Experimental Study of Microscopic Displacement Efficiency of Polymer Microspheres Using Low-Field NMR

For reservoirs in high water cut exploitation period, profile control and water plugging is one of the important ways to improve oil recovery. Cores with different permeability were flooded to analyze the displacement results and displacement mechanisms for different grain size of polymer microspheres. Fluid distribution in cores was measured by NMR spectroscopy after water flooding, polymer microspheres flooding, and subsequent water flooding. The range of pore sizes from which oil was swept out was also calculated. The results showed that microspheres can effectively sweep remaining oil in different pore size of the cores. The suitability of different grain size of polymer microspheres with cores is different, microspheres with micron size are suitable for high-permeability cores, and microspheres with nanometer size are suitable for low-permeability cores.     

Nanofluid in Hydrophilic State for EOR Implication Through Carbonate Reservoir

More than 50% of oil is trapped in petroleum reservoirs after applying primary and secondary recovery methods for removal. Thus, to produce more crude oils from these reservoirs, different enhanced oil recovery (EOR) approaches should be performed. In this research, the effect of hydrophilic nanoparticles of SiO₂ at 12 nm size, in (EOR) from carbonate reservoir is systematically investigated. Using this nanoparticle, we can increase viscosity of the injection fluid and then lower the mobility ratio between oil and nanofluid in carbonate reservoirs. To this end, a core flooding apparatus was used to determine the effectiveness and robustness of nanosilica for EOR from carbonate reservoirs. These experiments are applied on the reservoir carbonate core samples, which are saturated with brine and oil that was injected with nanoparticles of SiO₂ at various concentrations. The output results depict that, with increasing nanoparticle concentration, the viscosity of the injection fluid increases and results in decreased mobility ratio between oil and nanofluid. The results confirm that using the nanoparticle increases the recovery. Also, increasing the nanoparticle concentration up to 0.6% increases the ultimate recovery (%OOIP), but a further increase to 1.0 does not have a significant effect.     

Novel investigation based on cationic modified starch with residual anionic polymer for enhanced oil recovery

Cationic modified starch polymer (CMSP) is a newly developed green chemical agent designed to reutilize the residual anionic polymer found in reservoirs for enhanced oil recovery (EOR). In this study, a series of experiments were conducted to investigate the phase behavior of the residual anionic polymer, CMSP solution, and the flocculation generated from the mixture in plugging capacity and capability of enhancing oil recovery in heterogeneous reservoirs. The experiment results show that the phase behavior of the residual anionic polymer and CMSP solution could be divided into two parts: rapid flocculation reaction and dispersion reaction. The main mechanisms of the rapid flocculation reaction were charge neutralization and bridging. Based on the above results, an optimal amount of CMSP was chosen for plugging capacity, stability, and EOR study. Plugging tests in both parallel cores and EOR in three-layer heterogeneous square cores illustrate that the injected CMSP slug after polymer flooding can effectively block the high-permeability zone and initiate the remaining oil in middle- to low-permeability zones. The investigation results prove that the CMSP solution, injected after polymer flooding, reduces the pollution of produced fluid and further improves oil recovery.     

Investigation on the Adaptability of the Polymer Microspheres for Fluid Flow Diversion in Porous Media

Large amounts of water producing from producers have been a great concern for petroleum engineers. In an attempt to inhibit water production and promote oil productivity, various water control agents and techniques have been devised for enhanced oil recovery purpose for decades with some good successes reported commercially. Mainly field-targeted specifically, however, these chemicals are limited in expansive reservoir applications for failing to tolerate harsh formation conditions of high temperature (HT) and high salinity (HS). Besides, their low injectivity is also another proper impediment. In this presentation, we synthesized a new agent of polymer microspheres using inverse emulsion polymerization technique to divert fluid patterns in deep porous media for reservoirs encountered recovery enhancement problems. These microspheres are made to tolerate HT and HS conditions, and can be pumped into deep pore space with relative ease. With the help of nuclear magnetic resonance (NMR) and nuclear pore membrane filtration techniques, a series of experimental procedures were conducted to test the adaptability of newly produced polymer microspheres to targeted pore structure in enhancing the sweeping efficiency of injection fluids. Both laboratory core tests and NMR data show good characteristics of polymer microspheres in modifying injection profile, demonstrating a good capability to divert fluid flow patterns in deep porous media and enhance oil productivity.     

