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Reservoir Formation Damage Analysis

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (24 February 2023) | Viewed by 12869

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Special Issue Editors

Dr. Shifeng Zhang

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Guest Editor

School of Petroleum and Natural Gas Engineering, Changzhou University, Changzhou 213164, China
Interests: wellbore stability and lost circulation analysis; formation damage mechanism and control; drilling fluid additive development

Dr. Liangbin Dou

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Guest Editor

College of Petroleum Engineering, Xi'an Shiyou University, Xi'an 710065, China
Interests: formation damage controlling; hydraulic fracturing; wellbore complex multiphase flow

Dr. Wenmin Guo

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Guest Editor

School of Petroleum and Natural Gas Engineering, Changzhou University, Changzhou 213164, China
Interests: displacement mechanism; streamline simulation; numerical reservoir simulation

Dr. Guoqiang Xing

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Guest Editor

School of Petroleum and Natural Gas Engineering, Changzhou University, Changzhou 213164, China
Interests: fluid flow mechanism of complex fractured well; well test analysis; flow dynamics of unconventional reservoirs

Dr. Yan Zhuang

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Guest Editor

School of Petroleum and Natural Gas Engineering, Changzhou University, Changzhou 213164, China
Interests: reservoir damage mechanism; geomechanics and wellbore stability analysis

Special Issue Information

Dear Colleagues,

Formation damage has become a major obstacle to the efficient drilling and economic development of conventional or unconventional reservoirs. The damage occurs during drilling, fracturing, water flooding, workover, etc., which results in a decrease in well productivity due to the natural or induced decline in the permeability. With the advances in materials, analytical or digital methods, work has been carried out to overcome the problems related to formation damage. A number of modern and nondestructive analytical methods were used to study the damage mechanism, such as dry/cryogenic scanning electron microscopy (SEM), X-ray diffraction (XRD), CT scanning (both using adapted medical scanners and the use of high-resolution micro-CT instruments) and nuclear magnetic resonance (NMR). To counteract this problem, minimize formation damage, increase permeability of the zone around the wellbore and improve oil and gas production, chemicals such as clay stabilizer nanoparticles can be used to reduce the damage. In addition, fracturing or matrix acidizing has also been suggested as a remediation method to improve permeability.

This Special Issue aims to present and disseminate the most recent research on formation damage, related to theory, modeling, experiments, migration methods, chemicals and applications, etc.

Topics of interest for publication include, but are not limited to:

Advanced modeling approaches and theoretical study on formation damage mechanism;
Advanced experimental approaches and lab study to identify the pore scale mechanisms of formation damage;
Drilling and completion fluids to migrate the formation damage;
Fracturing or workover fluids to migrate the formation damage;
Matrix acidizing technology to improve reservoir permeability;
Fracturing technology to increase flowing channels and improve reservoir permeability;
Field application of novel methods or technology.

Dr. Shifeng Zhang
Dr. Liangbin Dou
Dr. Wenmin Guo
Dr. Guoqiang Xing
Dr. Yan Zhuang
Guest Editors

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Keywords

formation damage
modeling
experimental
drilling and completion fluid
fracturing or workover fluid
fracturing or matrix acidizing
field application

Published Papers (10 papers)

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Research

20 pages, 20493 KiB

Open AccessArticle

Formation Timing and Features of Stylolites and Controlling Factors for the Second-Period Stylolites in the Carboniferous KT-I Formation of NT Oilfield

by Changhai Li, Lun Zhao, Weiqiang Li, Wenqi Zhao, Meng Sun, Yu Zhang and Tianyu Zheng

