi possível avaliar a eficiência da injeção do banco de sacrifício. Dois polímeros de HPAM, com pesos moleculares de 7 e 20 milhões de Daltons foram testados em amostras de arenito de 350 mD e 5000 mD, respectivamente. Duas salmouras sintéticas foram utilizadas: uma com base em um campo na Colômbia (NaCl a 0,7%) usada com o polímero de baixo peso molecular e uma outra com base na água do mar (3,5% TDS) usada com o polímero de alto peso molecular. A retenção individual e a retenção cumulativa causada pelos bancos de HPAM foram determinadas, assim como o volume poroso inacessível (IPV). Além disso, o fator de resistência e a redução da permeabilidade foram também calculados. Valores de 79% e 100% na redução da retenção de polímero para o banco de recuperação projetado foram obtidos devido aos esquemas de injeção aplicados. No entanto, para obter esta redução foi necessário induzir uma retenção cumulativa de 175,7 µg/g para o polímero de baixo peso molecular e de 58,9 µg/g para o polímero de alto peso molecular. O IPV foi de 0.5 volumes porosos, em experimentos com o polímero de baixo peso molecular em amostras de baixa permeabilidade, e de 0.25 volumes porosos nos experimentos com HPAM de alto peso molecular em amostras de alta permeabilidade. Também se provou que a redução da permeabilidade causada pela injeção de polímero não tem uma relação linear com sua concentração. Este trabalho oferece informações sobre o uso de bancos de sacrifício de polímero como agente de redução da retenção.
ABSTRACT
Polymer loss due to retention is an inevitable phenomenon, which happens during flooding processes. The development of methods to minimize this retention is beneficial to broaden the application of this EOR method. This work evaluates injection schemes for reducing polymer retention in porous media experimentally. The approach consists of injecting a sacrifice bank of low polymer concentration, and subsequently, flood the designed polymer bank. An experimental methodology was developed to quantify polymer retention in sandstone samples. To measure the irreversible polymer retention due to the first polymer concentration injected, two identical polymer banks of 20 PV separated by 30 PV of brine were injected at a constant flow rate of 1ml/min. Two injection schemes varying polymer concentration were performed: one in which polymer concentration of the following banks decreased, and one in which the concentration increased. By comparing the results of these two schemes, it was possible to evaluate the efficiency of the injection of the sacrifice bank. Two HPAM polymers, with molecular weights of 7 and 20 million Daltons, were tested in 350 mD and 5000 mD sandstone samples, respectively. Two synthetic brines were used, a Colombian-field brine (0.7% NaCl) for the low-molecular weight polymer and a seawater brine (3.5% TDS) for the high-molecular weight polymer. Polymer retention and the cumulative retention caused by HPAM banks and the inaccessible pore volume (IPV) were determined. Additionally, resistance factor and absolute permeability reduction were measured. Values of 79% and 100% on polymer retention reduction for the designed recovery bank were detected by the injection schemes applied. However, to obtain this reduction in the retention of the designed recovery polymer bank, a cumulative retention of 175.7 µg/g was observed for the low molecular weight polymer and 58.9 µg/g for the high-molecular weight polymer. IPV was high (around 0.5 PV) in experiments with low-molecular weight polymer and low permeability samples. On the other hand, IPV was low (around 0.25 PV) in experiments with high-molecular weight HPAM and high permeability samples. We also proved that the permeability reduction caused by polymer flooding has not a linear relation with the injected polymer concentration for the conditions tested. This work offers valuable insights into the use of sacrificial banks of lower polymer concentration as a reducing retention agent for the more concentrated polymer bank.
Key Word: Polymer Flooding; Chemical Flooding; Polymer Retention; Enhanced Oil
LIST OF FIGURES
Figure 2.1. Scheme of the improvement of areal sweep (Adapted from Sorbie, 1991) ... 24
Figure 2.2. Different types of shear stress vs shear rate ... 26
Figure 2.3. Comparison between Carreau - Power Laws (Adapted from Sorbie, 1991). ... 27
Figure 2.4. Structure of partially hydrolyzed polyacrylamide (Adapted from Sorbie, 1991) .. 28
Figure 2.5. The structure of the xanthan biopolymer (Sheng, 2010) ... 30
Figure 2.6. Schematic of polymer retention mechanisms in porous media (Adapted from Willhite and Dominguez, 1977) ... 35
Figure 2.7. Cumulative distribution of HPAM and biopolymers adsorption. (Adapted from Sheng, 2010) ... 36
Figure 2.8. Salinity Effect on Polymer Adsorption (Adapted from Martin et al., 1983) ... 37
Figure 2.9. Salinity Effect on Residual Resistance Factor (Adapted from Martin et al., 1983) ... 37
Figure 2.10. Molecular Weight Effect on Polymer Retention (Adapted from Yang et al., 2002a). ... 38
Figure 2.11. Permeability Effect on Polymer Retention due to mechanical trapping (Adapted from Vela et al., 1976)... 39
Figure 2.12. Langmuir Isotherm Model for High Molecular Weight Polymers-HPAM. (Adapted of Dason and Lantz, 1972) ... 40
Figure 2.13. Biopolymer concentration effect on adsorption. (Adapted from Lötsch, 1988) .. 40
Figure 2.14. Inaccessible Pore Volume. (Adapted from Dason and Lantz, 1972) ... 42
Figure 2.15. Tracer and polymer concentration profiles in the effluent (Adapted from Hughes et al., 1990) ... 42
Figure 3.1. Dynamic experiments performed by Zhang and Seright (2014). ... 47
Figure 4.1. Flowchart of the Experimental Methodology ... 51
Figure 4.2. Rheometer HAAKE MARS III used in the Rheological Measurements ... 53
Figure 4.3. HPAM Flopaam 3230S rheology in brine-SF ... 54
Figure 4.4. HPAM Flopaam 3630S rheology in brine-SW ... 54
Figure 4.5. Comparison between rheological behaviors for both HPAM. ... 55
Figure 4.6. Determination of the Overlapping Concentration for HPAM 3230S ... 56
Figure 4.7. Determination of the Overlapping Concentration for HPAM 3630S ... 56
Figure 4.8. Soxhlet used in the Core Cleaning Process ... 59
Figure 4.10. Diagram of the Experimental Setup for Retention Tests ... 62
