scholarly journals Enhanced Oil Recovery by Hydrophilic Silica Nanofluid: Experimental Evaluation of the Impact of Parameters and Mechanisms on Recovery Potential

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5767
Author(s):  
Tariq Ali Chandio ◽  
Muhammad A. Manan ◽  
Khalil Rehman Memon ◽  
Ghulam Abbas ◽  
Ghazanfer Raza Abbasi
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Pore Throat ◽  
Recovery Mechanism ◽  
Recovery Potential ◽  
Porosity Reduction ◽  
Recovery Mechanisms ◽  
Profile Changes ◽  
The Impact ◽  
Integrated Study

Nanofluids as an EOR technique are reported to enhance oil recoveries. Among all the nanomaterial silica with promising lab results, economic and environmental acceptability are an ideal material for future applications. Despite the potential to enhance recoveries, understanding the two-fold impact of parameters such as concentration, salinity, stability, injection rate, and irreproducibility of results has arisen ambiguities that have delayed field applications. This integrated study is conducted to ascertain two-fold impacts of concentration and salinity on recovery and stability and evaluates corresponding changes in the recovery mechanism with variance in the parameters. Initially, silica nanofluids’ recovery potential was evaluated by tertiary flooding at different concentrations (0.02, 0.05, 0.07, 0.1) wt. % at 20,000 ppm salinity. The optimum concentration of 0.05 wt. % with the highest potential in terms of recovery, wettability change, and IFT reduction was selected. Then nano-flooding was carried out at higher salinities at a nanomaterial concentration of 0.05 wt. %. For the mechanism’s evaluation, the contact angle, IFT and porosity reduction, along with differential profile changes were analyzed. The recovery potential was found at its highest for 0.05 wt. %, which reduced when concentrations were further increased as the recovery mechanisms changed and compromised stability. Whereas salinity also had a two-fold impact with salinity at 30,000 ppm resulting in lower recovery, higher salinity destabilized the solution but enhanced recoveries by enhancing macroscopic mechanisms of pore throat plugging.

Integrated EOR Screening in a Marginal Oil Field Environment

2021 ◽  
Author(s):  
Chukwunonso Uche ◽  
Samuel Esieboma ◽  
Jennifer Uche ◽  
Ibrahim Bukar
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Oil Field ◽  
Chemical Flooding ◽  
Implementation Challenges ◽  
Recovery Potential ◽  
Field Environment ◽  
Screening Study ◽  
The Impact

Abstract An evaluation of potential EOR processes applicable in the marginal oil field operation of the Niger Delta region is presented. Technical feasibility, process availability, oil recovery potential, and other uncertainties and risks associated with exploitation of enhanced oil recovery technique in a marginal oil field environment are being assessed. Few Enhanced oil recovery processes, namely polymer flooding, chemical flooding and microbial EOR (MEOR), are considered for possible application in this marginal oil field. The objective of the screening study is to evaluate and rank the EOR options and also select the most attractive method that will have to be further chased to a pilot test stage. Emphasis is strictly on a technical assessment of the incremental oil potential of each of the EOR methods and also identification of critical operational and logistical components of the entire process for their implementation in the offshore operating environment. Recoverable volumes associated with EOR may be significant, but key project development and implementation challenges and extra cost elements must be considered in any EOR forecast for an effective EOR process ranking. Some of these concerns (e.g. Polymer/chemical supply, facilities requirements, and the impact of EOR on reservoir performance and wellbore integrity) may be significant enough to eliminate a method from being considered further and at that point the best EOR option that requires minimal cost exposure for achieving the best recoverable shall be considered. Moreso, there is consideration of the quantity and quality of laboratory data that should support the viability of each EOR process being considered. This paper narrates the state of technical readiness for field implementation of each EOR method and identifies remaining work required to progress EOR process in this marginal oil field.

