基于核磁共振孔隙划分的致密油藏自发渗吸原油可动性研究

自发渗吸驱油是致密油藏提高采收率的有效手段,但不同的孔隙划分方法会导致原油可动性精细定量表征存在差异性.基于此,以鄂尔多斯盆地延长组致密油藏为研究对象,开展了四种典型致密岩心的自发渗吸驱油实验,利用基于核磁共振分形理论的流体分布孔隙精细划分方法,区分了致密砂岩岩心孔隙类型,明确了不同类型岩心孔隙结构对原油可动性和自发渗吸驱油速率的控制特征.研究结果表明不同类型岩心自发渗吸模拟油动用程度介于22.07%～33.26%,核磁共振T2谱双峰型岩心自发渗吸模拟油动用程度高于单峰型岩心;不同类型致密砂岩岩心中流体分布孔隙可初步划分出P1和P2两种类型, P1类型孔隙则可进一步划分出P1-1, P1-2和P1-3三种亚类型孔隙;致密砂岩岩心中P1和P2类孔隙中模拟油均有不同程度的动用, P1类孔隙作为致密岩心中主要孔隙,尤其是P1类孔隙中P1-2和P1-3类孔隙的数量决定了自发渗吸模拟油动用程度;P1-1, P1-2和P1-3类孔隙结构差异性对自发渗吸模拟油动用程度起决定性作用,较小尺寸孔径孔隙较大的孔隙结构差异性不仅提升了自发渗吸模拟油动用程度,而且提升了自发渗吸驱油速率;流体可动性指数较高的P...     

聚合物注入能力的实验研究

聚合物驱油作为一种重要的三次采油方法,在国内外油气田开发中得到了广泛应用.聚合物驱油效果的好坏取决于多种因素,其中很重要的一个因素是聚合物的注入能力,这一因素直接决定了聚合物驱油的成败.本文利用实验方法研究了聚合物的分子质量、岩样的渗透率以及注入速度等因素对聚合物注入能力的影响.结果表明,聚合物溶液具有粘弹性,注入速度增大,注入性变差.同时聚合物分子量越大,岩心渗透率越低,聚合物注入性越差.对于孤岛中一区,平均孔隙半径与聚合物分子折算半径之比大于10时,聚合物可顺利注入地层.研究结果可用于指导现场聚合物的选取,从而有效保证聚合物的注入能力,使聚合物驱油达到预期效果.     

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根据岩心实验提出了两参数的非线性渗流方程,并在此基础上结合Buckly-Leverett 方程建立了非线性非混相驱替方程. 通过对该方程求解分析可知,与线性达西渗流相比,非 线性渗流的驱油相率较差;同一含水饱和度下的含水率更高;而储层中各点的压力梯度更大, 导致所需注采压差更大. 说明有效的开发低渗透油藏需要比中高渗油藏更小的井距和更高的 注采压力体系.     

致密砂岩逆向渗吸作用距离实验研究

中国致密油储量丰富, 但多数致密储层波及效率低, 衰竭开发效果较差. 逆向渗吸是致密油藏注水开发过程中的一种重要的提高采收率途径, 目前许多学者主要针对致密油藏渗吸采收率及其影响因素开展研究, 而对于渗吸作用距离(表征致密油藏渗吸作用范围)研究较少. 本文采用CT在线扫描装置建立了致密岩心逆向渗吸作用距离量化方法, 明确了逆向渗吸的作用范围, 进一步研究了流体压力、含水饱和度、岩心渗透率和表面活性剂对逆向渗吸作用距离的影响, 阐明了逆向渗吸作用距离与渗吸采收率的关系, 为提高致密油藏采收率提供指导. 研究结果表明, 渗透率为0.3 mD的致密岩心逆向渗吸作用距离尺度仅为1.25 ~ 1.625 cm; 5 MPa条件下渗透率为0.302 mD的岩心逆向渗吸作用距离为1.375 cm. 在本实验条件下, 流体压力和初始含水饱和度对致密岩心逆向渗吸作用距离的影响较小, 而渗透率和表面活性剂对致密岩心逆向渗吸作用距离的影响显著, 渗透率为0.784 mD的岩心逆向渗吸作用距离相较于渗透率为0.302 mD的岩心提高2.63倍. 逆向渗吸作用距离是渗吸采收率表征的重要参数, 决定了逆向渗吸作用的波及范围.      

