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14 pages, 20709 KiB

Open AccessArticle

Study on Microscopic Pore Structure Classification for EOR of Low Permeability Conglomerate Reservoirs in Mahu Sag

by Yong Wang, Xubin Zhao, Chuanyi Tang, Xuyang Zhang, Chunmiao Ma, Xingyu Yi, Fengqi Tan, Dandan Zhao, Jie Li and Yuqian Jing

Energies 2023, 16(2), 626; https://doi.org/10.3390/en16020626 - 4 Jan 2023

Cited by 6 | Viewed by 1201

Abstract

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil [...] Read more.

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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23 pages, 6747 KiB

Open AccessArticle

A Comprehensive Simulation Study of Physicochemical and Geochemical Interactions on Immiscible CO₂-LSWAG Injection in Carbonates

by Ladislane dos Santos Bastos, Igor Emanuel da Silva Lins, Gloria Meyberg Nunes Costa and Silvio Alexandre Beisl Vieira de Melo

Energies 2023, 16(1), 440; https://doi.org/10.3390/en16010440 - 30 Dec 2022

Viewed by 1273

Abstract

Low-salinity water-alternating-CO₂ (CO₂-LSWAG) injection has been widely studied and employed due to its capability to promote enhanced oil recovery (EOR). However, there is no consensus on the dominant mechanisms for oil recovery in carbonates due to the extreme complexity of [...] Read more.

Low-salinity water-alternating-CO₂ (CO₂-LSWAG) injection has been widely studied and employed due to its capability to promote enhanced oil recovery (EOR). However, there is no consensus on the dominant mechanisms for oil recovery in carbonates due to the extreme complexity of the oil–brine–rock interactions. This work proposes a comparative investigation of the physicochemical and geochemical effects of continuous CO₂ and CO₂-LSWAG immiscible injections on oil recovery in a carbonate core. Simulations were carried out using oil PVT properties and relative permeability experimental data from the literature. A comparison of SO₄²⁻ and Mg²⁺ as interpolant ions, oil, water and gas production, pressure, and rock and fluid properties along the core and in the effluent was made. The results show a high recovery factor for CO₂ (62%) and CO₂-LSWAG (85%), even in immiscible conditions. The mineral dissolution and porosity variations were more pronounced for CO₂-LSWAG than CO₂. The simulation results showed that Mg²⁺ as an interpolant improves oil recovery more than SO₄²⁻ because Mg²⁺ concentration in the aqueous phase after LSW injection leads to relative permeability values, which are more favorable. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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13 pages, 4098 KiB

Open AccessArticle

Experimental Evaluation of Shale Oil Development Effectiveness by Air Injection

by Chao Chen, Xiang Tang, Ming Qin, Rui Zhou, Zhenhua Ding, Guihui Lian, Huan Qi, Xin Chen, Zheyu Liu and Yiqiang Li

Energies 2022, 15(24), 9513; https://doi.org/10.3390/en15249513 - 15 Dec 2022

Cited by 2 | Viewed by 1266

Abstract

In recent years, as an important part of unconventional resources, the effective development of shale oil has been a key area of research in petroleum engineering. Given the widespread availability and low cost of air, the evaluation of air injection in shale reservoirs [...] Read more.

In recent years, as an important part of unconventional resources, the effective development of shale oil has been a key area of research in petroleum engineering. Given the widespread availability and low cost of air, the evaluation of air injection in shale reservoirs is a topic worth exploring. This paper analyzes the production performance of different methods of air injection development in the shale reservoir, including air flooding and air huff and puff (HnP), based on full-diameter core air injection experiments. Meanwhile, the characteristics of the residual oil and produced oil are revealed by forming a systematic evaluation method that includes nuclear magnetic resonance (NMR), laser scanning confocal microscopy (LSCM), and gas chromatographic (GC) analysis. The results show that air flooding development is characterized by early gas breakthrough, long oil production period, and “L” shape oil production decline; while air HnP is characterized by first producing gas and then producing oil, rapid oil production, and high oil recovery efficiency in the first round. Compared with air flooding, the replacement efficiency of the first round of air HnP is significantly higher, demonstrating higher feasibility of air HnP in the early stages of development, although the cumulative recovery of three rounds air HnP (17.17%) is lower than that of air flooding (23.36%). The large pores (T₂ > 10 ms) are the main source of air injection recovery, while the residual oil is mainly concentrated in the medium pores (1–10 ms). Air injection development has a higher recovery factor for light components (

