Table of Content

25 April 2023, Volume 30 Issue 2

Previous Issue    Next Issue

Summary

Status and Prospects of Carbon Capture, Utilization and Storage Technology

Zhang Kai, Chen Zhangxing, Lan Haifan, Ma Haoming, Jiang Liangliang, XueZhenqian, Zhang Yuming, Cheng Shixuan

2023, 30(2):  1-9.  DOI: 10.3969/j.issn.1006-6535.2023.02.001

Asbtract ( )   PDF (1806KB) ( )  

References | Related Articles | Metrics

Carbon capture, utilization and storage (CCUS) is an effective carbon treatment technology. In the context of carbon neutrality, the CCUS technology in China will usher in a trillion-dollar industrial trend. At present, a significant progress has been made in all aspects of CCUS technology, but large-scale applications still face many challenges. By investigating the domestic and international CCUS technology literature and the CCUS projects in operation and planned to be built worldwide, the current development status and research progress of CCUS technology at home and abroad are summarized, and the challenges and future development prospects of CCUS are further clarified. The study shows that the current carbon capture efficiency is less than 90%, and the cost of carbon capture accounts for 60%-85% of the total cost of CCUS projects. The research and development of carbon capture technology should focus on pre-combustion capture (such as ethanol, ammonia and natural gas processing industries) and post-combustion capture to improve carbon capture efficiency and reduce carbon capture costs; the CO₂ utilization technology is currently at the industrial demonstration stage, and breaking the high-temperature and high-pressure environmental bottleneck and finding suitable catalysts to improve carbon utilization efficiency are the key research directions for the next stage of CO₂ utilization technology; the CO₂ storage in oil and gas fields and saline aquifer shall be further researched and promoted on a large scale in terms of an improvement of CO₂ enhanced oil and gas recovery and an increase of CO₂ storage potential; In CCUS projects, challenges such as achieving economic profitability, technological innovation, cost reduction and efficiency, and policy subsidy incentives need to be overcome; new energy sources coupled with CCUS, such as hydrogen and geothermal energy from oil and gas fields, will become a new model for CCUS promotion in the future. This study has implications for accurately grasping the research direction of CCUS technology, promoting the progress and innovation of CCUS technology, and accelerating the leapfrog development of CCUS technology.

A Review of Water Detection Method and Plugging Technology for Horizontal Wells

Shen Zhenzhen, Wang Mingwei, Gao Yong, Wu Wen, Cheng Xin, Feng Xiaowei, Deng Shengxue

2023, 30(2):  10-19.  DOI: 10.3969/j.issn.1006-6535.2023.02.002

Asbtract ( )   PDF (1353KB) ( )  

References | Related Articles | Metrics

Horizontal wells have obvious advantages in increasing the productioncapacity of oil and gas wells, but influenced by the non-homogeneity of the reservoir, the water breakthrough from horizontal wells is more common during the development of edge and bottom water reservoirs or water drive reservoirs, which brings great challenges to the efficient development of oil fields. Therefore, effective water detection and water plugging technology is one of the important means to improve the development effect of horizontal wells. To address the problem of difficult water breakthrough identification in horizontal wells, the characteristics and field applications of horizontal well water detection methods such as dynamic verification, mechanical water detection, water detection by logging and water detection with tracers were comprehensively summarized, and the problems and development directions of horizontal well water detection and water plugging methods were analyzed. This study can provide a reference for water detection and water plugging in high water-bearing inefficient horizontal wells.

Geologic Exploration

Effects of Nuclear Magnetic Resonance Frequency on the Transverse Relaxation Time of Altered Volcanic Rocks

Zhang Lihua, Pan Baozhi, Shan Gangyi, Wang Min, Cao Yue

2023, 30(2):  20-25.  DOI: 10.3969/j.issn.1006-6535.2023.02.003

Asbtract ( )   PDF (2329KB) ( )  

References | Related Articles | Metrics

In order to study the effect of frequency on the transverse chirality time T₂ of altered volcanic rocks, the altered volcanic rock samples from Longfeng Mountain area were selected for X-ray diffraction whole-rock and clay analysis, and NMR measurements at 2 MHz and 12 MHz were performed on representative samples. The results of the study show that the altered clay minerals are dominated by chlorite; the T₂ spectrum tends to shift to the left as the NMR frequency increases; this shift can lead to a false perception of the pore structure and can be corrected for the shift by the fitting formula. This correction method can guide the application of NMR instrument measurements at other frequencies in wells.

