Editorial

4 pages, 161 KiB

Open AccessEditorial

Recent Advances in Reservoir Stimulation and Enhanced Oil Recovery Technology in Unconventional Reservoirs

by Lufeng Zhang, Linhua Pan, Yushi Zou, Jie Wang, Minghui Li and Wei Feng

Processes 2024, 12(1), 234; https://doi.org/10.3390/pr12010234 - 22 Jan 2024

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In the past decade, significant advances in reservoir stimulation and enhanced oil recovery technologies have resulted in rapid production growth in unconventional reservoirs [...] Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

Research

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12 pages, 2075 KiB

Open AccessArticle

Lab Experiments for Abrasive Waterjet Perforation and Fracturing in Offshore Unconsolidated Sandstones

by Yigang Liu, Peng Xu, Liping Zhang, Jian Zou, Xitang Lan and Mao Sheng

Processes 2023, 11(11), 3137; https://doi.org/10.3390/pr11113137 - 02 Nov 2023

Viewed by 698

Abstract

Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too [...] Read more.

Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too difficult to be mechanically isolated in several stages. Hydra-jet fracturing technology has the advantages of multistage fracturing by one trip, waterjet perforation, and hydraulic isolation. The challenges of hydraulic-jet fracturing in offshore unconsolidated sandstone reservoir can be summarized as follows: the long jet distance, high filtration loss, and large pumping rate. This paper proposes full-scale experiments on the waterjet perforation of unconsolidated sandstone, waterjet penetration of screen liners and casing, and pumping pressure prediction. The results verified that multistage hydra-jet fracturing is a robust technology that can create multiple fractures in offshore unconsolidated sandstone. Lab experiments indicate that the abrasive water jet is capable to perforate the screen-casing in less than one minute with an over 10 mm diameter hole. The water jet perforates a deep and slim hole in unconsolidated sandstone by using less than 20 MPa pumping pressure. Recommended perforating parameters: maintain 7% sand concentration and perforate for 3.0 min. Reduce sand ratio to 5%, maintain 3.0 m³/min flow rate, and continue perforating for 7.0 min. The injection drop of the nozzle accounts for more than 62% of the tubing pump pressure. The recommended nozzle combinations for different fracturing flow rates are 8 × ø6 mm or 6 × ø7 mm for 2.5 m³/min and 3.0 m³/min, and 8 × ø7 mm for 3.5 m³/min and 4.0 m³/min. A one-trip-multistage hydra-jet fracturing process is recommended to be used for horizontal wells in offshore unconsolidated sandstone reservoirs. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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13 pages, 2775 KiB

Open AccessArticle

Axial Force Calculation Model for Completion String with Multiple Point Resistances in Horizontal Well

by Zhen Nie, Shuzhe Shi, Bohong Wu and Xueqin Huang

Processes 2023, 11(9), 2621; https://doi.org/10.3390/pr11092621 - 02 Sep 2023

Viewed by 879

Abstract

Frequent accidents may happen during the string run-down and pull process due to the lack of accuracy in the prediction of string force analysis. In order to precisely predict the completion string axial force in horizontal wells, a new model is established, and [...] Read more.

Frequent accidents may happen during the string run-down and pull process due to the lack of accuracy in the prediction of string force analysis. In order to precisely predict the completion string axial force in horizontal wells, a new model is established, and an in-house software has been developed. The model aims to predict the multiple local resistances that occur at different points on the completion string, which makes up for the technical defects of the commonly used software. It can calculate resistance at different points of the string, which will lead to varying hook load amplification. This method can also predict the axial force of the completion string. By changing the hook load, location, and direction, the resistance can be determined more accurately. Based on the calculation and analysis, the relationship between local resistance, the blocking point, and the amplification factor is also obtained. Furthermore, this model is used to analyze the local resistance of a horizontal well with multiple external packers in the low-permeability Sadi Reservoir of Halfaya Oilfield, Iraq. The recorded data from in-site operations are compared with the predicted results from this model. The results show that the relative errors between the recorded data and model calculation are within the range of 10%, which indicates that the calculated values are reliable. Meanwhile, the results indicate the success of the subsequent completion design and the construction of the oilfield. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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15 pages, 5887 KiB

Open AccessArticle

Three-Dimensional Printing of Synthetic Core Plugs as an Alternative to Natural Core Plugs: Experimental and Numerical Study

by Juan Antonio Cruz-Maya, José Luis Mendoza-de la Cruz, Luis Carlos Martínez-Mendoza, Florencio Sánchez-Silva, José Alfredo Rosas-Flores and Janet Jan-Roblero

Processes 2023, 11(9), 2530; https://doi.org/10.3390/pr11092530 - 23 Aug 2023

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Abstract

This paper proposes three-dimensional (3D) additive fabrication of synthetic core plugs for core flooding experiments from spheres and grains of Berea Sandstone using a digital particle packing approach. Samples were generated by systematically combining the main textural parameters of the rock reservoir to [...] Read more.

This paper proposes three-dimensional (3D) additive fabrication of synthetic core plugs for core flooding experiments from spheres and grains of Berea Sandstone using a digital particle packing approach. Samples were generated by systematically combining the main textural parameters of the rock reservoir to design synthetic core plugs Numerical flow simulation was per-formed using the lattice Boltzmann method (LBM) to verify the flow distribution and permeability for comparison with the experimentally measured permeability and to that obtained from correlations in the literature. The digital porosity of the sample was compared to the porosity measured using an HEP-P helium porosimeter. The numerical and experimental results for permeability and porosity differed by a maximum of 18%. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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22 pages, 9926 KiB

Open AccessArticle

Evaluation of Fracture Volume and Complexity of Tight Oil Wells Based on Flowback Data

by Jie Li, Sen Liu, Jianmin Li, Zhigang Liu, Xi Chen, Jiayan Li and Tianbo Liang

Processes 2023, 11(8), 2436; https://doi.org/10.3390/pr11082436 - 13 Aug 2023

Viewed by 833

Abstract

For tight reservoirs, horizontal wells and multi-stage fracturing can generate a complex fracture network that realizes economic and effective development. The volume and complexity of the fracture network are of great significance to accurately predicting the productivity of tight oil wells. In this [...] Read more.

For tight reservoirs, horizontal wells and multi-stage fracturing can generate a complex fracture network that realizes economic and effective development. The volume and complexity of the fracture network are of great significance to accurately predicting the productivity of tight oil wells. In this work, a mathematical model of a multiphase flow is proposed to evaluate the stimulation effect based on the early flowback data. The model showing the early slope of the material balance time (MBT) and production balance pressure (RNP) can help estimate the effective stimulated volume of the horizontal well. The linear flow region can be determined from the slope of the log–log plot of the MBT versus RNP curve, which equals 1. The method is verified by commercial simulation software, and the calculated stimulated volume is consistent with the statistical results of simulation results. Results also show that the flow pattern of the fracture–matrix system can be judged by the slope of the flowback characteristic curve in the early stage of flowback, and then the complexity of the fracture network can also be obtained. The proposed method can provide an avenue to evaluate the fracturing work using the flowback data quickly. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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11 pages, 7214 KiB

Open AccessArticle

Impact of Formation Dip Angle and Wellbore Azimuth on Fracture Propagation for Shale Reservoir

by Kefeng Yang, Lei Wang, Jingnan Ge, Jiayuan He, Ting Sun, Xinliang Wang and Yanxin Zhao

Processes 2023, 11(8), 2419; https://doi.org/10.3390/pr11082419 - 11 Aug 2023

Cited by 1 | Viewed by 614

Abstract

The significant vertical heterogeneity, variations in ground stress directions, and irregular bedding interfaces make it extremely challenging to predict fracture propagation in continental shale reservoirs. In this article, we conducted a series of triaxial laboratory experiments on continental shale outcrop rocks to investigate [...] Read more.

