生物多糖在高温高盐油藏聚合物驱可行性探索

探索了定优胶在高温、高盐油藏聚合物驱的可行性，采用黄原胶、魔芋胶作为对比，对其流变性、流度控制及提高采收率能力进行考察。稳态流变性及流度控制能力研究显示，三者增稠能力及在多孔介质中流度控制能力强弱顺序为：定优胶>黄原胶>魔芋胶。与另两种生物多糖相比较，定优胶有更好的耐温、耐盐特性及在高温中良好的长期稳定性。结合石英砂润湿性改性及原液、产出液流体力学半径变化情况，分析了3种多糖建立阻力的主要机理，对于魔芋胶、黄原胶、定优胶，机械捕集作用对多孔介质动态滞留量的贡献率分别为45.90%、60.78%、81.83%，定优胶较大的流体力学半径更易被多孔介质捕集，降低高渗多孔介质水相渗透率能力更强，且室内驱油实验中，定优胶提高采收率高达24.31%，明显优于黄原胶(17.02%)及魔芋胶(8.19%)，是一种很有前景的提高高温、高盐油藏稠油采收率的驱油剂。     

多孔介质内超临界CO2流体及泡沫驱油特性的比较实验研究

CO₂混相驱替可以提高原油采收率,因此近年来得到研究者们的广泛关注。使用高温高压驱替设备,利用超临界CO₂流体、超临界CO₂泡沫及N₂泡沫作为驱替介质,对油水饱和孔隙介质中的油相驱替特性开展了比较实验研究。通过对驱替过程沿程压力及对驱替增采油量的测量,对不同驱替手段在孔隙介质内的油相增采特性进行深入研究和探讨。研究发现在温度为50℃、压力为13 MPa时,超临界CO₂流体对多孔介质内的油相驱替效果有显著提升,当压力进一步升高到23 MPa时,油相增采效果不明显。说明在本实验条件下超临界CO₂流体与油相在50℃、13 MPa时可达到混相驱替状态;而采用超临界CO₂泡沫及N₂泡沫注入工艺未能进一步提高出油量。沿程压差测量结果则显示,与N₂泡沫相比,超临界CO₂泡沫在多孔介质试样内的驱替压差较小,起泡性能较差。实验结果对于筛选及评价超临界CO₂驱油工艺具有一定的指导意义。     

Capillary breakup extensional rheometry of associative and hydrolyzed polyacrylamide polymers for oil recovery applications

High molecular weight polymers used for heavy oil recovery exhibit viscoelasticity that can influence the oil recovery during chemical enhanced oil recovery. Different polymers having similar molecular weight and shear rheology may have different elongation flow behavior depending on their extensional properties. Displacing slugs are more likely to stretch than shear in tortuous porous media. Therefore, it is critical to seek an analytical tool that can characterize extensional parameters to improve polymer selection criteria. This article focuses on the extensional characterization of two polymers (hydrolyzed polyacrylamide and associative polymer) having identical shear behavior using capillary breakup extensional rheometer to explain their different porous media behavior. Maximum extensional viscosity at the critical Deborah number and Deborah number in porous media classified the associative polymer as the one having high elastic‐limit. Extensional characterization results were complemented by significantly higher pressure drop, marginally increased oil recovery of associative polymer in porous media. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 135, 46253.     

Investigation on Foam Self‐Generation Using In Situ Carbon Dioxide (CO2) for Enhancing Oil Recovery

In situ carbon dioxide (CO₂) foam flooding has proved to be economically feasible in the oil field, but its self‐generation behavior in the bulk scale/porous media is far from understood. In this study, the optimum in situ CO₂‐foaming agent was first screened, and then in situ foam was investigated in the bulk. In situ foam flooding was conducted to evaluate the displacement characteristics and enhanced oil recovery of this system. The results showed that the foaming agent comprising 0.5% sodium dodecyl sulfonate (SDS) + 0.5% lauramido propyl hydroxyl sultaine (LHSB) gave the best foam properties and that the in situ CO₂ foam with a slow releasing rate is effective both in bulk scale and in porous media, allowing a considerable enhancement of oil recovery in sand packs with different permeabilities.     

