Visualisation of Residual Oil Recovery by Near-miscible Gas and SWAG Injection Using High-pressure Micromodels

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).     

Pore-Scale Imaging and Analysis of Wettability Order,Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤?1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

     

Experimental Study of Pore-Scale Mechanisms of Carbonated Water Injection

Carbon dioxide (CO₂) injection is a well-established method for increasing recovery from oil reservoirs. However, poor sweep efficiency has been reported in many CO₂ injection projects due to the high mobility contrast between CO₂ and oil and water. Various injection strategies including gravity stable, WAG and SWAG have been suggested and, to some extent, applied in the field to alleviate this problem. An alternative injection strategy is carbonated water injection (CWI). In CWI, CO₂ is delivered to a much larger part of the reservoir compared to direct CO₂ injection due to a much improved sweep efficiency. In CWI, CO₂ is used efficiently and much less CO₂ is required compared to conventional CO₂ flooding, and hence the process is particularly attractive for reservoirs with limited access to large quantities of CO₂ (offshore reservoirs or reservoirs far away from inexpensive natural CO₂ resources). This article describes the results of a pore-scale study of the process of CWI by performing high-pressure visualisation flow experiments. The experimental results show that CWI, compared to unadulterated (conventional) water injection, improves oil recovery as both a secondary (before water flooding) and a tertiary (after water flooding) recovery method. The mechanisms of oil recovery by CWI include oil swelling, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution. In this article the potential benefit of a subsequent depressurisation period on oil recovery after the CWI period is also investigated.     

Effect of petrophysical matrix properties on bypassed oil recovery from a matrix-fracture system during CO2 near-miscible injection: Experimental investigation

The effects of petrophysical matrix properties such as porosity and permeability on bypassed oil recovery were investigated during CO₂ injection in fractures at different miscibility regimes (first-contact miscibility, near-miscibility, and immiscibility). A special experimental setup was designed for this purpose and a series of CO₂ injection experiments were performed using two different types of porous media, sandstones and carbonates. To confirm the analysis, some tests were repeated in the presence of irreducible water saturation. In addition, dimensional analysis was used to capture the dominant forces and mechanisms.The results demonstrated that the highest oil recovery was achieved within near-miscible regime for the both rock types. Furthermore, in all miscibility regimes, the oil recovery factor decreased with the increase of the rock complexity and frequency of dead-end pores, whereas it declined as the permeability decreased. However, differences in recovery factors of near-critical and super-critical tests grew. Considering the analytical calculations and the results of experiments including initial water saturation, it can be concluded that near-critical point wetting and the number of dead-end pores have significant effects on variations of the oil recovery factor. With near-critical point wetting, maximum recovery was achieved at near-critical state, and the presence of dead-end pores caused the role of this mechanism to be more noticeable. As a result, differences in the recovery factor of near-critical and super-critical tests grew.     

Numerical simulation of pore-scale flow in chemical flooding process

Chemical flooding is one of the effective technologies to increase oil recovery of petroleum reservoirs after water flooding. Above the scale of representative elementary volume (REV), phenomenological modeling and numerical simulations of chemical flooding have been reported in literatures, but the studies alike are rarely conducted at the pore-scale, at which the effects of physicochemical hydrodynamics are hardly resolved either by experimental observations or by traditional continuum-based simulations. In this paper, dissipative particle dynamics (DPD), one of mesoscopic fluid particle methods, is introduced to simulate the pore-scale flow in chemical flooding processes. The theoretical background, mathematical formulation and numerical approach of DPD are presented. The plane Poiseuille flow is used to illustrate the accuracy of the DPD simulation, and then the processes of polymer flooding through an oil-wet throat and a water-wet throat are studies, respectively. The selected parameters of those simulations are given in details. These preliminary results show the potential of this novel method for modeling the physicochemical hydrodynamics at the pore scale in the area of chemical enhanced oil recovery.     

Pore Scale and Macroscopic Displacement Mechanisms in Emulsion Flooding

The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control.     

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.

     

Displacement mechanisms of enhanced heavy oil recovery by alkaline flooding in a micromodel

Enhanced oil recovery (EOR) by alkaline flooding for conventional oils has been extensively studied. For heavy oils, investigations are very limited due to the unfavorable mobility ratio between the water and oil phases. In this study, the displacement mechanisms of alkaline flooding for heavy oil EOR are investigated by conducting flood tests in a micromodel. Two different displacement mechanisms are observed for enhancing heavy oil recovery. One is in situ water-in-oil (W/O) emulsion formation and partial wettability alteration. The W/O emulsion formed during the injection of alkaline solution plugs high permeability water channels, and pore walls are altered to become partially oil-wetted, leading to an improvement in sweep efficiency and high tertiary oil recovery. The other mechanism is the formation of an oil-in-water (O/W) emulsion. Heavy oil is dispersed into the water phase by injecting an alkaline solution containing a very dilute surfactant. The oil is then entrained in the water phase and flows out of the model with the water phase.     

