Study on Compatibility between Complex Mode Micropore Structure and Polymer Solution of Different Formulation for Conglomerate Reservoir

Tan, Fengqi; Jing, Yuqian; Ma, Chunmiao; Liu, Zhenping; Chen, Yukun; Li, Xiankun; Jiang, Ruihai

doi:https://doi.org/10.1155/2023/6651621

Geofluids

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Abstract Introduction Conclusion Data Availability Conflicts of Interest Acknowledgments References Copyright Related Articles

Research Article | Open Access

Volume 2023 | Article ID 6651621 | https://doi.org/10.1155/2023/6651621

Study on Compatibility between Complex Mode Micropore Structure and Polymer Solution of Different Formulation for Conglomerate Reservoir

Fengqi Tan,^1,2Yuqian Jing ,^1,2Chunmiao Ma ,^1,2Zhenping Liu,³Yukun Chen,³Xiankun Li,^1,2and Ruihai Jiang^1,2

Academic Editor: Zhaojie Song

Received21 Jan 2023

Revised07 Mar 2023

Accepted11 Mar 2023

Published23 Mar 2023

Abstract

In this paper, the conglomerate reservoir is selected as the object to investigate the micropore structure and the compatibility of polymer solutions. Firstly, the characteristics of complex mode pore structure are analyzed based on casting thin sections, scanning electron microscope, and capillary pressure curve. Then the conglomerate reservoir is divided into five types by use of the K-means clustering algorithm, and the differences in micropore structure among the different reservoir types are also clarified. Secondly, the dynamic light scattering technology is used to directly determine the hydrodynamic diameter of different polymer formulations. As the polymer molecular weight increases, the average hydrodynamic diameter becomes larger, and with the same polymer molecular weight, the average hydrodynamic diameter becomes gradually larger as the solution concentration increases. Based on the above research results, the matching relationship between five reservoir types and polymer solutions is determined through laboratory experiments. The experimental results show that when the polymer molecular weight is determined, the volume of pore volume that can be effectively swept by polymer hydration molecules gradually decreases as the concentration of the solution increases. When the polymer molecular weight and its concentration are both determined, the pore volume of effective displacement of polymer-hydrated molecules also gradually reduces with becoming worse reservoir pore structure. The scope of application of different polymer formulations becomes progressively smaller as the microscopic pore structure of type I to type V reservoirs becomes deteriorated. The compatibility between the micropore structure of different conglomerate reservoir types and polymer solution is determined to provide the geological basis for the reasonable formulation of the polymer flooding scheme.

1. Introduction

The conglomerate reservoir is a special type of reservoir, due to its nearby source, multiwater system, rapidly changing depositional environment, and complex sedimentary diagenesis, resulting in strong anisotropy and complex modal micropore structure characteristics of the reservoir [1–3]. The lithology controls the physical property and oil-bearing properties of the reservoir. For conglomerate reservoirs, the content of sand and shale is relatively high, the gravel is suspended in the sand and mud, the pore throat distribution is extremely uneven, the average throat radius is small, the pore throat ratio is large, the pore throat coordination number is low, and the overall characteristics are multipeak biased fine state. The complex pore structure has a relatively large impact on oil recovery under different displacement methods [4–6]. At present, the conglomerate reservoir has been developed through a long period of waterflooding, with a limited swept volume of injected water, increasing water content, and rapidly decreasing oil production. Therefore, the tertiary oil recovery technology with polymer flooding as the pilot test becomes an inevitable trend to improve the complex mode conglomerate reservoir [7–9]. As we all know, compared to water injection and flooding, tertiary oil recovery mainly uses chemicals to improve the adsorption performance and interaction between oil, gas, water, and rock to maximize the recovery of oil reservoirs [10]. As one of the most important forms of displacement in tertiary oil recovery technology, it is characterized by the addition of high molecular weight polyacrylamide polymer to water, which increases the solution viscosity, reduces the permeability of the aqueous phase, improves the mobility ratio between the displacement phase and the displaced phase, expands the swept volume, and thus increases the displacement efficiency [11–13].

