Multi-Phase Flow and Unconventional Oil/Gas Development

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18 pages, 8713 KiB

Open AccessArticle

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

by Jianhai Wang, Yibo Feng, Aiqing Cao, Jingyu Zhang and Danqi Chen

Processes 2024, 12(3), 447; https://doi.org/10.3390/pr12030447 - 22 Feb 2024

Viewed by 514

Abstract

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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16 pages, 13160 KiB

Open AccessArticle

Flowback Characteristics Analysis and Rational Strategy Optimization for Tight Oil Fractured Horizontal Well Pattern in Mahu Sag

by Hui Tian, Kai Liao, Jiakang Liu, Yuchen Chen, Jun Ma, Yipeng Wang and Mingrui Song

Processes 2023, 11(12), 3377; https://doi.org/10.3390/pr11123377 - 06 Dec 2023

Viewed by 757

Abstract

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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31 pages, 8472 KiB

Open AccessArticle

Zoning Productivity Calculation Method of Fractured Horizontal Wells in High-Water-Cut Tight Sandstone Gas Reservoirs under Complex Seepage Conditions

by Benchi Wei, Xiangrong Nie, Zonghui Zhang, Jingchen Ding, Reyizha Shayireatehan, Pengzhan Ning, Ding-tian Deng and Jiao Xiong

Processes 2023, 11(12), 3308; https://doi.org/10.3390/pr11123308 - 27 Nov 2023

Viewed by 630

Abstract

Tight sandstone gas reservoirs generally contain water. Studying the impact of water content on the permeability mechanism of tight gas reservoirs is of positive significance for the rational development of gas reservoirs. Selected cores from a tight sandstone gas reservoir in the Ordos Basin were used to establish the variation in its seepage mechanism under different water saturations. The experimental results show that the gas slip factor in tight water-bearing gas reservoirs decreases as the water saturation increases. The stress sensitivity coefficient and the threshold pressure gradient (TPG) increase with increasing water saturation, characterizing the relationships between stress sensitivity coefficients, TPG, permeability, and water saturation. As the water saturation gradually increases, the relative gas phase permeability of tight sandstone gas reservoirs will sharply decrease. When the water saturation exceeds 80%, the gas phase permeability becomes almost zero, resulting in gas almost ceasing to flow. Through the analysis of experimental results, we defined high-water-cut tight sandstone gas reservoirs and analyzed the permeability characteristics of high-water-cut tight sandstone gas reservoirs in different regions. Combining stress sensitivity coefficients and the TPG with permeability and water saturation relationships, we established a zoning productivity calculation method of fractured horizontal wells in high-water-cut tight sandstone gas reservoirs under complex seepage conditions and validated the practicality of the model through example calculations. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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24 pages, 9593 KiB

Open AccessArticle

CFD Numerical Simulation Study Based on Plunger Air Lift

by Qi Xia, Guowei Wang, Hongshan Mei, Minwei Qiu, Yuqiang Tang, Shimao Zhang, Hao Zhou, Ruiquan Liao and Manlai Zhang

Processes 2023, 11(11), 3103; https://doi.org/10.3390/pr11113103 - 29 Oct 2023

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Abstract

To study the movement law of a plunger air lift and liquid discharge efficiency, this paper observes the plunger movement and leakage through indoor experiments, based on which the CFD method is applied to establish a numerical model with the same experimental conditions, and compares the simulation results with the experiments, verifies the feasibility of the CFD simulation, and optimizes the structure of the plunger, and researches the change rule of the bottom-hole pressure and the wellhead pressure in a 200 m long wellbore. The results show that the error between CFD simulation and experimental data is 12.5%. When the depth of the plunger groove is 10 mm, the width of each groove is 10 mm, and the number of grooves is 12, the leakage is minimal; in addition, to ensure the smooth lifting of the plunger, it is necessary to control the wellhead pressure and keep the pressure difference with the bottom of the well. When the wellbore pressure is 10 MPa, the wellhead pressure should be no more than 7 MPa, and when the wellbore–wellhead pressure difference is kept at a certain level (7 MP), the plunger cannot continue to move up when the wellhead pressure is more than 18 MP, so it is necessary to control the wellbore pressure as it cannot be too big and increase the wellbore–wellhead pressure difference as much as possible. The above study of the plunger lifting law provides a reference basis for the determination of the above research plunger process parameters. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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14 pages, 4108 KiB