Microbial Enhanced Oil Recovery in Fractional-Wet Systems: A Pore-Scale Investigation

Microbial enhanced oil recovery (MEOR) is a technology that could potentially increase the tertiary recovery of oil from mature oil formations. However, the efficacy of this technology in fractional-wet systems is unknown, and the mechanisms involved in oil mobilization therefore need further investigation. Our MEOR strategy consists of the injection of ex situ produced metabolic byproducts produced by Bacillus mojavensis JF-2 (which lower interfacial tension (IFT) via biosurfactant production) into fractional-wet cores containing residual oil. Two different MEOR flooding solutions were tested; one solution contained both microbes and metabolic byproducts while the other contained only the metabolic byproducts. The columns were imaged with X-ray computed microtomography (CMT) after water flooding, and after MEOR, which allowed for the evaluation of the pore-scale processes taking place during MEOR. Results indicate that the larger residual oil blobs and residual oil held under relatively low capillary pressures were the main fractions recovered during MEOR. Residual oil saturation, interfacial curvatures, and oil blob sizes were measured from the CMT images and used to develop a conceptual model for MEOR in fractional-wet systems. Overall, results indicate that MEOR was effective at recovering oil from fractional-wet systems with reported additional oil recovered (AOR) values between 44 and 80%; the highest AOR values were observed in the most oil-wet system.     

Parameter Determination Using 3D FIB-SEM Images for Development of Effective Model of Shale Gas Flow in Nanoscale Pore Clusters

A large amount of nano-pores exists in pore clusters in shale gas reservoirs. In addition to the multiple transport regimes that occur on the nanoscale, the pore space is another major factor that significantly affects the shale gas recoverability. An investigation of the pore-scale shale gas flow is therefore important, and the results can be used to develop an effective cluster-scale pore network model for the convenient examination of the process efficiency. Focused ion beam scanning electron microscope imaging, which enables the acquisition of nanometre-resolution images that facilitate nano-pore identification, was used in conjunction with a high-precision pore network extraction algorithm to generate the equivalent pore network for the simulation of Darcy and shale gas flows through the pores. The characteristic parameters of the pores and the gas transport features were determined and analysed to obtain a deeper understanding of shale gas flow through nanoscale pore clusters, such as the importance of the throat flux–radius distribution and the variation of the tortuosity with pressure. The best parameter scheme for the proposed effective model of shale gas flow was selected out of three derived schemes based on the pore-scale prediction results. The model is applicable to pore-scale to cluster-scale shale gas flows and can be used to avoid the multiple-solution problems in the study of gas flows. It affords a foundation for further study to develop models for shale gas flows on larger scales.     

天然气驱长岩心室内实验研究

低渗透油藏注水开发效果差、采收率低,而采用气驱技术是动用此类难采储量的有效方法之一。本文利用长岩心实验模型,进行了物理模拟研究,得到了该油藏在纯气驱、纯水驱、完全水驱后气水交替驱、原始状态下气水交替驱和油藏目前注水倍数下气水交替驱等方式下的采收率和压力等变化情况,为油藏选择合理的开采方式提供了依据,并且为进一步的数值模拟工作提供了基础数据。     

基于孔与裂隙网络模型的平行微裂隙对驱油的影响规律研究

认识双重多孔介质中油水两相微观渗流机制是回答形成什么类型的裂隙网络可提高油藏采收率的关键. 微裂隙的分布可以提高多孔介质的绝对渗透率,但对于基质孔隙中的流体介质,微裂隙的存在会引起多孔介质中局部流体压力和流场的变化,导致局部流动以微裂隙流动为主,甚至出现窜流现象,降低驱油效率. 本文基于孔与裂隙双重网络模型,在网络进口设定两条平行等长且具有一定间隔的微裂隙,分析微裂隙的相对间隔(微裂隙之间距离/喉道长度)和微裂隙相对长度(微裂隙长度/喉道长度)对于微观渗流特征的影响. 结果表明:随微裂隙相对长度的增加,出现驱油效率逐渐降低,相对渗透率曲线中的油水共渗区水饱和度和等渗点增加,油水两相的共渗范围减小等现象;随着微裂隙之间相对间隔增大,周围越来越多的基质孔穴间的压力差减小,在毛管压力的限制下,驱替相绕过这些区域,而导致水窜现象.      

Consideration on Data Dispersion for Two-Phase Flow Micromodel Experiments

Transparent man-made porous media, also known as micromodels, are a widely used exploration tool in the field of two-phase flow in porous media (Alireza and Sohrabi in Soc Petrol Eng 166435, 2013; Bondino et al., in International symposium of the society of core analysts held in Napa Valley, California, USA, 2013) to enhance the comprehension of oil recovery mechanisms at pore-scale. Although they have more often been used as qualitative visualization tools to explore the elementary physicochemical features of a given flow mechanism, their utilization as a quantitative tool is interesting especially in industrial context, where they represent an easy and low-cost screening tool for complex recovery mechanisms (low salinity waterflooding, polymer flooding, etc). However, the repeatability of these experiments and thus the possibility to derive quantitative conclusions from them appears not to be investigated in the literature in our field of study. In this work, we explore the dispersion of data such as capillary desaturation curves and secondary waterflood recoveries using micromodels of different sizes and different pore patterns from our laboratory and from an external one. Using datasets with low sampling (low number of repeats of an experiment) and with very large sampling, we document the type of data dispersion, we analyze its reasons and we verify to which extent truly quantitative conclusions can be drawn from these datasets. Our study demonstrates that at low sampling drawing quantitative inferences from our datasets is questionable due to the large uncertainty of the produced data.     

