An Investigation on the Process of Re-Imbibition of Oil and its Impact on Oil Recovery in the Yates Field

2021 ◽  
Author(s):  
Xiao Jin ◽  
Alhad Phatak ◽  
Aaron Sanders ◽  
Dawn Friesen ◽  
Ed Lewis ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Core Sample ◽  
Wettability Alteration ◽  
Initial Exposure ◽  
Rock Samples ◽  
Final Volume ◽  
External Phase ◽  
Incremental Oil Recovery ◽  
Dolomite Rock ◽  
The Impact

Abstract In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also re-imbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The re-imbibition phenomenon is investigated in this paper utilizing Amott cells. Three cationic surfactants (C12-, C12-16-, C16-based) solutions with interfacial tensions (IFT) between 0.18 to 0.95 mN/m were pre-selected to be evaluated. Current applications of the C12- based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite rock samples were flooded with Yates crude oil before being aged at 140 °F for 6 weeks. For the imbibition tests, synthetic brine was set as the external phase within the Amott cell and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34% to 64% of the original oil volume in the core sample. During the re-imbibition test, a large amount of oil was able to re-imbibe into the rock, displacing the brine. Most of the displacement occurred within the first two weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil re-imbibed into the rock, ranged from 0% to 18%. Given the possibility of surfactant dilution in field applications, another set of tests were conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for both the C12- based surfactant and the C12-16- mixture. Partition coefficients were determined for each of the tested surfactants and the ion pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on re-imbibition was investigated. Results show increasing permeability may lead to a linear response in oil re-imbibition,therefore minimizing the permeability range when selecting rock samples may be necessary when conducting the re-imbibition test. The importance of oil re-imbibition is demonstrated in the experimental study and we make an argument for conducting both the imbibition and re-imbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery designs for field treatments.

An Investigation on the Process of Reimbibition of Oil and Its Impact on Oil Recovery in the Yates Field

2021 ◽  
pp. 1-15
Author(s):  
Xiao Jin ◽  
Alhad Phatak ◽  
Aaron Sanders ◽  
Dawn Friesen ◽  
Ed Lewis ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Core Sample ◽  
Wettability Alteration ◽  
Current Application ◽  
Initial Exposure ◽  
Rock Samples ◽  
Final Volume ◽  
External Phase ◽  
The Impact

Summary In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also reimbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The reimbibition phenomenon is investigated in this paper using Amott cells. Three cationic surfactants (C12-, C12–16-, C16-based) with interfacial tensions (IFT) between 0.18 and 0.95 mN/m were preselected to be evaluated. Current application of the C12-based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite (SD) rock samples were flooded with Yates crude oil before being aged at 60°C for 6 weeks. For the imbibition tests, the aqueous surfactant solution was set as the external phase within the Amott cell, and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34 to 60% of the original oil volume in the core sample. During the reimbibition test, a large amount of oil was able to reimbibe into the rock, displacing the brine. Most of the displacement occurred within the first 2 weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil reimbibed into the rock, ranged from 0 to 18%. Given the possibility of surfactant dilution in field applications, another set of tests was conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for all the tested surfactants. Partition coefficients were determined for each of the tested surfactants, and the ion-pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on reimbibition was investigated. Results show increasing permeability may lead to a linear response in oil reimbibition; therefore, minimizing the permeability range when selecting rock samples may be necessary when conducting the reimbibition test. The importance of oil reimbibition is demonstrated in the experimental study, and we make an argument for conducting both the imbibition and reimbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery (EOR) designs for field treatments.

Phase Behavior, Wettability Alteration, and Oil Recovery of Low-Salinity Surfactant Solutions in Carbonate Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1784-1802 ◽  
Author(s):  
Sepideh Veiskarami ◽  
Arezou Jafari ◽  
Aboozar Soleymanzadeh
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Study Phase ◽  
Low Salinity ◽  
Angle Measurements ◽  
Contact Angle Measurements ◽  
Favorable State ◽  
Phase Behaviors ◽  
The Impact

Summary Recent investigations have shown that treatment with injected brine composition can improve oil production. Various mechanisms have been suggested to go through the phenomenon; nevertheless, wettability alteration is one of the most commonly proposed mechanisms in the literature. Wettability alteration of the porous media toward a more favorable state reduces the capillary pressure, consequently contributing to the oil detachment from pore walls. In this study, phase behavior, oil recovery, and wettability alteration toward a more favorable state were investigated using a combination of formulations of surfactant and modified low-salinity (LS) brine. Phase behaviors of these various formulations were examined experimentally through observations on relative phase volumes. Experiments were performed in various water/oil ratios (WORs) in the presence of two different oil samples, namely C1 and C2. These experiments were conducted to clarify the impact of each affecting parameter; in particular, the impact of resin and asphaltene of crude oil on the performance of LS surfactant (LSS) flooding. Hereafter, the optimal formulation was flooded into the oil-wet micromodel. Optimum formulations increased the capillary number more than four orders of magnitude higher than that under formation brine (FB) flooding, thus causing oil recovery rates of 61 and 67% for oil samples C1 and C2, respectively. Likewise, the wettability alteration potential of optimized formulations was studied through contact angle measurements. Results showed that LS and LSS solutions could act as possible wettability alternating methods for oil-wet carbonate rocks. Using the optimum formulation resulted in a wettability alteration index (WAI) of 0.66 for sample C1 and 0.49 for sample C2, while using LS brine itself ended in 0.51 and 0.29 for oil samples C1 and C2, respectively.

