Understanding reservoir engineering aspects of shale oil development on the Alaska North Slope
非常规液体储层的基质渗透率远低于常规油储层，这使得多阶段水力压裂和水平钻井技术在提高这些紧密油储层的井筒-基质连通性方面发挥了关键作用。尽管如此，在一次采油过程中，采收率仍然只有5%到10%。鉴于如此庞大的资源基础，即使在生产力方面的小幅提升也可能带来数十亿桶的额外石油。因此，开发适用于非常规油储层的有效提高采收率技术显得尤为重要。本研究探讨了二氧化碳作为提高紧密油储层采收率剂的技术可行性。在最低混溶压力（MMP）以上，CO2和油是混溶的，这导致毛细管力减少，从而提高了局部驱油效率。CO2的混溶压力显著低于其他气体所需的压力，这使得在广泛的储层压力下实现CO2混溶注入成为可能。通过对巴肯岩心样本进行核磁共振成像实验，我们发现在较低能量水平下，X射线的光电吸收机制占主导地位，能更好地捕捉CO2的渗透影响。实验结果表明，CO2混溶驱油至少能回收70%的原始油，尽管实验中使用了较小的压力梯度。此外，实验还发现，在早期生产期间，CT数值的变化大于后期，可能的解释包括：1）早期生产中可能未完全实现混溶；2）CO2优先带走轻质烃组分，留下密度更大的重质组分。为了解读核磁共振成像实验中的采油机制，构建了一个数值组分模型来复现实验室结果。模型显示，轻质烃组分的蒸发是主要的采油机制。其他控制因素包括再压裂、原油膨胀、粘度和界面张力的降低。通过与实验室实验的历史拟合，引入了额外的复杂性，例如岩石非均质性和存在促进垂直于岩心长度方向流动的裂缝。为了精确匹配驱油过程，需要解决上述问题。
CMG软件应用情况
在这项研究中，使用了CMG的GEM软件包进行组分模拟，以复现实验室观察到的驱油趋势，并更好地理解非常规紧密油储层中的流体流动机制。CMG软件用于定义巴肯原油的相行为和流体性质，以及进行流体流动模拟。通过CMG的WinProp工具，对巴肯原油进行了组分分析，并优化了PVT实验数据和实验确定的混溶压力。这些数据作为后续流动模拟的重要输入。
Abstract
Horizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. The Shublik shale, a major source rock for hydrocarbon accumulations on the North Slope of Alaska, has huge potential for oil and gas production, with an estimated 463 million barrels of technically recoverable oil.
This thesis presents a workflow for proper modeling of flow simulation in shale wells by incorporating results from hydraulic fracturing software into hydraulic fracture flow modeling. The proposed approach allows us to simulate fracture propagation and leak-off of fracturing fluid during hydraulic fracturing. This process honors the real proppant distribution, horizontal and vertical variable fracture conductivity, and presence of fracturing fluid in the fractures and surrounding matrix. Data from the Eagle Ford Shale in Texas was used for this modeling which is believed to be analogous to Alaska's Shublik shale.
The performance of a single hydraulic fracture using a black oil model was simulated. Simulation results showed that for the hydraulically fractured zone, the oil recovery factor is 5.8% over thirty years of production, to an assumed economic rate of 200 STB/day. It was found that ignoring flowback overestimated oil recovery by about 17%. Assuming a constant permeability in the hydraulic fracture plane resulted in overestimation of oil recovery by almost 25%. The conductivity of the unpropped zone affected the recovery factor predictions by as much as 10%. For the case investigated, about 25% of the fracturing fluid was recovered during the first 2 months of production; in total, 44% of it was recovered over thirty years. Permeability anisotropy was found to have a significant effect on the results.
These results suggest that assuming a constant conductivity for the fractures and ignoring the presence of water in the fractures and the surrounding matrix leads to overestimation of initial production rates and final recovery factors. In addition, the modified workflow developed here more accurately and seamlessly integrates the modeled induced fracture characteristics in the reservoir simulation of shale resource plays.
作者单位
阿拉斯加费尔班克斯大学 能源资源工程系 硕士学位论文 作者：Behnam Zanganeh
Abstract:
