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Johann Plank - One of the best experts on this subject based on the ideXlab platform.
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synthesis characterization and performance of a novel phosphate modified Fluid Loss additive useful in oil well cementing
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Thomas Hurnaus, Johann PlankAbstract:Abstract A phosphate-modified terpolymer comprising of 2-acrylamido-2-tert-butyl sulfonic acid (ATBS), N,N-dimethyl acrylamide (NNDMA) and 2-(methacryloxy)ethyl phosphate (MEP) was synthesized by aqueous free radical copolymerization and evaluated as Fluid Loss additive (FLA) in oil well cement. Successful incorporation of MEP was confirmed via 1H NMR spectroscopy, and molecular properties of the terpolymer were determined using size exclusion chromatography. It was found that the presence of phosphate anchor groups along the polymer backbone enhances the FLA's performance in cement slurries at high temperatures (up to 140 °C) and in sea water when compared with commonly used ATBS-co-NNDMA or its counterpart composed of ATBS, NNDMA and 2-(methacryloxy)ethanol which bears a hydroxyl instead of the phosphate functionality. The phosphate-modified FLA also revealed better effectiveness and robustness when combined with acetone–formaldehyde–sulfite (AFS) dispersant or ATBS-co-acrylic acid retarder. Adsorption measurements suggest that the superior Fluid Loss performance is owed to higher adsorption of the phosphated FLA. Measurements of the adsorbed layer thickness on cationic polystyrene particles indicate that the phosphated FLA adsorbs in a train-like conformation which results from the strong affinity of the phosphate anchor groups to the positively charged surface.
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preparation and properties of a dispersing Fluid Loss additive based on humic acid graft copolymer suitable for cementing high temperature 200 c oil wells
Journal of Applied Polymer Science, 2013Co-Authors: Oyewole Taye Salami, Johann PlankAbstract:A humic acid graft copolymer possessing both water-retention and dispersing properties in cement slurry was synthesized by grafting lateral chains of 2-acrylamido-2-methylpropane sulfonic acid (AMPS®), N,N-dimethylacrylamide (NNDMA), and acrylic acid (AA) onto a backbone of humic acid using aqueous free radical polymerization. The graft copolymer is composed of 20 wt % humic acid backbone and 80 wt % graft chain (molar ratio AMPS/NNDMA/AA = 1 : 0.31 : 0.03), it exhibits a Mw of 323 kDa and is highly anionic in cement pore solution. The influence of this specific molecular design on cement flow properties is unraveled. When tested at 200°C, the graft copolymer achieved very low cement Fluid Loss values (∼50 mL) at low rheology. This behavior differentiates it from most common synthetic high temperature Fluid Loss additives which excessively viscosify cement slurries. The working mechanism of the graft copolymer was found to rely on adsorption onto the surface of hydrating cement. © 2013 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013
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synthesis characterization and working mechanism of a synthetic high temperature 200 c Fluid Loss polymer for oil well cementing containing allyloxy 2 hydroxy propane sulfonic ahps acid monomer
Journal of Applied Polymer Science, 2013Co-Authors: Constantin Tiemeyer, Johann PlankAbstract:A polymer comprising of 2-acrylamido-2-methyl propane sulfonic acid, N, N-dimethyl acrylamide, allyloxy-2-hydroxy propane sulfonic acid (AHPS), acrylic acid, and N, N-methylene bisacrylamide was synthesized by aqueous free radical copolymerization and tested as high temperature performing Fluid Loss additive (FLA) in oil well cement. Successful incorporation of AHPS was confirmed and characteristic properties of the copolymer were determined using size exclusion chromatography. The FLA showed excellent water retention in cement at 200°C/70 bar. At this temperature, polymer structure changed from branched to linear and hydrodynamic size decreased by ∼50%, thus indicating potential fragmentation, while performance remained unaffected by these alterations. The FLA copolymer does not viscosify cement slurries which is advantageous in high temperature well cementing. The working mechanism of the AHPS-based copolymer was found to rely on reduction of filtercake permeability which is caused by a voluminous coprecipitate of the FLA with tartaric acid retarder, mediated by Ca2+ ions. © 2012 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013
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role of colloidal polymer associates for the effectiveness of hydroxyethyl cellulose as a Fluid Loss control additive in oil well cement
