Table of Content

25 August 2021, Volume 28 Issue 4

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Summary

Study Progress of Rock Fracturing Technology with High-voltage Pulse Discharge in Liquid

Li Zhaoxuan, Yan Tie, Hou Zhaokai, Sun Wenfeng, Ju Guoshuai, Liu Shulong

2021, 28(4):  1-9.  DOI: 10.3969/j.issn.1006-6535.2021.04.001

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There are much more challenges in the exploration and development of tight sandstone and shale oil and gas reservoirs due to their tight lithology and extremely low porosity and permeability. For low-permeability oil and gas resources, rock fracturing technology with high-voltage pulse discharge in liquid is one of the important means to improve the effect of development. In this paper, the experimental device development, influencing factors and rock fracture law of the rock fracturing technology with high-voltage pulse discharge in liquid were analyzed and summarized, and the existing problems and development direction were determined. The results showed that the improvement of the conductivity of the liquid medium was helpful to increase the intensity of the pulse discharge shock wave; the higher the discharge voltage and the greater the discharge energy, the better the rock fracturing effect; the rock fracturing was mainly affected by tensile and shear stress, the fracture progress was symmetric, with turning, bifurcation and waveform characteristics. This paper provides a reference for the studies on rock fracturing technology with high-voltage pulse discharge in liquid, with great significance for the development of unconventional oil and gas reservoirs.

Geologic Exploration

Favorable Hydrocarbon Transport Sites of Aogula Fault and Their Influence on Hydrocarbon Accumulation Pattern of Saertu, Putaohua and Gaotaizi Reservoirs

Wang Yunzeng

2021, 28(4):  10-15.  DOI: 10.3969/j.issn.1006-6535.2021.04.002

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To address the problem of unclear hydrocarbon distribution pattern in Saertu, Putaohua and Gaotaizi reservoirs near Aogula Fault, the favorable hydrocarbon transport site of Aogula Fault and its influence on hydrocarbon accumulation in different periods were studied with the description of the favorable sites for hydrocarbon transport by associate fractures and by convex ridges, based on the study of the relationship between the development of Aogula Fault and the hydrocarbon distribution, and the hydrocarbon distribution of Saertu, Putaohua and Gaotaizi reservoirs near Aogula Fault. The results of the study showed that Aogula Fault was developed with favorable sites for hydrocarbon transport by associated fractures in Saertu, Putaohua and Gaotaizi reservoirs, except for east and west ends and the central part; Aogula Fault had seven favorable sites for hydrocarbon transport by convex ridges in Saertu, Putaohua and Gaotaizi reservoirs, including three sites in its central and central-western parts, and only one site in the east; the relationship between the favorable hydrocarbon transport site of Aogula Fault and hydrocarbon accumulation in Saertu, Putaohua and Gaotaizi reservoirs during different periods was mainly manifested by the hydrocarbon transport jointly by associated fractures and convex ridges, resulting in the greatest hydrocarbon accumulation in Saertu reservoir; the contribution of transport by associated fracture to hydrocarbon accumulation was greater than that of transport by convex ridges. The study correctly revealed the hydrocarbon distribution pattern in the Saertu, Putaohua and Gaotaizi reservoirs near Aogula Fault, with a guiding significance for the further hydrocarbon exploration of Saertu, Putaohua and Gaotaizi reservoirs.

Exploration Potential of Paleogene and Cretaceous Litho-stratigraphic Hydrocarbon Reservoirs in the Northern Sag of Melut Basin, South Sudan