C_{15^{-}}

), resulting in a higher level of heavy components in the residual oil. This paper discusses the feasibility and development effectiveness of air injection in shale oil reservoirs, and its development characteristics are further clarified. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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8 pages, 1626 KiB

Open AccessArticle

Study on the Effect of Acid Corrosion on Proppant Properties

by Feng Xu, Kuai Yao, Desheng Li, Dongjin Xu and Huan Yang

Energies 2022, 15(22), 8368; https://doi.org/10.3390/en15228368 - 9 Nov 2022

Cited by 1 | Viewed by 963

Abstract

Pre-acid fracturing is an effective technique to improve productivity of tight reservoirs. While acid injection can clean the formation and improve the fracturing performance by reducing the fracture pressure of the reservoir, the chemical reaction of the acid solution with proppant may reduce [...] Read more.

Pre-acid fracturing is an effective technique to improve productivity of tight reservoirs. While acid injection can clean the formation and improve the fracturing performance by reducing the fracture pressure of the reservoir, the chemical reaction of the acid solution with proppant may reduce the compressive strength of the proppant and therefore negatively affect the fracture conductivity. In this study, we experimentally investigated the solubility of the proppant in acid and the effect of acid corrosion on proppant compressive strength and fracture conductivity. The results show that the concentration of the acid solution has the greatest effect on solubility of the proppant, which is followed by the contact reaction time. Though a proppant of larger particle size indicates a lower solubility, the acid corrosion poses a greater damage to its compressive strength and conductivity. The quartz sand proppant exhibits superior stability to ceramic proppant when they are subjected to acid corrosion. The experimental results could serve as reference for selection of proppant and optimization of acid concentration and duration of acid treatment during pre-acid fracturing. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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20 pages, 12146 KiB

Open AccessArticle

Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin

by Feng-Qi Tan, Chun-Miao Ma, Xu-Yang Zhang, Ji-Gang Zhang, Long Tan, Dan-Dan Zhao, Xian-Kun Li and Yu-Qian Jing

Energies 2022, 15(19), 7359; https://doi.org/10.3390/en15197359 - 7 Oct 2022

Cited by 4 | Viewed by 1502

Abstract

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat [...] Read more.

The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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17 pages, 6014 KiB

Open AccessFeature PaperArticle

Investigation of the Flow Intensity in an Inverted Seven-Point Well Pattern and Its Influence on the EOR Efficiency of S/P Flooding

by Tingli Que, Xin Chen, Dan Guan, Qingqing Yun, Huoxin Luan, Xuechen Tang, Jinxin Cao, Zheyu Liu and Xiaobin Nie

Energies 2022, 15(18), 6632; https://doi.org/10.3390/en15186632 - 10 Sep 2022

Viewed by 1375

Abstract

Polymer and surfactant (S/P) binary flooding is a widely used chemical flooding technology for enhanced oil recovery (EOR). However, it is mostly used in the five-spot well pattern, and there is little research on the effect of well patterns on its flow law [...] Read more.

Polymer and surfactant (S/P) binary flooding is a widely used chemical flooding technology for enhanced oil recovery (EOR). However, it is mostly used in the five-spot well pattern, and there is little research on the effect of well patterns on its flow law and EOR efficiency in the reservoir. In this paper, the flow intensity of S/P flooding in an inverted seven-spot well unit and its EOR efficiency are investigated. Based on the theoretical derivation and simulation, the flow distribution at different positions in the inverted seven-spot well pattern unit was calculated. The oil displacement efficiency was evaluated by simulating different flow intensities with various flow velocity. The microscopic residual oil of the core at the end of displacement was scanned and recognized. The 2D model was used to simulate the well pattern to clarify the EOR of S/P flooding. The results show that the swept area in the well unit can be divided into the strong swept region (>0.2 MPa); medium swept region (0.1–0.2 MPa); weak swept region (0.03–0.1 MPa); and invalid swept region (<0.03 MPa), according to the pressure gradient distribution. Compared to the five-spot well pattern, the inverted seven-spot well pattern featured a weak swept intensity, but a large swept area and lower water cut rise rate. Increasing the flow intensity can improve oil displacement efficiency, and disperse and displace continuous cluster remaining oil. The 2D model experiments show that the incremental oil recoveries by SP flooding after water flooding in the five-spot well pattern and inverted seven-spot well pattern are 25.73% and 17.05%, respectively. However, the ultimate oil recoveries of two well patterns are similar by considering the previous water flooding. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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12 pages, 2216 KiB