Figure 4.11. Experimental Setup for the Retention Tests... 63
Figure 4.12. Absorbance behavior as a function of the wavelength of the polymers. ... 64
Figure 4.13. Absorbance behavior as a function of polymer concentration for both polymers65 Figure 4.14. Experimental Procedure Adapted from Lötsch et al., 1985 ... 66
Figure 4.15. Polymer Injection Scheme 01 – Increasing Polymer Concentration ... 68
Figure 4.16. Polymer Injection Scheme 02 – Decreasing Polymer Concentration ... 68
Figure 5.1. Absorbance Behavior in Experiment 1 ... 71
Figure 5.2. Absorbance Behavior in Experiment 2 ... 72
Figure 5.3. Normalized Concentration Behavior in Experiment 1 ... 73
Figure 5.4. Normalized Concentration Behavior in Experiment 2 ... 73
Figure 5.5. Polymer Retention Results in Experiment 1 ... 74
Figure 5.6. Polymer Retention Results in Experiment 2 ... 75
Figure 5.7. Conductivity Results in Experiment 1 ... 76
Figure 5.8. Conductivity Results in Experiment 2 ... 76
Figure 5.9. Determination of the Inaccessible Pore Volume in Experiment 1 ... 77
Figure 5.10. Determination of the Inaccessible Pore Volume in Experiment 2 ... 78
Figure 5.11. Differential Pressure Results in Experiment 1 ... 80
Figure 5.12. Differential Pressure Results in Experiment 2 ... 81
Figure 5.13. Permeability Reduction due to each Polymer Bank in Experiment 01 ... 82
Figure 5.14. Permeability Reduction due to each Polymer Bank in Experiment 2 ... 82
Figure 5.15. RRF and RF results in Experiment 1 ... 83
Figure 5.16. RRF and RF results in Experiment 2 ... 84
Figure 5.17. Absorbance Behavior in Experiment 3. ... 86
Figure 5.18. Absorbance Behavior in Experiment 4 ... 86
Figure 5.19. Normalized Concentration Behavior in Experiment 3 ... 87
Figure 5.20. Normalized Concentration Behavior in Experiment 4 ... 87
Figure 5.21. Polymer Retention Results in Experiment 3 ... 88
Figure 5.22. Polymer Retention Results in Experiment 4 ... 89
Figure 5.23. Conductivity Results in Experiment 3 ... 90
Figure 5.24. Conductivity Results in Experiment 4 ... 90
Figure 5.25. Determination of the Inaccessible Pore Volume in Experiment 3 ... 91
Figure 5.26. Determination of the Inaccessible Pore Volume in Experiment 4 ... 92
Figure 5.28. Differential Pressure Results in Experiment 4 ... 94
Figure 5.29. Permeability Reduction due to each Polymer Bank in Experiment 3 ... 95
Figure 5.30. Permeability Reduction due to each Polymer Bank in Experiment 4 ... 95
Figure 5.31. RRF and RF results in Experiment 3 ... 96
LIST OF TABLES
Table 2.1. Inaccessible PV in different types of porous media (Adapted from Green and
Willhite, 1998) ... 43
Table 3.1. Experimental Results and Conditions in Zhang and Seright (2014) Experiments. . 46
Table 3.2. Technical Screening Guides* for Polymer Flooding by Taber et al., 1997 ... 47
Table 3.3. Parameters of field cases of polymer injection projects* ... 50
Table 4.1. HPAM polymer used in the experiments ... 52
Table 4.2. Synthetic brines used for preparation of the polymer solutions ... 53
Table 4.3. Characterization Results of the Polymers... 57
Table 4.4. Petrophysical properties of the samples used in the experiments ... 61
Table 4.5. Tracers used in the Retention Experiments ... 65
Table 5.1. Summary of the Experiments Proposed ... 70
Table 5.2. Comparison between Average Pore Radius of the Sandstones and the Radius of Gyration of the HPAM 3230S ... 79
Table 5.3. Comparison between Average Pore Radius of the Sandstones and the Radius of Gyration of the HPAM 3630S ... 92
LIST OF SYMBOLS
(∆𝑝)𝑏 Differential pressure of brine bank at steady state psi (∆𝑝)𝑏2 Differential pressure of subsequent brine banks at steady state psi (∆𝑝)𝑏i Initial differential pressure of the fisrt brine bank at steady state psi (∆𝑝)𝑝 Differential pressure of polymer bank at steady state psi (∆𝑝)𝑤1 Differential pressure before polymer bank injection at steady state psi (∆𝑝)𝑤2 Differential pressure after polymer bank injection at steady state psi (𝐶/𝐶𝑜)𝑝𝑜𝑙𝑦𝑚𝑒𝑟 Normalized polymer concentration
(𝐶/𝐶𝑜)𝑠𝑎𝑙𝑡 Normalized salt concentration
µ𝑜 Dynamic viscosity of oil phase cP µ𝑝 Dynamic viscosity of polymer phase cP µ𝑤 Dynamic viscosity of water phase cP 𝐴𝑀 Maximum absorbance value for a specific polymer bank
𝐴𝑖 Absorbance value at any PV displaced for a specific polymer bank 𝐴𝑚 Minimum absorbance value for a specific polymer bank
𝐶∗ Overlapping concentration ppm 𝐶𝑖 Polymer concentration in the effluents of each bank ppm 𝐶𝑜 Initial polymer concentration of each bank ppm 𝐸𝐷 Microscopic displacement efficiency 𝐸𝑑 Macroscopic (volumetric) displacement efficiency 𝐾𝑜 Initial absolute permeability of the sample mD 𝑁𝐴 Avogadro’s number (6.022𝑥1023) mole-1 𝑃𝑉𝑝𝑜𝑙𝑦𝑚𝑒𝑟 Normalized pore volume where occurred the polymer breakthrough 𝑃𝑉𝑡𝑟𝑎𝑐𝑒𝑟 Normalized pore volume where occurred the tracer breakthrough 𝑅𝑔 Radius of gyration nm 𝑉𝑟𝑜𝑐𝑘 Volume of rock grains cm3 𝑘𝑜 Effective permeability of oil phase mD 𝑘𝑝 Effective permeability of polymer phase mD 𝑘𝑤 Effective permeability of water phase mD 𝛾̇ Shear rate s-1 𝜆𝐷 Displacing phase mobility
𝜆𝑑 Displaced phase mobility 𝜆𝑜 Oil mobility 𝜆𝑝 Polymer mobility
𝜆𝑤 Water mobility
𝜌𝑝𝑜𝑙𝑦𝑚𝑒𝑟 Polymer solution density g/cm3 𝜌𝑟𝑜𝑐𝑘 Bulk rock density g/cm3 𝜎𝑀 Maximum conductivity value for a specific polymer bank S/m 𝜎𝑖 Conductivity value at any PV displaced for a specific polymer bank S/m 𝜎𝑚 Minimum conductivity value for a specific polymer bank S/m 𝑃𝑉𝑖
𝑃𝑉𝑜
⁄ Pore volume normalized
µ Dynamic viscosity cP 𝜂 Apparent viscosity cP 𝐸 Overall displacement efficiency
𝐼𝑃𝑉 Inaccessible pore volume % PV
𝐾 Absolute permeability of the sample mD 𝐾/𝐾𝑜 Absolute permeability reduction
𝑀 Mobility ratio
𝑃𝑉 Pore volume cm3 𝑅𝐹 Resistance factor
𝑅𝑅𝐹 Residual resistance factor
𝑞 Flow rate cm3/min 𝑟 Average pore radius of the sandstone samples µm 𝛤 Polymer retention μg polymer/g rock 𝜆 Mobility
𝜌 Density g/cm3 𝜏 Shear stress Pa 𝜙 Effective porosity
SUMÁRIO
1. INTRODUCTION ... 181.1.
Motivation ... 20
1.2.
Objectives ... 20
1.3.
Dissertation Structure ... 21
2. THEORETICAL FUNDAMENTALS ... 222.1.
Mobility Control... 22
2.1.1. Efficient Microscopic and Macroscopic Displacement ... 22
2.1.2. Mobility Ratio ... 23
2.1.3. Resistance Factor and Residual Resistance Factor ... 24
2.1.4. Rheology ... 25
2.2.
Polymers in EOR Applications ... 28
2.2.1. Hydrolyzed Polyacrylamide (HPAM) ... 28
2.2.2. Xanthan Gum ... 30
2.3.
