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Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs

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A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Chemical Processes and Systems".

Deadline for manuscript submissions: closed (10 March 2024) | Viewed by 14009

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Special Issue Editors

Dr. Chao Zhang

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Guest Editor

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: CO₂ flooding; CO₂ geological sequestration; foam fluids EOR (enhanced oil recovery); heavy oil; tight oil; fracture-vuggy carbonate reservoir
Special Issues, Collections and Topics in MDPI journals

Dr. Fansheng Huang

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Guest Editor

Jiangsu Key Laboratory of Coal-based Greenhouse Gas Control and Utilization, China University of Mining and Technology, Xuzhou 221008, China
Interests: coalbed methane; shale gas; tight sandstone gas; CO₂ geological sequestration

Dr. Tengfei Wang

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Guest Editor

College of Chemistry & Environmental Engineering, Yangtze University, Jingzhou 434000, China
Interests: chemistry flooding; gas flooding; heavy oil development; tight oil development; oil shale development; fracture-vuggy carbonate reservoir development
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Unconventional reservoirs, including shale and tight oil and gas, heavy oil, coal bed methane (CBM), natural gas, and fracture-vuggy carbonate reservoirs, are widely distributed and abundant around the world. This is an important area for the strategic replacement and development of oil and gas resources. In contrast to conventional reservoirs, the multiphase fluid flow law and the development process in unconventional reservoirs are more complex and difficult. The pore scales of unconventional oil and gas reservoirs involve centimeter, micron, and nanometer scales. The formation environment is mostly of a high temperature, high pressure, and high salinity. The flow of a fluid in a porous medium is also a rather complicated course, combining intricate phase variations. These issues have all contributed to the difficulties of oil and gas development and are attracting increasing attention and research from academics.

This Special Issue focuses on the sustainable development of unconventional oil and gas resources, recent advances, and the challenges they are facing for sustainability. We aim to gather researchers in the aforementioned fields to highlight the current development of new techniques; exchange the latest knowledge of the underlying mechanisms; present advanced algorithms for modeling and innovative experimental methods; and facilitate collaboration between researchers in different fields. We welcome the submission of both original research and review articles.

Potential topics include, but are not limited to, the following:

Multi-scale simulations of fluid flow in fracture-vuggy carbonate reservoirs;
Adsorption and desorption in shale and CBM;
New advances in natural gas hydrate development;
Gas injection assisting heavy oil development;
The efficient utilization of multifunctional foam fluid;
CO₂-based enhanced oil recovery (EOR) in unconventional oil and gas reservoirs;
CO₂ storage in abundant reservoirs.

Dr. Chao Zhang
Dr. Fansheng Huang
Dr. Tengfei Wang
Guest Editors

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Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Processes is an international peer-reviewed open access monthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2400 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

unconventional reservoir
efficient development measures
green technologies
sustainability
carbon reduction

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Related Special Issue

Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition) in Processes (5 articles)

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Research

19 pages, 7028 KiB

Open AccessArticle

Optimization Simulation of Hydraulic Fracture Parameters for Highly Deviated Wells in Tight Oil Reservoirs, Based on the Reservoir–Fracture Productivity Coupling Model

by Chonghao Mao, Fansheng Huang, Qiujia Hu, Shiqi Liu, Cong Zhang and Xinglong Lei

