Chemical Sand Consolidation: From Polymers to Nanoparticles

Alakbari, Fahd Saeed; Mohyaldinn, Mysara Eissa; Muhsan, Ali Samer; Hasan, Nurul; Ganat, Tarek Al-Arbi Omar

doi:10.3390/polym12051069

Cited by 37 publications

(20 citation statements)

References 77 publications

(120 reference statements)

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“…However, mechanical techniques are not without their limitations and disadvantages. These techniques are often more time-consuming and expensive when compared with chemical techniques, not to mention other issues including productivity reduction, complexity in installing the equipment, installation damage to the wellbore and causing interference to reservoir operation [ 9 , 10 , 11 ]. Therefore, chemical technique provides an attractive alternative to consolidate weak rock formation.…”

Section: Introductionmentioning

confidence: 99%

Adsorption of Hydrolysed Polyacrylamide onto Calcium Carbonate

et al. 2022

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Carbonate rock strengthening using chemical techniques is a strategy to prevent excessive fines migration during oil and gas production. We provide herein a study of the adsorption of three types of hydrolysed polyacrylamide (HPAM) of different molecular weight (F3330S, 11–13 MDa; F3530 S, 15–17 MDa; F3630S, 18–20 MDa) onto calcium carbonate (CaCO3) particles via spectrophotometry using a Shimadzu UV-2600 spectrometer. The results are compared to different adsorption isotherms and kinetic models. The Langmuir isotherm shows the highest correlation coefficient (R2 > 0.97) with equilibrium parameters (RL) ranging between 0 and 1 for all three HPAMs, suggesting a favorable monolayer adsorption of HPAM onto CaCO3. The adsorption follows pseudo-second order kinetics, indicating that the interaction of HPAM with CaCO3 is largely dependent on the adsorbate concentration. An adsorption plot reveals that the amount of HPAM adsorbed onto CaCO3 at equilibrium increases with higher polymer molecular weight; the equilibrium adsorbed values for F3330S, F3530S and F3630S are approximately 0.24 mg/m2, 0.31 mg/m2, and 0.43 mg/m2, respectively. Zeta potential analysis shows that CaCO3 has a zeta potential of +12.32 mV, which transitions into negative values upon introducing HPAM. The point of zero charge (PZC) is observed at HPAM dosage between 40 to 50 ppm, in which the pH here lies between 9–10.

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Section: Introductionmentioning

confidence: 99%

Adsorption of Hydrolysed Polyacrylamide onto Calcium Carbonate

et al. 2022

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“…This viscoelastic behaviour is attributed by the formation of wormlike micelles (WLMs) [28]. In addition, smart wormlike micelles (WLMs) or smart self-organized structures, can be used in a myriad of applications within the oil and gas industry, including hydraulic fracturing, emulsions, polymer, surfactant, and foam flooding [15,32]. Nowadays, investigation is carried out to develop WLMs that respond to external stimuli for the ease to control visco-elasticity [33,34].…”

Section: Introductionmentioning

confidence: 99%

Experimental Investigation and Performance Evaluation of Modified Viscoelastic Surfactant (VES) as a New Thickening Fracturing Fluid

et al. 2020

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In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir’s formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value ( 6.17 ), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 6 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 ∘ C) and 170 (s − 1 ) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 ( ∘ C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is ( 7.99 % ), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

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“…If not detected early and alleviated, sand erosion may lead to hydrocarbon leakage from piping components and total failure of other production facilities such as pumps, compressors, and valves. The industrial practice for minimizing or avoiding sand production, and hence sand erosion, is by implementing sand control techniques, such as mechanical sand control (Ma et al 2020;Wu et al 2016) and/or chemical sand control (Alakbari et al 2020).…”

Section: Introductionmentioning

confidence: 99%

Erosion of sand screens by solid particles: a review of experimental investigations

Abduljabbar

Mohyaldinn

Younis

et al. 2022

J Petrol Explor Prod Technol

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In oil and gas industry, sand can be carried with oil and gas, when producing from unconsolidated sandstone reservoirs. The existence of sand particles with fluids flow can lead to severe damages to production system’s components. Therefore, sand control techniques are needed to prevent potential damages. Standalone sand screens (SAS) are widely used because they can provide reliable sand control with low cost and low complexity. However, SAS application can become disadvantageous because of mechanical erosion due to sand particle impingement. The experimental investigation of sand screens erosion is challenging, as the measurements are to be carried out for a representative SAS material and geometry at laboratory-scale simulated conditions. The simulated conditions should mimic the real flow conditions, which involve many interrelated parameters. Some of these parameters are related to the entrained sand particles (i.e., particle shape, size and, concentration) while other parameters are related to the flow characteristics (i.e., flow velocity and fluid properties). In this review, the key factors influencing sand screens erosion are described, and erosion mechanisms are highlighted. In addition, experimental results showing the effects of key parameters on SAS erosion are discussed and evaluated. Also, challenges associated with previous studies, along with a proposed outlook to overcome those challenges, are presented. It has been found that the limitations of the previous studies are related to test setup and flow direction, particle–particle interaction, and particle–fluid interaction considerations. This review highlighted noticeable research gaps in sand screens erosion measurements that can be considered in future.

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Chemical Sand Consolidation: From Polymers to Nanoparticles

Cited by 37 publications

References 77 publications

Adsorption of Hydrolysed Polyacrylamide onto Calcium Carbonate

Adsorption of Hydrolysed Polyacrylamide onto Calcium Carbonate

Experimental Investigation and Performance Evaluation of Modified Viscoelastic Surfactant (VES) as a New Thickening Fracturing Fluid

Erosion of sand screens by solid particles: a review of experimental investigations

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