At present, most of the researches focus on polymer or reservoir micropore structure, but seldom on the matching relationship between them [14, 15]. In addition to its molecular weight and concentration, the oil displacement efficiency of polymers is also influenced by clay minerals and micropore structure [16, 17]. As polymers are polymer compounds, when the water-soluble polymer hydration molecules flow through the porous media will inevitably go through the micropore size selection. The higher the molecular weight of the polymer the better the viscosity building, and the ability to reduce the permeability of the water phase permeability is also stronger, but the higher the molecular weight the easier mechanical degradation [18]. In the process of polymer flooding, if the molecular weight is too high, the pore throat will be blocked, causing reservoir damage. If the molecular weight is too low, the viscosity will become worse, which is bound to increase the amount of polymer and affect the oil displacement effect [19–21]. Therefore, the prerequisite for polymer flooding is to determine the matching relationship between polymer molecular weight and micropore structure [22] and select the optimal injection molecular weight for reservoirs with different permeability levels to solve displacement problems in terms of technical feasibility and economic feasibility. For complex conglomerate reservoirs, due to the complex micropore structure, the study of the compatibility between polymer molecular weight and pore throat size needs to determine the relationship between micropore structure and hydrodynamic radius of polymer solution for different reservoir types on the basis of reservoir classification. And then use the “bridging adsorption” principle to calculate the minimum radius of pore throat blockage for different molecular weights and concentrations of polymer solution, and finally establish a matching map between them. The conglomerate reservoir selected for the manuscript is located in the Mahu oilfield in the Junggar Basin of northwest China. The manuscript makes use of a variety of information and data to classify conglomerate reservoirs and establish corresponding standards, and the results of the research are applicable to reservoirs with similar lithology and physical properties to those in the study area. For conglomerate reservoirs with complex pore structures, weak permeability, and limited polymer flooding sweep ability, the next step will be to explore the adjustment of the polymer flooding formula or injection method and further provide the basic geological basis for the rational and efficient development of polymer flooding in conglomerate reservoirs.

2. Classification of Reservoir Types

Due to the serious heterogeneity of conglomerate reservoirs, complex pore structure, and nonreticulation characteristics of the seepage system, a reasonable classification of reservoir types is necessary to establish the matching relationship between micropore structure and polymer parameters. For the micropore structure characteristics of different reservoir types, the optimal polymer molecular weight, and concentration are selected to achieve the goal of improving the overall recovery of the reservoir. The micropore structure characteristics refer to the geometry, size, distribution, and interconnection of pores and throats of rocks [23]. The classification of reservoir types in conglomerate reservoirs is based on a comprehensive analysis of the differences in pore structure based on core photos, casting thin sections, scanning electron microscopy, capillary pressure curves, and other data, and then extract parameters that can quantitatively characterize the pore throat to reasonably classify the reservoir types. As can be seen from Table 1, different depositional environments and hydrodynamic conditions lead to relatively large differences in the degree of sorting and rounding of sedimentary particles. The different relative contents and combination relationships of gravel, sand, and mud sediments form complex pore structures, which are then modified by later diagenesis, and the configuration relationships of pore throats reflect greater differences. These all indicate that the micropore structure of conglomerate reservoirs varies considerably between reservoir types, which in turn affects seepage capacity and displacement efficiency.