油藏复杂驱动体系物理模拟相似准则研究进展

综述了水驱油、化学驱油、蒸汽驱、混相驱及非混相驱等复杂油藏驱替体系物理模拟相似准则的研究现状.系统介绍了相似参数敏感性分析方法,定义了表征目标函数对相似参数依赖程度的敏感因子,结合数值方法便可定量地确定复杂体系主要相似参数,并实际应用于工程问题.讨论了水驱和聚合物驱物理模拟应优先满足的相似准则及其随参数范围的变化.      

水平井两相渗流

研究了水平井两相渗流问题.在流线不变的假定下,给出了水驱油饱和度的二维分布和见水时间公式。两相渗流的见水时间比活塞式驱替的时间快 f(s_t)倍,f(s_t)是含水百分数在前沿处的导数值。     

基于三维网络模型的水驱油微观渗流机理研究

利用逾渗网络模型在微观水平进行随机模拟来研究水驱油的微观渗流规律,通过模型计 算结果与油水稳态相对渗透率驱替实验结果对比验证了网络模拟的有效性. 在此基础上,讨 论了在不同润湿条件下、水驱不同阶段的剩余油微观分布规律. 将剩余油分布形态归纳为4 种状态：孤粒/孤滴状、斑块状、网络状和油水混合状态. 研究表明,网络状剩余油的块数 较少,但所占体积比例较大. 随着剩余油饱和度的降低,最大网络状油所占孔隙数减少,剩 余油饱和度在40{\%}$\sim$50{\%}附近开始以较快速度减少. 润湿性不仅影响驱油效率,也影响剩余油分布形态. 在驱替过程中,剩余油分布总的变化趋势是逐渐趋于分散.     

致密油藏动态裂缝扩展机理及应用

致密油藏采用注水吞吐补充地层能量取得了一定效果. 但多轮次注水吞吐后, 地层压力和产量降低快. 本文考虑了致密油藏复杂的裂缝形态, 根据艾尔文理论及弹性力学剖析I型裂缝尖端附近的应力场分布, 基于渗流力学、裂缝性致密油藏特征及动态裂缝渗流规律, 建立了多裂缝交叉裂缝扩展渗流模型, 结合注水诱导裂缝扩展机理及断裂力学能量守恒原理, 得到裂缝扩展长度. 依据致密油藏逆向渗吸原理, 提出将注水吞吐转为不稳定脉冲注水. 对比分析注水吞吐、脉冲注水2种能量补充发方式, 预测10年累计采油、压力及剩余油分布. 结果表明, 裂缝净内压随着注水量的增加而升高, 当应力场强度因子达到断裂韧度, 在裂缝尖端会发生扩展. 扩展及延伸的天然裂缝相互沟通, 呈现不规则复杂缝网, 在复杂缝网中主要发生逆向渗吸作用. 脉冲注水累计产油高、注水波及面积广、逆向渗吸作用强. 裂缝性致密油藏水平井注水吞吐转变为脉冲注水方式, 能够充分发挥动态缝网的逆向渗吸及线性驱替作用, 实现有效驱油的目的.      

储层含水条件下致密砂岩/页岩无机质纳米孔隙气相渗透率模型

页岩及致密砂岩储层富含纳米级孔隙,且储层条件下页岩孔隙(尤其无机质孔隙)及致密砂岩孔隙普遍含水,因此含水条件下纳米孔隙气体的流动能力的评价对这两类气藏的产能分析及生产预测具有重要意义.本文首先基于纳米孔隙内液态水及汽态水热力学平衡理论,量化了储层孔隙含水饱和度分布特征;进一步在纳米孔隙单相气体传质理论的基础上,考虑了孔隙含水饱和度对气体流动的影响;最终建立了含水饱和度与气相渗透率的关系曲线. 基于本文岩心孔隙分布特征,计算结果表明:储层含水饱和度对气体流动能力的影响不容忽视,在储层含水饱和度20%的情况下,气相流动能力与干燥情况相比将降低约10%;在含水饱和度40% 的情况下,气相流动能力将降低约20%.      