Microfluidic study of surfactant flooding of heavy oil in layered porous media containing fractures

Surfactant injection is a promising method for enhanced oil recovery (EOR) due to its effective micro-displacement mechanisms. However, understanding the interaction of a surfactant solution with heavy oil in porous media is neither straightforward nor well understood, particularly in heterogeneous systems. By enabling in-situ real-time monitoring of flow transport, microfluidic studies have provided novel insights into the underlying multiphase physics of flow at the pore scale. This paper examines the two-phase displacement efficiency of a new surfactant in layered–fractured porous microfluidic patterns, a topic seldom discussed in the literature. To evaluate the performance of the proposed surfactant, we considered several heterogeneous media with varying layer and fracture geometrical characteristics, quantifying displacement efficiency for each case. Based on the analysis of pore-scale snapshots, it was inferred that the primary mechanisms responsible for EOR during surfactant flooding into heavy oil include pore wall transportation, emulsifications, the deformation of residual oil, inter-pore or intra-pore bridging, and wettability alteration. Macroscopic displacement experiments revealed that the width of the swept area from surfactant injection significantly exceeded that of water injection, resulting in a substantially higher oil recovery. Furthermore, it was demonstrated that the direction of fluid flow in relation to fracture orientation plays a critical role in the dynamics of surfactant solution movement and, consequently, the ultimate oil production.     

Flow characteristics of three enhanced oil recovery polymers in porous media

This article presents an experimental study aiming to explore the relationship among rheological properties, flow characteristics in porous media, and enhanced oil recovery (EOR) performance of three typical EOR polymers. The results suggest that xanthan gum exhibits a very pronounced shear‐thinning behavior, which is probably also the reason explaining its moderate adsorption extent within porous media (thickness of adsorbed layer, e = 3.1 μm). The advanced viscoelastic properties coupled with the less adsorption extent compared to the hydrophobically modified copolymer (HMSPAM) allow xanthan gum to establish a “piston‐like” displacement pattern and lead up to 49.4% original oil in place (OOIP) of the cumulative oil recovery during polymer flooding. Regarding HMSPAM, the significant permeability reduction of the porous media induced by multilayer adsorption (e = 5.6 μm) results in much higher drive forces (ΔP) in the extended waterflooding stage, which further raises the cumulative oil recovery by 18.5% OOIP. In general, xanthan gum and HMSPAM totally produced 84% OOIP which is 15% higher than the extensively used EOR polymer, hydrolyzed polyacrylamide (HPAM), under the same experimental conditions. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015 , 132, 41598.     

Experimental study of dispersion in a consolidated sandstone

Dispersion experiments were conducted on a Berea sandstone core having a permeability of 0.28 (μm)², using chloride ion as the water soluble tracer to provide quantitative information useful to the prediction of the motion of reservoir fluids in enhanced oil recovery. Both single phase (water only) and two phase (water plus oil) experiments were completed under identical operating conditions in order to observe flow differences. The theory of Ebach and White (1958) was used to determine the dispersion coefficients. It has been found that over a wide range of fluid velocities, low concentrations of oil have no effect on the dispersion of chloride ions in the water phase but high concentrations of oil (S₀ ? 0.55) resulted in a dispersion coefficient 2.2 times higher than for chloride ions in water alone. This work indicates that the presence of an immiscible phase has a pronounced affect on the dispersion coefficient in porous media and must be accounted for in quantitative modeling of reservoir flows.     

SIMULTANEOUS HEAT AND FLUID FLOW IN POROUS MEDIA: CASE STUDY: STEAM INJECTION FOR TERTIARY OIL RECOVERY

Heat transfer and fluid flow in porous media occur simultaneously in thermal enhanced oil recovery and significantly increase the rate of energy transfer. The purpose of this investigation was to take advantage of such contemporary transfers and to study heavy oil recovery efficiency using hot-water flooding, cold-water flooding, and steam injection into porous media. A set of multistage laboratory tests was performed to find the temperature profile during steam injection as a means of tertiary oil recovery. Sand-packed models were utilized to investigate the oil recovery efficiency during cold and hot water injection as well as steam flooding for both secondary and tertiary oil production stages. An oil bank was formed in steam injection during the tertiary oil recovery from a vertical standing sand-packed model, resulting in very high oil recovery efficiency. Steam injection was found to be very effective, compared to cold- and hot-water flooding, for the recovery of heavy oil. Based on the principles of transport phenomena in porous media, a mathematical model was developed to predict the temperature profile during the steam injection process. Satisfactory agreement is achieved between the temperature profile predicted from the model and the experimental results.     