Will Carbon Dioxide Injection in Shale Reservoirs Produce from the Shale Matrix, Natural Fractures, or Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Co2 Injection ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Recovery Potential ◽  
Shale Reservoirs ◽  
The Impact

Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.

scholarly journals Effect of nanoparticles concentration on electromagnetic-assisted oil recovery using ZnO nanofluids

PLoS ONE ◽  
2020 ◽  
Vol 15 (12) ◽  
pp. e0244738
Author(s):  
Muhammad Adil ◽  
Keanchuan Lee ◽  
Hasnah Mohd Zaid ◽  
M. Fadhllullah A. Shukur ◽  
Takaaki Manaka
Keyword(s):  
Oil Recovery ◽  
Metal Oxide Nanoparticles ◽  
Mobility Ratio ◽  
Oxide Nanoparticles ◽  
Surfactant Flooding ◽  
Zno Nps ◽  
Recovery Mechanism ◽  
Em Field ◽  
Zno Nanofluids ◽  
The Impact

Utilization of metal-oxide nanoparticles (NPs) in enhanced oil recovery (EOR) has generated substantial recent research interest in this area. Among these NPs, zinc oxide nanoparticles (ZnO-NPs) have demonstrated promising results in improving oil recovery due to their prominent thermal properties. These nanoparticles can also be polarized by electromagnetic (EM) field, which offers a unique Nano-EOR approach called EM-assisted Nano-EOR. However, the impact of NPs concentrations on oil recovery mechanism under EM field has not been well established. For this purpose, ZnO nanofluids (ZnO-NFs) of two different particle sizes (55.7 and 117.1 nm) were formed by dispersing NPs between 0.01 wt.% to 0.1 wt.% in a basefluid of sodium dodecylbenzenesulfonate (SDBS) and NaCl to study their effect on oil recovery mechanism under the electromagnetic field. This mechanism involved parameters, including mobility ratio, interfacial tension (IFT) and wettability. The displacement tests were conducted in water-wet sandpacks at 95˚C, by employing crude oil from Tapis. Three tertiary recovery scenarios have been performed, including (i) SDBS surfactant flooding as a reference, (ii) ZnO-NFs flooding, and (iii) EM-assisted ZnO-NFs flooding. Compare with incremental oil recovery from surfactant flooding (2.1% original oil in place/OOIP), nanofluid flooding reaches up to 10.2% of OOIP at optimal 0.1 wt.% ZnO (55.7 nm). Meanwhile, EM-assisted nanofluid flooding at 0.1 wt.% ZnO provides a maximum oil recovery of 10.39% and 13.08% of OOIP under EM frequency of 18.8 and 167 MHz, respectively. By assessing the IFT/contact angle and mobility ratio, the optimal NPs concentration to achieve a favorable ER effect and interfacial disturbance is determined, correlated to smaller hydrodynamic-sized nanoparticles that cause strong electrostatic repulsion between particles.

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Wenting Yue ◽  
John Yilin Wang
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Improved Oil Recovery ◽  
Smackover Formation ◽  
Artificial Lift ◽  
Production History ◽  
Current Production ◽  
The Impact

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

scholarly journals Polymer Optimisation- Shear Thinning or Thickening?

2019 ◽  
Vol 7 (4) ◽  
Author(s):  
Gloria Gyanfi ◽  
Wilberforce Nkrumah Aggrey ◽  
Ernest Ansah Owusu ◽  
Kofi Ohemeng Prempeh
Keyword(s):  
Shear Rate ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Shear Thickening ◽  
Shear Thinning ◽  
Injection Rate ◽  
Injection Well ◽  
Polymer Injection ◽  
Well Pattern ◽  
The Impact

With most polymers employed in polymer enhanced oil recovery exhibiting one or both non-Newtonian behaviours that is shear thickening and thinning at different shear rate, it is expedient to analyse the impact of these non-Newtonian behaviours in polymer optimisation. CMG simulation suite was employed to analyse the permeability pinch-out formation with a five (5) spot injection well pattern for a 360days simulation run using a 90days polymer injection well cycling. Shear thinning polymer was found not to be conducive for lower permeable formation as a high percentage of the polymer was retained. NPV was affected by polymer injection rate which controlled polymer optimisation

Oil Recovery Mechanisms During Sequential Injection of Chelating Agent Solutions Into Carbonate Rocks

2019 ◽  
Vol 142 (1) ◽  
Author(s):  
Amjed M. Hassan ◽  
Hasan S. Al-Hashim
Keyword(s):  
Oil Recovery ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Analytical Models ◽  
Productivity Index ◽  
Wettability Alteration ◽  
Permeability Enhancement ◽  
Recovery Mechanisms ◽  
The Impact