Study on Influencing Factors of Chemical Flooding for Heavy Oil

Alkali and alkali/surfactant displacing agents are designed for two kinds of heavy oil. Results of emulsifying capacity, dynamic interfacial tension (IFT) and water-wet core flooding tests show that, although alkaline/surfactant systems exhibit better capacity in emulsification and IFT reduction, oil recovery values of alkaline/surfactant flooding are lower than those of alkaline flooding. Glass-etched micromodel tests further demonstrate that, when alkaline solution penetrates into the oil phase, water streams break into ganglia coating oil film. Water ganglia may be entrapped by narrow throats, consequently presenting a water-oil alternating slug flow. Similar water ganglia also appears in alkaline/surfactant flooding, however, water channeling along the pore surface occurs subsequently, resulting in its relatively lower oil recovery.     

Experimental investigation on spontaneous counter‐current imbibition in water‐wet natural reservoir sandstone core using MRI

Counter‐current imbibition is a process whereby a wetting phase spontaneously imbibes into a porous media, displacing the non‐wetting phase. This process is considered an important oil recovery mechanism during water flooding in fractured oil reservoirs. In this study, the dynamic process of counter‐current imbibition for a natural reservoir sandstone core with an all‐face‐open boundary condition was monitored using magnetic resonance imaging (MRI). A series of images and relaxation time T₁ spectra were acquired. The movement of water spontaneously entering the core sample while oil escapes, the spatial distribution of oil and water, and the in situ saturation change of oil and water in porous media can be accurately detected using MRI. MRI assists the direct evaluation of the basic mechanisms of imbibitions. Experimental results suggest the remaining oil was trapped in some large pores because of the capillary pressure, and the oil recovery in some large‐pore regions is lower than that in some small‐pore regions at the end of imbibition. Experimental findings show a close agreement between conventional material balance and oil recovery determined from MRI. The in situ oil recovery data agree well with the empirical models. The observations from MRI images could provide test cases to enable the development of mathematical models and to facilitate the evaluation of the proposed imbibition mechanisms. Copyright © 2016 John Wiley & Sons, Ltd.     

Foam Flooding with Ultra-Low Interfacial Tension to Enhance Heavy Oil Recovery

Severe viscous fingering during water flooding of heavy oil leaves a large amount of oil untouched in the reservoir. Improving sweep efficiency is vital for increasing heavy oil recovery. Previous researches have proved that foam flooding can increase the sweep efficiency and oil recovery. The polymers could make the foam more stable and have better plugging capacity, but the interfacial tension (IFT) of oil and water increase which could decrease the displacement efficiency of the heavy oil. In view of the deficiency of conventional foam flooding, it is necessary to research the ultra-low interfacial tension foam which could improve macro-swept volume and micro-displacement efficiency in heavy oil reservoir. In this paper a novel foam agent is developed by the combination of surfactant and additives to lower the IFT of oil and water. The operating parameters including foam injections modes and gas liquid ratio were investigated by core flooding experiments. Field test performance shows that oil production per day increased from 85.6 to 125.7 t, water cut declined from 92.1 to 83.6% after 3 months injection. This study provides a novel method to improve heavy oil recovery with an ultra-low interfacial tension foam flooding system.     

The Wettability Alteration and the Effect of Initial Rock Wettability on Oil Recovery in Surfactant-based Enhanced Oil Recovery Processes

Wettablity alteration of rock surface is an important mechanism for surfactant-based enhanced oil recovery (EOR) processes. Two salt and temperature-tolerant surfactant formulations were developed based on the conditions of high temperature (97–120°C) and high salinity (20 × 10⁴ mg/L) reservoirs where a surfactant-based EOR process is attempted. Both the two sufactant formulations can achieve ultralow interfacial tension level (≤10^?3 mN/m) with crude oil after aging for 125 days at reservoir conditions. Wettability alteration of core slices induced by the two surfactant formulations was evalutated by measuring contact angles. Core flooding experiments were carried out to study the influence of initial rock wettabilities on oil recovery in the crude oil/surfactant/formation water/rock system. The results indicated that the two formulations could turn oil-wet core slices into water-wet at 90–120°C and 20 × 10⁴ mg/L salinity, while the water-wet core slices retained their hydrophilic nature. The core flooding experiments showed that the water-wet cores could yield higher oil recovery compared with the oil-wet cores in water flooding, surfactant, and subsequent water flooding process. The two surfactant formulations could successfully yield additional oil recovery in both oil-wet and water-wet cores.     