SIMULTANEOUS HEAT AND FLUID FLOW IN POROUS MEDIA: CASE STUDY: STEAM INJECTION FOR TERTIARY OIL RECOVERY

Heat transfer and fluid flow in porous media occur simultaneously in thermal enhanced oil recovery and significantly increase the rate of energy transfer. The purpose of this investigation was to take advantage of such contemporary transfers and to study heavy oil recovery efficiency using hot-water flooding, cold-water flooding, and steam injection into porous media. A set of multistage laboratory tests was performed to find the temperature profile during steam injection as a means of tertiary oil recovery. Sand-packed models were utilized to investigate the oil recovery efficiency during cold and hot water injection as well as steam flooding for both secondary and tertiary oil production stages. An oil bank was formed in steam injection during the tertiary oil recovery from a vertical standing sand-packed model, resulting in very high oil recovery efficiency. Steam injection was found to be very effective, compared to cold- and hot-water flooding, for the recovery of heavy oil. Based on the principles of transport phenomena in porous media, a mathematical model was developed to predict the temperature profile during the steam injection process. Satisfactory agreement is achieved between the temperature profile predicted from the model and the experimental results.     

The flow and displacement in porous media of fluids with yield stress

We study the mobilization and subsequent flow in a porous medium of a fluid with a yield stress, modeled as a Bingham plastic. We use single-capillary expressions for the mobilization and flow in a pore-throat, and a pore-network model that accounts for distributed yield-stress thresholds. First, we extend the statistical physics method of invasion percolation with memory, which models lattice problems with thresholds, to incorporate dynamic effects due to the viscous friction following the onset of mobilization. Macroscopic relations between the applied pressure gradient and the flow rate for single-phase flow are proposed as a function of the pore-network microstructure and the configuration of the flowing phase. Then, the algorithm is applied to model the displacement of a Bingham plastic by a Newtonian fluid in a porous medium. The results find application to a number of industrial processes including the recovery of oil from oil reservoirs and the flow of foam in porous media.     

Effect of salinity and alcohol partitioning on phase behavior and oil displacement efficiency in surfactant-polymer flooding

The equivalent alkane carbon number (EACN) of a crude oil, namely Ankleshwar crude, is successfully modeled by a mixture of pure alkanes. The EACN of the crude oil is found to be 9.3, and an appropriate mixture of nonane and decane exhibited phase behavior similar to that of the crude oil. A surfactant system for a water flooded reservoir at 80 C and having a salinity in the range of 2% to 3% NaCl is formulated by blending a phosphated ester with a petroleum sulfonate in the weight ratio of 2/5. The addition of phosphate ester not only increases the salt tolerance of the petroleum sulfonate system, it also broadens the IFT minimum. The oil displacement tests at 80 C in sandpacks and Berea cores showed that the surfactant formulation containing tertiary amyl alcohol (TAA) displaced 92% oil in sandpacks and 79% crude oil in Berea cores. The oil recovery efficiency was poor when formulations contained other alcohols. From the effluent surfactant concentration, it is shown that there is a correlation between the tertiary oil recovery, surfactant breakthrough and surfactant retention in porous media. It is proposed that, because alcohols such as isopropyl alcohol (IPA), isobutyl alcohol (IBA) and secondary butyl alcohol (SBA) partition significantly in the equilibrated excess brine phase, the alcohol-depleted surfactant slug forms stable emulsions resulting in faster breakthrough of surfactant in the effluent and lower oil displacement efficiency. In the case of TAA-containing formulation, there is a partitioning of TAA in the oil phase. Therefore, there is a mass transfer of alcohol from surfactant slug to the oil ganglia in porous media. This produces a transient ultralow IFT between residual oil and the surfactant solution which mobilizes oil, resulting in higher oil displacement efficiency. Presented in part at International Symposium on Oilfield and Geothermal Chemistry, June 1983, in Denver, CO.     

Evaluating the performance of designed terpolymers for polymer flooding

In this work, polymeric materials designed for enhanced oil recovery (EOR) were evaluated for their intended application. Properties including viscosity, flow through porous media (resistance factor and residual resistance factor), and heavy oil displacement (incremental oil recovery) were assessed for designed terpolymers of 2-acrylamido-2-methylpropane sulphonic acid (AMPS), acrylamide (AAm), and acrylic acid (AAc). The same properties were evaluated for two commercially available reference materials (e.g., partially hydrolyzed polyacrylamides or HPAM) with similar characteristics, which allowed for direct comparison between the newly designed terpolymers and materials that are currently on the market for the polymer flooding application. The incremental oil recovery directly associated with polymer flooding, which includes both the polymer flooding and post-polymer waterflooding stages (excluding the initial waterflooding injection (or secondary) oil recovery), demonstrates that the designed terpolymers provided a higher incremental recovery (42% and 58%) than the reference materials (33% and 46%). Therefore, the terpolymers provided a higher contribution to incremental (or enhanced) oil recovery than the typical HPAM. Additionally, both designed terpolymers showed better injectivity in unconsolidated porous media and are less likely to cause plugging than the commercially available reference materials. Therefore, using a targeted design approach ultimately led to polymeric materials with excellent performance for EOR polymer flooding applications.     