Open AccessArticle

Study on Production Characteristics during N₂ Flooding in Low Permeability Reservoirs: Effect of Matrix Permeability and Fracture

by Ruofan Wang, Kurbanjan Arkin, Yanyan Liang, Haibo Li, Lei Zheng, Haifeng Li and Binfei Li

Processes 2023, 11(7), 2112; https://doi.org/10.3390/pr11072112 - 15 Jul 2023

Viewed by 1086

Abstract

The N₂ flooding enhanced oil recovery process is an important technical means for the development of low permeability reservoirs due to its good energy enhancement effect and good injectivity. Low permeability reservoirs have a large permeability span and strong heterogeneity, which will have a significant impact on gas injection development. In order to explore the influence of matrix permeability and fractures on the production characteristics of N₂ flooding, this study conducted a series of displacement experiments with full-scale matrix permeability (0.1–50 mD) and different fracture conditions. The research results indicate that, in non-fracture low permeability cores, the pressure difference decreased with the matrix permeability increase, and the volume of N₂ injection required to achieve the highest injection pressure decreased. In addition, the increase in matrix permeability accelerates the gas breakthrough and gas channeling, but is beneficial for improving no-gas oil recovery and ultimate oil recovery due to the decrease in crude oil flow resistance. The impact of different matrix permeability ranges on production characteristics varies. When the matrix permeability is less than 2 mD, the characteristics of oil and gas production are significantly affected by changes in matrix permeability. When the matrix permeability is greater than 2 mD, the impact of changes in matrix permeability on development effectiveness is weakened. The existence of fracture causes a high permeability channel to appear in the low permeability matrix, exacerbating the gas breakthrough and channeling, and significantly reducing the utilization of matrix crude oil (about a 50% decrease in oil recovery). The increase in matrix permeability is beneficial for weakening the heterogeneity between fractures and the matrix, alleviating the gas channeling, thereby increasing the swept volume in the low permeability matrix and improving oil recovery. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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15 pages, 6110 KiB

Open AccessArticle

Study on Flow Characteristics of Flue Gas and Steam Co-Injection for Heavy Oil Recovery

by Yanmin Ji, Boliang Li, Zongyuan Han, Jian Wang, Zhaomin Li and Binfei Li

Processes 2023, 11(5), 1406; https://doi.org/10.3390/pr11051406 - 06 May 2023

Cited by 2 | Viewed by 1251

Abstract

Flue gas is composed of N₂ and CO₂, and is often used as an auxiliary agent for oil displacement, with good results and very promising development prospects for co-injection with steam to develop heavy oil. Although research on the oil displacement mechanism of flue gas has been carried out for many years, the flow characteristics of steam under the action of flue gas have rarely been discussed. In this paper, the flow resistance and heat transfer effect of flue gas/flue gas + steam were evaluated by using a one-dimensional sandpack, a flue gas-assisted steam flooding experiment was carried out using a specially customized microscopic visualization model, and the microscopic flow characteristics in the process of the co-injection of flue gas and steam were observed and analyzed. The results showed that flue gas could improve the heat transfer effect of steam whilst accelerating the flow of steam in porous media and reducing the flow resistance of steam. Compared with pure steam, when the volume ratio of flue gas and steam was 1:2, the mobility decreased by 2.8 and the outlet temperature of the sandpack increased by 35 °C. This trend intensified with an increase in the proportion of flue gas. In the microscopic oil displacement experiments, the oil recovery and sweep efficiency of the flue gas and steam co-injection stage increased by 4.7% and 32.9%, respectively, compared with the pure steam injection stage due to the effective utilization of blocky remaining oil and corner remaining oil caused by the expansion of fluid channels, the flow of flue gas foam, and the dissolution and release of flue gas in heavy oil. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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18 pages, 4832 KiB

