Measurement of Surfactant-Induced Interfacial Interactions at Reservoir Conditions

Xu, Wei; Ayirala, Subhash C.; Rao, Dandina N.

doi:10.2118/96021-pa

Cited by 33 publications

(13 citation statements)

References 41 publications

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“…From Table 4, it is observed that the potential change in the wettability of the reservoir rock shifted toward more water-wet condition. Therefore, this wettability change can increase the imbibition of water into the hydrocarbon reservoir, consequently optimizing the oil recovery (Xu et al 2008). This change in wettability is due to the fact that chelating agents dissolve minerals present inside the pore spaces as described by (Shafiq et al 2018).…”

Section: Methodsmentioning

confidence: 99%

Investigation of change in different properties of sandstone and dolomite samples during matrix acidizing using chelating agents

Shafiq

Mahmud

Zahoor

et al. 2019

J Petrol Explor Prod Technol

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Properties of rock, such as effective porosity, permeability and pore size distribution (PSD), are generally referred to as petrophysical properties. These properties are among the most significant for reservoir evaluation. Acid stimulation treatments are usually used in sandstones to mitigate the impact of formation damage, with the aim of restoring or enhancing the natural matrix permeability and consequently boosting the well productivity. Hydrochloric acid (HCl) is commonly used in the preflush stage to remove calcium and other metal ions, preventing the development of calcium fluoride (CaF 2) and other silicate precipitates that could block the pore throats, while an acid mixture (HF-HCl combination) is usually preferred as the main stimulation fluid for the removal of quartz and remaining metal ions. However, sometimes the application of these acids can lead to other problems, including fast reactions, corrosion of pipes, environmental hazards, precipitation reactions and formation damage due to the incompatibility of HCl with clay minerals, so chelating agents have been proposed as an alternative for matrix stimulation fluids. In this study, three different chelating agents, ethylenediaminetetraacetic acid (EDTA), N-(2-hydroxyethyl) ethylenediamine-N,N′,N′-triacetic acid (HEDTA) and N-acetyl-l-glutamic acid (GLDA), have been used to stimulate Berea sandstone, Colton tight sandstone and Guelph dolomite samples. Core flood experiments were conducted on 1.5 × 3 (in 2) core plugs, at a temperature below 180 °F. A slow injection rate of (1-0.5 cc/min) was chosen for the treatment fluid, promoting the dissolution of ions by increasing the contact time between the fluid and the rock. Furthermore, nuclear magnetic resonance, wettability and micro-computed tomography (CT scan) analyses were employed to evaluate the effect of the acid treatment on formation properties such as porosity, PSD, pore topology, wettability and pore structure. After exposing the samples to HEDTA, large wormholes were detected in their pore network, demonstrating that HEDTA has the highest potential to create new pore spaces when compared to GLDA and EDTA when reacted with both types of samples.

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Section: Methodsmentioning

confidence: 99%

Investigation of change in different properties of sandstone and dolomite samples during matrix acidizing using chelating agents

Shafiq

Mahmud

Zahoor

et al. 2019

J Petrol Explor Prod Technol

View full text Add to dashboard Cite

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“…They also concluded that altering wet ability by surfactants can result in enhanced oil recovery through decreasing capillary pressure and adhesive forces. [6] In their research about evaluation of lingosulfonates as an adsorbed material to be sacrificed (lost) during surfactant injection, Hong,S.A,Bac,J.H referred that the lost amount of surfactant can be significantly decreased (more than 50%) if an initial treatment by lignosulfonate wash is done. [7] Researcher Marc Baviere showed in his study about olefin sulfonate (AOS) behavior in high temperature and high hardiness as a surfactant in EOR that this sulfonate group gives important results especially at high temperatures and salinity, in addition to the chemical stability of this kind of Sulfonates.…”

Section: Reference Studymentioning

confidence: 99%

Using Anionic Surfactants for Increasing the Displacement Factor in Jaribee Formation of Dero Oil Field