Processes 2024, 12(1), 179; https://doi.org/10.3390/pr12010179 - 12 Jan 2024

Viewed by 1197

Abstract

The production potential of highly deviated wells cannot be fully realized by conventional acid fracturing, as it can only generate a single fracture. To fully enhance the productivity of highly deviated wells, it is necessary to initiate multiple fractures along a prolonged well section to ensure the optimal number of fractures, thereby maximizing the economic returns post-stimulation. Thus, the number of fractures is a crucial parameter in the acid fracturing design of highly deviated wells. Considering factors such as the random distribution of natural fractures within the reservoir and interference between fractures during production, and, based on the oil–water two-phase flow equation, a three-dimensional reservoir–fracture production coupling model and its seepage difference model are established to simulate the production performance of highly deviated wells under varying conditions, including the number of fractures, fracture spacing, and conductivity parameters. A numerical model for the number of acid fracturing fractures in highly deviated wells is also established, in conjunction with an economic evaluation model. The simulation results indicate that the daily oil production of highly deviated wells increases with the increase in fracture number, fracture conductivity, fracture length, and reservoir permeability. However, over time, the daily oil production gradually decreases. Similarly, the cumulative production also increases with these parameters, but shows a downward trend over time. By conducting numerical simulations to evaluate the productivity and economy of highly deviated wells post-acid fracturing, it is determined that the optimal number of fractures to achieve maximum efficiency is six. The reliability of this result is confirmed by the pressure distribution cloud map of the formation after acid fracturing in highly deviated wells. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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21 pages, 4610 KiB

Open AccessArticle

Effect of Interaction between Carbon Dioxide and Fluid Phase/Rock Interface on Carbon Dioxide Storage

by Xiaopeng Cao, Qihong Feng and Yanfeng Ji

Processes 2023, 11(12), 3331; https://doi.org/10.3390/pr11123331 - 30 Nov 2023

Cited by 1 | Viewed by 992

Abstract

The interaction between CO₂, formation water, and rock surfaces after CO₂ flooding and the mechanism by which it affects CO₂ storage were studied in this paper. The results show that variations in the solubility of CO₂ in crude oil under pressure are similar to those observed in formation water. The solubility of CO₂ increases as pressure increases under a low-pressure conditions. The solubility of CO₂ in crude oil increases significantly when crude oil is in a low-viscosity state, and this makes it easier to diffuse CO₂ into the oil phase at high temperatures. More resistance is encountered when CO₂ diffuses into the liquid-containing space of an irregular core, making the coefficient of diffusion into the oil–water two-phase flow in the porous medium smaller. After the core is corroded by a CO₂-saturated aqueous solution, the quartz content in the mineral component increases and the plagioclase and potassium feldspar content significantly decrease. The dissolution of the feldspar leads to the formation of a large amount of secondary kaolinite, thus increasing the kaolinite content. In the early stage of CO₂ erosion during dynamic displacement, the combined effect of particle migration and inorganic precipitation leads to a slow growth in core permeability and porosity. As the erosion progresses, the influence of particle migration and inorganic precipitation on permeability gradually decreases, while the porosity of the core gradually increases. The secondary pores play a role, and the erosion of the CO₂–water system makes the permeability and porosity of the core gradually increase. During dynamic displacement, CO₂ is mainly stored in the reservoir in free and irreducible states. Under the pressure of the reservoir, some of the CO₂ participates in erosion reactions and is stored in the rock or the solution in the form of minerals or ions. In addition, a small portion of the CO₂ is dissolved in the residual water and residual oil that remain after the dynamic displacement. The results of this paper can provide some theoretical support for the design of a CO₂ storage site. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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15 pages, 8940 KiB

Open AccessFeature PaperArticle

Polyethylene Composite Particles as Novel Water Plugging Agent for High-Temperature and High-Salinity Reservoirs

by Bo Deng, Ning Yang, Jiangang Li, Chenwei Zou, Yunpu Tang, Jianwei Gu, Yifei Liu and Wei Liu