Open AccessArticle

Fast and Robust Prediction of Multiphase Flow in Complex Fractured Reservoir Using a Fourier Neural Operator

by Tie Kuang, Jianqiao Liu, Zhilin Yin, Hongbin Jing, Yubo Lan, Zhengkai Lan and Huanquan Pan

Energies 2023, 16(9), 3765; https://doi.org/10.3390/en16093765 - 27 Apr 2023

Cited by 1 | Viewed by 1388

Abstract

Predicting multiphase flow in complex fractured reservoirs is essential for developing unconventional resources, such as shale gas and oil. Traditional numerical methods are computationally expensive, and deep learning methods, as an alternative approach, have become an increasingly popular topic. Fourier neural operator (FNO) networks have been shown to be a hundred times faster than convolutional neural networks (CNNs) in predicting multiphase flow in conventional reservoirs. However, there are few relevant studies on applying FNO to predict multiphase flow in reservoirs with complex fractures. In the present study, FNO-net and U-net (CNN-based) were successfully applied to predict pressure and gas saturation fields for the 2D heterogeneous fractured reservoirs. The tested results show that FNO can accurately depict the influence of fine fractures, while the CNN-based method has relatively poor performance in the treatment of fracture systems, both in terms of accuracy and computational speed. In addition, by adding initial conditions and boundary conditions to the loss function of FNO, we prove the necessity of adding physical constraints to the data-driven model. This work contributes to improving the understanding of the applicability of FNO-net, and provides new insights into deep learning methods for predicting multiphase flow in complex fractured reservoirs. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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18 pages, 4765 KiB

Open AccessArticle

Mechanical Behavior of Gas-Transmission Pipeline in a Goaf

by Bin Zhao, Hailun Zhang, Yu Wang, Yutong Zhou and Jiaxin Zhang

Processes 2023, 11(4), 1022; https://doi.org/10.3390/pr11041022 - 28 Mar 2023

Cited by 2 | Viewed by 1060

Abstract

To solve the safety hazard of a buried gas pipeline caused by subsidence of a mined-out area, a three-dimensional model of a buried pipeline in a mined-out area was established using geological parameters and the finite-element software ABAQUS. The effects of the friction coefficient of the pipe and soil, the coal-seam dip angle, and the horizontal angle on the mechanical behavior of the pipe under varying widths of goaf area were investigated. The results indicate that the maximum equivalent stress of the pipeline is negatively correlated with the horizontal angle. Concerning longitudinal mining, the pipeline exhibits a high-stress zone when the mining length is >200 m, the surface displacement appears in a small range when the mining length is 40 m, and the stratum displacement range increases gradually with the increase in the mining length. When the width of the goaf is constant, the maximum equivalent stress of the pipeline is positively correlated with the tube-soil friction coefficient and negatively correlated with the coal seam dip angle. The position of maximum stress gradually tends to appear near the uphill side of the coal seam, with an increase in the coal seam dip angle. Full article

(This article belongs to the Topic Multi-Phase Flow and Unconventional Oil/Gas Development)

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Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.7	4.5	2011	16.9 Days	CHF 2400
Energies energies	3.2	5.5	2008	16.1 Days	CHF 2600
Gases gases	-	-	2021	15.0 days *	CHF 1000
Gels gels	4.6	2.9	2015	11.1 Days	CHF 2600
Nanomaterials nanomaterials	5.3	7.4	2010	13.6 Days	CHF 2900
Processes processes	3.5	4.7	2013	13.7 Days	CHF 2400

* Median value for all MDPI journals in the second half of 2023.

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