Experimental Study on Shut-in-Time Optimization for Multi-Fractured Horizontal Wells in Shale Reservoirs

2022 ◽  
Author(s):  
Liang Tao ◽  
Jianchun Guo ◽  
Zhongbo Wang ◽  
Yi Liu ◽  
Yuhang Zhao ◽  
...  
Keyword(s):  
Clay Mineral ◽  
Shale Gas ◽  
Mineral Content ◽  
Type I ◽  
Diffusion Experiment ◽  
Ion Diffusion ◽  
Water Imbibition ◽  
Study Results ◽  
Shale Reservoir ◽  
Shale Reservoirs

Abstract The optimization of shut-in-time in shale gas well is an important factor affecting the production of single well after volume fracturing. In this study, a new method for determining the optimal shut-in-time considering clay mineral content and ion diffusion concentration was proposed. First, a novel water spontaneous imbibition apparatus under the conditions of formation temperature and confining pressure was designed. Then, the water imbibition satuation of 15 shale samples from the Longmaxi Formation (LF) of the Sichuan Basin were measured to quantitatively evaluate the water imbibition ability and classify reservoir types. Finally, the salt ion concentration diffusion experiment was carried out to optimize the shut-in-time of different types of shale reservoirs. The experimental results shown that the clay mineral content was the key factor affecting water wettability of shale, the shale reservoirs can be divided into two types and the critical value of clay mineral content was about 40%. Based on the law of salt ion diffusion in shale, the initiation time of micro-fractures induced by shale hydration was about 10-15 days. Under the experimental conditions, the optimal shut-in time of type I shale reservoir and type II shale reservoir were about 20 days and 15 days respectively. The average daily gas production has increased from 15.6×104 m3/day to 25.1×104 m3/day. The study results can provide scientific basis for the optimization of flowback regime of shale gas resrvoirs.

scholarly journals Factors Controlling Shale Reservoirs and Development Potential Evaluation: A Case Study

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Chao Luo ◽  
Hun Lin ◽  
Yujiao Peng ◽  
Hai Qu ◽  
Xiaojie Huang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Mineral Content ◽  
Gas Content ◽  
Longmaxi Formation ◽  
Development Potential ◽  
Reservoir Characteristics ◽  
Lower Silurian ◽  
Single Well ◽  
Shale Reservoir ◽  
Shale Reservoirs

The shale of the Lower Silurian Longmaxi Formation is an important gas-producing layer for shale gas development in southern China. This set of shale reservoir characteristics and shale gas development potential provide an important foundation for shale gas development. This study takes wellblock XN111 in the Sichuan Basin, China, as an example and uses X-ray diffraction (XRD), scanning electron microscopy (SEM), isothermal adsorption, and other techniques to analyze the shale reservoir characteristics of the Lower Silurian Longmaxi Formation. The results show that the Lower Silurian Longmaxi Formation was deposited in a deep-water shelf environment. During this period, carbonaceous shale and siliceous shale characterized by a high brittle mineral content ( quartz > 40   wt . % , carbonate   mineral > 10   wt . % ) and a low clay mineral content (<30 wt.%, mainly illite) were widely deposited throughout the region. The total organic carbon (TOC) content reaches up to 6.07 wt.%, with an average of 2.66 wt.%. The vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The methane adsorption capacity is 0.84–4.69 m3/t, with an average of 2.92 m3/t. Pores and fractures are developed in the shale reservoirs. The main reservoir space is composed of connected mesopores with an average porosity of 4.78%. The characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation are controlled by the following factors: (1) the widespread deep-water shelf deposition in wellblock XN111 was a favorable environment for the development of high-quality shale reservoirs with a cumulative thickness of up to 50 m; (2) the high TOC content enabled the shale reservoir to have a high free gas content and a high adsorptive gas storage capacity; and (3) the shale’s high maturity or over maturity is conducive to the development of pores and fractures in the organic matter, which effectively improves the storage capacity of the shale reservoirs. The reservoir characteristic index was constructed using the high-quality shale’s thickness, gas content, TOC, fracture density, and clay content. Using production data from shale gas wells in adjacent blocks, a mathematical relationship was established between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristics Index (Rci). The EUR of a single well in wellblock XN111 was estimated.