Analysis on Fault Characteristics and Reservoir Control of Ordovician Hydrocarbon-Rich Triangle Zone in Tabei-Tazhong Uplift

Wang Rujun, Feng Jianwei, Li Shiyin, Chang Lunjie, Du He, Deng Xingliang

2023, 30(2):  26-35.  DOI: 10.3969/j.issn.1006-6535.2023.02.004

Asbtract ( )   PDF (1125KB) ( )  

References | Related Articles | Metrics

In view of the lack of systematic understanding of reservoir and accumulation control of faults in the Ordovician hydrocarbon-rich triangle zone in Tabei-Tazhong Uplift, a systematic study was conducted on the distribution characteristics of the strike-slip faults and reservoirs in the Tabei-Tazhong Area through detailed seismic interpretation and tectonic mechanic mechanism analysis, especially the development characteristics and hydrocarbon enrichment mechanism of hydrocarbon-rich triangle zone were analyzed through the mechanical mechanism of fault formation, fault scale, fault segmentation and fault combination style, et al. It was found in the study that the hydrocarbons in Tabei-Tazhong Area were controlled by two regional strike-slip faults, there were obvious differences in fault levels in the hydrocarbon-rich triangle zone formed by the two faults, and there were obvious segmentation characteristics; the fault zone in Tazhong Area was generally divided into linear, diagonal and feather segments, while the fault zone in Tabei Area could be divided into braided-grabon, tensilesegment and pinnate feather segments; the fault segmentation resulted in significant differences in hydrocarbon enrichment characteristics in different segments of the same fault, and different development methods could be used for different segments to improve the overall productivity of reserves. The study can provide valuable reference for the exploration of carbonate reservoirs with similar geological conditions at home and abroad.

Shallow Gas Accumulation Conditions and Its Main Control Factors in the Changchunling South Block

Zan Chunjing, Ji Hancheng, Zhao Zhongbo, Shi Shangming

2023, 30(2):  36-43.  DOI: 10.3969/j.issn.1006-6535.2023.02.005

Asbtract ( )   PDF (3900KB) ( )  

References | Related Articles | Metrics

Shallow gas resources are widely distributed and have a broad prospect for exploration and development. In view of unclear understanding of shallow gas distribution in the Changchunling South Block, by taking the shallow-buried reservoir at the fourth member of Quantou Formation as the target formation, main controlling factor is specified by analyzing the reservoir forming conditions so as to obtain the controlling effect of sedimentary microfacies and fault on gas reservoir formation. The study results show that the gas source in the research area is mainly derived from the associated gas of crude oil generated by the hydrocarbon source rock at the first member of Qingshankou Formation. The reservoir is the fluvial facies deposition with thick channel sand body and good physical property, which is conducive to shallow gas enrichment. The reservoir sand bodies in fault structure and incline provide good vertical and lateral migration channels for shallow gas. The research area has an anticlinal shape, which is cut by three groups of faults in North-South, NW and a few NE strikes, and the structural trap conditions are good. Meanwhile, the hydrocarbon source rock at the first member of Qingshankou Formation is the regional cap rock with large thickness. The fault stops its activity at the late period of the Mingshui Formation and the preservation condition is good. Sedimentary microfacies and faults are the main controlling factors of shallow gas accumulation in the research area, so fault-lithologic gas reservoirs should be mainly sought, and the anticline uplift zone in the eastern part of the research area is a favorable exploration area. The research results point out a favorable direction for further exploration of this block.

Analysis of the Genesis and Exploration Direction of Low-saturation Reservoirs in the Baikouquan Formation, Wellblock YB4, Mahu Sag

Wang Aixia, Xu Huaibao, Geng Mei, Liu Wenfeng, Zhou Boyu, Wang Yan'e, Dong Wenbo

2023, 30(2):  44-50.  DOI: 10.3969/j.issn.1006-6535.2023.02.006

Asbtract ( )   PDF (1295KB) ( )  

References | Related Articles | Metrics

In order to clarify the formation mechanism of the low-saturation reservoir in the Baikouquan Formation, Wellblock YB4, Mahu Sag slope area to lay the foundation for oil and gas exploration, the influence of reservoir properties, tectonic characteristics, tectonic development history, oil source supply and barrier/interbed characteristics on the oil saturation of the Baikouquan Formation was systematically analyzed on the basis of the study of reservoir geological characteristics, and the favorable exploration directions in the study area were summarized. The study shows that The formation of the low-saturation reservoir of the Baikouquan Formation of Wellblock YB4 mainly includes such five factors as poor reservoir properties, gentle structure, insufficient oil source, structural inversion, and interbed/barrier development. The first three factors are the main control factors, and the structural inversion and interbed/barrier development further aggravate the reduction of oil saturation in the Baikouquan Formation reservoirs;the insufficient oil source is the objective reservoir geological background, and tectonics and reservoir are the two main control factors of oil and gas accumulation in the Wellblock YB4 of the Mahu Sag, and the area where the favorable sedimentary facies zone and the local high point of inherited development are satisfied at the same time has a relatively high oil and gas filling degree, which is a favorable direction for the further oil and gas exploration. The research results have certain guiding significance for the in-depth development of the study area.

