scholarly journals Profile Control Using Fly Ash Three-Phase Foam Assisted by Microspheres with an Adhesive Coating

2021 ◽  
Vol 11 (8) ◽  
pp. 3616
Author(s):  
Yulong Yang ◽  
Tingting Cheng ◽  
Zhenjiang You ◽  
Tuo Liang ◽  
Jirui Hou
Keyword(s):  
Fly Ash ◽  
High Temperatures ◽  
Oil Recovery ◽  
Foam Stability ◽  
Solid Particles ◽  
Sweep Efficiency ◽  
Steam Flooding ◽  
Three Phase ◽  
Profile Control ◽  
Adhesive Coating

Foam-assisted steam flooding is a promising technique to alleviate gas channeling and enhance sweep efficiency in heterogeneous heavy-oil reservoirs. However, long-term foam stabilization remains problematic at high temperatures. Three-phase foam (TPF), containing dispersed solid particles, has been proposed to improve foam stability under harsh reservoir conditions. We fabricated a novel TPF system by adding ultrafine fly ash particles, as well as high-temperature resistant microspheres with an adhesive coating layer. This work aims at assessing the ability of the generated TPF in controlling steam channeling and enhancing oil recovery. Static and core flood tests were performed to evaluate foam strength and stability. Our results suggested a stronger foamability at a lower consolidation agent concentration, while a longer half-life period of foam and settling time of solid particles at a larger consolidation agent concentration were observed. Bubbles suspended independently in the liquid phase, with sizes varying from 10 to 100 μm, smaller than that of the conventional foam, suggesting a significant enhancement of foam dispersity and stability. The plugging rate was close to 90% when the temperature was as high as 300 °C, demonstrating a well-accepted plugging effect under high temperatures. A larger pore volume injection of TPF yielded a higher EOR in parallel cores, which substantiated the effectiveness of the three-phase foam system in sealing high-permeability channels.

scholarly journals Study on three phase foam for Enhanced Oil Recovery in extra-low permeability reservoirs

2018 ◽  
Vol 73 ◽  
pp. 55 ◽  
Author(s):  
Ming Zhou ◽  
Juncheng Bu ◽  
Jie Wang ◽  
Xiao Guo ◽  
Jie Huang ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Foam Stability ◽  
Temperature Tolerance ◽  
Resistance Coefficient ◽  
Low Permeability ◽  
Displacement Efficiency ◽  
Three Phase ◽  
Profile Control ◽  
Low Permeability Reservoirs

Poly (MSt-MMA) nanosphere as foam stabilizing agent was synthesized by emulsion polymerization. The three phase foam was prepared with Disodium 4-Dodecyl-2,4′-Oxydiben Zenesulfonate (DOZS) as foaming agent, Hydrolyzed Polyacrylamide (HPAM) and synthesized poly (MSt-MMA) nanospheres as the mixed foam stabilizing agents. It had outstanding foaming performance and foam stability. The optimal three phase foam system consisting of 0.12 wt% HPAM, 0.04 wt% poly (MSt-MMA) nanospheres and 0.12 wt% DOZS by orthogonal experiment, had high apparent viscosity, which showed that three components had a very good synergistic effect. The three phase foam’s temperature tolerance and salt tolerance were researched in laboratory tests. Flooding oil experiment showed that the average displacement efficiency of three phase foam system was 16.1 wt% in single core experiments and 21.7 wt% in double core experiments. Resistance coefficient of low permeability core was more than those of high permeability core, but their residual resistance coefficients were small. The results of core experiment and pilot test indicated that the three phase foam had good profile control ability and generated low damage to the low permeability layer for extra-low permeability reservoirs. Three phase foam flooding has great prospects for Enhanced Oil Recovery (EOR) in extra-low permeability reservoirs.

scholarly journals Nuclear Magnetic Resonance Evaluation Study for Effect of Foam flooding in Heterogeneous Cores

2020 ◽  
Vol 213 ◽  
pp. 01025
Author(s):  
Shuai Hua ◽  
Yuan Li ◽  
Qinfeng Di
Keyword(s):  
Oil Recovery ◽  
Foam Stability ◽  
Dynamic Change ◽  
Water Flooding ◽  
Sweep Efficiency ◽  
Displacement Effect ◽  
Oil Displacement ◽  
Profile Control ◽  
Foam Flooding ◽  
Heterogeneous Cores

