Table of Content

10 December 2023, Volume 45 Issue 6

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GEOLOGY EXPLORATION

Progress and Development Direction of Researches on Remaining Oil in Alluvial Fan Reservoir

ZHANG Yang, LI Ji, SONG Binghui, HUANG Jinfu, WU Xingwang

2023, 45(6):  1-17.  DOI: 10.11885/j.issn.1674-5086.2022.01.02.01

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Alluvial fan is the most important sedimentary facies types in oilfields with ultra-high water cut in China, which has complex hydrodynamic conditions, strong reservoir heterogeneity, low research degree and high development potential. Enhancing oil recovery and tapping remaining oil in alluvial fan reservoir is one of the key problems for stable production in oilfields with ultra-high water cut. In this paper, the research achievements of scholars at home and abroad in recent decades are comprehensively analyzed, and the research progress and development direction of remaining oil in alluvial fan reservoir are discussed. It is considered that the study of macro and micro reservoir characteristics of alluvial fan is more and more precise, the research methods of remaining oil are developing towards quantification and visualization. However, the study on the formation and mobilization mechanism of the remaining oil is still in the exploratory stage. Based on the above review, we conclude that three issues in the study of remaining oil in alluvial fan reservoir should be focused. The first is the relationship between macro-micro reservoir and macro-micro remaining oil, the second is the exploration and application of remaining oil production mechanism, and the third is the research method innovation of deep fusion of multi subjects.

Structural Fracture Characteristics of Basement Rocks in Jianbei Gas Field and Its Reservoir Improvement Effect

CHENG Xin, CHAI Xiaoying, YANG Huijie, WANG Haicheng, XIAO Xin

2023, 45(6):  18-30.  DOI: 10.11885/j.issn.1674-5086.2021.12.21.02

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Fracture is the key factor affecting the development of basement rock reservoir. Using core, thin section and imaging logging data, the characteristics of structural fractures in bedrock reservoir of Jianbei Gas Field is analyzed, and the improvement effect of fractures on reservoir properties is addressed. The structural fractures are mainly vertical-high angle and semi-unfilled, with open fractures accounting for 63.3%, mainly showing near EW, NW–SE, NE–SW and near SN orientations. The dominant orientation of fractures in the upper layer of basement rock is near EW (accounting for 80%), with high fracture density and large aperture; while most fractures in the lower layer are NW–SE and NE–SW, with heterogeneous distribution and generally small aperture; On the plane, the fractures in the high part of the anticline have the greatest liner density and aperture, followed by the those in the structural slope and saddle, and the effective fractures in the fault control area have relatively low liner density and small aperture. Structural fractures promote weathering and leaching of basement rock, and effectively communicate secondary pores, improve reservoir permeability by 1~2 orders of magnitude. Fracture development results in the formation of high-quality reservoir with a thickness of about 40~150 m below the unconformity surface. The comprehensive analysis shows that the highquality reservoir in the high part of the structure has a large thickness, which controls the high productivity of gas wells and is favorable for exploration and development deployment. The 40 m thick reservoir section under the basement unconformity has experienced strong weathering and leaching and has good properties, which is a favorable target for horizontal well drilling.

Reservoir Characteristics and Reservoir-controlling Factors of E_s3 Member in Qi'nan Sag, Huanghua Depression