Nan Zhengbing, Xiao Kunye, Zhang Guangya, Liu Jiguo, Shi Zhongsheng, Xiao Gaojie

2021, 28(4):  16-22.  DOI: 10.3969/j.issn.1006-6535.2021.04.003

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The northern sag of the Melut Basin is a hydrocarbon-rich depression, with the basic conditions for the formation of litho-stratigraphic hydrocarbon reservoirs. Since no breakthrough has been made in the exploration of Cretaceous deep litho-stratigraphic hydrocarbon reservoirs, a unified sequence stratigraphic framework was established after a study conducted on sequence stratigraphy and sedimentary facie, and the exploration potential and direction of the litho-stratigraphic hydrocarbon reservoirs of primary sequence above and within the source of the northern sag of Melut Basin were clarified. It was found in the study that the upper Yabus member-Adar-Lau high-stand system was mainly developed at the source, and the favorable facies belts were river, delta, and fan delta, forming tectonic-lithological traps; Galhak-Algayger lacustrine transgressive system was mainly developed within the source, and the favorable facies belts were delta front, fluxoturbidite fan and flood turbidite fan, forming lithological and tectonic-lithological traps. The comprehensive analysis suggested that the in-source sequence was the primary exploration target for finding tectonic-lithological reservoirs. Well-developed reservoir-caprock assemblage in a favorable tectonic setting was the key factor for Cretaceous hydrocarbon accumulation in Melut Basin. The facies belt of braided river delta front was the dominant facies belt for Cretaceous hydrocarbon accumulation, and the Galhak Formation of the Upper Cretaceous Series was the main target interval for Cretaceous hydrocarbon accumulation. The results of the study are of great significance for further exploration in the northern sag of Melut Bsin.

Quantitative Characterization of Pore Throat Structure of Glutenite Reservoir with Extra-low Permeability in Triassic Baikouquan Formation in Junggar Basin

Zhang Daiyan, Hu Haisheng, Wang Yingwei

2021, 28(4):  23-29.  DOI: 10.3969/j.issn.1006-6535.2021.04.004

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In view of the strong heterogeneity, complex pore throat structure and great difficulty in quantitative characterization of glutenite reservoir with extra-low permeability, the pore throat structure of glutenite reservoir with extra-low permeability in Triassic Baikouquan Formation in Junggar Basin was studied with cast sheet observation, conventional mercury injection and mercury injection at constant rate. The results showed that the reservoir heterogeneity was high, the conglomerate content was more than 50%, the pore throat sorting coefficient was from 1.10 to 3.60, with an average of 1.97; the average pore radius and average throat radius of the reservoir were 127.80 μm and 0.25 μm, respectively, and the mainstream throat radius ranged from 0.71 μm to 1.12 μm, with an average of 0.91 μm; for glutenite reservoirs, the mainstream throat radius was an important indicator to characterize the permeability of the reservoir. It is recommended to improve the reservoir development degree and single well production with "horizontal well + fracturing by stimulated reservoir volume", and to enhance the oil recovery with gas flooding and stimulation by gas injection.

Evolution Characteristics and Difference Evaluation of Shale Oil Reservoirs in the Upper Sweet Spot Interval of Lucaogou Formation in Jimusaer Sag

Peng Shouchang, Zha Xiaojun, Lei Xianghui, Fei Fanxu, Xu Dongsheng, Gao Yang

2021, 28(4):  30-38.  DOI: 10.3969/j.issn.1006-6535.2021.04.005

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Shale oil reservoir in the Jimusaer Sag is an important hydrocarbon exploration area in the Junggar Basin. Major breakthroughs have been made in recent years. In the past, most studies focused on the sedimentary environment, rock characteristics, microscopic pore structure, etc., while few studies were conducted on the evolutionary characteristics and differences of shale oil reservoirs. In order to explore the evolutionary characteristics and differences of the reservoirs in the study area, the typical core samples were taken from the upper sweet spot interval of Lucaogou Formation in Jimusaer Sag, the characteristics and controlling factors of shale oil reservoirs in the upper sweet spot interval of Lucaogou Formation in Jimusaer Sag were studied by means of rock slice, casting sheet, X-ray diffraction, etc., as well as analyzing the evolutionary characteristics and differences of the reservoirs were analyzed. The results of the study showed that the shale oil reservoirs in the upper sweet spot interval of Lucaogou Formation were in complex rock mineral composition, mainly including dolomite, feldspathic lithic sandstone, dolomitic sandstone, silty dolomite and gray mudstone. The reservoir space type was dominated by dissolved pore, intergranular pore and intercrystalline pore, with a few fractures. After the multi-stage evolution of acid-base fluids, the reservoir experienced diagenetic evolutions such as compaction and pressolution, calcite and dolomite cementation, and complex metasomatism. There were differences in the physical properties, pore-throat structure parameters and logging response characteristics of the reservoirs with of different lithologies. This study provides a favorable basis for the exploration and development of shale oil reservoirs in Lucaogou Formation in Jimusaer.

