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 Mechanism of Enhanced Oil Recovery for In-Depth Profile Control and Cyclic Waterflooding in Fractured Low-Permeability Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Daiyin Yin ◽  
Wei Zhou
Keyword(s):  
Enhanced Oil Recovery ◽  
Depth Profile ◽  
Oil Recovery ◽  
Water Injection ◽  
High Water ◽  
Low Permeability ◽  
Profile Control ◽  
High Water Cut ◽  
Water Cut ◽  
Low Permeability Reservoirs

When fractured low-permeability reservoirs enter a high water cut period, injected water always flows along fractures, water cut speeds increase rapidly, and oil production decreases quickly in oil wells. It is difficult to further improve the oil recovery of such fractured low-permeability reservoirs. In this paper, based on the advantages of in-depth profile control and cyclic water injection, the feasibility of combining deep profile control with cyclic water injection to improve oil recovery in fractured low-permeability reservoirs during the high water cut stage was studied, and the mechanisms of in-depth profile control and cyclic waterflooding were investigated. According to the characteristics of reservoirs in Zone X, as well as the fracture features and evolution mechanisms of the well network, an outcrop plate fractured core model that considers fracture direction was developed, and core displacement experiments were carried out by using the HPAM/Cr3+ gel in-depth profile control system. The enhanced oil recovery of waterflooding, cyclic water injection, and in-depth profile control, as well as a combination of in-depth profile control and cyclic water injection, was investigated. Moreover, variations in the water cut degree, reserve recovery percentage, injection pressure, fracture and matrix pressure, and water saturation were monitored. On this basis, the mechanism of enhanced oil recovery based on the combined utilization of in-depth profile control and cyclic waterflooding methods was analyzed. The results show that in-depth profile control and cyclic water injection can be synchronized to further increase oil recovery. The recovery ratio under the combination of in-depth profile control and cyclic water injection was 1.9% higher than that under the in-depth profile control and 5.6% higher than that under cyclic water injection. The combination of in-depth profile control and cyclic water injection can increase the reservoir pressure; therefore, the fluctuation of pressure between the matrix and its fractures increases, more crude oil flows into the fracture, and the oil production increases.

scholarly journals Low-tension gas process in high-salinity and low-permeability reservoirs

2020 ◽  
Vol 17 (5) ◽  
pp. 1329-1344
Author(s):  
Alolika Das ◽  
Nhut Nguyen ◽  
Quoc P. Nguyen
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Oxidative Degradation ◽  
Qualitative Assessment ◽  
Low Permeability ◽  
Displacement Efficiency ◽  
Fractional Flow ◽  
Hydrocarbon Gases ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

scholarly journals Enhanced Oil Recovery by a Suspension of Core-Shell Polymeric Nanoparticles in Heterogeneous Low-Permeability Oil Reservoirs

Nanomaterials ◽  
2019 ◽  
Vol 9 (4) ◽  
pp. 600 ◽  
Author(s):  
Long ◽  
Wang ◽  
Zhu ◽  
Huang ◽  
Leng ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Newtonian Fluid ◽  
Oil Recovery ◽  
Polymeric Nanoparticles ◽  
Low Permeability ◽  
High Permeability ◽  
Permeability Ratio ◽  
Nanoparticle Suspension ◽  
Shear Rates ◽  
Low Permeability Reservoirs

Polymeric nanoparticle suspension is a newly developed oil-displacing agent for enhanced oil recovery (EOR) in low-permeability reservoirs. In this work, SiO2/P(MBAAm-co-AM) polymeric nanoparticles were successfully synthesized by a simple distillation–precipitation polymerization method. Due to the introduction of polymer, the SiO2/P(MBAAm-co-AM) nanoparticles show a favorable swelling performance in aqueous solution, and their particle sizes increase from 631 to 1258 nm as the swelling times increase from 24 to 120 h. The apparent viscosity of SiO2/P(MBAAm-co-AM) suspension increases with an increase of mass concentration and swelling time, whereas it decreases as the salinity and temperature increase. The SiO2/P(MBAAm-co-AM) suspension behaves like a non-Newtonian fluid at lower shear rates, yet like a Newtonian fluid at shear rates greater than 300 s−1. The EOR tests of the SiO2/P(MBAAm-co-AM) suspension in heterogeneous, low-permeability cores show that SiO2/P(MBAAm-co-AM) nanoparticles can effectively improve the sweep efficiency and recover more residual oils. A high permeability ratio can result in a high incremental oil recovery in parallel cores. With an increase of the permeability ratio of parallel cores from 1.40 to 15.49, the ratios of incremental oil recoveries (low permeability/high permeability) change from 7.69/4.61 to 23.61/8.46. This work demonstrates that this SiO2/P(MBAAm-co-AM) suspension is an excellent conformance control agent for EOR in heterogeneous, low-permeability reservoirs. The findings of this study can help to further the understanding of the mechanisms of EOR using SiO2/P(MBAAm-co-AM) suspension in heterogeneous, low-permeability 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.

Smart mobility control agent for enhanced oil recovery during CO2 flooding in ultra-low permeability reservoirs

Fuel ◽  
2019 ◽  
Vol 241 ◽  
pp. 442-450 ◽  
Author(s):  
Yan Zhang ◽  
Mingwei Gao ◽  
Qing You ◽  
Hongfu Fan ◽  
Wenhui Li ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Control Agent ◽  
Mobility Control ◽  
Low Permeability ◽  
Co2 Flooding ◽  
Smart Mobility ◽  
Low Permeability Reservoirs
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