Application of Pre-stack Inversion Technology in Gas Hydrate Reservoir Prediction

Meng Dajiang, Lu Yunqian, Zhang Baojin, Wang Lijie

2023, 30(2):  51-57.  DOI: 10.3969/j.issn.1006-6535.2023.02.007

Asbtract ( )   PDF (3454KB) ( )  

References | Related Articles | Metrics

Seabed sediments containing gas hydrate usually have high compressional and shear wave velocity and low density, while only wave impedance attributes can be acquired by conventional post-stack impedance inversion. Due to the low density of hydrates, the wave impedance of hydrate-bearing formation was superimposed with that of surrounding formation to a certain extent. Therefore, there was some error in identification of hydrate reservoirs by post-stack wave impedance. In order to improve the prediction accuracy of gas hydrate ore body, the pre-stack inversion technology was proposed to improve the low prediction accuracy of gas hydrate reservoirs. The sensitive elastic parameters of the gas hydrate reservoir were determined through the petrophysical analysis, and the gas hydrate and gaseous hydrocarbon reservoir were predicted with the pre-stack inversion technology on the basis of seismic trace set optimization, fine synthetic record calibration and initial model establishment. The results of the study show that The intersection of compressional and shear wave velocity was the most sensitive elastic parameter to identify the reservoir in the study area, and the identification factor of compressional and shear wave velocity was reconstructed based on the coordinate rotation technology and effective in identifying the reservoirs and characterizing the hydrate and gaseous hydrocarbon reservoirs clearly. The prediction results show that the natural gas hydrate ore body in the study area struck nearly from south to north, and the hydrate and gaseous hydrocarbon were relatively developed in the south of the ore body, which was in line with the drilling conditions. The prediction results can provide a reliable basis for hydrate reservoir calculation in terms of area and thickness.

Establishment of Sequence Stratigraphic Framework and Optimization of Favorable Exploration Areas of Lianggaoshan Formation, Sichuan Basin

Hong Haitao, Zhang Shaomin, Zhang Rui, Guan Xu

2023, 30(2):  58-64.  DOI: 10.3969/j.issn.1006-6535.2023.02.008

Asbtract ( )   PDF (2416KB) ( )  

References | Related Articles | Metrics

In view of the complex and various problems in the establishment of sequence stratigraphic framework and the optimization of favorable areas in Lianggaoshan Formation, Sichuan Basin, according to the logging and seismic data of Liangshan Formation, the marker beds of different scales were identified, a logging-seismic identification standard was established for the marker beds, a sequence stratigraphic framework was constructed with regional grid lines, the relationship between lithology and facies zone changes of Lianggaoshan Formation in the whole basin was clarified by the combined analysis of seismic trace and well logging data, and the favorable exploration areas were determined according to the distribution of favorable facies zones and the relationship of "source and reservoir". The study shows that after the water entering horizon was regarded as the marker bed and the sequence stratigraphic framework as established, the development horizon, thickness and distribution range of source rock and reservoir could be quickly determined. Submember 3, Member 1 of Lianggaoshan Formation was regarded as the horizon favorable for source rock development, Submember 1, Member 2 of Lianggaoshan Formation regarded as the horizon favorable for reservoir development, and Submember 3, Member 1 of Lianggaoshan Formation regarded as the source rock development area, namely in the northeast of Sichuan Basin and the edge of Longgang-Liangping Area, with a maximum shale thickness of 60～80 m, which was a favorable target area for further exploration. The results of the study have enriched the sequence stratigraphy, sedimentary evolution and exploration area optimization of Lianggaoshan Formation, Sichuan Basin, and also provided theoretical basis for the exploration and development of similar reservoirs.

Study on Optimization Method and System of Unconventional Favorable Areas Based on Structural Equation

Liu Chunlin, Meng Lingwei, Liu Ke, Luo Wenjie, Wu Guowen, Liu Qiangjiu

2023, 30(2):  65-70.  DOI: 10.3969/j.issn.1006-6535.2023.02.009

Asbtract ( )   PDF (1178KB) ( )  

References | Related Articles | Metrics

Since there is not yet a perfect target area optimization system established for the exploration and development of unconventional oil and gas fields in China, based on the existing development evaluation theories for unconventional oil and gas fields, referring to the experience and reasonable methods of foreign unconventional oil and gas field development evaluation system, in combination with the geological characteristics of unconventional oil and gas fields in the Ordos Basin, 10 influencing factors were selected, including shale resource abundance, effective shale thickness and maturity in actual blocks, an optimization system integrating structural equation model and fuzzy integral evaluation was conducted. The application was excellent. It was found in the study that the evaluation method based on structural equation model could objectively and comprehensively identify the influencing factors of the target area optimization system, and calculate the weight of each influencing factor, making the evaluation results more objective and accurate, and providing a certain theoretical basis for decision makers. There is much for reference of the results of the study to the exploration, well deployment and enhanced oil recovery of unconventional oil and gas reservoirs.