Polymer Stability ... 31
2.3.1. Chemical Degradation ... 31
2.3.2. Mechanical Degradation ... 32
2.3.3. Biological Degradation ... 33
2.4.
Polymer Retention in Porous Media ... 33
2.4.1. Polymer Retention Units... 34
2.4.2. Polymer Retention Mechanisms in Porous Media... 34
2.4.3. Influential Factors in the Retention of Polymers ... 36
2.4.4. Inaccessible Pore Volume... 41
3.1.
Fundamental Aspects ... 44
3.2. Screening Criteria for Polymer Flooding ... 47
3.3. Field Cases of Polymer Injection Application ... 49
4. EXPERIMENTAL METHODOLOGY ... 51
4.1.
Stage One: Rheological Characterization of Fluids ... 52
4.1.1. Polymers ... 52
4.1.2. Brine and Polymer Solutions ... 52
4.2.
Stage Two: Core Handling and Characterization ... 57
4.2.1. Permeability Range Criteria ... 58
4.2.2. Porous Media ... 58
4.2.3. Samples Cleaning Process ... 58
4.2.4. Sample Saturation Process ... 59
4.2.5. Determination of the Petrophysical Properties ... 60
4.3.
Stage Three: Retention Tests ... 61
4.3.1. Experimental Setup ... 62
4.3.2. Tracers ... 65
4.3.3. Dynamic Retention Measurement: Experimental Procedure ... 66
4.3.4. Polymer Injection Schemes ... 67
5. RESULTS AND DISCUSSIONS ... 70
5.1.
HPAM 3230S Experiments ... 71
5.1.1. Absorbance Results ... 71
5.1.2. Conductivity Results ... 75
5.1.3. Differential Pressure Results ... 80
5.2.
HPAM 3630S Experiments ... 85
5.2.2. Conductivity Results ... 89
5.2.3. Differential Pressure Results ... 93
6. CONCLUSIONS ... 98
REFERENCES ... 100
Appendix A - DATA OF THE RHEOLOGY MEASUREMENTS FOR HPAM 3230S SOLUTIONS ... 109
Appendix B - DATA OF THE RHEOLOGY MEASUREMENTS FOR HPAM 3630S SOLUTIONS ... 110
1. INTRODUCTION
At the global level, the total demand for primary energy will increase from 273.9 mboe/d in 2014 to 382.1 mboe/d in 2040, representing a rise of 40%. Currently, fossil fuels (oil, gas, and coal) stands for 81% of global energy consumption (OPEC, 2017). In 2040, fossil fuels will maintain their importance in global energy consumption, although with a lower contribution of 77% in the total energy demand (OPEC, 2017). In recent years, world reserves did not record a significant increase to meet future energy needs, with a value of 1700 billion barrels at the end of 2014, sufficient to meet 52.5 years of global production. Furthermore, global oil production growth was more than double that of global consumption, rising by 2.1 million barrels/day or 2.3% (BP, 2015). MANRIQUE et al. (2010) reported that most of the current world oil production comes from mature fields, evidencing the decay of new significant discoveries in the last decades to replace and increase the existing reserves. To supply that energy demand in the coming years is necessary to produce the recoverable oil by applying IOR and EOR methods in a scenario of technical and economic feasibility.
An oil recovery method can be defined in three stages: primary stage, secondary stage, and tertiary stage. Historically, these stages described the production from a reservoir in a chronological sense. Primary production is due to natural energy available in the reservoir. Thus, it does not require injection of external fluids or addition of drive force. These natural energy sources include rock and fluid expansion, solution gas, water influx, gas cap, and gravity drainage. Secondary recovery usually is implemented after primary production decline. Traditional secondary recovery processes are by injection of external fluids, such as water and/or gas, mainly for the purpose of pressure maintenance and volumetric sweep efficiency. These are purely mechanical methods, without any chemical or thermodynamic interaction between the fluids or between the fluids and the rock. Tertiary recovery refers to the intervention after secondary recovery process became uneconomical. It is characterized by injection of special fluids such as chemicals, miscible gases, and/or the injection of thermal energy (GREEN AND WILLHITE, 1998; SHENG, 2010). Water injection is the standard recovery method for maintaining reservoir pressure and improving oil sweep efficiency. The oil displacement efficiency by water, however, is limited in the cases of unfavorable mobility ratio between water and oil in the reservoir (HATZIGNATIOU et al., 2013).
The term EOR (Enhanced Oil Recovery) was originally used as a reference of a variety of new recovery processes aiming at recovering oil left behind after waterflooding. According to a definition provided by STOSUR et al. (2003) and SHENG (2010), EOR refers to any reservoir process that changes the current rock/oil/brine interactions in the reservoir, such as, thermal recovery (in situ combustion, air injection THAI, CAPRI, SAGD, VAPEX, hot water drive), miscible flooding (CO2, nitrogen, flue gas, hydrocarbon, solvent), chemical flooding (polymer, surfactant, alkaline, emulsion, foam and their combinations) and microbial processes. The term IOR (Improved Oil Recovery) refers to any practice aiming to increase oil recovery, including EOR processes, conformance control (cement plug/gel treatment for water and gas shut-off), immiscible gas injection (dry gas, CO2, nitrogen, alternating or co-injection with water), water injection, cyclic water injection, well stimulation (such as acidizing) and fracturing.
The enhanced oil recovery by polymer flooding appears to remedy problems present in water injection, increasing the water viscosity and reducing the permeability to the aqueous phase (HATZIGNATIOU et al., 2013). Polymer solutions are designed to develop a favorable mobility ratio between the injected polymer solution and the oil displaced ahead of the polymer. Therefore, a stable volumetric sweep takes place improving macroscopic sweep efficiency (GREEN AND WILLHITE, 1998). However, sometimes this polymer injection is not economically feasible due to excessive retention of polymer in the reservoir (BROSETA et al., 1995). During injection, part of the polymer is retained in the porous media due to mechanical entrapment in pores smaller than the size of the polymer molecule, adsorption on the rock surface and hydrodynamic retention induced by the interstitial velocity variation (GOGARTY, 1967; DAWSON AND LANTZ, 1972; SZABO, 1975; HUH et al., 1990; GREEN AND WILLHITE, 1998; ZHANG AND SERIGHT, 2014; FERREIRA AND MORENO, 2017). The significance of the mechanical entrapment depends on the pore size distribution, and it is a more likely mechanism for polymer retention in low-permeability formation (SZABO, 1975; WILLHITE AND DOMINGUEZ, 1977; SORBIE, 1991; SHENG, 2010). The retention causes a viscosity reduction of the polymer injected and a delay in its flooding. Thus, this phenomenon understanding is essential for establishing the appropriate retention behavior, which affects directly on the economic and technical feasibility of the project (SORBIE, 1991).
A possible method to minimize the polymer retention in porous media is suggested by ZHANG AND SERIGHT (2014). They proved that initial injection of a low-concentrated polymer bank could reduce the polymer retention caused by subsequent polymer banks injected. The low-concentrated banks are called “sacrifice banks” and they are in charge of inducing initial polymer retention in porous media, then, the subsequent polymer molecules injected will not have rock zones where could occur the retention.
This dissertation aims to evaluate the effect of a sacrifice bank as minimization method of the polymer retention in sandstones samples. Four displacement tests were performed to quantify polymer retention, inaccessible pore volume (IPV), resistance factor, and absolute permeability reduction due to each polymer bank.
