Experimental Investigation of Mechanisms in Functionalized Multiwalled Carbon Nanotube Flooding for Enhancing the Recovery From Heavy-Oil Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2681-2694 ◽  
Author(s):  
Seyed M. Ghalamizade Elyaderani ◽  
Arezou Jafari ◽  
Javad Razavinezhad
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Nanoparticle Concentration ◽  
Sweep Efficiency ◽  
Multiwalled Carbon ◽  
Oil Emulsion ◽  
Static Adsorption ◽  
Mwcnt Concentration ◽  
Before And After ◽  
Water In Oil Emulsion

Summary In the past few years, nanoparticle flooding has displayed significant potential for enhancing oil recovery. Among different nanoparticles, hydrophilic (functionalized) nanotubes have not been tested yet. Therefore, in this study, functionalized multiwalled carbon nanotubes (MWCNT) were used in three concentrations—0.01, 0.05, and 0.1 wt%—to conduct micromodel, interfacial–tension (IFT), wettability, viscosity, phase–behavior, and static–adsorption tests. In addition, constancy of nanofluids in the presence of sodium chloride (NaCl) was investigated qualitatively. Obtained results illustrated that by increasing the nanoparticle concentration from 0.01 to 0.1 wt%, nanofluid/oil IFT decreased, because MWCNT were placed between the surfaces of the oil and the nanofluid. Also, viscosity of the nanofluid improved slightly when the nanoparticle concentration increased. Moreover, contact angle was measured before and after coating with nanosuspensions, and the achieved data showed a change from oil–wet to water–wet. The resulting emulsion was a water–in–oil type; therefore, as MWCNT concentration increased, the size and number of water droplets in the oil also increased. This augmentation improved the effectiveness of the emulsion viscosity. Stability tests also provided evidence confirming that the nanofluids were stable for 10 days in concentrations of 0.01 and 0.1 wt% and in salinities of 1 and 0.5 wt%, respectively. Besides, the addition of 0.05 wt% sulfonated polymer to the nanofluids ensured their stability in higher salinities. Moreover, the results of the micromodel test revealed that by increasing the concentration of nanoparticles, sweep efficiency increased and the fingering phenomenon was reduced. In addition, the ultimate recovery of oil obtained by nanosuspension flooding in concentrations of 0.01, 0.05, and 0.1 wt% was, respectively, 12.6, 16.4, and 20% higher than that of waterflooding. Static adsorption on sandstone was found to be 0.575, 1.25, and 1.76 mg/m2 at 0.01, 0.05, and 0.1 wt%, respectively, and it reached its fixed amounts within 24 hours. Therefore, functionalized MWCNT might help increase heavy–oil recovery through mechanisms of reducing IFT, changing wettability from oil–wet to water–wet in oil–wet reservoirs, increasing viscosity (slightly), and developing a water–in–oil emulsion.

Pore-Scale Transport Mechanisms and Macroscopic Displacement Effects of In-Situ Oil-in-Water Emulsions in Porous Media

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Chuan Lu ◽  
Wei Zhao ◽  
Yongge Liu ◽  
Xiaohu Dong
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Mobility Control ◽  
Pore Scale ◽  
Sweep Efficiency ◽  
Emulsion Droplets ◽  
Oil In Water ◽  
Retention Volumes

Oil-in-water (O/W) emulsions are expected to be formed in the process of surfactant flooding for heavy oil reservoirs in order to strengthen the fluidity of heavy oil and enhance oil recovery. However, there is still a lack of detailed understanding of mechanisms and effects involved in the flow of O/W emulsions in porous media. In this study, a pore-scale transparent model packed with glass beads was first used to investigate the transport and retention mechanisms of in situ generated O/W emulsions. Then, a double-sandpack model with different permeabilities was used to further study the effect of in situ formed O/W emulsions on the improvement of sweep efficiency and oil recovery. The pore-scale visualization experiment presented an in situ emulsification process. The in situ formed O/W emulsions could absorb to the surface of pore-throats, and plug pore-throats through mechanisms of capture-plugging (by a single emulsion droplet) and superposition-plugging or annulus-plugging (by multiple emulsion droplets). The double-sandpack experiments proved that the in situ formed O/W emulsion droplets were beneficial for the mobility control in the high permeability sandpack and the oil recovery enhancement in the low permeability sandpack. The size distribution of the produced emulsions proved that larger pressures were capable to displace larger O/W emulsion droplets out of the pore-throat and reduce their retention volumes.

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.