Fractures in continental shale reservoirs: a case study of the Upper Triassic strata in the SE Ordos Basin, Central China

2015 ◽  
Vol 153 (4) ◽  
pp. 663-680 ◽  
Author(s):  
WENLONG DING ◽  
PENG DAI ◽  
DINGWEI ZHU ◽  
YEQIAN ZHANG ◽  
JIANHUA HE ◽  
...  
Keyword(s):  
Organic Matter ◽  
Shale Gas ◽  
Mineral Content ◽  
Ordos Basin ◽  
Total Content ◽  
Upper Triassic ◽  
Thin Sections ◽  
Yanchang Formation ◽  
Fracture Development ◽  
Shale Reservoirs

AbstractFractures are important for shale-gas reservoirs with low matrix porosity because they increase the effective reservoir space and migration pathways for shale gas, thus favouring an increased volume of free gas and the adsorption of gases in shale reservoirs, and they increase the specific surface area of gas-bearing shales which improves the adsorption capacity. We discuss the characteristics and dominant factors of fracture development in a continental organic matter-rich shale reservoir bed in the Yanchang Formation based on observations and descriptions of fracture systems in outcrops, drilling cores, cast-thin sections and polished sections of black shale from the Upper Triassic Yanchang Formation in the SE Ordos Basin; detailed characteristics and parameters of fractures; analyses and tests of corresponding fracture segment samples; and the identification of fracture segments with normal logging. The results indicate that the mineral composition of the continental organic-matter-rich shale in the Yanchang Formation is clearly characterized by a low brittle mineral content and high clay mineral content relative to marine shale in the United States and China and Mesozoic continental shale in other basins. The total content of brittle minerals, such as quartz and feldspar, is c. 41%, with quartz and feldspar accounting for 22% and 19% respectively, and mainly occurring as plagioclase with small amounts of carbonate rocks. The total content of clay minerals is high at up to 52%, and mainly occurs as a mixed layer of illite-smectite (I/S) which accounts for more than 58% of the total clay mineral content. The Upper Triassic Yanchang Formation developed two groups of fracture (joint) systems: a NW–SE-trending system and near-E–W-trending system. Multiple types of fractures are observed, and they are mainly horizontal bedding seams and low-dip-angle structural fractures. Micro-fractures are primarily observed in or along organic matter bands. Shale fractures were mainly formed during Late Jurassic – late Early Cretaceous time under superimposed stress caused by regional WNW–ESE-trending horizontal compressive stress and deep burial effects. The extent of fracture development was mainly influenced by multiple factors (tectonic factors and non-tectonic factors) such as the lithology, rock mechanical properties, organic matter abundance and brittle mineral composition and content. Specifically, higher sand content has been observed to correspond to more rapid lithological changes and more extensive fracture development. In addition, higher organic matter content has been observed to correspond to greater fracture development, and higher quartz, feldspar and mixed-layer I/S contents have been observed to correspond to more extensive micro-fracture development. These results are consistent with the measured mechanical properties of the shale and silty shale, the observations of fractures in cores and thin-sections from more than 20 shale-gas drilling wells, and the registered anomalies from gas logging.

scholarly journals Relationship between Organic Geochemistry and Reservoir Characteristics of the Wufeng-Longmaxi Formation Shale in Southeastern Chongqing, SW China

Energies ◽  
2021 ◽  
Vol 14 (20) ◽  
pp. 6716
Author(s):  
Shengxiu Wang ◽  
Jia Wang ◽  
Yuelei Zhang ◽  
Dahua Li ◽  
Weiwei Jiao ◽  
...  
Keyword(s):  
Organic Matter ◽  
Specific Surface ◽  
Adsorption Capacity ◽  
Surface Area ◽  
Clay Mineral ◽  
Shale Gas ◽  
Mineral Content ◽  
Organic Geochemistry ◽  
Quartz Content ◽  
Longmaxi Formation