1.1. Motivation
The successful implementation of an enhanced oil recovery project is limited by its technical and economic feasibility. Polymer flooding is based on increase water viscosity by adding polymer. However, the inevitable polymer retention in the porous media causes the loss of the added polymer through different retention mechanism. This phenomenon is currently one of the most significant challenges in the application of polymer injection on sandstones reservoir, and a high impact of the polymer retention does a project that could have a high-income potential to an infeasible plan. The study of methods to minimize polymer retention will allow its optimal application.
1.2. Objectives
The main objective of this work is evaluating the effect of a sacrifice bank on polymer retention in sandstones experimentally and analyze the key factors effects on the phenomenon, such as polymer concentration, polymer molecular size, injection bank scheme, and absolute permeability of the porous media.
In order to achieve this primary objective, four specific goals were defined:
Define an experimental methodology capable of determining key parameters on polymer retention in schemes of ascending and descending polymer concentration.
Determine the rheological behavior of the polymers and petrophysical properties of the porous media under defined conditions.
Carry out four retention experiments based on the experimental methodology defined previously.
Quantify the individual and cumulated polymer retention, residual resistance factor and resistance factor due to each injected polymer bank. Also inaccessible pore volume for each of the sandstone samples used was quantified.
1.3. Dissertation Structure
The overall structure of the work takes the form of six chapters as followed: Chapter 1 presents a brief introduction to the proposed theme, the motivation and the
objectives of this work.
Chapter 2 provides the theoretical basis and the concepts related to the proposed theme for the understanding of the dissertation. Topics such as mobility control, polymers used in EOR applications, polymer stability and polymer retention on porous media are defined.
In Chapter 3, a literature review is presented focusing on fundamental aspects handled in polymer retention and some experimental cases taken as reference in this dissertation, also in the screening of polymer flooding and lastly the most relevant field cases around the word of polymer injection.
Chapter 4 is concerned with the methodology used to perform the experiments, as well as the materials, equipment, experimental procedures and the test conditions to achieve the proposed objectives. Also explains all the preparations done to the samples and the injected fluids before starting the main flooding experiments.
Chapter 5 describes the experimental results of the four tests performed, as well as the processing of the experimental data and the discussions.
In Chapter 6, the conclusions of the work are summarized, as well as some suggestions and recommendations for future research.
2. THEORETICAL FUNDAMENTALS
This chapter presents the fundamental concepts of polymer injection as EOR method based on the water flooding process. Fundaments and definitions such as mobility ratio, residual resistance factor, rheology, type of polymer, influencing factors such as salinity, hardness, and pH on polymer viscosity, polymer degradation, and polymer retention, as well as the main characteristics and properties of the polymer are discussed.
2.1. Mobility Control
Mobility control is one of the most important concepts in EOR methods. The injection of chemicals can reach efficient mobility control by improving the injection of chemicals in order to improve the displacing fluid viscosity, reducing relative permeability of the aqueous phase or modifying wettability. These changes can be achieved through injection of foams, polymers, surfactants and other chemical agents (SHENG, 2010). Many EOR processes are designed to be a non-miscible displacement of oil, and poor design of mobility between these fluids can lead to problems such as early breakthroughs and loss of the displacing fluid. The following item presents basic concepts used for mobility control in EOR processes.
2.1.1. Efficient Microscopic and Macroscopic Displacement
The overall displacement efficiency (E) is defined as the product of the microscopic displacement efficiency (ED), and the macroscopic (volumetric) displacement efficiency (EV) expressed as a fraction (Equation 1).
𝐸 = 𝐸𝐷𝐸𝑣 (1)
Microscopic displacement refers to the movement of oil through the pores of the rock contacted by the displacing fluid, and its efficiency (ED) is strongly governed by the capillary and viscous forces. The microscopic efficiency impacts directly on the residual oil saturation in the regions contacted by the displacing fluid (e.g., water and polymer). On the other hand, macroscopic displacement efficiency (EV) is related to the effectiveness of displacing fluid contact the fluids into the reservoir at a volumetric scale (areal and vertical). Absolute permeability and effective porosity of the formation, vertical and areal heterogeneities, fractures, reservoir thickness, mobility ratio, flow rate, injection pattern are
some of the factors that influence macroscopic displacement efficiency. EV is a measure of the magnitude of the average residual oil saturation based on the residual oil in both swept and not swept zones of the reservoir (GREEN AND WILLHITE, 1998).
2.1.2. Mobility Ratio
Phase mobility (λ) is defined as the ratio between the effective permeability to the phase (k) through the porous media and its dynamic viscosity (µ) (SHENG, 2010). If three fluids (oil, water, and gas) were present in the porous media, their mobility is defined, respectively, by Equation 2. 𝜆𝑜 = 𝑘𝑜 𝜇𝑜, 𝜆𝑤 = 𝑘𝑤 𝜇𝑤, 𝜆𝑔 = 𝑘𝑔 𝜇𝑔 (2)
Mobility ratio (M) is the most used parameter in mobility control. It is described by the ratio between the mobility of the displacing phase (𝜆𝐷) and the mobility of the displaced phase (𝜆𝑑) (GREEN AND WILLHITE, 1998). Equation 3 presents the mobility ratio expression, where the displacing fluid is the polymer solution, and the displaced fluid is oil.
𝑀 = 𝜆𝐷 𝜆𝑑 = (𝑘𝐷/µ𝐷) (𝑘𝑑/µ𝑑) = (𝑘𝑝/µ𝑝) (𝑘𝑜/µ𝑜) = 𝑘𝑝 µ𝑜 𝑘𝑜 µ𝑝 (3)
According to CRAIG (1971), mobility ratios less than 1 (𝑀 ≤1) are favorable and those greater than 1 (𝑀 ≥1) are unfavorable for the displacement. To improve sweep efficiency, the mobility ratio should be reduced to values less than or equal to 1.
There are mainly two situations which the polymers applications may be considered as follows: unfavorable mobility ratio waterflood and moderate reservoir heterogeneity. In the first case, there is an inefficient microscopic (linear) displacement efficiency for 𝑀≥1 with its associated low Buckley-Leverett front height, this induces early breakthrough. In addition, viscous fingering can lead to a low waterflood areal sweep efficiency. This situation is illustrated schematically in Figure 2.1, which shows viscous fingering in a five-spot flood pattern. When there is an unfavorable mobility ratio in the waterflooding through some highly heterogeneous systems, such as those containing high-permeability channels, polymers are used to improve the vertical and areal efficiencies by redressing the mobility ratio. The polymer
increases the aqueous-phase viscosity and in addition, can decrease the permeability to the aqueous phase for certain polymers. This improves the microscopy displacement efficiency by increasing the Buckley-Leverett saturation front height (SORBIE, 1991).
Figure 2.1. Scheme of the improvement of areal sweep by polymer flooding in a five-spot (Adapted from
Sorbie, 1991)
2.1.3. Resistance Factor and Residual Resistance Factor
Besides raising the viscosity of the aqueous phase, the application of polymer solutions promotes the reduction of the permeability of the porous media by polymer retention. The determination of parameters such as resistance factor and residual resistance factor is essential for the understanding of the dynamic conditions of the reservoir.
