Residual Oil Recovery via Injection of Biosurfactant and Chemical Surfactant following Hot Water Injection in Middle East Heavy Oil Field

2013 ◽  
Author(s):  
Abdulkadir Elshafie ◽  
Saif Al-Bahry ◽  
Hamoud Al-Hadrami ◽  
Ali Al-Bemani ◽  
Sanket Joshi ◽  
...  
Keyword(s):  
Middle East ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Oil Field ◽  
Hot Water ◽  
Residual Oil

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

2021 ◽  
Author(s):  
Randy Agra Pratama ◽  
Tayfun Babadagli
Keyword(s):  
Porous Media ◽  
Phase Change ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Phase Distribution ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Residual Oil ◽  
Tertiary Recovery

Abstract Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

Low Salinity Hot Water Injection With Addition of Nanoparticles for Enhancing Heavy Oil Recovery

2019 ◽  
Vol 141 (7) ◽  
Author(s):  
Yanan Ding ◽  
Sixu Zheng ◽  
Xiaoyan Meng ◽  
Daoyong Yang
Keyword(s):  
Thermal Energy ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Operating Conditions ◽  
Hot Water ◽  
Wettability Alteration ◽  
Heavy Oil Recovery ◽  
Oil Saturation ◽  
Low Salinity

In this study, a novel technique of low salinity hot water (LSHW) injection with addition of nanoparticles has been developed to examine the synergistic effects of thermal energy, low salinity water (LSW) flooding, and nanoparticles for enhancing heavy oil recovery, while optimizing the operating parameters for such a hybrid enhanced oil recovery (EOR) method. Experimentally, one-dimensional displacement experiments under different temperatures (17 °C, 45 °C, and 70 °C) and pressures (about 2000–4700 kPa) have been performed, while two types of nanoparticles (i.e., SiO2 and Al2O3) are, respectively, examined as the additive in the LSW. The performance of LSW injection with and without nanoparticles at various temperatures is evaluated, allowing optimization of the timing to initiate LSW injection. The corresponding initial oil saturation, production rate, water cut, ultimate oil recovery, and residual oil saturation profile after each flooding process are continuously monitored and measured under various operating conditions. Compared to conventional water injection, the LSW injection is found to effectively improve heavy oil recovery by 2.4–7.2% as an EOR technique in the presence of nanoparticles. Also, the addition of nanoparticles into the LSHW can promote synergistic effect of thermal energy, wettability alteration, and reduction of interfacial tension (IFT), which improves displacement efficiency and thus enhances oil recovery. It has been experimentally demonstrated that such LSHW injection with the addition of nanoparticles can be optimized to greatly improve oil recovery up to 40.2% in heavy oil reservoirs with low energy consumption. Theoretically, numerical simulation for the different flooding scenarios has been performed to capture the underlying recovery mechanisms by history matching the experimental measurements. It is observed from the tuned relative permeability curves that both LSW and the addition of nanoparticles in LSW are capable of altering the sand surface to more water wet, which confirms wettability alteration as an important EOR mechanism for the application of LSW and nanoparticles in heavy oil recovery in addition to IFT reduction.

Challenges, Opportunities and Threats of Deep Bottoms-Up Water Injection in Heavy Oil Reservoir: Lessons Learnt from the G Field, South Oman

2021 ◽  
Author(s):  
Chaitanya Behera ◽  
Sandip Mahajan ◽  
Carlos Annia ◽  
Mahmood Harthi ◽  
Jane-Frances Obilaja ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Field Performance ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Light Oil ◽  
Alternative Water ◽  
Variable Water

Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

Oil Recovery Enhancement in Middle East Heavy Oil Field using Malonic Acid based Deep Eutectic Solvent

2015 ◽  
Author(s):  
I. Al-Weheibi ◽  
R. Al-Hajri ◽  
Y. Al-Wahaibi ◽  
B. Jibril ◽  
A. Mohsenzadeh
Keyword(s):  
Middle East ◽  
Malonic Acid ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Deep Eutectic Solvent ◽  
Oil Field

scholarly journals The use of laurylamine hydrocholoride CH3(CH2)11 NH3 –Cl for secondary oil recovery

