Chemical Flooding in Western Canada – Successes and Operational Challenges

2021 ◽  
Author(s):  
G. Renouf ◽  
G. Bolton ◽  
P. Nakutnyy
Keyword(s):  
Water Quality ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Chemical Recovery ◽  
Operating Parameters ◽  
Western Canada ◽  
Chemical Flooding ◽  
Government Documents ◽  
The Difference ◽  
Incremental Oil Recovery

Abstract Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada. Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods. The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.

Experimental Study of Enhanced-Heavy-Oil Recovery in Berea Sandstone Cores by Use of Nanofluids Applications

2015 ◽  
Vol 18 (03) ◽  
pp. 387-399 ◽  
Author(s):  
Osamah A. Alomair ◽  
Khaled M. Matar ◽  
Yousef H. Alsaeed
Keyword(s):  
Aluminum Oxide ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Silicon Oxide ◽  
Chemical Flooding ◽  
Berea Sandstone ◽  
Asphaltene Precipitation ◽  
Aluminum Oxides ◽  
Optimum Type ◽  
Incremental Oil Recovery

Summary The application of nanotechnology in the oil industry has become a useful approach in oil production. The main objective of this study is to investigate the effect of nanofluids on the recovery of heavy crude oil compared with waterflooding. The nanofluids are prepared by the addition of pure and mixed nanoparticles—silicon oxide, aluminum oxide, nickel oxide, and titanium oxide—at different concentrations to the formation water. The prepared nanofluids were screened to determine the suitable type for the heavy oil and rock samples subjected to the study. The effect of nanofluids on the interfacial tension and viscosity of emulsion were also investigated. Nanofluid-flooding tests were performed on a heavy-oil sample of 17.45 °API by use of Berea sandstone core samples with average air permeability of 184 md, liquid permeability of 60 md, and porosity of 20%. After selection of the optimum type of nanofluid, additional tests were performed including effect on asphaltene precipitation by use of a flow-assurance system. Results from the experiments show that the aluminum oxide nanofluid at concentration of 0.05 wt% reduced the emulsion viscosity by 25%. The mixed nanofluid of silicon and aluminum oxides at 0.05 wt% has shown the highest incremental oil recovery among the other nanofluids. It is expected to be the best type of chemical flooding because of its performance in reservoir condition (high pressure, temperature, and water salinity) and its capability to oppose asphaltene precipitation.

Non-Edible Oil Based Surfactant For Enhanced Oil Recovery

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Ijoma Onyemaechi
Keyword(s):  
Methyl Ester ◽  
Sodium Hydroxide ◽  
Sodium Carbonate ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Synthetic Surfactant ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Incremental Oil Recovery ◽  
Increasing Demand

Abstract After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.

Modeling of CoSolvent Assisted Chemical Flooding for Enhanced Oil Recovery in Heavy Oil Reservoirs

2018 ◽  
Author(s):  
Cuong Dang ◽  
Long Nghiem ◽  
Ngoc Nguyen ◽  
Chaodong Yang ◽  
Arash Mirzabozorg ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Chemical Flooding ◽  
Heavy Oil Reservoirs

Adaptability Research of Thermal–Chemical Assisted Steam Injection in Heavy Oil Reservoirs

2017 ◽  
Vol 140 (5) ◽  
Author(s):  
Wu Zhengbin ◽  
Liu Huiqing ◽  
Wang Xue
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Saturation ◽  
Steam Injection ◽  
Chemical Flooding ◽  
Displacement Efficiency ◽  
Reservoir Heterogeneity ◽  
Steam Flooding ◽  
Switch Time ◽  
Improvement Effect