纳米阵列中气体驱替液体的流动特征

纳米尺度下气体驱动液体流动特征在纳流控芯片及页岩气开发中具有广泛的应用前景. 利用管径规格为292.8 nm,206.2 nm,89.2 nm,67.0 nm,26.1 nm的氧化铝膜为纳米阵列,进行气驱水实验和单相气体流动实验,分析纳米尺度下气驱水流动特征. 实验表明,纳米阵列中气驱水时气体流量随驱动压力变化经历三个阶段:第一阶段流量缓慢增大,且比单相气体流量降低约一个数量级;第二阶段纳米阵列中的水被大量驱替出,流量迅速增大;第三阶段纳米阵列中的水全部被驱替出,流动特征与单相气体流动保持一致. 分析表明,气驱水第一阶段存在气液界面毛细管力的“钉扎”作用及固液界面相互作用力的影响,是产生非线性流动的主要原因;而一旦“钉扎”作用破坏,气体进入管道推动界面运动,气柱与液柱之间的毛细曲面曲率变化,毛细管力减小,气体流量急剧增大,其中毛细管力随驱替压力增大急剧变化,是造成第二阶段气体流量突变的主要原因.      

Experimental Investigation of Synergy of Components in Surfactant/Polymer Flooding Using Three-Dimensional Core Model

Surfactant/polymer (SP) floods have significant potentials to recover remaining oil after water flooding. Their efficiency can be maximized by fully utilizing synergistic effect of polymer and surfactant. Various components adsorbed on the rock matrix due to chromatographic separation can significantly weaken the synergistic effect. Due to scale and dimensional problems, it is hard to investigate chromatographic separation among various components using one-dimensional natural cores. This study compared the adsorption difference between artificial and natural cores and developed a three-dimensional artificial core model of a 1/4 5-spot configuration to simulate oil recovery in multilayered reservoirs with high, middle and low permeability for each layer. Sampling wells were established to monitor pressures, and effluent fluids were acquired to measure interfacial tension (IFT) and viscosity. Then, distances of synergy of polymer and surfactant in three layers were evaluated. Meanwhile, electrodes were set in the model to measure oil saturation variation with resistance changes at different locations. Through comparison with IFT values, the contribution of improved swept volume and oil displacement efficiency to oil recovery during SP flooding could be known. Results showed that injected 0.65 PV of SP could improve oil recovery by 21.56% when water cut reached 95% after water flooding. The retention ratio of polymer viscosity was kept 55.3% at the outlet, but IFT was only 2 mN/m within the 3/10 injector–producer spacing during SP injection. Although subsequent water flooding could result in surfactant desorption and the IFT became 10^?2?mN/m within the 3/10 injector–producer spacing, the IFT turned to 2?mN/m at the half of the model. The enhanced displacement efficiency by reducing IFT only worked within three-tenth location of the model in the high permeability layer, while the enlarged swept volume contributed much in the other areas.

     

A Dynamic Pore Network Model for Oil Displacement by Wettability-Altering Surfactant Solution

A dynamic pore network model, capable of predicting the displacement of oil from a porous medium by a wettability-altering and interfacial tension reducing surfactant solution, is presented. The key ingredients of the model are (1) a dynamic network model for the displacement of oil by aqueous phase taking account of capillary and viscous effects, (2) a simulation of the transport of surfactant through the network by advection and diffusion taking account of adsorption on the solid surface, and (3) the coupling of these two by linking the contact angle and interfacial tension appearing in the dynamic network simulation to the local concentration of surfactant computed in the transport simulation. The coupling is two-way: The flow field used to advect the surfactant concentration is that associated with the displacement of oil by the injected aqueous phase, and the surfactant concentration influences the flow field through its effect on the capillarity parameters. We present results obtained using the model to validate that it reproduces the displacement patterns observed by other authors in two-dimensional networks as capillary number and mobility ratio are varied, and to illustrate the effects of surfactant on displacement patterns. A mechanism is demonstrated whereby in an initially mixed-wet medium, surfactant-induced wettability alteration can lead to stabilization of displacement fronts.     