Effect of pressure variation on polymer flooding

2021 ◽  
Author(s):  
Ahmad Ali Manzoor
Keyword(s):  
Polymer Solution ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Constant Pressure ◽  
Maximum Pressure ◽  
Core Flooding ◽  
Sweep Efficiency ◽  
Black Oil Model ◽  
Original Oil In Place

Chemical-based enhanced oil recovery (EOR) techniques utilize the injection of chemicals, such as solutions of polymers, alkali, and surfactants, into oil reservoirs for incremental recovery. The injection of a polymer increases the viscosity of the injected fluid and alters the water-to-oil mobility ratio which in turn improves the volumetric sweep efficiency. This research study aims to investigate strategies that would help intensify oil recovery with the polymer solution injection. For that purpose, we utilize a lab-scale, cylindrical heavy oil reservoir model. Furthermore, a dynamic mathematical black oil model is developed based on cylindrical physical model of homogeneous porous medium. The experiments are carried out by injecting classic and novel partially hydrolyzed polyacrylamide solutions (concentration: 0.1-0.5 wt %) with 1 wt % brine into the reservoir at pressures in the range, 1.03-3.44 MPa for enhanced oil recovery. The concentration of the polymer solution remains constant throughout the core flooding experiment and is varied for other subsequent experimental setup. Periodic pressure variations between 2.41 and 3.44 MPa during injection are found to increase the heavy oil recovery by 80% original-oil-in-place (OOIP). This improvement is approximately 100% more than that with constant pressure injection at the maximum pressure of 3.44 MPa. The experimental oil recoveries are in fair agreement with the model calculated oil production with a RMS% error in the range of 5-10% at a maximum constant pressure of 3.44 MPa.

Investigation into the properties of water-in-heavy oil emulsion and its role in enhanced oil recovery during water flooding

2019 ◽  
Vol 177 ◽  
pp. 798-807 ◽  
Author(s):  
Shishi Pang ◽  
Wanfen Pu ◽  
Jianyong Xie ◽  
Yanjie Chu ◽  
Chongyang Wang ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Water Flooding ◽  
Oil Emulsion

An Investigation Into Propagation Behavior of the Steam Chamber During Expanding-Solvent SAGP (ES-SAGP)

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 413-430
Author(s):  
Zhanxi Pang ◽  
Lei Wang ◽  
Zhengbin Wu ◽  
Xue Wang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Heat Losses ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Steam Chamber ◽  
Heavy Oil Reservoirs

Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.

Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Yang Zhao ◽  
Shize Yin ◽  
Randall S. Seright ◽  
Samson Ning ◽  
Yin Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Salinity ◽  
Polymer Flooding ◽  
Heavy Oil Recovery ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Increased Oil Recovery

Summary Combining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.

scholarly journals A Multicomponent Thermal Fluid Numerical Simulation Method considering Formation Damage

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Xinan Yu ◽  
Xiaoping Li ◽  
Shuoliang Wang ◽  
Yi Luo
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Damage Model ◽  
Simulation Method ◽  
Formation Damage ◽  
Thermal Fluids ◽  
Before And After ◽  
Control Equation

Multicomponent thermal fluid huff and puff is an innovative heavy oil development technology for heavy oil reservoirs, which has been widely used in offshore oilfields in China and has proved to be a promising method for enhancing oil recovery. Components of multicomponent thermal fluids contain many components, including carbon dioxide, nitrogen, and steam. Under high temperature and high pressure conditions, the complex physical and chemical reactions between multicomponent thermal fluids and reservoir rocks occur, which damage the pore structure and permeability of core. In this paper, the authors set up a reservoir damage experimental device, tested the formation permeability before and after the injection of multiple-component thermal fluids, and obtained the formation damage model. The multicomponent thermal fluid formation damage model is embedded in the component control equation, the finite difference method is used to discretize the control equation, and a new multielement thermal fluid numerical simulator is established. The physical simulation experiment of multicomponent thermal fluid huff and puff is carried out by using the actual sand-packed model. By comparing the experimental results with the numerical simulation results, it is proved that the new numerical simulation model considering formation damage proposed in this paper is accurate and reliable.

scholarly journals CO2 Foam and CO2 Polymer Enhanced Foam for Heavy Oil Recovery and CO2 Storage

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5735
Author(s):  
Ali Telmadarreie ◽  
Japan J Trivedi
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Co2 Storage ◽  
High Mobility ◽  
Pressure Profile ◽  
Gas Production ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Co2 Foam

Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. High oil viscosity, high mobility ratio, inadequate sweep, and reservoir heterogeneity adds more challenges and severe difficulties during any EOR method. Foam injection showed potential as an EOR method for challenging and heterogeneous reservoirs containing light oil. However, the foams and especially polymer enhanced foams (PEF) for heavy oil recovery have been less studied. This study aims to evaluate the performance of CO2 foam and CO2 PEF for heavy oil recovery and CO2 storage by analyzing flow through porous media pressure profile, oil recovery, and CO2 gas production. Foam bulk stability tests showed higher stability of PEF compared to that of surfactant-based foam both in the absence and presence of heavy crude oil. The addition of polymer to surfactant-based foam significantly improved its dynamic stability during foam flow experiments. CO2 PEF propagated faster with higher apparent viscosity and resulted in more oil recovery compared to that of CO2 foam injection. The visual observation of glass column demonstrated stable frontal displacement and higher sweep efficiency of PEF compared to that of conventional foam. In the fractured rock sample, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion. Aside from oil production, the higher stability of PEF resulted in more gas storage compared to conventional foam. This study shows that CO2 PEF could significantly improve heavy oil recovery and CO2 storage.

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