The resistance factor (RF) describes the effect of the mobility reduction by the water viscosity increase and the effective permeability decrease to the aqueous phase due to polymer addition (Equation 4). Experimental applications of polymers in the laboratory allow a practical approximation of the resistance factor, which can be determined by differential pressure through the porous media at a constant flow rate of polymer and water (BAILJAL, 1982).
𝑅𝐹 = 𝜆𝑤 𝜆𝑝 =
(∆𝑝/𝑞)𝑝
The residual resistance factor (RRF) describes the reduction of the effective permeability to water and is defined as the relation between the water mobility before (subscript 𝑤1) and after (subscript 𝑤2) the injection of the polymer solution (Equation 5). According to ROSA et al. (2006), residual resistance factor values can be range from 3 to 5.
𝑅𝑅𝐹 = 𝜆𝑤1 𝜆𝑤2 = 𝑘𝑤1µ𝑤1 𝑘𝑤2µ𝑤2= (∆𝑝/𝑞)𝑤2 (∆𝑝/𝑞)𝑤1 (5)
Where ∆𝑝 is the differential pressure under steady-state regime, and 𝑞 is the flow rate.
2.1.4. Rheology
Rheology is defined as the study of deformation and flow of matter. In practice, rheology studies the fundamental or constitutive relations, between force and deformation in materials, primarily liquids (MACOSKO, 1994).
For liquids, the simplest constitutive relation (Equation 6) is Newton´s law, where the shear stress (τ) is proportional to the deformation of shear rate (𝛾̇) and the constant of proportionality is called the Newtonian viscosity (µ). Viscosity is an intrinsic property of a fluid. The SI (international system) unit of viscosity is the Pascal-second but is most used the cgs (centimeter-gram-second) unit which is the poise (1 poise = 0.1Pascal-second). As a reference, the water viscosity is approximately one centipoise (0.001 Pascal-second) at 25°C (MACOSKO, 1994).
𝜏 = 𝜇𝛾̇ (6)
Many materials obey Newton´s law. Gases and most all molecule liquids like water and oils present Newtonian behavior. However, some materials, such as, polymers solutions, behave between the ideal elastic solid and the ideal viscous fluid. In general, the Newtonian constitutive expression (Equation 6) accurately describes the rheological behavior of low molecular weight liquids and even high polymers at very low shear rates. Nevertheless, the viscosity can be a strong function of the shear rate for polymeric liquids, emulsions and concentrated suspensions (MACOSKO, 1994).
If the shear stress is not linearly proportional to the shear rate, such liquid is called non-Newtonian fluid and the ratio between 𝜏/𝛾̇ is called apparent viscosity (𝜂) MALKIN AND ISAYEV, 2006). This situation is shown for different materials in Figure 2.2, which illustrates different behavior between the shear stress and shear rate.
In Figure 2.2, the red line represents the Newtonian fluid behavior, and its slope is a constant. The blue line represents the behavior of pseudoplastic fluids, which shows a smaller slope as shear rate increases (viscosity appears to be less at increasing shear rates). In simple shear flow, the vast majority of polymer solutions are pseudoplastic (SORBIE, 1991). The green line represents the dilatant fluids, which the apparent viscosity increases as shear rate increases, this dilatant behavior is not commonly seen in dilute homogeneous polymer solutions. The yellow line represents the Bingham plastic, and it behaves initially rather like a solid, when initial stress is applied, Bingham plastic does not immediately flow unless the stress becomes higher than the minimum yield stress, 𝜏𝑜, then Bingham plastic flows as a Newtonian fluid as shown in Figure 2.2 (SORBIE, 1991).
Figure 2.2. Different types of shear stress vs shear rate
A large number of models to represent the pseudoplastic behavior has been developed. The most widely used form of the constitutive relation for non-Newtonian fluids is the power law model (BIRD et al., 1960; MACOSKO, 1994). The power law model (Equation 7) describes the pseudoplastic behavior in the shear thinning region in Figure 2.3 (blue dotted
line). This model is called as power law or Ostwald and de Waele model. In Equation 7, the 𝜂 is apparent viscosity and 𝛼 and 𝑛 arethe consistency index and the behavior index, respectively. In the pseudoplastic region, 𝑛 ≤ 1 (typically 0.4 ≤ 𝑛 ≤ 0.7). For a Newtonian fluid 𝑛 = 1.
𝜂 = 𝛼𝛾̇𝑛−1 (7)
Although the power law model is quite satisfactory for describing the pseudoplastic region, it is unsuitable at high and low shear rates. CARREAU (1972) defined a more adequate model for these shear regimes called as Carreau Model (orange line in Figure 2.3). In Equation 8 this model is presented, where 𝜂∞ is the viscosity at infinite shear rate, 𝜂𝑜 is viscosity at zero shear rate, 𝛽 is a time constant and 𝑛 is the same index in power law model.
𝜂 = 𝜂∞+ (𝜂𝑜− 𝜂∞) [1 + (𝛽𝛾̇)2] (𝑛−1)/2 (8)
Although there are currently more models to predict the rheological behavior of a non-Newtonian fluid, the Carreau model is considered one of the most used to adjust the behavior of polymer solutions such as xanthan and polyacrylamide solutions (SORBIE, 1991). The 𝜂𝑜 value is referred to the low-shear Newtonian plateau value of the viscosity, and the 𝜂∞ as the high-shear Newtonian plateau in viscosity for the pseudoplastic fluids in Figure 2.3.
In Figure 2.3, three zones are differentiated depending on the shear rate level. A Newtonian behavior is shown at low flow rates (first plateau zone), then followed by a region of shear thinning where the fluid viscosity decreases as the shear rate increases. At very high shear rates, the viscosity behavior achieves a second plateau value.
2.2. Polymers in EOR Applications
A polymer is a large molecule that is composed of identical units, called monomers. The polymers may have molecular weights of several million or may merely consist of a few repeating units. Two types of polymers are used in EOR applications, the synthetic polymers, such as polyacrylamide in its partially hydrolyzed form (HPAM) and the biopolymers, such as xanthan (SORBIE, 1991; SHENG, 2010).
2.2.1. Hydrolyzed Polyacrylamide (HPAM)
This polyacrylamide has been used in oil recovery processes far more frequently than xanthan biopolymer; one of the reason is HPAM solutions exhibit significantly greater viscoelasticity than xanthan solutions (WANG et al., 2006a). HPAM is a synthetic straight-chain polymer of acrylamide monomers, some of which have been hydrolyzed (Figure 2.4) and it may usually have an average molecular weight ranging 2-10 millions of Daltons. The HPAM performance depends on its molecular weight and degree of hydrolysis.
The degree of hydrolysis may be relevant for some physical properties such as polymer adsorption, shear stability, and thermal stability. However, even though commercial polymers are supplied with a stated degree of hydrolysis, it is well-known that at elevated temperatures the hydrolysis of the amide will be present (SORBIE, 1991). Polyacrylamide adsorbs strongly on mineral surfaces. Thus, the polymer is partially hydrolyzed to reduce adsorption by reacting polyacrylamide with a base, such as sodium or potassium hydroxide or sodium carbonate. Hydrolysis converts some of the amide groups (COONH2) to carboxyl groups (COO-), as shown in Figure 2.4. The degree of hydrolysis is the fraction of amide groups that were converted by hydrolysis. It ranges from 15% to 35% in commercial polymers (GREEN AND WILLHITE, 1998).