Displacement Theory of Low-Tension Gas Flooding

Low-tension gas (LTG) flooding is a promising chemical enhanced oil recovery technique in tight sandstone and carbonate reservoirs where polymer may not be used because of plugging and degradation issues. This process has been the subject of many experimental studies. However, theoretical investigation of the LTG process is scarce in the literature. Hence, in this study, we lay out a displacement theory for LTG flooding, with a constant mobility reduction factor, which lays the groundwork for further theoretical studies. The proposed model is based on the three-phase flow of water, oil, and gas in the presence of a water-soluble surfactant component. Under the developed model, we study the effect of MRF and oil viscosity on the flow dynamics and oil recovery. Moreover, we explain experimental observations on early gas breakthrough that occurs during LTG core floods even in the presence of a stable foam drive.

     

A sequential numerical chemical compositional simulator

Chemical flooding in the petroleum industry has a larger scale of oil recovery efficiency than water flooding. On the other hand, it is far more technical, costly, and risky. Numerical reservoir simulation can be employed to conduct mechanism study, feasibility evaluation, pilot plan optimization, and performance prediction for chemical flooding to improve recovery efficiency and reduce operational costs. In this article, we study numerical simulation of chemical flooding such as alkaline, surfactant, polymer, and foam (ASP+foam) flooding. The main displacement mechanisms in this type of flooding are interfacial tension lowering, capillary desaturation, chemical synergetic effects, and mobility control. The model of chemical flooding involves such physicochemical phenomena as dispersion, diffusion, adsorption, chemical reactions, and in situ generation of surfactant from acidic crude oil. The numerical simulator is based on a sequential solution approach that solves both pressure and compositions implicitly, and is applied to three experiments, a chemical flow without mass transfer between phases, a laboratory sandstone core, and an ASP+foam displacement problem with mass transfer, and to a real oilfield. A comparison with UTCHEM is also performed. These applications and comparison indicate that this numerical simulator is practical, efficient, and accurate for simulating complex chemical flooding processes.      

撞击载荷下泡沫铝夹芯梁的塑性动力响应

应用泡沫金属子弹撞击加载的方式研究了固支泡沫铝夹芯梁和等质量实体梁的塑性动力响应。 采用激光测速装置和位移传感器测量了泡沫子弹的撞击速度和后面板中心点的位移-时间曲线,研究了加载 冲量、面板厚度和芯层厚度对夹芯梁抗冲击性能的影响。给出了泡沫铝夹芯梁的变形与失效模式,实验结果 表明结构响应对夹芯结构配置比较敏感,后面板中心点的残余变形与加载冲量、面板厚度呈线性关系。与等 质量实体梁的比较表明,泡沫铝夹芯梁具有更好的抗冲击能力。实验结果对多孔金属夹芯结构的优化设计具 有一定的参考价值。     

High Resolution Imaging of Unstable,Forced Imbibition in Berea Sandstone

An experimental investigation is presented of immiscible, high-mobility ratio forced imbibition in a representative linear homogeneous sandstone. Water floods with mobility ratios (from 1 to 155) at various water injection rates were conducted. Fine-scale (order mm³) in situ water saturation history was collected via X-ray computed tomography (CT). Three-dimensional images were constructed of stable displacement and the initiation and growth of unstable water fingers. Interestingly, viscous fingers do not lead the displacement front by significant distances, counter to experience in miscible systems. In this homogeneous porous medium, both water (displacing phase) injection rate and oil (displaced phase) viscosity have an obvious effect on the stability of the water front. As the oil viscosity and displacement rate increase, the water front becomes less stable. In addition, the so-called shock mobility ratio, as computed from steady-state relative permeability, is found to be predictive regarding displacement front stability. When the shock mobility ratio is greater than 1, the displacement is always unstable. Steady-state relative permeability, however, is found to be a function of viscosity ratio for unstable displacements.     

Foam Mobility in Heterogeneous Porous Media

It is shown experimentally that in situ generation of foam is an effective method for achieving gas mobility control and diverting injected fluid to low permeability strata within heterogeneous porous media. The experimental system is composed of a 0.395 porosity, 5.35 µm² synthetic sandstone and a 0.244 porosity, 0.686 µm² natural sandstone. The cores are arranged in parallel and communicate through common injection and production conditions. Nitrogen is the gas phase and alpha-olefin sulfonate (AOS 1416) in brine is the foamer. Three types of experiments were conducted. First, gas alone was injected into the system after presaturation with the foamer solution. Second, gas and foamer solution were coinjected at an overall gas fraction of 90% into cores presaturated with surfactant. Each core accepted a portion of the injected gas and liquid according to the mobility within the core. Lastly, gas and foamer solution were coinjected into the individual, isolated porous media in order to establish baseline behavior. The results are striking. It is possible to achieve total diversion of gas injection to the low permeability medium in some cases. The results also confirm previous predictions that foamed gas can be more mobile in lower permeability porous media.     