Journal of Applied Polymer Science, 2012Co-Authors: Daniel Bulichen, Johann PlankAbstract:The working mechanism of hydroxyethyl cellulose (HEC) as a Fluid Loss additive in oil well cement was investigated. The specific anionic charge amount, intrinsic viscosity, and associative behavior in a cement pore solution were determined. The Fluid Loss performance was probed through the static filtration of cement slurries. HEC achieves Fluid Loss control by reducing cement filtercake permeability. No influence on the filtercake microstructure was observed. ζ Potential measurements and a special filtration test indicated that no adsorption on cement occurred. Environmental scanning electron microscopy images revealed that in a wet environment, HEC swelled to a multiple of its size and possessed an enormous water-sorption capacity. Concentration-dependent measurements of the hydrodynamic diameter of HEC dissolved in a cement pore solution showed that large associates were formed. These colloidal associates physically obstructed the filtercake pores. Finally, the addition of sulfonated melamine formaldehyde dispersant to the cement slurries containing HEC greatly improved the Fluid Loss control. A specific interaction was responsible for this synergistic effect. © 2012 Wiley Periodicals, Inc. J Appl Polym Sci, 2012
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mechanistic study on carboxymethyl hydroxyethyl cellulose as Fluid Loss control additive in oil well cement
Journal of Applied Polymer Science, 2012Co-Authors: Daniel Bulichen, Johann PlankAbstract:The working mechanism of carboxymethyl hydroxyethyl cellulose (CMHEC, Mw 2.6 × 105 g/mol) as Fluid Loss control additive (FLA) for oil well cement was investigated. First, characteristic properties of CMHEC such as anionic charge amount, intrinsic viscosity in cement pore solution, and static filtration properties of cement slurries containing CMHEC were determined at 27°C and 70 bar. Effectiveness of the FLA was found to rely on reduction of cement filter cake permeability. Consequently, the working mechanism is ascribed to constriction of cement filter cake pores. Zeta potential measurements confirm that at low CMHEC dosages (0–0.3% by weight of cement, bwoc), adsorption of the polymer onto the surface of hydrating cement occurs. However, at dosages of 0.4% bwoc and higher, an associated polymer network is formed. This was evidenced by a strong increase in hydrodynamic diameter of solved CMHEC molecules, an exponential increase in viscosity and a noticeable reduction of surface tension. Thus, the working mechanism of CMHEC changes with dosage. At low dosages, adsorption presents the predominant mode of action, whereas above a threshold concentration of ∼ 10 g/L (the “overlapping concentration”), formation of associated polymer networks is responsible for effectiveness of CMHEC. Addition of anionic polyelectrolytes (e.g., sulfonated melamine formaldehyde polycondensate, Mw 2.0 × 105 g/mol) to cement slurries containing CMHEC greatly improves Fluid Loss control. Apparently, the presence of such polyelectrolytes causes the formation of colloidal associates from CMHEC to occur at lower dosages. Through this mechanism, effectiveness of CMHEC as cement Fluid Loss additive is enhanced. © 2011 Wiley Periodicals, Inc. J Appl Polym Sci, 2012
Yili Kang - One of the best experts on this subject based on the ideXlab platform.
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lost circulation control for formation damage prevention in naturally fractured reservoir mathematical model and experimental study
Spe Journal, 2017Co-Authors: Yili Kang, Zhenjiang YouAbstract:Drill-in Fluid Loss is the most important cause of formation damage during the drill-in process in fractured tight reservoirs. The addition of lost-circulation material (LCM) into drill-in Fluid is the most popular technique for Loss control. However, traditional LCM selection is mainly performed by use of the trial-and-error method because of the lack of mathematical models. The present work aims at filling this gap by developing a new mathematical model to characterize the performance of drill-in Fluid-Loss control by use of LCM during the drill-in process of fractured tight reservoirs. Plugging-zone strength and fracture-propagation pressure are the two main factors affecting drill-in Fluid-Loss control. The developed mathematical model consists of two submodels: the plugging-zone-strength model and the fracture-propagation-pressure model. Explicit formulae are obtained for LCM selection dependent on the proposed model to control drill-in Fluid Loss and prevent formation damage. Effects of LCMmechanical and geometrical properties on Loss-control performance are analyzed for optimal fracture plugging and propagation control. Laboratory tests on Loss-control effect by use of different types and concentrations of LCMs are performed. Different combinations of acid-soluble rigid particles, fibers, and elastic particles are tested to generate a synergy effect for drill-in FluidLoss control. The derived model is validated by laboratory data and successfully applied to the field case study in Sichuan Basin, China.