Study on Physical Properties and Favorable Reservoirs of Terrestrial Pulveryte Reservoirs in Da'anzhai Member, Yuanba Area, Sichuan

Zhu Yixiu, Lyu Pin, Jin Ke, Guo Qiheng, Wang Huan, Wang Xinyao, Shi Yuan

2021, 28(4):  39-47.  DOI: 10.3969/j.issn.1006-6535.2021.04.006

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The terrestrial pulveryte of Da'anzhai Member in Yuanba Area of Sichuan Basin is different from that in other areas in the Basin, and the physical properties of the reservoirs are quite different, so it is necessary to study the physical properties of the pulveryte reservoirs in the target member in this area. The physical properties, reservoir space, pore structure and permeability of rocks in the study area were analyzed by means of microscopical observation, porosity and permeability measurement with helium, low-temperature nitrogen adsorption, scanning electron microscope, FIB, etc. The results showed that the pulveryte reservoir space type in the study area was classified as pore and fracture, including organic matter pore, intergranular pore, dissolved pore, intercrystalline pore and micropore among clay minerals, as well as tectonic fracture, shale bedding fracture and diagenetic shrinkage fracture; the average porosity was 3.35% and the average permeability was 1.54 mD, so this reservoir was a pore-fracture reservoir with ultra-low porosity and low permeability; the pulveryte reservoir was dominated by micropores and mesopores with a size of mainly 3 to 7 nm; the organic-rich shale and shell shale were the most favorable reservoir lithology in the second sub-member, and the organic-rich pulveryte section in the lower and middle layers of the Da'anzhai Member was the favorable reservoir interval. The analysis of reservoir characteristics is helpful to discover the formation mechanism of terrestrial tight reservoirs with ultra-low porosity and low permeability in the Da'anzhai Member, and also provides support and reference for the genesis analysis and of distribution rule prediction of such reservoirs.

Characteristics of Favorable Glutenite Reservoirs in Anfutun Steep Bank

Lan Kuo

2021, 28(4):  48-54.  DOI: 10.3969/j.issn.1006-6535.2021.04.007

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In view of the characteristics of rapid lithofacies change and great difference in oil-bearing property of the glutenite mass in Anfutun steep bank of Damintun Sag, comprehensive geological research method was used for paleogeomorphic restoration, sedimentary facies analysis and microscopic study of reservoir characteristics. It was found in the study that thick layered fan delta glutenite was widely developed in the western fault trough belt, with the characteristics of skirt belt multi-stage overlapping distribution. The subfacies sandstone reservoir in the Anfutun fan front was developed with intergranular dissolved pores, presenting sound reservoir properties and hydrocarbon occurrence; the sand mass was in direct contact with the mudstone of the depression, which was condcutive to preferential capture of oil and gas near the source, and it was clear that the subfacies at the fan delta front was the dominant lithofacies. The glutenite mass at the Anfutun steep bank was characterized by "reservoir control with facies zone and reservoir control with physical properties". This research is of guiding significance for hydrocarbon exploration of other glutenite masses in the western fault trough.

Exploration of the Genetic Mechanism of Oil-Water Coexistence in Oil Reservoirs in the North-Central Area of Lixian Slope in Jizhong Depression

Ye Dashuai, Ding Wenlong, Tang Xiaoqi, Hu Yanxu, Zhang Yujing, Du Jin, Wu Yuewei, He Yanchen

2021, 28(4):  55-61.  DOI: 10.3969/j.issn.1006-6535.2021.04.008

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In order to explore the genetic mechanism and oil-water distribution characteristics of oil reservoirs in the north-central Lixian slope in Jizhong Depression, critical moments of the petroleum system, sealed coring analysis, and logging data were systematically analyzed. The results showed that the oil-water coexistence in the Lixian slope reservoir was related to the charging degree of the reservoir and the microscopic pore structure of the reservoir; due to low thermal evolution of source rock in the study area, the poor physical properties and high viscosity of crude oil, late hydrocarbon generation and expulsion, and low tectonic amplitude, it was required to overcome additional flow resistance when the oil and gas floated through a longer migration path, resulting in oil and gas charging in the trap; in addition, the pores of the reservoir were not uniformly sorted and the micro-heterogeneity was more serious, resulting in insufficient and uneven oil and gas charging, high natural water saturation in the reservoir, and oil-water coexistence after conventional oil testing or reservoir fracturing stimulation. The study results can become great reference and guidance for further oil exploration and rolling evaluation in the study area.

