scholarly journals An Elongational and Shear Evaluation of Polymer Viscoelasticity during Flow in Porous Media

2020 ◽  
Vol 10 (12) ◽  
pp. 4152 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Leonhard Ganzer
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Viscoelastic Properties ◽  
Mechanical Degradation ◽  
Core Flooding ◽  
Higher Temperature ◽  
Core Flood ◽  
The Impact ◽  
Harsh Conditions ◽  
Polymer Viscoelasticity

This paper uses a combination of approaches to evaluate the viscoelastic phenomenon in high-molecular-weight polymers (24–28 M Daltons) used for enhanced oil recovery (EOR) applications. Rheological data were cross-analyzed with single- and two-phase polymer flooding experiments in outcrop cores and micromodels, respectively. First, the impact of semi-harsh conditions (salinity, hardness, and temperature) was evaluated. Second, the impact of polymer degradation (sand face flow), focusing on the viscoelastic properties, was investigated. Finally, polymer viscoelastic properties were characterized, proposing a threefold rheological approach of rotational, oscillatory, and elongational behavior. Data from the rheological approaches were cross-analyzed with core flooding experiments and performed at a room temperature of 22 °C and at a higher temperature of 55 °C. The change in polymer viscoelastic properties were analyzed by investigating the effluents from core flooding experiments. Oil recovery experiments in micromodel helped our understanding of whether salinity or hardness has a dominating impact on in situ viscoelastic polymer response. These approaches were used to study the impact of mechanical degradation on polymer viscoelasticity. The brines showed notable loss in polymer viscoelastic properties, specifically with the hard brine and at higher temperature. However, the same polymer solution diluted in deionized water exhibited stronger viscoelastic properties. Multiple flow-behaviors, such as Newtonian, shear thinning, and thickening dominated flow, were confirmed through pressure drop analysis against interstitial velocity as already reported by other peer researchers. Turbulence-dominated excessive pressure drop in porous media was calculated by comparing core flood pressure drop data against pressure data in extensional viscometer–rheometer on a chip (eVROC®). In addition, a significant reduction in elastic-dominated flow was confirmed through the mechanical degradation that happened during core flood experiments, using various approaches. Finally, reservoir harsh conditions (high temperature, hardness, and salinity) resulted in a significant reduction in polymer viscoelastic behavior for all approaches.

Optimization of Smart Water Chemical Composition for Carbonate Rocks Through Comparison of Active Cations Performance

2017 ◽  
Vol 139 (6) ◽  
Author(s):  
Malek Jalilian ◽  
Peyman Pourafshary ◽  
Behnam Sedaee Sola ◽  
Mosayyeb Kamari
Keyword(s):  
Chemical Composition ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
Low Cost ◽  
Recovery Phase ◽  
Ion Concentration ◽  
Water Flooding ◽  
Core Flooding ◽  
Smart Water ◽  
The Impact

Designing smart water (SW) by optimizing the chemical composition of injected brine is a promising low-cost technique that has been developed for both sandstone and carbonate reservoirs for several decades. In this study, the impact of SW flooding during tertiary oil recovery phase was investigated by core flooding analysis of pure limestone carbonate rocks. Increasing the sulfate ion concentration by using CaSO4 and MgSO4 of NaCl concentration and finally reducing the total salinity were the main manipulations performed to optimize SW. The main objective of this research is to compare active cations including Ca2+ and Mg2+ in the presence of sulfate ions (SO42−) with regard to their efficiency in the enhancement of oil production during SW flooding of carbonate cores. The results revealed a 14.5% increase in the recovery factor by CaSO4 proving its greater effectiveness compared to MgSO4, which led to an 11.5% production enhancement. It was also realized that low-salinity water flooding (LSWF) did not lead to a significant positive effect as it contributed less than 2% in the tertiary stage.

scholarly journals An Experimental Investigation the Optimum of Salinity and Ph of Sea-Water to Improve Oil Recovery from Sandstone Reservoir as A Secondary Recovery Process

2020 ◽  
Vol 1 (2) ◽  
pp. 83
Author(s):  
Madi Abdullah Naser ◽  
Mohammed A Samba ◽  
Yiqiang Li
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Recovery Process ◽  
Water Flooding ◽  
Core Flooding ◽  
Low Salinity ◽  
Seawater Salinity ◽  
Secondary Recovery ◽  
Two Parameters ◽  
The Impact

Laboratory tests and field applications shows that the salinity of water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity water flooding studies. However, there are few quantitative studies on seawater composition change and it impact on increasing or improving oil recovery.  This study was conducted to investigate only two parameters of the seawater (Salinity and pH) to check their impact on oil recovery, and what is the optimum amount of salinity and ph that we can use to get the maximum oil recovery.  Several core flooding experiments were conducted using sandstone by inject seawater (high, low salinity and different pH). The results of this study has been shown that the oil recovery increases as the injected water salinity down to 6500 ppm and when the pH is around 7. This increase has been found to be supported by an increase in the permeability. We also noticed that the impact of ph on oil recovery is low when the pH is less than 7.