Shale gas accumulates in reservoirs that have favorable characteristics and associated organic geochemistry. The Wufeng-Longmaxi formation of Well Yucan-6 in Southeast Chongqing, SW China was used as a representative example to analyze the organic geochemical and reservoir characteristics of various shale intervals. Total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis, scanning electron microscopy (SEM), and nitrogen adsorption analyses were conducted, and a vertical coupling variation law was established. Results showed the following: the Wufeng-Longmaxi formation shale contains kerogen types I and II2; the average TOC value at the bottom of the formation is 3.04% (and the average value overall is 0.78%); the average Ro value is 1.94%; the organic matter is in a post mature thermal evolutionary stage; the shale minerals are mainly quartz and clay; and the pores are mainly intergranular, intragranular dissolved pores, organic matter pores and micro fractures. In addition, the average specific surface area (BET) of the shale is 5.171 m2/g; micropores account for 4.46% of the total volume; the specific surface area reaches 14.6%; and mesopores and macropores are the main pore spaces. There is a positive correlation between TOC and the quartz content of Wufeng-Longmaxi shale, and porosity is positively correlated with the clay mineral content. It is known that organic pores and the specific area develop more favorably when the clay mineral content is higher because the adsorption capacity is enhanced. In addition, as shale with a high clay mineral content and high TOC content promotes the formation of a large number of nanopores, it has a strong adsorption capacity. Therefore, the most favorable interval for shale gas exploration and development in this well is the shale that has a high TOC content, high clay mineral content, and a suitable quartz content. The findings of this study can help to better identify shale reservoirs and predict the sweet point in shale gas exploration and development.

Clay minerals in shales of the Lower Silurian Longmaxi Formation in the Eastern Sichuan Basin, China

Clay Minerals ◽  
2017 ◽  
Vol 52 (2) ◽  
pp. 217-233
Author(s):  
Geng Yi-Kai ◽  
Jin Zhen-Kui ◽  
Zhao Jian-Hua ◽  
Wen Xin ◽  
Zhang Zhen-Peng ◽  
...  
Keyword(s):  
Clay Minerals ◽  
Clay Mineral ◽  
Mixed Layer ◽  
Shale Gas ◽  
Mineral Content ◽  
High Pressures ◽  
Gas Reservoirs ◽  
Longmaxi Formation ◽  
Lower Silurian ◽  
Layer I

AbstractThe present study examines the characteristics of clay minerals in shale gas reservoirs and their influence on reservoir properties based on X-ray diffraction and scanning electron microscopy. These analyses were combined with optical microscopy observations and core and well-log data to investigate the genesis, distribution characteristics, main controlling factors and pore features of clay minerals of the Lower Silurian Longmaxi Formation in the East Sichuan area, China. The clay mineral assemblage consists of illite + mixed-layer illite-smectite (I-S) + chlorite. This assemblage includes three sources of clay minerals: detrital, authigenic and diagenetic minerals. The lower section of the Longmaxi Formation in the Jiaoshiba area has sealing ability which resulted in abnormal high pressures during hydrocarbon generation which inhibited illitization. Therefore, an anomalous transformation sequence is present in which the mixed-layer I-S content increases with depth. This anomalous transformation sequence can be used to infer the existence of abnormal high pressures. The detrital components of the formation also affect the clay-minerals content indirectly, especially the abundance of K-feldspar. The transformation of mixed-layer I-S to illite is limited due to the limited availability of K+, which determines the extent of transformation. Three types of pores were observed in the shale reservoir rocks of the Longmaxi Formation: interparticle (interP) pores, intraparticle (intraP) pores and organic-matter pores. The clay-mineral content controls the development of intraP pores, which are dominated by pores within clay particles. For a given clay mineral content, smectite and mixed-layer I-S were more conducive to the development of shale-gas reservoirs than other clay minerals.

scholarly journals Simulation of tectonic stress field and prediction of fracture distribution in shale reservoir

2021 ◽  
Vol 44 (4) ◽  
pp. 397-407
Author(s):  
Wenlong Ding ◽  
Weite Zeng ◽  
Ruyue Wang ◽  
Kai Jiu ◽  
Zhe Wang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Shear Fracture ◽  
Triaxial Compression ◽  
Prediction Method ◽  
Reference Value ◽  
Tectonic Stress ◽  
Fracture Rate ◽  
Shale Reservoir ◽  
Shale Reservoirs ◽  
Fracture Distribution

In this paper, a finite element-based fracture prediction method for shale reservoirs was proposed using geostress field simulations, uniaxial and triaxial compression deformation tests, and acoustic emission geostress tests. Given the characteristics of tensile and shear fractures mainly developed in organic-rich shales, Griffith and Coulomb – Mohr criteria were used to calculate shale reservoirs' tensile and shear fracture rates. Furthermore, the total fracture rate of shale reservoirs was calculated based on the ratio of tension and shear fractures to the total number of fractures. This method has been effectively applied in predicting fracture distribution in the Lower Silurian Longmaxi Formation shale reservoir in southeastern Chongqing, China. This method provides a new way for shale gas sweet spot optimization. The simulation results have a significant reference value for the design of shale gas horizontal wells and fracturing reconstruction programs.

