Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

scholarly journals Microbial-derived bio-surfactant using neem oil as substrate and its suitability for enhanced oil recovery

2020 ◽  
Author(s):  
Temitope Ogunkunle ◽  
Adesina Fadairo ◽  
Vamegh Rasouli ◽  
Kegang Ling ◽  
Adebowale Oladepo ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Seed Oil ◽  
Petroleum Industry ◽  
Neem Seed ◽  
Core Flooding ◽  
Core Samples ◽  
Two Samples ◽  
Neem Seed Oil ◽  
Acting Agent

AbstractThe limitation in the formulation and application of synthetic surfactants in petroleum industry is owing to their high cost of production or importation and their associated toxic effect which have been proven to be harmful to the environment. Hence it is vitally imperative to develop an optimum surfactant that is cost-effective, environmentally safe (biodegradable) and equally serves as surface acting agent. This study discusses the production of microbial produced bio-surfactant and its application in enhanced oil recovery. The bacteria Pseudomonas sp. were isolated from urine and allow to feed on neem seed oil as the major carbon source and energy. The crude bio-surfactant produced from the fermentation process was used to prepare three (3) solutions of bio-surfactants at different concentrations of 5 g/500 mL, 10 g/500 mL and 15 g/500 mL, and their suitability for enhanced oil recovery (EOR) was evaluated. Reservoir core samples and crude oil collected from the Niger Delta field were used to evaluate the EOR application of the microbial-derived surfactants. The sets of experimental samples were carried out using core flooding and permeability tester equipment, and the results obtained were compared with conventional waterflooding experiments. The three bio-surfactant concentrations were observed to recover more oil than the conventional waterflooding method for the two core samples used. Optimum performance of the produced microbial-derived surfactant on oil recovery based on the concentrations was observed to be 10 g/500 mL for the two samples used in this study. Therefore, eco-friendly bio-surfactant produced from neem seed oil using Pseudomonas sp. has shown to be a promising potential substance for enhanced oil recovery applications by incremental recoveries of 51.9%, 53.2%, and 29.5% at the concentration of 5, 10, and 15 g/500 mL and 24.7%, 28.7%, and 20.1% at concentration of 5, 10, and 15 g/500 mL for the two core samples, respectively.

scholarly journals Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing

Nanomaterials ◽  
2020 ◽  
Vol 10 (5) ◽  
pp. 972 ◽  
Author(s):  
Amin Rezaei ◽  
Hadi Abdollahi ◽  
Zeinab Derikvand ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Amir Mosavi ◽  
...  
Keyword(s):  
Size Distribution ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Alpha Olefin Sulfonate ◽  
Core Flooding ◽  
Recovery Method ◽  
Fluid Saturation

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

scholarly journals Controlled Salinity-Biosurfactant Enhanced Oil Recovery at Ambient and Reservoir Temperatures—An Experimental Study

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1077
Author(s):  
Tinuola Udoh ◽  
Jan Vinogradov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Core Flooding ◽  
Improved Oil Recovery ◽  
Rock Samples ◽  
Recovery Potential ◽  
System Temperature ◽  
High And Low Temperatures ◽  
First Time ◽  
Increased Oil Recovery

In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relative to injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 °C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.

The Effect of Zinc Oxide and Aluminum Oxide Nanoparticles on Interfacial Tension and Viscosity of Nanofluids for Enhanced Oil Recovery

2014 ◽  
Vol 1024 ◽  
pp. 56-59 ◽  
Author(s):  
Hasnah Mohd Zaid ◽  
Noor Rasyada Ahmad Latiff ◽  
Noorhana Yahya
Keyword(s):  
Zinc Oxide ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Substantial Reduction ◽  
Aluminium Oxide ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Aluminum Oxide Nanoparticles

Application of nanotechnology in enhanced oil recovery (EOR) has been increasing in the recent years. After secondary flooding, more than 60% of the original oil in place (OOIP) remains in the reservoir due to trapping of oil in the reservoir rock pores. One of the promising EOR methods is surfactant flooding, where substantial reduction in interfacial tension between oil and water could sufficiently displace oil from reservoir. The emulsion that is created between the two interfaces has a higher viscosity than its original components, providing more force to push the trapped oil. In this paper, the recovery mechanism of the enhanced oil recovery was determined by measuring oil-nanofluid interfacial tension and the viscosity of the nanofluid. Series of core flooding experiments were conducted using packed silica beads whichreplicate core rocks to evaluate the oil recovery efficiency of the nanofluid in comparison to that using an aqueous commercial surfactant, 0.3wt% sodium dodecyl sulfate (SDS). 117 % increase in the recovery of the residual oil in place (ROIP) was observed by the 2 pore volume (PV) injection of aluminium oxide nanofluid in comparison with 0.3wt% SDS. In comparison to the type of material, 5.12% more oil has been recovered by aluminium oxide compared to zinc oxide nanofluid in the presence of EM wave. The effect of the EM wave on the recoverywas also studied by and it was proven that electric field component of the EM waves has been stimulating the nanofluid to be more viscous by the increment of 54.2% in the oil recovery when aluminium oxide nanofluid was subjected to 50MHz EM waves irradiation.

scholarly journals The Role of Microbial Products in Green Enhanced Oil Recovery: Acetone and Butanone

Polymers ◽  
2021 ◽  
Vol 13 (12) ◽  
pp. 1946
Author(s):  
Bashirul Haq
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Process ◽  
Residual Oil ◽  
Core Flooding ◽  
Recovery Potential ◽  
Wide Range ◽  
Green Surfactant ◽  
Core Flood