A New Method for Calculating Adsorbed Gas Amount in Highly Evolved Shale Formations with Rich Organic Matters

Gao Wenlu, Zhou Wen, Xu Hao, Zhou Qiumei, Tang Chao, Liu Ruiyin, Jiang Ke

2023, 30(2):  71-77.  DOI: 10.3969/j.issn.1006-6535.2023.02.010

Asbtract ( )   PDF (2114KB) ( )  

References | Related Articles | Metrics

In order to work out the accurate amount of adsorbed gas in the highly evolved shale formation with rich organic matters, a new method was proposed to calculate the amount of adsorbed gas with different adsorption media considering formation water content after conducting isothermal methane adsorption and scanning electron microscopy experiments on highly evolved marine shale samples with rich organic matters from Longmaxi Formation, Southern Sichuan. Through the correction of organic matter adsorption fraction, the total amount of adsorbed gas on all pore surfaces of shale under stratigraphic conditions was converted into the amount of gas adsorbed by organic matters only on the organic matter pore surface. The results of the study show that the gas content calculated from the corrected amount of gas adsorbed by organic matters was basically consistent with the measured gas content on site. With the increase of organic matter content, the difference between the amount of gas adsorbed by organic matters and the total adsorbed gas amount of shale was decreased gradually, indicating that the corrected amount of gas absorbed by organic matters conforms to the actual methane adsorption model of the highly evolved shale formations with rich organic matters under stratigraphic conditions. This method can provide a basis for the calculation of adsorbed gas amount under the stratigraphic conditions of shale reservoirs.

Enrichment Characteristics and Potential Area Prediction of Chang9 Reservoir in Huaqing Area of Ordos Basin

Yang Hao, Yang Bo, Shi Wei, Lin Li, Fang Yan, Zhu Yushuang

2023, 30(2):  78-85.  DOI: 10.3969/j.issn.1006-6535.2023.02.011

Asbtract ( )   PDF (1502KB) ( )  

References | Related Articles | Metrics

In response to unclear understanding of distribution pattern and enrichment characteristics of Chang9 Reservoir in Huaqing Area, Ordos Basin, which restricts the exploration and development of the study area, after a comprehensive comparison and analysis of the tectonic characteristics, petrological characteristics, reservoir pore space and sand body development characteristics of Chang9 Reservoir, the enrichment rule and potential area of Chang9 Reservoir in the study area were discussed according to the characteristics of excess pressure distribution and hydrocarbon accumulation configuration of Chang7 Reservoir. The results show that the local low-amplitude structure and fracture development in Chang9 Reservoir are favorable for hydrocarbon migration and accumulation. Feldspathic lithic sandstone and lithic sandstone are developed in Chang9 Reservoir. The interstitial materials are chlorite, turbidite and ferrocalcite, followed by hydromica and silicalite. The reservoir pores of Chang9 Reservoir are mainly intergranular pores and feldspar dissolved pores, leading to extremely low porosity and permeability, so Chang9 Reservoir is of low porosity and permeability. The connectivity of sand bodies in Chang9 Reservoir is controlled by the environment of shallow water delta front. The differences of rhythm, interbed development and heterogeneity of other reservoirs result in the differences in hydrocarbon enrichment in the study area. The oil source of Chang9 Reservoir originates from the source rock of Chang7 Member. The source rocks are selectively filled into the reservoir under the action of the internal excess pressure of Chang7 Member, resulting in the uneven distribution of hydrocarbons in the area. According to the reservoir geological study and the characteristics of excess pressure distribution and recovery, Block Yuan521 is considered as a favorable area for the next exploration. There is much guiding significance of the study results for the deep exploration of the Chang9 Reservoir in Huaqing Area.

Research Methods and Applications of Hydrodynamic Field in Huizhou Sag

You Tingting, Pang Xiongqi, Li Hongbo, Yuan Wu, Hu Tao, Yu Sa, Shi Kanyuan, Cai Zhe

2023, 30(2):  86-94.  DOI: 10.3969/j.issn.1006-6535.2023.02.012

Asbtract ( )   PDF (2497KB) ( )  

References | Related Articles | Metrics

To address the problem that the distribution law of unconventional tight oil and gas reservoirs in the Huizhou Sag is unclear and the top and bottom boundaries are unknown, which seriously affects the exploration and development process, based on the data of logging, oil production testing and high-pressure Hg injection, the lower limit of buoyant accumulation in the study area is determined by the combination of statistical analysis of reservoir properties and case study method, and the bottom limit of hydrocarbon accumulation is determined by the minimum flowing pore throat radius method and the potential difference method inside and outside the reservoir, and the free and restricted hydrodynamic fields in the Huizhou Sag are divided to find out the distribution boundaries of unconventional oil and gas reservoirs. The research results show that the lower limit of buoyant accumulation in Huizhou Sag is 3 500-4 000 m, the corresponding porosity is 8.50%, and the permeability is 1.00 mD; the critical pore throat radius of the bottom limit of hydrocarbon accumulation is 0.032 5 μm, the critical porosity is from 1.72% to 2.00%, and the corresponding depth bottom limit is 6 000 to 6 500 m. The research results point to the direction for opening up new oil and gas exploration areas in the Huizhou Sag and finding new oil and gas exploration targets and alternative resources.

