A New Approach of Pressure Profile and Oil Recovery during Dual and Single Carbonate Core Flooding by Seawater and CO2 Injection Process at Reservoir Conditions

2017 ◽  
Author(s):  
Xianmin Zhou ◽  
Fawaz AlOtaibi ◽  
Sunil Kokal ◽  
Almohannad Alhashboul ◽  
Jassi Al-Qahtani
Keyword(s):  
Oil Recovery ◽  
Pressure Profile ◽  
Core Flooding ◽  
New Approach ◽  
Injection Process ◽  
Reservoir Conditions

scholarly journals Comparative Study of Using Sea-Water for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs: Effects of Temperature and Aging Time on Oil Recovery

2018 ◽  
Vol 7 (2) ◽  
pp. 1-13
Author(s):  
Madi Abdullah Naser ◽  
Mohamed Erhayem ◽  
Ali Hegaig ◽  
Hesham Jaber Abdullah ◽  
Muammer Younis Amer ◽  
...  
Keyword(s):  
Aging Time ◽  
Oil Recovery ◽  
Sea Water ◽  
Essential Element ◽  
Recovery Process ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Injection Process ◽  
Reservoir Conditions ◽  
The Impact

Oil recovery process is an essential element in the oil industry, in this study, a laboratory study to investigate the effect of temperature and aging time on oil recovery and understand some of the mechanisms of seawater in the injection process. In order to do that, the sandstone and carbonate cores were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, they were put in the seawater to recover, and this test is called a spontaneous imbibition test. The spontaneous imbibition test in this study was performed at room temperature to oven temperature 80 oC with different sandstone and carbonate rock with aging time of 1126 hours. The result shows that the impact of seawater on oil recovery in sandstone is higher than carbonate. At higher temperature, the oil recovery is more moderate than low temperature. Likewise, as the aging time increase for both sandstone and carbonate rocks the oil recovery increase. 

Design Researches in Making In-Situ Thermal Foam System as a New Enhanced Heavy Oil Recovery Method

2021 ◽  
Author(s):  
Vladimir Nikolaevich Kozhin ◽  
Andrey Valerevich Mikhailov ◽  
Konstantin Vasilievich Pchela ◽  
Ivan Ivanovich Kireev ◽  
Sergey Valerevich Demin ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Ionic Composition ◽  
Chemical Effect ◽  
Recovery Method ◽  
Injection Process ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Displacement Factor ◽  
Water Gas

Abstract The paper presents the results of lab and filtration studies aimed at improving the procedure of thermal/gas/chemical effect (TGCE) with the generation of thermogenic system in reservoir conditions, proposed as an alternative to the methods of increasing oil recovery, such as water-gas effect procedure and foam injection process. The objects of research were thermal/gas generating compositions at the basis of sodium salts of sulfamic and nitric acids. Moreover, the influence of the ionic composition of the aqueous solution and temperature on the surface properties of the attracted solutions of surfactants (surfactants) was also evaluated. Filtration tests have shown that the use of a thermal/gas generating composition leads to additional displacement of high-viscous oil. The introduction of surfactants in the thermal/gas generating composition promotes foaming in the porous medium of the reservoir model and prevents gas breakthrough that leads to an increase in the oil displacement factor up to 24 %.

Analyzing the Influence of Salinity on Produced Water Re-Injection

2021 ◽  
Author(s):  
Adekunle Tirimisiyu Adeniyi ◽  
Chimgozirim Prince Ejim
Keyword(s):  
Oil Recovery ◽  
Produced Water ◽  
Core Sample ◽  
Production Performance ◽  
Core Flooding ◽  
Daily Rate ◽  
Reservoir Conditions ◽  
Cumulative Production ◽  
Water Disposal ◽  
Incremental Oil Recovery