2012 ◽  
Vol 9 (1) ◽  
pp. 120-123
Author(s):  
Baghdad Science Journal
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Cationic Surfactants ◽  
Water Injection ◽  
Solution Concentration ◽  
Oil Field ◽  
Residual Oil ◽  
Secondary Oil Recovery ◽  
Total Oil ◽  
The Relationship

Laurylamine hydrochloride CH3(CH2)11 NH3 – Cl has been chosen from cationic surfactants to produce secondary oil using lab. model shown in fig. (1). The relationship between interfacial tension and (temperature, salinity and solution concentration) have been studied as shown in fig. (2, 3, 4) respectively. The optimum values of these three variables are taken (those values that give the lowest interfacial tension). Saturation, permeability and porosity are measured in the lab. The primary oil recovery was displaced by water injection until no more oil can be obtained, then laurylamine chloride is injected as a secondary oil recovery. The total oil recovery is 96.6% or 88.8% of the residual oil has been recovered by this technique as shown in fig. (5). This method was applied in an oil field and it gave approximate values close to that obtained in the lab.

A visual investigation of enhanced heavy oil recovery by foam flooding after hot water injection

2016 ◽  
Vol 147 ◽  
pp. 361-370 ◽  
Author(s):  
Zhengbin Wu ◽  
Huiqing Liu ◽  
Zhanxi Pang ◽  
Yalong Wu ◽  
Xue Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Foam Flooding

Visual Flooding Experiment of Hot Water, Steam and Solvent Under SAGD and VAPEX Conditions

2021 ◽  
Author(s):  
Songyan Li ◽  
Rui Han ◽  
Qun Wang ◽  
Xuemei Wei
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Hot Water ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Water Steam ◽  
Solvent Vapor ◽  
Recovery Method ◽  
Steam Flooding

Abstract Steam-assisted gravity drainage (SAGD) is an important method of heavy oil production, and the solvent vapor extraction (VAPEX) process is also an economically feasible, technically reliable, and environmentally friendly in situ heavy oil recovery method. In this paper, a microscopic visual flooding device was used to conduct seven groups of visual flooding experiments, including hot water, steam, liquid solvent and vapor solvent, at different temperatures. It can be directly observed that the residual oil in the hot water swept area is generally distributed in “spots”, “strips” and “clusters” of varying sizes. The residual oil after steam flooding generally has a “cluster” distribution, the residual oil after liquid solvent flooding has a “film” distribution, and there is only a little “spot” residual oil distributed after solvent vapor flooding. Additionally, we found that the sweep efficiency and displacement efficiency of hot water, steam and solvent increase with increasing temperature, and the sweep efficiency of hot water is higher than that of steam and liquid solvent. Vapor solvent has the greatest recovery factor, reaching approximately 90%. The experimental results hint at the future development trend of solvent injection and support the foundation of more general applications pertaining to the sustainable production of unconventional petroleum resources.

Heavy-Oil Recovery by Combined Hot Water and Alkali/Cosolvent/Polymer Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 74-86 ◽  
Author(s):  
M.. Tagavifar ◽  
R.. Fortenberry ◽  
E.. de Rouffignac ◽  
K.. Sepehrnoori ◽  
G. A. Pope
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Field ◽  
Hot Water ◽  
Mobility Control ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Polymer Flood ◽  
Low Interfacial Tension ◽  
Combined Strategy

Summary A hybrid process is developed and optimized for heavy-oil recovery that combines moderate reservoir heating and chemical enhanced oil recovery in the form of alkali/cosolvent/polymer flood. The process is simulated by use of a model derived from existing laboratory and pilot data of a 5,000-cp heavy-oil field. It is found that hot waterflooding is efficient in heating the reservoir only when high early injectivity is achievable. This may not be the case if incipient fluid injectivity is low and/or long, continuous, horizontal shale baffles are present. To remedy the former, an electrical-preheating period is devised, whereas switching to a horizontal flood could overcome the latter. Once the reservoir temperature is raised sufficiently, a moderately unstable alkali/cosolvent/polymer flood is capable of mobilizing and displacing oil. A best combined strategy for efficient reservoir heating, high oil recovery, and cost effectiveness is found to involve reducing the oil viscosity to values of approximately 300–500 cp and combining a degree of mobility control and low interfacial tension as recovery mechanisms.

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