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analytical model of plugging zone strength for drill in Fluid Loss control and formation damage prevention in fractured tight reservoir
Journal of Petroleum Science and Engineering, 2017Co-Authors: Chengyuan Xu, Yili Kang, Fei ChenAbstract:Developed fractures are beneficial for the efficient development of tight reservoir. They also lead to drill-in Fluid Loss and induce severe formation damage. Fracture plugging with Loss control material (LCM) is the most common way to control drill-in Fluid Loss in fractured formation. Fracture plugging effect largely depends on the strength of fracture plugging zone, because in most cases plugging failure is caused by the strength failure of plugging zone. However, the effects of LCM mechanical and geometric parameters on plugging zone strength are still unclear. Moreover, traditional LCM selection is mainly performed by trial-and-error method, due to the lack of mathematical models. This paper develops an analytical model for plugging zone strength accounting for the frictional failure and shear failure of fracture plugging zone. Effects of LCM mechanical and geometric properties on plugging zone strength are analyzed. The proposed model is validated by laboratory data. Application procedure of the proposed model to drill-in Fluid Loss control is developed and successfully applied to the field case study in Sichuan basin, China. The modelling results show that particle-particle friction angle, particle-fiber friction angle, fiber tensile strength, D90 degradation rate, and friction angle between plugging zone and fracture surface are main mechanical parameters affecting the plugging zone strength. Particle size distribution, aspect ratio and initial angle of fiber, and plugging zone porosity are main geometric parameters during Loss control. Single LCM parameters are applied to the selection of LCM type. Plugging zone parameters are used for the determination of optimal LCM concentration. Reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to optimize the plugging zone strength and Loss control effect.
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fracture plugging optimization for drill in Fluid Loss control and formation damage prevention in fractured tight reservoir
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Yili Kang, Fei Chen, Zhenjiang YouAbstract:Well-developed natural fractures are beneficial for the economic and efficient development of tight reservoirs. However, they also lead to drill-in Fluid Loss and induced severe formation damage. Fracture plugging with Loss control material (LCM) is the most common way to control lost circulation. Fracture plugging effect largely depends on the fracture propagation pressure, because plugging failure is mainly caused by fracture propagation in fractured formation. Nevertheless, the effects of the plugging parameters on the fracture propagation pressure are still unclear. The current paper develops a mathematical model for fracture propagation pressure accounting for fracture plugging. Key indexes are proposed for fracture plugging optimization based on parameter analysis. Laboratory experiments are conducted to select reasonable LCM type and concentration. The application procedure of the proposed model to drill-in Fluid Loss control is presented and successfully applied to field case study. The modelling results show that the plugging zone length, width and permeability are the major plugging parameters that affect the fracture propagation pressure. The larger the plugging zone width and the smaller the plugging zone length and permeability, the higher the fracture propagation pressure. Maximum plugging pressure, total Loss volume before sealing and D90 degradation rate are proposed as the three indexes for LCM selection. Experimental results show that the combination of rigid granule, fiber and elastic particle can create a synergistic effect to optimize the fracture plugging effect. For the 500 μm width fracture, the optimal concentrations for rigid granule, fiber and elastic particle are 5.0%, 1.5% and 2.5%, respectively.
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prevention of fracture propagation to control drill in Fluid Loss in fractured tight gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Long Tang, Fei ChenAbstract:Abstract Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to drill-in Fluid Loss and induce serious formation damage. Preventing natural fractures propagation is the key to control drill-in Fluid Loss in the fractured reservoir. Plugging and sealing the fracture Loss channel with Loss control material (LCM) can improve the fracture propagation pressure (FPP) effectively. However, the main parameters that affect the improved FPP are not clear. To our best knowledge, few papers have been published on the comprehensive parametric analysis for improved FPP to select reasonable LCM and control drill-in Loss in fractured tight gas reservoir. In this paper, we develop a mathematic model to analyze the parameters that affect the FPP after plugging. Laboratory experiment is conducted to select reasonable LCM based on the parametric analysis. Study results show that formation stress anisotropy, elastic modulus, fracture length, fracture pressure and plugging location are the main parameters that impact the improved FPP. According to the analysis results, maximum plugging pressure and total Loss volume before sealing are proposed as the key indexes for LCM selection. Experiment results show that reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to effectively control drill-in Fluid Loss in fracture tight gas reservoir.