Energies 2023, 16(6), 2909; https://doi.org/10.3390/en16062909 - 22 Mar 2023

Viewed by 1131

Abstract

The formation timing of stylolites, which is of great importance for analyzing the controls of stylolites, has nearly never been examined. In this paper, based on the data of cores, imaging logging, conventional logging, and mercury injection, the characteristics of stylolites formed in different stages of tectonic movement were investigated, and the controlling factors of oil-stained stylolites, formed in the second period of tectonic movement, were analyzed in particular. Furthermore, the influence of different controlling factors on the development of stylolites was compared, by using grey correlation analysis. The results show that there are three periods of stylolites in the study area, and all three periods developed both low-angle stylolites and high-angle stylolites. The prominent characteristics of both the low-angle and high-angle stylolites of the second period, are being oil-stained. The higher the structural location, the greater the buried depth, the lower the dolomite content, the higher the calcite content, the higher the clay content, the smaller the rock density, the greater the porosity, the smaller the rock grain size, the easier it is to develop both the low-angle stylolites and the high-angle stylolites. The influence of different controlling factors on the development of low-angle stylolites is given by depth, porosity, curvature, rock density, rock grain size, clay content, dolomite content, and calcite content, in this order. The importance of the influences on the development of high-angle stylolites proceeds as follows: curvature, calcite content, depth, rock particle size, clay content, rock density, dolomite content, and porosity. Tectonism is the most important influencing factor on the development of stylolites. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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14 pages, 3013 KiB

Open AccessArticle

Shale Formation Damage during Fracturing Fluid Imbibition and Flowback Process Considering Adsorbed Methane

by Mingjun Chen, Maoling Yan, Yili Kang, Sidong Fang, Hua Liu, Weihong Wang, Jikun Shen and Zhiqiang Chen

Energies 2022, 15(23), 9176; https://doi.org/10.3390/en15239176 - 03 Dec 2022

Cited by 3 | Viewed by 982

Abstract

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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14 pages, 6704 KiB

Open AccessArticle

A Novel Experimental Study on Conductivity Evaluation of Intersected Fractures

by Haitao Wang, Chen Chen, Yiming Yao, Jingrui Zhao, Qijun Zeng and Cong Lu

Energies 2022, 15(21), 8170; https://doi.org/10.3390/en15218170 - 02 Nov 2022

Cited by 2 | Viewed by 1140

Abstract

Massive hydraulic fracturing (MHF) is currently the most effective technology used to create fracture networks with sufficient conductivity and maximize the stimulated reservoir volume (SRV) in tight oil and gas reservoirs. The newly initiated fracture networks during MHF usually exhibit complex fracture morphology and contain intersected fractures and fracture branches. The conductivity of these fractures plays a pivotal role in determining long-term productivity. Due to the complex geometry, it is difficult to accurately evaluate intersected fracture conductivity through traditional conductivity measurement methods and devices which are designed for a single primary fracture. Unlike previous studies where fracture conductivity was measured using two rock slabs under single-direction (vertical) loading, we establish a novel conductivity measurement apparatus that can mimic different fracture intersection scenarios under both vertical and transverse loading to facilitate the evaluation of intersected fracture conductivity. Based on this apparatus, a standard conductivity measurement framework for intersected fractures under biaxial compaction conditions is also proposed, and stable and reliable conductivity testing data are obtained. Sensitivity analyses are performed to find out the controlling factors of intersected fracture conductivity and the corresponding conductivity evolution law. Results indicate that the overall intersected fracture conductivity of intersected fractures can be divided into three stages, with closure pressure increasing, videlicet, the conductivity rapid reduction stage at low closure pressure, the conductivity slow reduction stage, and the conductivity stabilization stage. Higher proppant concentration results in higher conductivity. However, the conductivity differences among cases with different proppant concentration are relatively small at high closure pressure (conductivity stabilization stage). The more complex the fracture intersecting pattern is, the higher the conductivity would be. The experimental results can provide guidance for the design of proppant placement procedure for intersected fractures. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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16 pages, 5517 KiB