The significant vertical heterogeneity, variations in ground stress directions, and irregular bedding interfaces make it extremely challenging to predict fracture propagation in continental shale reservoirs. In this article, we conducted a series of triaxial laboratory experiments on continental shale outcrop rocks to investigate the effects of formation dip angle and wellbore orientation on crack propagation under horizontal well conditions. Our study revealed that fracture propagation features can be categorized into four distinct types: (1) hydraulic fractures pass through the bedding interface without activating it; (2) fractures pass through and activate the bedding interface; (3) hydraulic fractures open and penetrate the bedding interface while also generating secondary fractures; and (4) hydraulic fractures open but do not penetrate the bedding interface. We found that as the dip angle decreases, the likelihood of fractures penetrating through the bedding interface increases. Conversely, as the dip angle increases, fractures are more likely to simply open the interface without penetrating it. Moreover, we observed that the well azimuth significantly affects the degree of fracture distortion. Specifically, higher azimuth angles corresponded to a higher degree of fracture distortion. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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19 pages, 6845 KiB

Open AccessArticle

Numerical Simulation of Multi-Fracture Propagation Based on the Extended Finite Element Method

by Qiquan Ran, Xin Zhou, Jiaxin Dong, Mengya Xu, Dianxing Ren and Ruibo Li

Processes 2023, 11(7), 2032; https://doi.org/10.3390/pr11072032 - 07 Jul 2023

Cited by 1 | Viewed by 823

Abstract

Multi-stage, multi-cluster fracturing in horizontal wells is widely used as one of the most effective methods for unconventional reservoir transformation. This study is based on the extended finite element method and establishes a multi-hydraulic fracturing propagation model that couples rock damage, stress, and [...] Read more.

Multi-stage, multi-cluster fracturing in horizontal wells is widely used as one of the most effective methods for unconventional reservoir transformation. This study is based on the extended finite element method and establishes a multi-hydraulic fracturing propagation model that couples rock damage, stress, and fluid flow, and the influence of horizontal stress difference and cluster spacing on fracture propagation is quantitatively analyzed. The simulation results show that changes in horizontal stress differences and inter-cluster spacing have a significant impact on the final propagation morphology of hydraulic fractures, and the change of the fracture initiation sequence forms different stress shadow areas, which in turn affects the propagation morphology of the fractures. When two fractures simultaneously propagate, they will eventually form a “repulsive” deviation, and a smaller stress difference and a decrease in inter-cluster spacing will lead to a more significant deviation of the fracture. Specifically, when the horizontal stress difference is 4 MPa and the cluster spacing is 6 m, the offset of the fracture tip along the direction of minimum horizontal principal stress is about 1.6 m, compared to the initial perforation position. When two fractures propagate sequentially, the fractures do not significantly deviate and propagate along the direction of maximum horizontal principal stress. When fractures propagate sequentially, the stress difference has little effect on the morphology of the fracture, but changes in inter-cluster spacing will significantly affect the length of the fracture. This study quantifies the effect of inter-fracture interference on fracture propagation morphology, providing guidance for optimizing the construction parameters of multi-stage hydraulic fracturing. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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16 pages, 5594 KiB

Open AccessArticle

Cryogenic Fracture Proliferation from Boreholes under Stresses

by Minsu Cha, Naif B. Alqahtani and Lei Wang

Processes 2023, 11(7), 2028; https://doi.org/10.3390/pr11072028 - 06 Jul 2023

Cited by 1 | Viewed by 919

Abstract

Cryogenic fracturing has been explored in recent years as a waterless fracturing method for well stimulation to avoid issues encountered in water-based hydraulic fracturing. Cryogenic stimulation using liquid nitrogen applies large thermal gradients on reservoir rocks to induce fractures. This study investigates the [...] Read more.

Cryogenic fracturing has been explored in recent years as a waterless fracturing method for well stimulation to avoid issues encountered in water-based hydraulic fracturing. Cryogenic stimulation using liquid nitrogen applies large thermal gradients on reservoir rocks to induce fractures. This study investigates the initiation and proliferation of cryogenic fractures from boreholes under external stress on specimens. We flowed liquid nitrogen through boreholes drilled through the center of transparent PMMA cylinders under uniaxial stress and monitored fracture proliferation, temperatures, and borehole pressures. Our results show that the effect of stress resembles that of hydraulic fractures such that fractures propagate more in the direction of the stress. Under loading perpendicular to the borehole axis, a cloud of annular and longitudinal fractures extends more in the direction of loading. Under loading parallel to the borehole axis, longitudinal fractures dominate, and annular fractures become more suppressed and more sparsely distributed than those of unconfined specimens. Even if fractures are driven to initiate against the influence of stress, such as those from a boundary edge of a high stress concentration, they gradually deflect in the direction of stress, similar to hydraulic fractures from perforation holes that curve toward a direction perpendicular to the minimum stress direction. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 5308 KiB

Open AccessArticle

Study on the Fracture Propagation in Multi-Horizontal Well Hydraulic Fracturing

by Qiquan Ran, Xin Zhou, Jiaxin Dong, Mengya Xu, Dianxing Ren and Ruibo Li

Processes 2023, 11(7), 1995; https://doi.org/10.3390/pr11071995 - 02 Jul 2023

Cited by 1 | Viewed by 889

Abstract

Multi-horizontal well hydraulic fracturing is a widely employed and highly effective method for stimulating tight and shale reservoirs. However, most existing studies primarily focus on investigating the impact of intra-well interference on fracture propagation while neglecting the influence of inter-well interference. Here, a [...] Read more.

Multi-horizontal well hydraulic fracturing is a widely employed and highly effective method for stimulating tight and shale reservoirs. However, most existing studies primarily focus on investigating the impact of intra-well interference on fracture propagation while neglecting the influence of inter-well interference. Here, a multi-well hydraulic-fracture-propagation model is established to examine the effects of inter-well interference on fracture propagation within a multi-well system. In this study, based on the bilinear T-S criterion, the stiffness degradation is used to describe the damage and evolution process of fracture, the coupling process of fluid flow and solid damage and deformation is realized, and the dynamic distribution of inter-fracture flow is realized by using Kirchhoff function on the basis of the cohesive zone method (CZM) finite element model. Finally, the fracture-propagation model of multiple horizontal wells is established. Based on this model, the mechanism of inter-well interference on fracture propagation is studied, and the influence law of Young’s modulus and fracture displacement on fracture propagation in multi-wells is investigated. The results show that the reservoir can be divided into self-influence area, tension area and compression area according to the stress distribution state in the hydraulic fracture propagation of multi-wells. The propagation rate of hydraulic fractures in horizontal wells is significantly accelerated when they propagate to the local tension area generated by the fracture tip of neighboring wells, and rapidly decreases as the hydraulic fractures continue to propagate to the compression area of neighboring wells. Rocks with a lower Young’s modulus tend to be more plastic, forming hydraulic fractures with usually lower fracture lengths and usually larger fracture widths. The hydraulic fracture has an inhibitory effect on the propagation of fractures closer to each other in neighboring wells, and this inhibitory effect gradually increases as the distance decreases. The dominance of the dominant fracture to propagate in the self-influence area gradually decreases under inter-well and intra-well interference. As the dominant fracture propagates into the tension and compression areas of the neighboring well fractures, the feed fluid will show a brief rise and then eventually stabilize. This study quantifies the effect of inter-well interference on fracture propagation and lays the foundation for treatment optimization of small well spacing hydraulic fracturing. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 3139 KiB

Open AccessArticle

Physical Simulation Experiments of Hydraulic Fracture Initiation and Propagation under the Influence of Deep Shale Natural Fractures

by Zhou Hu, Pengfei Chen, Wei Jiang, Yadong Yang, Yizhen Li, Longqing Zou, Huaming Wang, Yuping Sun and Yu Peng

Processes 2023, 11(7), 1934; https://doi.org/10.3390/pr11071934 - 27 Jun 2023

Cited by 2 | Viewed by 732

Abstract

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in [...] Read more.

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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19 pages, 6759 KiB

Open AccessArticle

Study on Casing Safety Evaluation in High-Temperature Wells with Annular Pressure Buildup

by Hao Wang, Mu Li, Qing Zhao, Weiwei Hao, Hui Zhang, Yafei Li, Pengpeng Huang and Yi Zou

Processes 2023, 11(7), 1915; https://doi.org/10.3390/pr11071915 - 26 Jun 2023

Viewed by 2215

Abstract

In high-temperature wells, annular pressure buildup (APB) caused by temperature increase is a widespread phenomenon in production, especially in offshore thermal recovery wells. It increases the load on the tubing and casing and consequently threatens the wellbore integrity. Hence, research on casing safety [...] Read more.