Based on the analysis of the variability of microscopic pore structure in conglomerate reservoirs, nine parameters were extracted based on the experimental data of 54 capillary pressure curves: porosity, permeability, mean value, skewness, median saturation radius, maximum pore throat radius, average capillary radius, apparent pore throat volume ratio, and unsaturated mercury volume percent. And then the division-based K-means clustering algorithm was selected to classify the conglomerate reservoirs into five types according to the principle of minimum distance within clusters and farthest distance between clusters [24] (Table 2). Among them, for type I reservoirs, the lithology is mainly coarse sandstone and medium coarse sandstone, with porosity greater than 22%, permeability greater than 300 mD, low interstitial fillings, weak heterogeneity, uniform pore distribution, large pore throat radius, very low drainage pressure, and the shape of capillary pressure curve is coarse skewness. For type II reservoirs, the lithology is mainly gravelly coarse sandstone and coarse sandstone, with porosity of more than 22%, a permeability of 100~300 mD, low interstitial fillings, mixed matrix dominated by mud and kaolinite, weak heterogeneity, large pore throat radius, low drainage pressure, and the shape of capillary pressure curve is medium skewness. For type III reservoirs, the lithology is mainly unequal sandstone containing coarse gravel, with porosity ranging from 19% to 22%, permeability ranging from 50 to 100 mD, medium interstitial fillings, mixed matrix dominated by kaolinite and mud, cement with a small amount of pyrite, medium pore throat radius, medium drainage pressure, and the shape of capillary pressure curve is fine skewness. For type IV reservoirs, the lithology is mainly glutenite and sandy conglomerate, with porosity is between 17% ~22%, permeability between 30~50 mD, low interstitial fillings, mixed matrix dominated by kaolinite and mud, and the cementation is occasionally pyrite, small pore throat radius, high drainage pressure, and the shape of the capillary pressure curve is not skewed. For type V reservoirs, the lithology is mainly conglomerate and calcareous conglomerate, with a porosity is less than 15%, a permeability of less than 30 mD, serious heterogeneity, uneven pore distribution, small pore throat radius, high drainage pressure, and a shape of the capillary pressure curve is not skewed. On the basis of reasonable classification of reservoir types, the optimal polymer flooding solution matching parameters can be established for different micropore structure characteristics.

3. Determination of the Hydrodynamic Size of Polymer Solutions

When the polymer solution flows through the conglomerate reservoir pore medium, the pore throat size will naturally select the polymer hydration molecules. If most of the polymer hydration molecules are blocked when passing through the pore throat, it will cause the polymer solution to collect and block in the micropores, reducing the reservoir percolation capacity and thus affecting the polymer oil displacement efficiency [25]. Generally, the relative relationship between the hydrodynamic diameter of polymer solution and the pore throat diameter is used to quantitatively characterize whether polymer molecules can pass through pores and throats of different sizes. The higher the molecular weight of the linear polymer, the longer the main chain, the larger the hydrodynamic radius in the solution, the larger the surface area in contact with the solution, and therefore the higher the viscosity [26, 27]. Therefore, based on the “bridging adsorption” principle of polymer molecular hydrodynamic diameter (D_h) and pore throat diameter (D), that is, a blockage is formed when , the minimum diameter of polymer plugging pore throat with different molecular weights can be calculated.

Using oilfield injection water to configure different polymer solutions, the hydrodynamic diameters of polymer molecules at different molecular weights and concentrations were directly determined using dynamic light scattering techniques. As can be seen from Table 3, four polymer molecular weights, such as , , , and , were chosen to configure solutions of different concentrations, and the average hydrodynamic size of polymer molecules and their distribution functions were obtained after measurement and conversion. Overall, the average hydrodynamic diameter becomes larger as the polymer molecular weight increases, while the average hydrodynamic diameter becomes progressively larger as the solution concentration increases for the same polymer molecular weight.

The hydrodynamic size distribution function of polymer molecules shows that the hydrodynamic diameter is not a unique value for a defined formulation of polymer solution, but rather exhibits different frequencies of distribution within a certain interval of variation. It has been shown that the molecular weight of the polymer is equal to the degree of polymerization multiplied by the molecular weight of the basic chain link. Polymeric compounds are homologous mixtures with different molecular weights. Generally, the molecular weight is the average molecular weight. As a result, the hydrodynamic diameters of the same solution will have different frequency distributions, and for the convenience of research and quantitative characterization, the hydrodynamic diameters are also averaged. For the 1500 × 10⁴ molecular weight polymer solution, the average hydrodynamic diameters vary considerably for different concentrations, with 1093 nm, 832 nm, 612 nm, and 548 nm for 0.2%, 0.15%, 0.12%, and 0.1% concentrations, respectively. As the concentration of the solution decreases, the average hydrodynamic diameter becomes smaller, and the effect of concentration on the reduction of the hydrodynamic diameter can reach about 50%, and other molecular-weight polymer solutions also show the same change rule (Table 4).