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comprehensive evaluation of formation damage induced by working Fluid Loss in fractured tight gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Lijun You, Benjian ZhangAbstract:Abstract Western Sichuan tight gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fracture is beneficial for the economic and efficient development of tight gas reservoir. But it will lead to lost circulation of working Fluid and induce formation damage. Lost circulation has frequently occurred during drill-in, completion and test process. Formation damage degree and damage range are the key indexes for the formation damage evaluation. To our best knowledge, few papers have been published on the comprehensive consideration of the above two indexes. In this paper, we conduct laboratory experiments and develop a mathematical model to evaluate the formation damage degree and determine the formation damage range. Based on the study results a formation damage pattern is established to analyze the mechanism and process of the formation damage induced by working Fluid Loss. The study results show that the average formation damage degree induced by drill-in Fluid Loss is 68.51% and increases to 78.70% when the kill Fluid Loss damage is taken into consideration. The radius of formation damage zone induced by working Fluid Loss is 15.8 m. The formation damage pattern is as follows: First the Loss of drill-in Fluid induces serious formation damage including sensitive damage, particle plugging and water phase trapping. Then the subsequent Loss of kill Fluid in the process of completion and test further aggravates the formation damage degree. Finally in the acidizing treatment the acidizing radius cannot exceed the damage zone radius so that the formation damage cannot be completely removed. The comprehensive evaluation and pattern of formation damage are necessary for designing reasonable reservoir protection and damage removal measures for the fractured tight gas reservoir.
Reza Barati - One of the best experts on this subject based on the ideXlab platform.
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application of nanoparticles as Fluid Loss control additives for hydraulic fracturing of tight and ultra tight hydrocarbon bearing formations
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Reza BaratiAbstract:Abstract Fluid Loss into the matrix rock and micro-fractures is inevitable during a typical hydraulic fracturing job. This makes the application of a comparable Fluid Loss additive to reduce the filtrate volumes into microfractures of a shale formation necessary. Injection of polymeric solutions, either as slick water or cross-linked Fluids, in order to propagate a fracture and distribute proppants and keep the fracture open is a common practice in hydraulic fracturing of unconventional tight and ultra-tight formations. In addition to propagation of a main fracture, polymeric Fluids will be invading the already existing network of micro-fractures and extending the network connected to the main fracture. Different classes of nanoparticles have been used by several researchers to carry different agents including surfactants and enzymes for hydraulic fracturing purposes. Nano-sized pores and micro-sized fractures in tight and ultra-tight formations require a nano to micro-sized Fluid Loss additive to improve propagation of the hydraulic fractures by efficiently reducing the Fluid Loss. In this study, application of silica and polyelectrolyte complex (PEC) nanoparticles as Fluid Loss additives for three sets of core plugs with permeability values within the 10 −5 –10 −4 mD, 0.01–0.1 mD and 1–40 mD range was investigated. The nano-sized material used in this study significantly reduced the Fluid Loss volume for the cores with permeability values below 0.1 mD when mixed only with 2% KCl or with low concentrations of guar polymer prepared in 2% KCl.