In high-temperature wells, annular pressure buildup (APB) caused by temperature increase is a widespread phenomenon in production, especially in offshore thermal recovery wells. It increases the load on the tubing and casing and consequently threatens the wellbore integrity. Hence, research on casing safety evaluation and APB management has great significance for field production. In this paper, the tubing and casing safety evaluation and APB limit determination methods are presented considering the effect of thermal stress and APB. Based on the case study of an offshore thermal recovery well, an APB-management chart and the recommended optimal range of APB are provided. Finally, an analysis of three commonly used mitigation methods is presented. The effect and the recommended parameters of these mitigation methods are further discussed. The research results show that the thermal stress and APB phenomena affect the stress distribution of the casing and may bring great danger to the wellbore integrity. Maintaining the APB in the safety range is necessary for field production. It is recommended that the annular pressure be kept below the critical value given in this paper. Injecting nitrogen in annulus A and installing rupture disks are both effective methods to improve casing safety. In the case study, the APB decrease percentage is more than 75% when nitrogen is injected in annulus A. However, the nitrogen pressure, the rupture pressure and the installation depth of the rupture disk need to be determined via casing safety evaluation. The effect of optimizing the steel grade and thickness of the tubing and casing is not significant. They can be used as assistance methods when other mitigation methods are adopted. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 4253 KiB

Open AccessArticle

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

by Fei Xu, Hanqiao Jiang, Ming Liu, Shuai Jiang, Yong Wang and Junjian Li

Processes 2023, 11(6), 1678; https://doi.org/10.3390/pr11061678 - 31 May 2023

Cited by 4 | Viewed by 875

Abstract

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on [...] Read more.

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T₂ distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T₁-T₂ maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T₁-T₂ maps. Finally, the T₁-T₂ maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 3316 KiB

Open AccessArticle

Estimation of Fracture Height in Tight Reserviors via a Finite Element Approach

by Jiujie Cai and Fengxia Li

Processes 2023, 11(5), 1566; https://doi.org/10.3390/pr11051566 - 21 May 2023

Cited by 1 | Viewed by 1159

Abstract

In tight reservoirs, the rock formations are typically less porous and permeable, which makes it more difficult for hydrocarbons to flow through them. In addition to length and conductivity, the height of a fracture is another critical parameter of the hydraulic fracturing treatments [...] Read more.

In tight reservoirs, the rock formations are typically less porous and permeable, which makes it more difficult for hydrocarbons to flow through them. In addition to length and conductivity, the height of a fracture is another critical parameter of the hydraulic fracturing treatments in unconventional tight/shale formations, which determines the stimulated reservoir volume. If the fracture height is too shallow, the volume of rock exposed to the fluid and proppant may not be sufficient to improve the reservoir’s production significantly. Conversely, if the fracture height is too deep, the injected fluid may not be able to propagate high enough to reach the desired formation. However, after years of research, fracture height has often been simplified in traditional or recent studies of fracture simulation and estimation. The objective of this work is to propose an innovative way to simulate the hydraulic fracturing process in both horizontal and vertical directions in tight formations with a well-built finite element numerical model. Fracture toughness

K_{I C}

is calculated based on the Brazilian test. Vertical fracturing fluid was also considered, and the model was validated by fracture height monitoring data from a stimulated well in the Montney formation. The influence of rock and fluid properties on the fracture height propagation was studied thoroughly with sensitivity analysis. The results indicated the fracture height prediction model was in good accordance with the monitoring data collected from the field, with an error margin of 7.2%. Sensitivity analysis results showed that a high Young’s modulus led to a larger stress intensity factor at the fracture tip, thus further advancing the fracture. Minimum horizontal stress also tends to facilitate the fracture to propagate. The influence of Poisson’s ratio and fluid viscosity on fracture height propagation was also investigated. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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24 pages, 4700 KiB

Open AccessArticle

Cenozoic Subsidence History of the Northern South China Sea: Examples from the Qiongdongnan and Yinggehai Basins

by Ming Ma, Jiafu Qi, Jinshan Ma, Heng Peng, Linlin Lei, Qian Song, Qing Zhang and Mengen Bai

Processes 2023, 11(3), 956; https://doi.org/10.3390/pr11030956 - 21 Mar 2023

Cited by 1 | Viewed by 1207

Abstract

The Qiongdongnan and Yinggehai Basins are important petroliferous basins. To study the Cenozoic subsidence characteristics of these two basins, their controlling factors, and their implications, we studied the basins’ subsidence characteristics via one-dimensional, two-dimensional, and holistic subsidence. Then, we compared the basins’ subsidence [...] Read more.

The Qiongdongnan and Yinggehai Basins are important petroliferous basins. To study the Cenozoic subsidence characteristics of these two basins, their controlling factors, and their implications, we studied the basins’ subsidence characteristics via one-dimensional, two-dimensional, and holistic subsidence. Then, we compared the basins’ subsidence characteristics based on the evolution of several particular geological processes that occurred in the South China Sea (SCS) and adjacent areas. The results indicated that the change in the holistic subsidence of both basins occurred episodically. In addition, the subsidence in these two basins differed, including their subsidence rates, the migration of the depocenters, and the changes in the holistic subsidence. The dynamic differences between the two basins were the main factors controlling the differences in the subsidence in the two basins. In the Qiongdongnan Basin, the subsidence characteristics were primarily controlled by the mantle material flowing under the South China Block in the Eocene and the spreading of the SCS from the Oligocene to the Miocene. In the Yinggehai Basin, the subsidence characteristics were primarily controlled by the coupling between the uplift of the Tibetan Plateau and the strike-slip motion of the Red River Fault before the Early Miocene and by only the effect of the strike-slip motion of the Red River Fault from the Middle Miocene to the Late Miocene. Since the Pliocene, the subsidence characteristics of both basins have been principally controlled by the dextral strike-slip motion of the Red River Fault. The major faults contributed to the spaciotemporal variations in the subsidence within each basin. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 5785 KiB

Open AccessArticle

Experimental Study of Acid Etching and Conductivity of High-Temperature-Resistant Cross-Linked Acid

by Hai Lin, Tengfei Hou, Fuguo Wang, Long Yue, Shiduo Liu, Guide Yuan, Guoqing Wang, Yong Liu, Qing Wang and Fujian Zhou

Processes 2023, 11(3), 722; https://doi.org/10.3390/pr11030722 - 28 Feb 2023

Cited by 1 | Viewed by 1260

Abstract

Acid fracturing is one of the effective techniques for developing low-permeability carbonate reservoirs economically. With the increasing reservoir depth, the reservoir temperature and closure pressure increase, posing new challenges to the acid system. In this paper, a high-temperature-resistant cross-linked acid system is selected, [...] Read more.

Acid fracturing is one of the effective techniques for developing low-permeability carbonate reservoirs economically. With the increasing reservoir depth, the reservoir temperature and closure pressure increase, posing new challenges to the acid system. In this paper, a high-temperature-resistant cross-linked acid system is selected, which maintains a viscosity above 80 mPa·s in the temperature range of 120 °C to 140 °C and can effectively reduce acid leak-off. The acid system can not only open the reservoir and ensure the extension of the fracture, but also reduce the reaction rate between the acid and the reservoir and increase the etching distance. The rock slab acid etching and conductivity tests show that the optimum injection rate is 50 mL/min, the rock etching morphology is channel type, and the conductivity remains above 110 D·cm. However, as the acid concentration decreases, the rock slab conductivity decreases considerably, especially at 10% acid concentration, where the closure pressure rises to 15 MPa, and there is almost no conductivity. In particular, after the acid system is broken, the reacted acid can form a filter cake on the core surface, hindering further intrusion of the residue into the core and reducing reservoir damage. The study shows that high-temperature-resistant cross-linked acid systems can effectively improve the stimulation of deeply fractured carbonate reservoirs at high temperatures. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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16 pages, 7672 KiB

Open AccessArticle

Case Study on the Effect of Acidizing on the Rock Properties of the Mahu Conglomerate Reservoir

by Lifeng Wang, Wenting Jia, Yajun Xu, Jianye Mou, Ze Liao and Shicheng Zhang

Processes 2023, 11(2), 626; https://doi.org/10.3390/pr11020626 - 18 Feb 2023

Viewed by 1189

Abstract

The development of the Mahu tight reservoir has adopted horizontal wells with staged fracturing. In the fracturing, there is a problem of a high fracturing pressure. Acid treatment is often used to lower the fracturing pressure on site. At present, the impact of [...] Read more.

