Table of Content

25 February 2024, Volume 31 Issue 1

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Summary

Research and Prospects of Efficient and Low-carbon SAGD Development Technology for Shallow Ultra-Heavy Oil in Xinjiang Oilfield

Sun Xin′ge, Luo Chihui, Zhang Shengfei, Zhang Wensheng, Luo Shuanghan

2024, 31(1):  1-8.  DOI: 10.3969/j.issn.1006-6535.2024.01.001

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In response to the increasing contradiction between high energy consumption for ultra-heavy oil development and high quality development of oilfield in the context of “carbon neutrality and emission peak” target, Xinjiang Oilfield, through mechanism research and field practice, has continued its research and achieved significant results in maintaining efficient expansion of steam chamber, breaking through reservoir seepage barrier blockage, improving the steam flooding and gravity drainage efficiency in shallow and thin layers, and achieving efficient and balanced fluid production in long horizontal sections of horizontal wells: the gas-assisted technology is employed to achieve the insulation, pressure retention and energy boosting of steam chambers, and the oil-to-steam ratio can be increased by up to 20%; the vertical well pattern and reservoir upgrading and expansion technologies are utilized to improve the seepage characteristics of Class Ⅲ ultra-heavy oil reservoirs, and the drainage rate can be increased by 20% to 40%; the fully confined production method is adopted, resulting in an increase in VHSD produced liquid temperature from 100 ℃ to 150 ℃ and a 50% increase in oil recovery rate; a further research on the mechanism of thermal recovery flow control device (FCD) is conducted, and the reservoir-wellbore coupling optimization design method is improved, so the production degree of the horizontal section of horizontal wells can be increased by 20%. During the “14th Five-Year Plan” period, Xinjiang Oilfield will conduct a further research of solvent-assisted SAGD, waterless SAGD and temperature-controlled hydrothermal fracturing technologies, and gradually improve the series of low-carbon and high-efficiency development technologies for shallow ultra-heavy oil. The research can provide technical guidance for the development of similar reservoirs.

Research Progress and Development Trend of Heavy Oil Chemical Viscosity Reducing Agent

Zhang Yang, An Gaofeng, Jiang Qi, Wang Dingli, Mao Jincheng, Jiang Guanchen

2024, 31(1):  9-19.  DOI: 10.3969/j.issn.1006-6535.2024.01.002

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In the dual-carbon context, how to economically, efficiently, and greenly enhance the recovery of heavy oil reservoirs by heavy oil recovery technology based on thermal recovery is a key concern of researchers. The essence of realizing commercial development of heavy oil reservoirs is to reduce the viscosity and enhance the flow capacity of heavy oil. The article systematically analyzed the viscosity-inducing mechanism of heavy oil and the viscosity-reducing mechanism of various viscosity reducers, summarized the synthesis processes of emulsifying viscosity reducers, oil-soluble viscosity reducers, and nano viscosity reducers, and evaluated the advantages and shortcomings of different viscosity reducers. The advantages and shortcomings of different viscosity reducers were evaluated. The development trend of viscosity reducers was also discussed and prospected. Sorting out the existing chemical viscosity reducers could help develop new viscosity reducer systems and enhance the recovery of heavy oil reservoirs.

Geologic Exploration

Differential Evolutions of Hydrocarbon Generation and Expulsion History of Lower Cambrian Source Rocks in Tahe Oilfield and Accumulation Effects

Xu Qinqi, Zhang Li, Li Bin, Zhong Li, Zhang Xin, Zhou Haodong

2024, 31(1):  20-30.  DOI: 10.3969/j.issn.1006-6535.2024.01.003

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In response to the unclear understanding of the main controlling factors for multiphase oil and gas enrichment of the Ordovician oil reservoirs in Tahe Oilfield, the basin simulation technology was used to reconstruct the thermal evolution history and hydrocarbon generation history of the Lower Cambrian source rocks, and oil and gas migration and accumulation processes of typical profiles. The research shows that the Lower Cambrian source rocks in Tahe Area have entered a mature stage from the early Caledonian period and are currently in a high maturity-wet gas stage. They have developed three thermal evolution models of intermittent burial, continuous burial, and long-term shallow burial, corresponding to three hydrocarbon generation models of dual peak, strong oil and weak gas, and single peak. The differential thermal evolutions of source rocks lead to the history of oil and gas evolution with multiple stages of filling, vertical migration, and lateral adjustment and transformation in the Ordovician. The oil and gas phases present an orderly distribution pattern of light-medium-heavy oil reservoirs. The thermal evolutions of the Lower Cambrian source rocks in different structural belts in Tahe Area show a trend of increasing from northwest to southeast, showing a clear positive correlation with the differences in oil and gas phases, reflecting the characteristics of "source control". The thermal evolution characteristics controlled the distribution of current oil and gas reservoirs in the Himalayan period. Research indicates that the hydrocarbon generation intensities in the salt zone and Tuofutai of Tahe Oilfield are high, and the total amount of hydrocarbon generation during the Himalayan period is relatively large, making it a favorable area for further exploration and development. The research results have certain guiding significance for the evaluation of deep oil and gas resources and targets in Tahe Oilfield.