Sedimentary Characteristics and Evolution of Shallow Water Delta in Fuyu Tight oil Reservoir in Sanzhao Sag, Northern Songliao Basin

Bu Chunming

2021, 28(4):  62-71.  DOI: 10.3969/j.issn.1006-6535.2021.04.009

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Aiming at the troubles of rapid phase change and difficulty in prediction of sandbody in Fuyu tight oil reservoir of Sanzhao Sag, the sedimentary characteristics and evolution of shallow water delta in Sanzhao Sag were analyzed in combination with core, seismic, logging and other data, as well as based on the division of high-resolution sequence framework. The results showed that the Fuyu oil layer is divided into 2 long-term semi-cycles and 4 medium-term cycles, and the datum plane dropped to the lowest at MSC3; the study area was dominated by delta plain distributary channel, delta front underwater distributary channel and sheet sand deposit, with meandering stream and shore-shallow lacustrine deposit in some places. In the context of water advance following water recession in the Fuyu reservoir, the datum plane evolution experienced four stages, including slow decline in early stage, rapid decline in middle stage, slow rise and rapid rise in late stage, with obvious differences in sedimentary facies types and sandbody distribution characteristics in different evolutionary stages. This study can provide a geological basis for the reservoir sandbody prediction of Sanzhao Sag.

Characteristics of Miocene Evaporite Reservoir in Gulf of Suez and Prospective Zone Prediction

Tian Yu, Qu Jianhua, He Wei, Zhang Yijiu, Cao Lina, Deng Yong, Qian Li, Li Chen

2021, 28(4):  72-78.  DOI: 10.3969/j.issn.1006-6535.2021.04.010

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Miocene evaporite is widely developed in the Gulf of Suez. Industrial oil run has been found in some wells in the test of evaporite formations, indicating bright prospects for oil and gas exploration and development. In order to clarify the reservoir characteristics and distribution law of evaporite formations, in a case study of Miocene South Gharib Formation (referred to as the SG Formation) in the North West Gemsa block (referred to as the NWG block) in Egypt, the lithology and reservoir characteristics of the SG Formation were studied according to core, cast slice, mercury injection test, physical property analysis and logging data. The results showed that the SG Formation was composed of various rock, mainly salt rock, mixed with anhydrite, polyhalite, carnallite and dolomite; the reservoir space was mainly inter-granular pores; the mercury injection curve shape and the pore throat radius distribution presented fine skewness, micro throat, and other characteristics, with poor seepage; dolomite and foliated anhydrite were in relatively good physical properties, which were important rock types for reservoir development in the study area; the other evaporites were generally poor in physical properties and could not be used as reservoirs; the distribution area of favorable reservoirs was mainly located in the west of the block and was the key area for next exploration of the SG Formation. The study results play a guiding role in the oil and gas exploration and development of Miocene evaporite formations in the Gulf of Suez.

Characteristics, Genesis and Distribution of Interlayers in E₃¹ Reservoir of Gasikule Oilfield, Qaidam Basin

Yu Huimin, Song Yanchen, Peng Yuting, Liu Bo, Li Tong, Shi Kaibo

2021, 28(4):  79-87.  DOI: 10.3969/j.issn.1006-6535.2021.04.011

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The interlayers developed in the reservoir restrict the distribution of remaining oil. In view of the difficulty in enhancing recovery efficiency of remaining oil by gas injection after long-term water-flooding development in E₃¹ reservoir of Gasikule Oilfield, Qaidam Basin, in the study case of Ⅳ-3 to Ⅳ-5 sublayers in E₃¹ reservoir, Gasikule Oilfield, a comprehensive study was conducted on core, logging, test and analysis to identify the types, characteristics and genesis of interlayers, establish the standards for interlayer identification, and characterize spatial distribution characteristics of interlayer on these standards. It was found in the study that argillaceous and calcareous interlayers were mainly developed in Gasikule E₃¹ reservoir, with argillaceous interlayer dominated, whose genesis was mainly controlled by high-frequency cycles, and calcareous interlayer was distributed relatively less and mostly formed by cementation. Based on the analysis of stratigraphic architecture and stratigraphic texture, the interlayer of Gasikule E₃¹ reservoir can be divided into three levels: interlayer between sublayers, interlayer between single sandbodies and interlayer in single sandbody. A quantitative identification standard of argillaceous interlayer and calcareous interlayer was established based on the normalization of log curves of GR, SP, AC and R_LLD. The interlayer between sublayers was thick, high in continuity, and basically distributed in the whole area; the interlayer between single sandbodies was poor in continuity and continuously distributed in some places; the interlayer in single sandbody was sporadically distributed, with the thinnest thickness. The study results provide a certain geological basis for gas-flooding development of Gasikule E₃¹ reservoir.