The development of the Mahu tight reservoir has adopted horizontal wells with staged fracturing. In the fracturing, there is a problem of a high fracturing pressure. Acid treatment is often used to lower the fracturing pressure on site. At present, the impact of this acid treatment on the physical parameters of the rocks of the reservoir in the Mahu region has not been systematically studied. Aiming to solve this problem, this paper conducted an experimental study on how acid dissolution affects the physical properties of the Mahu conglomerate, including its porosity, permeability, triaxial rock mechanical parameters, tensile strength, and mineral composition. First, the experimental scheme was designed. Next, a series of experiments were conducted. Finally, the experiment results were analyzed comparatively before and after acidizing. The acid composition, concentration, and contact time were the main factors for the analysis, based on which the acid system and related parameters were recommended. This study showed that the Mahu conglomerate exhibited brittle plasticity characteristics under stress. The carbonate content in this region was low, while the feldspar content was high, so it was necessary to use mud acid to effectively dissolve feldspar, clay, and other silicates. After acidizing, the porosity was 200% of the original value. The permeability increased by up to 14 times. The tensile strength decreased significantly by up to 84%. The value of Young’s modulus of the rock decreased by up to 63.6%. The value of Poisson’s ratio was reduced by up to 40.7%. A combination of 6% HF + 15% HCl is recommended, with an effective acid treatment time of over 60 min for the Mahu conglomerate. Acidizing could significantly change the mechanical properties and permeability of the rock of the Mahu conglomerate reservoir, thus effectively reducing the formation fracturing pressure. This research provides technical support for Mahu acid dipping in horizontal well fracturing. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 25403 KiB

Open AccessArticle

Preparation of Polymer Solution for Profile Control and Displacement Using Wastewater with High Ca²⁺/Mg²⁺ and Fe²⁺ Concentrations

by Xuanran Li, Anzhu Xu, Mengqi Ma, Shanglin Liu, Jun Ni and Lun Zhao

Processes 2023, 11(2), 325; https://doi.org/10.3390/pr11020325 - 19 Jan 2023

Viewed by 1164

Abstract

In the present study, we used Kalamkas, which is a typical Kazakhstani oilfield, which produces wastewater with high Ca²⁺/Mg²⁺ and Fe²⁺ concentrations, as a case study. We investigated a method for preparing Fe²⁺ polymer solutions without oxygen isolation [...] Read more.

In the present study, we used Kalamkas, which is a typical Kazakhstani oilfield, which produces wastewater with high Ca²⁺/Mg²⁺ and Fe²⁺ concentrations, as a case study. We investigated a method for preparing Fe²⁺ polymer solutions without oxygen isolation under the conditions of salinity >110 × 10³ mg/L, Ca²⁺/Mg²⁺ concentration >7000 mg/L, and Fe²⁺ concentration >30 mg/L. Fe²⁺-resistant groups were grafted onto the molecular chains of a hydrophobically associating polymer prepared using existing synthesis technology to overcome the decrease in apparent viscosity of the polymer solution due to the oxidation of Fe²⁺ during solution preparation. The experiments showed that PAM-IR with iron-resistant groups can be completely dissolved in the wastewater within 180 min, and can tolerate an NaCl concentration of up to 0.23 × 10⁶ mg/L, a Ca²⁺ concentration of up to 10 × 10³ mg/L, an Mg²⁺ concentration of up to 9 × 10³ mg/L, and a Fe²⁺ concentration of up to 90 mg/L, with favorable thickening performance and resistances to NaCl, Ca²⁺, Mg²⁺, and Fe²⁺. PAM-IR has good injection performance and can establish a high resistance factor (F_R) and residual resistance factor (F_RR) to increase the sweep efficiency. Therefore, it is potentially useful for enhancing oil recovery. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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19 pages, 8688 KiB

Open AccessArticle

Change Characteristics of Heavy Oil Composition and Rock Properties after Steam Flooding in Heavy Oil Reservoirs

by Ting Huang, Kai Peng, Wenzhi Song, Changpeng Hu and Xiao Guo

Processes 2023, 11(2), 315; https://doi.org/10.3390/pr11020315 - 18 Jan 2023

Cited by 2 | Viewed by 1106

Abstract

The thermal recovery method of steam flooding is one of the most common development methods for heavy oil reservoirs. However, after multiple rounds of steam injection development, the composition of crude oil and reservoir rock properties have changed greatly, which is unfavorable for [...] Read more.

The thermal recovery method of steam flooding is one of the most common development methods for heavy oil reservoirs. However, after multiple rounds of steam injection development, the composition of crude oil and reservoir rock properties have changed greatly, which is unfavorable for the subsequent enhanced oil recovery. It is necessary to study the distribution of the remaining oil after the thermal recovery of heavy oil reservoirs, and clarify the change characteristics of the components of the crude oil under different steam injection conditions. At the same time, the change of porosity and the permeability of the rocks after steam flooding, and its influence on oil recovery, are investigated. In this paper, the composition changes of heavy oil before and after steam flooding are studied through experiments and numerical simulation methods. A numerical model is established to study the retention characteristics of heavy components in heavy oil reservoirs by the CMG software. The effects of different steam injection conditions, and heavy oil with different components on the residual retention of heavy components, are compared and studied. The changes of rock physical properties in heavy oil reservoirs after steam flooding is clarified. The results show that after steam flooding, the heavy components (resin and asphaltenes) of the recovered oil decrease, and the heavy components in the formation increase in varying degrees. With the increase of heavy components in the crude oil, the remaining oil in the formation increases after steam flooding, and the retention of heavy components increases; after steam flooding, the stronger the rock cementation strength, the higher the degree of reserve recovery, and it is difficult to form breakthrough channels; the greater the steam injection intensity, the earlier to see steam breakthrough in the production well, and the lower the degree of reserve recovery. The research reveals the changes of heavy oil components and rock properties after steam flooding, providing support for the subsequent enhanced oil recovery. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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16 pages, 6115 KiB

Open AccessArticle

Numerical Simulation Research on the Effect of Artificial Barrier Properties on Fracture Height

by Jian Zou, Ying Zhang, Liping Zhang, Jiyun Jing, Yangyang Fu, Yunjin Wang, Guchang Zhang and Fujian Zhou

Processes 2023, 11(2), 310; https://doi.org/10.3390/pr11020310 - 17 Jan 2023

Cited by 5 | Viewed by 1103

Abstract

Hydraulic fracturing is an important measurement for the stimulation of oil and gas wells and is widely used in the development of low-permeability and ultra-low-permeability reservoirs. However, fractures can pass through barriers with poor properties during fracturing, resulting in fractures that do not [...] Read more.

Hydraulic fracturing is an important measurement for the stimulation of oil and gas wells and is widely used in the development of low-permeability and ultra-low-permeability reservoirs. However, fractures can pass through barriers with poor properties during fracturing, resulting in fractures that do not reach the pre-designed length. In a worse situation, it is possible to communicate with the water layer and cause sudden water flooding, resulting in the failure of the fracturing construction. In order to improve the efficiency of fracturing construction, an effective way to control the height of fractures is by laying diverting agents to form artificial barriers. In this study, we established a three-dimensional numerical calculation model of fracture propagation, considering artificial barriers in the finite element analysis framework; the fracture propagation is governed by a cohesive zone model. The influence of artificial barriers with different Young’s modulus and different permeability on the fracture height was simulated and calculated. Different fracture geometries under different pumping injection rates were also considered. The simulation results show that the smaller the Young’s modulus of the artificial barrier, the smaller the extension in the direction of the fracture height: when its Young’s modulus is 28 GPa, the half fracture height is about 25 m, while when Young’s modulus increases to 36 GPa, the half fracture height increases by about 10m. When the fracture does not penetrate the artificial barrier area, the larger the Young’s modulus, the smaller the fracture width and the larger the fracture height. With the change in the permeability of the artificial barrier, the change in the fracture width direction of the fracturing fracture is only about 0.5 m, but the inhibition on the fracture height direction is more obvious; in the case of maximum permeability and minimum permeability, the fracture height change is 10 m. The influence of pumping injection rates on the width and height of the fracture is obvious: with the increase in the pumping rates, both the height and width of the fractures increase. However, when the pumping rate increases from 0.12 m³/s to 0.14 m³/s, the change in the direction of fracture height is no longer significant, and the increase is only 0.6 m. This study investigates the role of artificial barrier properties and pumping rates in controlling fracture height extension, clarifies the feasibility of artificial barriers to control fracture height technology, and provides guidance for the selection of diverting agents and the determination of the pumping rate in the process of fracturing construction. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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13 pages, 6329 KiB

Open AccessArticle

Study on Salt Dissolution Law of High Salinity Reservoir and Its Influence on Fracturing

by Liyan Pan, Lei Wang, Weijie Zheng, Feipeng Han, Ariya Zibibula, Zhenlong Zhu and Shengxiang Li

Processes 2023, 11(2), 304; https://doi.org/10.3390/pr11020304 - 17 Jan 2023

Viewed by 1061

Abstract

For the high-salt reservoir of the Fengcheng Formation in the Mahu area, the production decreases rapidly due to the conductivity decrease after fracturing. The analysis shows that this has a great relationship with the special salt dissolution characteristics of the High salinity reservoir. [...] Read more.