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.     

Microtomography of Imbibition Phenomena and Trapping Mechanism

Water imbibition during the waterflooding process of oil production only sweeps part of the oil present. After water disrupts the oil continuity, most oil blobs are trapped in porous rock by capillary forces. Developing an efficient waterflooding scheme is a difficult task; therefore, an understanding of the oil trapping mechanism in porous rock is necessary from a microscopic viewpoint. The development of microfocused X-ray CT scanner technology enables the three-dimensional visualization of multiphase phenomena in a pore-scale. We scanned packed glass beads filled with a nonwetting phase (NWP) and injected wetting phase (WP) in upward and downward injections to determine the microscopic mechanism of immiscible displacement in porous media and the effects of buoyancy forces. We observed the imbibition phenomena for small capillary numbers to understand the spontaneous imbibition mechanism in oil recovery. This study is one of the first attempts to use a microfocused X-ray CT scanner for observing the imbibition and trapping mechanisms. The trapping mechanism in spontaneous imbibition is determined by the pore configuration causing imbibition speed differences in each channel; these differences can disrupt the oil continuity. Gravity plays an important role in spontaneous imbibition. In upward injection, the WP flows evenly and oil is trapped in single or small clusters of pores. In downward injection, the fingering phenomena determine the amount of trapped oil, which is usually in a network scale. Water breakthrough causes dramatic decrease in the oil extraction rate, resulting in lower oil production efficiency.     

Coreflooding Studies to Evaluate the Impact of Salinity and Wettability on Oil Recovery Efficiency

In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of experiments) with decrease in brine salinity and increase in brine temperature.     

Accurate Modelling of Pore-Scale Films and Layers for Three-Phase Flow Processes in Clastic and Carbonate Rocks with Arbitrary Wettability

Three-phase flow is a key process occurring in subsurface reservoirs, for example, during $\text{ CO }_2$ sequestration and enhanced oil recovery techniques such as water alternating gas (WAG) injection. Predicting three-phase flow processes, for example, the increase in oil recovery during WAG, requires a sound understanding of the fundamental flow physics in water- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this study, we use pore-network modelling, a reliable and physically based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from water- to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows for the accurate modelling of the mobilisation of many disconnected phase clusters that arise, in particular, during higher order WAG floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the sample. For water-wet systems, we have validated our model with available experimental data from core floods. For oil-wet systems, we validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.     

Fundamental Study of Pore Scale Mechanisms in Microbial Improved Oil Recovery Processes

A fundamental study of microscopic mechanisms and pore-level phenomena in the Microbial Improved Oil Recovery method has been investigated. Understanding active mechanisms to increase oil recovery is the key to predict and plan MIOR projects successfully. This article presents the results of visualization experiments carried out in a transparent pore network model. In order to study the pore scale behavior of bacteria, dodecane and an alkane oxidizing bacterium, Rhodococcus sp. 094, suspended in brine, are examined for evaluating the performance of bacterial flooding in the glass micromodel. The observations show the effects of bacteria on remaining oil saturation, allowing us to get better insight on the mechanisms. Bacterial mass composed of bacteria and bioproducts growth in the fluid interfaces and pore walls have been recorded and are presented. No gas is observed throughout any of the experiments. The biomass blocks some pores and pore-throats, and thereby changing the flow pattern. As a consequent, the flow pattern change together with the previously proposed mechanisms, including the interfacial tension reduction and wettability changes are recognized as active mechanisms in the MIOR process.     

Relative Permeability of Near-Miscible Fluids in Compositional Simulators

Miscible gas injection is one of the most effective enhanced oil recovery techniques. There are several challenges in accurately modeling this process, which occurs in the near-miscible region. The adjustment of relative permeability for near-miscible processes is the main focus of this work. The dependence of relative permeability on phase identification can lead to significant complications while simulating near-miscible displacements. We present an analysis of how existing methods incorporate compositional dependence in relative permeability functions. The sensitivity of the different methods to the choice of reference points is presented with guidelines to limit the modification of the relative permeabilities to physically reasonable values. We distinguish between the two objectives of reflecting near-miscible behavior and ensuring smooth transitions across phase changes. We highlight an important link that combines the two objectives in a more general framework. We make use of Gibbs free energy as a compositional indicator in the generalized framework. The new approach was implemented in an automatic differentiation general purpose research simulator and tested on a set of near-miscible gas-injection problems. We show that including compositional dependencies in the relative permeability near the critical point impacts the simulation results with significant improvements in nonlinear convergence.