Reservoir Engineering

Mechanism of Nitrogen Stimulation Assisted by Common Heavy Oil Viscosity Reducer

Li Binfei, Zang Yunong, Liu Xiaobo, Huang Yongmei, Li Haifeng, Zhu Jianjun, Lu Xiaojuan

2021, 28(4):  88-95.  DOI: 10.3969/j.issn.1006-6535.2021.04.012

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To address the issues on indefinite production characteristics and unclear synergistic mechanism of reaction between viscosity reducer and nitrogen during nitrogen stimulation assisted by common heavy oil viscosity reducer, the microscopic distribution characteristics of fluid and the mechanism of viscosity reducer in the stimulation process were discovered by microscopic visual experiments and physical simulation to compare and study the production characteristics of nitrogen stimulation assisted by common heavy oil viscosity reducer. The results showed that in the nitrogen stimulation assisted by common heavy oil viscosity reducer, the viscosity reducer effectively dispersed crude oil and nitrogen to form oil-in-water emulsion and a small amount of foam, and the Jamin effect of the emulsion and foam effectively inhibited gas channeling to enlarge the affected area, extend the action time of elastic energy of gas and prolong the effective nitrogen stimulation cycle, and the oil recovery was improved by 6.5 percentage points with nitrogen stimulation assisted by common heavy oil viscosity reducer in the indoor experiments. The study results are conducive to further clarifying the principles of viscosity reducer selection and provide a reference for the field application of nitrogen stimulation assisted by viscosity reducer.

Study on the Characteristics of Changes in Heavy Oil Components during In-Situ Combustion

Jiang Haiyan, Li Tianyue, Du Kun, Yuan Shibao, Zhang Yupeng

2021, 28(4):  96-101.  DOI: 10.3969/j.issn.1006-6535.2021.04.013

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In view of the complicated changes in heavy oil components during in-situ combustion, the characteristics of changes in heavy oil components between different zones in the in-situ combustion were studied based on CMG-WinProp module. The results of the study showed that the heavy components were cracked into light components by high-temperature oxidation reaction in the combustion zone; the light components were polymerized and converted into heavy components in the coking zone; the light oil after combustion reaction was mainly accumulated in the oil bank zone. The change of the phase diagram showed that with the progress of in-situ combustion, the reservoir temperature was gradually increased, the gas-liquid area was gradually widened, and the critical point of phase diagram moved to the upper left with the increase of light component content. The study results are of great significance for further understanding the laws of component changes in the thermal recovery of heavy oil.

Effect of Hydrophobic Carbon Chain Length of Alkyl Betaine Surfactant on Spontaneous Imbibition of Low-permeability Core

Zhu Weiyao, Zhao Chengyuan, Ma Qipeng, Li Hua, Song Zhiyong

2021, 28(4):  102-107.  DOI: 10.3969/j.issn.1006-6535.2021.04.014

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In view of the influence of different hydrophobic carbon chain lengths of alkyl betaines with the same hydrophilic group structure on the imbibition mechanism, the influence of the hydrophobic carbon chain length of alkyl betaine on spontaneous imbibition under the conditions of high temperature, high salinity and low permeability conditions was analyzed by experiments conducted on spontaneous imbibition, contact angle and oil-water interfacial tension. The results showed that with the increase of carbon number of the hydrophobic group from 12 to 18, the degree of imbibition and recovery of the four alkyl betaines were 37.8%, 39.4%, 41.0% and 42.1%, respectively; the reverse imbibition was adopted; the contact angle decreased with the increase of carbon number, favorable to crude oil stropped from the core, and the interfacial tension decreased with the increase of carbon number, conducive to the deformation and flow of oil droplets, both of which promoted the imbibition. The experimental results were in line with the normalized recovery percent model, with a theoretical guidance for the application of alkyl betaine as a imbibition agent in low-permeability oil fields.

Characteristics of Preferential Migration Pathway of Polymer Flooding in Conglomerate Reservoirs and Its Effects on Remaining Oil