For the high-salt reservoir of the Fengcheng Formation in the Mahu area, the production decreases rapidly due to the conductivity decrease after fracturing. The analysis shows that this has a great relationship with the special salt dissolution characteristics of the High salinity reservoir. In order to study the problem of salt dissolution pattern, the effect of different temperatures, the salt concentration of fracturing fluid, the viscosity of fracturing fluid, and injection rate on the rate of salt dissolution was evaluated by using the dynamic experimental evaluation method of salt dissolution. Through the grey correlation analysis of salt rock dissolution rate, it can be found that the degree of influence is from large to small which the influence of temperature is greater than fracturing fluid velocity, followed by fracturing fluid viscosity and, finally, fracturing fluid salt concentration. The results of compressive strength tests on salt-bearing rocks after dissolution show that the compressive strength is greatly reduced after salt dissolution by more than 60%. At the same time, the test results of proppant-free conductivity showed that the conductivity increased first and then decreased sharply after salt dissolution. This shows that in the early stage of salt dissolution, the flow channel will increase through dissolution. The rock strength decreases greatly with the increase of salt dissolution. As a result, collapse leads to a sharp reduction in the facture conductivity. Therefore, it is necessary to choose saturated brine fracturing fluid. In the proppant conductivity experiments, by optimizing the use of saturated brine fracturing fluid with 30/50 mesh or 20/40 mesh ceramic proppant with a sand concentration of 5 Kg/m², a high facture conductivity can be achieved under high closure pressure conditions. Based on the above study, directions and countermeasures for improving high saline reservoirs are proposed, which point the way to improve the fracturing conductivity. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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13 pages, 6189 KiB

Open AccessArticle

A New Model of Temperature Field Accounting for Acid–Rock Reaction in Acid Fracturing in Shunbei Oilfield

by Jianye Mou, Jiayuan He, Haiqian Zheng, Rusheng Zhang, Lufeng Zhang and Budong Gao

Processes 2023, 11(1), 294; https://doi.org/10.3390/pr11010294 - 16 Jan 2023

Cited by 1 | Viewed by 1375

Abstract

The Shunbei oil formation is a deep, high-temperature carbonate reservoir. Acid fracturing is an effective technology to stimulate this formation. For acid fracturing, the temperature field is fundamental information for the acid system selection, acid–rock reaction, live acid penetration distance prediction, acid fracturing [...] Read more.

The Shunbei oil formation is a deep, high-temperature carbonate reservoir. Acid fracturing is an effective technology to stimulate this formation. For acid fracturing, the temperature field is fundamental information for the acid system selection, acid–rock reaction, live acid penetration distance prediction, acid fracturing design, etc. Therefore, in this paper, we conduct a numerical study on the temperature field in acid fracturing to account for the acid–rock reaction in the Shunbei formation. Firstly, a new mathematical model of the fracture temperature field during acid fracturing is established based on the laws of mass and energy conservation and acid–rock reaction kinetics. The fracture model is based on a PKN model, which accounts for a few factors, such as the acid–rock reaction heat, acid–rock reaction rate dependence on the temperature, and the fracture width change with acid erosion. Then, the numerical mode is developed. Next, an extensive numerical study and a parameter analysis are conducted based on the model with the field data from the Shunbei formation. The study shows that the acid–rock reaction in acid fracturing has obvious effects on the temperature field, resulting in a 10~20 °C increase in the Shunbei formation. The acid–rock reaction dependence on temperature is a factor to be accounted for. The rock dissolution increases first and then decreases from the inlet to the tip of the fracture, unlike the monotonous decrease without temperature dependence. The temperature gradient is high near the inlet and then decreases gradually. Beyond half of the fracture, the temperature is close to the formation temperature. The temperature drops fast in the initial injection stage and tends to stabilize at about 50 min. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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11 pages, 3380 KiB

Open AccessArticle

Case Study: Successful Application of a Novel Gas Lift Valve in Low Pressure Wells in Fuling Shale Gas Field

by Qiaoping Liu, Jingfei Tang, Wenqi Ke, Haibo Wang and Uzezi Davis Orivri

Processes 2023, 11(1), 19; https://doi.org/10.3390/pr11010019 - 22 Dec 2022

Cited by 2 | Viewed by 1751

Abstract

The Fuling shale gas field is facing a rapid gas production decline due to heavy liquid loading issues. Given the condition that most wells are located at remote areas in the mountains, the traditional gas lift methods that require either fixed compressor or [...] Read more.

The Fuling shale gas field is facing a rapid gas production decline due to heavy liquid loading issues. Given the condition that most wells are located at remote areas in the mountains, the traditional gas lift methods that require either fixed compressor or skid-mounted gas lift trucks do not seem feasible and occur high operation costs. A new type of gas lift valve that can be opened or closed at a low valve dome pressure indicates the high sensitivity to low production pressure. Thus, the piping line pressure can be utilized to activate the valve due to its new advantages. In addition, the specially designed structure of the gas lift valve can be activated via pressure increases in the tubing to create a channel between the tubing and annulus. The valve that previously functioned as a dummy valve was then switched to a gas lift valve. Field application results show that all wells were successfully restarted by only utilizing the low piping pressure, and loaded liquid was lifted with gas production at an incremental rate that reached up to 27.4 × 10 kscm/d per well. Fewer slickline operations were conducted to replace the dummy valve. The result of the application shows that the new type of gas lift system has a wide range of application prospect for low pressure wells, especially for shale gas wells. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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17 pages, 4335 KiB

Open AccessArticle

Study on the Flow Pattern and Transition Criterion of Gas-Liquid Two-Phase Flow in the Annular of Shale Gas Fractured Horizontal Wells

by Yu Lei, Zhenghua Wu, Wei Wang, Jian Wu and Bin Ma

Processes 2022, 10(12), 2630; https://doi.org/10.3390/pr10122630 - 07 Dec 2022

Viewed by 1118

Abstract

Improving the accuracy of pressure prediction in the wellbore annular is of great importance for the design in oil and gas production. However, due to the existence of double-layer liquid membrane and the lack of relevant experiments, the existing correlations fail to the [...] Read more.

Improving the accuracy of pressure prediction in the wellbore annular is of great importance for the design in oil and gas production. However, due to the existence of double-layer liquid membrane and the lack of relevant experiments, the existing correlations fail to the field application. In this study, a new model of flow pattern transition in inclined annulus pipe is proposed by using a mechanistic approach to classify the flow patterns. Firstly, a gas-liquid two-phase flow experiment in annulus pipe was carried out in a pipe with an outer diameter of 73.02 mm and an inner diameter of 121.36 mm, and then the influence of inclined angle on the transition boundary of flow pattern is discussed. Finally, a hydrodynamic transition criterion for the flow pattern model of inclined annulus pipe is established and verified in detail. The experimental results show that bubble flow, slug flow, churn flow and annular flow were observed under different inclination angles, and the results indicate that the slug flow will be shifted to the larger gas-liquid superficial flow rate region with the smaller inclination angle, and the annular flow will appear in the higher gas superficial flow rate region. Compared to the performance of the existing correlations (Kelessidis and Zhang) and the present model using the experimental data, the accuracy of the new model reached 83%, significantly higher than the other two models, and the new correlation was better in predicting the transition from slug flow to churn flow and churn flow to annular flow. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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10 pages, 1905 KiB

Open AccessArticle

Study on the Influence of Pressure Reduction and Chemical Injection on Hydrate Decomposition

by Lei Wang, Zhikang Song, Xin Huang, Wenjun Xu and Zhengbang Chen

Processes 2022, 10(12), 2543; https://doi.org/10.3390/pr10122543 - 29 Nov 2022

Cited by 2 | Viewed by 1114

Abstract

This study simulated seabed high pressure and low temperature conditions to synthesize natural gas hydrates, multi-stage depressurization mode mining hydrates as the blank group, and then carried out experimental research on the decomposition and mining efficiency of hydrates by depressurization and injection of [...] Read more.

