Microscopic Mechanisms of Oil Recovery By Near-Miscible Gas Injection

As gas flooding becomes a more viable means of enhanced oil recovery, it is important to identify and understand the pore-scale flow mechanisms, both for the development of improved gas flooding applications and for the predicting phase mobilisation under secondary and tertiary gas flooding. The purpose of this study was to visually investigate the pore-level mechanisms of oil recovery by near-miscible secondary and tertiary gas floods. High-pressure glass micromodels and model fluids representing a near-miscible fluid system were used for the flow experiments. A new pore-scale recovery mechanism was identified which significantly contributed to oil recovery through enhanced flow and cross-flow between the bypassed pores and the injected gas. This mechanism is strongly related to a very low gas/oil interfacial tension (IFT), perfect wetting conditions and simultaneous flow of gas and oil in the same pore, all of which occur as the gas/oil critical point is approached. The results of this study helps us to better understand the pore-scale mechanisms of oil recovery in very low-IFT (near-miscible) systems. In particular we show that in near-miscible gas floods, behind the main gas front, the recovery of the oil continues by cross-flow from the bypassed pores into the main flow stream and as a result almost all of the oil, which has been contacted by the gas, could be recovered. Our observations in high-pressure micromodel experiments have demonstrated that this mechanism can only occur in near-miscible processes (as opposed to immiscible and completely miscible processes), which makes oil displacement by near-miscible gas floods a very effective process.     

Laboratory and Simulation Investigation of Enhanced Coalbed Methane Recovery by Gas Injection

Methane/carbon dioxide/nitrogen flow and adsorption behavior within coal is investigated simultaneously from a laboratory and simulation perspective. The samples are from a coalbed in the Powder River Basin, WY. They are characterized by methane, carbon dioxide, and nitrogen sorption isotherms, as well as porosity and permeability measurements. This coal adsorbs almost three times as much carbon dioxide as methane and exhibits significant hysteresis among pure-component adsorption and desorption isotherms that are characterized as Langmuir-like. Displacement experiments were conducted with pure nitrogen, pure carbon dioxide, and various mixtures. Recovery factors are greater than 94% of the OGIP. Most interestingly, the coal exhibited ability to separate nitrogen from carbon dioxide due to the preferential strong adsorption of carbon dioxide. Injection of a mixture rich in carbon dioxide gives slower initial recovery, increases breakthrough time, and decreases the volume of gas needed to sweep out the coalbed. Injection gas rich in nitrogen leads to relatively fast recovery of methane, earlier breakthrough, and a significant fraction of nitrogen in the produced gas at short times. A one-dimensional, two-phase (gas and solid) model was employed to rationalize and explain the experimental data and trends. Reproduction of binary behavior is characterized as excellent, whereas the dynamics of ternary systems are predicted with less accuracy. For these coals, the most sensitive simulation input were the multicomponent adsorption–desorption isotherms, including scanning loops. Additionally, the coal exhibited a two-porosity matrix that was incorporated numerically.     

Modeling of Liquid Fuel Injection, Evaporation and Mixing in a Gas Turbine Burner Using Large Eddy Simulations

The interaction of turbulence, temperature fluctuation, liquid fuel transport, mixing and evaporation is studied by using Large Eddy Simulations (LES). To assess the accuracy of the different components of the methods we consider first isothermal, single phase flow in a straight duct. The results using different numerical methods incorporating dynamic Sub-Grid-Scale (SGS) models are compared with DNS and experimental data. The effects of the interactions among turbulence, temperature fluctuation, spray transport, evaporation and mixing of the gaseous fuel are studied by using different assumptions on the temperature field. It has been found that there are strong non-linear interactions among temperature-fluctuation, evaporation and turbulent mixing which require additional modeling if not full LES is used. The developed models and methods have been applied to a gas turbine burner into which liquid fuel is injected. The dispersion of the droplets in the burner is described. This revised version was published online in July 2006 with corrections to the Cover Date.     