用深部处理剂JY-8提高注聚区残余聚合物的利用率

针对目前各油田聚合物驱转为水驱后,一般出现含水上升快,产油量大幅度下降的情况,以及油层内残余的大量聚合物未得到利用,而目前开发的残余聚合物再利用技术存在一些缺点,未得到推广应用,研制出新型复合处理剂JY-8。新型复合处理剂JY-8可与聚合物形成强度较高的凝胶体,将地层内残余聚合物有效地固定和絮凝,是很好的固定剂和絮凝剂,实现了“二剂合一”,达到对地层进行深部调剖、驱油的目的;同时,通过调整复合处理剂JY-8的加量等可调节成胶时间和凝胶强度。室内评价和现场应用表明,与以前的技术相比,复合处理剂JY-8可使油层内的残余聚合物利用率从原来的8％提高到15.65％,使聚合物驱后续水驱的采收率增加值从原来的10.33％提高到18.1％,在油井上起到了很好的增油、控水效果。     

Mechanisms of Enhanced Oil Recovery by Surfactant-Induced Wettability Alteration

Different measurements were conducted to study the mechanisms of enhanced oil recovery (EOR) by surfactant-induced wettability alteration. The adhesion work could be reduced by the surfactant-induced wettability alteration from oil-wet conditions to water-wet conditions. Surfactant-induced wettability alteration has a great effect on the relative permeabilities of oil and water. The relative permeability of the oil phase increases with the increase of the water-wetness of the solid surface. Seepage laws of oil and water are greatly affected by surfactant-induced wettability alteration. Water flows forward along the pore wall in the water-wet rocks and moves forward along the center of the pores in the oil-wet rocks during the surfactant flooding. For the intermediate-wet system, water uniformly moves forward and the contact angle between the oil–water interface and the pore surface is close to 90°. The direction of capillary force is consistent with the direction of water flooding for the water-wet surface. While for the oil-wet surface, the capillary force direction is opposite to the water-flooding direction. The highest oil recovery by water flooding is obtained at close to neutral wetting conditions and the minimal oil recovery occurs under oil-wet conditions.     

In situ organically cross‐linked polymer gel for high‐temperature reservoir conformance control: A review

Polymer gel has been established as water‐blocking agents in oil recovery application. In this practice, a mixture known as gelant is injected into target area and set into a semisolid gel after a certain adequate time. Besides profile modification and water shutoff, the role of the polymer gel in conformance control is to block high permeability regions, before diverting injected water from high permeability to low permeability zones of the reservoir. It is to boost the oil displacement and sweep efficiency. This is the key to improve oil recovery in the heterogeneous oil reservoirs. However, very limited gels are applicable for harsh conditions, especially in high‐temperature reservoirs. Organically cross‐linked polymer is 1 of the materials for conformance control at high‐temperature reservoirs. Many experimental works and field applications have exhibited the potential of this technology. This paper presents a concise review on this polymer gel for conformance control at high‐temperature wells. Firstly, in situ organically cross‐linked polymer gel has been introduced, and the reason of the use over other types of polymer gels is summarized. The early studies of organically cross‐linked gel systems are also discussed, followed by the chemistry and the gelation mechanisms. An extensive review on factors that affect gelation kinetics and field applications is also discussed in some detail.     

Novel self‐assembling polymeric system based on a hydrophobic modified copolymer: formulation,rheological characterization,and performance in enhanced heavy oil recovery

This work presents the chemical formulation and rheological properties of a novel self‐assembling polymer (SAP) system derived from a hydrophobically modified sulfonated polyacrylamide (HMSPAM). This polymeric association was established through complexation between the pendant hydrophobic groups contained in HMSPAM and β‐cyclodextrin molecules. The new SAP system offers improved viscoelastic properties because of the “interlocking effect” of the hydrophobic groups into β‐cyclodextrin cavities. It also provides suitable reformability upon mechanical shear when compared to the base HMSPAM. Furthermore, SAP exhibits superior tolerance to elevate brine salinity and hardness, as well as high reservoir temperature. Sandpack flooding tests conducted at simulated reservoir conditions (Pelican Lake reservoir, Alberta, Canada) indicate that this system shows superior mobility control (resistance factor) compared to HMSPAM. It also shows potential as in situ permeability modifier, which makes this polymeric system particularly suitable for heavy oil recovery applications. For instance, the newly developed SAP produced 20% more incremental heavy oil recovery if compared to the performance of the commonly used partially hydrolyzed polyacrylamide and 7% more incremental oil recovery than the baseline HMSPAM at the same experimental conditions. Overall, this new self‐assembly system shows potential for applications in heavy oil recovery. Copyright © 2014 John Wiley & Sons, Ltd.     