This study simulated seabed high pressure and low temperature conditions to synthesize natural gas hydrates, multi-stage depressurization mode mining hydrates as the blank group, and then carried out experimental research on the decomposition and mining efficiency of hydrates by depressurization and injection of different alcohols, inorganic salts, and different chemical agent concentrations. According to the experimental results, the chemical agent with the best decomposition efficiency is preferred; the results show that: the depressurization and injection of a certain mass concentration of chemical agents to exploit natural gas hydrate is more effective than pure depressurization to increase the instantaneous gas production rate. This is because depressurization combined with chemical injection can destroy the hydrate phase balance while effectively reducing the energy required for hydrate decomposition, thereby greatly improving the hydrate decomposition efficiency. Among them, depressurization and injection of 30% ethylene glycol has the best performance in alcohols; the decomposition efficiency is increased by 52.0%, and the mining efficiency is increased by 68.2% within 2 h. Depressurization and injection of 15% calcium chloride has the best performance in inorganic salts; the decomposition efficiency is increased by 46.3%, and the mining efficiency is increased by 61.1% within 2 h. In the actual mining process, the appropriate concentration of chemical agents should be used to avoid polluting the environment. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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12 pages, 1915 KiB

Open AccessArticle

Investigation of the Vertical Propagation Pattern of the 3D Hydraulic Fracture under the Influence of Interlayer Heterogeneity

by Bingqian Wan, Yancheng Liu, Bo Zhang, Shuai Luo, Leipeng Wei, Litao Li and Jiang He

Processes 2022, 10(11), 2449; https://doi.org/10.3390/pr10112449 - 18 Nov 2022

Cited by 4 | Viewed by 1049

Abstract

The low permeability and thinly interbedded reservoirs have poor physical properties and strong interbedded heterogeneity, and it is difficult to control the hydraulic fracture (HF) height and width during hydraulic fracturing, which affects the effect of HF penetration and sand addition. In this [...] Read more.

The low permeability and thinly interbedded reservoirs have poor physical properties and strong interbedded heterogeneity, and it is difficult to control the hydraulic fracture (HF) height and width during hydraulic fracturing, which affects the effect of HF penetration and sand addition. In this work, a three-dimensional fluid–solid fully coupled HF propagation model is established to simulate the influence of interlayer heterogeneity on vertical HF height and HF width, and the relationship between HF length and HF width under different treatment parameters is further studied. The results show that, in thin interbedded strata, the high interlayer stress contrast, high tensile strength, and low Young’s modulus will inhibit the vertical propagation of HFs. The interlayer heterogeneity results in the vertical wavy distribution of HF width. Under the high interlayer stress contrast, Young’s modulus, and tensile strength, the HF width profile becomes narrow and the variation amplitude decreases. The HF length decreases and the HF width increases as the injection rate and fracturing fluid viscosity increase. This study is of great significance for clarifying the vertical propagation pattern in thinly interbedded reservoirs, optimizing the treatment parameters, and improving the effect of cross fracturing and proppant distribution. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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11 pages, 1980 KiB

Open AccessArticle

Research on Gas Channeling Identification Method for Gas Injection Development in High-Pressure Heterogeneous Reservoir

by Juan Luo and Lei Wang

Processes 2022, 10(11), 2366; https://doi.org/10.3390/pr10112366 - 11 Nov 2022

Cited by 1 | Viewed by 1233

Abstract

In a typical ultra-deep high-temperature and high-pressure heterogeneous reservoir in Xinjiang, gas channeling quickly occurs during gas injection because of the heterogeneity of the reservoir, the low viscosity of gas injection, and the high gas-oil fluidity ratio. The identification and prediction methods of [...] Read more.

In a typical ultra-deep high-temperature and high-pressure heterogeneous reservoir in Xinjiang, gas channeling quickly occurs during gas injection because of the heterogeneity of the reservoir, the low viscosity of gas injection, and the high gas-oil fluidity ratio. The identification and prediction methods of gas channeling in gas injection development were studied. First, gas channeling discrimination parameters were determined by the numerical simulation method. According to the ratio of gas to oil produced and the composition of oil and gas produced, the flow stages of formation fluid were divided into five regions: gas phase zone, two-phase zone, miscible zone, dissolved gas and oil zone, and original oil zone. The basis for gas channeling identification (namely, the field characterization parameters for gas channeling discrimination) was discovered through analysis and the knowledge of the operability of field monitoring data as the following two parameters: (1) the C1 content rising again on the previous platform when the trailing edge of the two-phase zone is produced and (2) the continuous rise of the gas-oil ratio in production. Then, considering the original high-pressure characteristics of the reservoir, the field characterization parameters of gas channeling under different formation pressures in the exploitation process (namely, C1 content and gas-oil ratio) were simulated and determined. Thus, a gas channeling discrimination method was established for gas injection development in ultra-deep high-temperature and high-pressure heterogeneous reservoirs. According to this gas injection approach, a gas channeling discrimination method was developed, and the field gas channeling judgment was carried out for a gas injection effective D1 well. The results of gas tracer detection were compared to verify the accuracy of this method, leading to strong support for this method in slowing down the gas channeling. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 2179 KiB

Open AccessArticle

Numerical Simulation of Hydraulic Fracturing and Penetration Law in Continental Shale Reservoirs

by Yanxin Zhao, Lei Wang, Kuo Ma and Feng Zhang

Processes 2022, 10(11), 2364; https://doi.org/10.3390/pr10112364 - 11 Nov 2022

Cited by 4 | Viewed by 1080

Abstract

The vertical heterogeneity of continental shale reservoirs is strong, the difference between lithology and stress between layers is large, the weak interface between layers develops, and the hydraulic fracture penetration and expansion are difficult, resulting in poor fracturing transformation effect. In view of [...] Read more.

The vertical heterogeneity of continental shale reservoirs is strong, the difference between lithology and stress between layers is large, the weak interface between layers develops, and the hydraulic fracture penetration and expansion are difficult, resulting in poor fracturing transformation effect. In view of this, based on the finite element and cohesive element method, this paper established a fluid-solid coupling model for the hydraulic fracture propagation through the continental shale and studied the control mechanism and influence law of various geological and engineering parameters on the hydraulic fracture propagation through the continental shale reservoir using single factor and orthogonal test analysis methods. Interfacial cementation strength between high layers, high vertical stress difference, low interlaminar stress difference, low tensile strength difference, low elastic modulus difference, high pressure fracturing fluid viscosity, and high injection displacement are conducive to the penetration and expansion of hydraulic fractures. The primary and secondary order of influence degree of each factor is: interlaminar interface cementation strength > interlaminar stress difference/tensile strength difference > fracturing fluid viscosity/injection displacement > vertical stress difference > elastic modulus. In addition, engineering application research has also been carried out, and it is recommended that the injection displacement during early construction should not be less than 3 m³/min, and the fracturing viscosity should not be less than 45 mPa·s. The field application effect is good, which verifies the engineering application value of the model. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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8 pages, 1300 KiB

Open AccessFeature PaperArticle

Investigation on the Injection Pattern of Intermittent Natural Gas Flooding in Ultra-Low Permeability Reservoirs

by Lifei Dong, Linxiang Li, Wenzhuo Dong, Miao Wang and Xiaozhi Chen

Processes 2022, 10(11), 2198; https://doi.org/10.3390/pr10112198 - 26 Oct 2022

Cited by 2 | Viewed by 951

Abstract

Natural gas is a viable oil displacement agent in ultra-low-permeability reservoirs due to its good fluidity. It can also cause gas channeling during continuous injection, which limits its oilfield application. In order to relieve gas channeling during natural gas flooding, the injection mode [...] Read more.