Bai Lei, Sun Pengchao, Hu Xiaodie, Wan Qingshan

2021, 28(4):  108-115.  DOI: 10.3969/j.issn.1006-6535.2021.04.015

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To address the problem of high water cut increasing rate and high fluid production rate in the conglomerate reservoir of Kexia Formation of QD1 reservoir, grid simulation with Rdos software and Eclipse chemical flooding simulation were conducted to characterize the preferential migration conduit and its relationship with remaining oil distribution in different stages of polymer flooding. The results show that the preferential migration conduit in Kexia Formation of QD1 reservoir was divided into two types. In the four stages of polymer flooding, 6 and 17 Type I conduits were developed in the front water flooding stage and the return regression stage respectively, and were concentrated in horizontal fractures and the relative-high-permeability area of the reservoir; Type II conduits were mainly developed in the near east-west direction in the effective peak period and the stable production period of polymer flooding; preferential migration conduit was an important factor to control the distribution of remaining oil in conglomerate reservoir of Kexia Formation; the remaining oil in the east of the study area was distributed in preferential migration conduit in the shape of bird foot and island; with the expansion of water flooding range, the remaining oil was reduced into clumps and spots, while the remaining oil in the west was distributed in a strop or line shape near the fault. This study provides a basis for the design of plugging measures for preferential migration conduit in QD1 oilfield and the improvement of the polymer flooding effect in conglomerate reservoir.

Study on Oil Recovery Enhancement by Gas-Injection Stimulation Assisted by Water Flooding in Complex Reservoir with Small Fault Block

Qu Shiyuan, Jiang Hanqiao, Li Junjian, Zhou Yu, Ma Kang, Chang Yuanhao

2021, 28(4):  116-122.  DOI: 10.3969/j.issn.1006-6535.2021.04.016

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In complex reservoir with small fault block, water or gas injection is difficultly to be applied to the whole reservoir and has little effect on the further developing the remaining oil. In order to improve the recovery efficiency of remaining oil in the complex reservoir with small fault block during the high water cut stage, numerical simulation methods were employed to explore the gas-injection stimulation assisted by water flooding, and its reservoir adaptability was analyzed by economic and efficiency indicators. According to the development effect of typical models under different measures, the optimal development mode of this method was determined as follows: energy supplement-energy enhancement bu well shut-in-shut-in stage-development stage; its technical limits were further determined as follows: the ratio of gas and water injection rates was 6.5 to 8.5, the pressure ratio between Stage 2 to Stage 1 was 0.1 to 0.3, and the injection-production ratio was 0.4 to 0.6. The study results were applied to Block A-7 of Shengli Oilfield, and the simulation prediction showed that this method improved the oil recovery by 12.96 percentage points compared with basic water-flooding development. The study results play an important guiding role in the development measure adjustment and oil recovery enhancement in complex reservoir with small fault block during the high water cut stage.

Influence and Application of Dynamic Imbibition on the Development of Ultra-low Permeability Reservoirs

Hu Yafei, Li Junshi, Hu Shuiqing, Wu Zhiying, Jiang Jing, Dong Ning, Hu Boyang, Lyu Yanbing

2021, 28(4):  123-128.  DOI: 10.3969/j.issn.1006-6535.2021.04.017

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In view of low permeability in ultra-low permeability reservoirs, complex pore throat structure, high heterogeneity, difficulty in realizing effective displacement with conventional water injection, strong imbibition between fractures and matrixes, and other problems, dynamic imbibition characteristics and main influencing factors were worked out by indoor imbibition experiments and similar theories on the basis of the mechanism analysis of dynamic imbibition and oil displacement in ultra-low permeability reservoirs, and the laboratory data were applied to the oilfield site. As indicated by experimental results, the main factors affecting dynamic imbibition in ultra-low permeability reservoirs included wettability, injection rate, fracture density, and stimulation turns. Among them, wettability was the primary factor affecting the imbibition. The stronger the hydrophilicity of the rock, the higher the permeability, the more fractures, and the better the dynamic imbibition effect; the water injection rate suitable for the development of ultra-low permeability reservoir was 0.1 mL/min; the reasonable stimulation turn was 2 to 3 cycles, and the optimal shut-in duration was about 30 days. The significant effect of dynamic imbibition was proven by the field tests where the average water cut was reduced by 20 percentage points, and the cumulative oil production was increased by 2 145 t in 5 horizontal wells after fracturing by stimulated reservoir volume and dynamic imbibition in Oilfield A, Ordos Basin. The study results play a guiding role in the formulation of production scheme of ultra-low permeability oilfields.