Processes 2023, 11(10), 3044; https://doi.org/10.3390/pr11103044 - 23 Oct 2023

Viewed by 1352

Abstract

Water channeling has always been one of the urgent problems during oilfield development. Especially for fractured reservoirs with high temperature, high salinity, and severe heterogeneity (e.g., deep carbonate reservoirs), it is difficult for the existing plugging agents to realize effective water plugging. In this paper, chemically stable polyethylene (PE) was selected as the main component to prepare multiscale PE composite particles that can be easily dispersed in water as a novel water plugging agent for fractured reservoir with high temperature and high salinity. The characteristics of the prepared PE composite particles, including thermal stability, salinity resistance, dispersibility, coalescence properties, and microscopic morphology, were systematically studied. Finally, the plugging performance of the particles was evaluated through visual physical simulation experiments. The prepared PE composite particles can be pulverized to a minimum of 6 μm, and the particle size is controllable within 6 μm to 3 mm by adjusting the pulverization parameters. The PE composite particles are easily dispersed in water by adding the dispersant, which is conducive to injectivity during the field application process. The particle size remains unchanged under the condition of salinity of 0–3.0 × 10⁵ mg/L, which indicates that the prepared particles have good salt-resistant stability. After high-temperature aging, the particles adhere to each other, and the size of the agglomerations reach a size dozens of times larger than the initial size of the particle, which is conducive to effective plugging in fractures. Thermal degradation behavior analysis shows that the PE composite particles could theoretically withstand a temperature of 434.4 °C. It can be seen from the SEM images that after high-temperature melting and kneading with other components, the microstructure changes from a fibrous structure to a dense flake structure. Physical simulation experiments show that the PE composite particles accumulate in fracture after injection and form effective plugging through coalescence and adhesion of the particles, thereby realizing water flow diversion. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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18 pages, 8991 KiB

Open AccessArticle

Experimental Simulation on the Stress Disturbance Mechanism Caused by Hydraulic Fracturing on the Mechanical Properties of Shale Formation

by Yu Tang, Heng Zheng, Hong Xiang, Xiaomin Nie and Ruiquan Liao

Processes 2023, 11(10), 2931; https://doi.org/10.3390/pr11102931 - 9 Oct 2023

Cited by 2 | Viewed by 1220

Abstract

Hydraulic fracturing is an indispensable technology for the development of shale oil and shale gas. Knowing the changes in the rock mechanical properties and failure modes during hydraulic fracturing is the key to improving the efficiency of hydraulic fracturing. Based on experiments and simulations, it can be concluded that the injection of fracturing fluid in the hydraulic fracturing caused deformation of the fracture surface, and the rock mechanical properties experienced degradation with a maximum reduction in the rock mechanical properties of 44.24%. As indicated in the experiments, the displacement of the measurement point was decreased with the distance increase between the injection point and the measurement point. According to the numerical simulations, tensile failure is the main failure mode in hydraulic fracturing, but the percentage of shear failure had an obvious increase with the increase in distance between the injection point and the measurement point. Comparing DDS #1 and DDS #5, the DDS #5 measurement point was farther away from the injection point, and the average percentage of shear failure increased from 21.94 to 52.72%. Meanwhile, the increase in the branch fractures also caused shear failure to occur. Comparing Sample 1 and Sample 3, in Sample 3, which had more branch fractures, the average percentage of shear failure increased from 33.12 to 37.58%. Due to the porous medium of the reservoir rock, the enormous pressure generated during the injection of fracturing fluid caused significant deformation of the fracture surface, leading to the tensile failure of the rock. The displacement of the fracture surface caused by the fracturing fluid injection also led to the deformation of the pore throat structure; thus, the shear failure increased when the measurement point was away from the injection point. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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17 pages, 6536 KiB

Open AccessFeature PaperArticle

Characteristics and Stabilization Mechanism of Three-Phase Foam: Improving Heavy Oil Recovery via Steam Stimulation through Two-Dimensional Visual Model

by Mingxuan Wu, Zengmin Lun, Yongqiang Tang, Jinming Dai, Mingkai Liu, Deqiang Wang and Zhaomin Li