Impact of clay type and water composition on low salinity water injection – visualisation approach

2018 ◽  
Vol 58 (1) ◽  
pp. 51 ◽  
Author(s):  
Tammy Amirian ◽  
Manouchehr Haghighi
Keyword(s):  
Oil Recovery ◽  
Wettability Alteration ◽  
Oil Film ◽  
Low Salinity ◽  
Water Composition ◽  
Low Salinity Water ◽  
Monovalent Ions ◽  
Salinity Water ◽  
The Impact ◽  
Clay Type

Low salinity water (LSW) injection as an enhanced oil recovery method has attracted much attention in the past two decades. Previously, it was found that the presence of clay such as kaolinite and water composition like the nature of cations affect the enhancement of oil recovery under LSW injection. In this study, a pore-scale visualisation approach was developed using a 2D glass micromodel to investigate the impact of clay type and water composition on LSW injection. The glass micromodels were coated by kaolinite and illite. A meniscus moving mechanism was observed and the oil–water interface moved through narrow throats to large bodies, displacing the wetting phase (oil phase). In the presence of kaolinite, the effect of LSW injection was reflected in the change to the wettability with a transition towards water-wetness in the large sections of the pore walls. The advance of the stable water front left behind an oil film on the oil-wet portions of pore walls; however, in water-wet surfaces, the interface moved towards the surface and replaced the oil film. As a result of wettability alteration towards a water-wet state, the capillary forces were not dominant throughout the system and the water–oil menisci displaced oil in large portions of very narrow channels. This LSW effect was not observed in the presence of illite. With regard to the water composition effect, systems containing divalent cations like Ca2+ showed the same extent of recovery as those containing only monovalent ions. The observation indicates a significant role of cation exchange in wettability alteration. Fines migration was insignificant in the observations.

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.

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.

Brine Chemistry Effects in Waterflood and CO2 Injection in Carbonate Reservoirs

2014 ◽  
Author(s):  
Hemanta K. Sarma ◽  
Yi Zhang
Keyword(s):  
Oil Recovery ◽  
Co2 Injection ◽  
Sulfate Concentration ◽  
Water Barrier ◽  
Co2 Diffusion ◽  
Reservoir Conditions ◽  
Brine Chemistry ◽  
Incremental Oil Recovery ◽  
The Impact ◽  
Brine Salinity

It has been reported that the waterflood performance in carbonate reservoirs could be significantly ameliorated by tuning the injected brine salinity and ionic composition. Also, it is noted that the brine salinity affects the CO2 injection process. This study looked into such possible effects of brine chemistry on waterflood and CO2 injection for typical UAE carbonate reservoir conditions of high temperature and pressure (T = 120°C and P = 20.68MPa). Effects on waterflood performance were investigated experimentally by a series of flooding tests at temperatures of 70°C and 120°C. In addition, an imbibition test was conducted at 70°C, followed by wettability monitoring tests at 90°C to investigate the impact of brine salinity variations and ionic compositions on waterflood performance. The impact of brine salinity on CO2-brine system properties including CO2 solubility in brine, interfacial tension between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine were evaluated through correlation-based studies in conjunction with some experimental data. A mathematical pore-scale model was developed to assess the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. This study led to the following findings: (1) Incremental oil recovery could be obtained by either reducing salinity or increasing sulfate concentration of the tertiary injected brine at both 70°C and 120°C. However, the incremental recovery was more remarkable at the higher temperature of 120°C. (2) At 70°C, lowering the water salinity is more effective than raising the sulfate concentration in injected water in terms of incremental oil recovery. It also exhibited a similar potential for increased oil recovery at 120°C. (3) Wettability monitoring tests showed that water-wetness of carbonate rock studied could be increased by either reducing the water salinity or increasing sulfate concentration of the surrounding water. This is consistent with the imbibition test, in which wettability alteration towards more water-wetness by low salinity water was noted. (4) Under typical UAE reservoir conditions, reducing the brine salinity could significantly enhance CO2 dissolution in brine, consequently inducing significant variation to the CO2-brine system properties. This would undoubtedly impact CO2 injection performance. (5) Under typical UAE reservoir conditions, the capacity and rate of CO2 diffusion through water barrier to oil phase could be significantly reinforced by lowering the brine salinity of the water barrier.

scholarly journals Application of Magnetic and Dielectric Nanofluids for Electromagnetic-Assistance Enhanced Oil Recovery: A Review