Hydrolysis introduces negative charges on the backbones of polymer chains that have a significant effect on the rheological properties of the polymer solution. At low salinities, the negative charges repel each other and cause the polymer chains to stretch. When an electrolyte, such as NaCl, is added to a polymer solution, the repulsive forces are shielded by a double layer of electrolytes; thus, the stretch is reduced (SHENG, 2010). For this reason, HPAM is considered a polyelectrolyte, and as such, it will interact quite actively with ions in solution. However, the polyacrylamide chain is flexible, and it may respond much more to the ionic strength of the aqueous solvent, and its solution properties are much more sensitive to salt/hardness than are those of xanthan (SORBIE, 1991). In freshwater (without the presence of ions), because of the charge repulsion of the carboxylic group, the HPAM flexible chain structure is stretched and the viscosity is high. In contrast, in saline water, the charge is neutralized or shielded, HPAM flexible chains are compressed, resulting in low viscosity (SHENG, 2010).
When the hydrolysis is higher, more COO- (carboxylate groups) are present, the adsorption is reduced, and the viscosity is higher, but chemical stability is reduced due to the less CONH2 content (amide). Low hydrolysis and more amide content rise chemical stability, but adsorption is increased (SHENG, 2010). When hydrolysis is above 40%, the flexible chains are severely compressed and distorted, and the viscosity is reduced. In hard water (with high contents of Ca2+ and Mg2+), when hydrolysis is above 40%, flocculation may occur (SHENG, 2010).
Generally, hydrolysis of polyacrylamide is fast under acidic and basic conditions. Also, when the temperature is high, the hydrolysis is fast even under neutral conditions. In other words, HPAM is not tolerant to high temperature or high salinity (WANG et al., 2003a; SHENG, 2010). In polymer flooding applications, hydrolysis process must be less than 40%, because of its long-term duration (SHENG, 2010).
2.2.2. Xanthan Gum
The most widely used polysaccharide is the xanthan gum, which is a commercial biopolymer. The structure of a xanthan biopolymer is shown in Figure 2.5. The polymer acts as a semi-rigid rod and is quite resistant to mechanical degradation. Average reported molecular weights of xanthan biopolymer used in EOR processes range from 1 million to 15 million (GREEN AND WILLHITE, 1998; SHENG, 2010). Usually, the polyacrylamide is much more viscous than polysaccharide biopolymer at equivalent concentrations in fresh water, but these copolymers are much more sensitive to saline water than the biopolymers. The viscosity of the synthetic polymer as HPAM is lower than biopolymers viscosity in the saline water (10,000 ppm TDS). Some permanent viscosity loss by shear effects can occur for polyacrylamide, but not for polysaccharide at the wellbore vicinity. However, the residual resistance factor (permeability reduction factor) caused by the polysaccharide polymers is lower than that produced by synthetic polymers (LUO et al., 2006; SHENG, 2010).
2.3. Polymer Stability
When polymers are used in oil recovery operations, it is crucial that the polymer properties are not rapidly degraded. Polymer degradation refers to any process that breaks down the molecular structure of macromolecules. The main feature of interest is the polymer solution viscosity although, for some polymers, the ability of the polymer to reduce the permeability of the reservoir formation may also be of some importance (SORBIE, 1991). This polymer degradation can be caused by chemical, mechanical and biological factors.
2.3.1. Chemical Degradation
This type of degradation refers to the breakdown of the polymer molecules, either through a short-term attack by contaminants, such as oxygen or through a longer-term attack of the molecular backbone by processes such as hydrolysis (SORBIE, 1991). That longer-term attack is caused by the intrinsic instability of molecules even in the absence of oxygen or other attacking species. In other words, polymer chemical stability is mainly controlled by oxidation-reduction reactions and hydrolysis (SHENG, 2010).
Effect of the Presence of Oxygen: The presence of oxygen leads to oxidative
degradation of the polyacrylamide polymer. However, at a low temperature, the effect of dissolved oxygen on HPAM solution viscosity is not significant, and the polymer solution can be stable for a long time. At higher temperatures, even if a small amount of oxygen exists, HPAM solution viscosity quickly decreases with time. LUO et al. (2006) run experimental tests and demonstrated that the half-lives for a polymer at 50°C, 70°C, and 90°C were 117, 20, and 2.6 hours, respectively. They concluded that as the oxygen concentration increased, the viscosity decreased faster. YANG AND TREIBER (1985) studied the chemical stability of polyacrylamide solution and identified the main variables affecting the polymer solution in the field, such as oxygen, temperature, oxygen scavengers, metal/metal ions, hydrogen sulfide, pH, salinity/hardness, chemical additives, and biocide. Their main finding was that the rate and extent of polymer degradation were governed mainly by the oxygen content of the solution and temperature.
Effect of Iron Ions: LUO et al., (2006) also performed experimental tests where
they investigated the impact of the ferric ion (Fe3+) on an HPAM solution viscosity at room temperature. When the ion Fe+3 concentration was low, the viscosity loss was not significant in
a short-term process and the viscosity loss was caused by the salinity effect. When the Fe3+ concentration was high, a brown precipitate, Fe(OH)3, was observed. Then, once the amount of the precipitate was small, the viscosity loss was not significant.
Effect of Temperature on Hydrolysis: Experimental tests performed by RYLES
(1983) proved the effect of temperature in HPAM solution in the absence of oxygen; the backbone chain of vinyl is quite thermally stable to temperatures as high as 120°C. He also showed that the dissolved salts had just a minor effect on the hydrolysis rate and the temperature was the primary determining factor. Finally, Ryles concluded the following:
The higher the temperature, the faster the rate of hydrolysis. The higher the temperature, the higher the degree of hydrolysis. The temperature level affected the hydrolysis significantly.
The divalent ions concentration strongly affected viscosity reduction. The highest viscosity retention occurred at 40 to 50% hydrolysis.
Effect of Divalent Ions on Hydrolysis: HPAM solution viscosity increases as
hydrolysis proceeds (increases) in a brine with a low monovalent content. However, in the presence of divalent, the viscosity behavior will be strongly determined by the divalent metal ion concentrations. As hydrolysis increases, more acrylate exists in the solution. Hydrolyzed polyacrylamides (negative carboxyl groups) strongly interact with divalent metal cations such as Ca2+ and Mg2+. This phenomenon is commonly associated with a reduction in solution viscosity, formation of gels or precipitates (SHENG, 2010).
2.3.2. Mechanical Degradation
This type of degradation describes the breakdown of molecules by the effect of high flow rate regions close to a wellbore because of high mechanical stresses on the polymer solution. This short-term effect is important only in the reservoir zone, which is near the wellbore and in some of the polymer handling equipment, such as chokes where drastic changes in fluid velocity exists due to changes in diameter. SERIGHT et al., (1983) studied the behavior of viscosity versus shear rate curves of a given polyacrylamide solution before and after different levels of shearing through a consolidated sandstone core. Even after modest levels of shearing (10.8 m/d), the HPAM solution viscosity was considerably reduced; after shearing at a very high flow rate (826 m/d) through the sandstone core, the polymer solution viscosity was
similar of the brine viscosity. Mechanical degradation is much more severe at higher flow rates, longer flow distances, and lower absolute permeability. Low permeable porous media, usually have small average pore throat diameter, and then the stress acting on the polymer is more significant. Thus, in these cases, it is more probable for the polymer chains to be broken and the viscosity be reduced. The effects of flow rate and flow distance are similar (SHENG, 2010).