XU Gang, CHEN Yongdong, CHEN Cheng, HU Lin, LIU Zichang

2023, 45(6):  31-42.  DOI: 10.11885/j.issn.1674-5086.2021.10.29.02

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Based on core observation, comprehensive laboratory analysis, combined with logging and other means, this paper studied the petrological and physical characteristics of Shahejie Formation reservoir in the study area, analyzed the characteristics and main controlling factors of reservoir development. The result shows that Feldspar lithic sandstone (49.29%) is the main rock type, followed by lithic feldspar sandstone (33.21%), which are near provenances with low compositional maturity. The porosity of the reservoir is mainly distributed in the range of 5%~25%, accounting for 83.38% of the sample, and the permeability is mainly distributed in the range of 0~10 mD, accounting for 77.45% of the sample, which belongs to the ultra-low porosity–low porosity–medium porosity, ultra–low permeability reservoir. Porosity and permeability are different in the vertical sections of the reservoirs, and the correlation is poor, and the reservoir heterogeneity is strong. Based on the above analyses, the reservoir physical property are mainly controlled by sedimentary facies, diagenesis and tectonics. Subaqueous distributary channel, underwater natural dike, mouth bar sand body in delta front, distributary channel, fissure fan sand body in delta plain and nearshore subaqueous fan are favorable reservoir distribution facies belts. Compaction and cementation lead to the deterioration of reservoir properties, micritic carbonate and chlorite cementation, dispersion cementation has a certain positive effect on the protection of the remaining intergranular pores. Morever, the dissolution and metasomatism of feldspar and debris also improved the performance of the reservoir. The tectonism is the effective supplement for reservoir development.

Evaluation of Hydrocarbon Generation Potential of Lacustrine Shale of Lianggaoshan Formation in Fuling Area, Southeastern Sichuan

LI Bin, JI Xin, PENG Jun, ZHANG Kun, WEI Xiangfeng

2023, 45(6):  43-56.  DOI: 10.11885/j.issn.1674-5086.2021.11.29.02

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In order to ascertain the hydrocarbon generation potential of the lacustrine shale of Lianggaoshan Formation in Fuling Area of southeastern Sichuan, geochemical test and analyses were done to more than 400 samples of Lianggaoshan Formation from more than 10 oil-bearing shale wells in this area. The research results show that Lower Liang-2 Member and Upper Liang-1 Member have the highest abundance of organic matter, with average TOC contents of 1.57% and 0.81% respectively, the hydrocarbon generation potential (S₁+S₂) of rock pyrolysis is 2.63~5.59 mg/g, and the major type of kerogen are II₁ and II₂. The reflectivity of the vitrinite of lacustrine shale is between 0.98% and 1.46%, which has the characteristics of mature to highly mature evolution. Based on the geochemical characteristics of the lacustrine organic matter in Lianggaoshan Formation, three different kerogen hydrocarbon generation kinetic models were established with reference to the principle of volume dynamics, which effectively restored the hydrocarbon generation and expulsion history of the mud shale in Lianggaoshan Formation in Fuling Area. The simulation results show that the hydrocarbon generation conversion rate of the mud shale of Lianggaoshan Formation in Fuling Area is 65.0%~98.2%, the hydrocarbon generation evolution process has a “single peak” characteristic, and the maximum hydrocarbon production rate is 5.15~18.50 mg/(g·Ma). The total hydrocarbon generation volume is 630 000 to 1 440 000 t. The hydrocarbon generation potential of source rocks is controlled by the sedimentary environment: from lake-side lakes to shallow lakes to semi-deep lakes, the hydrocarbon generation conversion rate, the maximum hydrocarbon production rate and the total amount of hydrocarbon generation show a gradual increase trend, of which semi-deep lake facies shale is the highest quality source rock in Fuling Area, which is mostly distributed in the area of TL7–YX1–TY1, and is the most favorable continental shale oil enrichment area in this area.

Seismic Characteristics Analysis of Karst Cavity Reservoirs Based on Seismic Numerical Simulation