Processes 2023, 11(9), 2649; https://doi.org/10.3390/pr11092649 - 4 Sep 2023

Viewed by 1080

Abstract

There is a problem of a rapid decline in production caused by the repeated heating of the near-wellbore zone during steam stimulation. Finding a suitable foam system to expand the area of the steam chamber and slow down the rapid production of hot water during the recovery process can effectively improve the effect of steam stimulation. In this paper, CGS foam was prepared with high-temperature-resistant surfactant GD, graphite particles, and clay particles. Through the study of foam properties, it was found that with the addition of particles, the strength of the foam’s liquid film, half-life time, and temperature resistance was greatly improved. The appropriate permeability of the CGS foam and the movement characteristics of it in formations with different permeabilities were studied through a plugging experiment with a sand pack. The plugging performances of the GD foam, CGS foam, and pure particles in a simulated reservoir were compared. The development of the steam cavity during the steam stimulation process and the influence of injecting GD foam and CGS foam on the flow in the simulated reservoir were studied through a two-dimensional visualization model. The temperature resistance and stability of the CGS foam were better than those of GD foam in the simulated formation. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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15 pages, 5928 KiB

Open AccessArticle

The Enhanced Oil Recovery Effect of Nitrogen-Assisted Gravity Drainage in Karst Reservoirs with Different Genesis: A Case Study of the Tahe Oilfield

by Hong Cheng

Processes 2023, 11(8), 2316; https://doi.org/10.3390/pr11082316 - 2 Aug 2023

Cited by 3 | Viewed by 1105

Abstract

For the Tahe Oilfield, there are multiple sets of karst reservoirs with different genesis developed in carbonate fracture-vuggy reservoirs and the varying karst reservoir type has a considerable influence on the distribution of residual oil. The complex characteristics of different karst reservoirs and the difficulty in producing the remaining oil in the middle and lower part of the reservoir greatly restrict the recovery effects. This work managed to comprehensively investigate the action mechanism of nitrogen-assisted gravity drainage (NAGD) on remaining oil in reservoirs with different karst genesis through modeling and experiments. Based on geological characteristics and modeling results, a reservoir-profile model considering reservoir type, fracture distribution, and the fracture–cave combination was established, the displacement experiments of main reservoirs such as the epikarst zone, underground river, and fault karst were carried out, and the oil–gas–water multiphase flow was visually analyzed. The remaining oil state before and after NAGD was studied, and the difference in recovery enhancement in different genetic karst reservoirs was quantitatively compared. The results show that NAGD was helpful in enhancing oil recovery (EOR) for reservoirs with different karst genesis. NAGD technique has the greatest increasing effect on the sweep efficiency of the fault-karst reservoir, followed by the epikarst zone reservoir, and the smallest in the underground river reservoir. The results of this research will facilitate an understanding of the EOR effect of karst-reservoir types on NAGD and provide theory and technical support for the high-efficiency development in varying karst reservoirs in the Tahe Oilfield. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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18 pages, 14467 KiB

Open AccessArticle

Pore-Scale Experimental Investigation of the Residual Oil Formation in Carbonate Sample from the Middle East

by Yongjie Liu, Jian Pi and Kaijun Tong

Processes 2023, 11(8), 2289; https://doi.org/10.3390/pr11082289 - 30 Jul 2023

Cited by 4 | Viewed by 1083

Abstract

Select porous carbonate cores are used to carry out water-flooding oil micro-CT flooding experiments, and use image processing to separate oil, water, microfacies, and rock skeleton. The gray value is used to determine the distribution position of the microfacies sub-resolution remaining oil. The gray image resolution is improved by the SRCNN method to improve the pore identification accuracy. The distribution and evolution law of the sub-resolution remaining oil after the displacement is determined by the oil-water distribution results. Using the SRCNN method, the pore recognition accuracy of the original scanned images of the two samples was increased by 47.88 times and 9.09 times, respectively. The sub-resolution residual oil and the macro-pore residual oil were determined from the CT scan images after the brine was saturated and divided into five categories. With the increase in the displacement ratio, the columnar and droplet residual oil of the low-permeability samples first increased and then decreased, and the cluster residual oil gradually decreased. The continuous residual oil of the hypertonic samples gradually decreased, and the discontinuous residual oil gradually increased. According to the research results of carbonate pore throat identification and sub-resolution microscopic residual oil change characteristics after water flooding under the SRCNN method, a method for distinguishing porous carbonate reservoirs is provided. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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17 pages, 24129 KiB