Reservoir Engineering

Influence of Fault Attributes of Deep Shale Gas on Fracturing Fracture Network

Ren Lan, Yu Zhihao, Zhao Jinzhou, Lin Ran, Wu Jianfa, Song Yi, Wu Jianjun

2023, 30(2):  95-100.  DOI: 10.3969/j.issn.1006-6535.2023.02.013

Asbtract ( )   PDF (1932KB) ( )  

References | Related Articles | Metrics

Deep shale formation faults are relatively developed, and the nearby geostress field presents non-uniform distribution. The fractures generated by hydraulic fracturing may propagate non-planarly, asymmetrically and irregularly, which further affects the volume of fracture network. To address this problem, taking the actual fault in Well Y101, South Sichuan Block as an example, a non-uniform stress field characterization model and a compression fracture network expansion model of the faults in the complex deep shale gas formation were established to analyze the influence of fault characteristic parameters on the ground stress, and to quantitatively study the influence of fault type, fault distance, length, height, strike, dip angle and distance on the fracture network volume. The results show that the larger the displacement, length and height of the fault, the greater the geostress deflection angle and geostress difference, and the smaller the volume of fracturing fracture network. The larger the dip angle of the fault and the distance away from the fault, the smaller the geostress deflection angle and geostress difference, and the bigger the volume of fracturing fracture network. The larger the strike of fault, the greater the geostress deflection angle, the smaller the geostress difference, and the bigger the volume of fracturing fracture network. The influence degree of the following fault parameters on the volume of fracture network is in descending order: dip angle, strike, fault displacement, distance, height and length. The study can provide a theoretical basis for the optimization design of fracturing fracture network under the complex structure of deep shale.

Pore Structure of Low-permeability Reservoir and Distribution Characteristics of Remaining Oil after Water Flooding Based on Digital Core

Guo Jingjing, Wang Dihe, Wang Panrong, Xiong Runfu, Wang Haitao, Wang Sibo

2023, 30(2):  101-108.  DOI: 10.3969/j.issn.1006-6535.2023.02.014

Asbtract ( )   PDF (5300KB) ( )  

References | Related Articles | Metrics

To address the unclear understanding of formation mechanism and occurrence of remaining oil in the late stage of water flooding of low-permeability sandstone reservoirs, a three-dimensional digital core model of the reservoir was established based on Micro-CT scanning technology to extract the inter-connected pore structure and quantitatively characterize the microscopic pore structure of rock samples, and an unstructured tetrahedral grid model was established, taking the low-permeability sandstone of Weizhou 11-1 and Weizhou 12-1 oil fields as the study object. On the basis of N-S equation and level set algorithm, a mathematical micro seepage model of oil-water flow was established, and the finite element method was used to solve the model, the micro water-oil displacement flow was simulated. The results of the study show that the pore throat size and connectivity are the key factors to determine the permeability of the reservoir. Viscous fingering can be found in the micro water-oil displacement simulation. The remaining oil after water flooding are mainly in the form of reticulated remaining oil, remaining oil in pores with dead ends, remaining oil in small pore throats, remaining oil in parallel pore channel, and oil film. With the improved water injection intensity, the reticulated remaining oil and retaining oil in small pore throats can be recovered effectively. After the oil-water viscosity ratio is improved, the sweep volume can be increased. With enhanced wettability, the remaining oil in pores with dead ends and in oil-philic pores can be recovered effectively. The results of the study are of guiding significance for further developing the remaining oil after water flooding in low permeability reservoirs.

Practice of Chemical Viscosity Reduction in Water Flooding for Sensitive Conventional Heavy Oil Reservoirs

Wei Chaoping, Shu Qinglin, Wu Guanghuan, Wu Wei, Zhong Liguo, Li Yingchun, Sun Yongquan, Zhang Bin

2023, 30(2):  109-115.  DOI: 10.3969/j.issn.1006-6535.2023.02.015

Asbtract ( )   PDF (2522KB) ( )  

References | Related Articles | Metrics

In response to the problems of low recovery rate of water flooding and steam injection difficulty in steam stimulation in the strongly water-sensitive conventional heavy oil reservoirs in Block Jin8, the chemical viscosity reduction, mine pilot test were conducted in two well groups, and the feasibility of this technology was verified by laboratory research and mine practice. The study shows that the interaction among crude oil, viscosity reducer and solid-phase model in porous media resulted in three effects: crude oil emulsification and dispersion, rock wettability change, and droplet deformation, bridging and blocking, thus reducing the apparent viscosity of crude oil, stripping the crude oil and expanding the swept volume. After water flooding, the remaining oil was dispersed and emulsified by injecting 0.3 times pore volume of viscosity reducer solution, and the immovable oil was changed into movable oil and flowed again, which decreased the water cut and improved the recovery efficiency by 7.29 percentage points. The test well clusters were designed with reservrir simulation technology. In the current inverted nine-spot water flooding well pattern, a single chemical viscosity-reducing solution was injected first; when the water content exceeded 75%, foam was added for viscosity-reducing compound flooding, and the volume of chemical agent injected into the slug should be 0.4 times the pore volume. Comparing the indicators of the test well cluster with water injection and chemical viscosity reduction for 1 year, chemical viscosity reduction has five advantages: slowing down the rise of water content, improving oil recovery rate, increasing the effective period of displacement, enhancing the water absorption capacity of the reservoir, and promoting the economic benefits of development. There is much for reference of the achievement of the study to similar reservoirs.