ZHENG Duoming, WANG Jiahong, XIAO Youjun, XIAO Wen, GAO Hongliang

2023, 45(6):  57-68.  DOI: 10.11885/j.issn.1674-5086.2022.03.31.04

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The “string of beads” response is a common feature on seismic section of carbonate karst reservoir in Tarim Basin. In order to understand the beaded response characteristics of different karst caves, a three dimensional model constituted of carbonate fracture-cavern bodies and strike-slip faults has been built based on the interpretation from real seismic data. Seven single-factor controlled modes of karst cavity body combinations are imbedded in the model. According to fluid type, cave size, distance to strong reflection interface, vertical resolution distance, lateral resolution distance, filling type and porosity. The numerical seismic simulation is performed over the model and the reverse time migration is done to the simulated data. For the “beads” response characteristics of the seven single-factor controlled modes on the migration section, a detailed comparison and analysis is made in respect of the relationship between the resolution, amplitude energy and controlling factors. The corresponding changing patterns on seismic section to the variation of controlling factor are concluded, and the following conclusions are obtained. The “beads” response of the different fluid type in karst cave are hardly distinguished on the migrated section. And its influence is mainly reflected in the variation of relative amplitude energy with effective elastic parameters. The energy amplitude of “beads” response has a positive relationship with the cave size. The distance of cave apart from the strong axis will affect the energy amplitude of the response. The vertical distance between caverns does not affect the beading response form of a single caverns, but affects the amplitude energy on the connection part. If the horizontal distance between caverns is too small, the “beads” response of two caverns will merge and form the “beads” illusion of a large cavern. The degree of mud filling and porosity in the cave will affect the amplitude energy of the “beads” response. By summarizing the variation rules of seismic response characteristics under the control modes of different factors and variables, the pattern recognition can provide a reference for effective prediction of fracture-cavity reservoirs.

Prediction for Total Porosity of Shale Based on Transfer Deep Neural Network

WANG Min, YANG Tao, TANG Hongming, YAN Jianping, LIAO Jijia

2023, 45(6):  69-79.  DOI: 10.11885/j.issn.1674-5086.2021.06.11.03

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Porosity is one of the key indicators to characterize the por structure of shale reservoirs. Quantitative prediction research on porosity is an important step in reservoir evaluation. The accurate value of shale porosity must be obtained through core analysis. How to obtain an accurate prediction of the porosity of the entire well based on a very small amount of coring well data is a significant problem. This paper proposes a new transfer deep neural network model, based on a small amount of core and logging data, to achieve accurate prediction of porosity. Firstly, according to Pearson correlation coefficient method, the logging parameters suitable for the source well deep neural network are selected as the input for the model. Secondly, a new method is proposed to calculate the similarity of the well logging data distribution between the source well and the target well, quantitatively measure the geological difference between two wells. Thridly, retrain the source well prediction network with a small amount of target well logging data similar to the source well logging data distribution, and build a transfer deep neural network for predicting the porosity migration of the target well. The test results of A2 and B2 show that: 1) This method requires only 10% of the data volume, and reaches the performance of an absolute mean error of 0.032 9 and a coefficient of determination of 0.841 6; 2) The proposed method for calculating the similarity of two wells can effectively measure the difference between wells. The more similar the distribution of the source well logging data and the target well logging data, the higher the accuracy of porosity prediction of the transfer learning network. The proposed model can effectively reduce the dependence on logging and core data, and greatly reduce shale gas exploration and development costs.

OIL AND GAS ENGINEERING

Mechanisms of Fluid-rock Interaction and Systems of Soaking in Shale Gas Reservoir: A Research Review

YANG Zhaozhong, DU Huilong, YI Liangping, LI Xiaogang, GOU Liangjie

2023, 45(6):  80-94.  DOI: 10.11885/j.issn.1674-5086.2022.05.04.02

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The production practice of shale gas reservoirs shows that soaking the well can significantly increase the initial production after fracturing operation. However, there is a lack of a comprehensive review and summary of the existing literature when it comes to which scientific-soaking system should be selected in a specific situation. Based on the research results of domestic and foreign scholars on the mechanism of reservoir reconstruction and damage, model, influencing factors and engineering process of fluid-rock reaction during shale gas well soaking, we systematically summarize the yield-increasing mechanism and the existing soaking system. The results show that the fluid rock reaction is the essence of soak production under reservoir conditions, and the degree of fluid-rock reaction is the key to formulate soaking system. The interaction of fluid-rock during well soaking can both contribute and damage the reservoir. The transformation of the reservoir includes the initiation and expansion of micro fractures and gas liquid imbibition displacement; the damage to the reservoir includes solid phase plugging during fluid-rock reaction and water phase trap caused by fracturing fluid intrusion. Establishing an unknown bridge between fluid-rock interaction and effective pore structure parameters of reservoir is the key to the study of the systems of soaking. In view of the cross scale and highly nonlinear problems that restrict the research on fluid-rock interaction, the author proposed an effective fracture characterization model based on molecular dynamics and an industrial artificial intelligence optimization model for shale gas well soak.