Open AccessArticle

Displacement Characteristics and Produced Oil Properties in Steam Flood Heavy Oil Process

by Xingchao Yang, Hongyan Zhao, Bo Zhang, Qinghui Zhao, Yulin Cheng, Yong Zhang and Yiqiang Li

Energies 2022, 15(17), 6246; https://doi.org/10.3390/en15176246 - 27 Aug 2022

Cited by 3 | Viewed by 1459

Abstract

Thermal recovery is one of the most effective techniques for viscous oil production, which has been widely used in the heavy oilfield development. The mechanisms and percolation characteristics of thermal recovery have attracted a lot of attention. However, the displacement characteristics and produced [...] Read more.

Thermal recovery is one of the most effective techniques for viscous oil production, which has been widely used in the heavy oilfield development. The mechanisms and percolation characteristics of thermal recovery have attracted a lot of attention. However, the displacement characteristics and produced oil properties in the steam flood heavy oil process are rarely addressed. In this paper, steam flooding experiments with two heavy oil viscosities under the temperatures from 120 to 200 °C and velocities from 1 to 3 mL/min were carried out to examine the oil displacement efficiency and the produced oil properties. The results show that the majority of the oil is produced in the low water cut stage. Temperature increment is helpful for prolonging the water breakthrough time. The high injection velocity of steam contributes to a high recovery factor, even if it enters into the high water cut stage. The rheology of the produced oils severely changes because the SARA composition changes, and emulsification occurs during the steam flooding heavy oil process. With the increasing steam temperature, the relative content of resins in the produced oils decreases, and asphaltenes increase. With the increase in the injection volume and the injection velocity of steam, the content of resins and asphaltenes increases. This leads to an increment in the produced oil viscosities. The effect of injection velocity on the rheology properties of the produced oils increases with temperature increment. The finding of this work will provide the technical support for heavy oilfields development. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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16 pages, 2152 KiB

Open AccessArticle

On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples

by Sami Yahyaoui, Rezki Akkal, Mohammed Khodja and Toudert Ahmed Zaid

Energies 2022, 15(15), 5687; https://doi.org/10.3390/en15155687 - 5 Aug 2022

Cited by 1 | Viewed by 1539

Abstract

The water–oil relative permeability behavior of different plugs from the Hassi Messaoud reservoir in south Algeria has been investigated to understand the fundamental processes of two-phase flow taking place within the macro-structure of rock samples. The experiments were conducted on cylindrical reservoir samples [...] Read more.

The water–oil relative permeability behavior of different plugs from the Hassi Messaoud reservoir in south Algeria has been investigated to understand the fundamental processes of two-phase flow taking place within the macro-structure of rock samples. The experiments were conducted on cylindrical reservoir samples (plugs) using the unsteady-state method to measure the oil–water relative permeabilities due to operational simplicity. The impact of factors such as wettability, overburden pressure and rock characteristics based on the relative permeability curves have been carefully assessed. During this test, temperature was kept in the range of 95 to 100 °C and pressure was maintained at 100 bar. Large variations in relative permeability curve trends have been experimentally observed for different rock samples under investigation, which can be explained by the heterogeneous nature of the studied reservoir. Results showed an intermediate alteration of wettability and for all studied samples, and the intersection point of the relative permeability values for oil and water is less than 50%, showing that these samples exhibit oil-wet behavior. Our results also show that displacement pressure increases from 0.13 to 2 psi, promoting a gradual displacement of oil relative permeability (Kro) toward higher saturations in water (45% to 60%). The results show that the oil recovery rate at breakthrough is approximately 16% to 28% of the initial oil in place (IOP), with an average of 23%. The final oil recovery rate, obtained by moving at constant pressure, ranges from 43% to 55% of the initial oil in place (IOP), with an average value of around 49%. The forced displacement at the end of the performed tests increased the average recovery rate by about 4%. These rates vary from 46% to 61% of the initial oil in place (IOP). The residual oil saturation (Sor) varies from 33.7% to 47.8% relative to pore volume (Vp); the average is about 42%. The residual oil saturation (Sor) is about 30% to 45% Vp after forced displacement at the end of the test, the average is about 38.5%, and the relative permeabilities Krw and Kro are equal to the water saturations of 33% to 50%; the average value is about 41%. Full article

(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)

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