Analysis of Geochemical Characteristics of Low Oil Saturation Reservoirs of Badaowan Formation in Mahu Slope,Junggar Basin,China

Xu Bodong, Zou Xianli, Wu Xinyu,Zhao Wenping,Wang Aixia, Xu Tao, Zhao Xiaodong

2024, 31(1):  31-38.  DOI: 10.3969/j.issn.1006-6535.2024.01.004

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Low oil saturation reservoirs of the Jurassic Badaowan Formation have been discovered in the shallow and middle layers of the slopes of Mahu Sag in Junggar Basin,but the production rates of the old wells are different after the production test, and it is difficult to identify the "sweet spots" of the reservoirs. Therefore, the geochemical characteristics of Badaowan Formation reservoirs were investigated using oil and gas geochemical parameters. The results show that the biomarker compounds of the crude oils from low oil saturation reservoirs of Badaowan Formation are of great significance in identifying the similarities and differences of crude oils and analyzing the genesis of crude oils. The crude oils are generally characterized by a high abundance of β-carotene and γ-cerane, which are the products of the typical hydrocarbon source rocks of the Permian Fengcheng Formation. Among them, the γ-cerane abundance of crude oils from low-production wells is relatively low, and Ts/Tm is large; the γ-cerane abundance of crude oils from high-production wells is high, and Ts/Tm is small. The chromatography effect is the main reason for the differences in biomarker compounds among crude oils. Comprehensive analysis shows that the fault communication mode and reservoir filling process affect the oil and gas accumulation, and the low oil saturation reservoirs in Badaowan Formation formed by tectonic tilts and adjustments in the late period have more exploration potential. Study results could provide ideas and directions for the next exploration and development in Mahu Sag.

Mesozoic Heavy Oil Source Analysis of Chepaizi Uplift in Junggar Basin

Yin Yanfang, Chang Xiangchun, Xu Youde, Su Lei, Liu Zhongquan

2024, 31(1):  39-47.  DOI: 10.3969/j.issn.1006-6535.2024.01.005

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Based on the analysis results of gas chromatography-mass spectrometry (GC-MS) of the Mesozoic crude oils, the biodegradation degree of the crude oils was quantitatively evaluated, the original quality of the typical biomarkers was recovered, and the oil source of heavy oils severely biodegraded was investigated in combination with hierarchical cluster analysis and biomarker parameter recovery method to clarify the oil source of the Mesozoic heavy oils from Chepaizi Uplift in Junggar Basin. The results show that the biodegradation level of crude oils in the Mesozoic of Chepaizi Uplift reaches more than 6 (PM6), which could be subdivided into two groups: A1 and A2. The proposed biomarker parameter recovery method for oil source comparison is effective, confirming that the A1 crude oils are related to the Permian hydrocarbon source rocks of Shawan Depression, and the A2 crude oils may come from the mixing of the Permian hydrocarbon source rocks of Shawan Depression, the Carboniferous hydrocarbon source rocks of Chepaizi Uplift and the Jurassic hydrocarbon source rocks of Sikeshu Depression, which is further supported and validated by principal component analysis (PCA). The study results are an essential reference for deepening the hydrocarbon exploration and deployment in the Mesozoic of the Chepaiko Uplift.