2.3.3. Biological Degradation
This type of degradation refers to the microbial breakdown of macromolecules of polymers by bacteria during storage or into the reservoir. Although the problem is more prevalent for biopolymers, a biological attack may also occur for synthetic polymers. Biological degradation of the polymer may take place either on the surface before injection or within the reservoir if its temperature is sufficiently low. Obviously, aerobic bacteria could be responsible for degradation process at the surface, whereas, within the formation, anaerobic species could attack the polymer (SORBIE, 1991). HPAM could provide nutrition to sulfate-reducing bacteria (SRB). As the number of SRB increases, polymer viscosity decreases. Biological degradation is important only at low temperatures or in the absence of effective biocides. Probably, the most common biocide used in oilfield applications in the past was formaldehyde (HCHO) diluted in aqueous solution in a concentration between 500 and 5000 ppm, but their application also causes a polymer degradation (SHENG, 2010).
2.4. Polymer Retention in Porous Media
When a polymer flows through a porous media, there is a measurable amount of polymer retained. Retention is caused primarily by adsorption on the surface of the rock and mechanical entrapment in the pores that are relatively smaller than the size of the polymer molecule in solution (GOGARTY, 1967; WILLHITE AND DOMINGUEZ, 1977; GREEN AND WILLHITE, 1998). The significance of the mechanical entrapment depends on the pore size distribution. It is a more likely mechanism for polymer retention in low-permeability formation (Szabo, 1975; WILLHITE AND DOMINGUEZ, 1977). In most cases, the retention of polymers used in EOR applications is considered instantaneous and irreversible. However, at this point, polymer molecules could be removed from the porous media by injecting prolonged water volumes. Usually, though, the release rate of those molecules is too low making difficult measuring the concentrations of the released polymer accurately (GREEN AND WILLHITE, 1998). Also, this polymer retention on the porous media may also cause some reduction of the rock permeability, which can contribute negatively to the oil recovery
mechanism. However, overall, the polymer retention tends to reduce oil recovery despite the permeability reduction contribution. In fact, the level of polymer retention is one of the key factors in determining the economic viability of a polymer flood. Thus, it is of great importance to establish the correct retention levels for a given proposed field polymer flood (SORBIE, 1991).
2.4.1. Polymer Retention Units
Independent on the polymer retention mechanisms, determining how much polymer could be retained in a process is the primary objective. Laboratory measurements of polymer retention (Г) are expressed as mass of polymer per mass of solids, usually in micrograms of polymer per grams of dry rock (μg/g). In bulk static adsorption, a more fundamental measure of adsorption is expressed as mass of polymer per solid surface area, which is referred as the surface excess (Гs), usually in milligrams or micrograms per square meter (mg/m2 or μg/m2). Sometimes, in field applications, the retention unit is mass of polymer per volume of the rock, usually in lb/acre-foot) (SHENG, 2010). The conversion from micrograms per gram to pounds per acre-foot is done as explains in Equation 9.
𝛤 [ 𝑙𝑏𝑚
𝑎𝑐𝑟𝑒 ∗ 𝑓𝑡] = 2.717 ∗ (1 − 𝜙) ∗ 𝜌𝑔𝑟𝑎𝑖𝑛 ∗ 𝛤 [
µ𝑔 𝑝𝑜𝑙𝑦𝑚𝑒𝑟
𝑔 ] (9)
Where 𝛤 is polymer retention is each unit system, 𝜙 is effective porosity, 𝜌𝑔𝑟𝑎𝑖𝑛 is the grain density of the rock in grams per cubic centimeter. For quartz, 𝜌𝑔𝑟𝑎𝑖𝑛 is 2.65 g/cm3 . The conversion from pounds per acre-foot to kilograms per cubic meter is given by the conversion factor of 3.67*10-4.
2.4.2. Polymer Retention Mechanisms in Porous Media
There are three retention mechanisms, which act when polymer solutions flow through porous media: polymer adsorption, mechanical entrapment, and hydrodynamic retention. WILLHITE AND DOMINGUEZ (1977) illustrated these three mechanisms schematically (see Figure 2.6). The adsorption is caused because of the nature of the polymer-rock surface system and cannot be avoided. Therefore, adsorption is the most important mechanism, and there will always be present in polymer retention. Mechanical entrapment is a filtration-like mechanism in which the larger polymer is retained by smaller pores, blocking those pores. Otherwise, this is not a mechanism that persists throughout a reservoir formation.
Hydrodynamic retention is generally low and can be neglected in most practical applications (SORBIE, 1991). Nevertheless, because of the difficulty to distinguish among these three mechanisms in dynamic flood tests, many authors only use the term retention to describe the polymer loss, sometimes using just the term adsorption (SHENG, 2010).
Figure 2.6. Schematic of polymer retention mechanisms in porous media. (Adapted from Willhite and
Dominguez, 1977)
Polymer Adsorption Mechanism: The adsorption phenomenon is referred to the
interaction between the polymer molecules and the solid surface. This interaction causes polymer molecules to be bound to the surface of the solid mainly by physical adsorption (van der Waal’s and hydrogen bonding) rather than by chemical adsorption, in which chemical bonds are formed between the molecule and the surface. Essentially, the polymer occupies surface adsorption sites. Adsorption depends on the surface area exposed to the polymer solution, and it is the only mechanism that removes polymer from the bulk solution if a free solid powder, such as silica sand or latex beads, is introduced into the bulk solution and stirred until equilibrium is reached (SORBIE 1991; SHENG, 2010). Polymer adsorption is considered irreversible; that is, it does not decrease as polymer concentration decreases (SZABO, 1979).
Mechanical Entrapment Mechanism: Mechanical entrapment is a mechanism of
polymer retention more likely for lower permeability materials where the pore sizes are smaller (SZABO, 1975; WILLHITE AND DOMINGUEZ, 1977). Additionally, this type of retention mechanism appears to increase in residual oil condition when compared with the fully
water-saturated situation (SZABO, 1975). Mechanical entrapment can be avoided by polymer prefiltering or by applying the polymer in a high permeable formation (SHENG, 2010).
Hydrodynamic Retention Mechanism: In Figure 2.6, some of the polymer
molecules are trapped temporarily in stagnant flow regions by hydrodynamic drag forces. In such zones it could be possible for the local polymer concentration to exceed that of the injected fluid. When the flow stops, these molecules may diffuse out into the main flow channels and, when these fluids are produced, they cause a peak in polymer concentration (SORBIE, 1991). This mechanism is a rate-dependent effect which is not a very large contributor to the overall levels of polymer retention in porous media. Hydrodynamic retention appears to be reversible because the amount of polymer retained after an increase in flow rate is about the same as the amount of polymer recovered when the flow rate is reduced. (SORBIE, 1991)
2.4.3. Influential Factors in the Retention of Polymers
Polymer adsorption/retention depends on the polymer type, solvent (salinity), rock surface, polymer molecular weight and the initial permeability of the rock (SHENG, 2010). Also, we may include the polymer concentration in solution.