Study on Evaluation Method of Flow Field in Offshore Oil Reservoirs

Cai Hui, Liu Yingxian, Ma Kuiqian, Jiang Ruizhong, Zhang Fulei

2021, 28(4):  129-135.  DOI: 10.3969/j.issn.1006-6535.2021.04.018

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Aim to the difficulties during the evaluation of favourable channels and displacing heterogeneity, namely water fractional flow, development coefficient and flux intensity were obtained to characterize the flow field of offshore oil reservoir, by the law of the water fractional flow relationship curve, in combination with new parameters based on the evaluation of offshore oil oilfields in the high water-cut stage. The flow field was classified with feature classification point method. Three feature classification points were determined by the characteristics of the linear section of the relationship curve of flux intensity and water flow rate and the inflection points on the linear section of the semi-logarithmic curve of the oil-water permeability ratio, and a "three-point and four-level" index flow field characterization method was established. The study results were applied to the flow field evaluation of offshore oil reservoirs, and the results showed that when the water fractional flow of the three classification points was 22%, 73% and 90%, respectively, the potential, development status and dominance of the flow field can be clearly defined. This flow field evaluation method is of certain theoretical guiding significance for the flow field reconstruction and development effect improvement in the later stage of offshore oilfields.

Description and Control Strategy of SAGD Steam Chamber of Extra-heavy Oil Reservoir with Edge-Top Water

Ge Mingxi

2021, 28(4):  136-141.  DOI: 10.3969/j.issn.1006-6535.2021.04.019

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Affected by the heterogeneity of the reservoir, the SAGD steam chamber in super-thick massive extra-heavy oil reservoir with no interlayer and top-edge water was unevenly developed in the vertical direction, with a risk of top-edge water drainage. In response to this problem, the spatial distribution characteristics of the steam chamber were three-dimensionally characterized based on the detailed description of the SAGD steam chamber in Block Du 84 of Liaohe Oilfield, steam injection interruption, steam injection reduction, intermittent steam injection and non-condensate gas injection were optimized and compared through numerical simulation, the impact of different development modes on the expansion of steam chamber was demonstrated, and the SAGD steam chamber balance control strategy was proposed. The results showed that the four control methods all restrained the steam chamber from expanding upward, and the intermittent steam injection was easier to balance the steam chamber, reduce steam consumption, extend the development period, with the production characteristics of high oil-steam ratio and high net oil production. There is much for technical guiding significance of this study to the description and control technology of SAGD steam chamber.

Characteristics and Influencing Factors of Dynamic Imbibition at High Temperature and High Pressure in Tight Sandstone Reservoir

Liu Jizi, Gong Lianhao, Bu Guangping, Wu Xing

2021, 28(4):  142-149.  DOI: 10.3969/j.issn.1006-6535.2021.04.020

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In order to solve the problem of low matrix producing degree in the water flooding process of tight sandstone reservoir, waterflood huff-puff and dynamic imbibition core experiments under the action of four typical surfactants were conducted to study the influence of mass fraction of surfactant, displacement speed, injection amount, well shut-in time, permeability and fracture on the dynamic imbibition effect. The results showed that the dynamic imbibition displacement efficiency first increased and then decreased with the acceleration of the displacement speed, and increased with the increase of surfactant mass fraction, injection amount and shut-in time, but the increase of displacement efficiency decreased continuously; the imbibition efficiency under the action of AEO-2 anionic surfactant was the highest and the best injection conditions were 0.3% mass fraction, 0.1 mL/min displacement speed, injection volume of 1.2 times pore volume and 18 h well shut-in; permeability and fracture were positively correlated with dynamic imbibition efficiency; large-scale fracturing by stimulated reservoir volume and acidification stimulation were important factors to improve the dynamic imbibition efficiency. The field test results showed that the average oil production of oil wells was increased by 166% and the average water cut decreased by 25.8% after waterflood huff-puff and dynamic imbibition in oil wells. The effect of increasing oil production and decreasing water cut was remarkable, so the dynamic imbibition has a greater prospect of application and promotion.

Drilling & Production Engineering

Analysis of Influencing Factors of Temperature Profile of Fractured Horizontal Wells in Tight Gas Reservoirs

Luo Hongwen, Li Haitao, An Shujie, Xin Ye, Li Lei, Zou Shunliang, Li Ying, Liu Chang