Open AccessArticle

Study on Residual Oil Distribution Law during the Depletion Production and Water Flooding Stages in the Fault-Karst Carbonate Reservoirs

by Bochao Tang, Ke Ren, Haitao Lu, Chenggang Li, Chunying Geng, Linshan Wei, Zhenhan Chai and Shouya Wu

Processes 2023, 11(7), 2147; https://doi.org/10.3390/pr11072147 - 19 Jul 2023

Cited by 5 | Viewed by 1272

Abstract

The fault-karst carbonate reservoir is a new type of deep carbonate oil and gas resource and a target for exploration and development. The distribution of remaining oil in this kind of oilfield is very complicated because of its unique reservoir characteristics of vertical migration and accumulation, segmented accumulation, and differential accumulation. Therefore, the S91 reservoir block, a typical fracture-vuggy carbonate reservoir in the Tahe oilfield, was taken as the object of this research. According to the development characteristics as well as the porosity and permeability characteristics of the fracture-vuggy, the reservoirs were divided into three types: cave, pore, and fracture. A numerical simulation model of the fracture-vuggy reservoir of the S91 unit was established, and the historical fitting accuracy with dynamic production data was more than 90%. Then, the distribution characteristics of the remaining oil in the depletion stage of the fault-karst carbonate reservoir were further studied and based on the analysis of the reservoir water-flood flow line, the remaining oil distribution characteristics in the depletion stage of the fault solution reservoir were revealed. The results show that the remaining oil distribution patterns during the depletion production stage can be divided into three types: attic type, bottom water coning type, bottom water running type. Due to the serious problem of the bottom aquifer lifting caused by the reservoir development, the residual oil between wells was relatively abundant during the depletion production stage. According to the simulation results, the remaining oil distribution modes in the water drive development stage were identified as three types: sweeping the middle between wells, bottom water connection and circulation, and oil separation through high-permeability channels. In addition, the reservoir connectivity was the main controlling factor for the remaining oil distribution in the fault-karst carbonate reservoir. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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15 pages, 3991 KiB

Open AccessArticle

Physical Simulation of Gas Injection Mechanism for High Dip Reservoir

by Kang Xiao, Xiangling Li and Xianbing Li

Processes 2023, 11(7), 2111; https://doi.org/10.3390/pr11072111 - 15 Jul 2023

Viewed by 1243

Abstract

High dip angle reservoirs are affected by gravity, resulting in poor sweep performance at the middle and high parts during waterflooding development. Previous studies have proposed top gas injection development for this type of reservoir, which has provided direction for improving the development effect of such reservoirs. However, current research efforts have mainly focused on the analysis of gas injection effects, rather than delving deeper into the gas injection mechanism and its influencing factors. Furthermore, the research methods adopted thus far have been primarily theoretical and fail to take into account the typical characteristics of high dip reservoirs in actual oilfields. Using a similarity criterion, this study establishes a high-temperature and high-pressure physical simulation device with variable inclination to analyze the impact of gas injection under various water injection conditions on the development of high dip reservoirs. The results suggest that the earlier the injection of water and gas, the slower the overall increase in water cut, and the more distinct the oil wall effect after gas injection, leading to a higher ultimate recovery. In the experiments, earlier injection timing can increase the final recovery rate by 9.59%. In addition, a visualized physical simulation device with an adjustable inclination angle has been established to analyze the sweep performance of high dip reservoirs under various gas injection timings. It is concluded that energy supplement in the early stage of pressure decline in the reservoir resulted in a more uniform movement of the oil-water interface at the bottom and the oil-gas interface at the top, and reduced the probability of water and gas channeling. The overall displacement efficiency is found to be improved with this approach. Earlier injection timing increased sweep efficiency by 5.95% and recovery efficiency by 13.2%, respectively. The injection gas source determined in this study, which is associated gas, is beneficial for low carbon plan and exhibits satisfactory oil recovery. The development of high dip reservoirs through top gas injection in combination with bottom water injection can generate a synergistic effect, which significantly enhances sweep efficiency and ultimate oil recovery. This finding provides theoretical guidance for practical implementation in the field. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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22 pages, 16409 KiB