Reservoir Engineering

Indoor Experiment and Technical Boundary of Heavy Reservoir with Gas Huff and Puff Assisted by Low-Viscosity Oil Injection

HU Changhao

2024, 31(1):  48-56.  DOI: 10.3969/j.issn.1006-6535.2024.01.006

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In the late stage of steam huff and puff or steam flooding for the heavy oil reservoir, the oil-steam ratio is only 0.1 to 0.2, which leads to high energy consumption and carbon emissions. To address the issue, a recovery method that utilizes low-viscosity oil injection assisted heavy reservoir with gas huff and puff has been proposed to improve the development effect. Through indoor test and reservoir numerical simulation, the mechanism and applicability are studied, and the technical boundary are delimited. The study shows that the mechanism of heavy reservoir with gas huff and puff assisted by low-viscosity oil injection is mainly viscosity reduction by dilution, solution gas drive, swept volume expansion and facies change by emulsification. The oil-carrying rate (volume ratio of produced heavy oil to injected low-viscosity oil) can reach 1.00-3.00, and the energy consumption and the water production is low. The new method is suitable for conventional heavy oil reservoirs and extra-heavy oil reservoirs, especially for deep zones, thin interbedded and small fault blocks. This study has guiding significance for reservoir screening and engineering design of heavy reservoir with gas huff and puff assisted by low-viscosity oil injection.

Optimization of Lateral Morphology of SAGD Fishbone Multilateral Wells and Recovery Change Law

Zhou Zhijun, Zhang Qi, Yi Xi, Tang Jiaqi, Zhang Guoqing

2024, 31(1):  57-65.  DOI: 10.3969/j.issn.1006-6535.2024.01.007

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Reservoir properties in Fengcheng oilfield are commonly poor, and their heterogenity is strong. SAGD fishbone multilateral wells can address the issue of limited steam chamber expansion of conventional SAGD by lateral penetrating deeply into the reservoir. In order to achieve the best development effect, it is necessary to optimize the lateral morphology of SAGD fishbone multilateral wells and grasp the law that affects the recovery variation. To this end, reservoir numerical simulation and orthogonal test design are used to determine the sensitivity of the lateral parameters to enhance oil recovery and optimize the lateral parameters. As a resunt, the influence of the lateral parameters on enhanced oil recovery is analyzed in reservoirs with different physical properties. The research results are applied to Fengcheng Oilfield, and the optimal well deployment scheme for the target block is as follows: lateral length is 120 m, the number of laterals is 4, the angle of laterals is 75 °, the laterals are asymmetrically distributed, and the spacing between laterals are 100 m. The research showed that the influence weights of each lateral parameter take the reservoir permeability of 2.0 D as the obvious cutoff point: the main influencing factors are lateral length, lateral angle, and lateral spacing when the reservoir permeability is less than 2.0 D, and the influence of lateral parameters on the increase of recovery, the impact of lateral angle and lateral spacing starts to become stronger when the reservoir permeability 2.0 D The Study results are of great significance for further enhanced oil recovery of the recovery of SAGD drive in Fengcheng Oilfield.

Characterization and Parameter Optimization of Steam-Air Compound Flooding in Heavy Oil Reservoirs

Yuan Shibao, Ren Zihan, Yang Fengxiang, Sun Xin′ge, Jiang Haiyan, Song Jia

2024, 31(1):  66-73.  DOI: 10.3969/j.issn.1006-6535.2024.01.008

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Aiming at the problems of the low heat utilization rate and slow startup of high viscosity oil in conventional fire flooding, taking the heavy oil reservoirs in Xinjiang Hongqian 1 Well Area as an example, the numerical simulation model was used to compare the oil displacement characteristics and combustion characteristics of conventional fire flooding and steam-air compound flooding, and the synergistic effects of the steam-air compound flooding was investigated and the injection parameters of the steam-air compound flooding were optimized through the analysis of the temperatures, oil saturation, and other parameters of the compound flooding in each zone. The results show that the main mechanisms to increase production and enhance efficiency are that the moist steam absorbs the heat retained in the combustion zone, becomes superheated steam, and is carried by the high-rate air across the combustion fronts so that the viscosity of the crude oil in the cold oil zone is significantly reduced, which improves the oil displacement efficiency while increasing the width, swept volume of combustion, and burning rate of the steam condensate zone; the optimization of the slug injection parameter could improve the development effect of the compound flooding, and the higher water-air ratio could make the production capacity higher; the optimal water/gas ratio should be about 3.0, and the optimal intervals between the steam injection slugs should be 90-120 d to meet the economic benefits of development because the slug injection could decrease production capacity. The research results are of great significance to improving the development effect of the fire flooding oil reservoirs.