Open AccessArticle

Investigation on Flowback Behavior of Imbibition Fracturing Fluid in Gas–Shale Multiscale Pore Structure

by Jiajia Bai, Guoqing Wang, Qingjie Zhu, Lei Tao and Wenyang Shi

Energies 2022, 15(20), 7802; https://doi.org/10.3390/en15207802 - 21 Oct 2022

Cited by 2 | Viewed by 1089

Abstract

To investigate the influence of flowback time and flowback difference on flowback behavior of shale fracturing fluid, we carried out the permeability test experiment of Longmaxi Formation shale under different flowback pressure gradients and analyzed the retention characteristics of water phase in shale pores and fractures after flowback by nuclear magnetic resonance (NMR) instrument. The results indicate that after flowback under the pressure gradient ranges of 0.06~0.18 MPa/cm, the content of retained water phase in shale samples ranges from 9.68% to 16.97% and the retention of fracturing fluid in shale does not decrease with the increase of flowback pressure difference. Additionally, increasing the flowback pressure difference will reduce the shale permeability damage rate, but the permeability damage rate is still above 80%. After the flowback, the water phase mainly stays in the pore space with D < 100 nm, especially in the pore space with 2~10 nm and 10~50 nm. It is extremely difficult for the water phase in the pores with D < 100 nm to flow back out. The experimental results show that the critical flowback pressure gradient for particle migration of rock powder in shale fracture surface is 0.09 MPa/cm. The research results have important guiding significance for shale gas well flowback. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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13 pages, 5152 KiB

Open AccessArticle

Synthesis and Plugging Performance of Poly (MMA-BA-ST) as a Plugging Agent in Oil-Based Drilling Fluid

by Jian Yang, Zhen Lei, Bo Dong, Zhongqiang Ai, Lin Peng and Gang Xie

Energies 2022, 15(20), 7626; https://doi.org/10.3390/en15207626 - 15 Oct 2022

Cited by 6 | Viewed by 1358

Abstract

Nanopolymer was developed in order to solve the problem that the micron-scale plugging agent cannot effectively plug nanopores, which leads to instability of the wellbore. The oil-based nano plugging agent poly (MMA-BA-ST) was synthesized by Michael addition reaction using styrene, methyl methacrylate and butyl acrylate compounds as raw materials. Poly (MMA-BA-ST) has a particle size distribution of 43.98–248.80 nm, with an average particle size of 108.70 nm, and can resist high temperatures of up to 364 °C. Poly (MMA-BA-ST) has little effect on the rheological performance parameters of drilling fluids, no significant change in the emulsion breaking voltage, significant improvement in the yield point of drilling fluids and good stability of drilling fluids. The mud cake experiment, and artificial rock properties of poly (MMA-BA-ST), showed that the best-plugging effect was achieved at 0.5% addition, with a mud cake permeability of 6.3 × 10⁻⁵ mD, a plugging rate of 72.12%, an artificial core permeability of 4.1 × 10⁻⁴ mD and a plugging rate of 88.41%. The nano plugging agent poly (MMA-BA-ST) can enter the nanopore joints under the action of formation pressure to form an effective seal, thus reducing the effect of filtrate intrusion on well wall stability. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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18 pages, 4106 KiB

Open AccessArticle

Composite Hydration Process of Clay Minerals Simulating Mineral Clay Components and Influence Mechanism of Cations

by Huang Siyao, Xu Mingbiao, Xu Peng, Zhang Yu and Wang Xinying

Energies 2022, 15(20), 7550; https://doi.org/10.3390/en15207550 - 13 Oct 2022

Cited by 2 | Viewed by 1292

Abstract

Clay minerals are an important part of the mud shale reservoir, and their type of content has a great impact on the hydration of the formation. The hydration of clay minerals causes a decrease in drilling fluid performance, an increase in pore pressure, and a decrease in rock strength, leading to wellbore wall collapse. Therefore, it is important to study the influence of clay mineral hydration on well-wall stability. In this paper, we analyze the hydration process of clay minerals qualitatively and quantitatively by simulating the mineral clay fraction and the effect of the change in cations on their hydration and clarify the difference in the hydration of different clay minerals. The results show the following: (1) montmorillonite has the most obvious hydration and swelling effect, while the hydration of illite is mainly based on hydration and dispersion, which easily produce exfoliations and fall off in the stratum; kaolinite has poor hydration performance, while chlorite shows certain hydration but low hydration degree. (2) Cations have a certain inhibitory effect on the hydration of clay minerals, and the degree of hydration inhibition is different for different types. (3) Different clay minerals also differ in the form of state after water exposure, as montmorillonite shows swelling, while illite has no swelling, but its dispersion is stronger. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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10 pages, 899 KiB

