The steam-assisted gravity drainage (SAGD) process is among the most applicable thermal enhanced oil recovery (TEOR) methods in North American heavy oil reservoirs. In addition to improving oil mobility through viscosity reduction, the high-temperature condition that a TEOR method causes may significantly alter the fluid flow performance and behavior, as manifested by the relative permeability to fluids in the reservoir. Therefore, in a SAGD and cyclic steam stimulation (CSS), the relative permeabilities can change within the temperature-gradient region developed around the SAGD chamber or between two cycles of CSS processes. However, there is no unique two-phase relative permeability model, especially for bitumen systems to cover a wide range of temperatures. Therefore, the primary objective of this study is to history-match the results of the recent study done by Esmaeili et al. using a new methodology and to conduct limited steady-state relative permeability measurements at different temperatures to confirm the validity of displacement-based relative permeability curves and then to propose a reliable general relative permeability model as a function of temperature. Twelve history-matched bitumen/water relative permeability sets are obtained in a wide range of temperatures from 70 to 220 °C under a confining pressure higher than 1000 psi and the test pressure in the range of 350–400 psi. An in-house developed reservoir simulator was used to obtain relative permeability curves from isothermal displacement data using the history-matching approach. The results demonstrated that both production and pressure-drop data can be matched using the optimized values of parameters of the generalized Corey relative permeability model. Furthermore, a more reliable value for actual residual oil saturation was determined by applying our new methodology in history matching. A comparative analysis with the steady-state relative permeability data allowed us to determine the extent to which the unsteady-state relative permeability is affected by viscous fingering. A considerable shift in both oil and water relative permeability at higher temperatures is noticed. Furthermore, it is also noted that the endpoint relative permeability to oil and water is also altered significantly. The implicit relative permeability data obtained from this study are consistent with the results of the JBN method that were reported in our previous study. By making the parameters of the Corey relative permeability model dependent on temperature, a new model of temperature-dependent bitumen/water relative permeability in sand was developed. It is anticipated that this model can facilitate inclusion of temperature-dependent relative permeability in reservoir simulation studies.

中文翻译：

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温度对油砂中沥青/水相对渗透率的影响

蒸汽辅助重力排水（SAGD）工艺是北美稠油油藏中最适用的热增强油采收（TEOR）方法之一。除了通过降低粘度来提高油的流动性之外，TEOR方法引起的高温条件还可能会显着改变流体的流动性能和行为，这表现为对储层中流体的相对渗透率所证明。因此，在SAGD和循环蒸汽刺激（CSS）中，相对渗透率可以在SAGD腔周围形成的温度梯度区域内或CSS过程的两个循环之间发生变化。但是，并没有独特的两相相对渗透率模型，特别是对于沥青系统而言，其涵盖的温度范围很广。因此，这项研究的主要目的是使历史记录与Esmaeili等人的最新研究结果相匹配。使用一种新方法并在不同温度下进行有限的稳态相对渗透率测量，以确认基于位移的相对渗透率曲线的有效性，然后提出一个可靠的通用相对渗透率模型，该模型是温度的函数。在70至220°C的宽温度范围内，高于1000 psi的围压和350-400 psi的测试压力下，可获得十二个历史匹配的沥青/水相对渗透率组。内部开发的油藏模拟器用于使用历史匹配方法从等温位移数据获得相对渗透率曲线。结果表明，可以使用广义Corey相对渗透率模型的参数优化值来匹配产量和压降数据。此外，通过在历史记录匹配中应用我们的新方法，可以确定实际残余油饱和度的更可靠值。与稳态相对磁导率数据的比较分析使我们能够确定粘性指法对非稳态相对磁导率的影响程度。注意到在较高温度下油和水的相对渗透率都有相当大的变化。此外，还应注意，端点对油和水的相对渗透率也发生了显着变化。从这项研究中获得的隐式相对渗透率数据与我们先前研究中报道的JBN方法的结果一致。通过使Corey相对渗透率模型的参数取决于温度，开发了一种新的温度相关的沥青/水相对渗透率模型。可以预计，该模型可以促进在储层模拟研究中纳入温度相关的相对渗透率。