Foam flooding demonstrated the ability to solve the viscous fingering problem of gas flooding and increase the sweep efficiency in enhancing oil recovery. It is commonly used in development of heterogeneous reservoirs. While the characteristics of fluid migration in pores and between layers were still unclear. In this paper, Dynamic change of oil and water with different foam quality was tested during foam flooding by NMR method. Oil displacement effect of water flooding and foam flooding was compared. The results showed the foam quality affected the foam stability and profile control effect. Compared with water flooding, the foam could increase the recovery rate of the low-permeability layer, and the foam system with high stability had a high sweep efficiency and a high oil displacement efficiency in the heterogeneous cores.

scholarly journals Investigation on the effect of active-polymers with different functional groups for EOR

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 61-68
Author(s):  
Dong Zhang ◽  
Jian Guang Wei ◽  
Run Nan Zhou
Keyword(s):  
Functional Groups ◽  
Oil Recovery ◽  
Molecular Size ◽  
Type I ◽  
Cleaning Efficiency ◽  
Sweep Efficiency ◽  
Profile Control ◽  
Branched Chain ◽  
Swept Volume ◽  
Enhance Oil Recovery

AbstractActive-polymer attracted increasing interest as an enhancing oil recovery technology in oilfield development owing to the characteristics of polymer and surfactant. Different types of active functional groups, which grafted on the polymer branched chain, have different effects on the oil displacement performance of the active-polymers. In this article, the determination of molecular size and viscosity of active-polymers were characterized by Scatterer and Rheometer to detect the expanded swept volume ability. And the Leica microscope was used to evaluate the emulsifying property of the active-polymers, which confirmed the oil sweep efficiency. Results show that the Type I active-polymer have a greater molecular size and stronger viscosity, which is a profile control system for expanding the swept volume. The emulsification performance of Type III active-polymer is more stable, which is suitable for improving the oil cleaning efficiency. The results obtained in this paper reveal the application prospect of the active-polymer to enhance oil recovery in the development of oilfields.

The Experimental Analysis of the Role of Flue Gas Injection for Horizontal Well Steam Flooding

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Zhanxi Pang ◽  
Peng Qi ◽  
Fengyi Zhang ◽  
Taotao Ge ◽  
Huiqing Liu
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Three Dimensional ◽  
Steam Injection ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Steam Flooding ◽  
Heavy Oil Reservoirs

Heavy oil is an important hydrocarbon resource that plays a great role in petroleum supply for the world. Co-injection of steam and flue gas can be used to develop deep heavy oil reservoirs. In this paper, a series of gas dissolution experiments were implemented to analyze the properties variation of heavy oil. Then, sand-pack flooding experiments were carried out to optimize injection temperature and injection volume of this mixture. Finally, three-dimensional (3D) flooding experiments were completed to analyze the sweep efficiency and the oil recovery factor of flue gas + steam flooding. The role in enhanced oil recovery (EOR) mechanisms was summarized according to the experimental results. The results show that the dissolution of flue gas in heavy oil can largely reduce oil viscosity and its displacement efficiency is obviously higher than conventional steam injection. Flue gas gradually gathers at the top to displace remaining oil and to decrease heat loss of the reservoir top. The ultimate recovery is 49.49% that is 7.95% higher than steam flooding.

A New High-Temperature Gel for Profile Control in Heavy Oil Reservoirs

2015 ◽  
Vol 138 (2) ◽  
Author(s):  
Changjiu Wang ◽  
Huiqing Liu ◽  
Qiang Zheng ◽  
Yongge Liu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Three Dimensional ◽  
Heat Stability ◽  
Steam Injection ◽  
Oil Reservoirs ◽  
Steam Flooding ◽  
Profile Control ◽  
Heavy Oil Reservoirs

Controlling the phenomenon of steam channeling is a major challenge in enhancing oil recovery of heavy oil reservoirs developed by steam injection, and the profile control with gel is an effective method to solve this problem. The use of conventional gel in water flooding reservoirs also has poor heat stability, so this paper proposes a new high-temperature gel (HTG) plugging agent on the basis of a laboratory experimental investigation. The HTG is prepared with nonionic filler and unsaturated amide monomer (AM) by graft polymerization and crosslinking, and the optimal gel formula, which has strong gelling strength and controllable gelation time, is obtained by the optimization of the concentration of main agent, AM/FT ratio, crosslinker, and initiator. To test the adaptability of the new HTG to heavy oil reservoirs and the performance of plugging steam channeling path and enhancing oil recovery, performance evaluation experiments and three-dimensional steam flooding and gel profile control experiments are conducted. The performance evaluation experiments indicate that the HTG has strong salt resistance and heat stability and still maintains strong gelling strength after 72 hrs at 200 °C. The singular sand-pack flooding experiments suggest that the HTG has good injectability, which can ensure the on-site construction safety. Moreover, the HTG has a high plugging pressure and washing out resistance to the high-temperature steam after gel forming and keeps the plugging ratio above 99.8% when the following steam injected volume reaches 10 PV after gel breakthrough. The three-dimensional steam flooding and gel profile control experiments results show that the HTG has good plugging performance in the steam channeling path and effectively controls its expanding. This forces the following steam, which is the steam injected after the gelling of HTG in the model, to flow through the steam unswept area, which improves the steam injection profile. During the gel profile control period, the cumulative oil production increases by 294.4 ml and the oil recovery is enhanced by 8.4%. Thus, this new HTG has a good effect in improving the steam injection profile and enhancing oil recovery and can be used to control the steam channeling in heavy oil reservoirs.