Study on Prediction Model for Unsteady Water Influx Rate and Dynamic Reserves of Gas Reservoirs with Bottom Water

Li Yuansheng, Teng Sainan

2023, 30(2):  116-121.  DOI: 10.3969/j.issn.1006-6535.2023.02.016

Asbtract ( )   PDF (1394KB) ( )  

References | Related Articles | Metrics

The V-H model is generally adopted to predict the unsteady water influx rate of gas reservoirs with bottom water, with the water seepage direction assumed as the planar radial flow, which is inconsistent with the vertical seepage characteristics of gas reservoirs with bottom water, leading to a deviation in the prediction of water influx rate and dynamic reserves. To solve this problem, a model for calculating the unsteady water influx rate of gas reservoirs with bottom water was established with consideration of the vertical flow of bottom water and the dimensionless aquifer thickness. By solving the water influx rate through numerical inversion, an empirical equation for the unsteady water influx rate of gas reservoir with bottom water was regressed. Coupled with the material balance equation, a method was developed to work out the dynamic reserves of gas reservoirs with bottom water. It is found in the study that the dimensionless aquifer thickness has a significant impact on the water influx rate. If the dimensionless aquifer thickness is small, the water influx flows linearly first and then radially, and the predicted water influx rate is greater than that of the V-H model. If the dimensionless aquifer thickness is large, the water influx flows hemispherically, and the predicted water influx rate is smaller than that of the V-H model. The study results were applied to the anticlinal gas reservoir with bottom water in H4 Fault Block, BD Gas Field, the East China Sea. The results show that the new method is faster than that of edge water model in predicting the bottom water influx rate, and the fitting effect of the predicted pressure is better than the V-H model, which is more consistent with the actual characteristics of water invasion in the gas reservoirs with bottom water. The study results are of great significance to improve the calculation accuracy of dynamic reserves of gas reservoirs with bottom water.

Research and Application of Vertical Well Network Development for Small-Spacing Horizontal Wells in Tight Conglomerate Reservoirs in Mahu Area

Chen Yuxin, Zhao Ting, Cheng Ning, Ma Junxiu, Yang Shengfeng, Li Yunzhe

2023, 30(2):  122-127.  DOI: 10.3969/j.issn.1006-6535.2023.02.017

Asbtract ( )   PDF (1659KB) ( )  

References | Related Articles | Metrics

In order to explore the overall fracturing effect of the multi-layered system vertical well network in tight oil reservoirs in the Mahu area and to improve the recovery degree of reservoir, a study on the three-dimensional spatial distribution characteristics of the ground stress parameters was conducted through an integrated geological engineering approach based on the construction of a three-dimensional geological model and a ground stress model, and the influence of inter-well and inter-cluster stress interference on the overall fracturing effect was analyzed, the optimal cluster distance, fracture length, fracture layout method and operation sequence were determined, and the optimized parameters for the development of vertical well pattern for small-well spacing horizontal wells were identified. The study shows that the vertical well pattern mode is adopted for development to optimize the cluster distance and a single cluster fracture scale. The zipper crossed arrangement of fractures can significantly improve the reservoir stimulation effect. The production degree of fracture-controlled reserves in the study area was increased from 70% to 90%. This study provides a reference for the development of stacked reservoir blocks with large oil thickness and good continuity.

Effect of Water Saturation on CO₂ Huff-n-Puff in Tight Reservoirs

Wang Yingwei, Zhang Yulong, Zhang Jing, Shi Leiting, Fan Xibin, Wang Ruiqi

2023, 30(2):  128-133.  DOI: 10.3969/j.issn.1006-6535.2023.02.018

Asbtract ( )   PDF (2386KB) ( )  

References | Related Articles | Metrics

The change of oil saturation in the reservoir will affect the interaction between CO₂ and reservoir fluid. In order to study the effect of water saturation on the oil recovery of glutenite tight reservoir by CO₂ huff-n-puff, tests were conducted on the dissolution, expansion and huff-n-puff of CO₂ in oil and water at different water saturation based on the reservoir conditions of Mahu glutenite tight reservoirs, Xinjiang. The results show that as the water saturation was increased, the solubility of CO₂ in oil and water was decreased from 6.08 mol/L to 2.01 mol/L, the expanding volume was decreased from the highest 1.53 times to 1.09 times, the effect of CO₂ interaction with crude oil gradually weakened, and the maximum cumulative recovery percent was 20.21%; the development effect of CO₂ huff-n-puff was better when the water saturation was less than 45.0%; when the water saturation was lower than 50.3%, asphaltene deposition was dominant, with decrease in reservoir permeability; when the water saturation was higher than 50.3%, mineral dissolution was dominant, with increase in reservoir permeability. The study results play a guiding role in the efficient development of tight oil reservoirs.