Abstract Produced water reinjection (PWRI) is one of the methods employed by oilfield operators to optimize production while conforming to increasingly stringent produced water disposal policies. Different produced water species from different facilities also have different salinities as a result of entrainment of treatment fluids, precipitation of salts at surface conditions, etc. During re-injection operations, the salinity of the injection fluid has to be accounted for as it affects the production. Previous studies have focused on laboratory analysis by core flooding. While this approach is indeed reasonable and offers a first-hand impression of the reservoir conditions, it presents a problem of cost and the age-old opinion that the core sample may not be representative of the entire reservoir. Therefore, I have employed a computer modeling approach using a commercial simulator to analyze the influence of salinity on production during produced water re-injection. It was found that the salinity truly affects production. Re-injection of produced water with salinity equal to the reservoir salinity of 1000 ppm was compared to three cases of re-injection of produced water from extraneous sources having salinities of 100 ppm, 500 ppm and 10000 ppm. It was found that salinity of 10000 ppm gave the best oil production performance for the reservoir model; a daily rate of 40 STB/DAY and an oil cumulative production of 40,000 STB. Incremental salinity of injected produced water led to incremental oil recovery. The mechanism resulting in incremental recovery was attributed to the increase in viscosity and decrease in mobility as the salinity increases.

scholarly journals Improvement of Steam Injection Processes Through Nanotechnology: An Approach through in Situ Upgrading and Foam Injection

Energies ◽  
2019 ◽  
Vol 12 (24) ◽  
pp. 4633 ◽  
Author(s):  
Oscar E. Medina ◽  
Yira Hurtado ◽  
Cristina Caro-Velez ◽  
Farid B. Cortés ◽  
Masoud Riazi ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
High Performance ◽  
Steam Injection ◽  
American Petroleum Institute ◽  
Oil Viscosity ◽  
Nitrogen Injection ◽  
Injection Process ◽  
Reservoir Conditions

This study aims to evaluate a high-performance nanocatalyst for upgrading of extra-heavy crude oil recovery and at the same time evaluate the capacity of foams generated with a nanofluid to improve the sweeping efficiency through a continuous steam injection process at reservoir conditions. CeO2±δ nanoparticles functionalized with mass fractions of 0.89% and 1.1% of NiO and PdO, respectively, were employed to assist the technology and achieve the oil upgrading. In addition, silica nanoparticles grafted with a mass fraction of 12% polyethylene glycol were used as an additive to improve the stability of an alpha-olefin sulphonate-based foam. The nanofluid formulation for the in situ upgrading process was carried out through thermogravimetric analysis and measurements of zeta potential during eight days to find the best concentration of nanoparticles and surfactant, respectively. The displacement test was carried out in different stages, including, (i) basic characterization, (ii) steam injection in the absence of nanofluids, (iii) steam injection after soaking with nanofluid for in situ upgrading, (iv) N2 injection, and (v) steam injection after foaming nanofluid. Increase in the oil recovery of 8.8%, 3%, and 5.5% are obtained for the technology assisted by the nanocatalyst-based nanofluid, after the nitrogen injection, and subsequent to the thermal foam injection, respectively. Analytical methods showed that the oil viscosity was reduced 79%, 77%, and 31%, in each case. Regarding the asphaltene content, with the presence of the nanocatalyst, it decreased from 28.7% up to 12.9%. Also, the American Petroleum Institute (API) gravity values increased by up to 47%. It was observed that the crude oil produced after the foam injection was of higher quality than the crude oil without treatment, indicating that the thermal foam leads to a better swept of the porous medium containing upgraded oil.

scholarly journals The effect of carbonate rock wettability on the performance of low salinity waterflooding: an experimental approach

2021 ◽  
Author(s):  
Abdulrazag Zekri ◽  
Hildah Nantongo ◽  
Fathi Boukadi
Keyword(s):  
Oil Recovery ◽  
Experimental Approach ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Main Research ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Conditions ◽  
Salinity Water

AbstractWhile the “low salinity waterflooding” (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a “base water”. Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil- and intermediate-wettability systems.