Recovery of Methane From Gas Hydrates in a Porous Medium by Injection of Carbon Dioxide

This paper presents a mathematical model for methane hydrate–carbon dioxide replacement by injection of carbon dioxide gas into a porous medium rich in methane and its gas hydrate. Numerical solutions describing the pressure and temperature variation in a reservoir of finite length are obtained. It is shown that the replacement process is accompanied by a decrease in pressure and an increase in temperature of the porous medium. It is established that during the time of complete replacement of methane from a reservoir decreases with increasing permeability of the porous medium and the pressure of the injected gas.     

Numerical Investigation of Unipolar Injection in the Presence of Electroconvective Motion in a Plane Layer of Transformer Oil

The effect of unipolar injection of charges on the electroconvective motion of a weakly conducting liquid in a plane-parallel electrode system is investigated. By means of a numerical experiment it is confirmed that the crisis in the stability of a plane layer of weakly conducting liquid with unipolar injection conductivity depends significantly on the electrochemical processes in the electrode layer. A~dependence of the unipolar charge injection on the initial conductivity for a solution of molecular iodine in transformer oil is obtained.     

不同水合物饱和度下注热水开采实验研究

为研究不同水合物藏饱和度对注热开采动态的影响,采用自制的一维天然气水合物(NGH)开采模拟实验装置,模拟地层多孔介质的条件,首先在填砂模型中生成不同饱和度的NGH,然后进行注热盐水分解实验。结果表明:不同饱和度的NGH注热分解产气都可划分为三个阶段,不同的是NGH饱和度越高,水合物分解阶段的产气速率越大,且该阶段持续的时间越长;NGH饱和度越高,注热分解阶段电阻率增大的幅度越大,系统各测点温度升高的幅度越小。注热分解过程中产水速率围绕注水速率而上下波动,且NGH饱和度越高,产水速率波动幅度越大;在实验研究范围内,随初始水合物饱和度的升高,注热开采的能量效率逐渐升高。因此,从能量效率来说,高饱和度的水合物藏更适宜于注热开采。     

应用PIV技术研究重力式油,气,水分离器的内部流场

重力式油、气、水三相分离器在边际油田开发、处理量不大且油井分布分散的油田开发等方面得到了广泛的应用,文中利用ＰＩＶ技术重点测试分离器内部流场,得到流动死区、旋涡区、流动“短路”等现象,并分析其对分离效率的影响,提出从底部进料、均匀化流速等改进措施．     

Visual Investigation of Improvement in Extra-Heavy Oil Recovery by Borate-Assisted $$\hbox {CO}_{2}$$-Foam Injection

The significant reduction in heavy oil viscosity when mixed with \(\hbox {CO}_{2}\) is well documented. However, for \(\hbox {CO}_{2}\) injection to be an efficient method for improving heavy oil recovery, other mechanisms are required to improve the mobility ratio between the \(\hbox {CO}_{2}\) front and the resident heavy oil. In situ generation of \(\hbox {CO}_{2}\)-foam can improve \(\hbox {CO}_{2}\) injection performance by (a) increasing the effective viscosity of \(\hbox {CO}_{2}\) in the reservoir and (b) increasing the contact area between the heavy oil and injected \(\hbox {CO}_{2}\) and hence improving \(\hbox {CO}_{2}\) dissolution rate. However, in situ generation of stable \(\hbox {CO}_{2}\)-foam capable of travelling from the injection well to the production well is hard to achieve. We have previously published the results of a series of foam stability experiments using alkali and in the presence of heavy crude oil (Farzaneh and Sohrabi 2015). The results showed that stability of \(\hbox {CO}_{2}\)-foam decreased by addition of NaOH, while it increased by addition of \(\hbox {Na}_{2}\hbox {CO}_{3}\). However, the highest increase in \(\hbox {CO}_{2}\)-foam stability was achieved by adding borate to the surfactant solution. Borate is a mild alkaline with an excellent pH buffering ability. The previous study was performed in a foam column in the absence of a porous medium. In this paper, we present the results of a new series of experiments carried out in a high-pressure glass micromodel to visually investigate the performance of borate–surfactant \(\hbox {CO}_{2}\)-foam injection in an extra-heavy crude oil in a transparent porous medium. In the first part of the paper, the pore-scale interactions of \(\hbox {CO}_{2}\)-foam and extra-heavy oil and the mechanisms of oil displacement and hence oil recovery are presented through image analysis of micromodel images. The results show that very high oil recovery was achieved by co-injection of the borate–surfactant solution with \(\hbox {CO}_{2}\), due to in-situ formation of stable foam. Dissolution of \(\hbox {CO}_{2}\) in heavy oil resulted in significant reduction in its viscosity. \(\hbox {CO}_{2}\)-foam significantly increased the contact area between the oil and \(\hbox {CO}_{2}\) significantly and thus the efficiency of the process. The synergy effect between the borate and surfactant resulted in (1) alteration of the wettability of the porous medium towards water wet and (2) significant reduction of the oil–water IFT. As a result, a bank of oil-in-water (O/W) emulsion was formed in the porous medium and moved ahead of the \(\hbox {CO}_{2}\)-foam front. The in-situ generated O/W emulsion has a much lower viscosity than the original oil and plays a major role in the observed additional oil recovery in the range of performed experiments. Borate also made \(\hbox {CO}_{2}\)-foam more stable by changing the system to non-spreading oil and reducing coalescence of the foam bubbles. The results of these visual experiments suggest that borate can be a useful additive for improving heavy oil recovery in the range of the performed tests, by increasing \(\hbox {CO}_{2}\)-foam stability and producing O/W emulsions.     