Figure 2.7. Cumulative distribution of HPAM and biopolymers adsorption. (Adapted from Sheng, 2010)
Polymer Type Effect on Retention: SHENG (2010) compiled the experimental
works on adsorption of the two types of polymers used in EOR processes: synthetic polymers and biopolymers. Figure 2.7 presents the results according to Sheng’s literature review. The
median HPAM adsorption (at 50% cumulative distribution of the compiled works) was 24 μg/g, while at 70% of the cumulative distribution, the adsorption data are below 30 μg/g. The median adsorption for biopolymers is 35 μg/g. Note that synthetic polymer adsorption is lower than biopolymer adsorption for the data analyzed. These median data may be used as a reference in cases without experimental data for a particular project.
Salinity Effect on Polymer Retention and Residual Resistance Factor:
MARTIN et al., (1983) analyzed salinity effect on different commercial polymers (Synthetic polymers and biopolymers).
Figure 2.8. Salinity Effect on Polymer Adsorption. (Adapted from Martin et al., 1983)
Sweepaid 103, Hi Vis, Cyanatrol 960S, Pusher 500, Pusher 700, Pusher 1000, Nalco Nal-flo were HPAM polymers, and Xanthan Broth, Kelco Xanflood, Flocon yolpolymer 1035 and Colloid XHO were polysaccharides. They prepared two polymer solutions with 0,1% and 2% total dissolved solids (TDS). Figure 2.8 shows the results of the retention tests, where the retention at 2% TDS is higher than that at 0.1% TDS for each pair of data. However, Figure 2.9 demonstrates that there is no direct relationship between polymer retention and residual resistance factor. At 2% of salinity, a lower residual resistance factor was obtained than at 0.1% of salinity. These results prove that for HPAM and biopolymer as the salinity of the polymer solution increases, the retention of polymer in the porous media also increases. On the other hand, the salinity effect on the residual resistance factor is inversely proportional.
Molecular Weight Effect: Figure 2.10 presents the adsorption behavior for an
HPAM with 30% hydrolysis as a function of its molecular weight and its concentration. In this study was used a calcium-montmorillonite surface. The results proved that the polymer adsorption decreases with the decrease of the molecular weight. For the polymer tested, a plateau was reached after 500 ppm of polymer concentration, it indicates that probably occurs an equilibrium concentration phenomenon (YANG et al., 2002a).
Permeability Effect: Figure 2.11 shows the results of retention experiments
performed by VELA et al. (1976) in Berea sandstones. As discussed above, mechanical trapping has a stronger influence in low-permeability rocks than in highly permeable ones. Therefore, as the permeability decreases, the polymer retention increases.
Figure 2.11. Permeability Effect on Polymer Retention due to mechanical trapping (Adapted from Vela et al.,
1976).
Polymer Concentration Effect: Polymer retention in porous media may be
correlated by use of the Langmuir isotherm model, which is given by Equation 10.
𝛤 = 𝑎1𝑏1𝐶
(1 + 𝑏1𝐶) (10)
Where 𝛤 is polymer adsorption, 𝐶 is polymer concentration in solution, 𝑎1 , 𝑏1 are constants. The Langmuir model is an equilibrium relationship, and its application assumes the retention as an instantaneous process. The constants are determined by fitting the data. If the Langmuir retention model applies, the graph of 1/𝛤 vs 1/𝐶 on a linear scale is a straight line with slope 1/𝑎1𝑏1 and intercept 1/𝑎1.
In the Langmuir model, retention is reversible. Thus, when polymer retention is considered to be irreversible, the Langmuir model cannot be used when the polymer
concentration is decreasing. (GREEN AND WILLHITE, 1998). Figure 2.12 is a typical retention isotherm for high-molecular-weight polymers (DASON AND LANTZ, 1972).
Figure 2.12. Langmuir Isotherm Model for High Molecular Weight Polymers-HPAM. (Adapted of Dason and
Lantz, 1972)
Equation 10 shows that polymer adsorption is a strong function of polymer concentration. Figure 2.12 evidences that as the polymer concentration increases, polymer adsorption also increases. However, data from LÖTSCH (1988) demonstrate that a higher biopolymer concentration led to a higher adsorption almost linearly (Figure 2.13).
Besides, many authors use static bulk measurements to match Langmuir isotherm model (DAWSON AND LANTZ, 1972; SZABO, 1975; CARDOZO et al., 2007). A dynamic method to measure polymer adsorption involves flow effects that static measurements does not. Data from SZABO (1979) proved that adsorption of silica (measured in static bulk adsorption) is 55 μg/g, which is higher than that (3.3 μg/g) of the sand pack (dynamic flow test). This occurred because the surface area of the silica is higher than in the sand pack. Up to now, the polymer concentration effect on polymer retention is questionable (ZHANG AND SERIGHT, 2014).
2.4.4. Inaccessible Pore Volume
The fraction of the pore space not contacted by the polymer solution is called the Inaccessible Pore Volume (IPV). In an aqueous polymer solution, the polymer molecules will displace faster than the water because they flow only through the pores that are larger than their sizes (SHENG, 2010). Polymer retention conceals the IPV impact on polymer transport in porous media. IPV accelerates polymer propagation, whereas polymer retention retards it. (DASON AND LANTZ, 1972; GREEN AND WILLHITE, 1998; SHENG, 2010; ZHANG AND SERIGHT, 2014). Laboratory data indicates that inaccessible pore volume effect is usually higher than adsorption loss for polymers. The inaccessible pore volume in laboratory cores is typically 20% (TRUSHENSKI et al., 1974).
Figure 2.14 shows an experimental test performed by DASON AND LANTZ (1972). In this experiment a polymer solution containing 2% NaCl was displaced through a Berea core until no further polymer was retained. Then the polymer and NaCl composition of the injected fluid was reduced for a period to create a “pulse” change in NaCl and polymer concentrations. The concentration profiles are effluent profiles of polymer and NaCl. The midpoint of the change in salt concentration arrived at about 1 PV injected. Nevertheless, the polymer pulse arrived about 0.24 PV earlier than expect and thus did not contact all the PV in the core. About 24% of the pore volume was not accessible to the polymer.
Figure 2.14. Inaccessible Pore Volume. (Adapted from Dason and Lantz, 1972)
HUGHES et al. (1990) performed a displacement test (Figure 2.15), where a constant polymer concentration was injected into the core, which has not been contacted previously by the polymer. Retention causes the effluent concentration to lag behind the tracer, as shown in the first flood in the Figure 2.15. In the second injection, the adsorption is occupied partly or fully by the previously injected polymer in the first flood, and the inaccessible pore volume can offset the lag so that the polymer breakthrough is earlier than the tracer is.
GREEN AND WILLHITE (1998), collected the data corresponding to the inaccessible pore volume obtained in different types of porous media for both polyacrylamides and biopolymers.
Table 2.1. Inaccessible PV in different types of porous media (Adapted from Green and Willhite, 1998)
Polymer / Sample Concentration
(ppm) Inaccessible Pore Volume (%PV) Xanthan biopolymer / Reservoir Sample 500 31 500 29 500 25 325 20
HPAM polymer / Berea Sandstone Sample (k=227 mD) 51,5 24 106 28 201 26 502 21 760 19.5 1070 18.7
Table 2.1 presents a representative data on inaccessible PV for xanthan and polyacrylamide in porous media. The polyacrylamide data indicates a slight decrease in inaccessible pore volume with concentration. Several models try to explain why and how inaccessible PV occurs, but none has gained universal acceptance.