Phase Behaviour,Fluid Properties and Recovery Efficiency of Immiscible and Miscible Condensate Displacements by SCCO<Subscript>2</Subscript> Injection: Experimental Investigation

This paper presents a quantitative investigation of the interfacial tension dependent relative permeability (IFT-DRP) and displacement efficiency of supercritical CO₂ injection into gas-condensate reservoirs. A high-pressure high-temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores at a constant reservoir temperature of 95°C and displacement velocity of 10 cm/h. This investigation covers immiscible displacements (1100 and 2100 psi), near-miscible displacement (3000 psi) and miscible displacements (4500 and 5900 psi). The coreflooding results demonstrated that displacement pressure is a key factor governing the attainment of optimum sweep efficiency. The ultimate condensate recovery increased by almost threefold when CO₂ was injected at near-miscible conditions (i.e., 23.40% ultimate recovery at 1100 psi compared to 69.70% at 3000 psi). Miscible flooding was found to give the optimum condensate recovery (9% extra ultimate recovery compared to near-miscible injection). Besides improving the ultimate recovery, miscible floods provided better mobility ratios and delayed gas breakthrough (0.62 PV BT at 5900 psi compared to 0.21 PV BT at 1100 psi). In addition to the elimination of IFT forces in miscible displacements, favourable ratios of fluid properties and phase behaviour relationships between the SCCO₂ and condensate were believed to be the driving force for the improved recovery as they provided a stabilising effect on the displacement front and stimulated swelling of the condensate volume. This paper incorporates the theoretical aspects of phase behaviour and fluid properties that largely affect the microscopic displacement efficiency and serves as a practical guideline for operators to aid their project designs and enhance their recovery capabilities.     

A Pore Scale Study of Non-Newtonian Effect on Foam Propagation in Porous Media

CO₂ injection is one of the most promising techniques to enhance oil recovery. However, an unfavorable mobility ratio, reservoir heterogeneity and gravity segregation can reduce the macroscopic sweep efficiency. In situ foaming of injected CO₂ is the method that has the most potential for improving sweep efficiency based on controlling CO₂ mobility. This study investigates the foaming behavior of N,N,N′-trimethyl-N′-tallow-1,3-diaminopropane (DTTM) surfactant with CO₂ in a transparent porous microflow model with natural rock pore structures. It focuses on the effect of the salinity induced non-Newtonian behavior of DTTM solution on foam propagation. The performance of foams stabilized by 0.5 wt% DTTM solution over the viscosity range from 0.71 (at 5 wt% NaCl) to 41 cp (at 20 wt% NaCl) was compared with conventional polymer-enhanced foams whose liquid phase contained a commonly used foaming surfactant, C15–18 Internal Olefin Sulfonate (C15–18 IOS) and a hydrolyzed polyacrylamide. Such comparisons have also provided insight into the respective impacts of liquid phase viscosification by worm-like surfactant micelles and polymer on foam texture associated with its rheological characteristics. It was found that at low aqueous phase viscosity (injection liquid viscosity of 0.71 cp) the maximum achievable viscosity of DDTM foam was around 1000 cp, which was 80 times IOS stabilized foam. The interfacial tension of DTTM was higher than that of IOS, resulting coarser foam texture and higher individual lamella resistance. An increase in DTTM solution viscosity by a factor of 33 decreased foam generation and viscosity for gas injection. This was not observed for the simultaneous injection of gas and DTTM solution. Overall, the effect of liquid phase viscosity on transient foam behavior during gas injection is similar for both DTTM and IOS regardless of the difference in the nature of viscosifying agents (WLM vs 3330 s polymer). An increase in gas injection pressure without liquid injection delayed foam propagation and reduced the magnitude of foam viscosity. The results from this study indicated that DTTM surfactant is an important alternative to commercially available polymers that have been used to enhance foam performance in porous media. This particular surfactant type also overcomes several disadvantages of polymers such as limited temperature and salinity tolerance, shear degradation, and filtering in low permeability formations.