Wellbore Stability Mechanism of Fractured Formation in the Thrust Belt of Southern Margin of Junggar Basin

YE Cheng, REN Tao, YIN Zebin, LI Cheng, BAI Yang

2023, 45(6):  95-103.  DOI: 10.11885/j.issn.1674-5086.2021.10.05.34

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The southern margin of Junggar Basin is characterized by complex geological structure, fractured formation and poor drillability, and frequent lost circulation, tending to stick and collapse during drilling. In order to achieve safe drilling of fractured formation in the southern margin, the lithology, hydration and rock mechanics characteristics of the formation represented by Tugulu and Hutubi anticlines are studied, and the clay mineral content, hydration strength and compressive strength of different formation are compared. Combined with the seismic interpretation section and the compressive strength loss model, the mechanism of wellbore instability and the mechanism of drilling fluid stability in the fractured formation in the southern margin are analyzed. The results show that the southern margin of the formation is dominated by mudstone and sandstone, the whole rock minerals are dominated by clay minerals, plagioclase and quartz, and the clay minerals are dominated by illite and illite/smectite, and the hydration characteristics are highly heterogeneous, including extremely strong-weak dispersion and strong-medium-weak expansion. The hydration expansion and dispersion of clay minerals and the expansion and expansion of micro-pores and fractures in the fractured formation around the well lead to the decrease of formation compressive strength, the increase of collapse pressure, and the decrease of drilling fluid density window, leading to wellbore instability. Reasonable drilling fluid density, excellent hydration inhibition, comprehensive porosity sealing, strict high temperature and high pressure filtration and efficient lithology carrying are the necessary measures to achieve safe drilling and wellbore stability in the fractured formation in the southern margin. The research results can provide a reference for the design of key parameters of drilling fluids in deep complex fractured formations in the southern margin and even Junggar Basin.

Integrated Pay Zone Protection Technologies in High-porosity & High-permeability Reservoirs of Bohai Bay

ZHAO Pingqi, WANG Heqiang, GUO Haitao, MA Cuiyan, WANG Ziyu

2023, 45(6):  104-112.  DOI: 10.11885/j.issn.1674-5086.2021.12.06.03

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As a representative of high-porosity and high-permeability sandstone reservoirs in the extremely shallow sea area of Bohai Bay, Zhaodong Oilfield is faced with the problems of low degree of diagenesis, loose cementation, medium to strong water sensitivity, medium to weak velocity sensitive damage, and is easy to be damage by external solid invasion. In order to maximize the potential of the reservoir, reduce the damage of the reservoir and realize the protection of the reservoir, based on the concept of integration, the KCl polymer water-based drilling fluid system and the non-solid water-based FLO–PRO reservoir drilling fluid system were tested through the indoor recovery of cuttings and core permeability recovery experiments, and it was found that the former could reduce the shale expansion rate by 81.40% and the core permeability by 88.21%, and the latter could restore the reservoir permeability to 100.00%. In practice, the cementing operation uses a low-density, low-temperature, ultraearly, and high-strength cement slurry system. Before the completion operation, the borehole was cleaned by a combination of physical and chemical methods; Clean KCl brine that has undergone two stages of filtration is used as the completion fluid during completion operations. The integrated reservoir protection technology effectively reduces the damage of external solids to the reservoir in all aspects of drilling and completion operations, maximizes the reservoir protection in the whole process, ensures safe and efficient well construction, reduces complex accidents and non-production time, and realizes the sustainable and profitable development of different water-cut stages of the oilfield..

