Adsorption in Chemical Floods with Ammonia as the Alkali

Sharma, Himanshu; Lu, Jun; Weerasooriya, Upali; Pope, Gary A.; Mohanty, Kishore K.

doi:10.2118/179682-ms

Cited by 15 publications

(3 citation statements)

References 12 publications

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“…Then, SAIL adsorption was estimated using the theory of diffuse percolation, that means, the difference in pore volumes corresponding to 0.5 normalized concentration between SCN – and SAIL profiles (eq ). ,, The theory of diffuse percolation suggests that when a solution is flooding a water-saturated core at an injection velocity of V , the front at C / C 0 = 0.5 also moves at that velocity, indicating breakthrough of the fronts when the effluents reach that normalized concentration τ = ( P V S A I L , 50 % − P V t r a c e r , 50 % ) × normalP normalV × false[ C 0 false] normalS normalA normalI normalL normalM normala normals normals normalr normalo normalc normalk where τ is the SAIL adsorption on the chalk rock surface in mg/g, [C 0 ] SAIL is the initial SAIL concentration in mg/cm 3 , PV is the core pore volume in cm 3 , PV SAIL,50% and PV tracer,50% are the pore volumes at 50% injection concentration of SAIL and tracer, respectively, in the effluent, and Mass rock is the dry core weight in grams.…”

Section: Experimental Workmentioning

confidence: 99%

Evaluation of Surface-Active Ionic Liquids in Smart Water for Enhanced Oil Recovery in Carbonate Rocks

et al. 2023

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Ionic modification of injected brines (Smart Water EOR) has previously demonstrated great potential for wettability alteration in carbonates from initially mixed-wet toward more water-wet conditions. However, the efficiency of Smart Water application is temperaturedependent, which reduces its ability as a rock wettability modifier at low temperatures (below 100 °C). Moreover, at low temperature conditions, the acid number of crude oils tends to increase in the reservoir, causing a stronger oil wetting character and less water-wet initial conditions. This paper evaluates the wettability alteration potential of surface-active ionic liquids added to Smart Water to obtain a synergistic enhanced oil recovery effect in low-temperature carbonate reservoirs. [C 12 mim]Br, [C 12 Py]Cl, and [C 16 Py]Cl were formulated in Smart Water (SW0Na) and tested as wettability modifiers in mixed-wet carbonate chalk cores. Spontaneous imbibition oil recovery tests showed that the addition of [C 12 mim]Br and [C 12 Py]Cl can cause wettability changes, resulting in increased oil recovery compared to pure SW0Na brine at 90 °C. The highest incremental oil recovery in tertiary mode of 24.6 % OOIP was obtained using [C 12 mim]Br in SW0Na, followed by [C 12 Py]Cl in SW0Na with 22.4 % OOIP, and only 11.5 % OOIP was recovered by pure SW0Na brine. The potential for wettability alteration for carbonate rocks was further evaluated in viscous flooding tests using the best formulation from the results obtained in the spontaneous imbibition experiments ([C 12 mim]Br in SW0Na). The core flooding results showed an ultimate recovery of 79.3 % OOIP achieved in secondary mode injection. Despite the difference in the head groups of the cationic [C 12 mim]Br and [C 12 Py]Cl ionic liquids, both formulations showed abilities to desorb polar organic components of crude oil from the chalk mineral surfaces, thus improving the performance of Smart Water EOR at 90 °C.

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Section: Experimental Workmentioning

confidence: 99%

Evaluation of Surface-Active Ionic Liquids in Smart Water for Enhanced Oil Recovery in Carbonate Rocks

et al. 2023

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“…Surfactant adsorption can be reduced by 50% or less by the polymer in SP flooding due to competitively adsorption between surfactants and polymers [49]. However, the surfactant reduction in SP (less than 50%) is much smaller than ASP (surfactant adsorption reduced to almost zero) [50,51]. Surfactant adsorption differs in SP and ASP flooding [2][3][4].…”

Section: Eor Mechanismsmentioning

confidence: 99%

Recent Advances of Surfactant-Polymer (SP) Flooding Enhanced Oil Recovery Field Tests in China