Characterization of Remaining Oil After Polymer Flooding by Laser Scanning Confocal Fluorescence Microscopy

In the mid- to late period of oil field development, it is important to consider the microscopic distribution of remaining oil of the reservoir in time, for it is the foundation of enhanced oil recovery. Focusing on the present insufficient research status of microscopic distribution of remaining oil after polymer flooding, this article first put forward and developed a set of fluorescence microscope technology of frozen core analysis of remaining oil, and used this technology combined with laser confocal microscopic detection technology to study microscopic distribution rules of remaining oil before and after polymer flooding. Through comparison and analysis on the difference of microscopic distribution form of remaining oil, the experimental results show that polymer flooding has different effects on different types of remaining oil. Using this technology, analysis of many different distribution forms of remaining oil involving the same mode of occurrence in different layers, different parts of the same layer, and different types of the same layer can be more clearly distinguished. Using polymer flooding pertinently according to the different distribution form of remaining oil will make the use of polymer more efficiently and the recovery higher.     

Estimation of the Scale Deposits Near Wellbore via Software in the Presence of Inhibitors

In this study, computer software was used in order to estimate the scaling tendency of the commingling of two incompatible waters existed in Egyptian oil reservoirs of Gulf of Suez area. The chemical analyses of the two incompatible waters (injection and formation waters) have been used as input data to the computer simulator. The reservoirs characterized by a temperature of 90–127°C, and salinity of 100,000–230,000 ppm. The scaling results for the commingling of both injection and formation water at reservoir temperatures and pressures are recorded. The results of theoretical software and laboratory jar-testing were compared. It was found that mixing of the injection water and formation water may lead to calcium carbonate and barium sulphate scaling at 40% formation water in absence of scale inhibitor. Two types of commercial scale inhibitors (AII and SII) were evaluated using both jar test method and National Association of Corrosion engineers standard test methods. The results showed the mastery of AII over the commercial inhibitor SII in preventing of both scales.     

The profile control and displacement mechanism of continuous and discontinuous phase flooding agent

In order to further explore the profile control and displacement mechanism of continuous and discontinuous phase flooding agent, the concentration distribution mathematical model of microsphere dispersion system in different branch channels is established, and its particle phase separation is simulated by using microfluidic technology. On this basis, in order to research the migration and plugging characteristics of microspheres, the visualization experiments on micro oil displacement mechanism of polymer solution and microspheres are carried out. And the experiment on the injection, migration, and plugging performance of microspheres in the multi-point core is performed. Results indicate that microspheres are in the axis of the channel due to the effect of fluid shear stress, and preferentially enter the large channel with low resistance and high flow velocity, which results in no particle or few particles in the small aperture and low flow velocity channel. The microspheres have better migration and retention capacity in the core and their migration shows the characteristic of “fluctuating pressure change”. Compared with polymer solution, the alleviation of “entry profile inversion” and the better migration and plugging performance of microsphere dispersion system can realize deep fluid diversion and expand sweep volume.     

Improvement of Sweep Efficiency by Alkaline Flooding for Heavy Oil Reservoirs

Severe viscous fingering during water flooding of heavy oil leaves a large amount of oil untouched in the reservoir. Improving sweep efficiency is vital for enhancing heavy oil recovery. This study presented a laboratory study for improving sweep efficiency by alkaline flooding in heavy oil Reservoirs. This included glass-etched micromodel flooding tests, one-dimensional flooding experiments and three-dimensional physical model study. The micromodel tests show that W/O droplet flow plays a prominent role in the alkaline flooding to improve sweep efficiency. There is a minimum alkaline concentration that generates the W/O droplet flow, and the W/O droplet flow is more obvious with the alkaline concentration increasing. A series of flood tests were conducted using 325 mPa · s, 2000 mPa · s, and 3950 mPa · s heavy oils to assess the effectiveness of W/O droplet flow in alkaline flooding for enhanced heavy oil recovery. The flood tests results demonstrate the considerable potential for improved heavy oil recovery by alkaline flooding, and moreover, the incremental oil recovery has been found to increase as the alkaline concentration increases. The result obtained in three-dimensional physical model study indicates that the sweep area can be greatly improved by the formation of W/O droplet flow in alkaline flooding.     