Flows of dilute hydrolyzed polyacrylamide solutions in porous media under various solvent conditions

Experimental results on pressure losses of flows of dilute polymer solutions through porous media are summarized. The polymer products employed in this study consisted of partially hydrolyzed polyacrylamides (HPAM) with different degrees of hydrolysis. The effect of the hydrolysis on the pressure drop is investigated in a porous media test section designed to minimize polymer degradation. The investigations were carried out for various solvent conditions, and it is shown that the maximum increase in pressure drop is mainly dependent on the molecular weight of the polymers. The onset of the polymer action is measured for various fluid and solvent properties. Particular attention is given to measurements near θ-conditions. The results stress the importance of the solvent properties on the actions of the polymers and on the resultant pressure drop for porous media flows. The addition of salt ions to solutions of partially hydrolyzed polyacrylamides yields onset behavior previously observed for nonionic polymers. The differences measured between various solvent properties can be explained by the actual hydrodynamic molecule dimensions for a given molecular weight and polymer concentration. To quantify the influences of the solvent properties on the polymers, measurements were carried out in aqueous solutions for various pH values and therefore at various degrees of dissociation. The importance of separating polymer effects caused by their linear dimension in the solution from those that are introduced by and increase in solvent viscosity is shown. Measurements were performed to quantify the effects of solvent viscosity on the polymer action and to separate these effects from those due to changes in molecule dimensions. The implications of the present results are stressed in connection with applications of polymer solutions in tertiary oil recovery, and the positive features of the molecule actions on flow in such applications are described.     

p-Sulfocalix[4]arene functionalized hydrophobically associative polyacrylamide: Flow characteristics and potential application to enhanced oil recovery

Hydrophobically associative polymers have been verified having enhanced oil recovery (EOR) potential. In this paper, a hydrophobically associative polyacrylamide functionalized with p-sulfocalix[4]arene (denoted as SHPAM) was firstly prepared through redox free-radical polymerization technique. Then, the water solubility, comprehensive properties, flowing behaviors, and displacement characteristics of SHAPM were investigated. Experimental results illustrated that SHPAM had benign water solubility, thickening ability, salt tolerance, temperature resistance, anti-shearing performance, thixotropy, and long-term stability. Also, SHPAM could reduce heterogeneity and extend sweep efficiency. Moreover, the adsorbed and retained SHPAM in porous media owned favorable viscoelasticity, which enhanced microscopic displacement efficiency. All the experiments results revealed that SHPAM has great applicable in enhancing oil recovery.     

Local effective permeability distributions for non-Newtonian fluids by the lattice Boltzmann equation

Effective permeability of porous media in subsurface environments (or packed beds in reactors, for instance) is subject to potentially large uncertainties due to heterogeneity of natural systems. We present a lattice Boltzmann method (LBM) to study the flow of single-phase non-Newtonian fluids by using a power law effective viscosity in different bidimensional porous media; arbitrarily and randomly generated. Macroscale-equivalent local effective permeability distributions and permeability bands at core scale are predicted.Our final goal is to propose a method for constructing core predictions from data obtained in thin samples of porous media, especially for non-Newtonian fluids (contaminated aquifers, petrochemicals and oil, for instance) whenever experiments are costly or just not available.     

Convective currents induced by chemical reactions in partially-filled porous media

Concentration gradients in a partially liquid-filled (unsaturated) porous body induce countercurrent gas and liquid flows which in their turn greatly influence the rate of the reactant transport. The origin of these convective flows is demonstrated starting with an elementary capillary circuit and passing to regular and random partially-filled porous media. The equations describing the mass transfer, reaction and balance of the pore filling in an unsaturated porous body are formulated and analysed. The qualitative estimates show that the gas-phase diffusion may play major role in smoothing out concentration gradients in a reacting liquid, and that under usual conditions the capillary forces in an unsaturated porous body with a wide distribution of pore sizes are strong enough to maintain the uniform filling throughout the partially-filled catalytic pellet. As an example of the quantitative solution of the basic set of equations, a simple reaction in a volatile liquid is considered; the results obtained show considerable acceleration of the diffusion-controlled reaction due to convective transport in an unsaturated porous medium.     