Open AccessArticle

Performance Evaluation and Field Application of Nano Plugging Agent for Shale Water-Based Drilling Fluid

by Minjia Jing, Zhiping Yuan, Xiaoyang Li, Jinjun Huang and Yuexin Tian

Energies 2022, 15(20), 7529; https://doi.org/10.3390/en15207529 - 12 Oct 2022

Cited by 3 | Viewed by 1250

Abstract

In this paper, nano plugging agent AMPS/AM was prepared, and its plugging performance was evaluated by a microfracture simulation experiment and a shale pressure resistance experiment. The pressure loss decreased by 66.09% compared with the top pressure of 6.9 MPa, and the average core indentation hardness increased 58.12% with 3% AMPS/AM blocking mud. The experiments indicate that AMPS/AM can effectively seal the shale micropore and nanopore structure and greatly improve the stability of fractured shale well wall. The field application results of the YS129H well in the Zhaotong block show that the water-based drilling fluid with nano plugging agent AMPS/AM as the key agent has strong plugging performance. The well mud is of high temperature and pressure water loss < s4 mL, mud cake permeability reduction rate of 85.67%, which indicates that the drilling fluid system has good sealing properties and well wall stability. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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18 pages, 10948 KiB

Open AccessFeature PaperArticle

Characterization and Evaluation of Carbonate Reservoir Pore Structure Based on Machine Learning

by Jue Hou, Lun Zhao, Xing Zeng, Wenqi Zhao, Yefei Chen, Jianxin Li, Shuqin Wang, Jincai Wang and Heng Song

Energies 2022, 15(19), 7126; https://doi.org/10.3390/en15197126 - 28 Sep 2022

Cited by 4 | Viewed by 1501

Abstract

The carboniferous carbonate reservoirs in the North Truva Oilfield have undergone complex sedimentation, diagenesis and tectonic transformation. Various reservoir spaces of pores, caves and fractures, with strong reservoir heterogeneity and diverse pore structures, have been developed. As a result, a quantitative description of the pore structure is difficult, and the accuracy of logging identification and prediction is low. These pose a lot of challenges to reservoir classification and evaluation as well as efficient development of the reservoirs. This study is based on the analysis of core, thin section, scanning electron microscope, high-pressure mercury injection and other data. Six types of petrophysical facies, PG1, PG2, PG3, PG4, PG5, and PG6, were divided according to the displacement pressure, mercury removal efficiency, and median pore-throat radius isobaric mercury parameters, combined with the shape of the capillary pressure curve. The petrophysical facies of the wells with mercury injection data were divided accordingly, and then the machine learning method was applied. The petrophysical facies division results of two mercury injection wells were used as training samples. The artificial neural network (ANN) method was applied to establish a training model of petrophysical facies recognition. Subsequently, the prediction for the petrophysical facies of each well in the oilfield was carried out, and the petrophysical facies division results of other mercury injection wells were applied to verify the prediction. The results show that the overall coincidence rate for identifying petrophysical facies is as high as 89.3%, which can be used for high-precision identification and prediction of petrophysical facies in non-coring wells. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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13 pages, 3846 KiB