Research on Yield Prediction of Carbonatite Gas Well with a Short Production Cycle Based on Machine Learning

Pang Lansu, Wang Yang, Jiang Wei, Wang Yongsheng, Gao Guohai, Wang Xin

2023, 30(2):  134-141.  DOI: 10.3969/j.issn.1006-6535.2023.02.019

Asbtract ( )   PDF (1986KB) ( )  

References | Related Articles | Metrics

In view of the problem that the traditional time series model cannot predict the gas yield of natural gas wells with a short production cycle, the affinity propagation algorithm based on machine learning is used to perform unsupervised clustering for natural gas wells and divide the well group. Combined with the geological and engineering parameters of the well group, principal component analysis is carried out to capture the key factors affecting the fluctuation of gas yield. Then, the maximum likelihood estimation method is used to solve the category of well group that the gas well belongs to, and the convolution neural network of training time for the production data of clustering center for the required category is used to predict the gas yield of the natural gas well in the short term. The results show that the yield prediction model of gas well based on machine learning has an average prediction error of 5.53%, and if compared with the long and short-term memory network (with an average error of 8.98%) and gated cyclic network (with an average error of 9.06%), the prediction error is smaller, indicating that this model can be applied for the yield prediction of carbonatite gas well with a relatively short development cycle. The research results are of great significance for the application research of machine learning in oil and gas reservoir development.

Study on the Feasibility of Nanofiltered Seawater Injection in Offshore Medium and Low Permeability Oilfields

Wang Yuqi, Feng Hengzhi, Xing Xijin, Wang Qi, Yue Qiansheng

2023, 30(2):  142-146.  DOI: 10.3969/j.issn.1006-6535.2023.02.020

Asbtract ( )   PDF (1638KB) ( )  

References | Related Articles | Metrics

To address the problem that the natural seawater as the injected water source damages the reservoir, the differences between the natural seawater and the nanofiltered seawater as the injected water were studied in terms of ionic composition of water samples, prediction of scaling tendency after mixing with the formation water, degree of scaling and core flow test to explore the feasibility of the nanofiltered seawater as the injected water source in offshore oilfields. The results of the study show that the content of scale forming ions such as Ca²⁺, Mg²⁺ and SO₄^2- in the nanofiltered seawater is significantly lower than that of the natural seawater; both the nanofiltered seawater and the natural seawater have scaling tendency after mixing with the formation water respectively, but the amount of scaling after the nanofiltered seawater is mixed with the formation water is significantly lower than that of the natural seawater, and the damage of the nanofiltered seawater as injected water to the liquid phase permeability of reservoir core is also significantly lower than that of the natural seawater. Therefore, the nanofiltered seawater as the injected water for offshore oil and gas fields is technically feasible. The results of the study provide a technical basis for the use of the nanofiltered seawater as the injected water in offshore oilfields.

Drilling & Production Engineering

Research and Application of Environmentally Friendly Variable-viscosity Fracturing Fluid for Shale Gas

Fan Yuheng, Zhou Feng, Jiang Tingxue, Zhang Shicheng, Bai Sen, Zhang Xiaofeng, Yang Quan, Yu Weichu

2023, 30(2):  147-152.  DOI: 10.3969/j.issn.1006-6535.2023.02.021

Asbtract ( )   PDF (2163KB) ( )  

References | Related Articles | Metrics

In order to solve the technical problems in deep shale gas development, such as great reservoir damage, poor proppant carrying and complicated variable-viscosity process of conventional fracturing fluid, an environmentally friendly variable-viscosity fracturing fluid system was developed, and laboratory performance evaluation and field application were carried out, taking into account the characteristics and construction requirements of deep shale reservoirs in Weiyuan Block. The study shows that the environmentally friendly fracturing fluid system was completely dissolved within 30 seconds, and the fracturing fluid viscosity was adjusted in real time within the range of 2 to 150 mPa·s. The drag reduction rate of low/high viscosity fracturing fluid prepared with flowback water was more than 70%, and the drag reduction rate of linear-gel fracturing fluid wais more than 65%. The reservoir damage rate of low/high viscosity fracturing fluid was less than 15.00%, and the core damage rate of linear-gel fracturing fluid was 15.47%. The environmentally friendly variable-viscosity fracturing fluid was biologically non-toxic and high in proppant-carrying performance, which was up to 65 times higher than that of clean water. The application in Weiyuan Well H21-5 in Weiyuan indicates that the environment-friendly variable-viscosity fracturing fluid actualized fast dissolution speed, excellent drag reduction performance and outstanding proppant-carrying performance, and it could changed the viscosity in real time to adapt to different fracturing conditions and satisfy the technical requirements of fracturing integrated with drag reduction and proppant carrying, with good application prospect.