Plugging Mechanism and Treatment Measures of Dengying Formation Gas Reservoir in Gaoshi-Moxi Platform Margin Belt

CHEN Lin, Lü Yabo, OU Jiaqiang, ZHANG Kun, LI Juan

2023, 45(6):  113-124.  DOI: 10.11885/j.issn.1674-5086.2022.09.08.01

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Since the gas reservoir of the Dengying Formation in Gaoshi-Moxi platform margin belt was put into production, many gas wells have been blocked to varying degrees during the production process, which is manifested as a variety of complex forms of wellhead, wellbore and formation plugging, seriously restricting the normal and stable production of the gas wells. The plugging samples were analyzed by acid dissolution, infrared spectroscopy, energy dispersive electron microscopy, X-ray diffraction and chromatography-mass spectrometry, with the result that the main components of the plugs are basically the same, and there are slight differences in the components of the plugs in different gas wells and key basic data such as geological features, completion methods, and well-entry fluids were comprehensively analyzed to further determine the source and formation mechanism of blockages. On this basis, according to the different plugging degrees and types of gas wells, the pump-injecting oil-cleaning organic blockage removing agent process for the wellbore is not completely blocked, the coiled tubing flushing process for the wellbore completely blocked, and the acidizing and plugging removal process measures for the formation blockage. Twelve gas wells in the Dengying Formation gas reservoir at the edge of the Gaoshi-Moxi platform belt were de-plugged by the above technologies, and the daily recovery gas volume is 145×10⁴ m³, and the economic benefits are remarkable. A series of gas well plugging control technologies suitable for Dengying Formation gas reservoirs have been formed, which can be popularized and applied in the same type of sour gas fields.

Application of Dissolvable Screen Pipe in HTHP Gas Well in Tarim Oilfield

WEI Junhui, JING Hongtao, XIE Ying, LI Jianming, SI Xiang

2023, 45(6):  125-134.  DOI: 10.11885/j.issn.1674-5086.2021.10.21.32

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In order to solve the problem of clean completion of high temperature and high pressure gas wells and rapid workover of sand buried wells in Tarim Oilfield, a dissolvable screen pipe has been developed that can be acid dissolvable to form a production channel, which can achieve the goal of clean completion by fully replacing the fluid. The dissolvable screen pipe is connected to the lower tubing column of the packer by pins, which can be fished in sections during workover operations, reducing the workload, lowering the workover cycle, reducing the risk and improving the workover efficiency, thus reducing the damage to the reservoir during workover operations. The material dissolved in all thicknesses at a temperature of 110 ℃. The physical properties also met the seal design requirements of 35 MPa internal pressure test and 15 min continuous steady pressure, and no deformation in the 650 kN tensile load test. In the three wells applied in the field, the average recovery rate of 211.0% was much higher than the previous 78.1%, achieving the effect of low-cost clean completion and safe repair operation later, which provides a good reference for the application effect of this technology.

Risk Analysis of Wellhead Uplift and Subsidence in High Temperature and High Yield Wells

WANG Xuegang, WEI Ruihua, ZHANG Hao, YU Hao, ZHAO Zhaoyang

2023, 45(6):  135-146.  DOI: 10.11885/j.issn.1674-5086.2021.11.10.02

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The phenomenon of wellhead growth caused by high temperature thermal expansion is widespread in major oil fields, which seriously threatens production safety. Based on the multistage heat transfer theory, the nonlinear heat transfer process and thermal expansion phenomenon of multistage casing-cement sheath-formation are simulated by finite element method, and a new wellhead lift calculation method is proposed. Taking Well X1 of a block in Xinjiang Oilfield as an example, the risk assessment and analysis of various string wellhead under different working conditions are carried out. It is found that under the limit production conditions, although the casing at all levels has a large lifting force at the wellhead due to the cementing effect of the casing annulus, the wellhead uplift phenomenon does not occur. However, when the casing cement sheath is damaged to a certain extent, the overall wellhead lift occurs, and the overall wellhead lift decreases from 3 cm to 2 cm under the action of the pressure and weight of the wellhead device. The results show that this method can quantitatively evaluate the wellhead safety in the actual production process, and has certain guiding significance for the actual field wellhead lifting calculation and risk evaluation.