Crystals ◽  
2021 ◽  
Vol 11 (2) ◽  
pp. 106
Author(s):  
Yarima Mudassir Hassan ◽  
Beh Hoe Guan ◽  
Hasnah Mohd Zaid ◽  
Mohammed Falalu Hamza ◽  
Muhammad Adil ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Experiments ◽  
Oil And Gas ◽  
Field Application ◽  
Wettability Alteration ◽  
Effective Performance ◽  
Global Concern ◽  
Incremental Oil Recovery ◽  
First Time

Crude oil has been one of the most important natural resources since 1856, which was the first time a world refinery was constructed. However, the problem associated with trapped oil in the reservoir is a global concern. Consequently, Enhanced Oil Recovery (EOR) is a modern technique used to improve oil productivity that is being intensively studied. Nanoparticles (NPs) exhibited exceptional outcomes when applied in various sectors including oil and gas industries. The harshness of the reservoir situations disturbs the effective transformations of the NPs in which the particles tend to agglomerate and consequently leads to the discrimination of the NPs and their being trapped in the rock pores of the reservoir. Hence, Electromagnetic-Assisted nanofluids are very consequential in supporting the effective performance of the nanoflooding process. Several studies have shown considerable incremental oil recovery factors by employing magnetic and dielectric NPs assisted by electromagnetic radiation. This is attributed to the fact that the injected nanofluids absorb energy disaffected from the EM source, which changes the fluid mobility by creating disruptions within the fluid’s interface and allowing trapped oil to be released. This paper attempts to review the experimental work conducted via electromagnetic activation of magnetic and dielectric nanofluids for EOR and to analyze the effect of EM-assisted nanofluids on parameters such as sweeping efficiency, Interfacial tension, and wettability alteration. The current study is very significant in providing a comprehensive analysis and review of the role played by EM-assisted nanofluids to improve laboratory experiments as one of the substantial prerequisites in optimizing the process of the field application for EOR in the future.

scholarly journals Polyelectrolyte–nanocomposite for enhanced oil recovery: influence of nanoparticle on rheology, oil recovery and formation damage

2021 ◽  
Author(s):  
Akinleye O. Sowunmi ◽  
Vincent E. Efeovbokhan ◽  
Oyinkepreye D. Orodu ◽  
Babalola A. Oni
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gum Arabic ◽  
Vital Role ◽  
Hydroxyl Group ◽  
Polymeric Solution ◽  
Incremental Oil Recovery ◽  
Polymeric Solutions ◽  
Performance Results ◽  
The Impact

AbstractGum arabic (GA) capacity as an enhanced oil recovery (EOR) agent is studied and compared to the commonly applied xanthan gum (XG). FTIR and TGA characterisation of these two polyelectrolytes and a rheology study by viscosity measurement was conducted on their polymeric and nano-polymeric solution at varying concentrations of the polymers and nanoparticles (NP). Coreflooding experiments were conducted based on a sequence of waterflooding and three slugs of increasing concentration of polymeric (and nano-polymeric) solutions to evaluate EOR performance. Results show similar rheology and oil recovery for 1.0 wt% GA and a 0.1 wt% XG polymeric solution. And the viscosity of GA tends to be Newtonian at a relatively high shear rate. The magnitude of incremental oil recovery of the first slug is independent of the GA concentration but significant for XG. However, the impact of nano-polymeric solution on oil recovery is higher than the polymeric solution. The increase in NP concentration played a vital role in oil recovery, thereby connoting the significance of IFT, contact angle, and its associated mechanisms for EOR. And FTIR affirms that the hydroxyl group in XG is less than GA, thus responsible for adsorption of GA compared to XG.

scholarly journals Recent Advances in Nanoparticles Enhanced Oil Recovery: Rheology, Interfacial Tension, Oil Recovery, and Wettability Alteration

2017 ◽  
Vol 2017 ◽  
pp. 1-15 ◽  
Author(s):  
Muhammad Shahzad Kamal ◽  
Ahmad A. Adewunmi ◽  
Abdullah S. Sultan ◽  
Mohammed F. Al-Hamad ◽  
Umer Mehmood
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Mobility Ratio ◽  
Wettability Alteration ◽  
Factors Affecting ◽  
Recent Advances ◽  
The Impact ◽  
Recovery Methods

Chemically enhanced oil recovery methods are utilized to increase the oil recovery by improving the mobility ratio, altering the wettability, and/or lowering the interfacial tension between water and oil. Surfactants and polymers have been used for this purpose for the last few decades. Recently, nanoparticles have attracted the attention due to their unique properties. A large number of nanoparticles have been investigated for enhanced oil recovery applications either alone or in combination with surfactants and/or polymers. This review discusses the various types of nanoparticles that have been utilized in enhanced oil recovery. The review highlights the impact of nanoparticles on wettability alteration, interfacial tension, and rheology. The review also covers the factors affecting the oil recovery using nanoparticles and current challenges in field implementation.

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