AlBredi

2016

Journal of Petroleum and Mining Engineering

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In this research, a lab study was conducted on the process of injection Of Surfactant Dodecyl benzene Sodium Sulfonate [Wetconat-P1220EH (DDBSCa)] into a lab prepared matrix model consists of Marble that physically simulates the reservoir properties of Jaribee producing formation in Dero oil field. An injecting operation of the said surfactant was applied on the rock model using The Following Volumetric ratios (15, 30 and 50% PV), then the injection was continued at each ratio using the displacement liquid until the Volumetric ratio 250%PV in order to guarantee an efficient displacement. Through the results of the displacement processes, the change of the following factors in relation with the ratio of the injected liquid to the volume of the pores of the model was studied O.F.D: oil displacement factor, W: water percentage in the produced liquid, and Ra: recoverability. represents the ratio of the produced oil volume at every injecting process to the accumulating volume of the injected liquid in the same stage. Ra=V_O/V_T. To compare the efficiency of displacement using the said surfactant with the efficiency of water injection (currently applied in Dero field), the model was prepared for water injection (Water flooding) by cleansing by kerosene and water, then dried and re-saturated with oil. A comparison between the change of the aforementioned factors of water injection and surfactant injection was graphically performed. The results of the graphical comparison of both injecting methods implied an obvious increase of (O.F.D) and (Ra) factors when injecting the surfactant at all studied injection ratios than that of the water injection.

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“…Surfactant is studied for improving water flooding in fractured reservoirs since it could change matrix wettability and/ or reduce water/oil interfacial tension (IFT) to enhance capillary imbibition and/or reduce residual oil saturation. The wettability alteration and IFT reduction are two main mechanisms of surfactant enhanced oil recovery (EOR) which depends on the oil/brine/rock system, the surfactant type and concentration, divalent ions, salinity, temperature and others (Standnes and Austad 2000;Standnes et al 2002;Babadagli 2002Babadagli , 2003Seethepalli et al 2004;Xu et al 2005;Alvarez and Schechter 2016;Golabi et al 2012;Alvarez et al 2014;Gao and Sharma 2013;Karnanda et al 2013).…”

Section: Introductionmentioning

confidence: 99%

Simulation study of surfactant injection in a fractured core

Cheng

Kleppe

Torsæter

2019

J Petrol Explor Prod Technol

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Surfactant flooding could be used to improve water flooding in fractured reservoirs due to the main mechanisms of wettability alteration and interfacial tension reduction. However, the surfactant flooding in fractured reservoir is not well studied. And there still exist some disputes like surfactant injection rate, surfactant application timing and surfactant injection size. The objective of this work is to study the effects of those parameters on surfactant oil recovery. A spontaneous imbibition model is established based on spontaneous imbibition experiments to verify the properties of rock, brine, oil and surfactant that would be used in the study of surfactant flooding. The spontaneous imbibition model is cut into two parts to create a vertical fracture in the middle. Then the fractured matrix is used as the model in the study of surfactant flooding. The simulation results show that considering the time cost and surfactant consumption, the surfactant injection rate of 0.027 cm 3 /h (i.e., 0.001 PV/h) is a proper injection rate for the base case, since the oil recovery rate is the same for the injection rate that is higher than 0.027 cm 3 /h, and the oil recovery is up to 90% ultimate oil recovery after injecting 2 PV surfactant solution. The analysis of surfactant diffusion and fracture porosity effects on surfactant oil recovery indicates that the surfactant diffusion is a key parameter to facilitate the movement of surfactant into the matrix. The injection rate has larger effect in the system with smaller fracture porosity. When the injection rate is higher than 0.53 cm 3 /h, the ultimate oil recovery is larger in the system with fracture porosity of 0.1% than the system with fracture porosity of 0.5%. In general, the earlier injection of surfactant results in a better result. For the base case, the surfactant flooding time and the required surfactant volume are smaller for the earlier application of surfactant. If the surfactant diffusion is negligible, the early injection of surfactant could increase the ultimate oil recovery. The maximum oil recovery is obtained after injecting 1.3 PV surfactant solution with the concentration of 0.01 g/cm 3. But for the lower surfactant concentration, it needs more surfactant solution. Furthermore, the surfactant efficiency is reduced because less surfactant is imbibed into the matrix. So under the condition of injection safety, higher surfactant concentration should be applied. This work not only studied the injection rate effect on oil recovery, it also analysed the effect of surfactant diffusion and fracture properties on the choice of injection rate. In addition, this work explained why the surfactant should be applied before water flooding and whether surfactant application is feasible after completed water flooding. At the end, the surfactant slug size effect on oil recovery and how it is affected by the surfactant concentration are discussed.

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Measurement of Surfactant-Induced Interfacial Interactions at Reservoir Conditions

Cited by 33 publications

References 41 publications

Investigation of change in different properties of sandstone and dolomite samples during matrix acidizing using chelating agents

Investigation of change in different properties of sandstone and dolomite samples during matrix acidizing using chelating agents

Using Anionic Surfactants for Increasing the Displacement Factor in Jaribee Formation of Dero Oil Field

Simulation study of surfactant injection in a fractured core

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