Sun

Guo

et al. 2020

Geofluids

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Recently, there are increasing interests in chemical enhanced oil recovery (EOR) especially surfactant-polymer (SP) flooding. Although alkali-surfactant-polymer (ASP) flooding can make an incremental oil recovery factor (IORF) of 18% original oil in place (OOIP) according to large-scale field tests in Daqing, the complex antiscaling and emulsion breaking technology as well as potential environment influence makes some people turn to alkali-free SP flooding. With the benefit of high IORF in laboratory and no scaling issue to worry, SP flooding is theoretically better than ASP flooding when high quality surfactant is available. Many SP flooding field tests have been conducted in China, where the largest chemical flooding application is reported. 10 typical large-scale SP flooding field tests were critically reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only one is conducted in Daqing Oilfield, although ASP flooding has entered the commercial application stage since 2014. 2 SP tests are conducted in Shengli Oilfield. Both technical and economic parameters are used to evaluate these tests. 2 of these ten tests are very successful; the others were either technically or economically unsuccessful. Although laboratory tests showed that SP flooding can attain IORF of more than 15%, the average predicted IORF for these 10 field tests was 12% OOIP. Only two SP flooding tests in (SP 1 in Liaohe and SP 7 in Shengli) were reported actual IORF higher than 15% OOIP. The field test in Shengli was so successful that many enlarged field tests and industrial applications were carried out, which finally lead to a commercial application of SP flooding in 2008. However, other SP projects are not documented except two (SP7 and SP8). SP flooding tests in low permeability reservoirs were not successful due to high surfactant adsorption. It seems that SP flooding is not cost competitive as polymer flooding and ASP flooding if judged by utility factor (UF) and EOR cost. Even the most technically and economically successful SP1 has a much higher cost than polymer flooding and ASP flooding, SP flooding is thus not cost competitive as previously expected. The cost of SP flooding can be as high as ASP flooding, which indicates the importance of alkali. How to reduce surfactant adsorption in SP flooding is very important to cost reduction. It is high time to reevaluate the potential and suitable reservoir conditions for SP flooding. The necessity of surfactant to get ultra-low interfacial tension for EOR remains further investigation. This paper provides the petroleum industry with hard-to-get valuable information.

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“…However, there seemed to be a shift of interest from sodium-based to ammonia-based alkali in recent years. Sharma et al (2016) recommended NH 4 OH as an alternative alkali for ASP processes transportation and storage advantages. Kusumah and Vazquez (2017) found that NH 4 OH would only require 9% of the storage required for Na 2 CO 3 to achieve the same pH value.…”

Section: Introductionmentioning

confidence: 99%

Experimental study on the performance of emulsions produced during ASP flooding

Laben¹,

Alameen

Khan

et al. 2021

J Petrol Explor Prod Technol

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ASP (Alkaline/Surfactant/Polymer) flooding is one of the most promising techniques that has proven to have successful application in several laboratory and pilot tests. However, the formation of persistent and stable emulsions is one of the associated problems with ASP flooding. The present work investigated the effect of sodium carbonate alkaline, Alpha Olefin Sulfonate (AOS) surfactant, and GLP100 polymer on produced crude oil emulsion. The study was conducted by measuring the emulsion stability in terms of water separation and rag layer volume using a TurbiScan analyzer, the dispersed droplet size using cross-polarization microscopy, the interfacial tension using spinning drop tensiometer, and rheological properties using rheometer. The experimental results have shown that AOS presence increased the emulsion stability only when its concentration is above 100 ppm. Meanwhile, below 100 ppm, the presence of AOS promoted water separation and reduced the rag layer volume. In a less significant manner, a high concentration of sodium carbonate alkali increased the stability of the emulsion. The use of GLP100 Polymer has shown substantial ability in promoting water separation and reducing the rag layer volume to a minimal level. It is believed that the outcomes of this work will aid in developing a suitable destabilization process to enhance the oil–water separation and produced water treatment from ASP flooding in the oil production fields. Further investigations on AS, AP, SP as well as the ASP's combined effect on emulsion stability, droplet size, interfacial tension and rheological properties are highly recommended to support the decision-makers on the EOR implementations with chemical additives.

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Adsorption in Chemical Floods with Ammonia as the Alkali

Cited by 15 publications

References 12 publications

Evaluation of Surface-Active Ionic Liquids in Smart Water for Enhanced Oil Recovery in Carbonate Rocks

Evaluation of Surface-Active Ionic Liquids in Smart Water for Enhanced Oil Recovery in Carbonate Rocks

Recent Advances of Surfactant-Polymer (SP) Flooding Enhanced Oil Recovery Field Tests in China

Experimental study on the performance of emulsions produced during ASP flooding

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