The Impact of Nanoparticles Adsorption and Transport on Wettability Alteration of Intermediate Wet Berea Sandstone

2015 ◽  
Author(s):  
Shidong Li ◽  
Ole Torsæter
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Fluid Pressure ◽  
Injection Pressure ◽  
Wettability Alteration ◽  
Colloidal Nanoparticles ◽  
Berea Sandstone ◽  
Nano Structure ◽  
The Core ◽  
The Impact

AbstractNanoparticles as part of nanotechnology have drawn the attention for its great potential of increasing oil recovery. From authors' previous studies (Li et al., 2013a), wettability alteration was proposed as one of the main Enhanced Oil Recovery (EOR) mechanisms for nanoparticles fluid, as adsorption of nanoparticles on pore walls leads to wettability alteration of reservoir. We conducted a series of wettability measurement experiments for aged intermediate-wet Berea sandstone, where the core plugs were treated by different concentration and type of nanoparticles fluid. Nanoparticles transport experiments also were performed for core plugs with injection of varying concentration and type of nanoparticles fluid. Pressure drop across the core plug during injection was recorded to evaluate nanoparticles adsorption and retention inside core, as well as desorption during brine postflush. Both hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles were utilized in above two experiments.The results of wettability alteration experiments indicated that hydrophilic nanoparticles have ability of making intermediate-wet Berea sandstone to be more water wet, and basically the higher concentration the more water wet will be. And different type of nanoparticles has different effect on the wettability alteration process. For nanoparticles transport experiments, the results showed that the nanoparticles undergo both adsorption and desorption as well as retention during injection. Pressure drop curves showed that absorption and retention of nano-structure particles inside core was significant while colloidal nanoparticles did not adsorb much. Permeability impairment was observed during nano-structure particles fluid injection, but on the contrary colloidal nanoparticles dispersion injection made core more permeable.

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.

Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions

2021 ◽  
Author(s):  
Umar Alfazazi ◽  
Nithin Chacko Thomas ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
High Salinity ◽  
Careful Consideration ◽  
Rock Surface ◽  
Ct Scanner ◽  
Core Samples ◽  
The Impact ◽  
Polymer Retention ◽  
Harsh Conditions

Abstract Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties. Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.

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 Impact of temperature and relative humidity on the transmission of COVID-19: a modelling study in China and the United States

BMJ Open ◽  
2021 ◽  
Vol 11 (2) ◽  
pp. e043863
Author(s):  
Jingyuan Wang ◽  
Ke Tang ◽  
Kai Feng ◽  
Xin Lin ◽  
Weifeng Lv ◽  
...  
Keyword(s):  
Regression Analysis ◽  
Relative Humidity ◽  
Human Mobility ◽  
The United States ◽  
Reproductive Number ◽  
Cross Sectional ◽  
The Usa ◽  
Higher Temperature ◽  
Potential Impact ◽  
The Impact

ObjectivesWe aim to assess the impact of temperature and relative humidity on the transmission of COVID-19 across communities after accounting for community-level factors such as demographics, socioeconomic status and human mobility status.DesignA retrospective cross-sectional regression analysis via the Fama-MacBeth procedure is adopted.SettingWe use the data for COVID-19 daily symptom-onset cases for 100 Chinese cities and COVID-19 daily confirmed cases for 1005 US counties.ParticipantsA total of 69 498 cases in China and 740 843 cases in the USA are used for calculating the effective reproductive numbers.Primary outcome measuresRegression analysis of the impact of temperature and relative humidity on the effective reproductive number (R value).ResultsStatistically significant negative correlations are found between temperature/relative humidity and the effective reproductive number (R value) in both China and the USA.ConclusionsHigher temperature and higher relative humidity potentially suppress the transmission of COVID-19. Specifically, an increase in temperature by 1°C is associated with a reduction in the R value of COVID-19 by 0.026 (95% CI (−0.0395 to −0.0125)) in China and by 0.020 (95% CI (−0.0311 to −0.0096)) in the USA; an increase in relative humidity by 1% is associated with a reduction in the R value by 0.0076 (95% CI (−0.0108 to −0.0045)) in China and by 0.0080 (95% CI (−0.0150 to −0.0010)) in the USA. Therefore, the potential impact of temperature/relative humidity on the effective reproductive number alone is not strong enough to stop the pandemic.

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