Natural gas is a viable oil displacement agent in ultra-low-permeability reservoirs due to its good fluidity. It can also cause gas channeling during continuous injection, which limits its oilfield application. In order to relieve gas channeling during natural gas flooding, the injection mode should be changed. The use of intermittent natural gas injection (IGI) after the continuous natural gas injection in an ultra-low-permeability reservoir is proposed, and optimization of the injection parameters is discussed. The results show that IGI can be divided into three stages, the gas injection stage, the well shutting stage and the oil production stage. With the increase in injection time, the oil recovery enhances obviously as a result of IGI because the gas fingering can be controlled at the well shutting stage, and the gas/liquid ratio grows slowly because the gas breakthrough can be reduced at the oil production stage. The oil recovery improves with the increase in cycle time of IGI, while the increase rate reduces evidently after the cycle time reaches 360 min. The oil recovery increment is low if the cycle index exceeds 3 in the ultra-low-permeability reservoir. Thus, the optimal cycle time for each round and the appropriate cycle index of IGI are 360 min and three rounds. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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14 pages, 3611 KiB

Open AccessArticle

Development and Performance Evaluation of Scale-Inhibiting Fracturing Fluid System

by Miao Zheng, Lianqi Sheng, Hongda Ren, Abulimiti Yiming, Erdong Yao, Kun Zhang and Longhao Zhao

Processes 2022, 10(10), 2135; https://doi.org/10.3390/pr10102135 - 20 Oct 2022

Cited by 1 | Viewed by 1383

Abstract

The injection water and formation water in the Mahu oil field have high salinity and poor compatibility, which leads to scaling and blockage in the formation or fracture propping zone during production. In this paper, a scale-inhibiting fracturing fluid system is developed which [...] Read more.

The injection water and formation water in the Mahu oil field have high salinity and poor compatibility, which leads to scaling and blockage in the formation or fracture propping zone during production. In this paper, a scale-inhibiting fracturing fluid system is developed which can prevent the formation of scale in the reservoir and solves the problem of scaling in the fracture propping zone at the Mahu oil field. Firstly, based on scale-inhibition rate, the performances of six commercial scale inhibitors were evaluated, including their acid and alkali resistance and temperature resistance. Then, the optimal scale inhibitors were combined with the fracturing fluid to obtain a scale-inhibiting fracturing fluid system. Its compatibility with other additives and scale-inhibition performance were evaluated. Finally, the system’s drag-reduction ability was tested through the loop friction tester. The results showed that, among the six scale inhibitors, the organic phosphonic acid scale inhibitor SC-1 has the best performance regardless of high-temperature, alkaline, and mixed scale conditions. In addition, SC-1 has good compatibility with the fracturing fluid. The scale-inhibiting fracturing fluid system can effectively prevent scaling inside the large pores in the propping zone, and a scale-inhibiting efficiency of 96.29% was obtained. The new fracture system maintained a drag-reduction efficiency of about 75%, indicating that the addition of the scale inhibitor did not cause a significant influence on the drag-reduction efficiency of the fracturing fluid. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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20 pages, 9245 KiB

Open AccessArticle

Numerical Simulation Study on the Flow Properties of Materials for Plugging While Drilling in MWD

by Lei Pu, Peng Xu, Mingbiao Xu, Jun Zhou, Qinglin Liu and Jianjian Song

Processes 2022, 10(10), 1955; https://doi.org/10.3390/pr10101955 - 28 Sep 2022

Cited by 1 | Viewed by 1626

Abstract

The method of plugging while drilling has been one of the commonly used methods to control formation loss during drilling. The damage to materials for plugging while drilling to MWD has become a complex problem. For many years, field engineers had insufficient knowledge [...] Read more.

The method of plugging while drilling has been one of the commonly used methods to control formation loss during drilling. The damage to materials for plugging while drilling to MWD has become a complex problem. For many years, field engineers had insufficient knowledge of the passing performance of materials for plugging while drilling in measurement while drilling (MWD). In the existing research, the blocking mechanism of materials for plugging while drilling to mud screen during the flow process is still unclear. In this study, we use computational fluid dynamics coupled with discrete element method (CFD–DEM) to investigate materials’ plugging mechanism while drilling. The results show that the migration process of lost circulation materials (LCMs) in the mud screen can be divided into three stages, displacement, retention, and accumulation of LCMs. The blocking mechanism of LCMs on the mud screen comes from two aspects. One is from the bridging of LCMs with larger particle size in the holes of the mud screen. Another source is the difference between the entry speed and the overflow speed of LCMs. The particle size and mass fraction of LCMs and the viscosity and displacement of the fluid affect the flow properties of LCMs from these two factors, respectively. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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12 pages, 3320 KiB

Open AccessArticle

Acid System and Stimulation Efficiency of Multistage Acid Fracturing in Porous Carbonate Reservoirs

by Dawei Zhu, Yunjin Wang, Mingyue Cui, Fujian Zhou, Yaocong Wang, Chong Liang, Honglan Zou and Fei Yao

Processes 2022, 10(9), 1883; https://doi.org/10.3390/pr10091883 - 17 Sep 2022

Cited by 9 | Viewed by 1607

Abstract

With little to no natural fracture development and the high calcite content in porous carbonate reservoirs, for multistage acid fracturing, different fluids are used to form a viscous fingering in the fracture, thus enhancing the degree of nonuniform etching. However, existing studies on [...] Read more.

With little to no natural fracture development and the high calcite content in porous carbonate reservoirs, for multistage acid fracturing, different fluids are used to form a viscous fingering in the fracture, thus enhancing the degree of nonuniform etching. However, existing studies on multistage acid fracturing mainly focused on the combination of fracturing fluid and acid, which is less specific for porous carbonate rocks. Here, the rheological properties of five fluids, including guar-based fluid, cross-linked guar, gelled acid, cross-linked acid, and diverting acid, were studied at each temperature condition, and the viscosity relationship between each fluid was clarified. Based on the rheological properties, the differences between the seven liquid combinations on the etched morphology of the fracture walls were studied and analyzed. The conductivity of the seven acid-etched fractures under different closure stress was simulated. The experimental results showed that the viscosity relationships between the fluids at different temperatures were cross-linked guar > cross-linked acid > diverting acid (spent acid) > gelled acid > guar-based liquid > diverting acid (fresh acid). Because cross-linked acid has higher viscosity than gelled acid, it can form more obvious viscous fingering with a variety of liquids, which is more suitable for acid fracturing stimulation of porous carbonate reservoirs. In addition, the combination of cross-linked and diverting acids was screened out. The multistage alternate injection of this fluid combination could form tortuous and complex etching channels, and its acid-etching fracture conductivity was significantly higher than that of other fluid combinations at different closure stress. In this study, we optimized the fluid combination of porous carbonates and clarified the effect and mechanism of nonuniform etching to provide guidance for the fluid combination selection of multistage alternate acid fracturing process for porous carbonate reservoirs. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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13 pages, 5803 KiB

Open AccessArticle

Numerical Investigation on Injected-Fluid Recovery and Production Performance following Hydraulic Fracturing in Shale Oil Wells

by Kai Liao, Jian Zhu, Xun Sun, Shicheng Zhang and Guangcong Ren

Processes 2022, 10(9), 1749; https://doi.org/10.3390/pr10091749 - 02 Sep 2022

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Abstract

Currently, volume fracturing of horizontal wells is the main technology for shale oil development. A large amount of fracturing fluid is injected into the formation, but the flowback efficiency is very low. Besides, the impact of fluid retention on productivity is not fully [...] Read more.

Currently, volume fracturing of horizontal wells is the main technology for shale oil development. A large amount of fracturing fluid is injected into the formation, but the flowback efficiency is very low. Besides, the impact of fluid retention on productivity is not fully clear. There is still a debate about fast-back or slow-back after fracturing, and the formulation of a reasonable cleanup scheme is lacking a theoretical basis. To illustrate the injected-fluid recovery and production performance of shale oil wells, an integrated workflow involving a complex fracture model and oil-water production simulation was presented, enabling a confident history match of flowback data. Then, the impacts of pumping rate, slick water ratio, cluster spacing, stage spacing and flowback rate were quantitatively analyzed. The results show that the pumping rate is negatively correlated with injected-fluid recovery, but positively correlated with oil production. A high ratio of slick water would induce a quite complex fracture configuration, resulting in a rather low flowback efficiency. Meanwhile, the overall conductivity of the fracture networks would also be reduced, as well as the productivity, which indicates that there is an optimal ratio for hybrid fracturing fluid. Due to the fracture interference, the design of stage or cluster spacing is not the smaller the better, and needs to be combined with the actual reservoir conditions. In addition, the short-term flowback efficiency and oil production increase with the flowback rate. However, considering the damage of pressure sensitivity to long-term production, a slow-back mode should be adopted for shale oil wells. The study results may provide support for the design of a fracturing scheme and the optimization of the flowback schedule for shale oil reservoirs. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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17 pages, 9989 KiB

Open AccessArticle

Fracture Characteristics and Distribution in Slant Core from Conglomerate Hydraulic Fracturing Test Site (CHFTS) in Junggar Basin, Northwest China

by Shanzhi Shi, Renyan Zhuo, Leiming Cheng, Yuankai Xiang, Xinfang Ma and Tao Wang

Processes 2022, 10(8), 1646; https://doi.org/10.3390/pr10081646 - 19 Aug 2022

Cited by 3 | Viewed by 1520

Abstract

Hydraulic fracture networks, especially fracture geometry, height growth, and proppant transport within the networks, present a critical influence on productivity evaluation and optimization of fracturing parameters. However, information about hydraulic fracture networks in post-fractured formations is seldom available. In this study, the characteristics [...] Read more.

