Modeling the Effects of Salinity, Polymer Rheology, Temperature, and Reservoir Wettability on the Performance of In-Depth Gel Treatment Coupled with Surfactant and Polymer Flooding

2018 ◽  
Author(s):  
Tariq K. Khamees ◽  
Ralph E. Flori ◽  
Ahmed A. Alsubaih ◽  
Ali K. Alhuraishawy
Keyword(s):  
Polymer Flooding ◽  
Polymer Rheology ◽  
Gel Treatment ◽  
Reservoir Wettability

The Effects of Wettability on Gel Performance in Layered Heterogeneous Reservoirs

2013 ◽  
Vol 448-453 ◽  
pp. 4028-4032 ◽  
Author(s):  
Guang Xi Shen ◽  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Produced Water ◽  
Water Production ◽  
Substantial Cost ◽  
Heterogeneous Reservoirs ◽  
Reservoir Performance ◽  
Water Breakthrough ◽  
Gel Treatment ◽  
Reservoir Wettability

Regarding the application of enhanced oil recovery (EOR), reservoir heterogeneity leads to early water breakthrough and significant water production, so that substantial cost may be needed to treat the produced water. Gel treatments have been widely used to prevent early water breakthrough and great amount of water production by the modification of permeability. Reservoir wettability gives significant impact on gel treatment. This study is to assess the effect of wettability on the reservoir performance during gel treatment in layered heterogeneous reservoirs. Performances were compared in terms of water-oil ratio and cumulative oil recovery for different wettability conditions. With respect to oil recovery, there is no striking improvement by gel treatment. However, the results indicate that gel process presents 77% decrement of water-oil ratio over waterflood for oil-wet system and 51% for water-wet system. Gel is distributed in reservoir more widely for oil-wet conditions than water-wet conditions, which means the effect of gels is more dominant in oil-wet conditions rather than water-wet conditions.

Impact of Rheology Models on Horizontal Well Polymer Flooding in a Heavy Oil Reservoir on Alaska North Slope: A Simulation Study

2021 ◽  
Author(s):  
Jianqiao Leng ◽  
Mingzhen Wei ◽  
Baojun Bai ◽  
Randall S. Seright ◽  
Yin Zhang ◽  
...  
Keyword(s):  
Bulk Viscosity ◽  
Simulation Study ◽  
Heavy Oil ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Polymer Flooding ◽  
North Slope ◽  
Oil Reservoir ◽  
Polymer Rheology ◽  
Heavy Oil Reservoir

Abstract Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot testconditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.

Mechanistic Simulation of Polymer Injectivity in Field Tests

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1178-1191 ◽  
Author(s):  
Mohammad Lotfollahi ◽  
Rouhi Farajzadeh ◽  
Mojdeh Delshad ◽  
Al-Khalil Al-Abri ◽  
Bart M. Wassing ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pressure Rise ◽  
Shear Thickening ◽  
Injection Rate ◽  
Field Application ◽  
Polymer Flooding ◽  
Velocity Shear ◽  
Polymer Rheology ◽  
Deep Bed Filtration ◽  
The Impact

Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

LARGE-SCALE SIMULATION OF OIL RECOVERY BY SURFACTANT-POLYMER FLOODING

2016 ◽  
Vol 4 (1) ◽  
pp. 12-31 ◽  
Author(s):  
D.Zh. Akhmed-Zaki ◽  
T.S. Imankulov ◽  
B. Matkerim ◽  
B.S. Daribayev ◽  
K.A. Aidarov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Polymer Flooding ◽  
Large Scale Simulation
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