Development and Application of High Temperature and High Pressure Wellbore Corrosion Probe Monitoring System

LONG Wu, LIU Zhendong, ZHANG Jiangjiang, LI Fang, ZENG Dezhi

2023, 45(6):  147-156.  DOI: 10.11885/j.issn.1674-5086.2021.05.26.01

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In order to solve the problem of high-temperature and high-pressure wellbore annulus corrosion monitoring, based on the principle of inductive corrosion monitoring technology, a method of serial connection of multiple sets of measurement test strips and simultaneous implementation of excitation signals is designed and developed, which is a tubular corrosion probe monitoring system for simultaneous monitoring of tubing and casing corrosion with multiple channels. The connection between the probe monitoring device and the tubing adopts a snap-fit connection, avoids the impact of device welding on tubing corrosion. Under the experimental conditions of 140 ℃ and 70 MPa, the temperature and pressure resistance and data reliability of the device is tested using on-site produced fluid. The deviation between the monitoring data and the simulation results of high temperature and high pressure corrosion is less than 5%, and the temperature and pressure resistance is good. Finally, the corrosion monitoring system is tested on-site. The results show that the developed wellbore corrosion probe monitoring system works well, and the relative error between the monitoring data and the on-site coupon is 8.32%. It is concluded that the monitoring system can meet the requirements of wellbore corrosion monitoring in harsh environments, and provides a new technical means for effectively grasping the wellbore oil casing annulus corrosion status and high-temperature and high-pressure wellbore corrosion monitoring.

A New Method for Determining Deviation Coefficient of Highly Sour Gas in Ultra Deep Reservior

REN Shilin, CHEN Xi, LAN Hui

2023, 45(6):  157-163.  DOI: 10.11885/j.issn.1674-5086.2021.09.07.01

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Accurate calculation of the deviation coefficient of natural gas multi-component system is very important for gas reservoir reserve evaluation, gas storage and surface equipment design. It is usually determined by experimental measurement, pseudo-critical pressure and temperature by querying the Standing-Katz chart, equation of state and empirical formula. Experimental determination and equation of state are expensive and complicated due to the variation of temperature and pressure conditions of gas and the existence of non-hydrocarbon components such as hydrogen sulfide. At the same time, it is not clear whether traditional empirical formulas such as DAK, DPR can be applied to calculation of the deviation coefficient of high sulfur gas with reservoir depth of more than 5 000 meters and non-hydrocarbon component content of 20%. Based on the regression of 999 data points of deviation coefficient of deep gas with high sulfur content measured in Changxing Formation gas reservoir of Yuanba Gas Field, a prediction model of deviation coefficient Z is obtained by pseudo-contrast pressure and pseudo-contrast temperature. The correlation coefficients of the proposed model with DAK, DPR, Beggs-Brill, Papay empirical formula and LXF analytical model are compared. The results show that the correlation coefficient between the z-factor model and the measured values is over 99%, and the calculation accuracy is obviously better than the traditional empirical formula method. The model presented in this paper can be used to determine the deviation coefficient of ultra-deep gas with high sulfur content in the pressure range of 0~70 MPa and temperature range of 30~150 ℃. The model is used to draw the relationship diagram of Z value with pseudo-contrast pressure in the range of pseudo-contrast temperature 1.02≤T_pr≤2.20 and pseudocontrast pressure 0.1≤P_pr≤20.0. It provides a useful reference for the efficient development of ultra-deep gas reservoirs with high sulfur content.