Green enhanced oil recovery is an oil recovery process involving the injection of specific environmentally friendly fluids (liquid chemicals and gases) that effectively displace oil due to their ability to alter the properties of enhanced oil recovery. In the microbial enhanced oil recovery (MEOR) process, microbes produce products such as surfactants, polymers, ketones, alcohols, and gases. These products reduce interfacial tension and capillary force, increase viscosity and mobility, alter wettability, and boost oil production. The influence of ketones in green surfactant-polymer (SP) formulations is not yet well understood and requires further analysis. The work aims to examine acetone and butanone’s effectiveness in green SP formulations used in a sandstone reservoir. The manuscript consists of both laboratory experiments and simulations. The two microbial ketones examined in this work are acetone and butanone. A spinning drop tensiometer was utilized to determine the interfacial tension (IFT) values for the selected formulations. Viscosity and shear rate across a wide range of temperatures were measured via a Discovery hybrid rheometer. Two core flood experiments were then conducted using sandstone cores at reservoir temperature and pressure. The two formulations selected were an acetone and SP blend and a butanone and SP mixture. These were chosen based on their IFT reduction and viscosity enhancement capabilities for core flooding, both important in assessing a sandstone core’s oil recovery potential. In the first formulation, acetone was mixed with alkyl polyglucoside (APG), a non-ionic green surfactant, and the biopolymer Xanthan gum (XG). This formulation produced 32% tertiary oil in the sandstone core. In addition, the acetone and SP formulation was effective at recovering residual oil from the core. In the second formulation, butanone was blended with APG and XG; the formulation recovered about 25% residual oil from the sandstone core. A modified Eclipse simulator was utilized to simulate the acetone and SP core-flood experiment and examine the effects of surfactant adsorption on oil recovery. The simulated oil recovery curve matched well with the laboratory values. In the sensitivity analysis, it was found that oil recovery decreased as the adsorption values increased.

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

2021 ◽  
Author(s):  
Yongsheng Tan ◽  
Qi Li ◽  
Liang Xu ◽  
Xiaoyan Zhang ◽  
Tao Yu
Keyword(s):  
Carbon Dioxide ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Core Flooding ◽  
Nuclear Magnetic

<p>The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO<sub>2</sub>) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO<sub>2</sub> nanofluids combines the advantages of CO<sub>2</sub> and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO<sub>2</sub> flooding and saturated CO<sub>2</sub> nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO<sub>2</sub> displacement experiment, the results show that viscous fingering and channeling are obvious during CO<sub>2</sub> flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO<sub>2</sub> nanofluids displacement experiment, the results show that saturated CO<sub>2</sub> nanofluids inhibit CO<sub>2</sub> channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO<sub>2</sub> nanofluids displacement is higher than that of CO<sub>2</sub> displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO<sub>2</sub> utilization.</p>

Effect of pressure variation on polymer flooding

2021 ◽  
Author(s):  
Ahmad Ali Manzoor
Keyword(s):  
Polymer Solution ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Constant Pressure ◽  
Maximum Pressure ◽  
Core Flooding ◽  
Sweep Efficiency ◽  
Black Oil Model ◽  
Original Oil In Place

Chemical-based enhanced oil recovery (EOR) techniques utilize the injection of chemicals, such as solutions of polymers, alkali, and surfactants, into oil reservoirs for incremental recovery. The injection of a polymer increases the viscosity of the injected fluid and alters the water-to-oil mobility ratio which in turn improves the volumetric sweep efficiency. This research study aims to investigate strategies that would help intensify oil recovery with the polymer solution injection. For that purpose, we utilize a lab-scale, cylindrical heavy oil reservoir model. Furthermore, a dynamic mathematical black oil model is developed based on cylindrical physical model of homogeneous porous medium. The experiments are carried out by injecting classic and novel partially hydrolyzed polyacrylamide solutions (concentration: 0.1-0.5 wt %) with 1 wt % brine into the reservoir at pressures in the range, 1.03-3.44 MPa for enhanced oil recovery. The concentration of the polymer solution remains constant throughout the core flooding experiment and is varied for other subsequent experimental setup. Periodic pressure variations between 2.41 and 3.44 MPa during injection are found to increase the heavy oil recovery by 80% original-oil-in-place (OOIP). This improvement is approximately 100% more than that with constant pressure injection at the maximum pressure of 3.44 MPa. The experimental oil recoveries are in fair agreement with the model calculated oil production with a RMS% error in the range of 5-10% at a maximum constant pressure of 3.44 MPa.

Hydrocarbon saturation determination with the single-well-chemical-tracer-test under laboratory conditions

2021 ◽  
pp. 131-143
Author(s):  
F. A. Koryakin ◽  
N. Yu. Tretyakov ◽  
O. B. Abdulla ◽  
V. G. Filippov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Production Efficiency ◽  
Oil Production ◽  
Tracer Test ◽  
Core Sample ◽  
Oil Saturation ◽  
Chemical Tracer ◽  
Single Well ◽  
Efficiency Estimation

Nowadays the share of hard-to-recover reserves is growing, and to maintain oil production on necessarily level, we need to involve hard-to-recover reserves or to increase oil production efficiency on a brownfields due to enhanced oil recovery. The efficiency of enhanced oil recovery can be estimated by oil saturation reduction. Single-well-chemical-tracer-test (SWCTT) is increasingly used to estimate oil saturation before and after enhanced oil recovery application. To interpret results of SWCTT, reservoir simulation is recommended. Oil saturation has been calculated by SWCTT interpretation with use of reservoir simulator (CMG STARS). Distribution constants has been corrected due to results of real core sample model, and core tests has been successfully simulated. Obtained values of oil saturation corresponds with real oil saturation of samples. Thus, SWCTT as a method of oil saturation estimation shows good results. This method is promising for enhanced oil recovery efficiency estimation.

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