2021, 28(4):  150-157.  DOI: 10.3969/j.issn.1006-6535.2021.04.021

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The absence of horizontal well temperature profile prediction models and the unclear dominant factors affecting the temperature profile make it very difficult to invert and interpret the production profile of fractured horizontal well in tight gas reservoirs based on the temperature test data of distributed optical fiber. To this end, a coupled temperature profile prediction model was established for fractured horizontal wells in tight gas reservoirs, taking into account multiple micro thermal effects and heat transfer in the fracture system, the reservoir temperature distribution and wellbore temperature profile characteristics of fractured horizontal wells in tight gas reservoir were simulated and analyzed, and the influence of different influencing factors on temperature profile was evaluated by orthogonal experimental analysis and quantitative empirical analysis. It was found in the study that the following factors were listed in descending order according to their influence of the factors on the temperature profile of fractured horizontal wells in tight gas reservoirs: fracture half-length, daily gas production of single well, reservoir permeability, wellbore diameter, fracture conductivity, wellbore inclination in horizontal section and the total thermal conductivity of the reservoir; the dominant factors were fracture half-length, daily gas production of single well, and reservoir permeability. The establishment of the temperature model and the determination of the dominant factors of the temperature profile laid a theoretical foundation for the quantitative interpretation of the production profile and fracture parameters of the fractured horizontal wells in tight gas reservoirs.

Study on Preparation of NiW-Si₃N₄/MWCNTs Composite Coating by Pulse Electrodeposition and Its Performance

Zhang Wei, Li Bengang, Long Xiongyun, Jing Wenjie, Zhu Mingzhao, Li Hongjie, Zhang Weigang, He Teng

2021, 28(4):  158-163.  DOI: 10.3969/j.issn.1006-6535.2021.04.022

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It is prone to corrosion for the steel surface of tubing and casing exposed to complex working conditions for a long time, leading to a reduction in the service life of the material and impact on the production of oil wells. NiW-Si₃N₄/MCNTs composite coating was prepared on the surface of C45 steel substrate by pulse electrodeposition technology, and the influence of the amount of nano-particles Si₃N₄ and MWCNTs used on the surface micromorphology, hardness and corrosion resistance of the composite coating was explored. It was found in the study that nano-particles added could inhibit the growth of the (220) and (200) crystal planes of the Ni-W coating, and promoted the crystal particle refinement of the Ni-W coating, greatly enhancing the microhardness (up to 1 243.7 HV) of NiW-Si₃N₄/MCNTs composite coating; compared with Ni-W coating, NiW-Si₃N₄/MCNTs composite coating was higher in resistance, lower in corrosion rate and better in corrosion resistance. The study laid a theoretical foundation for further enhancement of physico-chemical properties of Ni-W plating and reduction of tubing corrosion.

Application of Radioisotope Logging Technology in Injection Wells with Multi-layer Strings

Liu Zhenjiang, Wang Xiaojun

2021, 28(4):  164-169.  DOI: 10.3969/j.issn.1006-6535.2021.04.023

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To address the problem that the conventional radioisotope injection profile logging technology cannot meet the requirements of the water injection profile test of injection wells with multi-layer strings, the accuracy of radioisotope tracer testing was improved by selection of optimal radioisotope tracer and anti-dispersion agent, optimization of radioisotope tracer injection parameters, and other measures. The isotope tracer release device at wellhead was developed to release the isotope tracer at the wellhead Christmas tree based on the water injection pressure difference between different water injection intervals, which was simple and reliable in operation. This technology solves the logging difficulties of injection wells with multi-layer strings, and provides technical support for the promotion and application of the technology of injection well with multi-layer string.

Study and Application of Profile Control Technology of Produced Sand in Super Heavy Oil Reservoir, Xinjiang

Lyu Bolin, Xing Xiangrong, Fan Jingwen, Hu Pengcheng, Ma Peng, Yang Chun

2021, 28(4):  170-174.  DOI: 10.3969/j.issn.1006-6535.2021.04.024

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In view of the severe heterogeneity of thermal stimulation with steam injection in heavy oil reservoirs, the poor development conditions of low-and medium-permeability layers, and the serious interference of steam channeling in high-permeability layers, a new KWF compound plugging agent was developed independently by indoor experiments where curing agent (inorganic salt), dispersant (bentonite) and coagulant (caustic soda) were added to the produced sand of the oilfield through. The new plugging agent was featured by adjustable curing time (3 to 300 h), and resistance to pressure of greater than 6 MPa and temperature of greater than 350 ℃. After the plugging agent was injected into the high-permeability steam channeling, the system was cemented with the formation rock and the sealing rate was more than 85%, without any damage to the low-and medium-permeability layers. The field application showed that the system effectively blocked the big pores and enhanced the oil production, and the cumulative oil production was increased by 1 057 t. The produced sand profile control technology not only solves the environmental pollution caused by produced sand, but also reduces the cost of thermal recovery of heavy oil, with great significance for improving the final recovery efficiency and commercial benefits of the oilfield.