Open AccessArticle

Investigation on Water Invasion Mode and Remaining Oil Utilization Rules of Fractured-Vuggy Reservoirs: A Case Study of the Intersection Region of S99 Unit in Tahe Oilfield

by Hong Cheng, Feiyu Yuan, Shiliang Zhang, Lu Li, Xianping Luo and Bo Chen

Processes 2023, 11(6), 1833; https://doi.org/10.3390/pr11061833 - 16 Jun 2023

Cited by 4 | Viewed by 1288

Abstract

Fractured-vuggy reservoirs are a new target in carbonate oil and gas exploration and development. Because of well-developed reservoir bodies, including fractures and caverns, bottom water invasion can be observed in oilfield development, with low utilization efficiency of crude oil in the reservoir. Accordingly, this study focused on the intersection region of the S99 unit of the Tahe fractured-vuggy reservoirs. Based on seismic data, the reservoir bodies can be divided into three types—caverns, fractures, and broken solution pores. Using the same location condition assignment algorithm, four single-type models are fused into a multi-scale discrete three-dimensional geological model of fractured and cavernous reservoirs, and the corresponding fractured-vuggy reservoir model was established for numerical simulation. The single-well historical fitting precision exceeded 85%. Furthermore, the development can be divided into four stages—initial stage of production, peak production stage, liquid control and oil stabilization stage, and scale gas injection stable. Streamlining sweep analysis determined the utilization and distribution characteristics of the remaining oil in the reservoir. It can be concluded that structure, caverns, and fractures were the main controlling factors affecting the remaining oil distribution in the fractured-vuggy reservoir. The fluid exchange among single-well reserve zones was calculated using streamline-based quantitative sweep analysis and interwell flow quantitative analysis method. Through source-sink quantitative analysis, interwell flow relations were derived, and three water breakthrough modes were further concluded: violent flooding, slow ascending of water cut, and low cut or intermittent water production. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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14 pages, 10113 KiB

Open AccessArticle

Numerical and Experimental Simulation of Hydraulic Fracture Propagation Mechanism in Conglomerate Formation Based on Hybrid Finite-Discrete Element Method

by Linsheng Wang and Mingxing Wang

Processes 2023, 11(6), 1645; https://doi.org/10.3390/pr11061645 - 28 May 2023

Viewed by 1149

Abstract

Hydraulic fracturing was the main technology to achieve the economic development of conglomerate reservoirs, knowing that the hydraulic fracture propagation mode was of great significance for improving the development of conglomerate reservoirs. This paper proposed a new method to understand the hydraulic fracture behavior based on a hybrid finite-discrete element method. The simulation indicated that a complex fracture network was created near the wellbore in the studied conglomerate reservoir, and hydraulic fracture propagation around the gravel layer was the main failure mode when the hydraulic fracture reached the gravel layer. From the simulations, it was shown that under small differences in horizontal stress and tensile strength, the hydraulic fracture propagated more easily around the gravel layer, while it could cross the gravel under large differences in horizontal stress and tensile strength. Greater tensile strength differences can reduce the complexity of the fracture network. In addition, higher pumping rates and viscosities of fracturing fluid contribute to the complex fracture network and also can produce more gravel crosses when the hydraulic fracture is met. The main reason was that a higher pumping rate and higher viscosity of fracturing fluid can obtain a higher net pressure, which can ensure the hydraulic fracture crosses the gravel layer. Full article

(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs)

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