苏北盆地张家垛阜三段油藏岩心CO2-EOR数值模拟

纪文宇; 傅浩宇; 王德喜; 杨正茂; 陈雨菡; 施小清

doi:10.19509/j.cnki.dzkq.tb20240403

苏北盆地张家垛阜三段油藏岩心CO₂-EOR数值模拟

doi: 10.19509/j.cnki.dzkq.tb20240403

1.
南京大学地球科学与工程学院，南京 210023
2.
中国石化华东油气分公司，南京 210011

基金项目: 江苏省碳达峰碳中和科技创新专项资金项目（BE2022603）；国家自然科学基金项目（42272276）

详细信息

作者简介:
纪文宇：E-mail：wenyuji@smail.nju.edu.cn

通讯作者:
E-mail：shixq@nju.edu.cn

中图分类号: P618.13
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- 文章访问数: 107
- PDF下载量: 17
- 被引次数: 0
出版历程
- 收稿日期: 2024-07-17
- 录用日期: 2025-05-09
- 修回日期: 2025-05-09
- 网络出版日期: 2025-12-18

CO₂-EOR numerical simulation in cores from the Third Member of the Funing Formation in Zhangjiaduo oilfield, Subei Basin

1.
School of Earth Sciences and Engineering, Nanjing University, Nanjing 210023, China
2.
SINOPEC East China Oil & Gas Company, Nanjing 210011, China

More Information

Author Bio:
E-mail：wenyuji@smail.nju.edu.cn

Corresponding author: E-mail：shixq@nju.edu.cn

摘要

摘要:
二氧化碳强化石油开采（CO₂-EOR）是目前全球广泛应用的油田增产和碳封存技术之一。“双碳”目标导向下，CO₂-EOR数值模拟需考虑非独立水相对相间传质的影响，实现CO₂在油、气、水三相溶解分布的刻画。基于苏北盆地张家垛阜三段油藏实际储层条件，采用多相流数值模拟软件TOGA建立岩心驱替模型，实现三相全组分互溶模拟。通过模拟不同压力和注气速率下CO₂与油藏流体的相互作用，实现了研究区储层条件下CO₂在水、气、油三相中溶解性的差异性刻画，揭示了混相驱油机理。模拟结果表明，研究区发生混相驱的最小混相压力为30 MPa，此时油气界面张力接近0。混相驱替显著提高了石油采收率，如38，10 MPa围压下的采收率分别为85%，52%。CO₂在油相中的溶解性远大于其在水相中的溶解性，随着围压的增加CO₂在油、水两相中的摩尔百分数均提高，在22，38 MPa的围压下，水相中迁移的CO₂摩尔百分数分别为1.8%，2.1%，油相中迁移的CO₂摩尔百分数分别为70%，80%。研究区储层条件能够实现混相驱油，同时也有利于碳封存；提高CO₂注入速率可以提高生产效率，但对采收率和CO₂封存量的影响较小，还会增大气窜风险。研究成果为张家垛阜三段油藏的场地模拟和泄漏风险评估提供了技术参考。
- 二氧化碳强化石油开采（CO₂-EOR） /
- 混相驱替 /
- 数值模拟 /
- 溶解迁移 /
- 注气速率 /
- 围压 /
- 苏北盆地 /
- 驱油机理
Abstract: CO2-enhanced oil recovery (CO2-EOR) is currently one of the most widely applied technologies worldwide for oilfield production stimulation and carbon sequestration. Under the "dual carbon" goals, numerical simulation of CO2-EOR needs to consider the effect of interphase mass transfer by the non-independent water phase, so as to characterize the multiphase of dissolution distribution CO2. </sec><sec><title>Objective and Methods
Based on actual reservoir conditions of the Third Member of the Funing Formation in Zhangjiaduo Oilfield, Subei Basin, this study used the multiphase flow numerical simulation software TOGA to establish a core displacement model, and realized the simulation of three-phase full-component miscibility. By simulating the interactions between CO₂ and reservoir fluids under different confining pressures and gas injection rates, the differences in CO₂ solubility in the water, gas, and oil phases under the actual reservoir conditions of the study area were characterized, revealing the miscible flooding mechanism.
Results
The simulation results indicated that the minimum miscible pressure for miscible flooding in the study area was 30 MPa, at which the oil-gas interfacial tension approached zero. Miscible displacement significantly improved oil recovery, with recovery rates of 85% and 52% under confining pressures of 38 MPa and 10 MPa, respectively. CO₂ solubility in the oil phase was much greater than in the water phase, and with increasing confining pressure, the mole fractions of CO₂ in both oil and water phases increased. At confining pressures of 22 MPa and 38 MPa, the mole fractions of CO₂ migrating in the water phase were 1.8% and 2.1%, respectively, while those in the oil phase were 70% and 80%, respectively. The reservoir conditions in the study area can achieve miscible flooding, which is also conducive to carbon storage. Increasing the gas injection rate can improve production efficiency, but has a little effect on the ultinate oil recovery and CO₂ sequestration capacity, while potentially increasing the risk of gas channeling.
Conclusion
This study provides technical references for field simulation and leakage risk assessment of the Third Member of the Funing Formation in Zhangjiaduo Oilfield.
- CO₂-enhanced oil recovery (CO₂-EOR) /
- miscible flooding /
- numerical simulation /
- dissolution and migration /
- gas injection rate /
- confining pressure /
- Subei Basin /
- oil displacement mechanism