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nanoparticles as Fluid Loss control additives for hydraulic fracturing of tight and ultra tight hydrocarbon bearing formations
ASME 2014 33rd International Conference on Ocean Offshore and Arctic Engineering, 2014Co-Authors: Reza BaratiAbstract:Injection of polymeric solutions, either as slick water or cross-linked Fluids, in order to propagate a fracture and distribute proppants and keep the fracture open is a common practice in hydraulic fracturing of unconventional tight and ultra-tight formations. In addition to propagation of a main fracture, polymeric Fluids will be invading the already existing network of micro-fractures and extending the network connected to the main fracture. Fluid Loss into the matrix rock and micro-fractures is inevitable, so is the use of a comparable Fluid Loss additive to reduce the filtrate volume.Different classes of nanoparticles have been used by several researchers to carry different agents including surfactants and enzymes for hydraulic fracturing purposes. Nano-sized pores and micro-sized fractures in tight and ultra-tight formations require a nano to micro-sized Fluid Loss additive to improve propagation of the hydraulic fractures by efficiently reducing the Fluid Loss.In this study, application of silica and polyelectrolyte complex (PEC) nanoparticles as Fluid Loss additives for three sets of core plugs with permeability values within the 10−5 −10−4 mD, 0.01–0.1 mD and 1–40 mD range was investigated. The nano-sized material used in this study significantly reduced the Fluid Loss volume for the cores with permeability values below 0.1 mD when mixed only with 2% KCl or with low concentrations of guar polymer prepared in 2% KCl.Combination of the Fluid Loss additive application with chemical carrying application makes these nanoparticle systems a suitable package for hydraulic fracturing of tight and ultra-tight formations.Copyright © 2014 by ASME
Fei Chen - One of the best experts on this subject based on the ideXlab platform.
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analytical model of plugging zone strength for drill in Fluid Loss control and formation damage prevention in fractured tight reservoir
Journal of Petroleum Science and Engineering, 2017Co-Authors: Chengyuan Xu, Yili Kang, Fei ChenAbstract:Developed fractures are beneficial for the efficient development of tight reservoir. They also lead to drill-in Fluid Loss and induce severe formation damage. Fracture plugging with Loss control material (LCM) is the most common way to control drill-in Fluid Loss in fractured formation. Fracture plugging effect largely depends on the strength of fracture plugging zone, because in most cases plugging failure is caused by the strength failure of plugging zone. However, the effects of LCM mechanical and geometric parameters on plugging zone strength are still unclear. Moreover, traditional LCM selection is mainly performed by trial-and-error method, due to the lack of mathematical models. This paper develops an analytical model for plugging zone strength accounting for the frictional failure and shear failure of fracture plugging zone. Effects of LCM mechanical and geometric properties on plugging zone strength are analyzed. The proposed model is validated by laboratory data. Application procedure of the proposed model to drill-in Fluid Loss control is developed and successfully applied to the field case study in Sichuan basin, China. The modelling results show that particle-particle friction angle, particle-fiber friction angle, fiber tensile strength, D90 degradation rate, and friction angle between plugging zone and fracture surface are main mechanical parameters affecting the plugging zone strength. Particle size distribution, aspect ratio and initial angle of fiber, and plugging zone porosity are main geometric parameters during Loss control. Single LCM parameters are applied to the selection of LCM type. Plugging zone parameters are used for the determination of optimal LCM concentration. Reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to optimize the plugging zone strength and Loss control effect.
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fracture plugging optimization for drill in Fluid Loss control and formation damage prevention in fractured tight reservoir
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Yili Kang, Fei Chen, Zhenjiang YouAbstract:Well-developed natural fractures are beneficial for the economic and efficient development of tight reservoirs. However, they also lead to drill-in Fluid Loss and induced severe formation damage. Fracture plugging with Loss control material (LCM) is the most common way to control lost circulation. Fracture plugging effect largely depends on the fracture propagation pressure, because plugging failure is mainly caused by fracture propagation in fractured formation. Nevertheless, the effects of the plugging parameters on the fracture propagation pressure are still unclear. The current paper develops a mathematical model for fracture propagation pressure accounting for fracture plugging. Key indexes are proposed for fracture plugging optimization based on parameter analysis. Laboratory experiments are conducted to select reasonable LCM type and concentration. The application procedure of the proposed model to drill-in Fluid Loss control is presented and successfully applied to field case study. The modelling results show that the plugging zone length, width and permeability are the major plugging parameters that affect the fracture propagation pressure. The larger the plugging zone width and the smaller the plugging zone length and permeability, the higher the fracture propagation pressure. Maximum plugging pressure, total Loss volume before sealing and D90 degradation rate are proposed as the three indexes for LCM selection. Experimental results show that the combination of rigid granule, fiber and elastic particle can create a synergistic effect to optimize the fracture plugging effect. For the 500 μm width fracture, the optimal concentrations for rigid granule, fiber and elastic particle are 5.0%, 1.5% and 2.5%, respectively.