The Effect of Asphalt Precipitation on Flow Behavior and Production of a Fractured Carbonate Oil Reservoir During Gas Injection

The first field data, collected over an 11 year period, are presented which indicate the possible effect of asphalt precipitation on the permeability and injectivity index of a fractured carbonate oil reservoir. The asphalt aggregates were formed during enhanced oil recovery by injection of a rich gas into the reservoir. The data indicate that, while at the initial stages of the operations the permeability and injectivity index decrease, at later times they appear to oscillate with the process time, with apparent oscillations' periods that depend on the heterogeneity of the reservoir. Two classes of plausible mechanisms that give rise to such oscillatory behavior are discussed. One relies on the changes in the structure of the reservoir's fractures, while the other one is based on asphalt precipitation in the reservoir. Computer simulations of flow and precipitation of asphalt aggregates in a pore network model of the reservoir are carried out. The results appear to support our proposition that asphalt formation and precipitation in the reservoir are the main mechanism for the observed behavior of the injectivity index. We also develop a stochastic continuum model that accurately predicts the time-dependence of the reservoir's permeability and injectivity index during the gas injection process.     

The Experimental and Numerical Studies on Gas Production from Hydrate Reservoir by Depressurization

A set of experimental system to study hydrate dissociation in porous media is built and some experiments on hydrate dissociation by depressurization are carried out. A mathematical model is developed to simulate the hydrate dissociation by depressurization in hydrate-bearing porous media. The model can be used to analyze the effects of the flow of multiphase fluids, the kinetic process and endothermic process of hydrate dissociation, ice-water phase equilibrium, the variation of permeability, convection and conduction on the hydrate dissociation, and gas and water productions. The numerical results agree well with the experimental results, which validate our mathematical model. For a 3-D hydrate reservoir of Class 3, the evolutions of pressure, temperature, and saturations are elucidated and the effects of some main parameters on gas and water rates are analyzed. Numerical results show that gas can be produced effectively from hydrate reservoir in the first stage of depressurization. Then, methods such as thermal stimulation or inhibitor injection should be considered due to the energy deficiency of formation energy. The numerical results for 3-D hydrate reservoir of Class 1 show that the overlying gas hydrate zone can apparently enhance gas rate and prolong life span of gas reservoir.     

Injection,Flow, and Mixing of CO<Subscript>2</Subscript> in Porous Media with Residual Gas