scholarly journals Laboratory Study on the Potential EOR Use of HPAM/VES Hybrid in High-Temperature and High-Salinity Oil Reservoirs

2013 ◽  
Vol 2013 ◽  
pp. 1-8 ◽  
Author(s):  
Dingwei Zhu ◽  
Jichao Zhang ◽  
Yugui Han ◽  
Hongyan Wang ◽  
Yujun Feng
Keyword(s):  
Thermal Stability ◽  
High Temperature ◽  
Salinity Tolerance ◽  
Oil Recovery ◽  
High Salinity ◽  
Oil Reservoirs ◽  
Mechanical Degradation ◽  
Core Flooding ◽  
Reservoir Conditions ◽  
Viscoelastic Surfactant

Polymer flooding represents one of the most efficient processes to enhance oil recovery, and partially hydrolyzed polyacrylamide (HPAM) is a widely used oil-displacement agent, but its poor thermal stability, salt tolerance, and mechanical degradation impeded its use in high-temperature and high-salinity oil reservoirs. In this work, a novel viscoelastic surfactant, erucyl dimethyl amidobetaine (EDAB), with improved thermal stability and salinity tolerance, was complexed with HPAM to overcome the deficiencies of HPAM. The HPAM/EDAB hybrid samples were studied in comparison with HPAM and EDAB in synthetic brine regarding their rheological behaviors and core flooding experiments under simulated high-temperature and high-salinity oil reservoir conditions (T: 85°C; total dissolved solids: 32,868 mg/L; [Ca2+] + [Mg2+]: 873 mg/L). It was found that the HPAM/EDAB hybrids exhibited much better heat- and salinity-tolerance and long-term thermal stability than HPAM. Core flooding tests showed that the oil recovery factors of HPAM/EDAB hybrids are between those of HPAM and EDAB. These results are attributed to the synergistic effect between HPAM and EDAB in the hybrid.

Determination of Optimum Parameters for Anaerobic Thermophilic Bacterium Injection using Commercial Simulator: Core Flooding Validation and Sensitivity

2020 ◽  
Author(s):  
A. Koto
Keyword(s):  
Oil Recovery ◽  
Simulation Experiment ◽  
Previous Experiment ◽  
Core Sample ◽  
Thermophilic Bacterium ◽  
Injection Rate ◽  
Core Flooding ◽  
Optimum Parameters ◽  
Result Show

The objective of this paper is to determine the optimum anaerobic-thermophilic bacterium injection (Microbial Enhanced Oil Recovery) parameters using commercial simulator from core flooding experiments. From the previous experiment in the laboratory, Petrotoga sp AR80 microbe and yeast extract has been injected into core sample. The result show that the experiment with the treated microbe flooding has produced more oil than the experiment that treated by brine flooding. Moreover, this microbe classified into anaerobic thermophilic bacterium due to its ability to live in 80 degC and without oxygen. So, to find the optimum parameter that affect this microbe, the simulation experiment has been conducted. The simulator that is used is CMG – STAR 2015.10. There are five scenarios that have been made to forecast the performance of microbial flooding. Each of this scenario focus on the injection rate and shut in periods. In terms of the result, the best scenario on this research can yield an oil recovery up to 55.7%.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

scholarly journals Investigation on degradation mechanism of polymer blockages in unconsolidated sandstone reservoirs

e-Polymers ◽  
2020 ◽  
Vol 20 (1) ◽  
pp. 55-60
Author(s):  
Wenting Dong ◽  
Dong Zhang ◽  
Keliang Wang ◽  
Yue Qiu
Keyword(s):  
Oil Recovery ◽  
Degradation Mechanism ◽  
Injection Pressure ◽  
Polymer Flooding ◽  
Core Flooding ◽  
Reservoir Properties ◽  
Thermal Analyzer ◽  
Sandstone Reservoirs ◽  
Suction Index ◽  
Weighing Method

AbstractPolymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

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