Using magnesium oxide nanoparticles in a magnetic field to enhance oil production from oil-wet carbonate reservoirs

Enhanced oil production can maximise yield from depleted reservoirs, and in the face of dwindling global oil reserves can reduce the need for exploratory drilling during the transition away from fossil fuels. A hybrid technique, merging a magnetic field (MF) and magnesium oxide (MgO) nanoparticles (NPs), was investigated as a potential method of enhancing oil production from oil-wet carbonate reservoirs. The impact of this hybrid technique on rock wettability, zeta potential, and interfacial tension was also investigated. Displacement experiments were carried out on oil-wet Austin chalk – a laboratory carbonate rock analogue – using MgO NPs in deionized water (DW) and salt water (SW), in the presence of an MF up to 6000 G in strength. It was found that the addition of MgO NPs to DW before the spontaneous imbibition of the solution into initially oil-wet rock samples increased the recovery factor (RF, defined as the volume of oil recovered divided by the initial oil in place). For 0.005 wt% and 0.0025 wt% MgO NPs mixed in DW, the RF was 12.5% and 15.9% respectively. When DW was replaced with SW as the imbibing fluid, the RF increased by a further 0.7% of initial oil in place for the 0.0025 wt% MgO NPs. This additional increase in oil recovery was attributed to the presence of potential determining ions, which made the rock more water-wet. To avoid pore-clogging and thus the limited ingress of the solution into the rock, the NPs’ concentration was kept low. This hybrid technique is a cleaner alternative to conventional enhanced oil recovery techniques and will enable oil industries to produce oil more efficiently from existing reservoirs: when used in conjunction with Carbon Capture and Storage (CCS), this provides a useful short to medium-term option to support energy production during the transition to net zero.     

Study of a Double Cross-Linked HPAM Gel for in-Depth Profile Control

The concept of profile control is one of the most important strategies to enhance oil recovery in a high water production field, with polymer gels being used as a gelant matrix in various reservoirs around the globe. In an effort to reach a suitable profile control, previous attempts lead to an increase of polymer concentration, resulting in a poor injection and insufficient in-depth profile control. The work presented here introduces a novel gel system, using both key functional groups on HPAM to react with two types of cross-linking agents. Different formulations and the properties of this double cross-linked HPAM gel system have been studied. The experimental results indicate that the studied double cross-linked HPAM gel system exhibits a higher gel strength, an improved salt and shear resistance as well as an improved plugging effect compared to a single cross-linked HPAM gel system. Moreover, as a result of higher gel strength, the double cross-linked HPAM gel system also shows a longer gelation time, a parameter particularly useful for in-depth profile control. The gel microstructures have been evaluated, with the double cross-linked HPAM gel exhibiting a molecular structure that is more compact. The latter is a clear indication for the improved properties of the system as will be detailed in subsequent sections.     

Effects of CO2 Injection on Phase Behavior of Crude Oil

CO₂ flooding is a win-win technology, sequestrating greenhouse CO₂ while producing a significant amount of crude oil to help defray the cost of CO₂ sequestrating and enhancing oil recovery. However, due to the difference of sedimentary environment and poor properties of formations, physical properties of the crude oil and the effect of CO₂ flooding are not always satisfactory in most oilfields of China. Therefore, in this article, to improve the understanding of the oil recovery mechanisms and feasibility of CO₂ flooding in China, based on the oil and gas of Mao-3 oilfields, phase behavior of the CO₂ and crude oil system was investigated. Parameters like saturated pressure, volume factor, gas oil ratio, and viscosity were measured and their relationships analyzed. Results show that crude oil of Mao-3 reservoir and CO₂ has good mutual dissolution under reservoir conditions, and CO₂ could expand the oil and reduce the oil viscosity greatly. As a result, formation energy could be enhanced and flow characteristics of the oil could be improved by CO₂ flooding.     

Application potential of in situ emulsion flooding in the high-temperature and high-salinity reservoir

In this research, an emulsifier formulation named SC-18 for W/O system was screened out and evaluated for feasible application of in-situ emulsion flooding in high-temperature and high-salinity reservoir. Results showed that SC-18 could reduce interfacial tension to 10–2 order of magnitude and change rock wettability from oil-wet to water-wet, which was beneficial to decrease residual oil saturation and improve displacement efficiency. Meanwhile, rheological testing showed that emulsion produced by SC-18 exhibited good temperature tolerance and mechanical stability, which favored mobility control and sweep efficiency enhancement under harsh conditions. In addition, good viscoelasticity of produced emulsions could also improve sweep efficiency by strengthening plugging and diverting effects of emulsion droplets, namely enhancing “Jiamin effects.” By means of natural core flooding and visualized plate model, it was proved that in-situ emulsion flooding with SC-18 could improve both displacement efficiency and sweep efficiency for high-temperature and high-salinity reservoir.