Mechanism and Parameter Optimization of Thermal Solvent-Assisted Gravity Drainage Oil Recovery in Heavy Oil Reservoirs

Li Songyan, Cheng Hao, Han Rui, Wei Yaohui, Li Minghe, Feng Shibo

2024, 31(1):  74-80.  DOI: 10.3969/j.issn.1006-6535.2024.01.009

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There are significant heat loss, high water cut, and poor development effects during the recovery process of heavy oil reservoirs. Taking the Mackay River Reservoir in Canada as the research object, the numerical simulation model of hot solvent-assisted gravity drainage technology was constructed, and characteristics of SAGD, VAPEX, and hot solvent-assisted gravity drainage recovery were compared. The parameters are optimized for production pressures, injection rates, and injection temperatures of hot solvents. The results show that the hot solvent-assisted gravity drainage technology is better than SAGD and VAPEX in terms of injection and production differential pressure, oil recovery, and oil recovery rate; in the actual development process, the optimal conditions for the application of hot solvent-assisted gravity drainage technology are as follows: the bottomhole production pressure is 700 kPa, the injection rate is 160 m³/d, and the injection temperature is 275 ℃. The results of the three-dimensional experiments further validate the results of the numerical simulation calculations. This study provides a reference for efficiently developing shallow heavy oil reservoirs.

Feasibility of In-Situ Hydrogen Production During Fire Flooding in Reservoirs after Steam Injection Development

Wang Tiantian, Zhao Renbao, Jiang Ningning, Li Xin, Xu Han, Wang Hao

2024, 31(1):  81-86.  DOI: 10.3969/j.issn.1006-6535.2024.01.010

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A study on the influence of water saturation on the in-situ hydrogen production effect from heavy oil was carried out through combustion tube experiments to study the feasibility of technology on in-situ hydrogen production during fire flooding in reservoirs after steam injection development. The results show that the presence of water enhances the convective heat transfer effect and provides a high-temperature environment for the fracture of C-C and C-H in hydrocarbons and promotes the reversible reactions such as hydrothermal cracking, coke gasification, and water-steam conversion of heavy oil to move toward hydrogen production, which improves the in-situ hydrogen production effect. The temperature is 715.1 ℃, and the hydrogen volume fraction is up to 1.03% when the water saturation reaches 24.58%. The results verified the feasibility of in-situ hydrogen production from heavy oil during fire flooding in heavy oil reservoirs after steam injection development, and the study has significant reference value for improving the in-situ hydrogen production effect from heavy oil during fire flooding.

Study on Oil and Water Flow Characteristics of Thermochemical Flooding in Ultra-Thick Oil Reservoirs

Sun Baoquan, Yang Yong, Wu Guanghuan, Zhao Hongyu, Zhang Min, Sun Chao, Zhang Hejie

2024, 31(1):  87-93.  DOI: 10.3969/j.issn.1006-6535.2024.01.011

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Oil-water flow characteristics in different temperature regions are unknown during the thermochemical flooding in ultra-heavy oil reservoirs. The effects of hot water and oil displacement agents on oil displacement efficiency and the change rule of relative permeability at different temperatures were quantitatively investigated, and the impact of hot water and oil displacement agents on the oil flooding and their interaction were analyzed by using microscopic visualization experiments and one-dimensional physical simulation experiments. The experimental results show that the oil phase relative permeability increases in high-temperature oil displacement agent flooding when the temperature is 70 ℃, and the water phase relative permeability changes are negligible when the temperature is 150 ℃, the synergistic effect of hot water and oil displacement agent is more significant, and the relative permeability of the oil phase and water phase increases significantly under high-temperature oil displacement agent flooding after hot water flooding and direct high-temperature oil displacement agent flooding; the role of oil displacement agent weakens at the high-temperature restriction, and the hot water significantly enhances the oil displacement efficiency after the temperature is more than 200 ℃. The oil displacement efficiency of the oil displacement agent increases first and then decreases After the temperature exceeds 200 ℃. Thermochemical flooding can realize the beneficial development of ultra-heavy oil reservoirs through the successive driving and synergistic action of hot water and oil displacement agents in different temperature regions. This study can provide a reference for thermochemical flooding to enhance the recovery of ultra-heavy oil reservoirs.