PETROLEUM MACHINERY AND OILFIELD CHEMISTRY

Research on Working Condition Diagnosis of Beam Pumping Unit Based on LeNet Model

YE Zhewei, YI Qinjue, LUO Liang

2023, 45(6):  164-174.  DOI: 10.11885/j.issn.1674-5086.2021.05.06.02

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The beam pumping unit is the most widely used component in the rod pump system, and analyzing the indicator diagram of the rod pump is an important means to judge the downhole working conditions of the pumping unit. Traditional indicator diagram recognition method relies on expert experience and manual feature extraction, which leads to low recognition accuracy when dealing with similar indicator diagrams. Through the application of deep learning convolutional neural network in the field of image recognition, a LeNet-based convolutional neural network model was proposed, which realized the automatic recognition of the indicator diagram, and the model built simplified the model structure while considering 15 common downhole conditions of pumping units, and a dropout layer and a local response normalization layer are introduced to prevent the model from overfitting and improve the generalization ability of the model. The experimental results showed that the model not only converged quickly, but also had an average accuracy of 94.68% for diagnosing working conditions, which met the accuracy requirements of pumping unit working conditions detection. The research provides a basis for the construction of an intelligent monitoring and early warning system for pumping wells, and is of great significance to the construction of smart oilfields and efficient production of oilfields.

Study on Vibration Reduction Measures of Pipeline in a Compressor Station

LIU Enbin, LIAN Dianpeng, WANG Xingjie, SU Zhongya, XIE Ping

2023, 45(6):  175-184.  DOI: 10.11885/j.issn.1674-5086.2021.08.10.01

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Aiming at the problem of abnormal vibration of natural gas station pipeline, taking the outbound pipeline of a compressor station as the research object, the station pipeline vibration analysis is carried out, the station pipeline numerical model is established, and the correctness of the model is verified by field vibration test. The fluid-structure coupling method is used to analyze the vibration of pipelines under different working conditions. Then two vibration reduction schemes are proposed and verified by simulation. The main conclusions are as follows: 1) The fluid pressure fluctuation in the pipeline is the root cause of the abnormal vibration phenomenon of the station pipeline. 2) Through the analysis of the fluid pressure fluctuation spectrum in the pipeline, it is found that the pressure fluctuation in the pipeline is mainly concentrated in the low frequency range, and the pressure fluctuation frequency in the pipeline is close to the first two natural frequencies of the pipeline system. Therefore, the resonance phenomenon of the pipeline system makes the vibration more intense. 3) In the two vibration reduction schemes proposed, the diameter of connecting pipeline increased from Φ711 mm to Φ1 016 mm, and appropriate restraint measures are added. The results show that the scheme has the best damping effect, and the pipeline vibration level evaluation is excellent.

Mechanisms of High-salinity Improvement of the Stability of Betaine Foam

SUN Lin, DONG Shuo, ZHANG Yongchang, XIN Jun, PU Wanfen

2023, 45(6):  185-192.  DOI: 10.11885/j.issn.1674-5086.2021.06.03.02

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Betaine foam, characterized by its salt tolerance and the heightened stability with increasing salinity, holds a unique advantage in improving oil recovery in high-salinity reservoirs. In this paper, cocoamidopropyl hydroxysulfobetaine and dodecyl hydroxypropyl sulfobetaine were taken as the foam system to explore the mechanisms of high-salinity improvement foam stability. Foam performance tests have proceeded under various high-salinities. Particular attention was given to the surface dilatation rheology and diffusion-adsorption behaviors. The results showed that when the concentration of NaCl increased from 2.3% to 21.1%, the drainage velocity of betaine foam at the initial stage had little change, but the half-life of the foam could be extended by 13 times. With increased salinity, the saturated adsorption amount of betaine increased and the diffusion-adsorption rate decreased, which led to the increase of the dilatation modulus and the enhancement of the elasticity of the liquid film. Therefore, the coarsening and coalescence of betaine foam were significantly inhibited, resulting in improved foam stability. This work will generate fresh insight into the mechanisms of foam stability and optimization of foam system in high-salinity reservoirs.