Characteristics of Chang 7 shale gas in the Triassic Yanchang Formation, Ordos Basin, China

2017 ◽  
Vol 5 (2) ◽  
pp. SF31-SF39 ◽  
Author(s):  
Xiangzeng Wang
Keyword(s):  
Organic Matter ◽  
Clay Mineral ◽  
Shale Gas ◽  
Mineral Content ◽  
Ordos Basin ◽  
Central China ◽  
Late Triassic ◽  
Yanchang Formation ◽  
Geochemical Parameters ◽  
Porosity And Permeability

The Yanchang Formation in the Ordos Basin in North Central China represents a large, long-lived lacustrine system of the late Triassic Period. The extensive shales within this system provide hydrocarbons (HCs) for conventional and unconventional oil and gas reservoirs. In the formation, the Chang 7 shale is the thickest shale with the best geochemical parameters, and it is the main source rock in this area. In recent years, the discovery of shale gas in the Chang 7 shale has promoted the exploration and development of lacustrine shale gas in China. We have estimated the shale gas resource potential based on the analysis of the geologic conditions of the Chang 7 shale. The average thickness of the Chang 7 shale reaches 42.6 m, and the main organic matter types are types [Formula: see text] and [Formula: see text]. The average content of organic carbon is more than 3%, and the average HC potential is [Formula: see text]. However, the thermal maturity of the Chang 7 shale is low with a vitrinite reflectance [Formula: see text] ranging from 0.83% to 1.10%. The Chang 7 shale lithology consists of shale and sandy laminations or thin sandstones. The shale is characterized by high clay mineral content and poor porosity and permeability, with an average porosity of 1.8% and an average permeability of [Formula: see text]. The sandy laminations or thin sandstones are characterized by relatively higher brittle mineral content, relatively lower clay mineral content, and higher porosity and permeability. The pores of the Chang 7 shale include primary intergranular and intragranular pores, secondary intragranular and intragranular dissolved pores, fracture pores, and organic-matter-hosted pores. The proportion of adsorbed gas, free gas, and dissolved gas is approximately 52%, 37%, and 11%, respectively, and the shale gas resources of the Chang 7 shale are [Formula: see text].

Experimental Study on Water Imbibition Law of Longmaxi Formation Shale in the Sichuan Basin

2021 ◽  
Author(s):  
Liang Tao ◽  
Yuhang Zhao ◽  
Xiaozhuo Zhang ◽  
Yanxing Wang ◽  
Hongbo Feng ◽  
...  
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Scientific Basis ◽  
Gas Wells ◽  
Longmaxi Formation ◽  
Water Imbibition ◽  
Study Results ◽  
Key Factor ◽  
The Sichuan Basin ◽  
Volume Fracturing

Abstract Water imbibition is a key factor affecting the flowback system of shale gas wells after volume fracturing. This paper took shale samples from the Longmaxi formation (LF) in the Sichuan Basin as subjects, the experiments of shale water imbibition under different influencing factors were carried out. The water imbibition law was analyzed, and the shale water imbibition capacity was quantitatively characterized, the question if shut-down is necessary after volume fracturing of wells in shale gas reservoir has been answered objectively. The experimental results show that: according to imbibition saturation, the shale water imbibition can be divided into 3 periods, imbibition diffusion, imbibition transition and imbibition balance periods. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The shale sample with horizontal bedding had much larger imbibition capacity than the sample with vertical bedding. The initial micro-fractures provide percolation pathways for shale imbibition, making flow resistance drop and imbibition capacity increase rapidly. Imbibition capacities of the shale samples to different types of fluids in descending order were: deionized water, slick water, 2% KCl solution and kerosene. The micro-fracfures induced by shale hydration were mainly lamellation, with obvious directionality. Shale hydration can improve the fracturing effect of reservoir, resulting in the increase of porosity of 0.08-1.04 times and increase of permeability of 2.3-173.6 times. The study results can provide scientific basis for the optimization of flowback system of shale gas wells.