Open AccessArticle

Fractal Characteristics of Pore-Throats Structure and Quality Evaluation of Carbonate Reservoirs in Eastern Margin of Pre-Caspian Basin

by Xing Zeng, Weiqiang Li, Jue Hou, Wenqi Zhao, Yunyang Liu and Yongbo Kang

Energies 2022, 15(17), 6357; https://doi.org/10.3390/en15176357 - 31 Aug 2022

Cited by 7 | Viewed by 1249

Abstract

The Carboniferous reservoir KT-II layer in the Eastern margin of the Pre-Caspian Basin was formed in the open platform sedimentary environment and marked by a complicated pore-throats structure. Understanding the main controls on the carbonate reservoir quality is of great significance for reservoir classification and a relevant production prediction. This study focuses on revealing reservoir pore-throats structure’s fractal characteristics by analyzing the mercury intrusion capillary pressure (MICP), with the integration of the pore-throats radius’ distribution data. The relationship between fractal dimensions and reservoir parameters such as physical properties, mercury median saturation pressure (Pc50) and the proportion of large-size (radius > 0.1 μm) pores demonstrate that the lower fractal dimension corresponds not only to core plug samples with higher permeability, but also to lower Pc50 and a higher proportion of large pore-throats. Three classes of carbonate reservoir with different qualities were defined according to their fractal dimensions, petrophysical properties and photomicrograph features, et al. Combined with flow profiles from Production Log Tool tests, the relationship between the carbonate reservoir type and production behavior was revealed, thus providing suggestions on the middle and late stage of the water flooding production adjustment strategy. This work provides a typical case study for the further comprehensive evaluation and classification of a carbonate reservoir and it is quite meaningful for production efficiency optimization. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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16 pages, 2464 KiB

Open AccessFeature PaperArticle

Experimental Characterization of Oil/Gas Interface Self-Adjustment in CO₂-Assisted Gravity Drainage for Reverse Rhythm Reservoir

by Haishui Han, Xinglong Chen, Zemin Ji, Junshi Li, Weifeng Lv, Qun Zhang, Ming Gao and Hao Kang

Energies 2022, 15(16), 5860; https://doi.org/10.3390/en15165860 - 12 Aug 2022

Cited by 1 | Viewed by 953

Abstract

Worldwide practices have proven that gas-assisted gravity drainage can obviously enhance oil recovery, and this technology can be especially effective for reservoirs with a thick formation and large inclination angle. For the successful implementation of this process, a key technology is the stable control of gas–oil interface during gas injection. For a detailed exploration of this technique, a three-stage permeable visual model was designed and manufactured, with permeability decreasing from top to bottom, thus, a reverse rhythm reservoir was effectively modeled. Then the experiment concerning CO₂-assisted gravity drainage was carried out with the adoption of a self-developed micro visual displacement device. This study mainly focused on the micro migration law of gas–oil interface and the development effects of CO₂-assisted gravity drainage. According to the experiments, CO₂ fingering somewhat happens in the same permeable layer from the beginning of gas injection. However, phenomena of “wait” and “gas–oil interface self-adjustment” occur instead of flowing into the next layer when the injected CO₂ reaches the boundary of the next lower permeability layer through the dominant channel. By the “gas–oil interface self-adjustment”, the injected CO₂ first enters into the pores of the relative higher permeability layer to the greatest extent, and thus expands the sweep volume. Futhermore, in the process of CO₂ injection, obvious gas channeling occurs in the low permeability layer directly connected to the outlet, resulting in low sweep efficiency and poor development effect. After connecting the core with lower permeability at the outlet, the development indexes of the model, such as the producing degree of the low permeability layer, the oil recovery before and after gas breakthrough, are significantly improved, and the recovery degrees of the medium permeability layer and the high permeability layer are also improved, and the overall recovery factor is increased by 12.38%. This “gas–oil interface self-adjustment” phenomenon is explained reasonably from the two scales of macroscopic flow resistance and microscopic capillary force. Finally, the enlightenments of the new phenomenon are expounded on the application of gas-assisted gravity drainage on site and the treatment of producers with gas breakthrough in gas injection development. Full article

(This article belongs to the Special Issue Reservoir Formation Damage Analysis)

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