Modeling enhanced geothermal systems with carbon storage in fractured reservoirs

针对大量即将废弃的低渗透、天然裂缝发育油藏，本文提出“增强地热系统（EEGS）+二氧化碳封存（CCS）”协同开发思路：利用空气氧化残余原油放热，在实现地热发电的同时完成 CO₂ 长期封存。研究首先基于 Python 自编离散裂缝网络（DFN）生成器，建立含 2062 条天然裂缝的三维地质模型；随后耦合商业油藏模拟器 CMG，系统评估裂缝倾角、密度、储层温度及空气注入速率对采出程度、地热功率和 CO₂ 突破时间的影响，并进行技术-经济可行性分析。研究定量揭示了裂缝网络与操作参数对“地热-碳封存”共生系统的控制作用，为废弃油藏转型为低碳能源基地提供了技术-经济模板。

CMG 软件应用情况

  1. 模拟器选择：CMG-STARS 模块，用于同时描述空气-油-气-水多组分、氧化放热反应及 CO₂ 溶解/封存过程。
  2. 模型搭建：
    – 地质网格：在 Python-DFN 中生成 2062 条天然裂缝后，导入 CMG 建立局部加密的三维双孔-双渗模型；
    – 组分定义：空气（O₂/N₂）、原油、CO₂、水 4 伪组分，氧化反应采用 Arrhenius 动力学，放热量 3.2×10⁴ kJ/kg-oil；
    – 运行策略：注空气 20 年+后续封存 30 年，最大注入压力不超过地层破裂压力 90 %。
  3. 方案对比：利用 CMG 批跑 40 余组方案，考察裂缝倾角（30–90°）、裂缝密度（500–3000 条）、注入速率（0.8–1.8×10⁴ m³/d）及储层温度（80–160 °C）对采收率、地热功率与 CO₂ 突破的敏感性。
  4. 历史拟合：以某低渗裂缝性废弃油田 15 年生产数据为基准，产油、含水、井口温度拟合误差分别 < 5 %、3 %、4 %，验证了氧化放热与裂缝导流耦合模型的可靠性。
  5. 经济模块输出：将 CMG 计算的油产量、注气功耗、地热发电量导入自建经济评价表，得到动态现金流与回收期。

主要结论

  1. 裂缝倾角 70° 时注空气氧化带最稳定，50 年采出程度比 45° 倾角提高 18 %，CO₂ 突破延迟 15 年。
  2. 当天然裂缝密度＞2000 条时，低渗基质的“热交换面积”增大，地热净功率稳定在 2.8 MW 以上，且封存安全性最好。
  3. 最优操作参数：空气注入速率 1.3×10⁴ m³/d、储层初始温度 140 °C、注热井与裂缝走向垂直；该条件下年收益 260 万美元，静态回收期 7.69 年。
  4. CMG-STAR 多组分数值平台可准确耦合氧化放热、裂缝导流与 CO₂ 封存过程，为类似废弃油藏转型“地热-碳库”提供量化工具。
  5. 天然裂缝在低渗储层中并非“不利因素”，只要几何方位与注采井网匹配，可同时提升采油、产热和碳封存三重效益。

作者单位
美国科罗拉多矿业学院石油工程系

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Highlights

  • A new development approach combining Enhanced Geothermal Systems with Carbon Capture and Storage in abandoned oil reservoirs.
  • A 70° fracture dip angle optimizes fluid flow, heat transfer, and maximizes oil production.
  • 2062 natural fractures prolong oil and thermal energy production, delaying CO2 release by 15+ years.
  • Enhanced Geothermal Systems with Carbon Capture and Storage work best when fractures are perpendicular to injection/recovery directions.
  • Low-permeability reservoirs with high fracture density are ideal for abandoned reservoir development.

Abstract

The development potential of abandoned oil reservoirs is often underestimated, although they can provide both a solution for carbon dioxide storage and a source of clean geothermal energy. This study examines the feasibility of converting low-permeability, naturally fractured reservoirs into enhanced geothermal systems while simultaneously storing carbon dioxide. The importance of this work lies in addressing two global challenges at once: mitigating greenhouse gas emissions and producing sustainable energy from reservoirs that are no longer commercially viable. A numerical simulation framework was established by combining a fracture network model with a commercial reservoir simulator to investigate the influence of fracture geometry, reservoir temperature, and air injection rate on oil recovery, reservoir heating, and carbon dioxide storage performance. Furthermore, a techno-economic evaluation was performed to assess the overall financial feasibility of this approach. The results show that fractures oriented at approximately seventy degrees maximize oil recovery, and fracture densities above 2000 can delay carbon dioxide breakthrough by up to fifteen years. At an air injection rate of 13,000 m3/day, the cumulative oil recovery exceeds 140,000 m3 after 50 years, while geothermal energy output reaches 2.814 MW, generating about $2.60 million/year. The overall payback period for the system is estimated to be 7.69 years. These findings indicate that natural fractures, when favorably configured, can enhance rather than hinder performance. The study advances previous efforts by quantitatively demonstrating how fracture networks and operational parameters jointly determine the effectiveness of integrating geothermal energy recovery with carbon dioxide storage in abandoned oil reservoirs.

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