scholarly journals Experimental Study on Spontaneous Imbibition Characteristics of Fracturing Fluid at Cores from Different Layers in Fuling Shale Gas Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Sidong Fang ◽  
Jing Sun ◽  
DeHua Liu ◽  
Zhiyuan Yao ◽  
Bin Nie
Keyword(s):  
Clay Mineral ◽  
Shale Gas ◽  
Large Scale ◽  
Mineral Content ◽  
Spontaneous Imbibition ◽  
Fracturing Fluid ◽  
Gas Reservoir ◽  
Gas Well ◽  
Shale Gas Reservoir ◽  
Function Relationship

With low porosity and low permeability, shale reservoirs cannot be mined economically without large-scale hydraulic fracturing operation. However, abundant fracturing fluid will enter the reservoirs during the process of fracture. Nevertheless, there have not been specific research findings on the imbibition law of Fuling shale gas reservoir in China. In this study, an imbibition experiment was carried out on the shale core of Jiaoshiba block of Fuling shale gas reservoir to learn spontaneous imbibition characteristic of Fuling shale gas reservoir. Based on the experimental results, the imbibition process of Fuling shale gas reservoir fracturing fluid is divided into two stages. During the first stage, i.e., the former 30 hours, imbibition velocity is high, with the cumulative imbibition occupying more than 70% of the total imbibition; during the second stage, i.e., the latter 30 hours, the imbibition velocity substantially drops towards balance. There is a typical power function relationship between the average imbibition velocity and imbibition time, and this function relationship runs throughout the whole imbibition process. Nonetheless, the imbibition process of shale core cannot be described directly by the Handy equation. The imbibition velocity is closely related to clay mineral content and pore structure characteristics of shale core. The higher the clay mineral content, the higher the imbibition velocity. According to the relationship between the average imbibition velocity and imbibition time, we derived the estimation equation of fracture area formed by fractured shale gas well to estimate the fracture scale formed by shale gas well fracturing.

Depositional Environment Drive as Overpressure Generation: Study Case in “Gap” Field, North West Java Basin

2020 ◽  
Author(s):  
A., C. Prasetyo
Keyword(s):  
Clay Mineral ◽  
Depositional Environment ◽  
Mineral Content ◽  
Hydrocarbon Generation ◽  
Well Test ◽  
Burial History ◽  
The South ◽  
North West ◽  
The North ◽  
Geological Processes

Overpressure existence represents a geological hazard; therefore, an accurate pore pressure prediction is critical for well planning and drilling procedures, etc. Overpressure is a geological phenomenon usually generated by two mechanisms, loading (disequilibrium compaction) and unloading mechanisms (diagenesis and hydrocarbon generation) and they are all geological processes. This research was conducted based on analytical and descriptive methods integrated with well data including wireline log, laboratory test and well test data. This research was conducted based on quantitative estimate of pore pressures using the Eaton Method. The stages are determining shale intervals with GR logs, calculating vertical stress/overburden stress values, determining normal compaction trends, making cross plots of sonic logs against density logs, calculating geothermal gradients, analyzing hydrocarbon maturity, and calculating sedimentation rates with burial history. The research conducted an analysis method on the distribution of clay mineral composition to determine depositional environment and its relationship to overpressure. The wells include GAP-01, GAP-02, GAP-03, and GAP-04 which has an overpressure zone range at depth 8501-10988 ft. The pressure value within the 4 wells has a range between 4358-7451 Psi. Overpressure mechanism in the GAP field is caused by non-loading mechanism (clay mineral diagenesis and hydrocarbon maturation). Overpressure distribution is controlled by its stratigraphy. Therefore, it is possible overpressure is spread quite broadly, especially in the low morphology of the “GAP” Field. This relates to the delta depositional environment with thick shale. Based on clay minerals distribution, the northern part (GAP 02 & 03) has more clay mineral content compared to the south and this can be interpreted increasingly towards sea (low energy regime) and facies turned into pro-delta. Overpressure might be found shallower in the north than the south due to higher clay mineral content present to the north.

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