Preparation and Application of Non-radioactive Trace Metal Tracer

Zhang Yongfei, Li Yu, Zhang Min, Liu Haifeng, Chen Hu, Shi Shenglong, Xie Hongchao, Gao Yuan

2023, 30(2):  153-160.  DOI: 10.3969/j.issn.1006-6535.2023.02.022

Asbtract ( )   PDF (1682KB) ( )  

References | Related Articles | Metrics

In view of the limitations that conventional chemical tracers are of few types, toxic and low in detection accuracy and PLT logging technology fails to monitor the produced fluid profile of horizontal wells and highly inclined wells, trace metal tracer was prepared by using non-radioactive trace metal substances that do not exist or exist in very low content in the formation, and its performance was evaluated. Meanwhile, data analysis method was developed with optimized process flow. A systematic technology for monitoring non-radioactive trace metal tracer was developed and applied in the field. The results show that the non-radioactive trace metal tracer had a temperature resistance of 200 ℃ and a salt resistance of 25×10⁴mg/L. It could remain clear in the solutions with pH values of 1 and 14, and would not be adsorbed by clay substances in the reservoir. The detection accuracy was up to 10^-14kg/L. The tracer was effective in monitoring the produced liquid profile, analyzing the fracture morphology and evaluating the fracturing effect. This technology was used to monitor the fluid production of a horizontal well in Yanchang Oilfield, and the fracture development was analyzed by the normalized output curve of the tracer, providing technical data for the evaluation of fracturing effect. This technology provides technical support for produced fluid profile monitoring and fracture development evaluation.

Preparation and Evaluation of Temporary Plugging and Profile Control Agent for Fractured Wells in Tight Reservoirs

Tang Ke, Zhao Yong, Li Kai, Ning Meng, Pu Wanfen, Tian Kaiping

2023, 30(2):  161-167.  DOI: 10.3969/j.issn.1006-6535.2023.02.023

Asbtract ( )   PDF (3145KB) ( )  

References | Related Articles | Metrics

There is serious gas channeling in the development of Mahu high-temperature tight reservoir. Polymer gel can be used to plug large fractures, which effectively prevents gas channeling from fractures, but it also plugs matrix and micro fractures, resulting in decline in oil recovery. Therefore, a temperature-resistant temporary plugging and profile control agent MHZD was developed and evaluated from the aspects of gelling performance, microscopic morphology, injection performance and plugging capacity. The results show that: The temporary plugging and profile control agent is prepared by 0.6% temperature-resistant cationic polyacrylamide and 0.3% chromium ion cross-linking agent. The plugging system can be stably gelled at 90 ℃ within 38 h, with Grade H gel strength, and the gel can be automatically decomposed into an aqueous solution with a viscosity of 5.63 mPa·s after 7-10 d stabilization. After the injection of temporary plugging agent, the core resistance coefficient is less than 30.000, the maximum breakthrough pressure gradient is greater than 30.000 MPa/m, and the plugging rate and unplugging rate are both greater than 90%. The temporary plugging agent can effectively plug the large pores and recover the remaining oil in the small pores. This study plays an underlying role in plugging against gas channeling and enhancing oil recovery of fractured wells in Mahu tight reservoir.

Application of Fracture-controlled Fracturing Technology in Tridimensional Development of Shale Gas in Sichuan Basin

Li Pengfei

2023, 30(2):  168-174.  DOI: 10.3969/j.issn.1006-6535.2023.02.024

Asbtract ( )   PDF (2503KB) ( )  

References | Related Articles | Metrics

Although the physical conditions of shale reservoirs in Sichuan Basin are superior, the height of fractures formed by SRV fracturing is limited, making it difficult to develop the high-quality shale reservoirs with a thickness of tens of meters vertically. To solve this problem, an infilled well test was conducted on the X platform of Weiyuan Block, and new wells were under reservoir sitmulation by fracture-controlled fracturing technology, so as to explore the feasibility of tridimensional development of this block. The results show that: with the increase of induced stress between clusters by close-spaced fracturing technology, the propagation path of hydraulic fractures gets more complex. Considering the annual production and construction cost, the optimal cluster spacing is about 10 m. Temporary plugging agent deflection technology is beneficial to enhance oil recovery. When the temporary plugging agent is injected after 50% of the total fluid volume is injected, the propagation of multi-cluster fractures is the most uniform. The multi-functional integrated fracturing fluid can achieve the stepless viscosity variation and the alternating injection of variable-viscosity fluid, making the main fracture and complex fracture progapate at the same time. The fracture-controlled fracturing technology has been applied to the Weiyuan shale gas reservoir. The cumulative gas productions of the three new wells were 1.85, 1.36 and 1.55 times of the cumulative gas production of the three neighboring old wells in 90 days, 1 year and 2 years a after the new wells are put into production, showing good fracturing effect. This technology can be used as reference for the trimensional development of shale gas well clusters.