Research and Practice of Viscosity-Reducing Composite Flooding Technology for Conventional Heavy Oil Reservoirs

ZhaoLin, Hao Li′na, Yu Chunsheng, Zhang Yong, Xiao Menghua, Chai Xiqiong, Yao Jiang, Gong Hengyuan

2024, 31(1):  94-100.  DOI: 10.3969/j.issn.1006-6535.2024.01.012

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Aiming at the problems of low recovery of water flooding, high cost and high carbon emission of thermal recovery in conventional heavy oil reservoirs, anionic viscosity reducer and salt-resistant polymers were preferred based on the low-temperature and high-salt properties of reservoirs in Chunguang Oilfield. The water cut reduction and oil production increase mechanisms of hot-water flooding, single viscosity reducer flooding, and composite flooding were clarified based on indoor physical simulation experiments. The kinetic equations of the reaction of viscosity-reducing composite flooding were established. The numerical simulation method of viscosity-reducing composite flooding was developed in CMG-STARS software. Well-pattern spacing and injection-production strategy of viscosity-reducing composite flooding were optimized for conventional heavy oil reservoirs in Chun 2 unit. The results show that the viscosity-reducing composite flooding could give full play to the synergistic effect of viscosity enhancement of the displacing phase and viscosity reduction of the displaced phase, and it has the advantages of low system dosage, low carbon emission, and significant recovery enhancement; the viscosity-reducing composite flooding is suitable for five-spot pattern, the injector-producer distance should be less than 200 m; the optimal injection slug volume is 0.5 times of the pore volume and the injection to production ratio is 1.05 with the mass fraction of the viscosity-reducing agent at 0.25%. Practice shows that the water cut in wells was reduced by more than 30%, and the daily oil production was increased by 5 t/d after the viscosity-reducing composite flooding was implemented in extra-high water cut (water cut of 96%) reservoir at the late stage. This study confirms the feasibility of this technology applied in the field. It provides a reference to improve the effect of the development of conventional heavy oil reservoirs and realize the reduction of industrial emissions.

Enhanced Oil Recovery Experiment of Foam Oil Cold Recovery Induced by Water-Alternating-Gas Injection in Heavy Oil Reservoirs

Zhen Guinan, Wang Jian, Wu Baocheng, Wang Weilong, Tang Yang, Lu Yuhao

2024, 31(1):  101-108.  DOI: 10.3969/j.issn.1006-6535.2024.01.013

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Aiming at the problems of viscous indexing, insufficient producing, and low recovery in the process of water flooding in ordinary heavy oil reservoirs, based on Ji 7 Reservoir in Xinjiang Oilfield, the foam oil cold recovery technology was researched induced by water-alternating-gas injection, and the foam oil sample preparation device was designed by itself. The image of foam oil was characterized by Image J software, and the performance, bubble diameter, and foam number of foam oil were comprehensively analyzed; the visual plane model was designed and made to research the microscopic oil displacement mechanism of foam oil during gas injection assisted water flooding in heavy oil reservoir; the core displacement experiment was carried out to optimize the injection parameters of foam oil cold recovery induced by water-alternating-gas. The research shows that the foam oil formed by CO₂ in low-viscosity crude oil has better performance; the foaming volume is 202.1 mL, the half-life is 324 s, and the viscosity reduction rate is 32.35%; the foaming volume and half-life of foam oil are usually negatively correlated with the bubble diameter and the number of foam oil; the foam oil polymerization has a stripping effect on viscous wall residual oil, and CO₂ can effectively produce crude oil, oil film, and upper crude oil in small pore throat; under the condition of the gas-liquid ratio of 1∶1, the injection pressure of 30 MPa, and flooding rate of 0.2 mL/min, the foam oil cold recovery induced by water-alternating-gas could improve recovery by 18.90% compared with the ordinary water flooding in the heavy oil reservoir. The research results provide a theoretical basis for the foam oil cold recovery induced by water-alternating-gas injection in Ji 7 reservoir of Xinjiang Oilfield and also provide a reference for the enhanced oil recovery technology of water flooding heavy oil reservoirs in other oilfields.