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prevention of fracture propagation to control drill in Fluid Loss in fractured tight gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Long Tang, Fei ChenAbstract:Abstract Developed fractures are beneficial for the economic and efficient development of tight gas reservoir. But they will lead to drill-in Fluid Loss and induce serious formation damage. Preventing natural fractures propagation is the key to control drill-in Fluid Loss in the fractured reservoir. Plugging and sealing the fracture Loss channel with Loss control material (LCM) can improve the fracture propagation pressure (FPP) effectively. However, the main parameters that affect the improved FPP are not clear. To our best knowledge, few papers have been published on the comprehensive parametric analysis for improved FPP to select reasonable LCM and control drill-in Loss in fractured tight gas reservoir. In this paper, we develop a mathematic model to analyze the parameters that affect the FPP after plugging. Laboratory experiment is conducted to select reasonable LCM based on the parametric analysis. Study results show that formation stress anisotropy, elastic modulus, fracture length, fracture pressure and plugging location are the main parameters that impact the improved FPP. According to the analysis results, maximum plugging pressure and total Loss volume before sealing are proposed as the key indexes for LCM selection. Experiment results show that reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to effectively control drill-in Fluid Loss in fracture tight gas reservoir.
Meiyu Wang - One of the best experts on this subject based on the ideXlab platform.
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synthesis characterization and working mechanism of a novel sustained release type Fluid Loss additive for seawater cement slurry
Journal of Colloid and Interface Science, 2018Co-Authors: Lei Cao, Jianhua Tia, Jintang Guo, Chu Guo, Meiyu WangAbstract:Abstract Synthetic polymer Fluid Loss additive (FLA), an important type of admixture, was broadly applied in modern well cementation. However, the filter Loss volume and Fluidity of cement pastes containing polymer-FLA would deteriorate remarkably when sea water was used in mixing slurries instead of fresh water. In this study, a novel sustained-release-type Fluid Loss additive(S-FLA) was synthesized by means of anion-exchange intercalation reaction between an anionic type-copolymer and a calcium/aluminum type-Layered Double Hydroxide (Ca/Al-LDH). Based on the Fluidity and compressive strength of experiments, it was found that in seawater mixing conditions, this composite material not only utilized its sustained release effect to significantly improve retention Fluidity performance, but also the seed crystal effect of the Ca/Al-LDH effectively alleviated the declining in compressive strength of the slurries caused by the carboxyl group in the polymer. More interestingly, the realization of the slow release function increased actual adsorption capacity of the anionic polymer on the surface of cement hydrated particles, which made its controlling water Loss effect was also better than that of the conventional FLA. The above advantages of this hybrid materials created the possibility to surmount the negative effect of electrolytes present in seawater, so as to provide some useful references for its practical application in the offshore well cement.
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the ability of sodium metasilicate pentahydrate to adjust the compatibility between synthetic Fluid Loss additives and retarders applying in oil well cement
Construction and Building Materials, 2018Co-Authors: Jianhua Tian, Miaomiao Hu, Yang Xu, Meiyu WangAbstract:Abstract Sodium metasilicate pentahydrate (SMP), a type of hardening-accelerator, was widely used in cement slurry to enhance its early strength. In this study, we found that SMP had an novel ability to adjust the compatibility between 2-Acrylamido-2-Methyl Propane Sulfonic Acid (AMPS)-based Fluid Loss Additive (FLA) and Retarder in oil well cement. Reasons for this significance were proposed, that SMP promoted the formation and growth of hydration products by accelerating the hydration velocity of cement slurry, which increased the adsorption sites of cement hydration products. As that happens, the more AMPS-based polymers were adsorbed simultaneously on the surface of the hydration product, thereby effectively improving the compatibility problem caused by the competitive adsorption between the admixtures. Meanwhile, while SMP speeded up the hydration reaction, the pores space of cement hydrated particles were filled with more hydrates and consequently altered its pore size distribution, whose action was also beneficial to the development of early strength. Overall, those findings will provide further interpretation for the effect of admixture on cement hydration products and offer some useful references for practical application of oil well cementing in the future.