Thermal–chemical flooding (TCF) is an effective alternative to enhance heavy oil recovery after steam injection. In this paper, single and parallel sand-pack flooding experiments were carried out to investigate the oil displacement ability of thermal–chemical composed of steam, nitrogen (N2), and viscosity breaker (VB), considering multiple factors such as residual oil saturation (Sorw) postwater flood, scheme switch time, and permeability contrast. The results of single sand-pack experiments indicated that compared with steam flooding (SF), steam-nitrogen flooding, and steam-VB flooding, TCF had the best displacement efficiency, which was 11.7% higher than that of pure SF. The more serious of water-flooded degree, the poorer of TCF effect. The improvement effect of TCF almost lost as water saturation reached 80%. Moreover, the earlier TCF was transferred from steam injection, the higher oil recovery was obtained. The parallel sand-pack experiments suggested that TCF had good adaptability to reservoir heterogeneity. Emulsions generated after thermal–chemical injection diverted the following compound fluid turning to the low-permeable tube (LPT) due to its capturing and blocking ability. The expansion of N2 and the disturbance of VB promoted oil recovery in both tubes. As reservoir heterogeneity became more serious, namely, permeability contrast was more than 6 in this study, the improvement effect became weaker due to earlier steam channeling in the high-permeable tube (HPT).

scholarly journals Visualization of Chemical Heavy Oil EOR Displacement Mechanisms in a 2D System

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 950
Author(s):  
Francy Guerrero ◽  
Jonathan Bryan ◽  
Apostolos Kantzas
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flow Behavior ◽  
Bulk Liquid ◽  
Chemical Flooding ◽  
Sweep Efficiency ◽  
Screening Process ◽  
2D System ◽  
The Impact ◽  
Hele Shaw Cell

This study aims to develop a visual understanding of the macro-displacement mechanisms associated with heavy oil recovery by water and chemical flooding in a 2D system. The sweep efficiency improvements by water, surfactant, polymer, and surfactant-polymer (SP) were evaluated in a Hele-Shaw cell with no local pore-level trapping of fluids. The results demonstrated that displacement performance is highly correlated to the mobility ratio between the fluids. Surfactant and water reached similar oil recovery values at similar mobility ratios; however, they exhibited different flow patterns in the 2D system—reductions in IFT can lead to the formation of emulsions and alter flow pathways, but in the absence of porous media these do not lead to significant improvements in oil recovery. Polymer flooding displayed a more stable front and a higher reduction in viscous fingering. Oil recovery by SP was achieved mostly by polymer rather than due to the effect of the surfactant. The surfactant in the SP slug washed out residual oil in the swept zone without increasing the swept area. This shows the impact of the surfactant on reducing the oil saturation in water-swept zones, but the overall oil recovery was still controlled by the injection of polymer. This study provides insight into the fluid flow behavior in diverging flow paths, as opposed to linear core floods that have limited pathways. The visualization of bulk liquid interactions between different types of injection fluids and oil in the Hele-Shaw cell might assist in the screening process for new chemicals and aid in testing the production process.

Investigation into the Functions of Alkali and Surfactant in Chemical Flooding for Enhanced Heavy-Oil Recovery

2012 ◽  
Vol 524-527 ◽  
pp. 1816-1820 ◽  
Author(s):  
Ji Jiang Ge ◽  
Hai Hua Pei ◽  
Gui Cai Zhang ◽  
Xiao Dong Hu ◽  
Lu Chao Jin
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Chemical Flooding ◽  
Surfactant Flooding ◽  
Core Flooding ◽  
Sweep Efficiency ◽  
Water Emulsion ◽  
Tertiary Oil Recovery ◽  
Fingering Phenomena ◽  
Oil In Water Emulsion

In this study, a comparative study of alkaline flooding and alkali-surfactant flooding were conducted for Zhuangxi heavy oil with viscosity of 325 mPa•s at 55 °C. The results of core flooding tests show that the tertiary oil recovery of alkali-surfactant flooding are lower than those of alkaline-only flooding, in spite of the coexistence of the surfactant and alkali can reduce the IFT between the heavy oil and aqueous phase to an ultralow level. Further flood study via glass-etching micromodel tests demonstrates that injected alkaline-only solution can penetrate into the oil phase and creates some discontinuous water droplet inside the oil phase that tend to lower the mobility of the injected water and lead to the improvement of sweep efficiency. While for alkali-surfactant flooding, heavy oil is easily emulsified in brine by an alkaline plus very dilute surfactant formula to form oil-in-water emulsion, and then entrained in the water phase. Therefore, viscous fingering phenomena occur during the alkali-surfactant flooding, resulting in relatively lower sweep efficiency.

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