Diffusion Law of Thermochemical Oil Displacement System for Heavy Oil Reservoirs

Yu Jianmei, Wei Tao, Du Dianfa, Ren Lichuan, Hao Fanghui

2024, 31(1):  109-115.  DOI: 10.3969/j.issn.1006-6535.2024.01.014

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It is prone to steam channeling during steam flooding in heavy oil reservoirs, which makes the sweep coefficient small and the recovery low. So, thermochemical flooding technology, chemical agent-assisted steam flooding, has been developed. The diffusion laws of chemicals in thermochemical oil displacement systems are unclear and the field application effects are different. So, a mechanism model was constructed on the basis of physical simulation experiments, the diffusion laws of viscosity reducers and foams in different systems were studied qualitatively and quantitatively, and the diffusion laws of chemicals were clarified considering the pressure effect. The study shows that the viscosity reducer plugs diffuse along the dominant channels to promote steam channeling, but foam plugs block steam channels and modify injection profiles in the diffusion, which promotes the uniform expansion of the steam chambers. There is an interplay between the two, and the viscosity reducer plug should be placed in the foam after the plug. Thus, the steam channeling speed and the molar concentration of foam in mainstream directions are reduced by 8% and 30%, respectively. At the same time, a certain displacement pressure difference should be guaranteed, and the pressure could increase the swept volume of the chemicals and average molar concentration by 2.3 times and 1.0 times, respectively. The study has a reference value for the design of thermochemical flooding programs in heavy oil reservoirs.

Experimental Study on Influence of Petroleum Acid Content on Heavy Oil Fluid Properties

Li Bulin, Zhang Shengfei, Wang Qiang, Gou Yan, Shen Dehuang, Wang Hongzhuang

2024, 31(1):  116-122.  DOI: 10.3969/j.issn.1006-6535.2024.01.015

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Petroleum acids are strong polar components in the heavy oil system. Taking the ultra-heavy oil samples from SAGD well group of Fengcheng oilfield in Xinjiang as the research object, the molecular structures of petroleum acids were analyzed by high-energy mass spectrometry to study their influence on types, viscosity, and emulsification characteristics of heavy oil fluids. The influence of petroleum acid content on viscosity-temperature characteristics and shear rheology of heavy oil was investigated, and the influence of water cut on the apparent viscosity of heavy oil and its corresponding oil-water emulsification characteristics were analyzed under the conditions of different petroleum acid contents through experiments. The study shows that the acid value (in terms of KOH) of the ultra-heavy oil sample is 5.46 mg/g, the petroleum acid content of the sample is about 1.71%, which are dominated by 2-3 cyclic monoacids, and the carbon number is mainly distributed in the range of 15-35; the viscosity of the heavy oil decreases with the increase of the petroleum acid content; and the inflection point temperature of the sample from the Newtonian to the non-Newtonian fluid decreases from 120 ℃ to 100 ℃ when the content of the petroleum acid increases from 0 to 50%. The apparent viscosity first increases and then decreases when the water cut increases. The water cut at the antiphase point decreases from 30%-40% to 20%-30%, and the viscosity decreases dramatically at different water contents and when the petroleum acid content increases from 0 to 50%. This study reveals the influence of molecular structure characteristics and petroleum acid contents of petroleum acids in ultra-heavy oil on the fluid properties of heavy oil in western China, which provides a reference for reducing emulsification and corrosion of heavy oil and improving the efficient development of heavy oil resources.

Effect of Brine on Asphaltene Precipitation in Emulsions of Water Flooding Reservoirs

Song Jun, Li Haiyan, Song Wei, Liu Yifei, Li Jinhai, Pan Yuewen, Liu Junlong

2024, 31(1):  123-130.  DOI: 10.3969/j.issn.1006-6535.2024.01.016

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Water-in-oil emulsions are very easy to form in reservoir water injection development, and the mechanism of the effect of brine on asphaltene precipitation in emulsions is not clear. To address the above problems, based on the self-made experimental oil and water-in-oil emulsions, static centrifugal experiments and dynamic displacement experiments were carried out by spectrophotometry and simultaneous oil-water injection method, respectively, to study the effects of water cut, salt type, and salt mass concentration on asphaltene precipitation in emulsions, and reveal the mechanism of asphaltene precipitation under the action of salt water. Research shows that when the water cut in emulsion increases from 10% to 50%, the asphaltene instability increases and the mass fraction of precipitation increases from 4.5% to 10.6%, but the precipitation intensity weakens. Asphaltenes with low aromaticity are more likely to precipitate at the water/oil interfaces mainly because of adsorption by heteroatoms on the water surfaces at the interface. Asphaltene precipitation tends to increase and decrease with the increase of salt mass concentration, reaching the maximum when the salt mass concentration reaches 40 000 mg/L. MgCl₂, CaCl₂, NaCl, and KCl affect the amount of asphaltene precipitation from high to low. The emulsion with a 40% volumetric concentration of distilled water shows the most significant decrease in permeability during the flooding, followed by a 20% mass concentration of MgCl₂ emulsion, while the 20% distilled water and 20% NaCl emulsions show the smallest decrease in permeability. The effect of brine on asphaltene precipitation in the dynamic displacement is smaller than that in the static experiment. Still, the increase in water cut increases asphaltene precipitation and decreases core permeability. The research results are significant in improving the development effect of water injection in asphaltene reservoirs.