HTML全文

图 1 数值模拟网格剖分示意图

Figure 1. Schematic diagram of numerical simulation grid division

下载: 全尺寸图片幻灯片

图 2 原油恒质膨胀实验相对体积（a）、油相密度(b) 以及油相黏度(c)的拟合效果

Figure 2. Fitting results of relative volume (a), oil phase density (b), and oil phase viscosity (c) from constant composition expansion experiments

下载: 全尺寸图片幻灯片

图 3 不同围压下CO₂以0.2 mg/s 持续注入433 min时驱替前缘后段处界面张力

Figure 3. Interfacial tension at the rear section of displacement front with CO₂ injected at 0.2 mg/s for 433 minutes under different confining pressures

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图 4 不同围压下注入速率0.20 mg/s时CO₂驱替前缘演化

t. 累计注气时间；X. 岩心柱与岩心注入端的距离；下同

Figure 4. Evolution of CO₂ displacement front with an injection rate of 0.20 mg/s under different confining pressures

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图 5 不同围压下注入速率0.20 mg/s时CO₂迁移途径

a～c. 围压22 MPa；d～f. 围压38 MPa。$x_{{\mathrm{CO}}_2}. $ CO₂摩尔百分数；下同

Figure 5. CO₂ migration pathways with an injection rate of 0.20 mg/s under different confining pressures

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图 6 不同围压下石油采收率(c)以及累计产气量(a)、累计产油量(b)、CO₂封存量(d)与CO₂注入量关系

Figure 6. Oil recovery rate (c), and relationships of cumulative gas production (a), cumulative oil production (b), and CO₂ storage amount (d) with CO₂ injection amount under different confining pressures

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图 7 地层温压下注气速率对驱替过程的影响

Figure 7. Effect of gas injection rate on displacement process under formation temperature and pressure

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表 1 模型中原油组分及其摩尔百分数

Table 1. Crude oil components and their mole fractions in the model

组分	摩尔百分数/%	组分	摩尔百分数/%
CO₂	2.25	C5	1.41
C1	5.92	C6	3.22
C2	1.99	C7	4.39
C3	3.27	C8	4.73
C4	3.41	C9+	69.41

下载: 导出CSV

表 2 情景设置

Table 2. Scenario settings

编号	CO₂注入速率/ (mg·s⁻¹)	围压/ MPa	编号	围压/ MPa	CO₂注入速率/ (mg·s⁻¹)
Test1	0.20	10	Test7	38	0.10
Test2		22	Test8		0.15
Test3		26	Test9		0.20
Test4		30	Test10		0.25
Test5		34	Test11		0.30
Test6		38

下载: 导出CSV

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