Geologic structures associated with depleted natural gas reservoirs are desirable targets for geologic carbon sequestration (GCS) as evidenced by numerous pilot and industrial-scale GCS projects in these environments world-wide. One feature of these GCS targets that may affect injection is the presence of residual CH₄. It is well known that CH₄ drastically alters supercritical CO₂ density and viscosity. Furthermore, residual gas of any kind affects the relative permeability of the liquid and gas phases, with relative permeability of the gas phase strongly dependent on the time-history of imbibition or drainage, i.e., dependent on hysteretic relative permeability. In this study, the effects of residual CH₄ on supercritical CO₂ injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with no residual gas; (2) with residual supercritical CO₂; and (3) with residual CH₄. We further compare results of simulations that use non-hysteretic and hysteretic relative permeability functions. The primary effect of residual gas is to decrease injectivity by decreasing liquid-phase relative permeability. Secondary effects arise from injected gas effectively incorporating residual gas and thereby extending the mobile-gas plume relative to cases with no residual gas. Third-order effects arise from gas mixing and associated compositional effects on density that effectively create a larger plume per unit mass. Non-hysteretic models of relative permeability can be used to approximate some parts of the behavior of the system, but fully hysteretic formulations are needed to accurately model the entire system.     

Electromagnetic Sounding of Oil and Gas Formations

A mathematical model is proposed that describes electrical conductivity variation in the near-well zone during drilling formations containing three immiscible phases: oil, gas, and a small amount of native salt water. It is assumed that borehole drilling is performed using a clay–water solution, the mass-exchange process between the moving mud filtrate and immovable native water is infinitely fast, and displacement of the gas phase occurs by piston flow. The redistribution of the immiscible phases is described by the conventional Buckley–Leverett equations. The electromagnetic response of the medium is interpreted using the earlier proposed method of probabilistic convolutions.     

RLPG点火及冷态喷射过程研究

报道了再生式液体发射药火炮 (RLPG)点火及模拟工质冷态喷射过程的实验结果 ,定量测试了燃烧室、贮液室压力曲线。实验表明 ,采用液体阻尼可以有效减弱点火过程中的压力振荡。针对点火喷射过程建立了数学物理模型 ,并进行了相应数值模拟 ,计算值和实验数据吻合较好。研究结果对深入分析再生式液体发射药火炮内弹道循环有指导意义和参考价值。     

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

The reinjection of sour or acid gas mixtures is often required for the exploitation of hydrocarbon reservoirs containing remarkable amounts of acid gases (H₂S and CO₂) to reduce the environmental impact of field exploitation and provide pressure support for enhanced oil recovery (EOR) purposes. Sour and acid gas injection in geological structures can be modelled with TMGAS, a new Equation of State (EOS) module for the TOUGH2 reservoir simulator. TMGAS can simulate the two-phase behaviour of NaCl-dominated brines in equilibrium with a non-aqueous (NA) phase, made up of inorganic gases such as CO₂ and H₂S and hydrocarbons (pure as well as pseudo-components), up to the high pressures (~100 MPa) and temperatures (~200°C) found in deep sedimentary basins. This study is focused on the near-wellbore processes driven by the injection of an acid gas mixture in a hypothetical high-pressure, under-saturated sour oil reservoir at a well-sector scale and at conditions for which the injected gas is fully miscible with the oil. Relevant-coupled processes are simulated, including the displacement of oil originally in place, the evaporation of connate brine, the salt concentration and consequent halite precipitation, as well as non-isothermal effects generated by the injection of the acid gas mixture at temperatures lower than initial reservoir temperature. Non-isothermal effects are studied by modelling in a coupled way wellbore and reservoir flow with a modified version of the TOUGH2 reservoir simulator. The described approach is limited to single-phase wellbore flow conditions occurring when injecting sour, acid or greenhouse gas mixtures in high-pressure geological structures.     

Predictions of Axial and Transverse Injection into Supersonic Flow

CFD calculations are performed on a swept ramp injecting fuelaxially, and on a two-hole transverse fuel injection downstream of abackward-facing step, both into a supersonic turbulent flow. Theresulting complex flowfields are predicted using a cubick–ε turbulence closure. Comparisons with experimental data show very good agreement. A discussion of the main flow features is presented. The fast computational convergence demonstrates the readiness of the method for the design cycle. This revised version was published online in July 2006 with corrections to the Cover Date.     

Effect of Gas Injection from the Surface of a Body on Its Interaction with a Temperature Inhomogeneity in a Supersonic Flow

The flow pattern in the shock layer and the aerodynamic characteristics of a hemisphere in unsteady axisymmetric interaction with a closed spherical hot-gas region embedded in the oncoming supersonic flow in the presence of intense injection of gas from the body surface into the shock layer are studied on the basis of the inviscid perfect gas model. Two cases are considered, namely, (1) when the radius of the permeable surface is greater than that of the temperature inhomogeneity and (2) when the injection is localized in the vicinity of the forward stagnation point and the permeable region is smaller the inhomogeneity.     