Indoor Experimental Evaluation of Flue Gas SAGP in Thin Ultra-Heavy Oil Reservoirs

Hui Ruirui, Zhang Zhisheng, Zhang Zhidong, Li Na, Meng Dongfei, Chen Juan

2024, 31(1):  131-136.  DOI: 10.3969/j.issn.1006-6535.2024.01.017

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To address the problem of low recovery rate by steam flooding in thin ultra-heavy oil reservoirs, an indoor two-dimensional physical simulation experiment of flue gas SAGP was conducted on ultra-heavy oil reservoirs with developed interlayers by taking shallow heavy oil in the Hashan area on the northern edge of the Junggar Basin as the study object to study the characteristics of steam chamber development and gas distribution, and to analyze the change law of oil, gas and water in the process of flue gas SAGP, so as to evaluate the potential of flue gas SAGP in thin ultra-heavy oil reservoirs to enhance recovery and optimize the timing and volume of flue gas injection. The study shows that the recovery degree of the thin ultra-heavy oil in the flue gas SAGP stage can reach 56%, and the cumulative oil-to-steam ratio is 0.21, so there is a large potential for recovery enhancement; the steam is injected together with the flue gas, the flue gas is located at the front edge of the steam chamber, and no low-temperature insulation zone is formed near the top of the oil layer and the bottom of the cap layer; the flue gas gathers at the front edge of the steam chamber, which hinders the lateral expansion of the steam chamber and slows down the steam overlap; when the steam chamber is extended to the bottom of the oil layer, the recovery rate is 54% to 56% by injecting 0.08 to 0.10 times the pore volume of flue gas. The research results can provide an important reference for recovery enhancement of thin ultra-heavy oil reservoirs.

Drilling & Production Engineering

Development and Performance Evaluation of Oily Sludge Coagulant for Heavy Oil Production

Cai Li, Liu Qingwang, Fan Zhenzhong, He Chunfang, Zhang Ming, Wang Jiao, Guo Hao, Li Qingyang

2024, 31(1):  137-143.  DOI: 10.3969/j.issn.1006-6535.2024.01.018

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Aiming at the problem of oily sludge polluting the environment produced in the process of heavy oil production, an oily sludge coagulant was developed with baked clay and hydraulic lime as the main raw materials, and an oily sludge adjusting and blocking agent that can be coagulated and solidified in the oil layer was formulated with oily sludge coagulant and oily sludge as the main components, so that it can achieve the purpose of harmlessness of oily sludge and utilization of resources.The factors affecting the blocking performance of the oily sludge adjusting and blocking agent were analyzed and optimized, and the adjusting and blocking performances were evaluated through XRD detection and compressive strength. The study shows that the adjusting and blocking agent has the advantages of long gel time, good construction safety, pumpability and appropriate structural strength; when the mass fraction of oily sludge coagulant is above 17%, the core blocking rate is above 98%, and the breakthrough pressure is above 20 MPa, which has high blocking strength; at the same time, the adjusting and blocking agent is also a new technology of resourceful use of solid waste, which is in line with the national policy of circular economy and green development. Oily sludge coagulant technology effectively solves the environmental pollution problem caused by oily sludge discharge, providing a new means for comprehensive oilfield management and reducing production costs.

Analysis of Heat Loss of Lined Insulation Tubing in Heavy Oil Wells and Optimization of Recovery Parameters

Zeng Wenguang, Wang Xi, Li Fang, Zhang Jiangjiang, Zeng Dezhi

2024, 31(1):  144-151.  DOI: 10.3969/j.issn.1006-6535.2024.01.019

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The lined insulation tubing recovery technology was researched to address the problems of large heat loss of heavy oil and waste of resources during the heavy oil recovery process in Taha Oilfield. Based on the theory of steady state heat transfer in the wellbore and non-steady state heat transfer in formation, a mathematical model of heat transfer in the wellbore of heavy oil wells was established, and the heat preservation performance of tubings with different lining materials was evaluated, which reveals the influence of water cut, daily liquid production and depth of tubing insulated with heat preservation tubular on the temperature of the wellbore. The study shows that the tubing insulated with polyketone anticorrosion layer and aerogel insulation layer has the best thermal insulation performance, the daily fluid production and the depth of insulation tubing have a more significant impact on the wellhead temperature, and the water cut has a lesser effect on the wellhead temperature; when the daily fluid production is more than 72 t/d and the depth of insulated tubing is more than3 500 m, which satisfies the temperature requirements of heavy oil recovery. The study results clarify the feasibility of lined insulation tubing, which could provide a technical basis for the selection of lined insulation tubing in oilfield and the formulation of process parameters for heavy oil recovery.

