Photon-magnon response to fluid variability and saturation levels in sandstone reservoirs

Abstract The need to recover high viscosity heavy oil from the residual phase of reservoirs has raised interest in the use of electromagnetics (EM) for enhanced oil recovery. However, the transformation of EM wave properties must be taken into consideration with respect to the dynamic interaction between fluid and solid phases. Consequently, this study discretises EM wave interaction with heterogeneous porous media (sandstones) under different fluid saturations (oil and water) to aid the monitoring of fluid mobility and activation of magnetic nanofluid in the reservoir. To achieve this aim, this study defined the various EM responses and signatures for brine and oil saturation and fluid saturation levels. A Nanofluid Electromagnetic Injection System (NES) was deployed for a fluid injection/core-flooding experiment. Inductance, resistance and capacitance (LRC) were recorded as the different fluids were injected into a 1.0-m long Berea core, starting from brine imbibition to oil saturation, brine flooding and eventually magnetite nanofluid flooding. The fluid mobility was monitored using a fibre Bragg grating sensor. The experimental measurements of the relative permittivity of the Berea sandstone core (with embedded detectors) saturated with brine, oil and magnetite nanofluid were given in the frequency band of 200 kHz. The behaviour of relative permittivity and attenuation of the EM wave was observed to be convolutedly dependent on the sandstone saturation history. The fibre Bragg Grating (FBG) sensor was able to detect the interaction of the Fe3O4 nanofluid with the magnetic field, which underpins the fluid mobility fundamentals that resulted in an anomalous response.

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MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

Scientific Contributions Oil and Gas ◽

10.29017/scog.40.2.43 ◽

2018 ◽

Vol 40 (2) ◽

pp. 85-90

Author(s):

Yani Faozani Alli ◽

Edward ML Tobing ◽

Usman Usman

Keyword(s):

Oil Recovery ◽

Mobility Control ◽

Chemical Flooding ◽

Residual Oil ◽

Core Flooding ◽

Oil Viscosity ◽

Oil Saturation ◽

Remaining Oil ◽

Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

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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 ◽

10.3390/nano10050972 ◽

2020 ◽

Vol 10 (5) ◽

pp. 972 ◽

Cited By ~ 8

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.

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Effect of Emulsification on Enhanced Oil Recovery during Surfactant/Polymer Flooding in the Homogeneous and Heterogeneous Porous Media

Geofluids ◽

10.1155/2021/6674185 ◽

2021 ◽

Vol 2021 ◽

pp. 1-9

Author(s):

Xiaoyan Wang ◽

Jie Zhang ◽

Guangyu Yuan ◽

Wei Wang ◽

Yanbin Liang ◽

...

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

High Water ◽

Heterogeneous Porous Media ◽

Recovery Factor ◽

Water Flooding ◽

Core Flooding ◽

Positive Role ◽

High Water Cut ◽

Water Cut

Surfactant polymer (SP) flooding has become an important enhanced oil recovery (EOR) technique for the high-water cut mature oilfield. Emulsification in the SP flooding process is regarded as a powerful mark for the successful application of SP flooding in the filed scale. People believe emulsification plays a positive role in EOR. This paper uses one-dimensional homogenous core flooding experiments and parallel core flooding experiments to examine the effect of emulsification on the oil recoveries in the SP flooding process. 0.3 pore volume (PV) of emulsions which are prepared using ultralow interface intension (IFT) SP solution and crude oil with stirring method was injected into core models to mimic the emulsification process in SP flooding, followed by 0.35 PV of SP flooding to flood emulsions and remaining oil. The other experiment was preformed 0.65 PV of SP flooding as a contrast. We found SP flooding can obviously enhance oil recovery factor by 25% after water flooding in both homogeneous and heterogeneous cores. Compared to SP flooding, emulsification can contribute an additional recovery factor of 3.8% in parallel core flooding experiments. But there is no difference on recoveries in homogenous core flooding experiments. It indicates that the role of emulsification during SP flooding will be more significant for oil recoveries in a heterogeneous reservoir rather than a homogeneous reservoir.

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Study on Nitrogen Foam Flooding in Fractured Reservoir

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.524-527.1209 ◽

2012 ◽

Vol 524-527 ◽

pp. 1209-1212 ◽

Cited By ~ 1

Author(s):

Hong Xing Xu ◽

Chun Sheng Pu ◽

Hong Bin Yang ◽

Wen Hua Man ◽

Tao Yang

Keyword(s):

Oil Recovery ◽

Injection Rate ◽

Water Flooding ◽

Fractured Reservoir ◽

Core Flooding ◽

Oil Saturation ◽

Nitrogen Foam ◽

New Type ◽

Foam Flooding ◽

Enhance Oil Recovery

Aiming at the heterogeneity characteristics of fractured reservoir, a new type of nitrogen foam flooding agents is proposed. The gas/liquid ratio of nitrogen foam flooding is selected as 3:1, and the injection rate is selected as 3mL/min by the evaluation of foam resistance factor using core flooding equipment. In addition, this foam system has a better performance in the situation of low oil saturation. The results of nitrogen foam flooding show that it can enhance oil recovery by 38% after water flooding using artificial cuboid fractured core, indicating this nitrogen foam formula is suitable for EOR in fractured reservoir.

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Evaluating Efficiency of Surfactant-Polymer Flooding with Single Well Chemical Tracer Tests at Kholmogorskoye Field

10.2118/207314-ms ◽

2021 ◽

Author(s):

Mikhail Bondar ◽

Andrey Osipov ◽

Andrey Groman ◽

Igor Koltsov ◽

Georgy Shcherbakov ◽

...

Keyword(s):

Oil Recovery ◽

Promising Result ◽

Tracer Tests ◽

Polymer Flooding ◽

Water Flooding ◽

Residual Oil ◽

Core Flooding ◽

Oil Saturation ◽

Chemical Eor ◽

Single Well

Abstract EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed. The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required. Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result. Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant

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

Proc. Indon. Petrol. Assoc., Digital Technical Conference, 2020 ◽

10.29118/ipa20-se-530 ◽

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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