Chelating agent solutions have been proposed as effective fluids for enhancing oil production. Different recovery mechanisms are reported for increasing the oil recovery during chelating agent flooding. The aims of this work are to identify the possible recovery mechanisms during chelating agent flooding in carbonate reservoirs and to investigate the in situ CO2 generation as a potential recovery mechanism during the injection of chelating agent solutions into carbonate reservoirs. The contribution of CO2 on enhancing the oil recovery was determined using experimental measurements and analytical calculations. Several measurements were conducted to study the contribution of each mechanism on enhancing the oil recovery. Coreflooding tests, zeta potential measurements, CO2 generation, and interfacial tension (IFT) experiments were carried out. Also, analytical models were utilized to determine the impact of the injected chemicals on reducing the capillary pressure and improving the flow conditions. In flooding tests, two chemicals (EDTA and GLDA) were injected in a sequential mode and the chemical concentration was increased gradually. In addition, a comparative study was performed to evaluate the effectiveness of EDTA and GLDA solutions to enhance oil recovery. Several parameters were investigated in this paper including incremental oil recovery, in situ CO2 generation, hydrocarbon swelling, IFT, wettability alteration, permeability enhancement, productivity index, and chemical cost. The obtained results show that GLDA chelating agent has better performance than EDTA solutions for enhancing the oil recovery when the same concentrations are used. Also, the in situ generation of CO2 shows a significant impact on improving the oil recovery from carbonate reservoirs during chelating agent flooding. In the literature, the reported recovery mechanisms of using chelating agents are the IFT reduction, wettability alteration, and rock dissolution. Based on this work, injecting chelating agent solutions at low pH can lead to involve additional recovery mechanisms due to the CO2 generation, the additional mechanisms are hydrocarbon swelling, viscosity and density reduction, and oil vaporization.

Mechanistic Simulation of Polymer Injectivity in Field Tests

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1178-1191 ◽  
Author(s):  
Mohammad Lotfollahi ◽  
Rouhi Farajzadeh ◽  
Mojdeh Delshad ◽  
Al-Khalil Al-Abri ◽  
Bart M. Wassing ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pressure Rise ◽  
Shear Thickening ◽  
Injection Rate ◽  
Field Application ◽  
Polymer Flooding ◽  
Velocity Shear ◽  
Polymer Rheology ◽  
Deep Bed Filtration ◽  
The Impact

Summary Polymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding. The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water. In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates. The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times. One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

scholarly journals Experimental Microemulsion Flooding Study to Increase Low Viscosity Oil Recovery Using Glass Micromodel

2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Hamed Hematpur ◽  
Reza Abdollahi ◽  
Mohsen Safari-Beidokhti ◽  
Hamid Esfandyari
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Clean Energy ◽  
Injection Rate ◽  
Chemical Flooding ◽  
Recovery Method ◽  
Low Viscosity ◽  
Glass Micromodel ◽  
Actual Field ◽  
The Impact

The growing demand for clean energy can be met by improving the recovery of current resources. One of the effective methods in recovering the unswept reserves is chemical flooding. Microemulsion flooding is an alternative for surfactant flooding in a chemical-enhanced oil recovery method and can entirely sweep the remaining oil in porous media. The efficiency of microemulsion flooding is guaranteed through phase behavior analysis and customization regarding the actual field conditions. Reviewing the literature, there is a lack of experience that compared the macroscopic and microscopic efficiency of microemulsion flooding, especially in low viscous oil reservoirs. In the current study, one-quarter five-spot glass micromodel was implemented for investigating the effect of different parameters on microemulsion efficiency, including surfactant types, injection rate, and micromodel pattern. Image analysis techniques were applied to represent the phase saturations throughout the microemulsion flooding tests. The results confirm the appropriate efficiency of microemulsion flooding in improving the ultimate recovery. LABS microemulsion has the highest efficiency, and the increment of the injection rate has an adverse effect on oil recovery. According to the pore structure’s tests, it seems that permeability has little impact on recovery. The results of this study can be used in enhanced oil recovery designs in low-viscosity oil fields. It shows the impact of crucial parameters in microemulsion flooding.

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%.

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