Hydraulic fracture networks, especially fracture geometry, height growth, and proppant transport within the networks, present a critical influence on productivity evaluation and optimization of fracturing parameters. However, information about hydraulic fracture networks in post-fractured formations is seldom available. In this study, the characteristics (density and orientation) of hydraulic fractures were obtained from field observations of cores taken from conglomerate hydraulic fracturing test site (CHFTS). A large number of fractures were observed in the cores, and systematic fracture description was carried out. The fracture analysis data obtained includes fracture density, fracture depth, fracture orientation, morphology, fracture surface features, apertures, fill, fracture mechanical origin (type), etc. Our results show that 228 hydraulic fractures were intersected in a span of 293.71 m of slant core and composed of irregularly spaced single fractures and fracture swarms. One of the potential sources of the observed fracture swarms is near-wellbore tortuosity. Moreover, for regions far away from the wellbore, reservoir heterogeneity can promote complex hydraulic fracture trajectories. The hydraulic fractures were mainly cross-gravel and high-angle fractures and align with maximum horizontal stress (S_Hmax) ± 15°. The fracture density, orientations, and types obtained from the core fracture description provided valuable information regarding fracture growth behavior. For the near-wellbore area with a transverse distance of less than 25 m from the hydraulically-fractured wellbore, tensile fractures were dominant. While for the area far away from the wellbore, shear fractures were dominant. Our results provide improved understanding of the spatial hydraulic fracture dimensions, proppant distribution, and mechanism of hydraulic fracture formation. The dataset acquired can also be used to calibrate numerical models and characterize hydraulic fracture geometry and proppant distribution. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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19 pages, 28396 KiB

Open AccessArticle

Optimization of Water Injection Strategy before Re-Stimulation Considering Fractures Propagation

by Guangcong Ren, Xinfang Ma, Shicheng Zhang, Yushi Zou, Guifu Duan and Qiyong Xiong

Processes 2022, 10(8), 1538; https://doi.org/10.3390/pr10081538 - 05 Aug 2022

Cited by 1 | Viewed by 1445

Abstract

Water injection before re-stimulation has a positive effect to mitigate the “frac hit” and increase oil production in tight reservoirs. However, the study of water injection strategy optimization has not been thoroughly investigated. Some conclusions can be found in the existing literature, but [...] Read more.

Water injection before re-stimulation has a positive effect to mitigate the “frac hit” and increase oil production in tight reservoirs. However, the study of water injection strategy optimization has not been thoroughly investigated. Some conclusions can be found in the existing literature, but the pressure and stress distribution, fractures morphology and oil production were not considered as a whole workflow during the study. In addition, the different reservoir deficit was not considered. Although technical experience and economic benefit have been obtained in some field tests, failed cases still exist. To fill this gap, a series of numerical models are established based on a tight reservoir located in northwest China. Under the different re-stimulation timing, the pressure distribution, stress distribution, and fractures morphology after water injection of different injection/production ratios are calculated, respectively. The oil and water production are predicted. The results show that, after a short period of production with a small deficit, the degree of “frac hit” is slight. Injecting water has an obvious effect on increasing oil production for both parent and infill well. After a long period of production with a large deficit, the problem of “frac hit” is very severe. Injecting water has an obvious effect on increasing oil production only for the parent well. The production of infill well is influenced by the fractures’ interference and pressure increasing comprehensively. For the well group, measured by the final cumulative oil production, the optimal injection/production ratio is different, but the water injection volume is similar, which is about 15,000 m³. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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15 pages, 5028 KiB

Open AccessFeature PaperArticle

Study and Mechanism Analysis on Dynamic Shrinkage of Bottom Sediments in Salt Cavern Gas Storage

by Baocheng Wu, Mengchuan Zhang, Weibing Deng, Junren Que, Wei Liu, Fujian Zhou, Qing Wang, Yuan Li and Tianbo Liang

Processes 2022, 10(8), 1511; https://doi.org/10.3390/pr10081511 - 01 Aug 2022

Cited by 3 | Viewed by 1347

Abstract

Underground salt cavern gas storage is the best choice for the production peak adjustment and storage of natural gas, and is a basic means to ensure the safe supply of natural gas. However, in the process of these caverns dissolving due to water [...] Read more.

Underground salt cavern gas storage is the best choice for the production peak adjustment and storage of natural gas, and is a basic means to ensure the safe supply of natural gas. However, in the process of these caverns dissolving due to water injection, argillaceous insoluble sediments in the salt layer will fall to the bottom of the cavity and expand, occupying a large amount of the storage capacity and resulting in the reduction of the actual gas storage space. Effectively reducing the volume of sediments at the bottom of the cavity is a potential way to expand the storage capacity of the cavity. In this study, a method to reduce the volume of argillaceous insoluble sediments with particle sizes ranging from 10 mesh to 140 mesh, via a chemical shrinkage agent, has been proposed. Firstly, the inorganic polymer shrinkage agent PAC30 was synthesized, and then a set of dynamic shrinkage evaluation methods was established to evaluate the influence of temperature, particle size, concentration, and other factors on the shrinkage performance. Finally, by means of a scanning electron microscope (SEM), the Zeta potential, and static adsorption experiments, the mechanism of the interaction between PAC30 and cavity-bottom sediments was described and verified in detail. The experimental results show that the optimal concentration of PAC30 for dynamic shrinkage is 20 ppm. The shrinkage performance of PAC30 decreases with an increase in temperature, and the smaller the particle size of the insoluble sediments, the worse the shrinkage performance. According to the adsorption experiment and Zeta potential, PAC30 can be effectively adsorbed on the surface of insoluble sediments, and the SEM images show that, after adding PAC30, the particles are tightly packed, and the volume of insoluble sediments is significantly reduced. In the large-scale model experiment, the expansion rate of PAC30 reached 20%, which proves that the shrinkage agent is a potential method to expand the gas storage volume. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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15 pages, 3485 KiB

Open AccessFeature PaperArticle

Effect of Shear Flow on Drag Reducer Performance and Its Microscopic Working Mechanism

by Zhiyu Liu, Zaifu Tian, Haoren Yuan, Yuan Li, Hongkui Ge and Fujian Zhou

Processes 2022, 10(8), 1485; https://doi.org/10.3390/pr10081485 - 28 Jul 2022

Cited by 1 | Viewed by 1235

Abstract

As the development of unconventional oil and gas resources goes deeper, the stimulation of reservoirs goes deeper year by year. Flow in longer wellbores poses a challenge to the stability of drag-reduction performance of fracturing fluid. However, at present we have limited understanding [...] Read more.

As the development of unconventional oil and gas resources goes deeper, the stimulation of reservoirs goes deeper year by year. Flow in longer wellbores poses a challenge to the stability of drag-reduction performance of fracturing fluid. However, at present we have limited understanding of the mechanism of drag-reduction damage caused by shear flow, especially the microscopic mechanism. Therefore, in this work, the variation pattern of drag reducer solution performance with shear rate has been analyzed by using a high precision loop flow drag test system. The test results show that there is a critical shear rate for the performance damage of the drag reducer solution, and high strength shear flow and cumulative shear flow time are the main factors leading to the performance degeneration of the drag reducer. Based on the nanometer granularity distributions, rheological properties and microscopic structures observed with a transmission electron microscope of drag reducer solutions subjected to shear flows of different velocities, it is confirmed that the damage to the microscopic structure of the solution is the main reason leading to its performance degeneration. The destruction of the microscopic structure causes the drag reducer solution to degrade in non-Newtonian characteristics, so it becomes poorer in its capability of reducing turbulent dissipation and drops in drag-reduction capability. This research can provide a reference for improving and optimizing drag-reduction capability of fracturing fluid. Full article

(This article belongs to the Special Issue Recent Advances in Reservoir Stimulation and EOR Technology in Unconventional Reservoirs)

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