Stress Analysis and Influencing Factors of Perforation in Heavy-Oil Thermal Recovery Wells

Liang Jiangling, Yang Hong, Su Hongyi, Lin Tiejun, Zhao Chaoyang, Dan Han

2024, 31(1):  152-158.  DOI: 10.3969/j.issn.1006-6535.2024.01.020

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Aiming at the problems of frequent damage and fracture of perforated casing during the production process of thermal recovery wells, based on the theory of elasticity-plasticity and thermodynamics, a finite element thermodynamic coupling model of perforated casing during the process of steam injection-stewing-production was established by using finite element method to research the stress distribution characteristics of the perforated casing in each stage, and analyze the strength influence rule of the perforated casing under different parameters of perforated casing. The study shows that the obvious stress concentration occurs at the location of the injection hole boreholes during the production process. The casing stress could reach up to 498.16 MPa in the early stage, and the plastic failure occurs gradually under the joint action of the temperature difference and the internal and external pressure difference. The casing plastic failure is the most serious once the injection and production operation is completed. The influence of the perforation density on the value of Mises stress decreases with the increase of the perforation phasing degree, and the maximum perforation stress is inversely related to the perforation phasing degree. This study is of great significance to prolong the service life of perforated casing in heavy-oil thermal recovery wells and to ensure normal production operation.

Influencing Factors of Heavy Oil Cyclone Desanding

Yuan Liang, Zhang Shijian, Song Xuehua, Gan Ming, Zhuang Lequan, Jing Jiaqiang, Chen Jie

2024, 31(1):  159-168.  DOI: 10.3969/j.issn.1006-6535.2024.01.021

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Heavy oil with sand brings serious safety hazards to ground production facilities and export pipelines, and the high viscosity of heavy oil causes difficulties in oil-sand separation. Optimizing the cyclone structure and exploring the range of feeding conditions for efficient cyclone desander are of great significance in realizing the cyclone desanding of highly viscous heavy oil. To this end, numerical simulation was used to study the desanding rate and pressure drop under different heavy oil viscosities, water cuts, and cyclone geometries. The results show that the viscosity of the oil-water mixture has a significant effect on the sand separation efficiency, which is much larger than the effect of the cyclone structure on the desanding effect; the inlet diameter, the overflow diameter, and the length of the cone section of the cyclone structure parameters have the most significant effect on the cyclone field and the sand desanding rate; the control of the diversion ratio could reduce the oil phase flowing from the bottom outlet and the waste of resources, but the control of the diversion ratio is only effective and meaningful under the conditions of high viscosity and low water cut. The results of this study can provide a reference for the optimization of heavy oil cyclone desander structure and the design of the cyclone desanding process.

Main Control Factors and Countermeasures for Oil Well Waxing in B301 Test Area

Zhang Jihong, Li Wanshu, Tan Xinjian, Zhang Gang, Zhu Zhengjun

2024, 31(1):  169-174.  DOI: 10.3969/j.issn.1006-6535.2024.01.022

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The waxing is severe, the antiwaxing effect is poor, and the validity period is short in oil wells in B301 test area of H Basin. So, it is urgent to find out the main controlling factors affecting wax formation to meet the needs of antiwaxing in oil wells. To address the above problems, the wax, gum, asphaltene, and mechanical impurity contents in the produced fluid were measured by indoor experiments. Olga numerical simulation software was used to simulate the temperature, pressure, and flow rate. The study shows that wax, asphaltene, mechanical impurities, temperature, and flow rate are the main controlling factors affecting wellbore waxing in B301 test area, and the degree of influence is in the order of wax, temperature, asphaltene, mechanical impurities, and flow rate. The research results provide a theoretical and technical basis for further efficient development of B301 test area and a reference for anti-waxing methods in highly waxed oil reservoirs.