4. Matching Relationship between Polymer Flooding Formula and Pore Structure

4.1. Experimental Methods

The average hydrodynamic diameters of polymer solutions of different molecular weights and concentrations were determined by the dynamic light scattering method. According to the “bridging adsorption” principle of plugging the pore throat when polymer hydration molecules flow through the porous medium and in combination with the five classification results of conglomerate reservoirs, the matching relationship between the micropore structure of different reservoir types and the hydrodynamic diameter of polymer flooding formula can be established. This can guide the reasonable formulation of the chemical flooding scheme and improve the overall recovery of the reservoir. The experimental procedures are as follows: (1)Based on the results of the classification of conglomerate reservoirs, a typical capillary pressure curve is selected for each type of reservoir(2)The capillary pressure equation is , taking (D_h is the average hydrodynamic diameter of the polymer solution), the corresponding capillary pressure P can be obtained when the radius of the capillary is D_h/2(3)In the capillary pressure curve, a straight line parallel to the horizontal axis is made through (0, P) and (100, P). The intersection point of the straight line and the mercury curve is marked as (S, P), so S is the corresponding mercury saturation when the pore radius is D_h/2, that is, the pore volume whose pore radius is greater than or equal to D_h/2, that is, the volume that the polymer can sweep (Figure 1)(4)Based on physical modeling experiments, for conglomerate reservoirs, the polymer solution is considered to be well matched to the micropore of the reservoir when the volume of a polymer that can be swept is greater than or equal to 60%

4.2. Analysis of Experimental Results

Based on the designed experimental steps, a typical capillary pressure curve for five reservoir types in conglomerate reservoirs was selected. Different concentrations of polymer solutions were configured for the same molecular weight polymer, which in turn determined the swept volume of different polymer formulations for each reservoir type. The experimental results (Table 5) show that for different types of conglomerate reservoirs, the pore volume that can be effectively swept by polymer hydration molecules gradually decreases with increasing solution concentration provided that the polymer molecular weight is determined. And as the micropore structure of the reservoir becomes worse, that is, the reservoir changes from type I to type V, the degree of influence of the increase of polymer concentration on the change of swept volume also increases. For example, for polymer molecular weight, when the solution concentration increases from 0.10% to 0.20%, the reduction of sweep volume of the type I reservoir is 7.31%, the reduction of sweep volume of the type III reservoir is 8.83%, and the reduction of sweep volume of type V reservoir is 10.81%. In addition, when the polymer molecular weight and concentration are determined, as the reservoir pore structure becomes worse, the pore volume that can be effectively swept by polymer hydration molecules gradually decreases. For molecular weight, 0.15% concentration of polymer solution, when the reservoir changes from type I to type V, the swept volume is 67.2%, 61.2%, 56.3%, 48.1%, and 41.2%, respectively. For the same type of reservoir, the swept volume gradually decreases with the increase of polymer molecular weight and concentration, mainly due to the increase of polymer hydrodynamic diameter, which leads to the increase in the number of blocked throats and then affects the percolation capacity of the whole reservoir and reduces the displacement efficiency at the effective pore.