scholarly journals Enhanced oil recovery ability of branched preformed particle gel in heterogeneous reservoirs

2018 ◽  
Vol 73 ◽  
pp. 65 ◽  
Author(s):  
Long Yu ◽  
Qian Sang ◽  
Mingzhe Dong
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Low Permeability ◽  
High Permeability ◽  
Sweep Efficiency ◽  
Reservoir Heterogeneity ◽  
Heterogeneous Reservoirs ◽  
Preformed Particle Gel ◽  
Profile Control

Reservoir heterogeneity is the main cause of high water production and low oil recovery in oilfields. Extreme heterogeneity results in a serious fingering phenomenon of the displacing fluid in high permeability channels. To enhance total oil recovery, the selective plugging of high permeability zones and the resulting improvement of sweep efficiency of the displacing fluids in low permeability areas are important. Recently, a Branched Preformed Particle Gel (B-PPG) was developed to improve reservoir heterogeneity and enhance oil recovery. In this work, conformance control performance and Enhanced Oil Recovery (EOR) ability of B-PPG in heterogeneous reservoirs were systematically investigated, using heterogeneous dual sandpack flooding experiments. The results show that B-PPG can effectively plug the high permeability sandpacks and cause displacing fluid to divert to the low permeability sandpacks. The water injection profile could be significantly improved by B-PPG treatment. B-PPG exhibits good performance in profile control when the high/low permeability ratio of the heterogeneous dual sandpacks is less than 7 and the injected B-PPG slug size is between 0.25 and 1.0 PV. The oil recovery increment enhanced by B-PPG after initial water flooding increases with the increase in temperature, sandpack heterogeneity and injected B-PPG slug size, and it decreases slightly with the increase of simulated formation brine salinity. Choosing an appropriate B-PPG concentration is important for B-PPG treatments in oilfield applications. B-PPG is an efficient flow diversion agent, it can significantly increase sweep efficiency of displacing fluid in low permeability areas, which is beneficial to enhanced oil recovery in heterogeneous reservoirs.

Very High Temperatures Steam Foam Additives

2021 ◽  
Author(s):  
Céleste Odier ◽  
Margaux Kerdraon ◽  
Emie Lacombe ◽  
Eric Delamaide
Keyword(s):  
High Temperature ◽  
Ambient Temperature ◽  
Oil Recovery ◽  
Foam Stability ◽  
Steam Injection ◽  
Field Application ◽  
High Pressure Cell ◽  
Sweep Efficiency ◽  
Foaming Agents ◽  
Very High

Abstract In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found. In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature. Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C. Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application. In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature. To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.

Carbon Dioxide (CO2) Foam Stability Dependence on Nanoparticle Concentration for Enhanced Oil Recovery (EOR)

2014 ◽  
Vol 548-549 ◽  
pp. 1876-1880 ◽  
Author(s):  
T.A.T. Mohd ◽  
A. H. M. Muhayyidin ◽  
Nurul Aimi Ghazali ◽  
M.Z. Shahruddin ◽  
N. Alias ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Foam Stability ◽  
Foam Height ◽  
Sweep Efficiency ◽  
Low Viscosity ◽  
Reservoir Conditions ◽  
Foam Properties ◽  
Foam Generator ◽  
Foam Flooding

