Determination of Increase in Pressure Drop and Oil Recovery Associated with Alkaline Flooding for Heavy Oil Reservoirs

2009 ◽  
Author(s):  
M. Arhuoma ◽  
D. Yang ◽  
M. Dong ◽  
R. Idem
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs

scholarly journals Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Polymers ◽  
2018 ◽  
Vol 10 (11) ◽  
pp. 1225 ◽  
Author(s):  
Xiankang Xin ◽  
Gaoming Yu ◽  
Zhangxin Chen ◽  
Keliu Wu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
Porous Media ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flow Behavior ◽  
Polymer Flooding ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Newtonian Flow ◽  
Heavy Oil Reservoirs

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

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.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

Microorganisms of low-temperature heavy oil reservoirs (Russia) and their possible application for enhanced oil recovery

Microbiology ◽  
2017 ◽  
Vol 86 (6) ◽  
pp. 773-785 ◽  
Author(s):  
T. N. Nazina ◽  
D. Sh. Sokolova ◽  
T. L. Babich ◽  
E. M. Semenova ◽  
A. P. Ershov ◽  
...  
Keyword(s):  
Low Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs

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.

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