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.

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.

Nanoparticles EOR Aluminum Oxide (Al2O3) Used As a Spontaneous Imbibition Test for Sandstone Core

2019 ◽  
Author(s):  
Mohammed A. Samba ◽  
Hafsa A. Hassan ◽  
Mahjouba S. Munayr ◽  
Moataz Yusef ◽  
Abdelkareem Eschweido ◽  
...  
Keyword(s):  
Aluminum Oxide ◽  
Oil Recovery ◽  
Room Temperature ◽  
Spontaneous Imbibition ◽  
Chemical Flooding ◽  
Secondary Recovery ◽  
Chemical Eor ◽  
Change Temperature ◽  
Al2o3 Concentration ◽  
Polymer Surfactant

Abstract There are three types of oil production energy operations, primary recovery, secondary recovery and enhanced oil recovery (EOR). EOR consider as the last period for production operations. Where the EOR classify into many types such as thermal injection, gas injection, microbial EOR and chemical flooding. Chemical flooding classified into many types such as polymer, surfactant, alkaline and nanoparticles (NP). NP can be classified into many types such as Iron Oxide (Fe2O3), Aluminum Oxide (Al2O3) and Magnesium Oxide (MgO) etc. In this study NP Aluminum oxide (Al2O3) were used to enhance the oil recovery. The main objective of this study is to use the Nanoparticles EOR (Al2O3) and know it is effect on increasing the extraction of oil from cores. The big motivation of using Al2O3 that it is easy to extract it from raw clay. However, the raw clay is available in Libya and using it will be more economic than using other method of chemical EOR. Nanoparticles EOR Aluminum oxide (Al2O3) used as a spontaneous imbibition test for sandstone core samples after saturated by crude oil. A spontaneous imbibition test consisting of two scenarios of nanoparticle solution (Al2O3) with change temperature and compared with one scenario of distilled water. The spontaneous imbibition test was performed in this study at room temperature to oven temperature (30C°, 40C°, 50C°, 60C°, 70C°). The results shown that the oil recovery increases with the increase of the concentration of nanoparticle (Al2O3) and increase the temperature. The higher oil recovery was 76.04% at NP (Al2O3) concentration 1%. Finally, oil swelling and adsorption (NP (Al2O3) with oil drops) have been noticed during the extraction of oil. Thus, the gravity force will be higher than the capillary force.

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.

scholarly journals Phase behavior of heavy oil–solvent mixture systems under reservoir conditions

2020 ◽  
Vol 17 (6) ◽  
pp. 1683-1698 ◽  
Author(s):  
Xiao-Fei Sun ◽  
Zhao-Yao Song ◽  
Lin-Feng Cai ◽  
Yan-Yu Zhang ◽  
Peng Li
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Solvent Mixture ◽  
Average Error ◽  
Asphaltene Precipitation ◽  
Reservoir Conditions ◽  
Application Potential ◽  
Promising Application

AbstractA novel experimental procedure was proposed to investigate the phase behavior of a solvent mixture (SM) (64 mol% CH4, 8 mol% CO2, and 28 mol% C3H8) with heavy oil. Then, a theoretical methodology was employed to estimate the phase behavior of the heavy oil–solvent mixture (HO–SM) systems with various mole fractions of SM. The experimental results show that as the mole fraction of SM increases, the saturation pressures and swelling factors of the HO–SM systems considerably increase, and the viscosities and densities of the HO–SM systems decrease. The heavy oil is upgraded in situ via asphaltene precipitation and SM dissolution. Therefore, the solvent-enriched oil phase at the top layer of reservoirs can easily be produced from the reservoir. The aforementioned results indicate that the SM has promising application potential for enhanced heavy oil recovery via solvent-based processes. The theoretical methodology can accurately predict the saturation pressures, swelling factors, and densities of HO–SM systems with various mole fractions of SM, with average error percentages of 1.77% for saturation pressures, 0.07% for swelling factors, and 0.07% for densities.

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

scholarly journals Dynamics of Changes in Composition and Stability of the Heavy Oil Sampled from the Usinskoye Oil Field as a Result of Formation Treatment with a Sol-Forming EOR System

2019 ◽  
pp. 464-472
Author(s):  
Darya I. Chuikina ◽  
Tatiana V. Petrenko ◽  
Larisa D. Stakhina
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Field ◽  
Aggregative Stability ◽  
Heavy Oils ◽  
Asphaltene Precipitation ◽  
Liquid Adsorption ◽  
Oil Displacement ◽  
Before And After

The paper deals with a sol-forming system for oil recovery enhancement (EOR system) used to increase the rate of heavy oil displacement. The effect of sol-forming EOR system during the heavy oil displacement on the composition and stability of oil sampled from the Usinskoye oil field of Russia is investigated. The composition of a crude oil also plays an important role in changing its stability. The work is aimed to investigate stability of heavy crude oil in regards to asphaltene precipitation. For asphaltene toluene/n-heptane solutions, the aggregation stability of asphaltenes based on сhange in the optical density with time is investigated via spectrophotometry. SARA analysis is used to characterize the compositions of heavy oils. First, the content of asphaltenes precipitated from the oil samples is determined and then the samples of deasphalted crude oil (maltenes) are analyzed by the method of liquid adsorption chromatography for the purpose to study the composition of oil sampled from the wells before and after their treatment with the sol-forming EOR system. It is found out that the treatment of reservoir crude oil with the sol-forming EOR system results in changes in composition of saturated, aromatic hydrocarbons, resins, and asphaltenes (SARA components) and aggregative stability of produced oil. The results obtained showed that the aggregative stability of heavy oil depends not only on the content of SARA components in the dispersion medium but on the presence of metalloporphyrins in the oil. Metalloporphyrins could act as inhibitors of asphaltene precipitation, which is an additional factor responsible for the stabilization of the oil dispersed system

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).

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