Foam flooding is an established approach in Enhanced Oil Recovery (EOR) to recover a significant quantity of the residual oil left in the reservoir after primary and secondary recovery. However, foam flooding faces various problems due to low viscosity effect, which reduces its efficiency in recovering oil. Using surfactant to stabilize CO2foam may reduce mobility and improve areal and vertical sweep efficiency, but the potential weaknesses are such that high surfactant retention in porous media and unstable foam properties under high temperature reservoir conditions. Nanoparticles have higher adhesion energy to the fluid interface, which potentially stabilize longer lasting foams. Thus, this paper is aimed to investigate the CO2foam stability and mobility characteristics at different concentration of nanosilica, brine and surfactant. Foam generator has been used to generate CO2foam and analyze its stability under varying nanosilica concentration from 100 - 5000 ppm, while brine salinity and surfactant concentration ranging from 0 to 2.0 wt% NaCl and 0 – 10000 ppm, respectively. Foam stability was investigated through observation of the foam bubble size and the reduction of foam height inside the observation tube. The mobility was reduced as the concentration of nanosilica increased with the presence of surfactant. After 150 minutes of observation, the generated foam height reduced by 10%. Liquid with the presence of both silica nanoparticles and surfactant generated more stable foam with lower mobility. It can be concluded that the increase in concentration of nanosilica and addition of surfactant provided significant effects on the foam stability and mobility, which could enhance oil recovery.

Advances in Evaluation of Surfactant Performances at High Temperature by Static Foam Tests

2016 ◽  
Vol 1133 ◽  
pp. 634-638 ◽  
Author(s):  
Mudassar Mumtaz ◽  
Isa Mohd Tan ◽  
Muhammad Mushtaq ◽  
Muhammad Sagir
Keyword(s):  
High Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Foam Stability ◽  
Foam Height ◽  
Surfactant Molecule ◽  
Sweep Efficiency ◽  
Endurance Time ◽  
Alpha Olefin ◽  
Designed Experiment

—Foam stability and mobility reduction are the key parameters for foam assisted enhanced oil recovery. The harsh conditions such as high temperature, pressure and salinity present in an oil reservoir tend to destabilise the foam leading to poor sweep efficiency. Screening for the best performing foaming recipes has been performed to ascertain foam stability in the presence and absence of oil. Static foam test has been performed in order to study the foam stability and foam oil interactions at 90°C. Two anionic surfactants, alpha olefin sulphonate (AOS14-16) and methyl ester sulphonate (MES16-18) were mixed with betaine (foam booster) in different proportions to design the formulations. In addition to the ternary formulations, binary formulation involving surfactant and betaine were also evaluated for foam stability. For the study of oil effects on foaming performance of surfactant formulation, n-decane, diesel and Dulang crude oil are used. The recipes were evaluated by static foam tests to note the foam height and endurance time. It was found that the anionic surfactant played a major role in foam stability and the betaine was found less significant. However, the betaine alone was found effective for foaming and was poor for endurance time. While in mixture, the surfactant and betaine were found to interact strongly and a profound synergistic effect was noted. During oil interaction studies, the alkane type oils of low molecular weight become solubilised with surfactant molecule forming an emulsion and hence decimate the foam stability. However, higher alkanes with molecular chain more than ten carbon atoms (decane) stabilised the foam because of low solubilisation efficiency between surfactant and oil to form emulsions. The obtained results of the designed experiment have been analysed and discussed in detail to understand the contribution of individual component as well as their interactions with each other in order to stabilize foams.Keywords—Static Foam, Foam-Oil interactions, AOS, MES, Enhanced Oil Recovery

Visual Flooding Experiment of Hot Water, Steam and Solvent Under SAGD and VAPEX Conditions

2021 ◽  
Author(s):  
Songyan Li ◽  
Rui Han ◽  
Qun Wang ◽  
Xuemei Wei
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Hot Water ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Water Steam ◽  
Solvent Vapor ◽  
Recovery Method ◽  
Steam Flooding

Abstract Steam-assisted gravity drainage (SAGD) is an important method of heavy oil production, and the solvent vapor extraction (VAPEX) process is also an economically feasible, technically reliable, and environmentally friendly in situ heavy oil recovery method. In this paper, a microscopic visual flooding device was used to conduct seven groups of visual flooding experiments, including hot water, steam, liquid solvent and vapor solvent, at different temperatures. It can be directly observed that the residual oil in the hot water swept area is generally distributed in “spots”, “strips” and “clusters” of varying sizes. The residual oil after steam flooding generally has a “cluster” distribution, the residual oil after liquid solvent flooding has a “film” distribution, and there is only a little “spot” residual oil distributed after solvent vapor flooding. Additionally, we found that the sweep efficiency and displacement efficiency of hot water, steam and solvent increase with increasing temperature, and the sweep efficiency of hot water is higher than that of steam and liquid solvent. Vapor solvent has the greatest recovery factor, reaching approximately 90%. The experimental results hint at the future development trend of solvent injection and support the foundation of more general applications pertaining to the sustainable production of unconventional petroleum resources.

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