Drainage of Capillary-Trapped Oil by an Immiscible Gas: Impact of Transient and Steady-State Water Displacement on Three-Phase Oil Permeability

In a previous paper (Dehghanpour et al., Phys Rev E 83:065302, 2011a), we showed that relative permeability of mobilized oil, $k_\mathrm{ro}$ , measured during tertiary gravity drainage, is significantly higher than that of the same oil saturation in other tests where oil is initially a continuous phase. We also showed that tertiary $k_\mathrm{ro}$ strongly correlates to both water saturation, $S_\mathrm{w}$ , water flux (water relative permeability), $k_\mathrm{rw}$ , and the change in water saturation with time, $\mathrm{d}S_\mathrm{w}/\mathrm{d}t$ . To develop a model and understanding of the enhanced oil transport, identifying which of these parameters ( $S_\mathrm{w},\,k_{\mathrm{rw}}$ , or $\mathrm{d}S_\mathrm{w}/\mathrm{d}t$ ) plays the controlling role is necessary, but in the previous experiments these could not be deconvolved. To answer the remaining question, we conduct specific three-phase displacement experiments in which $k_{\mathrm{rw}}$ is controlled by applying a fixed water influx, and $S_\mathrm{w}$ develops naturally. We obtain $k_{\mathrm{ro}}$ by using the saturation data measured in time and space. The results suggest that steady-state water influx, in contrast to transient water displacement, does not enhance $k_{\mathrm{ro}}$ . Instead, reducing water influx rate results in excess oil flow. Furthermore, according to our pore scale hydraulic conductivity calculations, viscous coupling and fluid positioning do not sufficiently explain the observed correlation between $k_{\mathrm{ro}}$ and $S_{\mathrm{w}}$ . We conclude that tertiary $k_{\mathrm{ro}}$ is controlled by the oil mobilization rate, which in turn is linked to the rate of water saturation decrease with time, $\mathrm{d}S_\mathrm{w}/\mathrm{d}t$ . Finally, we develop a simple model which relates tertiary $k_{\mathrm{ro}}$ to transient two-phase gas/water relative permeability.     

Water removal from porous media by gas injection: experiments and simulation

The flow of a saturated gas through a porous medium, partially occupied by a liquid phase, causes evaporation due to gas expansion. This process, referred to as flow-through drying, is important in a wide variety of natural and industrial applications, such as natural gas production, convective drying of paper, catalysts, fuel cells and membranes. X-ray imaging experiments were performed to study the flow-through drying of water-saturated porous media during gas injection. The results show that the liquid saturation profile and the rate of drying are dependent on the viscous pressure drop, the state of saturation of the gas and the capillary characteristics of the porous medium. During the injection of a completely saturated gas, drying occurs only due to gas expansion. Capillary-driven flow from regions of high saturation to regions of low saturation lead to more uniform saturation profiles. During the injection of a dry gas, a drying front develops at the inlet and propagates through the porous medium. The experimental results are compared with numerical results from a continuum model. A good agreement is found for the case of sandstone. The comparison is less satisfactory for the experiments with limestone.     

聚合物驱交替注入改善吸液剖面的力学机制及效果评价方法

开发实践表明,聚合物驱采用单一段塞注入方式,暴露出了易发生剖面返转的问题。鉴于此,研究了通过交替注入方式改善吸液剖面的新型驱油方法。应用渗流力学基本定律,结合实验数据,论证了单一段塞注入剖面返转及交替注入抑制剖面返转的力学机制。结果表明,注聚合物过程中高、低渗层阻力系数表现规律不同,而交替注入方式能够使高、低渗层阻力系数表现规律趋同,是单一段塞注入方式发生剖面返转、交替注入方式抑制剖面返转的根本原因。本文建立了用低、高渗层累积阻力系数的比值作为吸液剖面改善效果的评价方法,该比值越小,低渗层吸液比例越高,吸液剖面改善效果越好。