低渗透油藏合理井网系统的研究

低渗透油藏受特殊的成藏条件、沉积环境影响,具有孔隙结构复杂、孔喉半径细小,油藏渗透率低,一般小于50×10-3μm2;储层非均质严重,平面渗透率级差最高达几百个数量级;驱替压力大、存在一定的启动压力;天然裂缝发育且存在人工裂缝等特点;因此,在不同渗透率级差下,如何建立起有效的驱替半径建立合理、经济的井网井距,对提高低渗油藏水驱油效率及采收率,提高低渗透油藏的开发水平具有十分重要的意义.以低渗透油藏唐157井区为例进行研究,建立了合适的井网井距.     

Flow-induced degradation of hydrolyzed polyacrylamide in porous media

Summary In this work we present an experimental study of flow-induced degradation of hydrolyzed polyacrylamide in aqueous solutions flowing through porous media. The degradation is analyzed by passing the solution repeatedly through the medium at a constant flow velocity and the degraded solution is then characterized by porous media and opposed jets flows. When the polyacrylamide is dissolved in deionized water, it exhibits a gradual extension thickening in the flow through porous media and opposed jets. In this case, the polymer degrades as it passes through the porous medium even at relatively low flow rates. When the polyacrylamide is dissolved in an NaCl solution, it exhibits critical extension thickening in porous media flows, and it only degrades at Reynolds numbers that are higher than the onset of the extension thickening behavior. Chain degradation is therefore only encountered when extension thickening is produced. The results also show that the extent of degradation decreases as the pore size decreases.     

Simulation of deformable preformed particle gel propagation in porous media

Preformed particle gel (PPG) treatment is a proven cost‐effective method for improving oil recovery. Although PPG system has a suspension‐like property, it has different propagation rules from the rigid particle suspension in porous media because of its good deformation property. In this study, an advanced phenomenological model of PPG propagation in porous media is presented. The model includes both PPG plugging and restarting behaviors. Log‐normal and normal distribution functions have been introduced in this model to calculate the PPG plugging probability. Power‐law equation is used to calculate the PPG restarting rate. This method can represent the commensurate relation between PPG and throat size. Then, the equations are solved numerically, using an explicit finite‐difference formulation in conjunction with a fourth‐order Runge‐Kutta method. The results match favorably with several laboratory experiments. Finally, the propagation rules and sensitivity analysis of PPG size, permeability and injection rate to propagation rules, and permeability reduction are performed. © 2017 American Institute of Chemical Engineers AIChE J, 63: 4628–4641, 2017     

Experimental Investigation into the Screening of New Surfactant Flowback Aids and Statistical Interpretation of Their Imbibing Capacity for Selected Core Substrates

Spontaneous imbibition is a pervasive part of many natural and industrial processes. As an inherent feature of fluid transport in porous media, it is a driver for oil recovery. Understanding spontaneous imbibition and leveraging surface science is fundamental for fluid recovery; specifically, the role of the surfactant in the imbibition processes and the potential to alter capillarity and wettability of reservoir rock. Surfactant success relies on the understanding of the factors governing the interfacial phenomena among crude oil, and formation properties under reservoir conditions. Developing a methodology coupling chemical performance with analytical techniques, and statistical interpretation of core/surfactant/oil interactions, can help establish workflows to advance new chemistries and enhance oil recovery. This article discusses a study of flowback aids formulated as microemulsions corresponding to the thermodynamically stable Winsor Type IV solutions. Neat formulated microemulsions, when dosed at field treatment concentrations, provide either oil-in-water droplet microemulsions or nanoemulsions. The solvency potential was measured, and the Kauri-butanol (Kb) value was determined. Parameters such as critical micelle concentration (CMC) and interfacial tension (IFT) were determined to characterize microemulsion solutions. These systems were tested using either in the column flow test with formation material sieved to match mineral grain size, or sandstone cores of various permeabilities. The results indicate that surfactant-based flow-enhancing aids are desirable for improved oil recovery when compared to the control fluid. The statistical analysis of core-fluid interaction includes an ANOVA followed by assumption evaluations and model interpretation, which demonstrates that the core permeability term, followed by the surfactant term, has the highest contribution whereas oil has no statistical significance to the model.