4.3. Compatibility Determination

When the swept volume of the polymer solution is greater than or equal to 60%, the polymer solution is considered to be well matched to the micropores of the reservoir, and a mating relationship between the two can be established. Based on the matching relationship chart between different reservoir types and different polymer formulations for conglomerate reservoirs, the optimal polymer flooding formulation for five types of micropore structures in conglomerate reservoirs is determined. It can be seen from Table 6 that for the type I conglomerate reservoir, there are 16 polymer solution formulations prepared with 4 molecular weights, and the swept volume of micropores is more than 60%, which indicates that the type I reservoir has uniform pore structure, weak heterogeneity, large average capillary radius, wide application scope, and strong selectivity for polymer solution formulation. Among them, a molecular weight, 0.2% concentration polymer solution can sweep 65.19% of the volume, while a molecular weight, 0.06% concentration polymer solution can sweep 78.01% of the volume. Although type I reservoir has wide applicability to polymer solutions with different formulations, the optimal polymer formulation still needs to comprehensively consider the influence factors of oil displacement efficiency and injection economy to determine the optimal injection scheme. For type II, III, and IV reservoirs, the scope of application of different polymer formulations becomes progressively smaller due to the deterioration of the pore structure. Type II reservoirs with molecular weight and 0.2% concentration of polymer solutions can sweep less than 60% of the volume and have poor compatibility. Type III reservoirs have four polymer formulations that can sweep less than 60% of the volume, while type IV reservoirs have 12, leaving only four formulations that can sweep more than 60% of the volume and have better compatibility. For type V reservoirs, the swept volume of all 16 polymer formulations is less than 60%, with the highest being 56.01%, indicating that type V reservoirs have complex pore structures, strong heterogeneity, small average capillary radius, weak percolation capacity, limited swept volume, and are not suitable for polymer flooding overall.

To sum up, the micropore structures of different reservoir types in conglomerate reservoirs are different, and the hydrodynamic diameters of polymer solutions with different molecular weights and concentrations are also different. Based on the “bridging adsorption” principle of polymer plugging pore throats and the effective swept volume of micropores, the compatibility relationship between different reservoir types and polymer flooding is established. Combining both displacement efficiency and injection economics, the most optimal injection formulations for different reservoir types in conglomerate reservoirs can be determined, providing a geological basis for the overall design of polymer flooding solutions.

Most of the previous research has focused on the mechanism of recovery enhancement by polymer drives and the development of new polymers. For example, Jiang et al. [28] viscosity variation law of polymer in porous media was studied, measured, and calculated the relative permeability curves of polymer flooding more accurately. Lu et al. [29] demonstrated the relationship between the concentration and viscosity of polymer displacement agents and the effectiveness of displacement and proposed a method to improve the effectiveness of polymer displacement. Bai et al. [30] analyzed the replacement mechanism of intercalated polymer and concluded that the oil-water dispersion properties of the intercalated polymer can soften the rigid oil-water interface and thus contributes to enhancing oil recovery compared to conventional polymers. In contrast to previous studies, we have matched reservoir micropore structure and polymer formulation rather than analyzing conglomerate reservoir characteristics or optimizing polymer formulation from a single perspective. This manuscript provides reasonable polymer formulations for different reservoir types, which can guide practical production and are significant for the efficient development of conglomerate reservoirs.

5. Conclusion

(1)Based on the complexity of the pore structure and the shape of the capillary pressure curve, conglomerate reservoirs can be divided into 5 types. From type I to type V reservoirs, the micropore structure deteriorates, the average capillary radius decreases, and the seepage capacity decreases(2)As the molecular weight of the polymer increases, the average hydrodynamic diameter becomes larger, while at the same molecular weight of the polymer, the average hydrodynamic diameter becomes progressively larger as the concentration of the solution increases(3)Under a defined polymer molecular weight, the volume of the pore that can be effectively swept by polymer hydration molecules decreases as the solution concentration increases, and as the reservoir micropore structure deteriorates, the degree of influence of increasing polymer concentration on the amount of swept volume change increases. When both the molecular weight and concentration of the polymer are determined, the effective swept volume of polymer hydration molecules gradually decreases as the pore structure becomes worse(4)When the swept volume of the polymer solution is greater than or equal to 60%, it is considered that the polymer solution matches well with the reservoir’s microscopic pores, and the applicability range of different polymer formulations for type I to type IV reservoirs gradually becomes smaller, thus establishing the compatibility relationship between different reservoir types and polymer flooding

Data Availability

The data presented in this study are available on request from the corresponding author. The data are not publicly available due to the need for further relevant research.

Conflicts of Interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Acknowledgments

This research was supported by the National Natural Science Foundation of China (No. 41902141), the Fundamental Research Funds for the Central Universities (No. E1E40403), and the PetroChina Innovation Foundation (No. 2018D-5007-0103).

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Copyright © 2023 Fengqi Tan et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

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